Q-2, r. 15 - Regulation respecting mandatory reporting of certain emissions of contaminants into the atmosphere

Updated to 1 July 2024

This document has official status.

chapter Q-2, r. 15

Regulation respecting mandatory reporting of certain emissions of contaminants into the atmosphere

Environment Quality Act

(chapter Q-2, ss. 2.2, 46.2 and 124.1).

Act respecting certain measures enabling the enforcement of environmental and dam safety legislation

(chapter M-11.6, ss. 30 and 45).

M.O. 2007-09-26; S.Q. 2022, c. 8, s. 1.

DIVISION I SCOPE, PURPOSE AND INTERPRETATION

1. This Regulation applies to every operator whose enterprise, facility or establishment emits a contaminant listed in Schedules A and A.1 into the atmosphere at a level that is equal to or greater than the reporting threshold prescribed for the contaminant. It also applies to all operators whose enterprise, facility or establishment engages in capture, storage, re-use or elimination of any of the contaminants listed in Schedule A.1 or receives transfers of any of those contaminants from another operator’s enterprise, facility or establishment.

The provisions of this Regulation apply in a reserved area or an agricultural zone established under the Act respecting the preservation of agricultural land and agricultural activities (chapter P-41.1).

M.O. 2007-09-26, s. 1; M.O. 2010-12-06, s. 1; M.O. 2023-1009, s. 1.

2. In the perspective of ensuring supervision of the quality of the environment in relation to phenomena that increase the greenhouse effect, acid rain, smog and toxic pollution, and of drawing up an inventory of certain contaminants emitted into the atmosphere, this Regulation determines the thresholds over which enterprises, facilities or establishments are required to report their emissions in relation to the contaminants associated with those phenomena, as well as certain other situations in which they are subject to the reporting requirements. It also determines the information to be provided, including confidential information that is necessary to calculate the quantity of the contaminants emitted, such as data pertaining to production, fuels, raw materials, equipment and processes.

M.O. 2007-09-26, s. 2; M.O. 2010-12-06, s. 2; M.O. 2023-1009, s. 2.

3. In this Regulation,

(0.1)  “biomass fuels” means any fuel whose entire heat generating capacity is derived from biomass;

(0.2)  “biomass” means a non-fossilized plant or part of a plant, an animal carcass or part of an animal, manure or liquid manure, a micro-organism and any other product derived from such matters;

(0.3)  “standard conditions” means a temperature of 20 °C and a pressure of 101.325 kPa;

(0.4)  “flexigas” means a gaseous fuel with a low calorific value produced through the gasification of coke;

(1)  “total fluorides” means the sum of fluorides emitted as gases and fluorides emitted as particles;

(1.1)  “associated gas” means a natural gas which is found in association with crude oil, either dissolved in crude oil or as a cap of free gas above the crude oil;

(2)  “Minister” means the Minister of Sustainable Development, Environment and Parks;

(3)  “process” means any method, reaction or operation through which the matter treated undergoes a physical or chemical change in the same production line and includes all successive operations on a single matter bringing about the same type of physical change;

(4)  “reporting threshold” means the quantity of a contaminant or a category of contaminants emitted by an enterprise, facility or establishment, expressed in reference to certain parameters, in excess of which the operator of the enterprise, facility or establishment must report its emission level.

For the application of Division II.1,

(1)  “CO2 emissions attributable to fixed processes” means the CO2 emissions resulting form a fixed chemical process reaction producing CO2 from carbon in a chemical bond in the raw material and carbon used to withdraw an unwanted component of the raw material where there is no substitutable raw material;

(2)  “greenhouse gas emissions attributable to combustion” means greenhouse gas emissions related to an exothermic reaction of a fuel;

(3)  “other category greenhouse gas emissions” means greenhouse gas emissions other than emissions attributable to fixed processes and emissions attributable to combustion.

Last, for the application of this Regulation to a closed landfill site, a person or municipality is considered to operate the site until such time as it is released from its environmental monitoring and maintenance obligations under section 85 of the Regulation respecting the landfilling and incineration of residual materials (chapter Q-2, r. 19).

M.O. 2007-09-26, s. 3; M.O. 2010-12-06, s. 3; M.O. 2011-12-16, s. 1; M.O. 2012-12-11, s. 1.

DIVISION II STANDARDS FOR THE MANDATORY REPORTING OF EMISSIONS OF CERTAIN CONTAMINANTS RESPONSIBLE FOR TOXIC POLLUTION, ACID RAIN AND SMOG INTO THE ATMOSPHERE

M.O. 2007-09-26, Div. II; M.O. 2010-12-06, s. 4.

4. Every person or municipality operating establishment that emits a contaminant listed in Part I of Schedule A into the atmosphere in a quantity that reaches or exceeds the reporting threshold set out in that Schedule for the contaminant or category of contaminants must, not later than 1 June of each year, communicate to the Minister by electronic means, using the form available on-line on the website of the Ministère du Développement durable, de l’Environnement, de la Faune et des Parcs, the quantity of each of the contaminants listed in Part I of Schedule A that the establishment emitted into the atmosphere in the preceding calendar year.

The operator must also identify the activities, processes or equipment that are the source of contaminant emissions, by specifying separately for each of them the emissions attributable to them, the quantity of fuel and raw materials used and the volume of production that have been used in calculating the quantities of contaminants.

Furthermore, the operator must provide the Minister with the methods of calculation or assessment referred to in the second paragraph of section 6 that were used as well as any information relevant to the calculations, including the factors and emission rates used, their source and, if they originate in published documents, the applicable reference.

For the purposes of this section, if an establishment has more than one facility, the data pertaining to each facility must be identified separately. In all cases, the operator must identify the activities, processes or equipment that are the source of contaminant emissions by indicating separately.

M.O. 2007-09-26, s. 4; M.O. 2010-12-06, s. 5; M.O. 2011-12-16, s. 2; M.O. 2012-12-11, s. 2; M.O. 2013-12-11, s. 1; M.O. 2014-12-16, s. 1; M.O. 2016-12-21, s. 1.

5. If the operator of the facility or establishment is required, under a public notice given pursuant to section 46 of the Canadian Environmental Protection Act (1999) (S.C. 1999, c. 33), to report to the Minister of the Environment of Canada for a contaminant listed in Part II of Schedule A, the operator must, not later than 1 June each year, transmit to the Minister by electronic means, using the form available on-line on the website of the Ministère du Développement durable, de l’Environnement, de la Faune et des Parcs, the quantity of any of those contaminants that the facility or establishment emitted into the atmosphere in the preceding calendar year.

The operator must also identify the activities, processes or equipment that are the source of contaminant emissions, by specifying separately for each of them the emissions attributable to them, the quantity of fuel and raw materials used and the volume of production that have been used in calculating the quantities of contaminants reported to the Minister of the Environment of Canada.

Furthermore, the operator must provide the Minister with the methods of calculation or assessment referred to in the second paragraph of section 6 that were used as well as any information relevant to the calculations, including the factors and emission rates used, their origin and, if they originate in published documents, the applicable reference.

M.O. 2007-09-26, s. 5; M.O. 2010-12-06, s. 6; M.O. 2011-12-16, s. 3; M.O. 2012-12-11, s. 3; M.O. 2013-12-11, s. 2.

5.0.1. When a facility or an installation changes operator during a year, the operator ceasing to operate must so inform the Minister as soon as possible.

For the purposes of sections 4 and 5, the emissions report for the current year must, in that case, be submitted by the new operator. The previous operator must provide the new operator with all the data required for the report for the period of the year for which the facility or establishment was under his or her responsibility.

M.O. 2016-12-21, s. 2.

5.1. The operator referred to in section 4 or 5 must include the following information with the information referred to in those sections:

(1)  the name of and contact information for the enterprise, facility or establishment as well as the name of and contact information for its representative;

(2)  the business number assigned to the operator when registered under the Act respecting the legal publicity of enterprises (chapter P-44.1) as well as the ID number assigned under the National Pollutant Release Inventory of the Government of Canada;

(3)  the type of enterprise, facility or establishment operated, the activities pursued and processes and equipment used as well as, where applicable, the 6-digit code under the North American Industry Classification System (NAICS Canada);

(4)  the name of and contact information for the person responsible for the contaminants emissions report for the enterprise, facility or establishment.

M.O. 2012-12-11, s. 4.

5.2. When the emissions of contaminants from an establishment reported in accordance with section 4 or 5 fall below the reporting threshold the following year, the operator of the establishment must, not later than 1 June following the first year in which the emissions are below the threshold, send a notice to the Minister including the following information and documents:

(1)  the information referred to in section 5.1;

(2)  an attestation that the emissions of contaminants referred to in Schedule A are below the reporting threshold;

(3)  the reason for the reduction in emissions of contaminants;

(4)  the signature of the person responsible for the declaration at the establishment.

M.O. 2012-12-11, s. 4.

6. The information communicated pursuant to section 4 or the second paragraph of section 5 must be based on the best data and best information the operator of the facility or establishment has, may reasonably be expected to have or may obtain by means of appropriate data processing.

The information may be based on one of the following methods of calculation or assessment:

(1)  a continuous emission monitoring and recording system;

(2)  a mass balance which, in the case of greenhouse gas emissions, must calculate or assess the emissions attributable to matters that contribute 0.5% or more of the total carbon introduced in the process at the facility or establishment;

(3)  a technical calculation using an emission factor published in scientific documents;

(4)  a technical calculation using an emission rate resulting from an emissions sampling; or

(4.1)  a model for the estimation of emissions;

(5)  (paragraph replaced);

(6)  (paragraph replaced).

In addition, unless otherwise indicated, the data required under this Regulation must be in metric units.

An emissions report made under section 4 or 5 must be signed by the person responsible for the report at the enterprise, facility or establishment, who must also attest to the veracity of the information communicated.

M.O. 2007-09-26, s. 6; M.O. 2010-12-06, s. 7; M.O. 2011-12-16, s. 4; M.O. 2012-12-11, s. 5.

DIVISION II.1 STANDARDS FOR THE MANDATORY REPORTING OF CERTAIN EMISSIONS OF GREENHOUSE GASES INTO THE ATMOSPHERE

M.O. 2010-12-06, s. 8.

6.1. Every person or municipality operating an establishment that, during a calendar year, emits into the atmosphere greenhouse gases mentioned in Schedule A.1 in a quantity equal to or greater than 10,000 metric tons CO2 equivalent must report those emissions to the Minister in accordance with this Division as long as its emissions are not below the reporting threshold for 4 consecutive years or, in the cases provided for in the seventh paragraph of section 19 or the fourth paragraph of section 19.0.1 of the Regulation respecting a cap-and-trade system for greenhouse gas emission allowances (chapter Q-2, r. 46.1), for 9 consecutive years, even if the establishment ceases its activities.

Every person or municipality operating an enterprise that purchases electricity produced outside Québec, except electricity produced in the territory of a partner entity referred to in Appendix B.1 to the Regulation respecting a cap-and-trade system for greenhouse gas emission allowances (chapter Q-2, r. 46.1) or a province or territory of Canada, for its own consumption or for sale in Québec must also report the emissions attributable to the production of that electricity, under the first paragraph. For such an emitter, and for an emitter that exports, transports or distributes electricity, that transports or distributes natural gas, that carries on gas or oil exploration or production, or that transports or distributes petroleum by pipeline, the reporting threshold provided for in the first paragraph applies to the enterprise as a whole.

Every person or municipality operating an enterprise that distributes each year more than 200 litres of fuels referred to in part QC.30.1 of protocol QC.30 in Schedule A.2 is to report to the Minister all greenhouse gas emissions attributable to their combustion or use as long as the quantity of fuels distributed is not below the reporting threshold for 4 consecutive years, even if it ceases to distribute such fuels.

For the purposes of this Division, an enterprise operated by an emitter referred to in the second paragraph is considered to be an establishment.

When an establishment referred to in the first paragraph has more than one facility, the data for each facility must be identified separately.

A person or municipality that ceases to operate an enterprise, a facility or an establishment or that cedes its operation must so notify the Minister as soon as possible The emissions report for the current year must be made by the new operator. The previous operator must provide the new operator with all the data required for the report for the period of the year for which the enterprise, facility or establishment was under his or her responsibility.

When an emitter referred to in the first paragraph permanently closes an establishment or an emitter referred to in the second or third paragraph dissolves an enterprise and they are still subject to the mandatory reporting of their greenhouse gas emissions under this section, they must, within 6 months of the permanent closing of the establishment or the dissolution of the enterprise, send to the Minister an emissions report for the period during which the establishment or enterprise was operating but was not covered by such a report. If such an establishment or enterprise is referred to respectively in the first or second paragraph of section 2 of the Regulation respecting a cap-and-trade system for greenhouse gas emission allowances, the emissions report must be sent with the verification report referred to in section 6.6.

M.O. 2010-12-06, s. 8; M.O. 2011-12-16, s. 5; M.O. 2012-09-05, s. 1; M.O. 2012-12-11, s. 6; M.O. 2013-12-11, s. 3; M.O. 2014-12-16, s. 2; M.O. 2015-12-14, s. 1; M.O. 2016-12-21, s. 3; M.O. 2017-12-18, s. 1; M.O. 2019-12-05, s. 1; M.O. 2020-12-01, s. 1; M.O. 2022-12-16, s. 1.

6.1.1. An emitter referred to in subparagraph 3 of the second paragraph of section 2 of the Regulation respecting a cap-and-trade system for greenhouse gas emission allowances (chapter Q-2, r. 46.1) who is registered in accordance with section 7 of that Regulation must report emissions to the Minister in accordance with this Division as long as the emissions are not under the reporting threshold provided for in the first paragraph of section 6.1 for 4 consecutive years or, in the cases provided for in the seventh paragraph of section 19 of the Regulation respecting a cap-and-trade system for greenhouse gas emission allowances, for 9 consecutive years, even if the establishment ceases its activities.

An emitter referred to in the second paragraph of section 2.1 of the Regulation respecting a cap-and-trade system for greenhouse gas emission allowances must report emissions to the Minister in accordance with this Division for as long as the emitter must cover the emissions under section 19.0.1 of that Regulation.

The fifth, sixth and seventh paragraphs of section 6.1 apply to the emitters referred to in this section, with the necessary modifications.

M.O. 2020-12-01, s. 2; M.O. 2022-12-16, s. 2.

6.1.2. Any person or municipality that is not referred to in section 6.1 or 6.1.1 and that operates an enterprise, a facility or an establishment that, during a calendar year, engaged in the capture, storage, re-use or elimination of any of the greenhouse gas emissions listed in Schedule A.1, or received transfers of any of those emissions from other operators’ enterprises, facilities or establishments is required to report its emissions for that calendar year to the Minister in accordance with this section.

The fifth, sixth and seventh paragraphs of section 6.1 apply to emitters referred to in this section with the necessary modifications.

M.O. 2023-1009, s. 3.

6.1.3. Emitters referred to in this section that operate an enterprise, a facility or an establishment that transfers greenhouse gas emissions listed in Schedule A.1 to an enterprise, facility or establishment of another operator that is subject to the requirement to report its emissions must provide that operator with all the data required for the report for the period concerned.

All emitters referred to in section 6.1.2 and those emitters referred to in sections 6.1 and 6.1.1 that operate an enterprise, a facility or an establishment that engages in one of the activities listed in the first paragraph of section 6.1.2 must, upon ceasing those activities, notify the Minister as soon as possible.

M.O. 2023-1009, s. 3.

6.2. An emitter referred to in section 6.1, 6.1.1 or 6.1.2 must, not later than 1 June each year, communicate to the Minister by electronic means, using the form available on-line on the website of the Ministère du Développement durable, de l’Environnement, de la Faune et des Parcs, a greenhouse gas emissions report for the preceding calendar year, including

(1)  the total quantity of the emitter’s greenhouse gas emissions in metric tons CO2 equivalent, excluding greenhouse gas emissions captured, stored, re-used, eliminated or transferred out of the establishment and emissions reported in accordance with protocols QC.17 and QC.30 of Schedule A.2, calculated using the following equation:

Where:

CO2e = Total Annual greenhouse gas emissions, in metric tons of carbon dioxide equivalent;

GHGi = Total Annual emissions of each greenhouse gas emitted, in metric tons;

GWPi = Global warming potential indicated in Schedule A.1 for each greenhouse gas emitted;

n = Number of greenhouse gases emitted;

i = Type of greenhouse gas emitted.

The total quantity of CO2 equivalent calculated pursuant to this subparagraph must be rounded up to the next highest whole number;

(2)  the total quantity of emissions of each type of greenhouse gas referred to in Schedule A.1, in metric tons, excluding greenhouse gas emissions captured, stored, re-used, eliminated or transferred out of the establishment, and emissions reported in accordance with protocols QC.17 and QC.30 of Schedule A.2;

(2.1)  in the case of a person or municipality operating an enterprise that distributes fuel, the quantity of greenhouse gas emissions attributable to the combustion or use of the fuel distributed in metric tons CO2 equivalent;

(2.2)  in the case of a person or municipality operating an enterprise that purchases electricity produced outside Québec, except electricity produced in the territory of a partner entity referred to in Appendix B.1 to the Regulation respecting a cap-and-trade system for greenhouse gas emission allowances (chapter Q-2, r. 46.1) or a province or territory of Canada, for its own consumption or for sale in Québec, the quantity of greenhouse gas emissions attributable to the production of that electricity, in metric tons CO2 equivalent;

(2.2.1)  in the case of a person or municipality operating an enterprise that exports electricity produced in Québec, the quantity of greenhouse gas emissions attributable to the production of that electricity, in metric tons CO2 equivalent;

(2.3)  for establishments in the sectors referred to in Appendix A to the Regulation respecting a cap-and-trade system for greenhouse gas emission allowances (chapter Q-2, r. 46.1), the total quantity of the emitter’s greenhouse gas emission in metric tons CO2 equivalent, excluding emissions captured, stored, re-used or transferred out of the establishment, emissions referred to in the second paragraph of section 6.6 and emissions calculated in accordance with protocols QC.17 and QC.30 of Schedule A.2;

(3)  all information prescribed in Schedule A.2 concerning the type of the emitter’s enterprise, facility or establishment and, where applicable, the type of activity pursued and the type of process or equipment used;

(4)  the total quantity of CO2 emissions attributable to the combustion of biomass and biofuels in metric tons;

(4.1)  the total quantity of CO2 emissions attributable to the use of biomass and biomass fuels for purposes other than combustion, in metric tons;

(4.2)  the quantity and description of biomass used, for each of the following categories:

(a)  forest biomass, specifying the quantity and description of each of the following types of waste:

i.  primary forest waste, namely waste from forest management activities such as parts of trees, residual trees, commercial and non-commercial tree sections, branches and foliage;

ii.  secondary forest waste, namely waste from industrial process and related products such as woodchips, sawdust, shavings and bark;

iii.  tertiary forest waste, namely waste from construction, demolition and packing processes;

(b)  agricultural biomass, specifying the quantity and description of each of the following types of waste:

i.  animal waste;

ii.  plant waste;

(c)  municipal biomass;

(d)  any other type of biomass not referred to in subparagraphs a to c;

(5)  the total quantity of emissions of each greenhouse gas that is captured, stored, re-used, eliminated or transferred out of the establishment and the quantity of emissions generated by each operation, in metric tons, along with the contact information of each operating or transfer site, and specify, in the case of CO2 emissions, whether they are attributable to the combustion or use of biomass or biomass fuels;

(5.1)  the total quantity of emissions of each greenhouse gas transferred from another establishment and the quantity of emissions generated by this operation, in metric tons, along with the contact information of the original site for each of those emissions and specify, in the case of CO2 emissions, whether they are attributable to the combustion or use of biomass or biomass fuels;

(6)  the calculation methods used in accordance with section 6.3;

(7)  in the case of types of enterprise, facility or establishment or types of activity, process or equipment not covered by a specific protocol in Schedule A.2 or for which greenhouse gas emissions have been calculated in accordance with the second paragraph of section 6.3:

(a)  the quantity of emissions of each type of greenhouse gas referred to in Schedule A.1 attributable to each type of activity or the use or each type of process or equipment in metric tons, excluding greenhouse gas emissions captured, stored, re-used, eliminated or transferred out of the establishment;

(b)  the CO2 emissions attributable to the combustion or use of biomass or biomass fuels, in metric tons;

(c)  the emission factors or rates used and their origin, reference or method of determination;

(8)  in the case of an emitter referred to in section 6.6:

(a)  if applicable, the total annual quantity of benchmark units relating to the emitter’s activities;

(b)  the total greenhouse gas emissions for each type of emission, and, if applicable, for each benchmark unit, excluding the emissions referred to in the second paragraph of section 6.6 and the emissions calculated in accordance with protocols QC.17 and QC.30 of Schedule A.2, namely:

i.  the annual fixed process CO2 emissions, in metric tons;

ii.  the annual greenhouse gas combustion emissions, in metric tons CO2 equivalent;

iii.  the annual other category greenhouse gas emissions, in metric tons CO2 equivalent;

(b.1)  the total quantity of emissions captured, stored, re-used, eliminated or transferred out of the establishment for each greenhouse gas and the quantity of emissions generated by each operation, in metric tons, while specifying the emissions type from those listed below, along with the contact information of each operating or transfer site and, in the case of CO2 emissions, whether they are attributable to the combustion or use of biomass or biomass fuels:

i.  the annual fixed process CO2 emissions, in metric tons;

ii.  the annual greenhouse gas combustion emissions, in metric tons CO2 equivalent;

iii.  the annual other category greenhouse gas emissions, in metric tons CO2 equivalent;

(b.2)  the total quantity of emissions of each greenhouse gas transferred from another establishment and the quantity of emissions generated by this operation, in metric tons, while specifying the emissions type from those listed below, along with the contact information of the original site for each emission and, in the case of CO2 emissions, whether they are attributable to the combustion or use of biomass or biomass fuels:

i.  the annual fixed process CO2 emissions, in metric tons;

ii.  the annual greenhouse gas combustion emissions, in metric tons CO2 equivalent;

iii.  the annual other category greenhouse gas emissions, in metric tons CO2 equivalent;

(c)  for a new facility in accordance with paragraph 11 of section 3 of the Regulation respecting a cap-andtrade system for greenhouse gas emission allowances, the total greenhouse gas emissions for each type of emission, and, if applicable, for each benchmark unit, excluding the emissions referred to in the second paragraph of section 6.6 and the emissions calculated in accordance with protocols QC.17 and QC.30 of Schedule A.2, namely:

i.  the annual fixed process CO2 emissions, in metric tons;

ii.  the annual greenhouse gas combustion emissions, in metric tons CO2 equivalent;

iii.  the annual other category greenhouse gas emissions, in metric tons CO2 equivalent.

(9)  (subparagraph revoked).

When the facility or establishment is equipped with a continuous CO2 monitoring system and when the emitter must, in accordance with this Regulation, indicate emissions by type, whether combustion, fixed process or “other”, the emitter must, for each type of emission,

(1)  estimate the greenhouse gas combustion emissions and the “other” category emissions using the emission factors in tables 1-1 to 1-8 in QC.1.7 of Schedule A.2. If no factor is indicated in the tables, the emitter may use a factor determined by Environment Canada, the U.S. Environmental Protection Agency (USEPA), the Intergovernmental Panel on Climate Change (IPCC), the National Council for Air and Stream Improvement (NCASI) or the World Business Council for Sustainable Development (WBCSD);

(2)  determine the annual fixed process greenhouse gas emissions by subtracting from the data measured by the continuous CO2 monitoring system the greenhouse gas combustion emissions and the “other” category emissions estimated in accordance with subparagraph 1.

The greenhouse gas emissions report referred to in the first paragraph must be signed by the person responsible for the report at the enterprise, facility or establishment, who must also attest to the veracity of the information communicated.

M.O. 2010-12-06, s. 8; M.O. 2011-12-16, s. 6; M.O. 2012-09-05, s. 2; M.O. 2012-12-11, s. 7; M.O. 2012, s. 7; M.O. 2013-12-11, s. 4; M.O. 2014-12-16, s. 3; M.O. 2017-12-18, s. 2; M.O. 2020-12-01, s. 3; M.O. 2023-1009, s. 4.

6.3. The quantities of greenhouse gas emissions reported under the first paragraph of section 6.2 must be calculated using the protocols prescribed in Schedule A.2 corresponding to the type of enterprise, facility or establishment operated and, where applicable, the type of activity pursued and the process or equipment used.

Notwithstanding the first paragraph, an emitter may use one of the calculation or assessment methods referred to in the second paragraph of section 6

(1)  to calculate the greenhouse gas emissions of one or more sources of emissions when the emissions attributable to them represent, cumulatively, not more than 3% of the emissions from the establishment in CO2 equivalent, up to a maximum of 20,000 metric tons CO2 equivalent where the emissions from the establishment are, in the case of an emitter not referred to in section 6.6, the greenhouse gas emissions referred to in subparagraph 1 of the first paragraph of section 6.2, and in the case of an emitter referred to in section 6.6, the greenhouse gas emissions referred to in subparagraph 2.3 of the first paragraph of section 6.2.

(2)  if no protocol is prescribed in Schedule A.2 for the type of enterprise, facility or establishment operated, for the type of activity pursued, for the type of process or equipment used or for the type of greenhouse gas emitted.

The emitter must use the same calculation method and perform 100% of the data sampling and measurement in accordance with that method for each report year. However, as soon as an emitter’s situation no longer corresponds to one of the cases referred to in the second paragraph, the emitter must change the calculation method for the protocols referred to in the first paragraph.

Notwithstanding the second and third paragraphs, when the emitter’s enterprise, facility or establishment is equipped with a continuous emission monitoring and recording system to measure the parameters needed to calculate greenhouse gas emissions or when such a system is installed during their operation, the emitter must used use the calculation methods applicable to that system.

M.O. 2010-12-06, s. 8; M.O. 2012-09-05, s. 3; M.O. 2012-12-11, s. 8; M.O. 2013-12-11, s. 5; M.O. 2015-12-14, s. 2; M.O. 2016-12-21, s. 4.

6.3.1. When an emitter, as part of its sampling activities, is unable to obtain analytical data, it must replace the missing data.

For that purpose, the emitter must apply the applicable method for the estimation of missing data specified in the calculation method prescribed by the applicable protocol in Schedule A.2 or, if the emitter uses a method of calculation or assessment referred to in the second paragraph of section 6, the emitter must demonstrate that everything has been done to capture 100% of the data and then apply the following method:

(1)  when the missing data concern carbon content, temperature, pressure or any other data that is sampled or analyzed, the emitter must analyze again, using the prescribed method, the original sample, a backup sample or a replacement sample for the same measurement and sampling period. If it is not possible to obtain valid data, the emitter must use replacement data established

(a)  by determining the sampling or measurement rate using the following equation:

R = QSAct/QSRequired

Where:

R = Actual sampling or measurement rate, expressed as a percentage;

QSAct = Quantity of actual samples or measurements obtained by the emitter using the calculation or assessment method used by the emitter;

QSRequired = Quantity of samples or measurements required to be obtained by the emitter using that method;

(b)  for data that require sampling or analysis, the emitter must

i.  if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data is available from before that period, the emitter must use the first available data from after the period for which the data is missing;

ii.  if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;

iii.  if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;

(2)  when the missing data concern a quantity of raw materials, such as fuel consumption, a quantity of material, a production quantity or a quantity of reference units, the replacement data must be estimated on the basis of all the data relating to the processes used;

(3)  when the missing data are data from a continuous emission monitoring and recording system, the emitter must determine the replacement data using the procedure indicated in protocol SPE 1/PG/7 entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or applying to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6 of Schedule A.2.

M.O. 2012-09-05, s. 4.

6.4. An emitter referred to in section 6.1, 6.1.1 or 6.1.2 must submit, with the information communicated pursuant to section 6.2, the following information:

(1)  the name of and contact information for the enterprise, facility or establishment as well as the name of and contact information for its representative;

(2)  (pargraph revoked);

(3)  the business number assigned to the emitter when registered under the Act respecting the legal publicity of enterprises (chapter P-44.1) as well as the ID number assigned under the National Pollutant Release Inventory of the Government of Canada;

(4)  the type of enterprise, facility or establishment operated and, where applicable, the activities pursued and processes and equipment used as well as, where applicable, the 6-digit code under the North American Industry Classification System (NAICS Canada);

(5)  the name of and contact information for the person responsible for the greenhouse gas emissions report for the enterprise, facility or establishment.

M.O. 2010-12-06, s. 8; M.O. 2012-12-11, s. 9; M.O. 2020-12-01, s. 4; M.O. 2023-1009, s. 5.

6.5. An emitter whose annual greenhouse gas emissions report includes one or more errors or omissions must, as soon as possible, communicate a notice of correction to the Minister containing the following information:

(1)  a description of the corrections to be made to the initial report;

(2)  the circumstances that led to the errors or omissions and, where application, the corrections made;

(3)  where applicable, an estimate of the quantity of greenhouse gas emissions represented by the errors or omissions.

M.O. 2010-12-06, s. 8; M.O. 2012-12-11, s. 10.

6.6. An emitter referred to in the first and second paragraphs of section 2 or in section 2.1 of the Regulation respecting a cap-and-trade system for greenhouse gas emission allowances (chapter Q-2, r. 46.1) must, not later than 1 June of each year, send to the Minister a report on the verification of its emissions report carried out by an organization accredited to ISO 14065, by a member of the International Accreditation Forum and in compliance with an ISO-17011 program, for the emitter’s sector of activity.

The following emissions do not need to be verified:

(1)  CO2 emissions attributable to the combustion or use of biomass and biomass fuels;

(2)  CH4 emissions attributable to coal storage and referred to in QC.5.3 in Schedule A.2;

(3)  CO2, CH4 and N2O emissions, referred to in protocol QC.27 of Schedule A.2, attributable to mobile equipment on the site of an establishment;

(3.1)  CO2, CH4 and N2O emissions attributable to residual materials landfill;

(4)  (subparagraph revoked);

(5)  (subparagraph revoked);

(6)  (subparagraph revoked);

(7)  (subparagraph revoked).

The emitter must have the annual report verified by a verifying organization and a verifier designated by that organization that also meets the following requirements:

(1)  this organization and this verifier have not acted as consultants for the emitter for the quantification or greenhouse gas emissions report or have not provided a service referred to in subparagraph 3 of the first paragraph of section 6.10 during the 3 preceding years;

(2)  this organization and this verifier have not verified more than 6 of the emitter’s consecutive annual reports since the 2012 emissions report; and

(3)  where the emitter wishes to have the verification of the annual report done by a verifying organization or verifier other than the organization or verifier that verified the report the preceding year, the verifying organization or verifier must not have verified the emissions report for that emitter during the 3 previous years.

An emitter referred to in the first or second paragraph of section 6.1 or the first paragraph of section 6.1.1 must have the emitter’s annual report verified until such time as the emitter’s greenhouse gas emissions fall below the threshold determined in the first paragraph or subparagraph 1 of the second paragraph of section 2 of the Regulation respecting a cap-and-trade system for greenhouse gas emission allowances for 4 consecutive years or, in the cases provided for in the seventh paragraph of section 19 of the Regulation respecting a cap-and-trade system for greenhouse gas emission allowances, for 9 consecutive years.

An emitter referred to in the third paragraph of section 6.1 must have the emitter’s annual report verified until such time as the fuel distributed falls below the threshold determined in subparagraph 2 of the second paragraph of section 2 of the Regulation respecting a cap-and-trade system for greenhouse gas emission allowances for 1 year, even if there is cessation of the distribution activities referred to in QC.30.1 of protocol QC.30 in Schedule A.2.

An emitter referred to in section 2.1 of the Regulation respecting a cap-and-trade system for greenhouse gas emission allowances must have the emitter’s annual report verified until such time as the emitter is bound to cover emissions under section 19.0.1 of the Regulation respecting a cap-and-trade system for greenhouse gas emission allowances.

Despite the first paragraph, the verification report on the emissions report may have been made by a verification organization in the process of being accredited so long as the organization receives its accreditation not later than 1 September of the year in which the emitter’s verification report is sent.

If the organization fails to receive its accreditation within the time period specified in the sixth paragraph, the emitter must, not later than 1 April following the end of that period, send to the Minister a new verification report of its emissions report made by an organization accredited in accordance with the first paragraph.

M.O. 2010-12-06, s. 8; M.O. 2011-12-16, s. 7; M.O. 2012-09-05, s. 5; M.O. 2012-12-11, s. 11; M.O. 2013-12-11, s. 6; I.N. 2014-08-01; M.O. 2014-12-16, s. 4; M.O. 2016-12-21, s. 5; M.O. 2017-12-18, s. 3; M.O. 2020-12-01, s. 5; M.O. 2022-12-16, s. 3.

6.6.1. In addition to the verification requirement provided for in the first paragraph of section 6.6, a person or municipality referred to in the first paragraph of section 2.1 of the Regulation respecting a cap-and-trade system for greenhouse gas emission allowances (chapter Q-2, r. 46.1) that registers for the system in accordance with sections 7.1 and 7.2 of that Regulation must, at the time of registration, send to the Minister, in accordance with section 6.6, a verification report on the emissions report for the year preceding the year in which the person or municipality intends to register.

M.O. 2017-12-18, s. 4; M.O. 2022-12-16, s. 4.

6.7. An emitter referred to in section 6.6 who communicates a notice of correction for the emitter’s emissions report in accordance with section 6.5 must include a verification report where any of the following relative importance thresholds is reached:

(1)  where errors or omissions, calculated using the equation below, represent 5% or more of the total emissions of the establishment referred to in the first paragraph of section 6.1 or section 6.1.1 or the enterprise referred to in the second or third paragraph of section 6.1 or correspond to emissions equal to or greater than 25,000 metric tons CO2 equivalent:

Where:

PE = Percentage of error;

SEO = Sum of CO2 equivalent greenhouse gas emissions erroneously calculated or omitted, in metric tons;

TER = Total greenhouse gas emissions initially reported and referred to in subparagraph 2.3 of the first paragraph of section 6.2 or, in the case of emissions reported according to protocol QC.17 or QC.30 of Schedule A.2, emissions referred to in subparagraph 2.1 or 2.2 of that paragraph, as the case may be, in metric tons CO2 equivalent;

(2)  where errors or omissions in the total annual quantity of benchmark units declared in accordance with subparagraph a of subparagraph 8 of the first paragraph of section 6.2, calculated using the equation below, represent 0.1% or more:

Where:

PE = Percentage of error;

BUEO = Quantity of benchmark units erroneously calculated or omitted, on the basis of the benchmark unit used;

BUD = Quantity of benchmark units initially declared, on the basis of the benchmark unit used.

Where the errors or omissions calculated in accordance with subparagraphs 1 and 2 of the first paragraph are less than the relative importance threshold provided for by those subparagraphs, the emitter must provide an attestation to that effect.

M.O. 2010-12-06, s. 8; M.O. 2012-12-11, s. 12; M.O. 2012-12-11, s. 12; M.O. 2013-12-11, s. 7; M.O. 2017-12-18, s. 5; M.O. 2020-12-01, s. 6.

6.8. The verification of an initial greenhouse gas emissions report must

(1)  be carried out in accordance with the ISO 14064-3 standard and using procedures that allow a reasonable level of assurance within the meaning of that standard;

(2)  include, over a period of 3 consecutive years, at least 1 visit of each establishment referred to in the first paragraph of section 6.1 or section 6.1.1 or the enterprise referred to in the second or third paragraph of section 6.1, covered by the report by the verifier designated by the verification organization;

(3)  be performed by using the relative importance thresholds provided for in subparagraphs 1 and 2 of the first paragraph of section 6.7.

Despite subparagraph 2 of the first paragraph, a visit must be made during a year in the following cases:

(a)  it is the first verification carried out by the verification organization for that establishment or enterprise;

(b)  the verification organization has not carried out the verification of the report of that establishment or enterprise for at least 3 years;

(c)  the previous verification resulted in a negative conclusion respecting the accuracy and reliability of the report;

(d)  the operator of the establishment or enterprise has changed since the previous verification;

(e)  the sources of emission or the types of reference unit have changed since the previous verification;

(f)  the verifier designated by the verification organization is of the opinion that a visit is necessary;

(g)  the verification is carried out as part of the permanent closing of the establishment or the dissolution of the enterprise under the seventh paragraph of section 6.1 or the third paragraph of section 6.1.1.

In the case of an emitter who transports or distributes electricity or natural gas, carries on natural gas or oil exploration or production or distributes fuel, the visit must allow a representative sampling of the emitter’s facilities.

M.O. 2010-12-06, s. 8; M.O. 2011-12-16, s. 8; M.O. 2012-12-11, s. 13; M.O. 2013-12-11, s. 8; M.O. 2014-12-16, s. 5; M.O. 2017-12-18, s. 6; M.O. 2020-12-01, s. 7; M.O. 2022-12-16, s. 5.

6.9. In addition to the information prescribed by the standards ISO 14064-3 and ISO 14065, the verification report must include

(1)  the name of and contact information for the verification organization and its representative, as well as the name of and contact information for the chief verifier, the person assigned to the internal review of the verification process and the other members of the verification team designated by the organization to carry out the verification;

(2)  the name of and contact information for the member of the International Accreditation Forum that accredited the verification organization, and the date of the accreditation;

(3)  the dates of the period during which the verification took place;

(3.1)  where applicable, the date of any visit to the enterprise, facility or establishment and, if the visit is made under the second paragraph of section 6.8, the reason for the visit;

(4)  a description of any error or omission observed in the emissions report or relating to the data, information or methods used;

(4.1)  a status report on the actions taken to correct errors or omissions observed during previous verifications that have not been corrected;

(5)  (paragraph revoked);

(6)  where applicable, the corrections made to the emissions report following the verification;

(7)  the total quantity of greenhouse gas emissions referred to in Schedule A.1, in metric tons, excluding greenhouse gas emissions that have been captured, stored, re-used, eliminated or transferred out of the establishment, emissions referred to in the second paragraph of section 6.6 and emissions reported using protocols QC.17 and QC.30 of Schedule A.2;

(7.0.1)  the total quantity of greenhouse gas emissions referred to in Schedule A.1 that have been captured, stored, re-used, eliminated or transferred out of the establishment, for each type of emissions, namely

i.  the annual fixed process CO2 emissions, in metric tons;

ii.  the annual greenhouse gas combustion emissions, in metric tons CO2 equivalent;

iii.  the annual other category greenhouse gas emissions, in metric tons CO2 equivalent;

(7.0.2)  the total quantity of greenhouse gas emissions referred to in Schedule A.1 that have been transferred from another establishment for each type of emissions, namely

i.  the annual fixed process CO2 emissions, in metric tons;

ii.  the annual greenhouse gas combustion emissions, in metric tons CO2 equivalent;

iii.  the annual other category greenhouse gas emissions, in metric tons CO2 equivalent;

(7.1)  the total quantity of reference units relating to the emitter’s activities for the report year;

(7.2)  for each benchmark unit, the total quantity of greenhouse gas emissions for each type of emissions, excluding emission referred to in the second paragraph of section 6.6, namely:

(a)  annual CO2 emissions attributable to fixed processes, in metric tons;

(b)  annual emissions of greenhouse gas attributable to combustion, in metric tons CO2 equivalent;

(c)  other annual greenhouse gas emissions, in metric tons CO2 equivalent;

(7.3)  the total quantity of greenhouse gas emissions attributable to the use of fuel distributed for consumption in Québec, in metric tons CO2 equivalent, calculated in accordance with subparagraph 1 of the first paragraph of part QC.30.2 of protocol QC.30 in Schedule A.2;

(7.4)  the total quantity of greenhouse gas emissions attributable to the acquisition by the emitter of electricity produced outside Québec, except electricity produced in the territory of a partner entity referred to in Appendix B.1 to the Regulation respecting a cap-and-trade system for greenhouse gas emission allowances (chapter Q-2, r. 46.1) or a province or territory of Canada, for its own consumption or for sale in Québec, and the total quantity of greenhouse gas emissions attributable to the exportation of electricity, in metric tonnes CO2 equivalent, calculated in accordance with protocol QC.17 of Schedule A.2;

(7.5)  in cases where the verifier observes that a portion of the reported quantity of greenhouse gas emissions or reference units was not determined in accordance with this Regulation and that the error relating to those emissions or units is equal to or greater than the relative importance threshold calculated in accordance with the first paragraph of section 6.7, an estimate of the absolute uncertainty and relative uncertainty relating to those emissions or units, established as follows:

Absolute uncertainty = | Quantity found non-compliant - Quantity documented |

Relative uncertainty = (Absolute uncertainty ÷ Total quantity reported) x 100%

Where:

Quantity found non-compliant = Portion of the reported quantity of greenhouse gas emissions or reference units determined as non-compliant by the verifier;

Quantity documented = Portion of the quantity found to be non-compliant that is re-evaluated by the verifier using invoices, operating registers, measuring instruments or process data;

Total quantity reported = Total quantity of greenhouse gas emissions reported and referred to in paragraph 7, 7.3 or 7.4 or total quantity of reference units reported and referred to in paragraph 7.1;

(8)  the conclusions of the verification, in particular regarding accuracy and reliability, of the emissions report;

(9)  a conflict of interest declaration, including

(a)  the name, contact information and sector and sub-sector of activity falling under the scope of the accreditation of the verification organization, as well as the name and contact information of the chief verifier, the person assigned to the internal review of the verification process and the other members of the verification team designated by the organization to carry out the verification;

(b)  a copy of the organization chart for the verification organization, as well as the names of and contact information for any subcontractors who took part in the verification;

(c)  an attestation signed by the representative of the verification organization that the requirements of section 6.10 have been met and that the risk of conflict of interest is acceptable; and

(10)  a written confirmation from the verifier that the calibration of the equipment used to measure the parameters required to calculate the greenhouse gas emissions subject to the verification or the quantity of reference units, according to the requirements provided for in the second paragraph of section 7.1, has been verified.

M.O. 2010-12-06, s. 8; M.O. 2012-09-05, s. 6; M.O. 2012-12-11, s. 14; M.O. 2013-12-11, s. 9; M.O. 2014-12-16, s. 6; M.O. 2015-12-14, s. 3; M.O. 2016-12-21, s. 6; M.O. 2020-12-01, s. 8; M.O. 2022-12-16, s. 6; M.O. 2023-1009, s. 6.

6.10. In addition to the requirements of the standards ISO 14064-3 and ISO 14065 concerning conflicts of interest, the emitter must ensure that none of the following situations exists between the emitter, its officers, the verification organization and the members of the verification team:

(1)  during the 3 years preceding the year of the declaration, one of the members of the verification team was employed by the emitter;

(2)  a member of the verification team or a close relative of that member has personal ties with the emitter or one of its officers;

(3)  during the 3 years preceding the year of the declaration, one of the members of the verification team or one of the subcontractors who took part in the verification provided the emitter with one of the following services:

(a)  the design, development, commissioning or maintenance of a data inventory or data management system for greenhouse gas emissions from an enterprise, establishment or facility of the emitter or, where applicable, for data on electricity or fuel transactions;

(b)  the development of greenhouse gas emission factors or other data that were used for the quantification or the greenhouse gas emissions report and required under this Regulation;

(c)  consultation concerning greenhouse gas emissions reductions, and in particular the design of an energy efficiency or renewable energy project and the assessment of assets relating to greenhouse gas sources;

(d)  the preparation of manuals, guides or procedures connected with the emitter’s greenhouse gas emissions reports;

(e)  consultation in connection with a greenhouse gas emission allowances market, including

i.  brokerage, with or without registration, while acting as a promoter or subscriber on behalf of the emitter;

ii.  advice concerning the suitability of a greenhouse gas emissions transaction;

iii.  the holding, purchase, sale, negotiation or withdrawal of emission allowances referred to in the second paragraph of section 46.6 of the Environment Quality Act (chapter Q-2);

(f)  a consultation in the field of health and safety and environmental management, including the consultation leading to ISO 14001 certification;

(g)  actuarial consulting, bookkeeping or other consulting services relating to accounting documents or financial statements;

(h)  a service connected with the process data management systems covered by the greenhouse gas emissions verification process;

(i)  an internal audit of greenhouse gas emissions;

(j)  a service provided in connection with litigation or an inquiry into greenhouse gas emissions;

(k)  a consultation for a greenhouse gas emissions reduction project or an offset credit project in accordance with the Regulation respecting a cap-and-trade system for greenhouse gas emission allowances (chapter Q-2, r. 46.1);

(4)  the person at the verification organization responsible for carrying out an internal review of the verification process, in accordance with the standards ISO 14065 and ISO 14064-3, has previously provided a verification or other service referred to in subparagraph 3 to the emitter during the report year or the current year.

The existence of one of the situations described in the first paragraph is considered to be a conflict of interest that invalidates the verification report.

For the purposes of this section, a close relative of a member of the verification team is that person’s spouse, child, spouse’s child, mother or father, mother’s or father’s spouse, child’s spouse or spouse’s child’s spouse.

M.O. 2012-12-11, s. 15; M.O. 2017-12-18, s. 7.

6.11. The Minister may determine the quantity of greenhouse gas emissions of an emitter referred to in section 2 or 2.1 of the Regulation respecting a cap-and-trade system for greenhouse gas emission allowances (chapter Q-2, r. 46.1) who has not reported them within the period prescribed or whose report cannot be satisfactorily verified. The Minister must, where applicable, take into account

(1)  the calculation methods provided for in this Regulation pursuant to section 6.3;

(2)  the number of hours during which the establishment or facility emits greenhouse gas;

(3)  the previous reports of the emitter concerned and the verification reports related to them; and

(4)  the quantity of matter, as a mass or volume, that the equipment of the establishment or facility is able to process or produce in a given time.

The verifier of the enterprise, establishment or facility and the emitter concerned must provide to the Minister, at the Minister’s request, any information allowing the Minister to determine the quantity of greenhouse gas emissions of that emitter.

M.O. 2017-12-18, s. 8.

DIVISION II.2 RETENTION OF INFORMATION AND DATA

M.O. 2010-12-06, s. 8.

7. The persons or municipalities to which the provisions of this Regulation apply must retain the required information and the calculations, assessments, measurements and other data on which emission data are based and any other document referred to in this Regulation for a minimum of 7 years from the date on which they were produced and submit them to the Minister on request.

M.O. 2007-09-26, s. 7; M.O. 2010-12-06, s. 9; M.O. 2012-12-11, s. 16; M.O. 2019-12-05, s. 2.

7.1. Any device, system or equipment required under this Regulation must be maintained in good working order and operate optimally during operating hours.

In addition, unless otherwise provided for in one of the protocols in Schedule A.2, the equipment of an emitter referred to in section 6.6 used to measure the parameters required to calculate greenhouse gas emissions subject to the verification or the calculation of the quantity of reference units must be calibrated according to the manufacturer’s instructions in order to maintain accuracy of plus or minus 5%.

If the emitter is unable to obtain the manufacturer’s calibration instructions, the emitter must establish and use a procedure allowing to maintain accuracy of the equipment of plus or minus 5% The procedure must have been certified by an engineer.

M.O. 2010-12-06, s. 10; M.O. 2012-09-05, s. 7; M.O. 2013-12-11, s. 10; M.O. 2019-12-05, s. 3.

DIVISION III MONETARY ADMINISTRATIVE PENALTIES

M.O. 2007-09-26, Div. III; M.O. 2012-12-11, s. 17.

8. A monetary administrative penalty of $250 in the case of a natural person or $1,000 in all other cases may be imposed on any person who

(1)  (paragraph revoked);

(2)  fails to keep any information, documents, calculation, assessment, measurement or data for the time prescribed in section 7;

(3)  in contravention of this Regulation, refuses or neglects to provide any other notice or other information, any study, research or expert report, or any information, report, calculation, plan or other document, or fails to comply with the time limit for providing them, if no monetary administrative penalty is otherwise provided for.

M.O. 2007-09-26, s. 8; S.Q. 2011, c. 20, s. 56; M.O. 2012-12-11, s. 17; M.O. 2014-12-16, s. 7; M.O. 2019-12-05, s. 4.

9. A monetary administrative penalty of $350 in the case of a natural person or $1,500 in all other cases may be imposed on any person who fails to communicate, in the prescribed conditions, any information, notice, attestation or report, as prescribed in one of sections 4, 5, 5.1 or 5.2, the fourth paragraph of section 6 or section 6.1, 6.1.1, 6.1.2, 6.2, 6.4 or 6.5.

M.O. 2007-09-26, s. 9; M.O. 2012-12-11, s. 17; M.O. 2014-12-16, s. 8; M.O. 2020-12-01, s. 9; M.O. 2023-1009, s. 7.

9.1. A monetary administrative penalty of $500 in the case of a natural person or $2,500 in all other cases may be imposed on any person who fails

(1)  to base any information communicated on the best data and best information, in accordance with the first or second paragraph of section 6;

(2)  to calculate the quantities of greenhouse gas emissions reported using once of the methods in section 6.3;

(3)  to carry out a verification referred to in section 6.8 in accordance with the standard prescribed by that section or to include in the verification report the information prescribed by section 6.9.

M.O. 2012-12-11, s. 17.

9.2. A monetary administrative penalty of $750 in the case of a natural person or $3,500 in all other cases may be imposed on any person who fails

(1)  to send to the Minister, within the prescribed time, the verification report referred to in section 6.6, 6.6.1 or 6.7, in accordance with those sections;

(2)  to ensure that none of the situations described in section 6.10 exist, in accordance with that section;

(3)  to maintain any device, system or equipment referred to in section 7.1 in good working order, or to ensure that it operates optimally during operating hours;

(4)  to calibrate equipment in accordance with the second paragraph of section 7 1 or to establish or use a procedure allowing to maintain accuracy of the equipment in accordance with the third paragraph of that section.

M.O. 2012-12-11, s. 17; M.O. 2019-12-05, s. 5.

DIVISION III.1 PENAL PENALTIES

M.O. 2012-12-11, s. 17.

9.3. Any person who contravenes section 7 is guilty of an offence and liable to a fine of

(1)  $1,000 to $100,000, in the case of a natural person;

(2)  $3,000 to $600,000, in all other cases.

Any person who, in contravention of this Regulation, refuses or neglects to provide any other notice or other information, any study, research or expert report, or any information, report, calculation, plan or other document, or fails to comply with the time limit for providing them, is guilty of an offence and liable to the same fines, if no monetary administrative penalty is otherwise provided for.

M.O. 2012-12-11, s. 17; M.O. 2014-12-16, s. 9.

9.4. Any person who contravenes section 4, 5, 5.1 or 5.2, the fourth paragraph of section 6 or section 6.1, 6.1.1, 6.1.2, 6.2, 6.4 or 6.5 is guilty of an offence and liable to a fine of

(1)  $2,000 to $100,000, in the case of a natural person;

(2)  $6,000 to $600,000, in all other cases.

M.O. 2012-12-11, s. 17; M.O. 2014-12-16, s. 10; M.O. 2020-12-01, s. 10; M.O. 2023-1009, s. 8.

9.5. Any person who contravenes the first or second paragraph of section 6, or section 6.3, 6.8 or 6.9, is guilty of an offence and liable to a fine of

(1)  $2,500 to $250,000, in the case of a natural person;

(2)  $7,500 to $1,500,000, in all other cases.

M.O. 2012-12-11, s. 17.

9.6. Any person who contravenes section 6.6, 6.6.1, 6.7, 6.10 or 7.1 is guilty of an offence and liable to a fine of

(1)  $4,000 to $250,000, in the case of a natural person;

(2)  $12,000 to $1,500,000, in all other cases.

M.O. 2012-12-11, s. 17; M.O. 2019-12-05, s. 6.

9.7. (Revoked).

M.O. 2012-12-11, s. 17; M.O. 2022-12-16, s. 7.

DIVISION IV MISCELLANEOUS

10. As of the date on which a contaminant listed in Part I of Schedule A is the subject of a public notice given pursuant to section 46 of the Canadian Environmental Protection Act (1999) (S.C. 1999, c. 33), that contaminant becomes governed by the provisions of section 5 of this Regulation. The reporting threshold applicable for that contaminant is then the reporting threshold provided for in the public notice.

M.O. 2007-09-26, s. 10.

11. (Omitted).

M.O. 2007-09-26, s. 11.

SCHEDULE A

(ss. 1, 4, 5, 10)

Part I

Types	Contaminants		Reporting thresholds
	Identification	CAS(1)
Contaminants that cause toxic pollution	Total fluorides (tF)		10 tons
	Polycyclic aromatic hydrocarbons (PAHs)		50 kg on an annual basis for all the contaminants in the PAH category
	Fluorene	86-73-7
	Phenanthrene	85-01-8
	Anthracene	120-12-7
	Pyrene	129-00-0
	Fluoranthene	206-44-0
	Chrysene	218-01-09
	Benzo (a) anthracene	56-55-3
	Benzo (a) pyrene	50-32-8
	Benzo (e) pyrene	192-97-2
	Benzo (b) fluoranthene	205-99-2
	Benzo (j) fluoranthene	205-82-3
	Benzo (k) fluoranthene	207-08-09
	Benzo (g, h, i) perylene	191-24-2
	Indeno (1, 2, 3, -cd) pyrene	193-39-5
	Dibenzo (a, h) anthracene	53-70-3

Part II

Types	Contaminants		Reporting thresholds(2)
	Identification	CAS(1)
Contaminants that cause acid rain and smog	Sulphur dioxyde	7446-09-05
	Nitrogen oxides	11104-93-1
	Volatile organic compounds
	Carbon monoxide	630-08-0
	Total particulate matter
	PM10
	PM2.5
	Ammonia	7664-41-7
Contaminants that cause toxic pollution	Mercury and its compounds
	Lead and its compounds
	Cadmium and its compounds
	Dioxines
	Furanes
	Benzene	71-43-2
	Hexachlorobenzene	118-74-1
	Formaldehyde	50-00-0
	Arsenic and its compounds
	Hexavalent chromium and its compounds
	Total reduced sulphur(3)

(1) The numbers entered in respect of the contaminants listed in this Schedule correspond to the identification code assigned by the Chemical Abstract Services division of the American Chemical Society.

(2) The reporting threshold applicable for a contaminant in Part II of this Schedule is the reporting threshold provided for that contaminant in the public notice given by the Minister of the Environment of Canada pursuant to section 46 of the Canadian Environmental Protection Act (1999)(S.C. 1999, c. 33).

(3) Expressed in the form of hydrogen sulphide.

M.O. 2007-09-26, Sch. A; M.O. 2010-12-06, s. 11; M.O. 2011-12-16, ss. 9 and 10; M.O. 2012-12-11, s. 18; M.O. 2012-12-11, s. 18; M.O. 2013-12-11, s. 11; M.O. 2019-12-05, s. 7.

SCHEDULE A.1

(ss. 1, 6.1 and 6.2)

Greenhouse gases and global warming potentials

Greenhouse gas - identification	CAS(1)	Global warming potential (GWP)
Carbon dioxide (CO2)	124-38-9	1
Methane (CH4)	74-82-8	25
Nitrous oxide (N2O)	10024-97-2	298
Sulphur hexafluoride (SF6)	2551-62-4	22,800
Hydrofluorocarbons (HFCs)
HFC-23 (CHF3)	75-46-7	14,800
HFC-32 (CH2F2)	75-10-5	675
HFC-41 (CH3F)	593-53-3	92
HFC-43-10mee (C5H2F10)	138495-42-8	1,640
HFC-125 (C2HF5)	354-33-6	3,500
HFC-134 (C2H2F4)	359-35-3	1,100
HFC-134a (C2H2F4)	811-97-2	1,430
HFC-143 (C2H3F3)	430-66-0	353
HFC-143a (C2H3F3)	420-46-2	4,470
HFC-152 (C2H4F2)	624-72-6	53
HFC-152a (C2H4F2)	75-37-6	124
HFC-161 (C2H5F)	353-36-6	12
HFC-227ea (C3HF7)	431-89-0	3,220
HFC-236cb (C3H2F6)	677-56-5	1,340
HFC-236ea (C3H2F6)	431-63-0	1,370
HFC-236fa (C3H2F6)	690-39-1	9,810
HFC-245ca (C3H3F5)	679-86-7	693
HFC-245fa (C3H3F5)	460-73-1	1,030
HFC-365mfc (C4H5F5)	406-58-6	794
Perfluorocarbons (PFCs)
Perfluoromethane (CF4)	75-73-0	7,390
Perfluoroethane (C2F6)	76-16-4	12,200
Perfluoropropane (C3F8)	76-19-7	8,830
Perfluorobutane (C4F10)	355-25-9	8,860
Perfluorocyclobutane (c-C4F8)	115-25-3	10,300
Perfluoropentane (C5F12)	678-26-2	9,160
Perfluorohexane (C6F14)	355-42-0	9,300
Perfluorodecalin (C10F18)	306-94-5	7,500
Perfluorocyclopropane (c-C3F6)	931-91-9	17,340
Nitrogen trifluoride (NF3)	7783-54-2	17,200

(1) The numbers entered in respect of the contaminants listed in this Schedule correspond to the identification code assigned by the Chemical Abstract Services division of the American Chemical Society.

M.O. 2010-12-06, s. 12; M.O. 2011-12-16, s. 11; M.O. 2012-12-11, s. 19; M.O. 2020-12-01, s. 11.

SCHEDULE A.2

(ss. 1, 6.1 and 6.3)

Information to be communicated and methods to be used in calculating greenhouse gas emissions depending on the type of enterprise, facility or establishment operated, the type of activity pursued, and the type of process or equipment used

PROTOCOLS

QC.1. STATIONARY COMBUSTION

QC.1.1. Covered sources

The covered sources are stationary combustion units such as boilers, combustion turbines, engines, incinerators, process heaters, acid gas scrubbing equipment, portable equipment, and any other stationary combustion unit for which this Schedule prescribes no specific requirements.

However, emergency generators and other equipment used in an emergency are not covered.

QC.1.2. Greenhouse gas reporting requirements

In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:

(1) the annual greenhouse gas emissions attributable to the combustion of fossil fuels and biomass fuels, in metric tons, indicating:

(a) CO2 emissions for each type of fuel;

(b) CH4 emissions for each type of fuel; and

(c) N2O emissions for each type of fuel;

(1.1) in the case of emitters referred to in section 6.6, for each benchmark unit, the annual greenhouse gas emissions attributable to each type of fuel, excluding CO2 emissions attributable to the combustion of biomass, in metric tons CO2 equivalent;

(2) the annual consumption of each type of fuel, expressed

(a) in bone dry metric tons, when the quantity is expressed as a mass;

(b) in thousands of cubic metres at standard conditions, when the quantity is expressed as a volume of gas;

(c) in kilolitres, when the quantity is expressed as a volume of liquid;

(d) in metric tons collected, in the case of municipal solid waste;

(3) where carbon content is used to calculate CO2 emissions, the average annual carbon content of each type of fuel;

(3.1) where the molecular weight is used to calculate CO2 emissions, the annual average molecular weight of each type of fuel;

(4) where high heat value is used to calculate CO2 emissions, the average annual high heat value of each type of fuel, expressed

(a) in gigajoules per bone dry metric ton, when the quantity is expressed as a mass;

(b) in gigajoules per thousand cubic metres, when the quantity is expressed as a volume of gas;

(c) in gigajoules per kilolitre, when the quantity is expressed as a volume of liquid;

(d) in gigajoules per metric ton collected, in the case of municipal solid waste;

(5) for stationary combustion units that burn biomass fuels or municipal solid waste, the annual steam generation in metric tons, where it is used to calculate emissions;

(6) in the case of acid gas scrubbing equipment for fluidized bed boilers, the annual quantity of sorbent used, in metric tons;

(7) the annual CO2 emissions attributable to acid gas scrubbing equipment for fluidized bed boilers, in metric tons;

(8) the number of times that the methods for estimating missing data provided for in QC.1.6 were used.

QC.1.3. Calculation methods for CO2 emissions

The annual CO2 emissions attributable to the combustion of fuels in stationary units must be calculated, for each type of fuel, using one of the five calculation methods specified in QC.1.3.1 to QC.1.3.5. However, in the case of an emitter who uses acid gas scrubbing equipment for fluidized bed boilers, the CO2 emissions attributable to that equipment must be calculated using the calculation method specified in  QC.1.3.6.

In addition, when a fuel is not specified in one of Tables 1-1 to 1-8 of QC.1.7, the CO2 emissions attributable to that fuel do not need to be calculated provided they do not exceed 0.5% of the total emissions of the establishment.

QC.1.3.1. Calculation method using the fuel-specific default CO2 emission factor, the default high heat value and the annual fuel consumption

The annual CO2 emissions attributable to the combustion of fuels in stationary units may be calculated using equation 1-1 or 1-1.1

(1) in the case of an emitter not referred to in section 6.6 who uses any type of fuel for which an emission factor is specified in Table 1-2, 1-3, 1-4, 1-5 or 1-6 in QC.1.7 and a high heat value is specified in Table 1-1 or 1-2;

(2) in the case of an emitter referred to in section 6.6 who uses

(a) natural gas with a high heat value that is equal to or greater than 36.3 GJ per thousand cubic metres but less than or equal to 40.98 GJ per thousand cubic metres, with the exception of an emitter using a stationary unit with a design rated heat input capacity that is greater than 264 GJ/h and that has operated for more than 1,000 hours during at least one of the 3 preceding years;

(b) a fuel in Table 1-2;

(c) municipal solid waste when no steam is generated;

(d) a biomass fuel specified in Table 1-3 except if it is targeted by another protocol specified in this Schedule.

However, this method cannot be used by an emitter who determines the high heat value of the fuels used using measurements carried out by the emitter in accordance with QC.1.5.4 or using data indicated by the fuel supplier, obtained at the frequency prescribed by QC.1.5.1.

Equation 1-1

CO2 = Fuel × HHV × EF × 0.001

Where:

CO2 = Annual CO2 emissions attributable to the combustion of each type of fuel, in metric tons;

Fuel = Mass or volume of the fuel combusted during the year, expressed

— in bone dry metric tons, when the quantity is expressed as a mass;

— in thousands of cubic metres at standard conditions, when the quantity is expressed as a volume of gas;

— in kilolitres, when the quantity is expressed as a volume of liquid;

— in metric tons collected, in the case of municipal solid waste;

HHV = High heat value of the fuel specified in Tables 1-1 and 1-2, expressed

— in gigajoules per bone dry metric ton, in the case of a fuel whose quantity is expressed as a mass;

— in gigajoules per thousand cubic metres, in the case of a fuel whose quantity is expressed as a volume of gas;

— in gigajoules per kilolitre, in the case of a fuel whose quantity is expressed as a volume of liquid;

— in gigajoules per metric ton collected, in the case of municipal solid waste;

EF = CO2 emission factor for the fuel specified in Table 1-2, 1-3, 1-4, 1-5 or 1-6, in kilograms of CO2 per gigajoule;

0.001 = Conversion factor, kilograms to metric tons;

Equation 1-1.1

CO2 = Fuel × OEF

Where:

CO2 = Annual CO2 emissions attributable to the combustion of each type of fuel, in metric tons;

Fuel = Mass or volume of the fuel combusted during the year, expressed

— in bone dry metric tons, when the quantity is expressed as a mass;

— in thousands of cubic metres at standard conditions, when the quantity is expressed as a volume of gas;

— in kilolitres, when the quantity is expressed as a volume of liquid;

— in metric tons collected, in the case of municipal solid waste;

OEF = Overall CO2 emission factor for the fuel, as specified in Table 1-3, 1-4 or 1-5, expressed

— in kilograms of CO2 per bone dry kilogram, in the case of a fuel whose quantity is expressed as a mass;

— in kilograms of CO2 per cubic metres at standard conditions, in the case of a fuel whose quantity is expressed as a volume of gas;

— in kilograms of CO2 per litre, in the case of a fuel whose quantity is expressed as a volume of liquid;

— in kilograms of CO2 per kilogram collected, in the case of municipal solid waste.

QC.1.3.2. Calculation method using the fuel-specific default CO2 emission factor and the high heat value indicated by the fuel supplier or determined by the emitter

The annual CO2 emissions attributable to the combustion of fuels in stationary units may be calculated

(1) in the case of an emitter not referred to in section 6.6 who uses

(a) any type of fuel other than municipal solid waste, for which an emission factor is specified in Table 1-2, 1-3, 1-4, 1-5 or 1-6 in QC.1.7, using equation 1-2;

(b) municipal solid waste and any biomass solid fuel specified in Table 1-3 in QC.1.7, when the combustion of the fuel produces steam, using equation 1-3;

(2) in the case of an emitter referred to in section 6.6 who uses natural gas or biomethane with a high heat value that is equal to or greater than 36.3 GJ per thousand cubic metres but less than or equal to 40.98 GJ per thousand cubic metres or who uses a fuel in Table 1-2 or a biomass fuel, using equation 1-2.

Equation 1-2

Where:

CO2 = Annual CO2 emissions attributable to the combustion of each type of fuel, in metric tons;

n = Number of measurements of high heat value required annually, as specified in QC.1.5.1;

i = Measurement period;

Fueli = Mass or volume of fuel combusted during measurement period i, expressed

— in bone dry metric tons, when the quantity is expressed as a mass;

— in thousands of cubic metres at standard conditions, when the quantity is expressed as a volume of gas;

— in kilolitres, when the quantity is expressed as a volume of liquid;

HHVi = High heat value of the fuel for measurement period i, expressed

— in gigajoules per bone dry metric ton, in the case of a fuel whose quantity is expressed as a mass;

— in gigajoules per thousand cubic metres, in the case of a fuel whose quantity is expressed as a volume of gas;

— in gigajoules per kilolitre, in the case of a fuel whose quantity is expressed as a volume of liquid;

EF = CO2 emission factor for the fuel as specified in Table 1-2, 1-3, 1-4, 1-5 or 1-6, in kilograms of CO2 per gigajoule;

0.001 = Conversion factor, kilograms to metric tons;

Equation 1-3

CO2 = Steam × B × EF × 0.001

Where:

CO2 = Annual CO2 emissions attributable to the combustion of each type of biomass solid fuel or municipal solid waste, in metric tons;

Steam = Total quantity of steam produced during the year by the combustion of biomass solid fuel or municipal solid waste, in metric tons;

B = Ratio of the boiler’s design rated heat input capacity to its design rated steam output capacity, in gigajoules per metric ton of steam;

EF = CO2 emission factor for biomass solid fuel or municipal solid waste specified in Table 1-3 or 1-6, or an establishment-specific factor determined in accordance with QC.1.5.3, in kilograms of CO2 per gigajoule;

0.001 = Conversion factor, kilograms to metric tons.

QC.1.3.3. Calculation method using the quantity of fuel combusted and the carbon content indicated by the fuel supplier or measured by the emitter

The annual CO2 emissions may be calculated using the following methods:

(1) for fuels whose quantity is expressed as a mass, other than municipal solid waste, the emitter must use equation 1-4 and, for biomass solid fuel if steam is generated, equation 1-4 or 1-5:

Equation 1-4

Where:

CO2 = Annual CO2 emissions attributable to the combustion of each type of solid fuel, in metric tons;

n = Number of measurements of carbon content required annually as specified in QC.1.5.1;

i = Measurement period;

Fueli = Bone dry mass of solid fuel combusted during measurement period i, in metric tons;

CCi = Average carbon content of the fuel whose quantity is expressed as a mass, from the fuel analysis results for the measurement period i indicated by the fuel supplier or measured by the emitter in accordance with QC.1.5.5, in kilograms of carbon per kilogram of fuel;

3.664 = Ratio of molecular weights, CO2 to carbon.

(2) for municipal solid waste if steam is generated, the emitter must use equation 1-5:

Equation 1-5

CO2 = Stream × B × EF × 0.001

Where:

CO2 = Annual CO2 emissions attributable to the combustion of each type of biomass solid fuel or municipal solid waste, in metric tons;

Steam = Total quantity of steam produced during the year by the combustion of biomass solid fuel or municipal solid waste, in metric tons;

B = Ratio of the boiler’s design rated heat input capacity to its design rated steam output capacity, in gigajoules per metric ton of steam;

EF = CO2 emission factor of biomass solid fuel or municipal solid waste indicated by the fuel supplier, established by the emitter in accordance with QC.1.5.3 or specified in Table 1-3 or 1-6 in QC.1.7, in kilograms of CO2 per gigajoule;

0.001 = Conversion factor, kilograms to metric tons.

(3) for fuels whose quantity is expressed as a volume of liquid, the emitter must use equation 1-6:

Equation 1-6

Where:

CO2 = Annual CO2 emissions attributable to the combustion of each type of fuel whose quantity is expressed as a volume of liquid, in metric tons;

n = Number of measurements of carbon content required annually as specified in QC.1.5.1;

i = Measurement period;

Fueli = Volume of fuel combusted during the measurement period i, in kilolitres;

CCi = Average carbon content of the liquid fuel, from the fuel analysis results for the measurement period i indicated by the fuel supplier or measured by the emitter in accordance with QC.1.5.5, in metric tons of carbon per kilolitre of fuel;

3.664 = Ratio of molecular weights, CO2 to carbon.

(4) for fuels whose quantity is expressed as a volume of gas, the emitter must use equation 1-7:

Equation 1-7

Where:

CO2 = Annual CO2 emissions attributable to the combustion of each type of fuel whose quantity is expressed as a volume of gas, in metric tons;

n = Number of measurements of carbon content and molecular weight required annually, as specified in QC.1.5.1;

i = Measurement period;

Fueli = Volume of gaseous fuel combusted during measurement period i, in thousands of cubic metres at standard conditions;

CCi = Average carbon content of the gaseous fuel, from the fuel analysis results for the measurement period i indicated by the fuel supplier or measured by the emitter in accordance with QC.1.5.5, in kilograms of carbon per kilogram of fuel;

MW = Molecular weight of the gaseous fuel, established in accordance with QC.1.5.5 from the fuel analysis results, in kilograms per kilomole or, when a mass flowmeter is used to measure the flow in kilograms per unit of time, replace

 _  _
|    |
| MW |
|----| by 1;
|MVC |
|_  _|                        

MVC = Molar volume conversion factor (24.06 m3 per kilomole at standard conditions);

3.664 = Ratio of molecular weights, CO2 to carbon;

1 = Conversion factor, kilograms to metric tons and thousands of cubic metres to cubic metres;

(5) in the case of a mixture of fuels, the emitter may use equations 1-4 to 1-6, using the average carbon content of the mixture of fuels measured by the emitter in accordance with QC.1.5, but the emitter must declare annual emissions of CO2 per type of fuel in accordance with QC.1.2.

QC.1.3.4. Calculation method using data from a continuous emission monitoring and recording system

The annual CO2 emissions attributable to the combustion any type of fuel used in stationary combustion units may be calculated using data from a continuous emission monitoring and recording system including a stack gas volumetric flow rate monitor and a CO2 concentration monitor, in accordance with the EPS 1/PG/7 protocol entitled “Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation” published in November 2005 by Environment Canada, or, in the case of an emitter not referred to in section 6.6, in accordance with the manufacturer’s specifications.

An oxygen concentration monitor may, however, be used instead of a CO2 concentration monitor if the following conditions are met:

(1) the continuous emission monitoring and recording system was installed before 1 January 2012;

(2) the gas effluent contains only the products of combustion;

(3) only the following fuels, that are not waste-derived fuels, are combusted: coal, petroleum coke, light or heavy oil, natural gas, propane, butane or wood waste.

When a continuous emission monitoring and recording system is used in connection with a stationary combustion unit, the CO2 emissions of all the fuels combusted must be calculated using data from the system.

The use of a continuous emission monitoring and recording system must take into account the particularities of each type of fuel used and meet the following requirements:

(1) for units that combust fossil fuels or biomass fuels, the emitter must

(a) use CO2 or, if applicable, oxygen concentrations and stack gas flow rate measurements to determine hourly CO2 emissions;

(b) report annual CO2 emissions, in metric tons, based on the sum of hourly CO2 emissions over the year;

(c) if the emitter combusts biomass fuels in the units and uses oxygen concentrations to calculate CO2, concentrations, demonstrate that the CO2 concentrations calculated correspond to the CO2 concentrations measured after verification of their relative accuracy in accordance with the SPE 1/PG/7 protocol;

(2) for units that combust waste-derived fuels and units that combust both fossil fuels and biomass fuels or waste-derived fuels that are partly biomass, the emitter must

(a) use CO2 concentrations and stack gas flow rate measurements to determine hourly CO2 emissions;

(b) report annual CO2 emissions, in metric tons, based on the sum of hourly CO2 emissions over the year;

(c) determine separately the portion of total CO2 emissions attributable to the combustion of biomass contained in the fuel using the calculation methods in QC.1.3.5;

(3) when the facility or establishment is equipped with a continuous CO2 monitoring system and when the emitter must, in accordance with this Regulation, report emissions by type, namely combustion, fixed process or “other” category, the emitter must, for each type of emission,

(a) estimate the greenhouse gas emissions attributable to combustion and the “other” category emissions using the emission factors in tables 1-1 to 1-8 in QC.1.7. If no factor is indicated in the tables, the emitter may use a factor published by Environment Canada, the U.S. Environmental Protection Agency (USEPA), the Intergovernmental Panel on Climate Change (IPCC), the National Council for Air and Stream Improvement (NCASI) or the World Business Council for Sustainable Development (WBCSD);

(b) determine the annual greenhouse gas emissions attributable to the fixed process by subtracting from the data measured by the continuous CO2 monitoring system the greenhouse gas emissions attributable to combustion and the “other” category emissions estimated in accordance with subparagraph a.

QC.1.3.5. Calculation method for the CO2 emissions attributable to the biomass portion of a fuel or mixture of fuels

An emitter who uses stationary combustion units that combust fuels or mixtures of fuels containing biomass must calculate the CO2 emissions of the biomass portion as follows:

(1) when the biomass portion is known and the mixture does not contain waste-derived fuels that are partly biomass, an emitter who

(a) does not use a continuous emission monitoring and recording system to measure the concentration of CO2, must use the applicable equations in QC.1.3.1 to QC.1.3.3 to calculate the CO2 emissions attributable to the combustion of biomass;

(b) uses a continuous emission monitoring and recording system to measure the concentration of CO2, must use the applicable equations in QC.1.3.1 to QC.1.3.3 to calculate the CO2 emissions attributable to the combustion of fossil fuels, and subtract the portion of CO2 emissions attributable to the combustion of fossil fuels from the total emissions in order to determine the emissions attributable to the combustion of biomass;

(2) when the biomass portion is not known, or when no emission factor is specified in Table 1-2 in QC.1.7, the emitter must, except for fuels containing less than 5% of biomass by weight or waste-derived fuels making up less than 30% by weight of the fuels combusted during the year:

(a) use the applicable equations in QC.1.3.1 to QC.1.3.4 to calculate the total CO2 emissions;

(b) determine the biomass portion of the fuels in accordance with the most recent version of ASTM D6866 “Standard Test Methods for Determining the Biobased Content of Solid, Liquid, and Gaseous Samples Using Radiocarbon Analysis”, or using any other analysis method published by an organization listed in QC.1.5;

(c) conduct, at least every 3 months, an analysis on a representative fuel or exhaust gas sample in accordance with the most recent version of ASTM D6866 or using any other analysis method published by an organization listed in QC.1.5, the analysis being conducted on the exhaust gas stream when waste-derived fuels are combusted;

(c.1) when the exhaust gas stream is sampled, collect samples over a period of at least 24 consecutive hours in accordance with the most recent version of ASTM D7459 “Standard Practice for Collection of Integrated Samples for the Speciation of Biomass (Biogenic) and Fossil-Derived Carbon Dioxide Emitted from Stationary Emissions Sources”, or using any other analysis method published by an organization listed in QC.1.5;

(d) divide total CO2 emissions between CO2 emissions attributable to the combustion of biomass fuels and CO2 emissions attributable to the combustion of nonbiomass fuels using the average proportions of the samples analyzed during the year;

(e) make the measurements in accordance with the most recent version of ASTM D6866 on the stationary combustion unit of the emitter’s choice if there is a common fuel source for multiple units or using any other analysis method published by an organization listed in QC.1.5;

(3) when equation 1-1, 1-1.1, 1-2 or 1-4 is used to calculate the CO2 emissions attributable to the combustion of biomass solid fuels, equation 1-8 may be used to quantify the consumption of biomass solid fuels:

Equation 1-8

                      __         __
                     |             |
                     | Hi × Steami  | - Ei
                     |__         __|        
     Biomass fuel1 = ____________________
                           HHV × Eff                        

Where:

Biomass fueli = Quantity of biomass fuel combusted during measurement period i, in metric tons;

Hi = Average enthalpy of the boiler for measurement period i, in gigajoules per metric ton of steam;

Steami = Total quantity of steam produced during measurement period i, in metric tons;

Ei = Total energy input of all fuels other than biomass fuels combusted during measurement period i, in gigajoules;

hhv = High heat value of the biomass fuel specified in Table 1-1 or determined by the emitter, in gigajoules per metric ton;

Eff = Energy efficiency of the biomass fuel, expressed as a percentage;

(4) when the emitter is a municipality, the biomass portion of the waste may be established using an alternative method such as waste characterization.

QC.1.3.6. Calculation method for CO2 emissions attributable to acid gas scrubbing equipment for fluidized bed boilers

The annual CO2 emissions attributable to acid gas scrubbing equipment for fluidized bed boilers must be calculated using a continuous emission monitoring and recording system in accordance with QC.1.3.4 or using equation 1-9:

Equation 1-9

                     _   _
                    | 44  |
     CO2 = QS × R × |_____|
                    | MMS |
                    |_   _|                        

Where:

CO2 = Annual CO2 emissions attributable to the acid gas scrubbing equipment for fluidized bed boilers, in metric tons;

QS = Annual quantity of sorbent used, in metric tons;

R = Ratio of moles of CO2 released upon capture of 1 mole of acid gas;

44 = Molecular weight of CO2, in kilograms per kilomole;

MMs = Molecular weight of sorbent, in kilograms per kilomole or, in the case of calcium carbonate, a value of 100.

QC.1.4. Calculation methods for CH4 and N2O emissions

The annual CH4 and N2O emissions attributable to the combustion of fuels in stationary units must be calculated, for each type of fuel, using the methods in QC.1.4.1 to QC.1.4.5.

However, when a fuel is not specified in one of Tables 1-1 to 1-8 of QC.1.7, the CH4 and N2O emissions attributable to that fuel do not need to be calculated.

QC.1.4.1. Calculation method using a default CH4 and N2O emission factor and the default high heat value for the fuel

The annual CH4 and N2O emissions attributable to the combustion of a fuel whose high heat value is not determined by the measurements made by the emitter or the data provided by the fuel supplier for the purpose of calculating CO2 emissions may be calculated using equation 1-10 or 1-10.1:

(1) in the case of an emitter not referred to in section 6.6 who uses any type of fuel for which an emission factor is specified in Table 1-3, 1-6 or 1-7 in QC.1.7 and a high heat value is specified in Table 1-1 or 1-2;

(2) in the case of an emitter referred to in section 6.6 who uses either

(a) natural gas with a high heat value that is equal to or greater than 36.3 GJ per thousand cubic metres but less than or equal to 40.98 GJ per thousand cubic metres; or

(b) a fuel in Table 1-2 or a biomass fuel.

In the case of any emitter, the emissions attributable to the combustion of coal must be calculated using equation 1-11.

Equation 1-10

CH4 or N2O = Fuel × HHV × EF × 0.000001

Where:

CH4 or N2O = Annual CH4 or N2O emissions attributable to the combustion of each type of fuel, in metric tons;

Fuel = Mass or volume of the fuel combusted during the year, expressed

— in bone dry metric tons, when the quantity is expressed as a mass;

— in thousands of cubic metres at standard conditions, when the quantity is expressed as a volume of gas;

— in kilolitres, when the quantity is expressed as a volume of liquid;

— in metric tons collected, in the case of municipal solid waste;

HHV = High heat value of the fuel specified in Table 1-1 and 1-2, expressed

— in gigajoules per bone dry metric ton, in the case of a fuel whose quantity is expressed as a mass;

— in gigajoules per thousand cubic metres, in the case of a fuel whose quantity is expressed as a volume of gas;

— in gigajoules per kilolitre, in the case of a fuel whose quantity is expressed as a volume of liquid;

— in gigajoules per metric ton collected, in the case of municipal solid waste;

EF = CH4 or N2O emission factor for the fuel established by the emitter in accordance with QC.1.5.3, emission factor for the fuel as specified in Table 1-3, 1-6 or 1-7, or emission factor from the document “AP-42, Compilation of Air Pollutant Emission Factors” published by the U.S. Environmental Protection Agency (USEPA), in grams of CH4 or N2O per gigajoule;

0.000001 = Conversion factor, grams to metric tons;

Equation 1-10.1

CH4 or N2O = Fuel × OEF × 0.001

Where:

CH4 or N2O = Annual CH4 or N2O emissions attributable to the combustion of each type of fuel, in metric tons;

Fuel = Mass or volume of the fuel combusted during the year, expressed

— in bone dry metric tons, when the quantity is expressed as a mass;

— in thousands of cubic metres at standard conditions, when the quantity is expressed as a volume of gas;

— in kilolitres, when the quantity is expressed as a volume of liquid;

— in metric tons collected, in the case of municipal solid waste;

OEF = Overall CH4 or N2O emission factor for the fuel, as specified in Table 1-3, 1-7 or 1-8, expressed

— in grams of CH4 or N2O per kilogram, in the case of a fuel whose quantity is expressed as a mass;

— in grams of CH4 or N2O per cubic metre at standard conditions, in the case of a fuel whose quantity is expressed as a volume of gas;

— in grams of CH4 or N2O per litre in the case of a fuel whose quantity is expressed as a volume of liquid;

0.001 = Conversion factor, kilograms to metric tons;

Equation 1-11

CH4 or N2O = Fuel × EFc × 0.001

Where:

CH4 or N2O = Annual CH4 or N2O emissions attributable to the combustion of coal, in metric tons;

Fuel = Mass of coal combusted during the year, in metric tons;

EFc = CH4 or N2O emission factor for the coal established by the emitter in accordance with QC.1.5.3 or emission factor for the coal specified in Table 1-8, in grams of CH4 or N2O per kilogram of coal;

0.001 = Conversion factor, kilograms to metric tons.

QC.1.4.2. Calculation method using a high heat value determined from data provided by the fuel supplier or measurements made by the emitter

When the high heat value of the fuel is determined from data provided by the fuel supplier or measurements made by the emitter in order to estimate CO2,the annual CH4 or N20 emissions for the fuels must be calculated using equation 1-12, subject to the emissions attributable to the combustion of coal which must be calculated using equation 1-13:

Equation 1-12

Where:

CH4 or N2O = Annual CH4 or N2O emissions attributable to each type of fuel, in metric tons;

n = Number of measurements of high heat value required annually, as specified in QC.1.5.1;

i = Measurement period;

Fueli = Mass or volume of fuel combusted during measurement period i, expressed

— in bone dry metric tons, when the quantity is expressed as a mass;

— in thousands of cubic metres at standard conditions, when the quantity is expressed as a volume of gas;

— in kilolitres, when the quantity is expressed as a volume of liquid;

— in metric tons collected, in the case of municipal solid waste;

HHVi = High heat value determined from data provided by the fuel supplier or measurements made by the emitter for the measurement period i in accordance with QC.1.5.4, for each type of fuel, expressed

— in gigajoules per bone dry metric ton, in the case of a fuel whose quantity is expressed as a mass;

— in gigajoules per thousand cubic metres, in the case of a fuel whose quantity is expressed as a volume of gas;

— in gigajoules per kilolitre, in the case of a fuel whose quantity is expressed as a volume of liquid;

— in gigajoules per metric ton collected, in the case of municipal solid waste;

EF = CH4 or N2O emission factor for the fuel established by the emitter in accordance with QC.1.5.3, emission factor for the fuel as specified in Table 1-3 or 1-7 in QC.1.7, or emission factor from the document “AP-42, Compilation of Air Pollutant Emission Factors” published by the U.S. Environmental Protection Agency (USEPA), in grams of CH4 or N2O per gigajoule;

0.000001 = Conversion factor, grams to metric tons;

Equation 1-13

Where:

CH4 or N2O = Annual CH4 or N2O emissions attributable to the combustion of coal, in metric tons;

n = Number of measurements required annually, as specified in QC.1.5.1;

i = Measurement period;

Fueli = Mass of coal combusted during measurement period i, in metric tons;

EFc = CH4 or N2O emission factor for the coal indicated by the fuel supplier or established by the emitter in accordance with QC.1.5.3, in grams of CH4 or N2O per kilogram of coal;

0.001 = Conversion factor, grams to metric tons.

QC.1.4.3. Calculation method for emissions attributable to the combustion of biomass, biomass fuels or municipal solid waste

The annual CH4 ou N2O emissions attributable to the combustion of biomass, biomass fuels or municipal solid waste must be calculated using equation 1-14 when CO2 emissions are calculated using equations 1-3 and 1-5:

Equation 1-14

CH4 or N20 = Steam × B × EF × 0.000001

Where:

CH4 or N2O = Annual CH4 or N2O emissions attributable to the combustion of biomass, biomass fuels or municipal solid waste, in metric tons;

Steam = Total quantity of steam produced during the year by the combustion of biomass, biomass fuels or municipal solid waste, in metric tons;

B = Ratio of the boiler’s design rated heat input capacity to its design rated steam output capacity, in gigajoules per metric ton of steam;

EF = CH4 or N2O emission factor for the biomass, biomass fuel or municipal solid waste established by the emitter in accordance with QC.1.5.3 or emission factor for the fuel specified in Table 1-3, 1-6 or 1-7 specified in QC.1.7, in grams of CH4 or N2O per gigajoule;

0.000001 = Conversion factor, grams to metric tons.

QC.1.4.4. Calculation method using a default CH4 and N2O emission factor and the energy input of the fuel determined by the emitter

The annual CH4 and de N2O emissions attributable to the combustion of a fuel must be calculated using equation 1-15 when the CO2 emissions for that fuel are calculated using a continuous emission monitoring and recording system in accordance with QC.1.3.4 and the energy input for the fuel is determined by the emitter using data from the system:

Equation 1-15

CH4 or N2O = E × EF × 0.000001

Where:

CH4 or N2O = Annual CH4 or N2O emissions attributable to the combustion of each fuel, in metric tons;

E = Energy input of each fuel determined using data from a continuous emission monitoring and recording system, in gigajoules;

EF = CH4 or N2O emission factor for the fuel specified in Table 1-3, 1-7 or 1-8 in QC.1.7, in grams of CH4 or N2O per gigajoule;

0.000001 = Conversion factor, grams to metric tons.

QC.1.4.5. Calculation method using data from a continuous emission monitoring and recording system

The annual CH4 or N2O emissions attributable to the combustion of any type of fuel used in stationary combustion units may be calculated using data from a continuous emission monitoring and recording system including a gas volumetric flow rate monitor and a CH4 or N2O concentration monitor, in accordance with the EPS 1/PG/7 protocol entitled “Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation” published in November 2005 by Environment Canada or, in the case of an emitter not referred to in section 6.6, in accordance with the manufacturer’s specifications.

QC.1.5. Sampling, analysis and measurement requirements

In the cases provided for in this protocol, the emitter may use the analysis methods published by the following organizations:

(1) American Society for Testing and Materials (ASTM);

(2) Centre d’Expertise en Analyse Environnementale du Québec (CEAEQ);

(3) Environment Canada;

(4) U.S. Environmental Protection Agency (USEPA);

(5) International Organization for Standardization (ISO);

(6) Technical Association of the Pulp and Paper Industry: Industry Standards & Regulations (TAPPI);

(7) Canadian Standards Association;

(8) Measurement Canada;

(9) American Association of State Highway and Transportation Officials (AASHTO);

(10) Association française de normalisation (AFNOR);

(11) Association of Fertilizer and Phosphate Chemists (AFPC);

(12) American Petroleum Institute (API);

(13) ASM International (ASM);

(14) British Standard Institution (BS);

(15) Gas Processors Association (GPA).

QC.1.5.1. Frequency of fuel sampling

When a calculation method requires an emitter to determine the carbon content, high heat value or emission factor of a fuel, the emitter must sample the fuel or obtain sampling results from the supplier for the fuel

(1) annually, for biomass fuels and waste-derived fuels for which the CO2 emissions are calculated using equations 1-2 and 1-4;

(2) semi-annually, for natural gas and biomethane;

(3) quarterly, for fuels specified in Table 1-2 in QC.1.7, liquid fuels, gaseous fuels, gases derived from biomass and biogas produced from landfill gas or from wastewater treatment or agricultural processes;

(4) monthly, for solid fuels except coal and waste-derived fuels, as specified below:

(a) the sample is a monthly composite of four weekly samples of equal mass, collected each week during the month of operation, which samples are taken after all fuel treatment operations but before fuel mixing to ensure that the samples are representative of the chemical and physical characteristics of the fuel immediately prior to combustion;

(b) the monthly composite sample is homogenised and well mixed prior to withdrawal and analysis;

(c) one in twelve monthly composite samples is randomly selected for additional analysis of its discrete constituent samples to ensure the homogeneity of the composite sample;

(4.1) monthly, in accordance with subparagraphs a to c of paragraph 4, or at each delivery in the case of coal;

(5) at each delivery in the case of any fuel that is not referred to in paragraphs 1 to 4.1;

(6) monthly, in accordance with subparagraphs a to c of paragraph 4, in the case of a mixture of fuels.

Despite subparagraphs 4, 4.1, 5 and 6 of the first paragraph, in the case of solid fuels or mixtures of fuels used in an electric arc furnace or a clinker kiln, the emitter may do the fuel sampling or use the sampling results of the supplier provided that the sampling is composed of at least 3 representative samples per year.

QC.1.5.2. Fuel consumption

An emitter who operates a facility or establishment where a stationary combustion unit is used must

(1) calculate fuel consumption by fuel type

(a) by measuring it directly;

(b) using recorded fuel purchases or sales invoices for each type of combustible measuring any stock change, in megajoules, litres, millions of cubic metres at standard conditions, metric tons or bone dry metric tons, using the following equation:

Fuel Consumption in a given Report Year = Total Fuel Purchases – Total Fuel Sales + Amount Stored at Beginning of Year – Amount Stored at Year End

(c) for fuel oil when no purchase took place during the year, tank drop measurements may also be used;

(d) in the case of an emitter that uses equation 1-2 or 1-4 to calculate CO2 emissions or equation 1-10, 1-10.1 or 1-12 to calculate CH4 and N2O emissions, by using equation 1-8 in the case of biomass fuels;

(2) convert fuel consumption in megajoules into one of the measurement units given in subparagraph b of paragraph 1 using the high heat value of the fuel determined using measurements carried out in accordance with QC.1.5.4, the high heat value indicated by the supplier or the high heat value specified in Table 1-1 specified in QC.1.7;

(3) calibrate, before the first emissions report using the calculation methods in QC.1 and thereafter annually or at the minimum frequency specified by the manufacturer, all flowmeters for liquid and gaseous fuels, except those used to bill gas, using one of the flow meter tests listed in Table 1-9 or the calibration procedures specified by the flow meter manufacturer.

For the application of the formula provided for in subparagraph b of subparagraph 1 of the first paragraph, in the case of a solid fuel, the volumetric mass used to determine the variation in inventory must be measured in accordance with an analysis method published by an organization listed in QC.1.5.

Fuel flow meters that measure mass flow rates may be used for liquid fuels, provided that the fuel density is used to convert the readings to volumetric flow rates. The density must in such cases be measured at the same frequency as the carbon content using the most recent version of method ASTM D1298, “Standard Test Method for Density, Relative Density (Specific Gravity), or API Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method”, or any other analysis method published by an organization listed in QC.1.5. An emitter using one of the methods specified in QC.1.3.1 or QC.1.3.2 may, however, use the mass flow specified in Table 1-10 in QC.1.7.

QC.1.5.3. Fuel emission factors

The emitter must establish emission factors using the following methods:

(1) when CO2 emissions are calculated using the method in QC.1.3.3 (2), the emission factor must be established in kilograms of CO2 per gigajoule and adjusted at least every 3 years through a stack test measurement of CO2 and use of the applicable ASME Performance Test Code published by the American Society of Mechanical Engineers (ASME) to determine heat input from all heat outputs, including the steam, exhaust gas streams, ash and losses;

(2) when CH4 or N2O emissions are calculated using emission factors based on source tests, the source test procedures must be repeated in subsequent years to update the emissions factors for the stationary combustion unit.

QC.1.5.4. High heat value of the fuel

The emitter must determine the average annual high heat value using equation 1-16:

Equation 1-16

Where:

HHVa = Average annual high heat value, expressed

— in gigajoules per bone dry metric ton, in the case of a fuel whose quantity is expressed as a mass;

— in gigajoules per thousand cubic metres, in the case of a fuel whose quantity is expressed as a volume of gas;

— in gigajoules per kilolitre, in the case of a fuel whose quantity is expressed as a volume of liquid;

— in gigajoules per metric ton collected, in the case of municipal solid waste;

n = Number of measurements of high heat value;

i = Measurement period;

HHVi = High heat value for the measurement period i, expressed

— in gigajoules per bone dry metric ton, in the case of a fuel whose quantity is expressed as a mass;

— in gigajoules per thousand cubic metres, in the case of a fuel whose quantity is expressed as a volume of gas;

— in gigajoules per kilolitre, in the case of a fuel whose quantity is expressed as a volume of liquid;

— in gigajoules per metric ton collected, in the case of municipal solid waste;

Fueli = Mass or volume of fuel combusted during measurement period i, expressed

— in bone dry metric tons, when the quantity is expressed as a mass;

— in thousands of cubic metres at standard conditions, when the quantity is expressed as a volume of gas;

— in kilolitres, when the quantity is expressed as a volume of liquid;

— in metric tons collected, in the case of municipal solid waste.

The emitter must determine high heat value using the sampling and analysis results indicated by the fuel supplier or the results of the sampling conducted by the emitter and using one of the following methods:

(1) for gases:

(a) in accordance with the most recent version of ASTM D1826 “Standard Test Method for Calorific (Heating) Value of Gases in Natural Gas Range by Continuous Recording Calorimeter”, ASTM D3588 “Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuels”, and ASTM D4891 “Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion”, and GPA 2261 “Analysis for natural gas and similar gaseous mixtures by gas chromatography” published by the Gas Processors Association (GPA), or using any other analysis method published by an organization listed in QC.1.5;

(b) by determining high heat value to within ± 5% using a continuous emission monitoring and recording system;

(c) when the continuous emission monitoring and recording system provides only low heat value, by converting the value to high heat value using equation 1-17:

Equation 1-17

HHV = LHV × CF

Where:

HHV = High heat value of the fuel or fuel mixture, in gigajoules per thousand cubic metres at standard conditions;

LHV = Low heat value of the fuel or fuel mixture, in gigajoules per thousand cubic metres at standard conditions;

CF = Conversion factor for converting low heat value to high heat value, established as follows:

(a) for natural gas and biomethane, the emitter must use a CF of 1.11;

(b) for refinery fuel gas, flexigas, associated gas or gas mixtures, the emitter must establish the weekly average FC as follows:

— using the low heat value measurements and the high heat value obtained by the continuous emission monitoring and recording system or by laboratory analysis as part of the daily carbon content determination;

— using the HHV/LHV ratio obtained from the laboratory analysis of the daily samples;

(2) for middle distillates, fuel oil and liquid waste-derived fuels, in accordance with the most recent version of ASTM D240 “Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter”, or ASTM D4809 “Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method)”, or using any other analysis method published by an organization listed in QC.1.5;

(3) for biomass solid fuel, in accordance with the most recent version of ASTM D5865 “Standard Test Method for Gross Calorific Value of Coal and Coke”, or using any other analysis method published by an organization listed in QC.1.5;

(4) for waste-derived fuels, in accordance with the most recent version of ASTM D5865 or ASTM D5468 “Standard Test Method for Gross Calorific and Ash Value of Waste Materials”, or using any other analysis method published by an organization listed in QC.1.5 and, when the waste-derived fuels are not pure biomass fuels, by calculating the biomass fuel portion of CO2 emissions in accordance with QC.1.3.5.

QC.1.5.5. Carbon content, molecular weight and molar fraction of fuel

The emitter must determine the average annual carbon content using equation 1-18:

Equation 1-18

Where:

CCa = Average annual carbon content, expressed

— in kilograms of carbon per bone dry kilogram, in the case of a fuel whose quantity is expressed as a mass;

— in kilograms of carbon per kilogram, in the case of a fuel whose quantity is expressed as a volume of gas;

— in metric tons of carbon per kilolitre, in the case of a fuel whose quantity is expressed as a volume of liquid;

n = Number of measurements of carbon content;

i = Measurement period;

CCi = Carbon content of the fuel for the measurement period i, expressed

— in kilograms of carbon per bone dry kilogram, in the case of a fuel whose quantity is expressed as a mass;

— in kilograms of carbon per kilogram, in the case of a fuel whose quantity is expressed as a volume of gas;

— in metric tons of carbon per kilolitre, in the case of a fuel whose quantity is expressed as a volume of liquid;

Fueli = Mass or volume of fuel combusted during measurement period i, expressed

— in bone dry metric tons, when the quantity is expressed as a mass;

— in thousands of cubic metres at standard conditions, when the quantity is expressed as a volume of gas;

— in kilolitres, when the quantity is expressed as a volume of liquid.

The carbon content and molecular weight or molar fraction must be determined using the sampling and analysis results indicated by the fuel supplier or the results of the sampling conducted by the emitter using one of the following methods:

(1) for solid fuels, namely coal, coke, biomass solid fuels and waste-derived fuels, in accordance with the most recent version of ASTM D5373 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal”, or using any other analysis method published by an organization listed in QC.1.5;

(2) for petroleum-based liquid fuels and liquid waste-derived fuels, using one of the following methods:

(a) in accordance with the most recent version of ASTM D5291 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants”;

(b) by applying the elementary analysis method;

(c) in accordance with the most recent version of ASTM D3238 “Standard Test Method for Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by n-d-M Method” and the most recent version of either ASTM D2502 “Standard Test Method for Estimation of Molecular Weight (Relative Molecular Mas(s) of Petroleum Oils From Viscosity Measurements” or ASTM D2503 “Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurements of Vapor Pressure”;

(d) using any other analysis method published by an organization listed in QC.1.5;

(3) for gaseous fuels, in accordance with the most recent version of ASTM D1945 “Standard Test Method for Analysis of Natural Gas by Gas Chromatography”, ASTM D1946 “Standard Practice for Analysis of Reformed Gas by Gas Chromatography”, or ASTM D2163 “Standard Test Method for Determination of Hydrocarbons in Liquefied Petroleum (L(P) Gases and Propane/Propene Mixtures by Gas Chromatography”, in accordance with any other analysis method published by an organization listed in QC.1.5, or by measuring the carbon content of the fuel to within ± 5% using data from a continuous emission monitoring and recording system, at the following frequency:

(a) weekly, for natural gas, biomethane and biogas;

(b) daily, for all other types of gaseous fuel;

(4) in the case of a mixture of fuels, in accordance with an analysis method published by a body referred to in QC.1.5.

QC.1.5.6. Measurements and data collection for fuel sampling

When the emission calculation methods require the periodic measurement or collection of data for an emissions source, the emitter must obtain a measurement and data collection rate of 100% for each report year, subject to the following:

(1) when, in sampling fuels, an emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period;

(2) when it is not possible to obtain valid data, the emitter must use replacement data established using the calculation method in QC.1.6.

QC.1.5.7. (Revoked).

QC.1.6. Methods for estimating missing data

When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:

(1) an emitter who uses one of the calculation methods specified in QC.1.3.1 to QC.1.3.3, QC.1.3.5, QC.1.3.6, QC.1.4.1, QC.1.4.2 and QC.1.4.3 must,

(a) when the missing data concern high heat value, carbon content, molecular mass, CO2 concentration, water content or any other data sampled to calculate greenhouse gas emissions,

i. determine the sampling or measurement rate using the following equation:

Equation 1-19

R = QS Act/QS Required

Where:

R = Actual sampling or measurement rate, expressed as a percentage;

QS Act = Quantity of actual samples or measurements obtained by the emitter;

QS Required = Quantity of samples or measurements required under QC.1.5;

ii. for data that require sampling or analysis,

— if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;

— if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made, except in the case of water content. In the latter case, replace the missing data by the lowest data value sampled or analyzed during the report year for which the calculation is made;

— if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years, except in the case of water content. In the latter case, replace the missing data by the lowest data value sampled or analyzed during the 3 preceding years;

(b) when the missing data concern stack gas flow rate, fuel consumption or the quantity of sorbent used, the replacement data must be estimated on the basis of all the data relating to the processes used;

(2) an emitter who uses one of the calculation methods specified in QC.1.3.4, QC.1.4.4 and QC.1.4.5 must determine the replacement data for the CO2, CH4, and N2O concentration using the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or applying to the missing parameters the following method:

(a) when the missing data are data measured by the continuous emission monitoring and recording system, determine the sampling or measurement rate using the following equation:

Equation 1-20

R = HS Act/HS Required

Where:

R = Actual sampling or measurement rate, expressed as a percentage;

HS Act = Hours of actual samples or measurements obtained by the emitter during the year;

HS Required = Quantity of samples or measurements required under QC.1.5;

(b) for data that require sampling or analysis,

i. if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data from before that period are available, the emitter must use the first available data from after the period for which the data is missing;

ii. if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;

iii. if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;

QC.1.7. Tables

Table 1-1. High heat value by fuel type

(QC.1.3.1(1), QC.1.4.1(1), QC.1.5.2(2), QC.17.3.1(2))

Liquid fuels	High heat value (GJ/kl)
Asphalt and road oil	44.46
Aviation gasoline	33.52
Diesel	38.30
Aviation turbo fuel	37.40
Kerosene	37.68
Propane	25.31
Ethane	17.22
Butane	28.44
Lubricants	39.16
Motor gasoline	34.87
Light fuel oil No. 1	38.78
Light fuel oil No. 2	38.50
Residual fuel oil (Nos. 5 and 6)	42.50
Crude oil	39.16
Naphta	35.17
Petrochemical feedstocks	35.17
Liquid petroleum coke	46.35
Ethanol-100%	23.41
Biodiesel-100%	35.67
Rendered animal fat	34.84
Vegetable oil	33.44
Solid fuels	High heat value (GJ/t)
Anthracite coal	27.70
Bituminous coal	26.33
Foreign bituminous coal	29.82
Sub-bituminous coal	19.15
Lignite	15.00
Coal coke	28.83
Solid petroleum coke	34.89
Wood waste (wood residue) dry basis	19.20
Spent pulping liquor (dry basis)	14.20
Municipal solid waste	11.57
Peat	9.30
Tires	32.80
Agricultural by-products1	9.59
Biomass by-products2	30.03
Gaseous fuels	High heat value (GJ/103m3)
Natural gas	38.32
Biomethane	38.32
Coke oven gas	19.14
Still gas	36.08
Landfill gas (methane portion)	37.03
Biogas (methane portion)	37.03
Acetylene	54.80

1. By-products not destined for consumption.

2. Animal and vegetable waste, excluding wood waste and spent pulping liquor.

Table 1-2. Emission factor and high heat factor by fuel type

(QC.1.3.1, QC.1.3.2, QC.1.3.5(2), QC.1.4.1(1), QC.1.5.1(3))

  ________________________________________________________________________________
 |                                |                        |                      |
 | Fuels                          | CO2 emission factor    |  High heat value     |
 |                                | kg CO2/GJ)             |  (GJ/kl)             |
 |________________________________|________________________|______________________|
 |                                |                        |                      |
 | Light fuel oil no. 1           | 69.37                  |  38.78               |
 |________________________________|________________________|______________________|
 |                                |                        |                      |
 | Light fuel oil no. 2           | 70.05                  |  38.50               |
 |________________________________|________________________|______________________|
 |                                |                        |                      |
 | Heavy fuel oil no. 4           | 71.07                  |  40.73               |
 |________________________________|________________________|______________________|
 |                                |                        |                      |
 | Kerosene                       | 67.25                  |  37.68               |
 |________________________________|________________________|______________________|
 |                                |                        |                      |
 | Liquefied petroleum gas (LPG)  | 59.65                  |  25.66               |
 |________________________________|________________________|______________________|
 |                                |                        |                      |
 | Pure propane                   | 59.66                  |  25.31               |
 |________________________________|________________________|______________________|
 |                                |                        |                      |
 | Propylene                      | 62.46                  |  25.39               |
 |________________________________|________________________|______________________|
 |                                |                        |                      |
 | Ethane                         | 56.68                  |  17.22               |
 |________________________________|________________________|______________________|
 |                                |                        |                      |
 | Ethylene                       | 63.86                  |  27.90               |
 |________________________________|________________________|______________________|
 |                                |                        |                      |
 | Isobutane                      | 61.48                  |  27.06               |
 |________________________________|________________________|______________________|
 |                                |                        |                      |
 | Isobutylene                    | 64.16                  |  28.73               |
 |________________________________|________________________|______________________|
 |                                |                        |                      |
 | Butane                         | 60.83                  |  28.44               |
 |________________________________|________________________|______________________|
 |                                |                        |                      |
 | Butene                         | 64.15                  |  28.73               |
 |________________________________|________________________|______________________|
 |                                |                        |                      |
 | Natural gasoline               | 63.29                  |  30.69               |
 |________________________________|________________________|______________________|
 |                                |                        |                      |
 | Gasoline                       | 65.40                  |  34.87               |
 |________________________________|________________________|______________________|
 |                                |                        |                      |
 | Aviation gasoline              | 69.87                  |  33.52               |
 |________________________________|________________________|______________________|
 |                                |                        |                      |
 | Aviation-type kerosene         | 68.40                  |  37.66               |
 |________________________________|________________________|______________________|                        

Table 1-3. Emission factors by fuel type

(QC.1.3.1(1), QC.1.3.2, QC.1.4.1(1), QC.1.4.4, QC.17.3.1(2))

Liquid fuels and biofuels	CO2	CO2	CH4	CH4	N2O	N2O
	(kg/l)	(kg/GJ)	(g/l)	(g/GJ)	(g/l)	(g/GJ)
Aviation gasoline	2.342	69.87	2.200	65.630	0.230	6.862
Diesel	2.663	69.53	0.133	3.473	0.400	10.44
Aviation turbo fuel	2.534	67.75	0.080	2.139	0.230	6.150
Kerosene
- Electric utilities	2.534	67.25	0.006	0.159	0.031	0.823
- Industrial	2.534	67.25	0.006	0.159	0.031	0.823
- Producer consumption	2.534	67.25	0.006	0.159	0.031	0.823
- Forestry, construction and commercial and institutional	2.534	67.25	0.026	0.690	0.031	0.823
Propane
- Residential	1.510	59.66	0.027	1.067	0.108	4.267
- Others	1.510	59.66	0.024	0.948	0.108	4.267
Ethane	0.976	56.68	N/A	N/A	N/A	N/A
Butane	1.730	60.83	0.024	0.844	0.108	3.797
Lubricants	1.410	36.01	N/A	N/A	N/A	N/A
Motor gasoline	2.289	65.40	2.700	77.140	0.050	1.429
Light fuel oil
- Electric utilities	2.725	70.23	0.180	4.639	0.031	0.799
- Industrial	2.725	70.23	0.006	0.155	0.031	0.799
- Producer consumption	2.643	68.12	0.006	0.155	0.031	0.799
- Forestry, construction and commercial and institutional	2.725	70.23	0.026	0.670	0.031	0.799
Residual fuel oil (Nos. 5 and 6)
- Electric utilities	3.124	73.51	0.034	0.800	0.064	1.506
- Industrial	3.124	73.51	0.12	2.824	0.064	1.506
- Producer consumption	3.158	74.31	0.12	2.824	0.064	1.506
- Forestry, construction and commercial and institutional	3.124	73.51	0.057	1.341	0.064	1.820
Naphtha	0.625	17.77	N/A	N/A	N/A	N/A
Petrochemical feedstocks	0.556	14.22	N/A	N/A	N/A	N/A
Liquid petroleum coke	3.826	82.55	0.12	2.589	0.0265	0.572
Ethanol (100%)	1.519	64.9	2.7	N/A	0.05	N/A
Biodiesel (100%)	2.497	70	0.133	N/A	0.4	N/A
Rendered animal fat	2.348	67.4	N/A	N/A	N/A	N/A
Vegetable oil	2.585	77.3	N/A	N/A	N/A	N/A
Biomass and other solid fuels	CO2	CO2	CH4	CH4	N2O	N2O
	(kg/kg)	(kg/GJ)	(g/kg)	(g/GJ)	(g/kg)	(g/GJ)
Wood waste (wood residue) dry basis	1.799	93.7	0.576	30	0.077	4
Spent pulping liquor (dry basis)	1.304	91.8	0.041	2.9	0.027	1.9
Agricultural by-products1	1.074	112	N/A	N/A	N/A	N/A
Biomass by-products2	3.000	100	N/A	N/A	N/A	N/A
Coal coke	2.480	86.02	0.03	1.041	0.02	0.694
Solid petroleum coke	3.386	97.07	1.058	30.33	0.139	3.98
Tires	2.650	80.8	N/A	N/A	N/A	N/A
Gaseous fuels and biofuels	CO2	CO2	CH4	CH4	N2O	N2O
	(kg/m3)	(kg/GJ)	(g/m3)	(g/GJ)	(g/m3)	(g/GJ)
Coke oven gas	0.879	45.92	0.037	1.933	0.0350	1.829
Still gas	1.75	48.50	N/A	N/A	0.0222	0.615
Landfill gas (methane portion)	1.830	49.41	0.095	2.566	0.019	0.513
Biogas (methane portion)	1.830	49.41	0.095	2.566	0.019	0.513
Acetylene	3.7193	67.87	N/A	N/A	N/A	N/A

1. By-products not destined for consumption.

2. Animal and vegetable waste, excluding wood waste and spent pulping liquor.

Table 1-4. CO2 emission factors for natural gas and biomethane

(QC.1.3.1(1), QC.1.3.2(1), QC.17.3.1(2))

 _________________________________________________________________________________
|                                                   |                             |
| Marketable gas                                    |  Marketable gas             |
| (kg CO2/m3)                                       |  (kg CO2/GJ)                |
|___________________________________________________|_____________________________|
|                                                   |                             |
| 1.878                                             |   49.01                     |
|___________________________________________________|_____________________________|                        

Table 1-5. CO2 emission factors for coal

(QC.1.3.1(1), QC.1.3.2(1), QC.17.3.1(2))

 __________________________________________________________________________________
|                           |                        |                             |
|  Source                   |  Emission factor       |     Emission factor         |
|                           |   (kg CO2/ kg)          |      (kg CO2/GJ)            |
|___________________________|________________________|_____________________________|
|                           |                        |                             |
| - Canadian bituminous     |   2.25                 |      85.5                   |
|___________________________|________________________|_____________________________|
|                           |                        |                             |
| - U.S. bituminous         |   2.34                 |      88.9                   |
|___________________________|________________________|_____________________________|
|                           |                        |                             |
| - Anthracite              |   2.39                 |      86.3                   |
|___________________________|________________________|_____________________________|                        

Table 1-6. Other emission factors

(QC.1.3.1(1), QC.1.3.2(1), QC.17.3.1(2))

 _________________________________________________________________________________
|                       |                   |                  |                  |
| Source                |    CO2 emission   |   CH4 emission   |    N2O emission   |
|                       |       factor      |      factor      |       factor     |
|                       |      (kg/GJ)      |      (g/GJ)      |       (g/GJ)     |
|_______________________|___________________|__________________|__________________|
|                       |                   |                  |                  |
| Municipal Solid Waste | 85.6              | 30               | 4.0              |
|_______________________|___________________|__________________|__________________|
|                       |                   |                  |                  |
| Peat                  | 103.0             | 1.0              | 1.5              |
|_______________________|___________________|__________________|__________________|                        

Table 1-7. CH4 and N2O emission factors for natural gas and biomethane by use

(QC.1.4.1(1), QC.1.4.4)

 ________________________________________________________________________________
|                      |              |              |              |            |
| Uses                 | CH4 (g/m3)    | CH4 (g/GJ)   | N2O (g/ m3)   | N2O (g/GJ) |
|______________________|______________|______________|______________|____________|
|                      |              |              |              |            |
| Electric Utilities   | 0.490        | 12.790       | 0.049        | 1.279      |
|______________________|______________|______________|______________|____________|
|                      |              |              |              |            |
| Industrial           | 0.037        | 0.966        | 0.033        | 0.861      |
|______________________|______________|______________|______________|____________|
|                      |              |              |              |            |
| Producer Consumption |              |              |              |            |
| (Non-marketable)     | 6.500        | 169.600      | 0.060        | 1.566      |
|______________________|______________|______________|______________|____________|
|                      |              |              |              |            |
| Pipelines            | 1.900        | 49.580       | 0.050        | 1.305      |
|______________________|______________|______________|______________|____________|
|                      |              |              |              |            |
| Cement               | 0.037        | 0.966        | 0.034        | 0.887      |
|______________________|______________|______________|______________|____________|
|                      |              |              |              |            |
| Manufacturing        |              |              |              |            |
| Industries           | 0.037        | 0.966        | 0.033        | 0.861      |
|______________________|______________|______________|______________|____________|
|                      |              |              |              |            |
| Residential,         |              |              |              |            |
| Construction,        |              |              |              |            |
| Commercial/          |              |              |              |            |
| Institutional,       |              |              |              |            |
| Agriculture          | 0.037        | 0.966        | 0.035        | 0.913      |
|______________________|______________|______________|______________|____________|                        

Table 1-8. CH4 and N2O emission factors for coal by use

(QC.1.4.1(1))

 _________________________________________________________________________________
|                           |                           |                         |
| Uses                      | Emission factor           | Emission factor         |
|                           | (g CH4/ kg coal)          | (g N2O/kg coal)          |
|___________________________|___________________________|_________________________|
|                           |                           |                         |
| - Electric utilities      | 0.022                     | 0.032                   |
|___________________________|___________________________|_________________________|
|                           |                           |                         |
| - Industry and heat and   |                           |                         |
|   Steam Plants            | 0.030                     | 0.020                   |
|___________________________|___________________________|_________________________|
|                           |                           |                         |
| - Residential, Public     |                           |                         |
|   Administration          | 4.000                     | 0.020                   |
|___________________________|___________________________|_________________________|                        

Table 1-9. Flow meter tests

(QC.1.5.2(3))

 _________________________________________________________________________________
|                      |                                                          |
| Standardization      | Method                                                   |
| organization         |__________________________________________________________|
|                      |                      |                                   |
|                      | Number               | Title                             |
|______________________|______________________|___________________________________|
|                      |                      |                                   |
| American Society of  | ASME MFC-3M-2004     | Measurement of Fluid Flow in Pipes|
| Mechanical Engineers |                      | Using Orifice, Nozzle, and Venturi|
| (ASME)               |______________________|___________________________________|
|                      |                      |                                   |
|                      | ASME MFC-4M-1986     | Measurement of Gas Flow by Turbine|
|                      | (Reaffirmed 2008)    | Meters                            |
|                      |______________________|___________________________________|
|                      |                      |                                   |
|                      | ASME MFC-5M-1985     | Measurement of Liquid Flow in     |
|                      | (Reaffirmed 2006)    | Closed                            |
|                      |                      | Conduits Using Transit-Time       |
|                      |                      | Ultrasonic                        |
|                      |                      | Flowmeters                        |
|                      |______________________|___________________________________|
|                      |                      |                                   |
|                      | ASME MFC-6M-1998     | Measurement of Fluid Flow in Pipes|
|                      | (Reaffirmed 2005)    | Using Vortex Flowmeters           |
|                      |______________________|___________________________________|
|                      |                      |                                   |
|                      | ASME MFC-7M-1987     | Measurement of Gas Flow by Means  |
|                      | (Reaffirmed 2006)    | of Critical Flow Venturi Nozzles  |
|                      |______________________|___________________________________|
|                      |                      |                                   |
|                      | ASME MFC-9M-1988     | Measurement of Liquid Flow in     |
|                      | (Reaffirmed 2006)    | Closed                            |
|                      |                      | Conduits by Weighing Method       |
|______________________|______________________|___________________________________|
|                      |                      |                                   |
| International        | ISO 8316: 1987       | Measurement of Liquid Flow in     |
| Organization for     |                      | Closed                            |
| Standardization(ISO) |                      | Conduits - Method by Collection of|
|                      |                      | the Liquid in a Volumetric Tank   |
|______________________|______________________|___________________________________|
|                      |                      |                                   |
| American Gas         | AGA Report No. 3     | Orifice Metering of Natural Gas   |
| Association (AGA)    |                      | Part 1:                           |
|                      |                      | General Equations & Uncertainty   |
|                      |                      | Guidelines (1990)                 |
|                      |______________________|___________________________________|
|                      |                      |                                   |
|                      | AGA Report No. 3     | Orifice Metering of Natural Gas   |
|                      |                      | Part 2:                           |
|                      |                      | Specification and Installation    |
|                      |                      | Requirements (2000)               |
|                      |______________________|___________________________________|
|                      |                      |                                   |
|                      | AGA Report No. 7     | Measurement of Natural Gas by     |
|                      |                      | Turbine                           |
|                      |                      | Meter (2006)                      |
|______________________|______________________|___________________________________|
|                      |                      |                                   |
| American Society of  | ASHRAE 41.8-1989     | Standard Methods of Measurement of|
| Heating,             |                      | Flow of Liquids in Pipes Using    |
| Refrigerating and    |                      | Orifice                           |
| Air-Conditioning     |                      | Flowmeters                        |
| Engineers (ASHRAE)   |                      |                                   |
|______________________|______________________|___________________________________|                        

Table 1-10. Density

(QC.1.5.2)

 _________________________________________________________________________________
|                                       |                                         |
| Fuel                                  |               Density                   |
|                                       |                (kg/l)                   |
|_______________________________________|_________________________________________|
|                                       |                                         |
| Light fuel oil no. 1                  |  0.81                                   |
|_______________________________________|_________________________________________|
|                                       |                                         |
| Light fuel oil no. 2                  |  0.86                                   |
|_______________________________________|_________________________________________|
|                                       |                                         |
| Heavy fuel oil no. 6                  |  0.97                                   |
|_______________________________________|_________________________________________|                        

QC.2. REFINERY FUEL GAS COMBUSTION

QC.2.1. Covered sources

The covered sources are stationary combustion units that combust gaseous fuels such as refinery fuel gas, flexigas or associated gas.

Notwithstanding the first paragraph, emissions attributable to the combustion of gas fuels at a flare must be calculated in accordance with QC.9.3.5.

QC.2.2. Greenhouse gas reporting requirements

In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information for each type of gaseous fuel (refinery fuel gas, flexigas and associated gas):

(1) the annual CO2, CH4 and N2O emissions, in metric tons;

(1.1) the emissions attributable to the combustion of gas fuels at a flare, calculated in accordance with QC.9.3.5, in metric tons CO2 equivalent;

(2) the annual consumption of gaseous fuel, in thousands of cubic metres at standard conditions;

(3) the average annual carbon content of each gaseous fuel when used to calculate CO2 emissions, in kilograms of carbon per kilogram of gaseous fuel;

(4) (subparagraph revoked);

(5) the average annual molecular weight of each gaseous fuel when used to calculate CO2 emissions, in kilograms per kilomole;

(6) the number of times that the methods for estimating missing data provided for in QC.2.5 were used.

Subparagraphs 3 and 5 of the first paragraph do not apply to the CO2 emissions of an emitter who calculates emissions using data from a continuous emission monitoring and recording system.

QC.2.3. Calculation methods for CO2, CH4 and N2O emissions

The annual CO2 emissions attributable to stationary units that combust gaseous fuels must be calculated by adding together the daily CO2 emissions for each supply system for refinery fuel gas, flexigas and associated gas, which emissions must be calculated using one of the calculation methods in QC.2.3.1 to QC.2.3.4.

The annual CH4 and N2O emissions attributable to stationary units that combust gaseous fuels must be calculated using the calculation method in QC.2.3.5.

QC.2.3.1. Use of a continuous emission monitoring and recording system

The annual CO2 emissions attributable to the combustion of gaseous fuels may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.1.3.4.

QC.2.3.2. Calculation of CO2 emissions for each supply system for refinery fuel gas and flexigas

The annual CO2 emissions for each supply system for refinery fuel gas and flexigas must be calculated based on the carbon content and molecular weight of the refinery fuel gas or flexigas, using equation 2-1:

Equation 2-1

Where:

CO2 = Annual CO2 emissions attributable to the combustion of refinery gas or flexigas, in metric tons;

n = Number of days of operation in the year;

m = Number of supply systems;

i = Day;

j = Supply system;

RFGij = Consumption of refinery gas or flexigas in supply system j for day i, in thousands of cubic metres at standard conditions;

CCij = Carbon content of the sample of refinery gas or flexigas in supply system j for day i, measured in accordance with QC.2.4.2, in kilograms of carbon per kilogram of fuel;

MWij = Molecular weight of the sample of refinery gas or flexigas in supply system j for day i, in kilograms per kilomole;

MVC = Molar volume conversion factor (24.06 m3 per kilomole at standard conditions);

3.664 = Ratio of molecular weights, CO2 to carbon;

1 = Conversion factor, kilograms to metric tons and thousands of cubic metres to cubic metres.

QC.2.3.3. Calculation of CO2 emissions for associated gas

The annual CO2 emissions for associated gas may be calculated using the calculation method in QC.1.3.2, with the exception of an emitter to whom section 6.6 of this Regulation applies, or using the method in QC.1.3.3.

QC.2.3.4. Calculation of CO2 emissions for gases mixed prior to combustion

In addition to the methods in QC.2.3.1 and QC.2.3.2, for gases mixed prior to combustion, the emitter may calculate the annual CO2 emissions for each gas before mixing. In this case, the emitter must

(1) measure the flow rate of each fuel stream;

(2) determine the carbon content of each fuel stream before mixing;

(3) calculate the CO2 emissions for each fuel stream using the following methods:

(a) for natural gas and associated gas, in accordance with QC.1.3.2, with the exception of an emitter to whom section 6.6 of this Regulation applies, or in accordance with QC.1.3.3;

(b) for flexigas, refinery fuel gas and low heat content gas, in accordance with QC.2.3.2;

(4) add together the CO2 emissions for each stream to determine the total emissions for the mixture.

QC.2.3.5. Calculation of CH4 and N2O emissions attributable to the combustion of gaseous fuels

The annual CH4 and N2O emissions attributable to the combustion of gaseous fuels must be calculated in accordance with QC.1.4.

QC.2.4. Sampling, analysis and measurement requirements

QC.2.4.1. Consumption of gaseous fuels

The consumption of gaseous fuels must be calculated daily using the methods in QC.1.5.2.

QC.2.4.2. Carbon content and molecular weight of gaseous fuels

When the calculation method in QC.2.3.2 is used, the emitter must measure the carbon content and molecular weight of the gaseous fuels daily, using one of the following methods:

(1) in accordance with QC.1.5.5;

(2) using the chromatographic analysis of gaseous fuels, provided that the gas chromatograph is maintained and calibrated according to the manufacturer’s instructions.

QC.2.4.3. (Revoked).

QC.2.4.4. (Revoked).

QC.2.5. Methods for estimating missing data

When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:

(1) an emitter who uses one of the calculation methods specified in QC.2.3.2 must,

(a) when the missing data concern high heat value, carbon content, molecular mass or any other data sampled to calculate greenhouse gas emissions,

i. determine the sampling or measurement rate using the following equation:

Equation 2-2

R = QS Act/QS Required

Where:

R = Actual sampling or measurement rate, expressed as a percentage;

QS Act = Quantity of actual samples or measurements obtained by the emitter;

QS Required = Quantity of samples or measurements required under QC.2.4;

ii. for data that require sampling or analysis,

— if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;

— if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;

— if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;

(b) when the missing data concern gas consumption, the replacement data must be estimated on the basis of all the data relating to the processes used;

(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.

QC.3. ALUMINUM PRODUCTION

QC.3.1. Covered sources

The covered sources are all the processes used for primary aluminum production.

QC.3.2. Reporting requirements for greenhouse gas emissions

In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:

(1) the annual CO2 emissions attributable to anode consumption from prebaked and Søderberg electrolysis cells, in metric tons;

(2) the annual CO2 emissions attributable to anode and cathode baking, in metric tons;

(3) the annual CF4 and C2F6 emissions attributable to anode effects, in metric tons;

(4) the annual CO2 emissions attributable to green coke calcination, in metric tons;

(5) the annual SF6 emissions attributable to cover gas consumption, in metric tons;

(6) the annual CO2, CH4 and N2O emissions attributable to the use of stationary combustion units, calculated and reported in accordance with QC.1, in metric tons;

(7) the annual liquid aluminum production, in metric tons;

(8) for the use of the prebaked anodes process, the annual net prebaked anode consumption for liquid aluminum production, in metric tons of anodes per metric ton of liquid aluminum;

(9) for the use of the Søderberg anodes process, the annual anode paste consumption, in metric tons of paste per metric ton of liquid aluminum;

(10) for the use of the baking process for prebaked anodes or cathodes, the annual quantity of baked anodes or cathodes removed from furnace, in metric tons;

(11) for the use of the coke calcination process:

(a) the annual consumption of green coke, in metric tons;

(b) the annual quantity of calcinated coke produced, in metric tons;

(c) the annual quantity of under-calcinated coke produced, in metric tons;

(12) for CF4 or C2F6 emissions:

(a) the slope determined in accordance with the method in QC.3.6.1, in metric tons of CF4 per metric ton of liquid aluminum, per anode effect minute, per pot-day for each series of pots using the same technology, and the date on which the slope is determined for each series of pots;

(b) (subparagraph revoked);

(c) (subparagraph revoked);

(d) (subparagraph revoked);

(e) (subparagraph revoked);

(f) the overvoltage coefficient determined in accordance with the method in QC.3.6.1, in metric tons of CF4 per metric ton of aluminum, per millivolt for each series of pots using the same technology;

(g) (subparagraph revoked);

(h) (subparagraph revoked);

(13) (subparagraph revoked);

(14) the number of times that the methods for estimating missing data provided for in QC.3.7 were used;

(15) (subparagraph revoked);

(16) the annual quantity of aluminum hydrate produced, calculated at the precipitation stage, in metric tons of aluminum hydrate (Al2O3) equivalent.

Subparagraphs a and f of subparagraph 12 of the first paragraph does not apply to the CF4 or C2F6 emissions of an emitter who calculates emissions using data from a continuous emission monitoring and recording system.

For the purposes of subparagraph 8 of the first paragraph of section 6.2:

(1) the emissions referred to in subparagraphs 1, 2 and 4 of the first paragraph are emissions attributable to fixed processes;

(2) the emissions referred to in subparagraph 6 of the first paragraph are emissions attributable to combustion;

(3) the emissions referred to in subparagraphs 3 and 5 of the first paragraph are other emissions.

QC.3.3. Calculation methods for CO2 emissions

QC.3.3.1. Calculation of CO2 emissions attributable to the consumption of prebaked anodes

The annual CO2 emissions attributable to the consumption of prebaked anodes must be calculated using equation 3-1 or 3-1.1:

Equation 3-1

Where:

CO2 = Annual CO2 emissions attributable to the consumption of prebaked anodes, in metric tons;

i = Month;

NAC = Net anode consumption for liquid aluminum production for month i, in metric tons of anodes per metric ton of liquid aluminum;

MP = Production of liquid aluminum for month i, in metric tons;

Sa = Sulphur content in the prebaked anodes for month i, in kilograms of sulphur per kilogram of prebaked anodes;

Asha = Ash content in the prebaked anodes for month i, in kilograms of ash per kilogram of prebaked anodes;

3.664 = Ratio of molecular weights, CO2 to carbon.

Equation 3-1.1

	12
CO2 =	∑	[NAC × MP × CC × 3.664]i
	i = 1

Where:

CO2 = Annual CO2 emissions attributable to the consumption of prebaked anodes, in metric tons;

i = Month;

NAC = Net anode consumption for aluminum production for month i, in metric tons of anodes per metric ton of liquid aluminum;

MP = Production of liquid aluminum for month i, in metric tons;

CC = Carbon content of prebaked anodes for month i, in kilograms of carbon per kilogram of prebaked anodes;

3.664 = Ratio of molecular weights, CO2 to carbon.

QC.3.3.2. Calculation of CO2 emissions attributable to anode consumption from Søderberg electrolysis cells

The annual CO2 emissions attributable to anode consumption from Søderberg electrolysis cells must be calculated using equation  3-2:

Equation 3-2

Where:

CO2 = Annual CO2 emissions attributable to anode consumption from Søderberg electrolysis cells, in metric tons;

i = Month;

PC = Anode paste consumption for month i, in metric tons of paste per metric ton of liquid aluminum;

MP = Production of liquid aluminum for month i, in metric tons;

CSM = Emissions of cyclohexane-soluble matter (CSM) or the International Aluminium Institute factor used, in kilograms of CSM per metric ton of liquid aluminum;

BC = Average content of pitch or other binding agent in paste for month i, in kilograms of pitch or other binding agent per kilogram of paste;

Sp = Sulphur content in pitch or other binding agent for month i, in kilograms of sulphur per kilogram of pitch or other binding agent;

Ashp = Ash content in pitch or other binding agent, in kilograms of ash per kilogram of pitch or other binding agent;

Hp = Hydrogen content in pitch or other binding agent, in kilograms of hydrogen per kilogram of pitch or other binding agent or the International Aluminium Institute factor used;

Sc = Sulphur content in calcinated coke, in kilograms of sulphur per kilogram of calcinated coke;

Ashc = Ash content in calcinated coke, in kilograms of ash per kilogram of calcinated coke;

CP = Monthly reported carbon present in the dust from Søderberg electrolysis cells, in kilograms of carbon per kilogram of liquid aluminum produced, or a value of 0;

3.664 = Ratio of molecular weights, CO2 to carbon.

QC.3.3.3. Calculation of CO2 emissions attributable to anode and cathode baking

The annual CO2 emissions attributable to anode and cathode baking must be calculated using the following calculation methods:

(1) for annual CO2 emissions, using equation 3-3:

Equation 3-3

CO2 = CO2 PM + CO2 P

Where:

CO2 = Annual CO2 emissions attributable to anode and cathode baking, in metric tons;

CO2 PM = Annual CO2 emissions attributable to packing material calculated in accordance with equation 3-4, in metric tons;

CO2 P = Annual CO2 emissions attributable to the coking of pitch or another binding agent, calculated in accordance with equation 3-5, in metric tons;

(2) for emissions of CO2 attributable to packing material, using equation 3-4:

Equation 3-4

Where:

CO2 PM = Annual CO2 emissions attributable to packing material, in metric tons;

i = Month;

CPM = Consumption of packing material for month i, in metric tons of packing material per metric ton of baked anodes or cathodes;

BAC = Quantity of baked anodes or cathodes removed from furnace for month i, in metric tons;

Ashpm = Ash content of packing material for month i, in kilograms of ash per kilogram of packing material;

Spm = Sulphur content of packing material for month i, in kilograms of sulphur per kilogram of packing material;

3.664 = Ratio of molecular weights, CO2 to carbon;

(3) for emissions of CO2 attributable to the coking of pitch or another binding agent, using equation 3-5:

Equation 3-5

Where:

CO2 P = Annual CO2 emissions attributable to the coking of pitch or another binding agent, in metric tons;

i = Month;

GAC = Quantity of green anodes or cathodes put into furnace during month i, in metric tons;

BAC = Quantity of baked anodes or cathodes removed from furnace for month i, in metric tons;

Hp = Hydrogen content in pitch or other binding agent for month i or the International Aluminium Institute factor used, in kilograms of hydrogen per kilogram of pitch or other binding agent;

PC = Pitch or other binding agent content of green anodes or cathodes for month i, in kilograms of pitch or other binding agent per kilogram of green anodes or cathodes;

RT = Recovered tar for month i, in metric tons;

3.664 = Ratio of molecular weights, CO2 to carbon.

QC.3.3.4. Calculation of CO2 emissions attributable to green coke calcination

The annual CO2 emissions attributable to green coke calcination must be calculated using equation 3-6:

Equation 3-6

Where:

CO2 = Annual CO2 emissions attributable to green coke calcination, in metric tons;

i = Month;

GC = Consumption of green coke for month i, in metric tons;

H2Ogc = Humidity content of green coke for month i, in kilograms of water per kilogram of green coke;

Vgc = Volatiles content of green coke for month i, in kilograms of volatiles per kilogram of green coke;

Sgc = Sulphur content of green coke for month i, in kilograms of sulphur per kilogram of green coke;

CC = Calcinated coke produced for month i, in metric tons;

UCC = Under-calcinated coke produced for month i, in metric tons;

ED = Emissions of coke dust for month i, in metric tons;

Scc = Sulphur in calcinated coke, in kilograms of sulphur per kilogram of calcinated coke;

3.664 = Ratio of molecular weights, CO2 to carbon;

0.035 = CH4 and tar content in coke volatiles contributing to CO2 emissions;

2.75 = Conversion factor, CH4 to CO2.

QC.3.4. Calculation method for CF4 and C2F6 emissions

Annual CF4 and C2F6 emissions must be calculated using one of the calculation methods in QC.3.4.1 and QC.3.4.2.

QC.3.4.1. Use of a continuous emission monitoring and recording system

The annual CF4 and C2F6 emissions may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.3.6.1.

QC.3.4.2. Annual CF4 and C2F6 emissions

The annual CF4 and C2F6 emissions must be calculated for each series of pots using the same technology, using the following methods:

(1) for CF4 emissions, using equation 3-7 or equation 3-8:

Equation 3-7

Where:

CF4 = Annual CF4 emissions, in metric tons;

i = Month;

slopeCF4 = Slope for series of pots j, determined in accordance with the method in QC.3.6.1, in metric tons of CF4 per metric ton of liquid aluminum, per anode effect minute, per pot-day, for month i;

AED = Anode effect duration, in anode effect minutes per pot-day, calculated for month i and obtained by multiplying the anode effects frequency, in number of anode effects per pot-day, by the average duration of anode effects, in minutes;

MP = Monthly production of liquid aluminum, in metric tons;

Equation 3-8

Where:

CF4 = Annual CF4 emissions attributable to anode effects, in metric tons;

m = Number of series of pots;

j = Series of pots;

i = Month;

OVCCF4 = Overvoltage coefficient determined in accordance with the method in QC.3.6.1, in metric tons of CF4 per metric ton of liquid aluminum per millivolt;

AEO = Monthly anode effect overvoltages, in millivolts per pot;

CE = Current efficiency of the aluminum production process, expressed as a fraction;

MP = Monthly production of liquid aluminum, in metric tons;

(2) for C2F6 emissions, using equation 3-8.1:

Equation 3-8.1

Where:

C2F6 = Annual C2F6 emissions, in metric tons;

i = Month;

CF4 = CF4 emissions for month i, in metric tons;

F = C2F6/CF4 weight fraction, determined by the emitter or selected from Table 3-1 in QC.3.8, in kilograms of C2F6 per kilogram of CF4.

QC.3.4.3. (Replaced);

QC.3.5. Calculation method for emissions of SF6 used as a cover gas

The annual emissions of SF6used as a cover gas must be calculated using one of the calculation methods in QC.3.5.1 and QC.3.5.2.

QC.3.5.1. Calculation based on change in inventory

The annual SF6 emissions may be calculated based on the change in inventory using equation 3-9:

Equation 3-9

SF6 = SInv-Begin -SInv-End + SPurchased -SShipped

Where:

SF6 = Annual emissions of SF6 used as a cover gas, in metric tons;

SInv-Begin = Quantity of SF6 in storage at the beginning of the year, in metric tons;

SInv-End = Quantity of SF6 in storage at the end of the year, in metric tons;

SPurchased = Quantity of SF6 purchases for the year, in metric tons;

SShipped = Quantity of SF6 shipped out of the establishment during the year, in metric tons.

QC.3.5.2. Calculation based on direct measurement

The annual SF6emissions may be calculated based on direct measurement using equation 3-10:

Equation 3-10

Where:

SF6 = Annual emissions of SF6 used as a cover gas, in metric tons;

i = Month;

QInput = Quantity of cover gas entering the electrolysis cells for month i, in metric tons;

CInput = Concentration of SF6 in the cover gas entering the electrolysis cells for month i, in metric tons of SF6 per metric ton of input gas;

QOutput = Quantity of gas containing SF6 collected and shipped out of the establishment for month i, in metric tons;

COutput = Concentration of SF6 in the gas collected and shipped out of the establishment for month i, in metric tons of SF6 per metric ton of gas collected and shipped out of the establishment.

QC.3.6. Sampling, analysis and measurement requirements

An emitter who operates a facility or establishment that produces aluminum must measure all parameters monthly, subject to the following exceptions:

(1) for the emissions of cyclohexane-soluble matter used in the calculation in equation 3-2 in QC.3.3.2, the emitter may measure the emissions monthly or use International Aluminium Institute factors;

(2) for the carbon present in dust from Söderberg electrolysis cells used in the calculation in equation 3-2 in QC.3.3.2, the emitter may measure the carbon monthly or use the value of 0;

(3) for the hydrogen content in pitch used in the calculation in equation 3-2 in QC.3.3.2 and equation 3-5 in QC.3.3.3, the emitter may measure the content monthly or use the International Aluminium Institute factors;

(4) for the parameters relating to CF4 and C2F6 emissions attributable to anode effects and referred to in QC.3.4, the emitter must measure the parameters in accordance with QC.3.6.1;

(5) for the parameters concerning the use of SF6 and referred to in QC.3.5, the emitter must measure the parameters in accordance with QC.3.6.2;

(6) in the case of the quantity of calcinated coke, the emitter may directly measure that quantity or determine it by multiplying the recovery factor by the quantity of green coke consumed, in accordance with equation 3-10-1:

Equation 3-10.1

CCPM = RF × CGC

Where:

CCPM = Calcinated coke produced and measured during the measurement campaign, in metric tons;

RF = Recovery factor determined yearly during a measurement campaign, in metric tons of calcinated coke per metric ton of green coke;

CGC = Consumption of green coke measured during the measurement campaign, in metric tons;

(7) in the case of the average carbon content of prebaked anodes used in the calculation in equation 3-1.1 in QC.3.3, the emitter may measure the content in accordance with the most recent version of ASTM D5373 “Standard Test Methods for Determination of Carbon, Hydrogen and Nitrogen in Analysis Samples of Coal and Carbon in Analysis Samples of Coal and Coke”, the most recent version of ISO 29541 “Solid mineral fuels — Determination of total carbon, hydrogen and nitrogen content — Instrumental method”, or any other analysis method published by a body referred to in QC.1.5.

QC.3.6.1. CF4 and C2F6 emissions from anode effects

An emitter who uses a continuous emission monitoring and recording system for CF4 and C2F6 emissions attributable to anode effects must comply with the guidelines in the document “Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories” published by the Intergovernmental Panel on Climate Change.

An emitter who uses the slope method or the Péchiney method specified in QC.3.4.2 must conduct performance tests to calculate the slope or overvoltage coefficients for each technology used in a series of pots using the Protocol for Measurement of Tetrafluoromethane and Hexafluoroethane Emissions from Primary Aluminum Production published in April 2008 by the U.S. Environmental Protection Agency (USEPA) and the International Aluminum Institute. The tests must be conducted whenever

(1) 36 months have passed since the last tests or a series of pots is started up;

(2) a change occurs in the control algorithm that affects the intensity or duration of the anode effects or the nature of the anode effect termination routine; or

(3) changes occur in the distribution or duration of anode effects, for example when the percentage of manual kills changes or when, over time, the number of anode effects decreases and results in anode effects of shorter duration, or when the algorithm for bridge movements and anode effect overvoltage accounting changes.

The slope or the overvoltage coefficient calculated following the performance tests conducted in the cases provided for in subparagraph 1 of the second paragraph must be used beginning on

(1) the date of the measurements; or

(1) 1 January immediately following the measurements.

The slope or the overvoltage coefficient calculated following the performance tests conducted in the cases provided for in subparagraphs 2 and 3 of the second paragraph must be used beginning on

(1) the date of the change; or

(2) 1 January immediately following the measurements.

QC.3.6.2. Emissions of SF6 used as a cover gas

An emitter who uses the direct measurement method in QC.3.5.2 to calculate SF6 emissions attributable to the consumption of cover gas must measure monthly the quantity of SF6 entering the electrolysis cells and the quantity and SF6 concentration of any residual gas collected and shipped out of the establishment.

QC.3.7. Methods for estimating missing data

When, as part of an emitter’s sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, reanalyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.

When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:

(1) an emitter who uses one of the calculation methods provided for in this Protocol must,

(a) when the missing data concern carbon content, sulphur content, ash content, hydrogen content, water content, CSM emissions, pitch content, carbon present in skimmed dust from electrolysis cells, volatiles content, data for slope calculations, frequency and duration of anode effects, overvoltage, SF6 concentration or data to calculate current efficiency,

i. determine the sampling or measurement rate using the following equation:

Equation 3-11

R = QS Act/QS Required

Where:

R = Actual sampling or measurement rate, expressed as a percentage;

QS Act = Quantity of actual samples or measurements obtained by the emitter;

QS Required = Quantity of samples or measurements required under QC.3.6;

ii. for data that require sampling or analysis,

— if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;

— if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;

— if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;

(b) when the missing data concern net anode consumption, anode paste consumption, packing material consumption, green anode or cathode consumption, quantity of tar recovered, green coke consumption, liquid aluminum production, aluminum hydrate production, baked anode or cathode production, calcinated and under-calcinated coke production, coke dust quantity or SF6 quantity, the replacement data must be estimated on the basis of all the data relating to the processes used;

(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.

QC.3.8 Table

Table 3-1. C2F6/CF4 weight fractions based on the technology used

(QC.3.4.2)

 ________________________________________________________________
|                                     |                          |
|     Technology used                 |     Weight fraction      |
|                                     |     (kg C2F6/kg CF4)      |
|_____________________________________|__________________________|
|                                     |                          |
|  Centre-worked prebaked anodes      |          0.121           |
|  (CWPB)                             |                          |
|_____________________________________|__________________________|
|                                     |                          |
|  Side-worked prebaked anodes        |          0.252           |
|  (SWPB)                             |                          |
|_____________________________________|__________________________|
|                                     |                          |
|  Vertical stud Söderberg (VSS)      |          0.053           |
|_____________________________________|__________________________|
|                                     |                          |
|  Horizontal stud Söderberg (HSS)    |          0.085           |
|_____________________________________|__________________________|                        

QC.4. CEMENT PRODUCTION

QC.4.1. Covered sources

The covered sources are all the processes used to produce Portland, natural, masonry, pozzolanic, or other hydraulic cements.

QC.4.2. Greenhouse gas emissions reporting requirements

In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular,

(1) (subparagraph revoked);

(2) the annual CO2 emissions attributable to the calcination process, in metric tons;

(3) for each cement kiln:

(a) the monthly CO2 emission factors, in metric tons of CO2 per metric ton of clinker;

(b) the annual quantity of clinker produced, in metric tons;

(c) (subparagraph revoked);

(d) (subparagraph revoked);

(d.1) (subparagraph revoked);

(d.2) (subparagraph revoked);

(e) (subparagraph revoked);

(f) (subparagraph revoked);

(g) (subparagraph revoked);

(h) the quarterly CO2 emission factors for the dust collected that is not recycled to the cement kiln, in metric tons of CO2 per metric ton of dust;

(h.1) (subparagraph revoked);

(h.2) (subparagraph revoked);

(i) the annual quantity of dust collected that is not recycled to the cement kiln, in metric tons;

(4) (subparagraph revoked);

(5) the annual CO2 emissions attributable to the oxidation of organic carbon, in metrictons;

(6) for each type of carbon-containing raw material that contributes 0.5% or more of the total carbon in the process:

(a) the quantity of raw material consumed during the year, in metric tons;

(b) the total organic carbon content of the raw material, in metric tons of organic carbon per metric ton of raw material;

(7) (subparagraph revoked);

(8) annual CO2, CH4 and N2O emissions attributable to the use of all fixed combustion equipment, calculated and reported in accordance with QC.1 in metric tons;

(9) the number of times that the methods for estimating missing data in QC.4.5 were used;

(10) (subparagraph revoked);

(11) the annual quantities of gypsum and limestone added to the clinker produced by the establishment, in metric tons.

Subparagraphs a and h of subparagraph 3 and subparagraph b of subparagraph 6 of the first paragraph do not apply to the emissions of an emitter who calculates emissions using data from a continuous emission monitoring and recording system.

For the purposes of subparagraph 8 of the first paragraph of section 6.2:

(1) the emissions referred to in subparagraphs 2 and 5 of the first paragraph are emissions attributable to fixed processes;

(2) the emissions referred to in subparagraph 8 of the first paragraph are emissions attributable to combustion.

QC.4.3. Calculation method for CO2, CH4 and N2O emissions from the use of cement kilns

The annual CO2 emissions attributable to the use of cement kilns, other than combustion emissions, must be calculated in accordance with one of the 2 calculation methods in QC.4.3.1 and QC.4.3.2.

The annual CO2, CH4 and N2O emissions attributable to the combustion of fuels in all cement kilns must be calculated in accordance with QC.4.3.3.

QC.4.3.1. Use of a continuous emission monitoring and recording system

The annual CO2 emissions may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.1.3.4. In addition, the CO2 emissions attributable to the combustion of fuels in all cement kilns must be calculated in accordance with QC.4.3.3.

QC.4.3.2. Calculation by mass balance

The CO2 emissions attributable to the use of each cement kiln must be calculated by adding together the CO2 emissions attributable to calcination and the CO2 emissions attributable to the oxidation of the organic carbon present in the raw materials, calculated in accordance with the following methods:

(1) the CO2 emissions attributable to calcination must be calculated, for each cement kiln, using equations 4-1 to 4-3:

Equation 4-1

Where:

CO2 - C = CO2 emissions attributable to calcination, in metric tons;

i = Month;

Cli = Monthly production of clinker, in metric tons;

EFCli = Monthly CO2 emission factor for the clinker, established using equation 4-2, in metric tons of CO2 per metric ton of clinker;

j = Quarter;

QCKD = Quarterly quantity of dust collected that is not recycled to the cement kiln, in metric tons;

EFCKD = Quarterly CO2 emission factor for the dust collected that is not recycled to the cement kiln, established using equation 4-3, in metric tons of CO2 per metric ton of dust;

Equation 4-2

EFCli = (CaOCli - CaONCC) × 0.785 + (MgOCli - MgONCC) × 1.092

Where:

EFCli = Monthly CO2 emission factor for the clinker, in metric tons of CO2 per metric ton of clinker;

CaOCli = Monthly content of calcium oxide in the clinker, determined in accordance with paragraph 1 of QC.4.4, in metric tons of calcium oxide per metric ton of clinker;

CaONCC = Monthly content of non-calcined calcium oxide in the clinker, in metric tons of non-calcined calcium oxide per metric ton of clinker.

The non-calcined calcium oxide content in the clinker is the sum of the CaO content present as a non-carbonate species in the raw materials before entering the kiln and the non-transformed CaCO3 content remaining in the clinker after oxidation, expressed as CaO; these values must be determined, respectively, in accordance with paragraphs 4 and 5 of QC.4.4, or a value of 0 must be used;

0.785 = Ratio of molecular weights, CO2 to calcium oxide;

MgOCli = Monthly content of magnesium oxide in the clinker, determined in accordance with paragraph 1 of QC.4.4, in metric tons of magnesium oxide per metric ton of clinker;

MgONCC = Monthly content of non-calcined magnesium oxide in the clinker, in metric tons of noncalcined magnesium oxide per metric ton of clinker.

The non-calcined magnesium oxide content in the clinker is the sum of the MgO content present as a non-carbonate species in the raw materials before entering the kiln and the non-transformed MgCO3 content remaining in the clinker after oxidation, expressed as MgO; these values must be determined, respectively, in accordance with paragraphs 4 and 5 of QC.4.4, or a value of 0 must be used;

1.092 = Ratio of molecular weights, CO2 to magnesium oxide;

Equation 4-3

EFCKD = (CaOCKD - CaONCD) × 0.785 + (MgOCKD - MgONCD) × 1.092

Where:

EFCKD = Quarterly CO2 emission factor for the dust collected that is not recycled to the cement kiln, in metric tons of CO2 per metric ton of dust;

CaOCKD = Quarterly content of calcium oxide in the dust collected that is not recycled to the cement kiln, determined in accordance with paragraph 6 of QC.4.4, in metric tons of calcium oxide per metric ton of dust;

CaONCD = Quarterly content of non-calcined calcium oxide in the dust collected that is not recycled to the cement kiln, in metric tons of non-calcined calcium oxide per metric ton of dust.

The non-calcined calcium oxide content in the dust is the sum of the CaO content present as a non-carbonate species in the raw materials before entering the kiln and the non-transformed CaCO3 content remaining in the kiln dust collected that is not recycled after oxidation, expressed as CaO; these values must be determined, respectively, in accordance with paragraphs 7 and 8 of QC.4.4, or a value of 0 must be used;

0.785 = Ratio of molecular weights, CO2 to calcium oxide;

MgOCKD = Quarterly content of magnesium oxide in the kiln dust collected that is not recycled in the cement kiln, determined in accordance with paragraph 6 of QC.4.4, in metric tons of magnesium oxide per metric ton of dust;

MgONCD = Quarterly content of non-calcined magnesium oxide in the dust collected that is not recycled to the cement kiln, in metric tons of noncalcined magnesium oxide per metric ton of dust.

The non-calcined magnesium oxide content in the dust is the sum of the magnesium oxide before entering the kiln as a non-carbonate species and the non-transformed MgCO3 content remaining in the kiln dust collected that is not recycled after oxidation, expressed as MgO; these values must be determined, respectively, in accordance with paragraphs 7 and 8 of QC.4.4, or a value of 0 must be used;

1.092 = Ratio of molecular weights, CO2 to magnesium oxide;

(2) the CO2 emissions attributable to the oxidation of the organic carbon present in the raw material must be calculated using equation 4-4:

Equation 4-4

Where:

CO2,RMm = CO2 emissions resulting from the oxidation of the raw material, in metric tons;

n = Number of raw materials;

m = Raw material;

TOCRMm = Total organic carbon content in raw material, determined in accordance with paragraph 10 of QC.4.4 or using a default value of 0.2% metric tons of total organic carbon content per metric ton of raw material;

RMm = Quantity of raw material, in metric tons;

3.664 = Ratio of molecular weights, CO2 to carbon.

QC.4.3.3. Calculation of the emissions attributable to the combustion of the fuels used in cement kilns

The CO2, CH4 and N2O emissions attributable to fuel combustion in each cement kiln must be calculated and reported using the calculation methods in QC.1. When pure biomass fuels, in other words fuels constituted of the same substance for at least 97% of their total weight, are combusted only during start-up, shut-down, or malfunction operating periods for the apparatus or units, the emitter may calculate CO2 emissions using the calculation method in QC.1.3.1.

QC.4.4. Sampling, analysis and measurement requirements

When using the calculation method in QC.4.3.2, an emitter who operates a facility or establishment that produces cement must

(1) determine monthly the calcium oxide and magnesium oxide content of the clinker, in accordance with the most recent version of ASTM C114 “Standard Test Methods for Chemical Analysis of Hydraulic Cement”, or using any other analysis method published by an organization listed in QC.1.5; the measurements being made daily from clinker drawn from the clinker cooler or monthly from clinker drawn from bulk storage;

(2) determine monthly the quantity of clinker produced using one of the following methods:

(a) direct weight measurement using the same plant instruments used for accounting purposes, such as weigh hoppers or belt weigh feeders, and ensure that the results obtained are consistent with the inventory data;

(b) direct measurement of raw kiln feed applying a kiln-specific feed-to-clinker conversion factor, the accuracy of the factor being verified by the emitter on an annual basis and whenever a major change to the process may affect the factor;

(3) determine monthly the quantity of raw materials consumed by direct weight measurement using the same plant instruments used for inventory purposes, such as weigh hoppers or belt weigh feeders, or using a material balance;

(4) determine monthly the calcium oxide and magnesium oxide content of the raw material before entering the kiln as a non-carbonate species using an analysis method published by an organization listed in QC.1.5;

(5) determine monthly the non-transformed CaCO3 content, expressed in CaO, remaining in the clinker and the nontransformed MgCO3 content, expressed in MgO, remaining in the clinker after oxidation using an analysis method published by an organization listed in QC.1.5;

(6) determine quarterly the calcium oxide and magnesium oxide content in the kiln dust collected that is not recycled to the cement kiln in accordance with the most recent version of ASTM C114, or using any other analysis method published by an organization listed in QC.1.5; the measurements being made daily at the exit of the kiln or quarterly if the dust is in bulk storage;

(7) determine quarterly the calcium oxide and magnesium oxide content in the kiln dust collected that is not recycled before entering the kiln as a non-carbonate species using an analysis method published by an organization listed in QC.1.5;

(8) determine quarterly the non-transformed CaCO3 content, expressed in CaO, and the non-transformed MgCO3 content, expressed in MgO, remaining in the kiln dust collected that is not recycled after oxidation using an analysis method published by an organization listed in QC.1.5;

(9) determine quarterly the quantity of kiln dust collected that is not recycled to the cement kiln by direct weight measurement using the same plant instruments used for inventory purposes, such as weigh hoppers or belt weigh feeders, or using a material balance;

(10) take samples annually of each category of raw materials in bulk storage and determine the total organic carbon content of the raw materials in accordance with the most recent version of ASTM C114 or in accordance with any other analysis method published by an organization listed in QC.1.5, or use the value of 0.2%.

QC.4.5. Methods for estimating missing data

When, as part of an emitter’s sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.

When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:

(1) an emitter who uses one of the calculation methods provided for in this Protocol must,

(a) when the missing data concern carbon content, calcium oxide content or magnesium oxide content,

i. determine the sampling or measurement rate using the following equation:

Equation 4-5

R = QS Act/QS Required

Where:

R = Actual sampling or measurement rate, expressed as a percentage;

QS Act = Quantity of actual samples or measurements obtained by the emitter;

QS Required = Quantity of samples or measurements required under QC.4.4;

ii. for data that require sampling or analysis,

— if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;

— if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;

— if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;

(b) when the missing data concern clinker production, the emitter must use the first data estimated after the period for which the data is missing or use the maximum daily production capacity and multiply it by the number of days in the month;

(c) when the missing data concern raw material consumption, the emitter must use the first data estimated after the period for which the data is missing or use the maximum rate of raw materials entering the kiln and multiply by the number of days in the month;

(d) when the missing data concern the quantity of dust, the quantity of gypsum or the quantity of limestone, the replacement data must be estimated on the basis of all the data relating to the processes used;

(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.

QC.5. COAL STORAGE

QC.5.1. Covered sources

The covered sources are all activities involving coal storage, in other words all post-mining activities such as preparation, handling, processing, transportation and storage.

QC.5.2. Greenhouse gas reporting requirements

In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:

(1) the annual CH4 emissions in metric tons;

(2) the annual coal purchases, in metric tons;

(3) the source of coal purchases:

(a) name of coal basin;

(b) source province or state;

(c) coal mine type (surface or underground);

(4) the number of times that the methods for estimating missing data provided for in QC.5.5 were used;

(5) (subparagraph revoked).

QC.5.3. Calculation methods for CH4 emissions

The annual CH4 emissions from coal storage must be calculated in accordance with the following calculation methods:

(1) CH4 emissions from coal storage must be calculated using equation 5-1:

Equation 5-1

Where:

CH4 = Annual CH4 fugitive emissions from coal storage, for each type of coal i, in metric tons;

n = Total number of types of coal;

i = Type of coal;

PCi = Annual purchases of coal, for each type of coal i, in metric tons;

EFi = CH4 emission factor for type of coal i, established in accordance with paragraph 2, in cubic metres of CH4 per metric ton of coal;

0.6772 = Conversion factor, cubic metres to kilograms of CH4;

0.001 = Conversion factor, kilograms to metric tons;

(2) the CH4 emission factor (EFi) must be based on the location and mine type where the coal was mined, in accordance with the following requirements:

(a) when the coal comes from a location in the United States, the emission factor is provided in Table 5-1 in QC.5.6;

(b) when the coal comes from a location in Canada, the emission factor is provided in Table 5-2 in QC.5.6;

(c) when the coal comes from a location outside Canada and the United States, the emission factor must be the factor determined in Table 5-3 in QC.5.6;.

QC.5.4. Sampling, analysis and measurement requirements

An emitter who operates a facility or establishment that stores coal must determine the total quantity of coal purchased

(1) by using invoices for coal purchases; or

(2) by weighing the coal using the same plant instruments used for inventory purposes, such as weigh hoppers or belt weigh feeders.

QC.5.5. Methods for estimating missing data

The emitter must demonstrate that everything has been done to capture 100% of the data.

When data relating to the total quantity of carbon purchased is missing, the replacement data must be estimated using all the data relating to the processes used.

QC.5.6. Tables

Table 5-1. CH4 emission factors for post-mining activities involving the storage or handling of coal from the United States

(QC.5.3(2)(a))

 ________________________________________________________________________________
|                                             |                                  |
|                                             |   CH4 emission factor by coal    |
| Coal origin                                 |      mine type (cubic metres     |
|                                             |           /metric ton)           |
|_____________________________________________|__________________________________|
|                       |                     |                 |                |
| State                 |   Coal basin        |     Surface     |  Underground   |
|                       |                     |       mine      |      mine      |
|_______________________|_____________________|_________________|________________|
|                       |                     |                 |                |
| Maryland, Ohio,       | Northern Appalachia |                 |                |
| Pennsylvania,         |                     |                 |                |
| West virginia North   |                     | 0.6025          |  1.4048        |
|_______________________|_____________________|_________________|________________|
|                       |                     |                 |                |
| Tennessee, West       | Central Appalachia  |                 |                |
| Virginia South        | Appalachia (WV)     |  0.2529         |  1.3892        |
|_______________________|_____________________|_________________|________________|
|                       |                     |                 |                |
| Virginia              | Central             |                 |                |
|                       | Appalachia (VA)     |  0.2529         |  4.0490        |
|_______________________|_____________________|_________________|________________|
|                       |                     |                 |                |
| East Kentucky         | Central             |                 |                |
|                       | Appalachia (EKY)    |  0.2529         |  0.6244        |
|_______________________|_____________________|_________________|________________|
|                       |                     |                 |                |
| Alabama, Mississippi  | Warrior             |  0.3122         |  2.7066        |
|_______________________|_____________________|_________________|________________|
|                       |                     |                 |                |
| Illinois, Indiana,    | Illinois            |                 |                |
| Kentucky West         |                     |  0.3465         |  0.6525        |
|_______________________|_____________________|_________________|________________|
|                       |                     |                 |                |
|                       | Rockies             |                 |                |
|                       | (Piceance Basin)    |  0.3372         |  1.9917        |
|                       |_____________________|_________________|________________|
|                       |                     |                 |                |
|                       | Rockies             |                 |                |
| Arizona, California,  | (Uinta Basin)       |  0.1623         |  1.0083        |
| Colorado, New Mexico, |_____________________|_________________|________________|
| Utah                  |                     |                 |                |
|                       | Rockies             |                 |                |
|                       | (San Juan Basin)    |  0.0749         |  1.0645        |
|                       |_____________________|_________________|________________|
|                       |                     |                 |                |
|                       | Rockies             |                 |                |
|                       | (Green River Basin) |  0.3372         |  2.5068        |
|                       |_____________________|_________________|________________|
|                       |                     |                 |                |
|                       | Rockies             |                 |                |
|                       | (Raton Basin)       |  0.3372         |  1.2987        |
|_______________________|_____________________|_________________|________________|
|                       |                     |                 |                |
| Montana, North Dakota,| N. Great Plains     |                 |                |
| Wyoming               |                     |  0.0562         |  0.1592        |
|_______________________|_____________________|_________________|________________|
|                       |                     |                 |                |
|                       | West Interior       |                 |                |
|                       | (Forest City,       |                 |                |
|                       | Cherokee Basins)    |  0.3465         |  0.6525        |
|                       |_____________________|_________________|________________|
|                       |                     |                 |                |
| Arkansas, Iowa,       | West Interior       |                 |                |
| Kansas, Louisiana,    | (Arkoma Basin)      |  0.7555         |  3.3591        |
| Missouri, Oklahoma,   |_____________________|_________________|________________|
| Texas                 |                     |                 |                |
|                       | West Interior       |                 |                |
|                       | (Gulf coast Basin)  |  0.3372         |  1.2987        |
|_______________________|_____________________|_________________|________________|
|                       |                     |                 |                |
| Alaska                | Northwest (AK)      |  0.0562         |  1.6233        |
|_______________________|_____________________|_________________|________________|
|                       |                     |                 |                |
| Washington            | Northwest (WA)      |  0.0562         |  0.5900        |
|_______________________|_____________________|_________________|________________|                        

Table 5-2. CH4 emission factors for post-mining activities involving the storage or handling of coal from Canada

(QC.5.3(2)(b))

 _________________________________________________________________________________
|                                                    |   CH4emission factor by    |
| Coal origin                                        |      mine type (cubic      |
|                                                    |     metres/ metric ton)    |
|____________________________________________________|____________________________|
|                         |                          |              |             |
| Province                | Coal basin               |   Surface    | Underground |
|                         |                          |     mine     |    mine     |
|_________________________|__________________________|______________|_____________|
|                         |                          |              |             |
| British Colombia        | Comox                    |  0.500       |  N/A        |
|                         |__________________________|______________|_____________|
|                         |                          |              |             |
|                         | Crowness                 |  0.169       |  N/A        |
|                         |__________________________|______________|_____________|
|                         |                          |              |             |
|                         | Elk Valley               |  0.900       |  N/A        |
|                         |__________________________|______________|_____________|
|                         |                          |              |             |
|                         | Peace River              |  0.361       |  N/A        |
|                         |__________________________|______________|_____________|
|                         |                          |              |             |
|                         | Province average         |  0.521       | N/A         |
|_________________________|__________________________|______________|_____________|
|                         |                          |              |             |
| Alberta                 | Battle River             |  0.067       |  N/A        |
|                         |__________________________|______________|_____________|
|                         |                          |              |             |
|                         | Cadomin-Luscar           |  0.709       |  N/A        |
|                         |__________________________|______________|_____________|
|                         |                          |              |             |
|                         | Coalspur                 |  0.314       |  N/A        |
|                         |__________________________|______________|_____________|
|                         |                          |              |             |
|                         | Obed Mountain            |  0.238       |  N/A        |
|                         |__________________________|______________|_____________|
|                         |                          |              |             |
|                         | Sheerness                |  0.048       |  N/A        |
|                         |__________________________|______________|_____________|
|                         |                          |              |             |
|                         | Smokey River             |  0.125       |  0.067      |
|                         |__________________________|______________|_____________|
|                         |                          |              |             |
|                         | Wabamun                  |  0.176       |  N/A        |
|                         |__________________________|______________|_____________|
|                         |                          |              |             |
|                         | Province average         |  0.263       |  0.067      |
|_________________________|__________________________|______________|_____________|
|                         |                          |              |             |
| Saskatchewan            | Estavan                  |  0.055       |  N/A        |
|                         |__________________________|______________|_____________|
|                         |                          |              |             |
|                         | Willow Bunch             |  0.053       |  N/A        |
|                         |__________________________|______________|_____________|
|                         |                          |              |             |
|                         | Province average         |  0.054       |  N/A        |
|_________________________|__________________________|______________|_____________|
|                         |                          |              |             |
| New Brunswick           | Province average         |  0.060       |  N/A        |
|_________________________|__________________________|______________|_____________|
|                         |                          |              |             |
| Nova Scotia             | Province average         |  N/A         |  2.923      |
|_________________________|__________________________|______________|_____________|                        

Table 5-3. CH4 emission factors for post-mining activities involving the storage or handling of coal from the outside the United States and Canada

(QC.5.3(2)(c))

 _________________________________________________________________
|                                                                 |
|              CH4 emission factor by coal mine type              |
|              (cubic metres/metric ton)                          |
|_________________________________________________________________|
|                                |                                |
|   Surface mine                 |   Underground mine             |
|________________________________|________________________________|
|                                |                                |
|   0.279                        |   1.472                        |
|________________________________|________________________________|                        

QC.6. HYDROGEN PRODUCTION

QC.6.1. Covered sources

The covered sources are all the processes used to produce hydrogen.

QC.6.2. Greenhouse gas reporting requirements

In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:

(1) the annual CO2 emissions attributable to hydrogen production processes, in metric tons;

(2) the annual feedstock consumption by feedstock type, including petroleum coke, expressed

(a) in bone dry metric tons, when the quantity is expressed as a mass;

(b) in thousands of cubic metres at standard conditions, when the quantity is expressed as a volume of gas;

(c) in kilolitres, when the quantity is expressed as a volume of liquid;

(d) in bone dry metric tons, for biomass-derived solid fuels;

(3) the annual hydrogen produced, in thousands of cubic metres at standard conditions;

(4) the average annual carbon content of each feedstock type;

(5) the annual CO2, CH4 and N2O emissions attributable to combustion, calculated and reported in accordance with QC.1, in metric tons;

(6) the number of times that the methods for estimating missing data provided for in QC.6.5 were used;

(7) (subparagraph revoked).

Subparagraph 4 of the first paragraph does not apply to the CO2 emissions of an emitter who calculates emissions using data from a continuous emission monitoring and recording system.

For the purposes of subparagraph 8 of the first paragraph of section 6.2:

(1) the emissions referred to in subparagraph 1 of the first paragraph are emissions attributable to fixed processes;

(2) the emissions referred to in subparagraph 5 of the first paragraph are emissions attributable to combustion.

QC.6.3. Calculation methods for CO2 emissions

CO2 emissions from the production of hydrogen must be calculated using one of the calculation methods in QC.6.3.1 and QC.6.3.2.

QC.6.3.1. Use of a continuous emission monitoring and recording system

The annual CO2 emissions from the production of hydrogen may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.1.3.4.

QC.6.3.2. Calculation by feedstock material balance

The annual CO2 emissions attributable to the production of hydrogen may be calculated by feedstock material balance using equations 6-1 to 6-3, depending on the type of feedstock:

(1) in the case of feedstocks for which the quantity is expressed as a volume of gas, the emitter must use equation 6-1:

Equation 6-1

Where:

CO2 = Annual CO2 emissions attributable to the production of hydrogen, in metric tons;

j = Month;

Qj = Quantity of gaseous feedstock consumed in month j, in thousands of cubic metres at standard conditions, or in metric tons when a mass flowmeter is used;

CCj = Average carbon content of the feedstock based on the analysis results for month j and measured by an emitter in accordance with QC.6.4, in kilograms of carbon per kilogram of feedstock;

MW = Molecular weight of the feedstock, in kilograms per kilomole or, when a mass flowmeter is used to measure the flow, in metric tons per unit of time, replace

 _  _
|    |
| MW |
|----| by 1;
|MVC |
|_  _|                        

MVC = Molar volume conversion factor (24.06 m3 per kilomole at standard conditions);

3.664 = Ratio of molecular weights, CO2 to carbon;

1 = Conversion factor, kilograms to metric tons and thousands of cubic metres to cubic metres;

(2) in the case of feedstocks for which the quantity is expressed as a volume of liquid, the emitter must use equation 6-2:

Equation 6-2

Where:

CO2 = Annual CO2 emissions attributable to the production of hydrogen, in metric tons;

j = Month;

Qj = Quantity of raw material consumed in month j, in kilolitres;

CFj = Average carbon content of feedstock based on the analysis results for month j and measured by an emitter in accordance with QC.6.4, in metric tons of carbon per kilolitre of feedstock;

3.664 = Ratio of molecular weights, CO2 to carbon;

(3) in the case of feedstocks for which the quantity is expressed as a mass, the emitter must use equation 6-3:

Equation 6-3

Where:

CO2 = Annual CO2 emissions attributable to the production of hydrogen, in metric tons;

j = Month;

Qj = Quantity of raw material consumed in month j, in metric tons;

CCj = Average carbon content of the feedstock based on the analysis results for month j and measured by an emitter in accordance with QC.6.4, in kilograms of carbon per kilogram of feedstock;

3.664 = Ratio of molecular weights, CO2 to carbon.

QC.6.4. Sampling, analysis and measurement requirements

An emitter who uses the calculation method in QC.6.3.2 must

(1) measure the feedstock consumption rate daily;

(2) determine the carbon content using either of the following methods:

(a) by collecting and analyzing samples of each type of feedstock consumed to measure the average carbon content using the methods specified in paragraph 5,

i. daily, for all feedstocks except natural gas, by collecting the sample from a location that provided samples representative of the feedstock consumed in the hydrogen production process;

ii. monthly, when natural gas is used as feedstock and not mixed with another feedstock prior to consumption;

(b) by using the carbon content indicated by the fuel supplier;

(3) determine the hydrogen produced daily;

(4) determine, quarterly, the quantity of CO2 and of carbon monoxide transferred off-site;

(5) to measure the average carbon content of each type of feedstock, use an analysis method published by an organization listed in QC.1.5 or one of the following analysis methods:

(a) for solid feedstocks, the most recent version of ASTM D2013/D2013M “Standard Practice for Preparing Coal Samples for Analysis”, ASTM D2234/D2234M “Standard Practice for Collection of a Gross Sample of Coal”, ASTM D3176 “Standard Practice for Ultimate Analysis of Coal and Coke”, ASTM D6609 “Standard Guide for Part-Stream Sampling of Coal”, ASTM D6883 “Standard Practice for Manual Sampling of Stationary Coal from Railroad Cars, Barges, Trucks, or Stockpiles” or ASTM D7430 “Standard Practice for Mechanical Sampling of Coal”;

(b) for liquid feedstocks, the most recent version of ASTM D2597 “Standard Test Method for Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing Nitrogen and Carbon Dioxide by Gas Chromatography”, ASTM D4057 “Standard Practice for Manual Sampling of Petroleum and Petroleum Products”, ASTM D4177 “Standard Practice for Automatic Sampling of Petroleum and Petroleum Products”, ISO 3170 “Petroleum Liquids—Manual sampling” or ISO 3171 “Petroleum liquids—Automatic pipeline sampling”;

(c) for gaseous feedstocks, the most recent version of UOP539 “Refinery Gas Analysis by Gas Chromatography” or GPA 2261 “Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography”.

QC.6.5. Methods for estimating missing data

When, as part of an emitter’s sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.

When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:

(1) an emitter who uses one of the calculation methods provided for in this Protocol must,

(a) when the missing data concern carbon content or molecular mass,

i. determine the sampling or measurement rate using the following equation:

Equation 6-4

R = QS Act/QS Required

Where:

R = Actual sampling or measurement rate, expressed as a percentage;

QS Act = Quantity of actual samples or measurements obtained by the emitter;

QS Required = Quantity of samples or measurements required under QC.6.4;

ii. for data that require sampling or analysis,

— if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;

— if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;

— if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;

(b) when the missing data concern raw material consumption or hydrogen production, the replacement data must be estimated on the basis of all the data relating to the processes used;

(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.

QC.7. IRON AND STEEL PRODUCTION

QC.7.1. Covered sources

The covered sources are primary processes to produce both iron and steel, secondary steelmaking processes, iron production processes, metallurgical coke production processes and iron ore pellet firing processes.

QC.7.2. Greenhouse gas reporting requirements

In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:

(1) for all types of process:

(a) (subparagraph revoked);

(b) the annual CO2, CH4 and N2O emissions attributable to the use of stationary combustion units, calculated and reported in accordance with QC.1, in metric tons;

(2) for metallurgical coke production:

(a) the annual CO2 and CH4 emissions attributable to the production of metallurgical coke, in metric tons;

(b) the annual consumption of coking coal used in the production of metallurgical coke, in metric tons;

(c) (subparagraph revoked);

(d) (subparagraph revoked);

(e) the annual production of metallurgical coke, in metric tons;

(f) the quantity of coke oven gas transferred out of the establishment during the year, in metric tons;

(g) the quantity of other coke oven by-products, such as coal tar and light oil, transferred out of the establishment during the year, in metric tons;

(g.1) the annual quantity of air pollution control residue collected, in metric tons;

(h) the average annual carbon content of the materials input for the production of metallurgical coke and of derivatives of those materials referred to in subparagraphs b to g.1, in metric tons of carbon per metric ton of material;

(h.1) the CH4 emission factors, as the case may be:

i. determined by the emitter, including the methods that were used for estimating those factors;

ii. indicated in Tables 1-1 to 1-8 of QC.1.7. If no factor is indicated in those tables, the emitter may use a factor determined by Environment Canada, the U.S. Environmental Protection Agency (USEPA) or the Intergovernmental Panel on Climate Change (IPCC);

(3) for steel production using a basic oxygen furnace:

(a) the annual CO2 and CH4 emissions attributable to steel production using a basic oxygen furnace, in metric tons;

(b) the annual consumption of molten iron and ferrous scrap, in metric tons;

(c) the annual consumption of each carbon-containing raw material that contributes 0.5% or more of the total carbon in the process, in metric tons;

(d) the annual production of steel, in metric tons;

(e) the quantity of slag produced, in metric tons;

(f) the quantity of basic oxygen furnace gas transferred off-site during the year, in metric tons;

(g) the annual quantity of air pollution control residue collected, in metric tons;

(h) the average annual carbon content of the materials and products referred to in subparagraphs b to g that contribute 0.5% or more of the total carbon in the process, in metric tons of carbon per metric ton of material and products;

(i) the CH4 emission factors, as the case may be:

i. determined by the emitter, including the methods that were used for estimating those factors;

ii. indicated in Tables 1-1 to 1-8 of QC.1.7. If no factor is indicated in those tables, the emitter may use a factor determined by Environment Canada, the U.S. Environmental Protection Agency (USEPA) or the Intergovernmental Panel on Climate Change (IPCC);

(4) for sinter production:

(a) the annual CO2 and CH4 emissions attributable to sinter production, in metric tons;

(b) the annual quantity of each carbonaceous material used in sinter production, in metric tons;

(c) the annual consumption of each raw material used in sinter production, other than carbonaceous materials that contribute 0.5% or more of the total carbon introduced in the process, in metric tons;

(d) the annual production of sinter, in metric tons;

(e) the annual quantity of air pollution control residue collected, in metric tons;

(f) the average annual carbon content of the materials and products referred to in subparagraphs b to e that contribute 0.5% or more of the total carbon in the process, in metric tons of carbon per metric ton of material and products;

(g) the CH4 emission factors, as the case may be:

i. determined by the emitter, including the methods that were used for estimating those factors;

ii. indicated in Tables 1-1 to 1-8 of QC.1.7. If no factor is indicated in those tables, the emitter may use a factor determined by Environment Canada, the U.S. Environmental Protection Agency (USEPA) or the Intergovernmental Panel on Climate Change (IPCC);

(5) for steel production using an electric arc furnace:

(a) the annual CO2 and CH4 emissions attributable to steel production using an electric arc furnace, in metric tons;

(b) the annual consumption of direct reduced iron pellets, in metric tons;

(c) the annual consumption of ferrous scrap, in metric tons;

(d) the annual consumption of each flux material, in metric tons;

(e) the annual consumption of carbon electrodes, in metric tons;

(f) the annual consumption of each carbon-containing raw material that contributes 0.5% or more of the total carbon in the process, in metric tons;

(g) the annual production of steel, in metric tons;

(h) the quantity of slag produced, in metric tons;

(i) the annual quantity of air pollution control residue collected, in metric tons;

(j) the average annual carbon content of the materials and products referred to in subparagraphs b to j that contribute 0.5% or more of the total carbon in the process, in metric tons of carbon per metric ton of material or product;

(k) the CH4 emission factors, as the case may be:

i. determined by the emitter, including the methods that were used for estimating those factors;

ii. indicated in Tables 1-1 to 1-8 of QC.1.7. If no factor is indicated in those tables, the emitter may use a factor determined by Environment Canada, the U.S. Environmental Protection Agency (USEPA) or the Intergovernmental Panel on Climate Change (IPCC);

(6) for the argon-oxygen decarburization of molten steel:

(a) the annual CO2 and CH4 emissions attributable to the oxygen decarburization or the vacuum degassing process using argon of molten steel, in metric tons;

(b) the annual quantity of molten steel charged to the process, in metric tons;

(c) the average annual carbon content of the molten steel before decarburization, in metric tons of carbon per metric ton of molten steel;

(d) the average annual carbon content of the molten steel after decarburization, in metric tons of carbon per metric ton of molten steel;

(e) the annual quantity of air pollution control residue collected, in metric tons;

(f) the average annual carbon content of the air pollution control residue collected, in metric tons of carbon per metric ton of residue;

(g) the CH4 emission factors determined by the emitter and the methods used to estimate them;

(7) for iron production using the direct reduction process:

(a) the annual CO2 and CH4 emissions attributable to iron production by direct reduction, in metric tons;

(b) the annual consumption of ore or pellets, in metric tons;

(c) the annual consumption of each carbon-containing raw material, other than ore or pellets, that contributes 0.5% or more of the total carbon in the process, in metric tons;

(d) the annual production of reduced iron pellets, in metric tons;

(e) the annual quantity of non-metallic by-products, in metric tons;

(f) the annual quantity of air pollution control residue collected, in metric tons;

(g) the average annual carbon content of the materials and products referred to in subparagraphs b to f that contribute 0.5% or more of the total carbon in the process, in metric tons of carbon per metric ton of material or product;

(h) the CH4 emission factors, as the case may be:

i. determined by the emitter, including the methods that were used for estimating those factors;

ii. indicated in Tables 1-1 to 1-8 of QC.1.7. If no factor is indicated in those tables, the emitter may use a factor determined by Environment Canada, the U.S. Environmental Protection Agency (USEPA) or the Intergovernmental Panel on Climate Change (IPCC);

(8) for iron production using a blast furnace:

(a) the annual CO2 and CH4 emissions attributable to iron production using a blast furnace, in metric tons;

(b) the annual consumption of ore or pellets, in metric tons;

(c) the annual consumption of each carbon-containing raw material, other than ore or pellets, that contributes 0.5% or more of the total carbon in the process, in metric tons;

(d) the annual consumption of each flux material, in metric tons;

(e) the annual production of iron, in metric tons;

(f) the annual quantity of non-metallic by-products, in metric tons;

(g) the annual quantity of air pollution control residue collected, in metric tons;

(h) the average annual carbon content of the materials and products referred to in subparagraphs b to g that contribute 0.5% or more of the total carbon in the process, in metric tons of carbon per metric ton of material and product;

(i) the CH4 emission factors, as the case may be:

i. determined by the emitter, including the methods that were used for estimating those factors;

ii. indicated in Tables 1-1 to 1-8 of QC.1.7. If no factor is indicated in those tables, the emitter may use a factor determined by Environment Canada, the U.S. Environmental Protection Agency (USEPA) or the Intergovernmental Panel on Climate Change (IPCC);

(9) for the indurating of iron ore pellets:

(a) the annual CO2 and CH4 emissions attributable to the indurating of iron ore pellets, for each type of pellets, in metric tons;

(b) the annual consumption of greenball pellets, in metric tons;

(c) the annual production of each type of fired pellets, in metric tons;

(d) the annual quantity of air pollution control residue collected, in metric tons;

(e) the average annual carbon content of the materials and products referred to in subparagraphs b to d and f that contribute 0.5% or more of the total carbon in the process, in metric tons of carbon per metric ton of material and product;

(f) the annual quantities of each raw material used, other than greenball pellets, in metric tons;

(g) (subparagraph revoked);

(9.1) in case a ladle furnace is used:

(a) the annual CO2 emissions attributable to the use of the ladle furnace, in metric tons;

(b) the annual quantity of liquid steel fed into the ladle furnace, in metric tons;

(c) the annual consumption of each additive that contributes 0.5% or more of the total carbon in the process, in metric tons;

(d) the annual consumption of carbon electrodes, in metric tons;

(e) the annual production of steel, in metric tons;

(f) the quantity of slag produced, in metric tons;

(g) the annual quantity of air pollution control residue, in metric tons;

(h) the annual quantity of residue other than those referred to in subparagraph g, in metric tons;

(i) the annual average carbon content of materials and products referred to in subparagraphs b to h that contribute 0.5% or more of the total carbon in the process, in metric tons of carbon per metric ton of materials or products;

(10) the number of times that the methods for estimating missing data provided for in QC.7.6 were used;

(11) (subparagraph revoked);

(12) the annual quantity of steel exiting each rolling mill, in metric tons;

(13) the annual quantity of forged steel produced, that is the quantity of steel, in the form of ingot, being brought to the forging operation, excluding from the initial weight of the ingot the weight of the part of the cut steel when the head of the ingot is cut prior to forging, in metric tons;

(14) the annual quantity of steel slabs, billets or ingots produced at the steel mill, in metric tons.

Subparagraph h of subparagraph 2, subparagraph h of subparagraph 3, subparagraph f of subparagraph 4, subparagraph j of subparagraph 5, subparagraphs c, d and f of subparagraph 6, subparagraph g of subparagraph 7, subparagraph h of subparagraph 8 and subparagraph e of subparagraph 9 of the first paragraph do not apply to the CO2 emissions of an emitter who calculates emissions using data from a continuous emission monitoring and recording system.

Subparagraph h.1 of subparagraph 2, subparagraph i of subparagraph 3, subparagraph g of subparagraph 4, subparagraph k of subparagraph 5, subparagraph g of subparagraph 6, subparagraph h of subparagraph 7, subparagraph i of subparagraph 8, subparagraph e of subparagraph 9 and subparagraph i of subparagraph 9.1 of the first paragraph do not apply to the CH4 emissions of an emitter who calculates emissions using data from a continuous emission monitoring and recording system.

For the purposes of subparagraph 8 of the first paragraph of section 6.2:

(1) the emissions of CO2 referred to in subparagraphs a of subparagraphs 2 to 9 of the first paragraph are emissions attributable to fixed processes;

(2) the emissions referred to in subparagraph b of subparagraph 1 of the first paragraph are emissions attributable to combustion;

(3) the emissions of CH4 referred to in subparagraphs a of subparagraphs 2 to 9 of the first paragraph are other emissions.

QC.7.3. Calculation methods for CO2 emissions

An emitter must calculate the annual CO2 emissions attributable to primary processes to produce both iron and steel, secondary steelmaking processes, iron production processes, metallurgical coke production processes and iron ore pellet indurating processes using one of the calculation methods in QC.7.3.1 and QC.7.3.2.

QC.7.3.1. Use of a continuous emission monitoring and recording system

The annual CO2 emissions attributable to primary processes to produce both iron and steel, secondary steelmaking processes, iron production processes, metallurgical coke production processes and iron ore pellet indurating processes may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.1.3.4.

QC.7.3.2. Calculation by mass balance

The annual CO2 emissions attributable to primary processes to produce both iron and steel, secondary steelmaking processes, iron production processes, metallurgical coke production processes and iron ore pellet indurating processes must be calculated using the methods in paragraphs 1 to 9 depending on the process used, expressed

(1) for primary processes to produce both iron and steel, secondary steelmaking processes, iron production processes, metallurgical coke production processes and iron ore pellet indurating processes, using equation 7-1:

Equation 7-1

CO2 = CO2, COKE + CO2, BOF + CO2, SINTER + CO2, EAF + CO2, AOD + CO2, DR + CO2, BF + CO2, IP + CO2, LF

Where:

CO2 = Annual CO2 emissions attributable to primary processes to produce both iron and steel, secondary steelmaking processes, iron production processes, metallurgical coke production processes and iron ore pellet firing processes, in metric tons;

CO2, COKE = Annual CO2 emissions attributable to the production of metallurgical coke, calculated in accordance with equation 7-2, in metric tons;

CO2, BOF = Annual CO2 emissions attributable to steel production using a basic oxygen furnace, calculated in accordance with equation 7-3, in metric tons;

CO2, SINTER = Annual CO2 emissions attributable to sinter production, calculated in accordance with equation 7-4, in metric tons;

CO2, EAF = Annual CO2 emissions attributable to steel production using an electric arc furnace, calculated in accordance with equation 7-5, in metric tons;

CO2, AOD = Annual CO2 emissions attributable to oxygen decarburization or the vacuum degassing using argon, calculated in accordance with equation 7-6, in metric tons;

CO2, DR = Annual CO2 emissions attributable to iron production using the direct reduction process, calculated in accordance with equation 7-7, in metric tons;

CO2, BF = Annual CO2 emissions attributable to iron production using a blast furnace, calculated in accordance with equation 7-8, in metric tons;

CO2, IP = Annual CO2 emissions attributable to the indurating of iron ore pellets, calculated in accordance with equation 7-9, in metric tons;

CO2, LF = Annual CO2 emissions attributable to using a ladle furnace, calculated in accordance with equation 7-9.1, in metric tons;

(2) for the production of metallurgical coke, using equation 7-2:

Equation 7-2

Where:

CO2, COKE = Annual CO2 emissions attributable to the production of metallurgical coke, in metric tons;

CC = Annual consumption of coking coal, in metric tons;

CCC = Average annual carbon content of coking coal, in metric tons of carbon per metric ton of coking coal;

GOC = Quantity of coke oven gas transferred offsite during the year, in metric tons;

CGOC = Average annual carbon content of the coke oven gas transferred offsite during the year, in metric tons of carbon per metric ton of coke oven gas;

MC = Annual production of metallurgical coke, in metric tons;

CMC = Average annual carbon content of the metallurgical coke produced, in metric tons of carbon per metric ton of metallurgical coke;

R = Annual quantity of air pollution control residue collected, in metric tons;

CR = Average annual carbon content of air pollution control residue collected or a default value of 0, in metric tons of carbon per metric ton of residue;

COBi = Quantity of coke oven by-product i transferred offsite during the year, in metric tons;

CCOB, i = Average annual carbon content of coke oven by-product i transferred offsite during the year, in metric tons of carbon per metric ton of by-product i;

n = Number of coke oven by-products transferred offsite during the year;

i = Type of by-product;

3.664 = Ratio of molecular weights, CO2 to carbon;

(3) for steel production using a basic oxygen furnace, using equation 7-3:

Equation 7-3

Where:

CO2, BOF = Annual CO2 emissions attributable to steel production using a basic oxygen furnace, in metric tons;

MI = Annual consumption of molten iron, in metric tons;

CMI = Average annual carbon content of molten iron, in metric tons of carbon per metric ton of molten iron;

SC = Annual consumption of ferrous scrap, in metric tons;

CSC = Average annual carbon content of ferrous scrap, in metric tons of carbon per metric ton of ferrous scrap;

n = Number of flux materials;

i = Type of flux material;

FLi = Annual quantity of flux material i used, in metric tons;

CFL, i = Average annual carbon content of flux material i, in metric tons of carbon per metric ton of flux material;

m = Number of carbonaceous materials that contribute 0.5% or more of the total carbon in the process;

j = Type of carbonaceous material;

CARj = Annual consumption of carbonaceous material j that contributes 0.5% or more of the total carbon in the process, in metric tons;

CCAR, j = Average annual carbon content of carbonaceous material j, in metric tons of carbon per metric ton of carbonaceous material;

ST = Annual production of molten steel, in metric tons;

CST = Average annual carbon content of molten steel, in metric tons of carbon per metric ton of molten steel;

SL = Annual production of slag, in metric tons;

CSL = Average annual carbon content of slag or a default value of 0, in metric tons of carbon per metric ton of slag;

BOG = Annual quantity of basic oxygen furnace gas transferred off-site during the year, in metric tons;

CBOG = Average annual carbon content of basic oxygen furnace gas transferred off-site during the year, in metric tons of carbon per metric ton of basic oxygen furnace gas;

R = Annual quantity of air pollution control residue collected, in metric tons;

CR = Average annual carbon content of air pollution control residue collected or a default value of 0, in metric tons of carbon per metric ton of residue;

3.664 = Ratio of molecular weights, CO2 to carbon;

(4) for sinter production, using equation 7-4:

Equation 7-4

Where:

CO2, SINTER = Annual CO2 emissions attributable to sinter production, in metric tons;

CARi = Annual consumption of raw carbonaceous material j that contributes 0.5% or more of the total carbon in the process, in metric tons;

CCAR,i = Average annual carbon content of raw carbonaceous material i, in metric tons of carbon per metric ton of raw carbonaceous material;

n = Number of carbonaceous materials;

i = Type of carbonaceous materials;

m = Number of raw material, other than carbonaceous material;

j = Type of raw material, other than carbonaceous material;

RMj = Annual consumption of raw material j other than carbonaceous materials, required for sinter production, such as natural gas or fuel oil, and that contributes 0.5% or more of the total carbon in the process, in metric tons;

CRMj = Average annual carbon content of raw material j, other than raw carbonaceous materials, required for sinter production, and that contributes 0.5% or more of the total carbon in the process, in metric tons of carbon per metric ton of raw material j;

SINTER = Sinter production, in metric tons;

CSINTER = Average annual carbon content of sinter, in metric tons of carbon per metric ton of sinter;

R = Annual consumption of air pollution control residue, in metric tons;

CR = Average annual carbon content of air pollution control residue collected or a default value of 0, in metric tons of carbon per metric ton of residue;

3.664 = Ratio of molecular weights, CO2 to carbon;

(5) for steel production using an electric arc furnace, using equation 7-5:

Equation 7-5

Where:

CO2, EAF = Annual CO2 emissions attributable to steel production using an electric arc furnace, in metric tons;

I = Annual consumption of direct reduced iron ore pellets, in metric tons;

CI = Average annual carbon content of direct reduced iron ore pellets, in metric tons of carbon per metric ton of direct reduced iron ore pellets;

SC = Annual consumption of ferrous scrap, in metric tons;

CSC = Average annual carbon content of ferrous scrap, in metric tons of carbon per metric ton of ferrous scrap;

m = Number of flux materials;

j = Type of flux material;

FLi = Annual quantity of flux material i used, in metric tons;

CFL, j = Average annual carbon content of flux material j used, in metric tons of carbon per metric ton of flux material;

EL = Annual consumption of carbon electrodes, in metric tons;

CEL = Average annual carbon content of carbon electrodes, in metric tons of carbon per metric ton of carbon electrodes;

n = Total number of carbonaceous materials;

i = Carbonaceous material;

CARi = Annual consumption of carbonaceous material i that contributes 0.5% or more of the total carbon in the process, in metric tons;

CCAR, i = Average annual carbon content of carbonaceous material i, in metric tons of carbon per metric ton of carbonaceous material;

ST = Annual production of molten steel, in metric tons;

CST = Average annual carbon content of molten steel, in metric tons of carbon per metric ton of molten steel;

SL = Annual production of slag, in metric tons;

CSL = Average annual carbon content of slag or a default value of 0, in metric tons of carbon per metric ton of slag;

R = Annual quantity of air pollution control residue collected, in metric tons;

CR = Average annual carbon content of air pollution control residue collected or a default value of 0, in metric tons of carbon per metric ton of residue;

3.664 = Ratio of molecular weights, CO2 to carbon;

(6) for the oxygen decarburization process or the argon vacuum degassing process, using equation 7-6:

Equation 7-6

             _                                   _
            |                                     |
CO2,AOD =    |Steel × (CSteel,in - CSteel,out) - (R × CR)| × 3.664
            |_                                   _|
                        

Where:

CO2,AOD = Annual CO2 emissions attributable to the oxygen decarburization process or the argon vacuum degassing process, in metric tons;

Steel = Quantity of molten steel charted to the oxygen decarburization process or the argon vacuum degassing process, in metric tons;

CSteel,in = Average annual carbon content of molten steel before decarburization or degassing, in metric tons of carbon per metric ton of molten steel;

CSteel,out = Average annual carbon content of molten steel after decarburization or degassing, in metric tons of carbon per metric ton of molten steel;

R = Annual consumption of air pollution control residue, in metric tons;

CR = Average annual carbon content of air pollution control residue collected or a default value of 0, in metric tons of carbon per metric ton of residue;

3.664 = Ratio of molecular weights, CO2 to carbon;

(7) for iron production by direct reduction, using equation 7-7:

Equation 7-7

Where:

CO2, DR = Annual CO2 emissions attributable to iron production by direct reduction, in metric tons;

Ore = Annual consumption of ore or pellets, in metric tons;

COre = Average annual carbon content of ore or pellets, in metric tons of carbon per metric ton of ore or pellets;

n = Number of raw materials, other than carbonaceous materials and ore;

i = Type of raw material, other than carbonaceous materials and ore;

RMi = Annual consumption of raw material i other than carbonaceous materials and ore, such as natural gas or fuel oil and that contributes 0.5% or more of the total carbon in the process, in metric tons;

CRM, i = Average annual carbon content of raw material i other than carbonaceous materials and ore, in metric tons of carbon per metric ton of raw material i;

m = Number of carbonaceous materials;

j = Type of carbonaceous material;

CARj = Annual consumption of each carbonaceous material j that contributes 0.5% or more of total carbon in the process, in metric tons;

CCAR, j = Average annual carbon content of each carbonaceous material j, in metric tons of carbon per metric ton of carbonaceous material j;

I = Annual production of iron produced by direct reduction, in metric tons;

CI = Average annual carbon content of iron produced by direct reduction, in metric tons of carbon per metric ton of iron produced by direct reduction;

NM = Annual production of non-metallic by-products, in metric tons;

CNM = Average annual carbon content of non-metallic by-products, in metric tons of carbon per metric ton of non-metallic by-products;

R = Annual consumption of air pollution control residue, in metric tons;

CR = Average annual carbon content of air pollution control residue collected or a default value of 0, in metric tons of carbon per metric ton of residue;

3.664 = Ratio of molecular weights, CO2 to carbon;

(8) for iron production using a blast furnace, using equation 7-8:

Equation 7-8

Where:

CO2, BF = Annual CO2 emissions attributable to iron production using a blast furnace, in metric tons;

n = Number of raw materials, other than carbonaceous materials and ore;

i = Type of raw material other than carbonaceous materials and ore;

RMi = Annual consumption of raw material i other than carbonaceous materials and ore and that contributes 0.5% or more of the total carbon in the process, in metric tons;

CRM, i = Average annual carbon content of raw material i, other than carbonaceous materials or ore, that contributes 0.5% or more of the total carbon in the process, in metric tons of carbon per metric ton of raw material i;

m = Number of carbonaceous materials;

j = Type of carbonaceous material;

CARj = Annual consumption of each carbonaceous material j that contributes 0.5% or more of total carbon in the process, in metric tons;

CCAR, j = Average annual carbon content of each carbonaceous material j, in metric tons of carbon per metric ton of carbonaceous material j;

p = Number of flux materials;

k = Type of flux material;

Fk = Annual quantity of each flux material k used, in metric tons;

CF,k = Average annual carbon content of each flux material k, in metric tons of carbon per metric ton of flux material k;

Ore = Annual consumption of ore or pellets, in metric tons;

COre = Average annual carbon content of ore or pellets, in metric tons of carbon per metric ton of ore or pellets;

I = Annual production of iron using a blast furnace, in metric tons;

CI = Average annual carbon content of iron produced using a blast furnace, in metric tons of carbon per metric ton of iron produced using a blast furnace;

NM = Annual production of non-metallic by-products, in metric tons;

CNM = Average annual carbon content of non-metallic by-products, in metric tons of carbon per metric ton of non-metallic by-products;

R = Annual consumption of air pollution control residue, in metric tons;

CR = Average annual carbon content of air pollution control residue collected or a default value of 0, in metric tons of carbon per metric ton of residue;

3.664 = Ratio of molecular weights, CO2 to carbon;

(9) for the indurating of iron ore pellets, using equation 7-9 or 7-9.01:

Equation 7-9

         _                                _
        |                                  |
CO2,IP = |(GBP × CGBP) - (FP × CFP) - (R × CR)| × 3.664
        |_                                _|                        

Where:

CO2, IP = Annual CO2 emissions attributable to the indurating of iron ore pellets, in metric tons;

GBP = Annual consumption of greenball pellets, in metric tons;

CGBP = Average annual carbon content of greenball pellets, in metric tons of carbon per metric ton of greenball pellets;

FP = Annual quantity of fired pellets produced by the indurating process, in metric tons;

CFP = Average annual carbon content of fired pellets, in metric tons of carbon per metric ton of fired pellets;

R = Annual consumption of air pollution control residue, in metric tons;

CR = Average annual carbon content of air pollution control residue collected or a default value of 0, in metric tons of carbon per metric ton of residue;

3.664 = Ratio of molecular weights, CO2 to carbon;

Equation 7-9.01

Where:

CO2, IP = Annual CO2 emissions attributable to the indurating of iron ore pellets, in metric tons;

n = Number of additives;

j = Type of additive, such as limestone, dolomite or bentonite;

ADj = Annual consumption of additive j, in metric tons;

CADj = Annual average carbon content of the additive j, in metric tons of carbon per metric ton of additive;

IRC = Annual consumption of iron ore, in metric tons;

CIRC = Annual average carbon content of the iron ore, in metric tons of carbon per metric ton of iron ore;

FP = Annual quantity of fired pellets produced by the indurating process, in metric tons;

CFP = Average annual carbon content of fired pellets, in metric tons of carbon per metric ton of fired pellets;

R = Annual quantity of air pollution control residue, in metric tons;

CR = Average annual carbon content of air pollution control residue collected or a default value of 0, in metric tons of carbon per metric ton of residue;

3.664 = Ratio of molecular weights, CO2 to carbon;

(10) where using a ladle furnace, in accordance with equation 7-9.1:

Equation 7-9.1

Where:

CO2,LF = Annual CO2 emissions attributable to using a ladle furnace, in metric tons;

MSsup = Annual quantity of molten steel supplied to the ladle furnace, in metric tons;

CMSsup = Average annual carbon content of molten steel supplied to the ladle furnace, in metric tons of carbon per metric ton of molten steel;

m = Number of additives;

j = Additive;

ADj = Annual consumption of the additive j that contributes 0.5% or more of the total carbon in the process, in metric tons;

CADj = Annual average carbon content of additive j that contributes 0.5% or more of the total carbon in the process, in metric tons of carbon per metric ton of additive j;

EL = Annual consumption of carbon electrodes, in metric tons;

CEL = Annual Average carbon content of carbon electrodes, in metric tons of carbon per metric ton of carbon electrodes;

MSprod = Annual production of molten steel produced in a ladle furnace, in metric tons;

CMSprod = Average annual carbon content of molten steel, in metric tons of carbon per metric ton of molten steel;

SL = Annual production of slag, in metric tons;

CSL = Average annual carbon content of slag or a default value of 0, in metric tons of carbon per metric ton of slag;

R = Annual quantity of air pollution control residue collected, in metric tons;

CR = Average annual carbon content of air pollution control residue collected or a default value of 0, in metric tons of carbon per metric ton of residue;

Rp = Annual quantity of other residue produced, in metric tons;

CRp = Average annual carbon content of other residue produced or a default value of 0, in metric tons of carbon per metric ton of residue;

3.664 = Ratio of molecular weights, CO2 to carbon;

QC.7.4. Calculation methods for CH4 emissions

An emitter must calculate the annual CH4 emissions attributable to primary processes to produce both iron and steel, secondary steelmaking processes, iron production processes, metallurgical coke production processes and iron ore pellet indurating processes using one of the calculation methods in QC.7.4.1 to QC.7.4.3.

QC.7.4.1. Use of a continuous emission monitoring and recording system

The annual CH4 emissions attributable to primary processes to produce both iron and steel, secondary steelmaking processes, iron production processes, metallurgical coke production processes and ore pellet indurating processes may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.1.4.5.

QC.7.4.2. Calculation using establishment-specific emission factors

The annual CH4 emissions attributable to primary processes to produce both iron and steel, secondary steelmaking processes, iron production processes, metallurgical coke production processes and iron ore pellet indurating processes must be calculated using establishment-specific emission factors determined by the emitter.

QC.7.4.3. Calculation using published emission factors

Annual CH4 emissions attributable to the primary processes to produce iron and steel, secondary steelmaking processes, iron production processes, metallurgical coke production processes and iron ore pellet firing processes can be calculated using the emission factors in Tables 1-1 to 1-8 in Q.C.1.7. If no factor is indicated in the tables, the emitter may use a factor determined by Environment Canada, the U.S. Environmental Protection Agency (USEPA) or the Intergovernmental Panel on Climate Change (IPCC).

QC.7.5. Sampling, analysis and measurement requirements

QC.7.5.1. Carbon content for materials other than ferrous scrap

When the calculation method in QC.7.3.2 is used, an emitter who operates a facility or establishment that produces iron or steel or who operates the indurating of iron ore pellets must, for materials that contribute 0.5% or more of the total carbon in the process, use the data provided by the supplier or determine the carbon content by analyzing a minimum of 3 representative samples per year, using an analysis method published by an organization listed in QC.1.5 or the following methods:

(1) for fossil fuels, in accordance with QC.1.5.5;

(2) for by-products needed in iron and steel production such as blast furnace gas, coke oven gas, coal tar, light oil, slag dust or sinter off gas, by measuring fuel carbon content to ±5% using data from a continuous monitoring and recording system or the methods in QC.1.5.1 and QC.1.5.5;

(3) for flux materials such as limestone or dolomite, using the most recent version of ASTM C25 “Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime”;

(4) for coal, coke and the carbon electrodes used in electric arc furnaces, using the most recent version of ASTM D5373 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal” or, for fuels, raw materials or liquid products, the most recent version of ASTM D7582 “Standard Test Methods for Proximate Analysis of Coal and Coke by Macro Thermogravimetric Analysis”;

(5) for iron and ferrous scrap, using the most recent version of ASTM E1019 “Standard Test Methods for Determination of Carbon, Sulfur, Nitrogen, and Oxygen in Steel, Iron, Nickel, and Cobalt Alloys by Various Combustion and Fusion Techniques”;

(6) for the steel produced, using one of the following methods:

(a) the most recent version of ASM CS-104 UNS G10460 “Carbon Steel of Medium Carbon Content” published by ASM International;

(b) the most recent version of ISO/TR 15349-1 “Unalloyed steel - Determination of low carbon content, Part 1: Infrared absorption method after combustion in an electric resistance furnace (by peak separation)”;

(c) the most recent version of ISO/TR 15349-3 “Unalloyed steel - Determination of low carbon content, Part 3: Infrared absorption method after combustion in an electric resistance furnace (with preheating)”;

(d) the most recent version of ASTM E415 “Standard Test Method for Atomic Emission Vacuum Spectrometric Analysis of Carbon and Low-Alloy Steel”;

(7) for baked or greenball iron ore pellets, using the most recent version of ASTM E1915 “Standard Test Methods for Analysis of Metal Bearing Ores and Related Materials for Carbon, Sulfur, and Acid-Base Characteristics”;

(8) for slag and air pollution control residue collected, in accordance with an analysis method published by an organization listed in QC.1.5 or using a default value of 0.

QC.7.5.2. Carbon content of ferrous scrap

When the calculation method in QC.7.5.2 is used, an emitter who operates a facility or establishment that produces iron or steel must use the data provided by the supplier or determine the carbon content by using the following method:

(1) separate the ferrous scrap into various classes according to carbon content;

(2) for each of the classes, determine the carbon content by analyzing a minimum of 5 representative samples in accordance with the most recent version of ASTM E1019 “Standard Test Methods for Determination of Carbon, Sulfur, Nitrogen, and Oxygen in Steel, Iron, Nickel, and Cobalt Alloys by Various Combustion and Fusion Techniques,” ASTM E415 “Standard Test Method for Atomic Emission Vacuum Spectrometric Analysis of Carbon and Low-Alloy Steel” or in accordance with an analysis method published by an organization listed in QC.1.5;

(3) calculate the characteristic carbon content for each class of ferrous scrap by taking the average of the measured content values, removing the highest and lowest value;

(4) calculate the average carbon content for ferrous scrap using equation 7-9.2:

Equation 7-9.2

Where:

CFS = Average annual carbon content of ferrous scrap, in metric tons of carbon per metric ton of ferrous scrap;

n = Number of classes of ferrous scrap;

i = Class of ferrous scrap;

CCFS,i = Carbon content of class i ferrous scrap, in metric tons of carbon per metric ton of ferrous scrap;

CFSi = Annual consumption of class i ferrous scrap, in metric tons.

QC.7.5.3. Consumption of materials and by-products

The emitter must determine the quantity of solid, liquid and gaseous materials and the quantity of by-products used or coming from all the processes referred to in QC.7.1 using the same equipment used for inventory purposes, such as weigh hoppers or belt weigh feeders.

QC.7.6. Methods for estimating missing data

When, as part of an emitter’s sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.

When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:

(1) an emitter who uses one of the calculation methods provided for in this Protocol must,

(a) when the missing data concern carbon content or sampled data,

i. determine the sampling or measurement rate using the following equation:

Equation 7-10

R = QS Act/QS Required

Where:

R = Actual sampling or measurement rate, expressed as a percentage;

QS Act = Quantity of actual samples or measurements obtained by the emitter;

QS Required = Quantity of samples or measurements required under QC.7.5;

ii. for data that require sampling or analysis,

— if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;

— if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;

— if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;

(b) when the missing data concern the consumption of carbon-containing raw material, consumption of ferrous scrap, annual consumption of molten iron, consumption of coking coal, consumption of flux material, consumption of direct reduced iron pellets, consumption of carbon electrodes, consumption of ore, quantity of slag produced, consumption of greenball pellets, production of fired pellets, production of coke oven gas, production of metallurgical coke, quantity of air pollution control residue collected, quantity of other coke oven by-products, the quantity of steel processed or produced, quantity of gas from basic oxygen furnaces transferred, the production of sinter, the production of iron or the quantity of non-metallic by-products, the replacement data must be estimated on the basis of all the data relating to the processes used;

(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.

QC.8. LIME PRODUCTION

QC.8.1. Covered sources

The covered sources are all the processes used for all types of lime production, except the lime kilns used in a pulp and paper plant and the processes used to process sludge containing calcium carbonate.

QC.8.2. Greenhouse gas reporting requirements

In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:

(1) (subparagraph revoked);

(2) the annual CO2 emissions attributable to the production process for each type of lime, in metric tons;

(3) for each type of lime produced:

(a) the monthly CO2 emission factor, in metric tons of CO2 per metric ton of lime;

(b) the annual production of each type of lime, in metric tons;

(c) (subparagraph revoked);

(d) (subparagraph revoked);

(4) for each type of calcined by-product or waste:

(a) the quarterly emission factors, in metric tons of CO2 per metric ton of calcined by-products or wastes;

(b) the annual production of calcined by-products or wastes, in metric tons;

(c) (subparagraph revoked);

(d) (subparagraph revoked);

(e) the annual quantity of calcined by-products and residue sold, in metric tons;

(5) (subparagraph revoked);

(6) the annual CO2, CH4 and N2O emissions attributable to the use of stationary combustion units, calculated and reported in accordance with QC.1, in metric tons;

(7) the number of times that the methods for estimating missing data in section QC.8.5 were used to determine lime production as required by subparagraph 3 of the first paragraph;

(8) (subparagraph revoked).

Subparagraphs a of subparagraphs 3 and 4 of the first paragraph do not apply to the emissions of an emitter who calculates emissions using data from a continuous emission monitoring and recording system.

For the purposes of subparagraph 8 of the first paragraph of section 6.2:

(1) the emissions referred to in subparagraph 2 of the first paragraph are emissions attributable to fixed processes;

(2) the emissions referred to in subparagraph 6 of the first paragraph are emissions attributable to combustion.

QC.8.3. Calculation methods for CO2, CH4 and N2O emissions

The annual CO2 emissions, other than combustion emissions, attributable to the use of kilns must be calculated in accordance with one of the 2 calculation methods in QC.8.3.1 and QC.8.3.2.

The annual CO2, CH4 and N2O attributable to the combustion of fuels in kilns must be calculated in accordance with QC.8.3.3.

QC.8.3.1. Use of a continuous emission monitoring and recording system

The annual CO2 emissions may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.1.3.4.

QC.8.3.2. Calculation by mass balance

The annual CO2 emissions attributable to the use of kilns must be calculated, for each type of lime, using equations 8-1 to 8-3:

Equation 8-1

Where:

CO2 = CO2 emissions from kilns, in metric tons;

i = Month;

L = Production of lime j for the month i, in metric tons;

EFL = CO2 emission factor of lime j for the month i, calculated in accordance with equation 8-2, in metric tons of CO2 per metric ton of lime;

x = Quarter;

z = Total number of types of calcined by-products and wastes;

y = Type of calcined by-products and waste;

CBF = Production of calcined by-products and wastes y in quarter x, including lime kiln dust, scrubber sludge and other calcined wastes, in metric tons;

EFCBF = CO2 emission factor for calcined by-products and wastes y for quarter x, calculated in accordance with equation 8-3, in metric tons of CO2 per metric ton of calcined by-products and wastes;

Equation 8-2

EFL = (CaOL × 0.785) + (MgOL × 1.092)

Where:

EFL = Monthly CO2 emission factor for lime, in metric tons of CO2 per metric ton of lime;

CaOL = Monthly content of calcium oxide in the lime, in metric tons of calcium oxide per metric ton of lime;

0.785 = Ratio of molecular weights, CO2 to calcium oxide;

MgOL = Monthly content of magnesium oxide in the lime, in metric tons of magnesium oxide per metric ton of lime;

1.092 = Ratio of molecular weights, CO2 to magnesium oxide;

Equation 8-3

EFCBP = (CaOCBP × 0.785) + (MgOCBP × 1.092)

Where:

EFCBP = Quarterly CO2 emission factor for calcined by-products and wastes, in metric tons of CO2 per metric ton of calcined by-products and wastes;

CaOCBP = Quarterly content of calcium oxide in calcined by-products and wastes, in metric tons of calcium oxide per metric ton of calcined by-products and wastes;

0.785 = Ratio of molecular weights, CO2 to calcium oxide;

MgOCBP = Quarterly content of magnesium oxide in calcined by-products and wastes, in metric tons of magnesium oxide per metric ton of calcined by-products and wastes;

1.092 = Ratio of molecular weights, CO2 to magnesium oxide.

QC.8.3.3. Calculation of the emissions attributable to the combustion of fuels in kilns

The CO2, CH4 and N2O emissions attributable to the combustion of fuels in kilns must be calculated and reported in accordance with the calculation methods in QC.1. When pure biomass fuels, in other words fuels constituted of the same substance for at least 97% of their total weight, are consumed only during start-up, shut-down, or malfunction operating periods for the apparatus or units, the emitter may calculate CO2 emissions using the calculation method in QC.1.3.1.

QC.8.4. Sampling, analysis and measurement requirements

An emitter who operates a facility or establishment that produces lime and who uses the method in QC.8.3.2 must:

(1) collect at least one sample each month for each type of lime produced during the month and determine the monthly content of calcium oxide and of magnesium oxide in each type of lime using the most recent version of ASTM C25 “Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime” or the most recent revision of the National Lime Association’s “CO2 Emissions Calculation Protocol for the Lime Industry”, or using any other analysis method published by an organization listed in QC.1.5;

(2) collect at least one sample each quarter for each type of calcined by-products or wastes produced during the quarter and determine the quarterly content of calcium oxide and of magnesium oxide in each type of calcined by-products or wastes in accordance with the standards in subparagraph 1;

(3) complete a monthly estimate of the quantity of lime produced and sold using the data on lime sales for each type of lime; the quantity must be adjusted to take into account the difference in beginning and end-of-period inventories of each type of lime;

(4) complete a quarterly estimate of the quantity of calcined by-products and wastes sold, using the data on sales for each type of calcined by-products or wastes; the quantity must be adjusted to take into account the difference in beginning- and end-of-period inventories, over a maximum period of one year, for each type of calcined by-products and wastes;

(5) determine, at least quarterly, the quantity of calcined by-products and wastes not sold for each type of calcined by-products and wastes, using the sales data or the production rate for calcined by-products and wastes compared to lime production;

(6) follow the quality assurance/quality control procedures in the most recent revision of the National Lime Association’s “CO2 Emissions Calculation Protocol for the Lime Industry” published by la National Lime Association.

QC.8.5. Methods for estimating missing data

When, as part of an emitter’s sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.

When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:

(1) an emitter who uses one of the calculation methods provided for in this Protocol must,

(a) when the missing data concern calcium oxide content or magnesium oxide content,

i. determine the sampling or measurement rate using the following equation:

Equation 8-4

R = QS Act/QS Required

Where:

R = Actual sampling or measurement rate, expressed as a percentage;

QS Act = Quantity of actual samples or measurements obtained by the emitter;

QS Required = Quantity of samples or measurements required under QC.8.4;

ii. for data that require sampling or analysis,

— if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;

— if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;

— if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;

(b) when the missing data concern lime production or the production of calcined by-products and waste, the replacement data must be estimated on the basis of all the data relating to the processes used;

(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.

QC.9. PETROLEUM REFINERIES

QC.9.1. Covered sources

The covered sources are all the processes used to produce gasoline, aromatics, kerosene, distillate fuel oils, residual fuel oils, lubricants, bitumen, or other products through distillation of petroleum or through redistillation, cracking, rearrangement or reforming of unfinished petroleum derivatives.

Facilities that distill only pipeline transmix, in other words off-spec material created when different specification products mix during pipeline transportation, are excluded.

QC.9.2. Greenhouse gas reporting requirements

In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:

(1) the annual CO2, CH4 and N2O emissions attributable to the combustion of refinery fuel gas, flexigas or associated gas, calculated and reported in accordance with QC.2, in metric tons;

(2) the annual CO2 emissions attributable to catalyst regeneration, calculated in accordance with QC.9.3.1, in metric tons;

(2.1) the annual CH4 and N2O emissions attributable to catalyst regeneration, calculated in accordance with QC.9.3.1, in metric tons;

(3) the annual CO2, CH4 and N2O emissions from process vents, calculated in accordance with QC.9.3.2, in metric tons;

(4) the annual CO2 and CH4 emissions attributable to asphalt production, calculated in accordance with QC.9.3.3, in metric tons;

(5) the annual CO2 emissions from sulphur recovery units, calculated in accordance with QC.9.3.4, in metric tons;

(6) the annual CO2, CH4 and N2O emissions attributable to the use of stationary combustion units that are not referred to in paragraphs 1 and 7, calculated and reported in accordance with QC.1, in metric tons;

(6.1) the annual CO2 emissions attributable to hydrogen production processes, calculated and reported in accordance with QC.6, in metric tons;

(7) the annual CO2, CH4 and N2O emissions from flares and antipollution devices, calculated in accordance with QC.9.3.5, in metric tons;

(8) the annual CH4 emissions from storage tanks, calculated in accordance with QC.9.3.6, in metric tons;

(9) the annual CH4 and N2O emissions attributable to wastewater treatment, calculated in accordance with QC.9.3.7, in metric tons;

(10) the annual CH4 emissions from oil-water separators, calculated in accordance with QC.9.3.8, in metric tons;

(11) the annual CH4 emissions from equipment leaks, calculated in accordance with QC.9.3.9, in metric tons;

(12) the annual consumption of each type of feedstock that emits CO2, CH4 or N2O, including petroleum coke, expressed

(a) in bone dry metric tons, when the quantity is expressed as a mass;

(b) in thousands of cubic metres at standard conditions, when the quantity is expressed as a volume of gas;

(c) in kilolitres, when the quantity is expressed as a volume of liquid;

(d) (subparagraph replaced);

(13) the annual consumption of each type of fuel that emits CO2, CH4 or N2O, expressed

(a) in bone dry metric tons, when the quantity is expressed as a mass;

(b) in thousands of cubic metres at standard conditions, when the quantity is expressed as a volume of gas;

(c) in kilolitres, when the quantity is expressed as a volume of liquid;

(d) (subparagraph replaced);

(14) the annual CO2 emissions from coke calcining, calculated in accordance with QC.9.3.10, in metric tons;

(14.1) the annual CH4 and N2O emissions from coke calcining, calculated in accordance with QC.9.3.10, in metric tons;

(15) the annual CH4 emissions from purging systems, calculated in accordance with QC.9.3.11, in metric tons;

(16) the annual CH4 emissions from loading operations, calculated in accordance with QC.9.3.12, in metric tons;

(17) the annual CH4 emissions from delayed coking, calculated in accordance with QC.9.3.13, in metric tons;

(18) the number of times that the methods for estimating missing data provided for in QC.9.5 were used;

(19) (subparagraph revoked);

(20) the annual quantity of crude oil refined, in kilolitres;

(21) the annual total charge of the refinery feed, in kilolitres.

For the purposes of subparagraph 8 of the first paragraph of section 6.2:

(1) the emissions referred to in subparagraphs 2, 5, 6.1 and 14 of the first paragraph are emissions attributable to fixed processes;

(2) the emissions referred to in subparagraphs 1 and 6 of the first paragraph are emissions attributable to combustion;

(3) the emissions referred to in subparagraphs 2.1, 3, 4, 7 to 11, 14.1 and 15 to 17 of the first paragraph are other emissions.

QC.9.3. Calculation methods for CO2, CH4 and N2O emissions

The annual CO2, CH4 and N2O emissions attributable to the operation of a petroleum refinery must be calculated in accordance with the calculation methods in QC.9.3.1 to QC.9.3.13.

QC.9.3.1. Calculation of CO2, CH4 and N2O emissions attributable to catalyst regeneration

The annual CO2, CH4 and N2O emissions attributable to catalyst regeneration for a facility equipped with a continuous emission monitoring and recording system must be calculated in accordance with QC.1.3.4 or, in the absence of such a system, in accordance with the following methods, depending on the process involved:

(1) for the continuous regeneration of catalyst material in fluid catalytic cracking units and fluid cokers:

(a) using the average coke consumption and equations 9-1, 9-2 and 9-3:

Equation 9-1

Where:

CO2 = Annual CO2 emissions attributable to the continuous regeneration of catalyst material in fluid catalytic cracking units and fluid cokers, in metric tons;

n = Number of hours of operation during the year;

j = Hour;

CBj = Hourly coke burn for hour j, calculated in accordance with equation 9-2 or determined by the emitter, in metric tons;

CC = Carbon content of coke burned, in kilograms of carbon per kilogram of coke burned;

3.664 = Ratio of molecular weights, CO2 to carbon;

Equation 9-2

Where:

CBj = Hourly coke burn, in metric tons;

K1, K2, K3 = Material balance and conversion factors (K1, K2 and K3) from Table 9-1 in QC.9.6;

Qr = Volumetric flow of regeneration gas before entering the antipollution system, calculated in accordance with equation 9-3 or measured continuously, in cubic metres per minute, at standard conditions and on a dry basis;

%CO2 = CO2 concentration in regenerator exhaust, in cubic metres of CO2 per cubic metre of regeneration gas on a dry basis, expressed as a percentage;

%CO = Concentration of carbon monoxide in regenerator exhaust, in cubic metres of carbon monoxide per cubic metre of regeneration gas on a dry basis, expressed as a percentage;

Qa = Volumetric flow of air to regenerator, in cubic metres per minute, at standard conditions and on a dry basis;

%O2 = Concentration of oxygen in regenerator exhaust, in cubic metres of oxygen per cubic metre of regeneration gas on a dry basis, expressed as a percentage;

Qoxy = Volumetric flow of oxygen to regenerator, in cubic metres per minute, at standard conditions and on a dry basis;

%O2,oxy = Concentration of oxygen in enriched air stream inlet to regenerator, expressed as a percentage per volume on a dry basis;

0.001 = Conversion factor, kilograms to metric tons;

Equation 9-3

     [79 × Qa + (100-%O2,oxy)× Qoxy]
Qr = ______________________________

       [100 - %CO2 - %CO - %O2]                        

Where:

Qr = Volumetric flow of regeneration gas from regenerator before entering the antipollution system, in cubic metres per minute, at standard conditions and on a dry basis;

79 = Nitrogen concentration in air, expressed as a percentage;

Qa = Volumetric flow of air to regenerator, in cubic metres per minute, at standard conditions and on a dry basis;

%O2,oxy = Concentration of oxygen in enriched air stream inlet, in cubic metres of oxygen per cubic metre of air stream on a dry basis, expressed as a percentage;

Qoxy = Volumetric flow of oxygen in enriched air stream inlet, in cubic metres per minute, at standard conditions and on a dry basis;

%CO2 = CO2 concentration in regenerator exhaust, in cubic metres of CO2 per cubic metre of regeneration gas on a dry basis, expressed as a percentage;

%CO = Concentration of carbon monoxide in regenerator exhaust, in cubic metres of carbon monoxide per cubic metre of regeneration gas on a dry basis, expressed as a percentage.

When no auxiliary fuel is burned and the emitter does not use a continuous CO monitoring and recording system, the percentage is zero;

%O2 = Concentration of oxygen in regenerator exhaust, in cubic metres of oxygen per cubic metre of regeneration gas on a dry basis, expressed as a percentage;

(b) using the CO2 and carbon monoxide concentrations in the regenerator exhaust and equation 9-3.1:

Equation 9-3.1

Where:

CO2 = Annual CO2 emissions attributable to the continuous regeneration of catalyst material in fluid catalytic cracking units and fluid cokers, in metric tons;

n = Number of hours of operation during the year;

j = Hour;

Qr = Volumetric flow of regeneration gas from regenerator before entering the antipollution system, in cubic metres per minute, at standard conditions and on a dry basis;

%CO2 = CO2 concentration in regenerator exhaust, in cubic metres of CO2 per cubic metre of regeneration gas on a dry basis, expressed as a percentage;

%CO = Concentration of carbon monoxide in regenerator exhaust, in cubic metres of carbon monoxide per cubic metre of regeneration gas on a dry basis, expressed as a percentage or, if there is no post-combustion device, a percentage of 0;

60 = Conversion factor, minutes to hours;

44 = Molecular weight of CO2, in kilograms per kilomole;

MVC = Molar volume conversion factor (24.06 m3 per kilomole at standard conditions);

0.001 = Conversion factor, kilograms to metric tons;

(2) for periodic catalyst regeneration processes, using equation 9-4:

Equation 9-4

Where:

CO2 = Annual CO2 emissions attributable to periodic catalyst regeneration processes, in metric tons;

n = Number of regeneration cycles during the year;

i = Regeneration cycle;

CBi = Quantity of coke burned, in metric tons per regeneration cycle i;

C = Carbon content of coke burned, measured or estimated by the emitter, or using a default value of 0.94 kg of carbon per kilogram of coke burned;

3.664 = Ratio of molecular weights, CO2 to carbon;

(3) for continuous catalyst regeneration processes of catalysers used for operations other than fluid catalytic cracking and fluid coking, using equation 9-5:

Equation 9-5

CO2 = CRR × (CFspent - CFregen) × H × 3.664

Where:

CO2 = Annual CO2 emissions attributable to continuous catalyst regeneration processes of catalysers used for operations other than fluid catalytic cracking and fluid coking, in metric tons;

CRR = Average catalyst regeneration rate, in metric tons per hour;

CFspent = Carbon content of spent catalyst, in kilograms of carbon per kilogram of spent catalyst;

CFregen = Carbon content of the regenerated catalyst, in kilograms of carbon per kilogram of regenerated catalyst.

If no carbon content in the regenerated catalyst is detected, the carbon content of the catalyst is zero;

H = Number of hours of operation of regenerator during the year;

3.664 = Ratio of molecular weights, CO2 to carbon;

(4) the CH4 emissions attributable to catalyst regeneration must be calculated using equation 9-5.1:

Equation 9-5.1

                 EFCH4     
     CH4 = CO2 × _____
                 EFCO2                        

Where:

CH4 = Annual CH4 emissions from catalyst regeneration, in metric tons;

CO2 = Annual CO2 emissions from catalyst regeneration, calculated using equations 9-1, 9-3.1 or 9-4, in metric tons;

EFCH4 = CH4 emission factor, 2.8 × 10-3 kg per gigajoule;

EFCO2 = CO2 emission factor, namely 97 kg per gigajoule;

(5) the N2O emissions attributable to catalyst regeneration must be calculated using equation 9-5.2:

Equation 9-5.2

                 EFN2O     
     N2O = CO2 × _____
                 EFCO2                        

Where:

N2O = Annual N2O emissions from catalyst regeneration, in metric tons;

CO2 = Annual CO2 emissions from catalyst regeneration, calculated using equation 9-1, in metric tons;

EFN2O = N2O emission factor, 5.7 × 10-4 kg per gigajoule;

EFCO2 = CO2 emission factor, 97 kg per gigajoule;

QC.9.3.2. Calculation of CO2, CH4 and N2O emissions from process vents

The annual CO2, CH4 and N2O emissions from process vents, other than emissions required for the process, must be calculated using equation 9-6, for each process vent with a CO2 flow of over 2% by volume, a CH4 flow of over 0.5% by volume, or an N2O flow of over 0.01% by volume:

Equation 9-6

Where:

Ex = Annual emissions of gas x from process vents, in metric tons;

x = CO2, CH4 or N2O;

m = Total number of vents;

j = Vent;

n = Number of venting events during the year;

i = Venting event;

VRi = Vent rate j for venting event i, in cubic metres per unit of time at standard conditions;

Fxi = Molar fraction of x in vent gas stream during venting event i, in kilomoles of x per kilomole of gas;

MWxi = Molecular weight of x in kilograms per kilomole or, when a mass flowmeter is used to measure the flow in kilograms per unit of time, replace

 _  _
|    |
|MWx |
|----| by 1;
|MVC |
|_  _|                        

MVC = Molar volume conversion factor (24.06 m3 per kilomole at standard conditions);

VTi = Duration of venting event i of vent j, using the same units of time as for VRi;

0.001 = Conversion factor, kilograms to metric tons.

QC.9.3.3. Calculation of CO2 and CH4 emissions attributable to bituminous product blowing processes

The annual CO2 and CH4 emissions attributable to bituminous product blowing processes must be calculated using the method in QC.9.3.2, or in accordance with the following methods:

(1) for bituminous product blowing operations without antipollution equipments, or bituminous product blowing activities controlled by a steam gas purification system, using the following equations:

Equation 9-7

CO2 = QBP × EFBP,CO2

Where:

CO2 = Annual CO2 emissions attributable to uncontrolled bituminous product blowing operations, in metric tons;

QBP = Quantity of bituminous product blown, in millions of barrels;

EFBP,CO2 = CO2 emission factor for uncontrolled bituminous product blowing operations determined by the emitter, or a default value of 1,100 metric tons per million barrels;

Equation 9-8

CH4 = QBP × EFBP,CH4

Where:

CH4 = CH4 emissions attributable to uncontrolled bituminous product blowing operations, in metric tons;

QBP = Annual quantity of bituminous product blown, in millions of barrels;

EFBP,CH4 = CH4 emission factor for uncontrolled bituminous product blowing operations determined by the emitter, or a default value of 580 metric tons per million barrels;

(2) for bituminous product blowing operations controlled by thermal oxidizer or flare, using equations 9-8.1 and 9-8.2, except if the emissions have already been calculated in accordance with QC.9.3.5 or QC.1.3:

Equation 9-8.1

CO2 = QBP × CBP × 0.98 × 3.664

Where:

CO2 = Annual CO2 emissions attributable to controlled bituminous product blowing operations, in metric tons;

QBP = Annual quantity of bituminous products blown, in millions of barrels;

CBP = Carbon content of bituminous product blown determined by the emitter, or a default value of 2,750 metric tons per million barrels;

0.98 = Efficiency of thermal oxidizer or flare;

3.664 = Ratio of molecular weights, CO2 to carbon;

Equation 9-8.2

CH4 = QBP × EFBP,CH4 × 0.02

Where:

CH4 = Annual CH4 emissions attributable to controlled bituminous product blowing operations, in metric tons;

QBP = Annual quantity of bituminous product blown, in millions of barrels;

EFBP,CH4 = CH4 emission factor for bituminous product blowing operations without antipollution equipments determined by the emitter, or a default value of 580 metric tons per million barrels;

0.02 = Fraction of CH4 uncombusted in thermal oxidizer or flare, in percentage expressed in decimal form.

QC.9.3.4. Calculation of CO2 emissions from sulphur recovery units

The annual CO2 emissions from sulphur recovery units must be calculated using equation 9-9:

Equation 9-9

                MW
     CO2 = FR ×   CO2 × MF × 0.001
                MVC                        

Where:

CO2 = Annual CO2 emissions from sulphur recovery units, in metric tons;

FR = Annual volumetric flow of acid gas emitted to the sulphur recovery units, in cubic metres at standard conditions;

MWCO2 = Molecular weight of CO2 of 44 kg per kilomole or, when a mass flowmeter is used to measure gas flow in kilograms per year, replace

 _      _
|        |
|  MWCO2  |
|--------| by 1;
|  MVC   |
|_      _|                        

MVC = Molar volume conversion factor (24.06 m3 per kilomole at standard conditions);

MF = Molecular fraction of CO2 in the acid gas emitted to sulphur recovery units, obtained by sampling at source and analyzing annually, in a percentage expressed as a decimal, or as a factor of 20% or 0.20;

0.001 = Conversion factor, kilograms to metric tons.

QC.9.3.5. Calculation of CO2, CH4 and N2O emissions attributable to combustion of hydrocarbons in flares and other antipollution equipments

The annual CO2, CH4 and N2O emissions attributable to combustion of hydrocarbons in flares and other antipollution equipments must be calculated in accordance with the calculation methods in QC.1, except the CO2 emissions attributable to the combustion of hydrocarbons in flares that must be calculated, based on the type of equipment used, using the following methods:

(1) for a flare equipped with a continuous monitoring and recording system to measure the flow and the parameters used to determine the carbon content of the gas, or if the parameters are measured at least weekly, using equation 9-10:

Equation 9-10

Where:

CO2 = Annual CO2 emissions attributable to the combustion of hydrocarbons in flares, in metric tons;

n = Number of measurement periods; minimum of 52 for weekly measurements and maximum of 366 for daily measurements;

p = Measurement period;

Flarep = Volume of gas directed to flares during measurement period p, in thousands of cubic metres at standard conditions;

MWp = Average molecular weight of flare gas combusted during measurement period p, in kilograms per kilomole or, when a mass flowmeter is used to measure flare gas flow in kilograms per measurement period, replace

 _      _
|        |
|  MWp   |
|--------| by 1.
|  MVC   |
|_      _|                        

If measurements are taken more frequently than daily, the arithmetic average of measurement values must be used;

MVC = Molar volume conversion factor (24.06 m3 per kilomole at standard conditions);

CCp = Average carbon content of flare gas combusted during measurement period p, in kilograms of carbon per kilogram of flare gas.

If measurements are taken more frequently than daily, the arithmetic average of measurement values must be used;

3.664 = Ratio of molecular weights, CO2 to carbon;

0.98 = Flare combustion efficiency;

1 = Conversion factor, kilograms to metric tons and thousands of cubic metres to cubic metres;

(2) for a flare equipped with a continuous monitoring and recording system to measure the flow and the parameters used to determine the high heat value of the gas, or if the parameters are measured at least weekly, using equation 9-11:

Equation 9-11

Where:

CO2 = Annual CO2 emissions attributable to the combustion of hydrocarbons in flares, in metric tons;

n = Number of measurement periods; minimum of 52 for weekly measurements and maximum of 366 for daily measurements;

p = Measurement period;

Flarep = Volume of gas directed to flares during measurement period p, in thousands of cubic metres at standard conditions;

If a mass flowmeter is used, the molecular weight must be measured and the molecular weight and mass flow must be converted to a volumetric flow using equation 9-12;

HHVp = High heat value of the gas combusted during the measurement period, in gigajoules per thousand cubic metres;

EF = Default CO2 emission factor of 57 kg per gigajoule;

0.98 = Combustion efficiency of flare;

0.001 = Conversion factor, kilograms to metric tons;

Equation 9-12

                      MVC
Flarep = Flarep (kg) × ___ × 0.001
                      MWP                        

Where:

Flarep = Volume of gas directed to flares during measurement period p, in thousands of cubic metres;

Flarep (kg) = Mass of flare gas combusted during measurement period p, in kilograms;

MVC = Molar volume conversion factor (24.06 m3 per kilomole at standard conditions);

MWp = Average molecular weight of flare gas combusted during measurement period p, in kilograms per kilomole;

0.001 = Conversion factor, cubic metres to thousands of cubic metres;

(3) when it is not possible to measure the parameters required in equations 9-10 and 9-11 during startup, shutdown or equipment malfunction, the quantity of gas discharged to the flare must be calculated for each startup, shutdown or malfunction and the CO2 emissions must be calculated using equation 9-13:

Equation 9-13

Where:

CO2 = Annual CO2 emissions attributable to the combustion of hydrocarbons in flare during startup, shutdown or malfunctions, in metric tons;

n = Annual number of startups, shutdowns or malfunctions;

p = Startup, shutdown or malfunction period;

(FlareSSM)p = Volume of gas directed to flare during startup, shutdown or malfunction period p, in thousands of cubic metres at standard conditions;

MWp = Average molecular weight of flare gas combusted during measurement period p, in kilograms per kilomole;

MVC = Molar volume conversion factor (24.06 m3 per kilomole at standard conditions);

CCp = Average carbon content of flare gas combusted during measurement period p, in kilograms of carbon per kilogram of flare gas;

3.664 = Ratio of molecular weights, CO2 to carbon;

0.98 = Flare combustion efficiency;

1 = Conversion factor, kilograms to metric tons and thousands of cubic metres to cubic metres;

(4) the CH4 emissions attributable to the combustion of hydrocarbons in flares must be calculated using equation 9-14:

Equation 9-14

Where:

CH4 = Annual CH4 emissions attributable to the combustion of hydrocarbons in flares, in metric tons;

CO2 = Annual CO2 emissions attributable to the combustion of hydrocarbons in flares, calculated using equations 9-10 to 9-12 or in accordance with QC.1, in metric tons;

EFCH4 = CH4 emission factor of 2.8 × 10-3 kG per gigajoule;

EFCO2 = CO2 emission factor of 57 kG per gigajoule;

0.02/0.98 = Correction factor for flare combustion efficiency;

16/44 = Correction factor for the molecular weight ratio of CH4 to CO2;

fCH4 = Fraction of carbon in CH4 in flare gas prior to combustion, in kilograms of carbon in CH4 in flare gas per kilograms of carbon in flare gas, or default value of 0.4;

(5) the N2O emissions attributable to the combustion of hydrocarbons in flares must be calculated using equation 9-15:

Equation 9-15

            EFN2O
N20 = CO2 × _____
            EFCO2                         

Where:

N2O = Annual N2O emissions attributable to the combustion of hydrocarbons in flares, in metric tons;

CO2 = Annual CO2 emissions attributable to the combustion of hydrocarbons in flares, calculated using equations 9-10 to 9-12 or in accordance with QC.1, in metric tons;

EFN2O = N2O emission factor of 5.7 × 10-4 kg per gigajoule;

EFCO2 = CO2 emission factor of 57 kg per gigajoule;

(6) when equipment or methods other than flares are used to destroy low Btu gases such as coker flue gas, gases from vapour recovery systems, casing vents and product storage tanks, the CO2 emissions must be calculated using equation 9-16:

Equation 9-16

Where:

CO2 = Annual CO2 emissions attributable to the combustion of low Btu gases, in metric tons;

n = Total number of low Btu gases;

p = Low Btu gas;

GVp = Annual volume of gas p, in thousands of cubic metres at standard conditions or in kilograms for a mass balance;

CCp = Carbon content of gas p, in kilograms of carbon per kilogram of gas;

MWp = Molecular weight of gas p in kilograms per kilomole or, when a mass flowmeter is used to measure the flow of gas p in kilograms, replace

 _  _
|    |
| MWp|
|----| by 1;
|MVC |
|_  _|                        

MVC = Molar volume conversion factor (24.06 m3 per kilomole at standard conditions);

3.664 = Ratio of molecular weights, CO2 to carbon;

1 = Conversion factor, kilograms to metric tons and thousands of cubic metres to cubic metres.

QC.9.3.6. Calculation of CH4 emissions from storage tanks

The CH4 emissions of the following storage tanks do not have to be calculated: units permanently attached to conveyances such as trucks, trailers, rail cars, barges, or ships; pressure vessels designed to operate in excess of 204.9 kPa and without emissions to the atmosphere; bottoms receivers or sumps; vessels storing wastewater; and reactor vessels associated with a manufacturing process unit.

The annual CH4 emissions from all other storage tanks must be calculated using the following methods:

(1) for storage tanks other than those used for unstabilized crude oil that have a vapour-phase CH4 concentration of 0.5% volume percent or more by volume, the CH4 emissions must be calculated using the following methods:

(a) when the CH4 composition is known, according to the procedures provided for in section 7.1 of the AP-42: “Compilation of Air Pollutant Emission Factors, Volume 1: Stationary Point and Areas Sources”, including TANKS Model (version 4.09(D), published by the U.S. Environmental Protection Agency (USEPA);

(b) using equation 9-17:

Equation 9-17

CH4 = Qpb × 6.29 × 10-7

Where:

CH4 = Annual CH4 emissions from storage tanks, in metric tons;

Qpb = Annual quantity of crude oil and intermediate products received from off-site that are processed at the establishment, in kilolitres;

6.29 × 10-7 = Default emission factor for storage tanks, in metric tons of CH4 per kilolitre;

(2) for storage tanks for unstabilized crude oil, the CH4 emissions must be calculated using the following methods:

(a) when the CH4 concentration is known, by measuring directly the vapour generated;

(b) using equation 9-18:

Equation 9-18

Where:

CH4 = Annual CH4 emissions from storage tanks, in metric tons;

2.57 × 10-5 = Equation correlation factor, in thousands of cubic metres at standard conditions, per kilolitre per kilopascal;

Qun = Annual quantity of unstabilized crude oil, in kilolitres;

/\P = Pressure differential from storage pressure to atmospheric pressure, in kilopascals;

MFCH4 = Mole fraction of CH4 in vent gas from the unstabilized crude oil storage tank, measured by the emitter, in kilomoles of CH4 per kilomole of gas, or a value of 0.27;

16 = Molecular weight of CH4, in kilograms per kilomole;

MVC = Molar volume conversion factor (24.06 m2 per kilomole at standard conditions);

1 = Conversion factor, kilograms to metric tons and thousands of cubic metres to cubic metres.

QC.9.3.7. Calculation of CH4 and N2O emissions attributable to anaerobic wastewater treatment

The annual emissions attributable to anaerobic wastewater treatment must be calculated:

(1) for CH4 emissions, using equation 9-19 or equation 9-20:

Equation 9-19

CH4 = Q × CODqave × B × MCF × 0.001

Where:

CH4 = Annual CH4 emissions attributable to wastewater treatment, in metric tons;

Q = Quantity of wastewater treated annually, in cubic metres;

CODqave = Quarterly average chemical oxygen demand of the wastewater, in kilograms per cubic metre;

B = CH4 generation capacity of 0.25 kg of CH4 per kilogram of chemical oxygen demand;

MCF = Conversion factor for CH4 specified in Table 9-3 of QC.9.6, depending on the process;

0.001 = Conversion factor, kilograms to metric tons;

Equation 9-20

CH4 = Q × BOD5qave × B × MCF × 0.001

Where:

CH4 = Annual CH4 emissions attributable to wastewater treatment, in metric tons;

Q = Quantity of wastewater treated annually, in cubic metres;

BOD5qave = Average quarterly five-day biochemical oxygen demand of the wastewater, in kilograms per cubic metre;

B = CH4 generation capacity of 0.25 kg of CH4 per kilogram of chemical oxygen demand;

MCF = Conversion factor for CH4 specified in Table 9-3 of QC.9.6, depending on the process;

0.001 = Conversion factor, kilograms to metric tons;

(2) for anaerobic processes from which biogas is recovered and not emitted, the CH4 emissions must be calculated by subtracting the quantity recovered;

(3) for N2O emissions, using equation 9-21:

Equation 9-21

N2O = Q × Nqave × EFN2O × 1.571 × 0.001

Where:

N2O = Annual N2O emissions attributable to wastewater treatment, in metric tons;

Q = Quantity of wastewater treated annually, in cubic metres;

Nqave = Quarterly average nitrogen content in effluent, in kilograms per cubic metre;

EFN2O = N2O emission factor from discharged wastewater of 0.005 kg of nitrogen produced by the decomposition of nitrous oxide (N2O-N) per kilogram of total nitrogen;

1.571 = Conversion factor, kilograms of N2O-N to kilograms of N2O;

0.001 = Conversion factor, kilograms to metric tons.

QC.9.3.8. Calculation of CH4 emissions from oil-water separators

The annual CH4 emissions from oil-water separators must be calculated using equation 9-22:

Equation 9-22

CH4 = EFNMHC × Qwater × CFNMHC ×0.001

Where:

CH4 = Annual CH4 emissions from oil-water separators, in metric tons;

EFNMHC = Emission factor for hydrocarbons other than CH4 as specified in Table 9-4 in QC.9.6, in kilograms per cubic metre;

Qwater = Quantity of wastewater treated annually by the separator, in cubic metres;

CFNMHC = Conversion factor, non-methane hydrocarbons to CH4, obtained by sampling and analysis at each separator or, in the absence of such data, a factor of 0.6;

0.001 = Conversion factor, kilograms to metric tons.

QC.9.3.9. Calculation of fugitive emissions of CH4 from system components

Annual fugitive emissions of CH4 must be calculated using one of the two following methods:

(1) using process-specific CH4 composition data for each process and one of the emission estimation procedures provided for in the EPA-453/R-095-017, NTIS PB96-175401 “Protocol for Equipment Leak Emission Estimates” published by the U.S. Environmental Protection Agency (USEPA);

(2) using equation 9-23:

Equation 9-23

CH4 = (0.4 × Nc) + (0.2 × NPU,1) + (0.1 × NPU,2) + (4.3 × NH2) + (6 × Nrgc)

Where:

CH4 = Annual CH4 emissions attributable to fugitive emissions from system components, in metric tons;

Nc = Number of crude oil distillation columns;

NPU,1 = Cumulative number of catalytic cracking units, coking units (delayed or fluid), hydrocracking, and full-range distillation columns (including depropanizer and debutanizer distillation columns);

NPU,2 = Cumulative number of hydrotreating/hydrorefining units, catalytic reforming units, and visbreaking units;

NH2 = Total number of hydrogen production units;

Nrgc = Total number of fuel gas systems.

QC.9.3.10. Coke calcining

The annual CO2, CH4 and N2O emissions attributable to coke calcining must be calculated using the following methods:

(1) the CO2 emissions attributable to coke calcining must be calculated in accordance with QC.1.3.4 when the facility is equipped with a continuous emission monitoring and recording system or, in the absence of such a system, using equation 9-24:

Equation 9-24

CO2 = [Min × CGC - (Mout + MCBR) × CMPC] × 3.664

Where:

CO2 = Annual CO2 emissions attributable to coke calcining, in metric tons;

Min = Annual mass of green coke entering the coke calcining process, in metric tons;

CGC = Average mass fraction carbon content of the green coke, in metric tons of carbon per metric ton of green coke;

Mout = Annual mass of marketable coke, in metric tons of petroleum coke;

MCBR = Annual mass of petroleum coke breeze collected in the dust collection system of the coke calcining unit, in metric tons of dust per metric ton of calcined coke;

CMPC = Average mass fraction carbon content of marketable petroleum coke, in metric tons of carbon per metric ton of petroleum coke;

3.664 = Ratio of molecular weights, CO2 to carbon;

(2) the annual CH4 emissions attributable to coke calcining must be calculated using equation 9-25:

Equation 9-25

            EFCH4
CH4 = CO2 × _____
            EFCO2                          

Where:

CH4 = Annual CH4 emissions attributable to coke calcining, in metric tons;

CO2 = Annual CO2 emissions from coke calcining, calculated using equation 9-1, in metric tons;

EFCH4 = CH4 emission factor determined by the emitter or a default value of 2.8 × 10-3 kg per gigajoule;

EFCO2 = CO2 emission factor of 97 kg per gigajoule;

(3) the annual N2O emissions attributable to coke calcining must be calculated using equation 9-26:

Equation 9-26

            EFN2O
N20 = CO2 × _____
            EFCO2                          

Where:

N2O = Annual N2O emissions attributable to coke calcining, in metric tons;

CO2 = Annual CO2 emissions attributable to coke calcining, calculated using equation 9-1, in metric tons;

EFN2O = N2O emission factor of 5.7 × 10-4 kg per gigajoule;

EFCO2 = CO2 emission factor of 97 kg per gigajoule.

QC.9.3.11. Uncontrolled blowdown systems

The annual CO2, CH4 and N2O emissions from uncontrolled blowdown systems must be calculated using the calculation methods in QC.9.3.2.

QC.9.3.12. Loading operations

The CH4 emissions attributable to crude oil, intermediate, or product loading operations must be calculated using equilibrium vapourphase CH4 composition data and the procedures in Section 5.2 of the AP-42: “Compilation of Air Pollutant Emission Factors, Volume 1: Stationary Point and Area Sources” published by the U.S. Environmental Protection Agency (USEPA). When the equilibrium vapour-phase concentration of CH4 is less than 0.5%, zero CH4 emissions may be assumed.

QC.9.3.13. Delayed coking processes

The CH4 emissions attributable to the depressurization of the vessels in each coking unit to the atmosphere must be calculated using one of the calculation methods in paragraphs 1 and 2, except in the case of an emitter who adds water or steam to the vessel once it is vented to the atmosphere, who must use the method in paragraph 1:

(1) the CH4 emissions attributable to the depressurization of the vessels in each coking unit to the atmosphere must be calculated using equation 9-6 and the CH4 emissions attributable to the subsequent opening of the vessel for coke cutting operations must be calculated, for each vessel with the same dimensions, using equation 9-27:

Equation 9-27

(2) the annual CH4 emissions from the depressurization vents and the subsequent opening of the vessels in each coking unit for coke cutting operations must be calculated using equation 9-27 and the manometric pressure of the coking vessel when the depressurization gases are first routed to the atmosphere.

QC.9.4. Sampling, analysis and measurement requirements

QC.9.4.1. Catalyst regeneration

For catalyst regeneration, the emitter must:

(1) for fluid catalytic cracking units and fluid cokers:

(a) measure the daily concentration of oxygen in the oxygen-enriched air stream inlet to the regenerator;

(b) measure the volumetric flow of air and oxygen-enriched air to the regenerator, on a continuous basis;

(c) measure the CO2, carbon monoxide and oxygen concentrations in the exhaust gas from the regenerator, on a continuous basis or weekly;

(d) when equation 9-1 is used, measure the daily carbon content of the coke combusted;

(e) measure the number of hours of operation;

(2) for periodic catalyst regeneration:

(a) measure the quantity of catalyst regenerated in each regeneration cycle;

(b) measure the carbon content of the catalyst prior to and after regeneration;

(3) for continuous catalyst regeneration in operations other than fluid catalytic cracking and fluid coking:

(a) measure the hourly catalyst regeneration rate;

(b) measure the carbon content of the catalyst, prior to and after regeneration;

(c) measure the number of hours of operation.

The values measured daily or weekly can be used to determine the minute or hourly data required for the corresponding equations.

QC.9.4.2. Process vents

For process vents, the emitter must, for each process venting event, measure the following parameters:

(1) the flow rate for each venting event;

(2) the molar fraction of CO2, CH4 and N2O in the vent gas stream during each venting event;

(3) the duration of each venting event.

QC.9.4.3. Asphalt production

For asphalt production, the emitter must measure the quantity of asphalt blown.

QC.9.4.4. Sulphur recovery

For sulphur recovery, the emitter must measure the volumetric flow rate of acid gas to the sulphur recovery units.

If using a source specific molecular faction value instead of the default factor, the emitter must conduct an annual test of the CO2 content in the acid gas emitted to sulphur recovery units.

QC.9.4.5. Flares and other antipollution equipments

For flares and other antipollution equipments, an emitter must:

(1) if using a continuous emission monitoring and recording system on the flare, use the measured flow rate when it is within the calibrated range of the measurement device, or, determine the flow rate according to a sector-recognized method when it is not measured by the system;

(2) if using equation 9-10 or 9-13, measure the parameters used to determine the carbon content of the flare gas daily;

(3) if using equation 9-11, measure the parameters used to determine the high heat value of the flare gas daily.

When the continuous monitoring and recording system does not provide the parameters used to determine the carbon content of the gas, the emitter must measure those parameters at least weekly.

QC.9.4.6. Storage tanks

For storage tanks, the emitter must determine the annual throughput of all types of products for each storage tank using one of the following methods:

(1) by measuring them directly using measurement devices;

(2) by using any other measured or collected data.

QC.9.4.7. Wastewater treatment

For wastewater treatment, the emitter must

(1) collect weekly samples to analyse the chemical oxygen demand and 5-day biochemical oxygen demand (DBO5) of the wastewater from the anaerobic treatment process following preliminary treatment;

(2) measure weekly the flow rate of wastewater entering the anaerobic wastewater treatment process, at the flow measurement location used to collect samples under paragraph 1 to analyse the chemical oxygen demand and 5-day biochemical oxygen demand (DBO5);

(3) determine quarterly the nitrogen content of the wastewater.

QC.9.4.8. Oil-water separators

For oil-water separators, the emitter must measure the daily volume of wastewater treated by the oil-water separators.

QC.9.4.9. Coke calcining

For coke calcining, the emitter must measure the mass and carbon content of the petroleum coke using one of the following methods:

(1) the most recent version of ASTM D3176 “Standard Practice for Ultimate Analysis of Coal and Coke”;

(2) the most recent version of ASTM D5291 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants”;

(3) the most recent version of ASTM D5373 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal”;

(4) any other analysis method published by an organization listed in QC.1.5.

QC.9.5. Methods for estimating missing data

When, as part of an emitter’s sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.

When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:

(1) an emitter who uses one of the calculation methods provided for in this Protocol must,

(a) when the missing data concern carbon content, molecular mass, molar fraction, molecular fraction, high heat value, CO2 concentration, CO concentration, O2 concentration, temperature, pressure, nitrogen content or biochemical oxygen demand,

i. determine the sampling or measurement rate using the following equation:

Equation 9-28

R = QS Act/QS Required

Where:

R = Actual sampling or measurement rate, expressed as a percentage;

QS Act = Quantity of actual samples or measurements obtained by the emitter;

QS Required = Quantity of samples or measurements required under QC.9.4;

ii. for data that require sampling or analysis,

— if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;

— if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;

— if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;

(b) when the missing data concern coke burn, volumetric gas flow, gas volume, number of hours of operation, quantity of bituminous product blown, quantity of crude oil and intermediate products, quantity of wastewater treated, quantity of coke, quantity of coke dust or number of vessels openings in a coking unit, the replacement data must be estimated on the basis of all the data relating to the processes used;

(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.

QC.9.6. Tables

Table 9-1. Coke burn rate material balance and conversion factors

(QC.9.3.1(1))

 _________________________________________________________________________________
|                                        |                                        |
|  Conversion factor                     |  (kg min)/(h m3 (dry base) %)          |
|________________________________________|________________________________________|
|                                        |                                        |
|  K1                                    |   0.2982                               |
|________________________________________|________________________________________|
|                                        |                                        |
|  K2                                    |   2.0880                               |
|________________________________________|________________________________________|
|                                        |                                        |
|  K3                                    |   0.0994                               |
|________________________________________|________________________________________|                        

Table 9-2. (Revoked)

Table 9-3. CH4 conversion factors by type of industrial wastewater treatment process

(QC.9.3.7(1))

__________________________________________________________________________________
|                            |                           |            |           |
| Type of treatment and      |         Comments          | Conversion |   Range   |
| discharge pathway or       |                           | factor     |           |
| system                     |                           | (MCF)      |           |
|____________________________|___________________________|____________|___________|
|                                                                                 |
| Untreated                                                                       |
|_________________________________________________________________________________|
|                            |                           |            |           |
| Sea, river and lake        | Rivers with high organic  | 0.1        | 0 - 0.2   |
| discharge1                 | loading may turn          |            |           |
|                            | anaerobic, however this   |            |           |
|                            | is not considered here    |            |           |
|____________________________|___________________________|____________|___________|
|                                                                                 |
| Treated                                                                         |
|_________________________________________________________________________________|
|                            |                           |            |           |
| Aerobic treatment plant    | Well maintained, some CH4 | 0          | 0 - 0.1   |
|                            | may be emitted from       |            |           |
|                            | settling basins           |            |           |
|____________________________|___________________________|____________|___________|
|                            |                           |            |           |
| Aerobic treatment plant    | Not well maintained,      | 0.3        | 0.2 - 0.4 |
|                            | overloaded                |            |           |
|____________________________|___________________________|____________|___________|
|                            |                           |            |           |
| Anaerobic digester for     | CH4 recovery not          | 0.8        | 0.8 - 1.0 |
| sludge2                    | considered here           |            |           |
|____________________________|___________________________|____________|___________|
|                            |                           |            |           |
| Anaerobic reactor2         | CH4 recovery not          | 0.8        | 0.8 - 1.0 |
|                            | considered here           |            |           |  
|____________________________|___________________________|____________|___________|
|                            |                           |            |           |
| Anaerobic shallow lagoon   | Depth less than 2 meters  | 0.2        | 0 - 0.3   |
|____________________________|___________________________|____________|___________|
|                            |                           |            |           |
| Anaerobic deep lagoon      | Depth more than 2 meters  | 0.8        | 0.8 - 1.0 |
|____________________________|___________________________|____________|___________|
|                                                                                 |
| For CH4 generation capacity (B) in kilograms of CH4 per kilogram of chemical    | 
| oxygen demand (COD), the emitter must use the default emission factor of        |
| 0.25 kg CH4 per kilogram COD.                                                   |
|                                                                                 |
| The emission factor for N2O from discharged wastewater (EFN2O) is 0.005 kg      |
| N2O-N per kg-N.                                                                 |
|                                                                                 |
| MCF = CH4 conversion factor (the fraction of waste treated anaerobically).      |
|                                                                                 |
| (1) The fact that rivers with high organic loading may turn anaerobic is not    |
| taken into account.                                                             |
|                                                                                 |
| (2) CH4 recovery is not taken into account.                                     |
|_________________________________________________________________________________|                        

Table 9-4. Emission factors for oil-water separators

(QC.9.3.8)

 _________________________________________________________________________________
|                                        |                                        |
| Type of separator                      | Emission factor (EFsep)a kg NMHC/m3     |
|                                        | wastewater treated                     |
|________________________________________|________________________________________|
|                                        |                                        |
| Gravity type - uncovered               | 1.11e-01                               |
|________________________________________|________________________________________|
|                                        |                                        |
| Gravity type - covered                 | 3.30e-03                               |
|________________________________________|________________________________________|
|                                        |                                        |
| Gravity type - covered and connected   | 0                                      |
| to destruction device                  |                                        | 
|________________________________________|________________________________________|
|                                        |                                        |
| DAFb of IAFc - uncovered               | 4.00e-03d                              |
|________________________________________|________________________________________|
|                                        |                                        |
| DAF or IAF - covered                   | 1.20e-04d                              |
|________________________________________|________________________________________|
|                                        |                                        |
| DAF or IAF - covered and connected     | 0                                      |
| to a destruction device                |                                        |
|________________________________________|________________________________________|
|                                                                                 |
| a EFs do not include methane                                                    | 
|                                                                                 |
| b DAF = dissolved air flotation type                                            |
|                                                                                 |
| c IAF = induced air flotation device                                            |
|                                                                                 |
| d EFs for these types of separators apply where they are installed as secondary |
|   treatment systems.                                                            |
|_________________________________________________________________________________|                        

Table 9-5. (Revoked)

QC.10. PULP AND PAPER MANUFACTURING

QC.10.1. Covered sources

The covered sources are all the processes used to manufacture pulp and paper products.

QC.10.2. Greenhouse gas reporting requirements

In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:

(1) the annual CO2 emissions attributable to the combustion of biomass, including black liquor, in recovery furnaces and lime kilns, calculated and reported in accordance with QC.1, in metric tons;

(2) the annual CH4 and N2O emissions attributable to the combustion of biomass, including black liquor, in recovery furnaces and lime kilns, calculated and reported in accordance with QC.1, in metric tons;

(3) the annual CO2 emissions attributable to the addition of carbonate materials in recovery furnaces and lime kilns, calculated and reported in accordance with QC.25.3, in metric tons;

(3.1) the annual CO2, CH4 and N2O emissions attributable to production of electricity, calculated and reported in accordance with QC.16, in metric tons;

(4) the annual CO2, CH4 and N2O emissions attributable to the use of stationary combustion units, calculated and reported in accordance with QC.1, in metric tons;

(5) the annual consumption of carbonate materials, in metric tons;

(6) the annual production of black liquor, in metric tons;

(7) the annual CH4 and N2O emissions from anaerobic wastewater treatment, calculated and reported in accordance with QC.9.3.7, in metric tons;

(8) the number of times that the methods for estimating missing data provided for in QC.10.5 were used;

(9) (subparagraph revoked);

(10) the annual production of each pulp and paper product manufactured, in metric tons of air-dried at 10% humidity marketable products.

For the purposes of subparagraph 8 of the first paragraph of section 6.2:

(1) the emissions referred to in subparagraph 3 of the first paragraph are emissions attributable to fixed processes;

(2) the emissions referred to in subparagraphs 2, 3.1 and 4 of the first paragraph are emissions attributable to combustion;

(3) the emissions referred to in subparagraph 7 of the first paragraph are other emissions.

QC.10.3. Calculation methods for CO2, CH4 and N2O emissions

To calculate the CO2, CH4 and N2O emissions from biomass, the high heat value or carbon content of the biomass must be determined by the emitter in accordance with QC.10.4.

QC.10.3.1. Calculation of CO2, CH4 and N2O emissions attributable to the combustion of biomass

The annual CO2, CH4 and N2O emissions attributable to the combustion of biomass, including black liquor, in recovery furnaces and rotary lime kilns in sulphite pulp and soda pulp mills, in combustion units for recovered sulphites or bisulphites, or in independent combustion units for semi-chemical pulp process, must be calculated in accordance with QC.1.

QC.10.3.2. Calculation of CO2, CH4 and N2O emissions attributable to the addition of carbonate materials

The annual CO2, CH4 and N2O emissions attributable to the addition of carbonate materials in recovery furnaces and lime kilns must be calculated in accordance with QC.25.3.

QC.10.3.3. Calculation of CO2, CH4 and N2O emissions attributable to the production of electricity

The annual CO2, CH4 and N2O emissions attributable to the production of electricity must be calculated in accordance with QC.16.

QC.10.4. Sampling, analysis and measurement requirements

An emitter who manufactures pulp and paper must:

(1) determine the quantity of black liquor produced each year using one of the following methods:

(a) by measuring it in accordance with the most recent version of TAPPI T 650 om-09 “Solids content of black liquor” published by the Technical Association of the Pulp and Paper Industry;

(b) by measuring it using monthly data from a monitoring device installed on the process line;

(c) by determining it using equation 1-8;

(d) by using any other analysis method published by an organization listed in QC.1.5;

(1.1) determine the high heat value of the black liquor using the most recent version of TAPPI T 684 om-11 “Gross heating value of black liquor”, or using any other analysis method published by an organization listed in QC.1.5;

(2) measure the monthly carbon content of the black liquor using the most recent version of ASTM D5373 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal” or ASTM 5291 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricant”, or using any other analysis method published by an organization listed in QC.1.5;

(3) (paragraph revoked);

(4) (paragraph revoked);

QC.10.5. Methods for estimating missing data

When, as part of an emitter’s sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.

When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:

(1) an emitter who uses one of the calculation methods provided for in this Protocol must,

(a) when the missing data concern carbonate content in raw materials or in carbonate-based material output, use the default value of 1.0;

(b) when the missing data concern carbon content or high heat value,

i. determine the sampling or measurement rate using the following equation:

Equation 10-1

R = QS Act/QS Required

Where:

R = Actual sampling or measurement rate, expressed as a percentage;

QS Act = Quantity of actual samples or measurements obtained by the emitter;

QS Required = Quantity of samples or measurements required under QC.10.4;

ii. for data that require sampling or analysis,

— if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;

— if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;

— if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;

(c) when the missing data concern the quantity of spent pulping liquor, the mass flow of spent pulping liquor, the annual production of each pulp and paper product manufactured or the quantity of carbonate material, the replacement data must be estimated on the basis of all the data relating to the processes used;

(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.

QC.11. SODIUM CARBONATE PRODUCTION

QC.11.1. Covered sources

The covered sources are all the processes used in the production of sodium carbonate by calcining trona or sodium sesquicarbonate, and all liquid alkaline feedstock processes that produce CO2.

QC.11.2. Greenhouse gas reporting requirements

In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:

(1) the annual CO2 emissions from sodium carbonate production, calculated in accordance with QC.11.3, in metric tons;

(2) the annual CO2, CH4 and N2O emissions attributable to fuel combustion in calcining kilns, calculated and reported in accordance with QC.1, in metric tons;

(3) the annual consumption of trona, sodium sesquicarbonate and liquid alkaline feedstock, in metric tons;

(4) the annual production of sodium carbonate, in metric tons;

(4.1) the number of times that the methods for estimating missing data specified in QC.11.5 were used;

(4.2) (subparagraph revoked);

(5) (subparagraph revoked);

(6) (subparagraph revoked);

(7) (subparagraph revoked);

(8) (subparagraph revoked);

(9) (subparagraph revoked).

For the purposes of subparagraph 8 of the first paragraph of section 6.2:

(1) the emissions referred to in subparagraph 1 of the first paragraph are emissions attributable to fixed processes;

(2) the emissions referred to in subparagraph 2 of the first paragraph are emissions attributable to combustion.

QC.11.3. Calculation methods for CO2 emissions

The annual CO2 emissions from sodium carbonate production unit must be calculated using one of the calculation methods in QC.11.3.1 to QC.11.3.3.

QC.11.3.1. Calculation method using data from a continuous emission monitoring and recording system

The annual CO2 emissions from a sodium carbonate production unit may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.1.3.4.

QC.11.3.2. Calculation method using inorganic carbon content

The annual CO2 emissions from a sodium carbonate production unit may be calculated using equation 11-1 or 11-2:

Equation 11-1

Where:

CO2 = Annual CO2 emissions attributable to sodium carbonate production, in metric tons;

i = Month;

CITR = Monthly inorganic carbon content of trona at kiln input for month i, in kilograms of carbon per kilogram of trona;

TR = Monthly quantity of trona input in month i, in metric tons;

0.097 = Ratio of CO2 emitted for each metric ton of trona, in metric tons of CO2 per metric ton of trona;

Equation 11-2

Where:

CO2 = Annual CO2 emissions attributable to sodium carbonate production, in metric tons;

i = Month;

CISC = Monthly inorganic carbon content of sodium carbonate at kiln output for month i, in kilograms of carbon per kilogram of sodium carbonate;

SC = Monthly quantity of sodium carbonate produced during month i, in metric tons;

0.138 = Ratio of CO2 emitted for each metric ton of sodium carbonate produced, in metric tons of CO2 per metric ton of sodium carbonate.

QC.11.3.3. Calculation method using site-specific emission factor

The annual CO2 emissions from a sodium carbonate production unit using liquid alkaline feedstock may be calculated using equations 11-3 to 11-5:

Equation 11-3

CO2 = EFCO2 × Va × H

Where:

CO2 = Annual CO2 emissions attributable to sodium carbonate production, in metric tons;

EFCO2 = CO2 emission factor, in metric tons of CO2 per metric ton of process vent flow from water stripper/evaporator, calculated using equation 11-4;

Va = Process vent mass flow of water stripper/evaporator, in metric tons per hour;

H = Number of hours of operation during the year;

Equation 11-4

         ERCO2
EFCO2 =  _____
          Vtp                        

Where:

EFCO2 = CO2 emission factor, in metric tons of CO2 per metric ton of process vent flow from water stripper/evaporator;

ERCO2 = CO2 emission rate, in metric tons per hour, calculated using equation 11-5;

Vtp = Process vent mass flow of water stripper/evaporator, measured during performance test, in metric tons per hour;

Equation 11-5

ERCO2 = [(CCO2 × 10000 × 4,16 × 10-8 × 44) × (VF × 60)] × 0.001

Where:

ERCO2 = CO2 emission rate, in metric tons per hour;

CCO2 = Hourly concentration of CO2 in the gas, determined in accordance with QC.11.4, expressed as a percentage;

10000 = Conversion factor, percentage to ppm;

4.16 × 10-8 = Conversion factor, ppm to kilomoles per cubic metre at standard conditions;

44 = Molecular weight of CO2, kilograms per kilomole;

VF = Volumetric flow of gas, in cubic metres at standard conditions per minute;

60 = Conversion factor, minutes to hours;

0.001 = Conversion factor, kilograms to metric tons.

QC.11.4. Sampling, analysis and measurement requirements

An emitter who uses equation 11-1 or 11-2 in QC.11.3.2 must:

(1) determine the monthly inorganic carbon content of the trona or sodium carbonate from a weekly composite sample for each production unit using the most recent version of ASTM E359 e1 “Standard Test Methods for Analysis of Soda Ash (Sodium Carbonate(e)”, or using any other analysis method published by an organization listed in QC.1.5;

(2) measure the quantity of trona or sodium carbonate for each production unit using the same plant instruments as those used for inventory purposes.

An emitter who uses equations 11-3 to 11-5 in QC.11.3.3 must conduct an annual performance test in normal operating conditions, during which the emitter must:

(1) conduct 3 emissions test runs of 1 hour each;

(2) determine the hourly CO2 concentration in accordance with Method 3A in appendix A-2 of Part 60 of Title 40 of the Code of Federal Regulations “Determination of Oxygen and Carbon Dioxide Concentrations in Emissions From Stationary Sources (Instrumental Analyzer Procedure)” published by the U.S. Environmental Protection Agency (USEPA);

(3) determine the stack gas volumetric flow rate using one of the methods published by the U.S. Environmental Protection Agency (USEPA):

(a) Method 2 in Appendix A-1 of Part 60 of Title 40 of the Code of Federal Regulations “Determination of Stack Gas Velocity and Volumetric Flow Rate (Type S Pitot Tube)”;

(b) Method 2A in Appendix A-1 of Part 60 of Title 40 of the Code of Federal Regulations “Direct Measurement of Gas Volumetric Through Pipes and Small Ducts”;

(c) Method 2C in Appendix A-1 of Part 60 of Title 40 of the Code of Federal Regulations “Determination of Gas Velocity and Volumetric Flow Rate in Small Stacks or Ducts (Standard Pitot Tube)”;

(d) Method 2D in Appendix A-1 of Part 60 of Title 40 of the Code of Federal Regulations “Measurement of Gas Volume Flow Rates in Small Pipes and Ducts”;

(e) Method 2F in Appendix A-1 of Part 60 of Title 40 of the Code of Federal Regulations “Determination of Stack Gas Velocity and Volumetric Flow Rate with Three-Dimensional Probes”;

(f) Method 2G in Appendix A-2 of Part 60 of Title 40 of the Code of Federal Regulations “Determination of Stack Gas Velocity and Volumetric Flow Rate With Two-Dimensional Probes”;

(4) prepare a CO2 emission factor determination report containing all the information needed to calculate the emission factor and the sample reports prepared pursuant to paragraph 1;

(5) determine the average process vent flow from the water stripper/evaporator;

(6) determine the annual vent flow rate from the mine water stripper/evaporator from monthly data using the same plant instruments as those used for inventory purposes, such as a volumetric flowmeter.

QC.11.5. Methods for estimating missing data

When, as part of an emitter’s sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.

When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:

(1) an emitter who uses one of the calculation methods provided for in this Protocol must,

(a) when the missing data concern the hourly concentration of CO2, the volumetric gas flow rate or the process vent average mass flow rate of gas in the water stripper/evaporator during a performance test, conduct a new performance test;

(b) when the missing data concern carbon content,

i. determine the sampling or measurement rate using the following equation:

Equation 11-6

R = QS Act/QS Required

Where:

R = Actual sampling or measurement rate, expressed as a percentage;

QS Act = Quantity of actual samples or measurements obtained by the emitter;

QS Required = Quantity of samples or measurements required under QC.11.4;

ii. for data that require sampling or analysis,

— if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;

— if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;

— if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;

(c) when the missing data concern the ore quantity, process vent mass flow rate of gas in the water stripper/evaporator or quantity of sodium carbonate, estimate the replacement data on the basis of all the data relating to the processes used;

(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.

QC.12. MANUFACTURING OF PETROCHEMICAL PRODUCTS

QC.12.1. Covered sources

The covered sources are all the processes used in the production of petrochemical products from feedstocks derived from petroleum, or petroleum and natural gas liquids, but not from feedstocks derived from biomass.

The production of methanol, hydrogen, or ammonia from synthesis gas is also covered if the annual production of methanol exceeds the combined production of both hydrogen recovered as a product and ammonia. However, if the annual mass of hydrogen recovered exceeds the combined annual production of methanol and ammonia, the emissions must be calculated and reported in accordance with QC.6 with respect to hydrogen production. In addition, if the annual production of ammonia exceeds the combined annual production of both hydrogen recovered as a product and methanol, the emissions must be calculated and reported in accordance with QC.23 with respect to ammonia production.

A process that produces only a petrochemical by-product, and a direct chlorination process that is operated independently of an oxychlorination process to produce ethylene dichloride, is not covered.

QC.12.2. Greenhouse gas reporting requirements

In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include

(1) the annual CO2, CH4 and N2O emissions attributable to the use of stationary combustion units, calculated and reported in accordance with QC.1, in metric tons;

(2) the annual CO2, CH4 and N2O emissions attributable to the combustion of refinery fuel gas, flexigas or associated gas, calculated and reported in accordance with QC.2, in metric tons;

(2.1) the annual CO2 emissions attributable to hydrogen production processes, calculated and reported in accordance with QC.6, in metric tons;

(3) the annual CO2 emissions attributable to each petrochemical process, in metric tons;

(4) the annual CO2 emissions attributable to catalyst regeneration calculated and reported in accordance with QC.9, in metric tons;

(4.1) the annual CH4 and N2O emissions attributable to catalyst regeneration calculated and reported in accordance with QC.9, in metric tons;

(5) the annual CO2, CH4 and N2O emissions attributable to flares and antipollution devices calculated and reported in accordance with QC.9, in metric tons;

(6) the annual CO2, CH4 and N2O emissions from process vents calculated and reported in accordance with QC.9, in metric tons;

(7) the annual CH4 emissions from leaks from equipment components calculated and reported in accordance with QC.9, in metric tons;

(8) the annual CH4 emissions from storage tanks calculated and reported in accordance with QC.9, in metric tons;

(9) the annual CH4 and N2O emissions attributable to wastewater treatment, calculated and reported in accordance with QC.9.3.7, in metric tons;

(10) the annual CH4 emissions attributable to oil-water separators, calculated and reported in accordance with QC.9.3.8, in metric tons;

(11) the annual consumption of each type of raw material that emits CO2, CH4 or N2O, expressed

(a) in metric tons, when the quantity is expressed as a mass;

(b) in thousands of cubic metres at standard conditions, when the quantity is expressed as a volume of gas;

(c) in kilolitres, when the quantity is expressed as a volume of liquid;

(d) in bone dry metric tons, for biomass-derived solid fuels, when the quantity is expressed as a mass;

(11.1) the annual production of each petrochemical product, namely:

(a) in dry metric tons when the quantity is expressed in weight;

(b) in thousands of cubic metres at standard conditions when the quantity is expressed as a volume of gas;

(c) in kilolitres when the quantity is expressed as a volume of liquid;

(d) in dry metric tons in the case of biomass fuels when the quantity is expressed in weight;

(12) the average annual carbon content of the materials consumed or of the products, in kilograms of carbon per kilogram of materials consumed or products;

(13) the average annual molecular mass of the gas consumed or of the products, in kilograms per kilomole;

(14) the number of times that the methods for estimating missing data provided for in QC.12.5 were used;

(15) (subparagraph revoked).

For the purposes of subparagraph 8 of the first paragraph of section 6.2:

(1) the emissions referred to in subparagraph 2.1, 3 and 4 of the first paragraph are emissions attributable to fixed processes;

(2) the emissions referred to in subparagraphs 1 and 2 of the first paragraph are emissions attributable to combustion;

(3) the emissions referred to in subparagraphs 4.1 and 5 to 10 of the first paragraph are other emissions.

QC.12.3. Calculation methods for CO2, CH4 and N2O emissions

The annual CO2, CH4 and N2O emissions attributable to the production of petrochemical products must be calculated in accordance with the calculation methods in QC.12.3.1 to QC.12.3.6.

QC.12.3.1. Calculation of CO2 emissions attributable to each petrochemical process

The annual CO2 emissions attributable to each petrochemical process must be calculated in accordance with the following methods:

(1) where the quantity of feedstock and the quantity of product are expressed as volumes of gas, using equation 12-1:

Equation 12-1

Where:

CO2 = Annual CO2 emissions attributable to each petrochemical process, in metric tons;

k = Month;

n = Number of feedstock materials;

m = Number of products;

i = Type of feedstock the quantity of which is expressed as a volume of gas;

j = Type of product the quantity of which is expressed as a volume of gas;

(VGI)i,k = Quantity of feedstock i consumed in month k, in thousands of cubic metres at standard conditions;

(CGI)i,k = Average carbon content of feedstock i in for month k, in kilograms of carbon per kilogram of feedstock;

(MMGI)i = Monthly average molecular mass of feedstock i, in kilograms per kilomole or, when a mass flowmeter is used to measure the flow of gas input in metric tons for month n, replace

 _  _
|    |
|MMGI |
|----| by 1;
|MVC |
|_  _|                        

MVC = Molar volume conversion factor (24.06 m3 per kilomole at standard conditions);

(VGP)j,k = Volume of product j produced in month k, in thousands of cubic metres at standard conditions;

(CGP)j,k = Average carbon content of product j produced in month k, in kilograms of carbon per kilogram of product;

(MMGP)j = Monthly average molecular mass of gas j, in kilograms per kilomole;

3.664 = Ratio of molecular weights, CO2 to carbon;

1 = Conversion factor, kilograms to metric tons and thousands of cubic metres to cubic metres;

(2) where the quantity of feedstock and the quantity of product are expressed as a mass, using equation 12-2:

Equation 12-2

Where:

CO2 = Annual CO2 emissions attributable to each petrochemical process, in metric tons;

n = Month;

k = Number of feedstock materials;

m = Number of products;

i = Type of feedstock material the quantity of which is expressed as a mass;

j = Type of product the quantity of which is expressed as a mass;

(QF)i,n = Quantity of feedstock i consumed in month n, in metric tons;

(CF)i,n = Average carbon content of feedstock i for month n, in kilograms of carbon per kilogram of feedstock;

(QP)j,n = Quantity of product j for month n, in metric tons;

(CP)j,n = Average carbon content of product j for month n, in kilograms of carbon per kilogram of product;

3.664 = Ratio of molecular weights, CO2 to carbon.

QC.12.3.2. Calculation of CO2, CH4 and N2O emissions attributable to catalyst regeneration

The annual CO2 emissions attributable to catalyst regeneration at a facility equipped with a continuous emission monitoring and recording system must be calculated in accordance with QC.1.3.4 or, in the absence of such a system, in accordance with QC.9.3.1 according to the type of process.

QC.12.3.3. Calculation of CO2, CH4 and N2O emissions attributable to combustion in flares and other antipollution equipments

The annual CO2, CH4 and N2O emissions attributable to combustion in flares must be calculated in accordance with the calculation methods in QC.9.3.5.

The annual CO2, CH4 and N2O emissions attributable to combustion in other antipollution equipments must be calculated in accordance with the calculation methods in QC.1, except CH4 and N2O emissions attributable to process off-gas combustion which must be calculated using equation 1-12 in QC.1.4.2 with emission factors of 2.8 × 10-3 kg per gigajoule for CH4 and 5.7 × 10-4 kg per gigajoule for N2O.

QC.12.3.4. Calculation of CO2, CH4 and N2O emissions from process vents

For each process vent that contains over 2% CO2 by volume, over 0.5% CH4 by volume, or over 0.01% N2O by volume, the annual CO2, CH4 and N2O emissions from process vents, other than emissions required for the process, must be calculated in accordance with QC.9.3.2.

QC.12.3.5. Calculation of fugitive CH4 emissions from equipment components

The annual fugitive emissions of CH4 from all components in the natural gas or refinery gas supply system and from pressure swing adsorption (PSA) systems must be calculated in accordance with paragraph 1 of  QC.9.3.9.

QC.12.3.6. Calculation of CH4 emissions from storage tanks

The annual CH4 emissions from storage tanks containing petroleum-derived products that are not equipped with pressure swing adsorption (PSA) systems must be calculated in accordance with QC.9.3.6.

QC.12.3.7. (Revoked).

QC.12.3.8. (Revoked).

QC.12.4. Sampling, analysis and measurement requirements

QC.12.4.1. Catalyst regeneration

For catalyst regeneration, the emitter must measure the parameters in accordance with QC.9.4.1.

QC.12.4.2. Flares and other antipollution devices

For flares and antipollution devices, the emitter must measure the parameters in accordance with QC.9.4.5 and determine quarterly the carbon content and high heat value.

QC.12.4.3. Process vents

For process vents, the emitter must, for each process vent event, measure the parameters in accordance with QC.9.4.2.

QC.12.4.4. (Revoked).

QC.12.4.5. Storage tanks

For storage tanks, the emitter must measure the annual throughput of crude oil, naphtha, distillate oils and gasoil using flowmeters.

QC.12.4.6. Wastewater treatment

For wastewater treatment, the emitter must measure the parameters in accordance with QC.9.4.7.

QC.12.4.7. Oil-water separators...

For oil-water separators, the emitter must measure the daily volume of wastewater treated in the oil-water separators.

QC.12.4.8. Feedstock consumption and products

An emitter who calculates greenhouse gas emissions in accordance with QC.12.3.1 must determine, monthly, the quantity of feedstock consumed and the quantity of products produced using the following methods:

(1) if the feedstock and product are gases, using a flowmeter;

(2) if the feedstock and product are liquids, using a flowmeter or by measuring the liquid level in a storage tank;

(3) if the feedstock and product are solids, using the same plant instruments as those used for inventory purposes, such as weigh hoppers or belt weight feeders.

The emitter must determine carbon content monthly and, in the case of a gas, its molecular weight, using the sampling and analysis results indicated by the supplier or samples taken by the emitter. When more than one monthly value is available, the arithmetic average must be used.

When the monthly average concentration of a specific compound in a feedstock or product is greater than 99.5% by weight or, in the case of a gas, by volume then, as an alternative, the emitter may determine the carbon content by assuming that 100% of that feedstock or product is the specific compound in normal operating conditions. A determination made using this alternative must be reevaluated after any process change that affects the feedstock or product composition. However, this alternative may not be used for products during periods of operation when off-specification product is produced, or when the average monthly concentration falls below 99.5%.

QC.12.5. Methods for estimating missing data

When, as part of an emitter’s sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.

When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:

(1) an emitter who uses one of the calculation methods provided for in this Protocol must,

(a) when the missing data concern carbon content, molecular mass, molar fraction, molecular fraction, high heat value, CO2 concentration, CO concentration, O2 concentration, temperature, pressure, nitrogen content or biochemical oxygen demand,

i. determine the sampling or measurement rate using the following equation:

Equation 12-3

R = QS Act/QS Required

Where:

R = Actual sampling or measurement rate, expressed as a percentage;

QS Act = Quantity of actual samples or measurements obtained by the emitter;

QS Required = Quantity of samples or measurements required under QC.12.4;

ii. for data that require sampling or analysis,

— if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;

— if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;

— if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;

(b) when the missing data concern coke burn, volumetric gas flow, gas volume, number of hours of operation, quantity of raw materials, quantity of product, quantity of steam or quantity of wastewater treated, the replacement data must be estimated on the basis of all the data relating to the processes used;

(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.

QC.13. ADIPIC ACID PRODUCTION.

QC.13.1. Covered sources

The covered sources are all the oxidization processes used for the production of adipic acid.

QC.13.2. Greenhouse gas reporting requirements

In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:

(1) the annual N2O emissions attributable to the production of adipic acid in metric tons;

(1.1) the annual CO2, CH4 and N2O emissions attributable to combustion, calculated and reported in accordance with QC.1, in metric tons;

(2) the total annual production of adipic acid, in metric tons;

(2.1) the annual production of adipic acid when the antipollution system is used, in metric tons;

(3) the N2O emission factor in metric tons of N2O per metric ton of adipic acid;

(4) the destruction factor for the facility’s antipollution equipment;

(5) the utilization factor for the facility’s antipollution equipment;

(6) the number of times that the methods for estimating missing data in QC.13.5 were used;

(7) (subparagraph revoked).

For the purposes of subparagraph 8 of the first paragraph of section 6.2:

(1) the emissions referred to in subparagraph 1.1 of the first paragraph are emissions attributable to combustion;

(2) the emissions referred to in subparagraph 1 of the first paragraph are other emissions.

QC.13.3. Calculation methods for N2O emissions attributable to the oxidation process

The annual N2O emissions attributable to the oxidation process must be calculated in accordance with the calculation method in QC.13.3.1 for each of the facility’s antipollution equipments.

QC.13.3.1. Calculation method using the N2O emission factor and destruction factors and the use of antipollution equipment

The annual N2O emissions must be calculated using equation 13-1:

Equation 13-1

Where:

N2O = N2O emissions attributable to the oxidation process, in metric tons;

n = Total number of periods. When a performance test is conducted annually, “n” is 1. If data is obtained from a continuous emission monitoring and recording system, “n” is at least 12;

i = Period;

EFN2O = N2O emission factor for period i, calculated in accordance with equation 13-2 or 13-3, in kilograms of N2O per metric ton of adipic acid produced;

PAA = Production of adipic acid in period i, in metric tons;

FD = Destruction factor for the antipollution equipment for period i, determined in accordance with QC.13.4;

FU = Use factor for the antipollution equipment, calculated in accordance with equation 13-4;

0.001 = Conversion factor, kilograms in metric tons;

Equation 13-2

Where:

EFN2O = N2O emission factor, in kilograms of N2O per metric ton of adipic acid produced;

n = Number of performance tests;

i = Performance test conducted in accordance with QC.13.4;

CN2O = N2O concentration in the gas stream during performance test i carried out in accordance with QC.13.4, in ppm;

Qfg = Volumetric flow of gas stream during performance test i, in cubic metres at standard conditions per hour;

1.826 × 10-6 = Conversion factor of ppm, kilograms per cubic metre at standard conditions;

P = Production rate of adipic acid during performance test i, in metric tons per hour;

Equation 13-3

        CN2O × Qfg × 1.826 × 10-6
EFN2O = _________________________
                  P                        

Where:

EFN2O = N2O emission factor, in kilograms of N2O per metric ton of adipic acid produced;

CN2O = N2O concentration in the continuously-measured gas stream, in ppm;

Qfg = Volumetric flow of continuously-measured gas stream, in cubic metres at standard conditions per hour;

1.826 × 10-6 = Conversion factor of ppm, in kilograms per cubic metre at standard conditions;

P = Production rate of adipic acid measured continuously, in metric tons per hour;

Equation 13-4

     PAA,1
FU = _____
     PAA,2                        

Where:

FU = Use factor of antipollution equipment;

PAA,1 = Production of adipic acid when the antipollution equipment is used, in metric tons;

PAA,2 = Annual production of adipic acid, in metric tons.

QC.13.3.2. (Revoked)

QC.13.4. Sampling, analysis and measurement requirements

An emitter who operates a facility or establishment that produces adipic acid must use a continuous monitoring and recording system or conduct performance tests.

In the latter case, the performance test must be conducted annually on the waste gas stream from the nitric acid oxidation step when the adipic acid production process is changed either by altering the ratio of cyclohexanone to cyclohexanol or be conducted when installing an antipollution system, in normal operating conditions and when the antipollution system is not used. A report on the determination of the N2O emission factor, containing all the information needed to calculate the emission factor, must be prepared.

An emitter who does not use a continuous monitoring and recording system must also

(1) measure the N2O concentration using one of the following methods:

(a) Method 320 in appendix A of Part 63 of Title 40 of the Code of Federal Regulations “Measurement of Vapor Phase Organic and Inorganic Emissions by Extractive Fourier Transform Infrared (FTIR) Spectroscopy”, published by the U.S. Environmental Protection Agency (USEPA);

(b) the most recent version of ASTM D6348 “Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy”;

(b.1) any other analysis method published by an organization listed in QC.1.5;

(c) determine the adipic acid production rate using annual sales data or using a measuring instrument such as a flowmeter or weight scales.

In all cases, an emitter must

(1) determine the total monthly quantity of adipic acid produced and, when the antipollution system is used, the quantity of adipic acid produced, using one of the methods in subparagraph c of subparagraph 1 of the third paragraph;

(2) determine the destruction factor using one of the following methods:

(a) using the manufacturer’s specified destruction factor;

(b) estimating the destruction factor based on all data relating to the processes used;

(c) conducting a performance test on the gas flow from the antipollution system;

(d) using a continuous emission monitoring and recording system.

QC.13.5. Methods for estimating missing data

When, as part of an emitter’s sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.

When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:

(1) an emitter who uses one of the calculation methods provided for in this Protocol must,

(a) when data determined on the basis of the performance test provided for in QC.13.4 is missing, conduct a new performance test;

(b) when the missing data concern carbon content, temperature, pressure or gas concentration, other than data prescribed in the performance test,

i. determine the sampling or measurement rate using the following equation:

Equation 13-5

R = QS Act/QS Required

Where:

R = Actual sampling or measurement rate, expressed as a percentage;

QS Act = Quantity of actual samples or measurements obtained by the emitter;

QS Required = Quantity of samples or measurements required under QC.13.4;

ii. for data that require sampling or analysis,

— if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;

— if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;

— if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;

(c) when the missing data concern adipic acid production or gas flow rate, the replacement data must be estimated on the basis of all the data relating to the processes used;

(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.

QC.14. LEAD PRODUCTION

QC.14.1. Covered sources

The covered sources are all processes used in primary and secondary lead production.

QC.14.2. Greenhouse gas reporting requirements

In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:

(1) (subparagraph revoked);

(2) the annual CO2 emissions attributable to the use in the furnace of each material that contributes 0.5% or more of the total carbon in the process, in metric tons;

(2.1) the annual CO2, CH4 and N2O emissions attributable to the use of stationary combustion equipment, calculated and reported in accordance with QC.1, in metric tons;

(3) the annual quantity of each material or product that contributes 0.5% or more of the total carbon in the process, in metric tons;

(4) the average annual carbon content of each material or product that contributes 0.5% or more of the total carbon in the process, in metric tons of carbon per metric ton of material or product;

(5) the number of times that the methods for estimating missing data in QC.14.5 were used;

(6) (subparagraph revoked);

(7) the annual quantity of lead produced, in metric tons;

Subparagraph 4 of the first paragraph does not apply to the CO2 emissions of an emitter who calculates emissions using data from a continuous emission monitoring and recording system.

For the purposes of subparagraph 8 of the first paragraph of section 6.2:

(1) the emissions referred to in subparagraph 2 of the first paragraph are emissions attributable to fixed processes;

(2) the emissions referred to in subparagraph 2.1 of the first paragraph are emissions attributable to combustion.

QC.14.3. Calculation methods for CO2 emissions attributable to primary and secondary lead production processes

The annual CO2 emissions attributable to use in the furnace of each material containing carbon must be calculated in accordance with one of the two calculation methods in QC.14.3.1 and QC.14.3.2.

QC.14.3.1. Use of a continuous emission monitoring and recording system

The annual CO2 emissions may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.1.3.4.

QC.14.3.2. Calculation by mass balance

The annual CO2 emissions may be calculated using equation 14-1:

Equation 14-1

Where:

CO2 = Emissions of CO2 attributable to the use in the furnace of materials containing carbon, in metric tons;

n = Number of types of material;

i = Type of material;

Mi = Annual quantity of each material i used that contributes 0.5% or more of the total carbon in the process, in metric tons;

Ci = Average annual carbon content of each material i used, in metric tons of carbon per metric ton of material;

m = Number of types of product;

j = Type of product;

Pj = Annual quantity of each product j that contributes 0.5% or more of the total carbon in the process, in metric tons;

Cj = Average annual carbon content of each product j used, in metric tons of carbon per metric ton of product;

3.664 = Ratio of molecular weights, CO2 to carbon.

QC.14.4. Sampling, analysis and measurement requirements

When the calculation method in QC.14.3.2 is used, an emitter who operates a facility or establishment that produces lead must:

(1) determine annually the carbon content of each material or product that contributes 0.5% or more of the total carbon in the process used in the furnace, either by using the data provided by the material or product supplier or by using the following methods, based on a minimum of 3 representative samples per year:

(a) for solid carbonaceous reducing agents and carbon electrodes, using the most recent version of ASTM D5373 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal”, or using any other analysis method published by an organization listed in QC.1.5;

(b) for liquid reducing agents, using the most recent version of ASTM D2502 “Standard Test Method for Estimation of Molecular Weight (Relative Molecular Mass) of Petroleum Oils From Viscosity Measurements”, ASTM D2503 “Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure”, ASTM D3238 “Standard Test Method for Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by the n-d-M Method” or ASTM D5291 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants”, or using any other analysis method published by an organization listed in QC.1.5;

(c) for gaseous reducing agents, using the most recent version of ASTM D1945 “Standard Test Method for Analysis of Natural Gas by Gas Chromatograph” or ASTM D1946 “Standard Practice for Analysis of Reformed Gas by Gas Chromatography”, or using any other analysis method published by an organization listed in QC.1.5;

(d) for waste-based materials, ores or other materials or products, by sampling and chemical analysis using an analysis method published by an organization listed in QC.1.5;

(2) calculate the annual quantity of each material or product containing carbon used in the furnace by adding together the monthly quantities of the material or product, which must be weighed using the same plant instruments used for inventory purposes, such as weigh hoppers or belt weigh feeders.

QC.14.5. Methods for estimating missing data

When, as part of an emitter’s sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.

When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:

(1) an emitter who uses one of the calculation methods provided for in this Protocol must,

(a) when the missing data concern carbon content or other sampled data,

i. determine the sampling or measurement rate using the following equation:

Equation 14-2

R = QS Act/QS Required

Where:

R = Actual sampling or measurement rate, expressed as a percentage;

QS Act = Quantity of actual samples or measurements obtained by the emitter;

QS Required = Quantity of samples or measurements required under QC.14.4;

ii. for data that require sampling or analysis,

— if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;

— if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;

— if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;

(b) when the missing data concern raw material consumption or the production of lead or other products, the replacement data must be estimated on the basis of all the data relating to the processes used;

(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.

QC.15. ZINC PRODUCTION

QC.15.1. Covered sources

The covered sources are all the processes used for primary and secondary zinc production.

QC.15.2. Greenhouse gas reporting requirements

In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:

(1) (subparagraph revoked);

(2) the annual CO2 emissions attributable to the use in the furnace of materials that contribute 0.5% or more of the total carbon in the process, in metric tons;

(2.1) the annual CO2, CH4 and N2O emissions attributable to combustion, calculated and reported in accordance with QC.1, in metric tons;

(3) the annual quantity of each material or product that contributes 0.5% or more of the total carbon in the process, in metric tons;

(4) the average annual carbon content of each material or product that contributes 0.5% or more of the total carbon in the process, in metric tons of carbon per metric ton of material;

(5) the number of times that the methods for estimating missing data in QC.15.5 were used;

(6) (subparagraph revoked);

(7) the annual quantity of cathodic zinc produced, in metric tons;

(8) the iron content of the ore, in metric tons.

Subparagraph 4 of the first paragraph does not apply to the CO2 emissions of an emitter who calculates emissions using data from a continuous emission monitoring and recording system.

For the purposes of subparagraph 8 of the first paragraph of section 6.2:

(1) the emissions referred to in subparagraph 2 of the first paragraph are emissions attributable to fixed processes;

(2) the emissions referred to in subparagraph 2.1 of the first paragraph are emissions attributable to combustion.

QC.15.3. Calculation methods for CO2 emissions attributable to primary and secondary zinc production processes

The annual CO2 emissions attributable to use in the furnace of each material containing carbon must be calculated in accordance with one of the two calculation methods in QC.15.3.1 and QC.15.3.2.

QC.15.3.1. Use of a continuous emission monitoring and recording system

The annual CO2 emissions may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.1.3.4.

QC.15.3.2. Calculation by mass balance

The annual CO2 emissions may be calculated using equation 15-1:

Equation 15-1

Where:

CO2 = Annual CO2 emissions attributable to the use in the furnace of materials containing carbon, in metric tons;

n = Number of types of material;

i = Type of material;

Mi = Annual quantity of each material i used that contributes 0.5% or more of the total carbon in the process, in metric tons;

Ci = Average monthly carbon content of material i used, in metric tons of carbon per metric ton of material;

m = Number of types of product;

j = Type of product;

Pj = Annual quantity of each product j that contributes 0.5% more of the total carbon in the process, in metric tons;

Cj = Average annual carbon content of each product j used, in metric tons of carbon per metric ton of product;

3.664 = Ratio of molecular weights, CO2 to carbon.

QC.15.4. Sampling, analysis and measurement requirements

When the calculation method in QC.15.3.2 is used, an emitter who operates a facility or establishment that produces zinc must:

(1) determine annually the carbon content of each material or product that contributes 0.5% or more of the total carbon in the process, either by using the data provided by the supplier, or by using the following methods:

(a) for ores containing zinc, using the most recent version of ASTM E1941 “Standard Test Method for Determination of Carbon in Refractory and Reactive Metals and Their Alloys”, or using any other analysis method published by an organization listed in QC.1.5;

(b) for carbonaceous reducing agents and carbon electrodes, using the most recent version of ASTM D5373 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal”, or using any other analysis method published by an organization listed in QC.1.5;

(c) for flux materials, using the most recent version of ASTM C25 “Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime”, or using any other analysis method published by an organization listed in QC.1.5;

(d) for waste-based materials, ores or other materials or products, by sampling and chemical analysis using an analysis method published by an organization listed in QC.1.5;

(2) calculate the annual quantity of each material or product containing carbon entering the furnace by direct weight measurement using the same plant instruments used for inventory purposes, such as weigh hoppers or belt weigh feeders.

QC.15.5. Methods for estimating missing data

When, as part of an emitter’s sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.

When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:

(1) an emitter who uses one of the calculation methods provided for in this Protocol must,

(a) when the missing data concern carbon content or other sampled data,

i. determine the sampling or measurement rate using the following equation:

Equation 15-2

R = QS Act/QS Required

Where:

R = Actual sampling or measurement rate, expressed as a percentage;

QS Act = Quantity of actual samples or measurements obtained by the emitter;

QS Required = Quantity of samples or measurements required under QC.15.4;

ii. for data that require sampling or analysis,

— if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;

— if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;

— if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;

(b) when the missing data concern raw material consumption, zinc production or by-product production, the replacement data must be estimated on the basis of all the data relating to the processes used;

(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.

QC.16. ELECTRICITY GENERATION

QC.16.1. Covered sources

The covered sources are stationary combustion units that combust solid, liquid or gaseous fuel for the purpose of producing electricity either for sale or for use at the facility or establishment, as well as cogeneration facilities where steam and electricity are produced.

However, emergency generators and other equipment used in an emergency with a rated capacity under 10 mW are not covered.

QC.16.2. Greenhouse gas reporting requirements

In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information, for each stationary combustion unit:

(1) the annual greenhouse gas emissions attributable to the combustion of fossil fuels, biomass fuels, biomass and municipal solid waste, in metric tons, indicating for each type of fuel:

(a) the CO2 emissions;

(b) the CH4 emissions;

(c) the N2O emissions;

(2) the annual consumption of fuel, expressed

(a) in bone dry metric tons, when the quantity is expressed as a mass;

(b) in thousands of cubic metres at standard conditions, when the quantity is expressed as a volume of gas;

(c) in kilolitres, when the quantity is expressed as a volume of liquid;

(d) in bone dry metric tons, in the case of biomass fuels, when the quantity is expressed as a mass;

(e) in metric tons collected, in the case of municipal solid waste;

(3) where carbon content is used to calculate CO2 emissions, the average annual carbon content of each type of fuel, in kilograms of carbon per kilogram of fuel;

(4) where high heat value is used to calculate CO2 emissions, the average annual high heat value of each type of fuel, expressed:

(a) in gigajoules per bone dry metric ton, in the case of a fuel whose quantity is expressed as a mass;

(b) in gigajoules per thousand cubic metres, in the case of a fuel whose quantity is expressed as a volume of gas;

(c) in gigajoules per kilolitre, in the case of a fuel whose quantity is expressed as a volume of liquid;

(d) in gigajoules per metric ton collected, in the case of municipal solid waste;

(5) the nameplate generating capacity of each electricity generating unit, in megawatts;

(6) the annual electricity production, in megawatt-hours;

(7) for each cogeneration unit, the type of cycle, whether a topping or bottoming cycle, and the useful thermal output, as applicable, in megajoules;

(8) the annual CO2 emissions attributable to acid gas scrubbers for fluidized bed boilers, in metric tons;

(9) the annual fugitive emissions of each HFC from cooling units, in metric tons;

(10) the annual fugitive emissions of CO2 from geothermal facilities, in metric tons;

(11) the annual fugitive emissions of CH4 from coal storage calculated and reported in accordance with QC.5, in metric tons;

(12) the annual quantity of sorbent used in acid gas scrubbing equipment for fluidized bed boilers, in metric tons;

(13) the annual energy transferred from the steam or geothermal fluid in geothermal facilities, in gigajoules;

(14) where steam or heat is acquired from another facility or establishment for electricity generation, the name of the steam or heat supplier and the quantity supplied, in megajoules;

(15) where additional fuels are used to support electricity generation or industrial production, the annual consumption of fuel by fuel type;

(16) the number of times that the methods for estimating missing data provided for in QC.16.7 were used;

(17) the annual production of steam, in metric tons;

(18) (subparagraph revoked);

(19) the total energy consumed, in gigajoules, calculated using the following equation:

Where

QQC.16 (consumed) = the total quantity of energy consumed annually to generate steam, in gigajoules;

n = Number of fuels consumed;

k = Fuels;

Fuelk = Mass or volume of the fuel k combusted annually, expressed

— in bone dry metric tons, when the quantity is expressed as a mass;

— in thousands of cubic metres at standard conditions, when the quantity is expressed as a volume of gas;

— in kilolitres, when the quantity is expressed as a volume of liquid;

— in metric tons collected, in the case of municipal solid waste;

HHVk = High heat value determined in accordance with QC.1.3.1 or QC.1.3.2, for each type of fuel, expressed

— in gigajoules per bone dry metric ton, in the case of a fuel whose quantity is expressed as a mass;

— in gigajoules per thousand cubic metres, in the case of a fuel whose quantity is expressed as a volume of gas;

— in gigajoules per kilolitre, in the case of a fuel whose quantity is expressed as a volume of liquid.

Subparagraphs 3 and 4 of the first paragraph do not apply to the CO2 emissions of an emitter who calculates emissions using data from a continuous emission monitoring and recording system.

For the purposes of subparagraph 8 of the first paragraph of section 6.2:

(1) the emissions referred to in subparagraph 8 of the first paragraph are emissions attributable to fixed processes;

(2) the emissions referred to in subparagraph 1 of the first paragraph are emissions attributable to combustion, excluding CO2 emissions attributable to the combustion of biomass;

(3) the emissions referred to in subparagraphs 9, 10 and 11 of the first paragraph are other emissions.

QC.16.3. Calculation methods for CO2 emissions

The annual CO2 emissions attributable to stationary combustion units that produce electricity, acid gas scrubbers and geothermal facilities must be calculated in accordance with one of the calculation methods in QC.16.3.1 to QC.16.3.4.

For a facility or establishment with natural gas, diesel or heavy oil-powered units that are not individually equipped with a flowmeter or a dedicated tank and for which data cannot be obtained using a continuous emission monitoring and recording system, an emitter may quantify CO2 emissions using data from a measurement device common to all the units.

To determine the emissions attributable to each stationary combustion unit, the estimate must be based on total emissions, the hours of operation and the combustion efficiency of each unit. For diesel-powered units, the estimate may be based on the total quantity of energy produced, the energy produced by each unit, and the total quantity of diesel fuel consumed.

QC.16.3.1. Use of a continuous emission monitoring and recording system

The annual CO2 emissions attributable to stationary combustion units producing electricity may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.1.3.4.

QC.16.3.2. Calculation of CO2 emissions attributable to stationary combustion units producing electricity

The annual CO2 emissions attributable to stationary combustion units producing electricity may be calculated using the following calculation methods:

(1) for units that use natural gas as a fuel or a fuel specified in Table 1-2:

(a) when the high heat value of the gas is greater than or equal to 36.3 MJ/m3 and less than or equal to 40.98 MJ/m3 at standard conditions, in accordance with QC.1.3.3 or, for an emitter to whom section 6.6 of this Regulation does not apply, in accordance with QC.1.3.2;

(b) when the high heat value of the gas is less than 36.3 MJ/m3 or greater than 40.98 MJ/ m3 at standard conditions, in accordance with QC.1.3.3;

(c) for other fuels listed in Table 1-2, in accordance with QC.1.3.1, QC.1.3.2 or QC.1.3.3;

(2) for units that use coal or petroleum coke as a fuel, in accordance with QC.1.3.3(1);

(3) for units that use middle distillates as a fuel other than those specified in Table 1-2, such as diesel, fuel oil or kerosene, gasoline, residual oil or liquefied petroleum such as ethane, propane, isobutene or n-butane, in accordance with QC.1.3.3 or, for an emitter to whom section 6.6 of this Regulation does not apply, in accordance with QC.1.3.2;

(4) for units that use refinery fuel gas, flexigas or associated gas as a fuel, in accordance with QC.2;

(5) for units that use biogas or biomass as a fuel, the calculations must be completed in accordance with QC.1.3.3 or, for an emitter to whom section 6.6 of this Regulation does not apply, in accordance with QC.1.3.1 or QC.1.3.2;

(6) for units that use municipal solid waste as a fuel, in accordance with QC.1.3.3 or, for an emitter to whom section 6.6 of this Regulation does not apply, in accordance with QC.1.3.1 or QC.1.3.2;

(7) for units that use biogas or biomass as a fuel but that, during start-up, shut-down, or malfunction operating periods only use fossil fuels or fuel gas, the CO2 emissions attributable to those fuels must be calculated:

(a) for fossil fuels, in accordance with QC.1.3.1, QC.1.3.2 or QC.1.3.3;

(b) for fuel gas, in accordance with QC.2.

(8) for units that use only a mixture of fossil fuels, in accordance with QC.16.3.2(1) to (4), for each type of fuel;

(9) for units that use a mixture of fossil fuels and biogas or biomass:

(a) when the emissions are calculated using data from a continuous emission monitoring and recording system, the portion of CO2 emissions attributable to the biomass or biogas must be calculated in accordance with subparagraph 2 of the fifth paragraph of QC.1.3.4;

(b) when the emissions are not calculated using data from a continuous emission monitoring and recording system, in accordance with QC.16.3.2(1) to (7), for each type of fuel;

(10) for an emitter who determines the high heat value of fuels using measurements made in accordance with QC.1.5.4 or data indicated by the fuel supplier at the intervals specified in QC.1.5.1, in accordance with QC.1.3.2, QC.1.3.3 or QC.1.3.4.

QC.16.3.3. Calculation of CO2 emissions from acid gas scrubbing for fluidized bed boilers

The annual CO2 emissions from acid gas scrubbing for fluidized bed boilers must be calculated in accordance with QC.1.3.6.

QC.16.3.4. Calculation of fugitive CO2 emissions from geothermal facilities

The annual fugitive CO2 emissions from geothermal facilities must be calculated using equation 16-1:

Equation 16-1

CO2 = 7.14 × QE × 0.001

Where:

CO2 = Annual fugitive emissions of CO2 from geothermal facilities, in metric tons per year;

7.14 = Default fugitive CO2 emission factor for geothermal facilities, in kilograms per gigajoule;

QE = Quantity of energy transferred from geothermal steam or fluid, in gigajoulesper year;

0.001 = Conversion factor, kilograms to metric tons.

QC.16.4. Calculation methods for CH4 and N2O emissions

The annual CH4 and N2O emissions attributable to stationary combustion units producing electricity must be calculated in accordance with QC.1.4.

For a facility or establishment with natural gas, diesel or heavy oil-powered units that are not individually equipped with a flowmeter or a dedicated tank and for which data cannot be obtained using a continuous emission monitoring and recording system, an emitter may calculate CO2, CH4 and N2O emissions using data from a measurement device common to all the units.

To calculate the emissions attributable to each stationary combustion unit, the estimate must be based on total emissions, the hours of operation and the combustion efficiency of each unit. For diesel-powered units, the estimate may be based on the total quantity of energy produced, the energy produced by each unit, and the total quantity of diesel fuel consumed.

QC.16.5. Calculation methods for fugitive HFC emissions

The annual fugitive HFC emissions attributable to cooling units used in electricity production must be calculated in accordance with one of the calculation methods in QC.16.5.1 and QC.16.5.2.

QC.16.5.1. Calculation of fugitive HFC emissions based on change in inventory

The annual fugitive HFC emissions attributable to cooling units used in electricity production may be calculated based on the change in inventory using equation 16-2:

Equation 16-2

QC.16.5.2. Calculation of fugitives HFC emissions based on service logs

The annual fugitive HFC emissions attributable to cooling units used in electricity production may be calculated on the basis of entries in equipment service logs using equation 16-3:

Equation 16-3

Where:

HFC = Annual fugitive HFC emissions attributable to cooling units used in electricity production, in metric tons;

n = Number of new cooling units brought into operation during the year;

i = New cooling unit brought into operation;

Q NEWi = Quantity of HFC used to fill the new cooling unit brought into operation i, in kilograms;

NC NEWi = Nameplate capacity of the new cooling unit brought into operation i, in kilograms;

m = Number of maintenance operations, either to recharge or recover, completed during the year;

j = Cooling unit maintained;

Q RECHj = Quantity of HFC used to recharge the unit during maintenance of cooling unit i, in kilograms;

Q RECOj = Quantity of HFC recovered during maintenance of cooling unit i, in kilograms;

p = Number of cooling units retired during the year;

k = Cooling unit retired;

NC RETk = Nameplate capacity of cooling unit k, in kilograms;

Q RETk = Quantity of HFC recovered from unit k, in kilograms;

0.001 = Conversion factor, kilograms to metric tons.

QC.16.6. Sampling, analysis and measurement requirements

QC.16.6.1. Solid, liquid and gaseous fuels

For all fuels except refinery fuel gas, flexigas and associated gas, sampling, consumption measurements, carbon content measurements, and measurements to calculate high heat value and emission factors must be completed in accordance with QC.1.5 when the calculation method in QC.16.3.2 is used.

QC.16.6.2. Refinery fuel gas, flexigas and associated gas

For refinery fuel gas, flexigas and associated gas, sampling, consumption measurements, carbon content measurements, and measurements to calculate high heat value and emission factors must be completed in accordance with QC.2.4 when the calculation method in QC.16.3.2 is used.

QC.16.6.3. Acid gas scrubbing

The emitter who operates a fluid bed boiler equipped with a gas scrubber must measure the quantity of sorbent used annually.

QC.16.6.4. Geothermal facility

The emitter must measure the quantity of energy transferred annually from geothermal steam or fluid.

QC.16.7. Methods for estimating missing data

When, as part of an emitter’s sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.

When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:

(1) an emitter who uses one of the calculation methods provided for in this Protocol must,

(a) when the missing data concern sampled data,

i. determine the sampling or measurement rate using the following equation:

Equation 16-4

R = QS Act/QS Required

Where:

R = Actual sampling or measurement rate, expressed as a percentage;

QS Act = Quantity of actual samples or measurements obtained by the emitter;

QS Required = Quantity of samples or measurements required under QC.16.6;

ii. for data that require sampling or analysis,

— if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;

— if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;

— if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;

(b) when the missing data concern the quantity of energy transferred or a quantity of HFC, the replacement data must be estimated on the basis of all the data relating to the processes used;

(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.

QC.17. CONSUMPTION AND SALE OF ELECTRICITY PRODUCED OUTSIDE QUÉBEC, AND EXPORTATION OF ELECTRICITY

QC.17.1. Covered sources

The covered sources are the activities of persons and municipalities that operate an enterprise, a facility or en establishment that purchases electricity produced outside Québec, except electricity produced in the territory of a partner entity referred to in Appendix B.1 to the Regulation respecting a cap-and-trade system for greenhouse gas emission allowances (chapter Q-2, r. 46.1) or a province or territory of Canada, for their own consumption or for sale in Québec, or that exports electricity.

For the purposes of this Part, a facility is considered identifiable when it meets the following conditions:

(1) the importation of the reported electricity is subject to a written contract between the facility and the first importer;

(2) the imported and reported electricity, as the case may be,

(a) comes from an electricity production facility built after 1 January 2008;

(b) is the result of an increase in production of the facility that occurred after 1 January 2008;

(c) was imported from a facility within the framework of a contract entered into before 1 January 2008 that is still in force or has been renewed, or was imported from that facility after the end of the contract.

QC.17.2. Specific information to be reported concerning greenhouse gas emissions

In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:

(1) for the acquisition of electricity produced outside Québec for the consumption of the enterprise, facility or establishment or for sale within Québec:

(a) the total quantity of electricity produced outside Québec that was acquired during the year for consumption or sale in Québec, in megawatt-hours;

(b) the annual total greenhouse gas emissions attributable to the production of electricity referred to in subparagraph a, calculated in accordance with QC.17.3.1, in metric tons CO2 equivalent;

(c) for each identifiable facility covered by a greenhouse gas emissions report made to the U.S. Environmental Protection Agency (USEPA) under Part 75 of Title 40 of the Code of Federal Regulations, or to the organization The Climate Registry:

i. the name and address of the facility, the identification number assigned to it by the U.S. Environmental Protection Agency (USEPA) or the organization The Climate Registry;

ii. the total quantity of electricity acquired, in megawatt-hours;

iii. the transmission losses, in megawatt-hours;

iv. the facility’s net annual electricity production, in megawatt-hours;

v. the annual greenhouse gas emissions attributable to the production of the electricity acquired from the facility, in metric tons CO2 equivalent;

vi. the annual greenhouse gas emissions of the facility, in metric tons CO2 equivalent;

(d) for each identifiable facility not covered by a greenhouse gas emissions report made to one of the organizations referred to in subparagraph c:

i. the information specified in subparagraphs i to v of subparagraph c, the identification number being required only if assigned;

ii. each fuel type used for electricity production and its heat value, that is:

— in gigajoules per metric ton, when the quantity of fuel is expressed as a mass;

— in gigajoules per kilolitre, when the quantity of fuel is expressed as a volume of liquid;

— in gigajoules per cubic metre, when the quantity of fuel is expressed as a volume of gas;

(e) for each identifiable facility for which the information needed to calculate greenhouse gas emissions using equation 17-1 or 17-2 is not available, and for each unspecified facility:

i. the state from which the electricity is acquired;

ii. the total quantity of electricity acquired, in megawatt-hours, for each state;

iii. the annual greenhouse gas emissions attributable to the electricity acquired, in metric tons CO2 equivalent, by state;

(2) for the exportation of electricity:

(a) the total quantity of electricity exported annually by the enterprise, facility or establishment, in megawatt-hours;

(b) the annual total greenhouse gas emissions caused or avoided by the exportation of the electricity, calculated in accordance with QC.17.3.2, in metric tons CO2 equivalent;

(c) for each identifiable facility covered by a greenhouse gas emissions report in accordance with this Regulation, for each destination province or state:

i. the annual greenhouse gas emissions caused or avoided by the exportation of the electricity produced by the facility, in metric tons CO2 equivalent;

ii. the total quantity of electricity produced by the facility and exported annually, in megawatt-hours;

(d) for each identifiable facility not covered by a greenhouse gas emissions report in accordance with this Regulation, and for each unidentifiable facility, by destination province or state:

i. the annual CO2 emissions caused or avoided by the exportation of the electricity produced by the specified or unspecified facility, in metric tons;

ii. the annual greenhouse gas emissions caused or avoided by the exportation of the electricity produced by the facility, in metric tons CO2 equivalent;

QC.17.3. Calculation methods for greenhouse gas emissions

The annual greenhouse gas emissions attributable to the production of electricity acquired outside Québec and acquired by an enterprise, a facility or an establishment for its own consumption or for sale within Québec must be calculated in accordance with one of the calculation methods in QC.17.3.1. The annual greenhouse gas emissions caused or avoided by the exportation of the electricity must be calculated in accordance with one of the calculation methods in QC.17.3.2.

QC.17.3.1. Calculation of greenhouse gas emissions attributable to the production of electricity acquired outside Québec and sold or consumed within Québec

The annual greenhouse gas emissions attributable to electricity produced outside Québec and sold or consumed within Québec must be calculated by adding the greenhouse gas emissions attributable to electricity acquired outside Québec and produced by identifiable and unidentifiable facilities which emissions are calculated in accordance with the following methods:

(1) for an identifiable facility covered by a greenhouse gas emissions report made to the U.S. Environmental Protection Agency (USEPA) under Part 75 of Title 40 of the Code of Federal Regulations, or the organization The Climate Registry, using equation 17-1:

Equation 17-1

                  MWhimp
     GHG = GHGi × _____
                  MWhn                        

Where:

GHG = Annual greenhouse gas emissions attributable to the production of electricity acquired outside Québec and produced by the identifiable facility, in metric tons CO2 equivalent;

GHGi = Annual greenhouse gas emissions attributable to the identifiable facility, in metric tons CO2 equivalent;

MWhimp = Total quantity of electricity acquired from the identifiable facility and consumed or sold annually in Québec, including an estimate of transmission losses, from the facility’s busbar, in megawatt-hours;

MWhn = Net annual production of electricity at the identifiable facility, in megawatt-hours;

(2) for an identifiable facility not covered by a greenhouse gas emissions report made to one of the organizations referred to in paragraph 1, using equation 17-2:

Equation 17-2

Where:

GHG = Annual greenhouse gas emissions attributable to the production of electricity acquired outside Québec and produced by the identifiable facility, in metric tons CO2 equivalent;

n = Number of fuels used annually by the facility;

j = Type of fuel;

Qj = Quantity of fuel j, expressed

— in bone dry metric tons, when the quantity is expressed as a mass;

— in kilolitres, when the quantity is expressed as a volume of liquid;

— in thousands of cubic metres, when the quantity is expressed as a volume of gas;

HHVj = High heat value of fuel j consumed for electricity production, as specified in Table 1-1 or 1-2 in QC.1.7, expressed

— in gigajoules per bone dry metric ton, when the quantity is expressed as a mass;

— in gigajoules per kilolitre, when the quantity is expressed as a volume of liquid;

— in gigajoules per thousand cubic metres, when the quantity is expressed as a volume of gas;

EFj = Greenhouse gas emission factor for fuel j, calculated using equation 17-2.1, in metric tons CO2 equivalent per gigajoule;

MWhimp = Quantity of electricity acquired from the identifiable facility and consumed or sold annually in Québec, including an estimate of transmission losses, from the facility’s busbar, in megawatt-hours;

MWhn = Net annual production of electricity at the identifiable facility, in megawatt-hours;

Equation 17-2.1

EFj = [(EFCO2 × 1000) + (EFCH4 × 25) + (EFN2O × 298)] × 0.000001

Where:

EFj = Greenhouse gas emission factor for fuel j, in metric tons CO2 equivalent per gigajoule;

EFCO2 = CO2 emission factor for fuel j as specified in Table 1-2, 1-3, 1-4, 1-5 or 1-6 in QC.1.7, in kilograms of CO2 per gigajoule;

1000 = Conversion factor, kilograms to grams;

EFCH4 = CH4 emission factor for fuel j as specified in Table 1-2, 1-3, 1-4, 1-5 or 1-6 in QC.1.7, in grams of CH4 per gigajoule;

25 = Global warming potential of CH4;

EFN2O = N2O emission factor for fuel j as specified in Table 1-2, 1-3, 1-4, 1-5 or 1-6 in QC.1.7, in grams of N2O per gigajoule;

298 = Global warming potential of N2O;

0.000001 = Conversion factor, grams to metric tons;

(3) for an identifiable facility for which the information needed to calculate greenhouse gas emissions using equation 17-1 or 17-2 is not available, and for an unidentifiable facility, using equation 17-3:

Equation 17-3

GHG = MWhimp × EFD

Where:

GHG = Annual greenhouse gas emissions attributable to the production of electricity acquired outside Québec and produced by the identifiable or unidentifiable facility, in metric tons CO2 equivalent;

MWhimp = Quantity of electricity acquired from the identifiable or unidentifiable facility and consumed or sold annually in Québec, in megawatt-hours;

EFD = Greenhouse gas emission factor for the North American market from which the electricity comes, in metric tons of CO2 per megawatt-hour, which is either

— indicated in Table 17-1 in QC.17.4;

— when the electricity comes from an identifiable nuclear, hydroelectric, sea current, wind, solar or tidal power facility, a factor of 0;

— when the electricity comes from a non-identifiable facility, a factor of 0.999.

QC.17.3.2. Calculation of greenhouse gas emissions caused or avoided by the exportation of the electricity

The annual greenhouse gas emissions caused or avoided by the exportation of the electricity must be calculated by adding the greenhouse gas emissions attributable to the exportation of electricity produced by identifiable facilities to the greenhouse gas emissions attributable to the exportation of electricity produced by unidentifiable facilities, using one of the following methods:

(1) for an identifiable facility covered by a greenhouse gas emissions report in accordance with QC.16, using equation 17-4:

Equation 17-4

                  MWhexp
     GHG = GHGi × _____  − (MWhexp × EFD)
                  MWhn                        

Where:

GHG = Annual greenhouse gas emissions caused or avoided by the exportation of the electricity produced by the identifiable facility, in metric tons CO2 equivalent;

GHGt = Total annual greenhouse gas emissions attributable to the identifiable facility, in metric tons CO2 equivalent;

MWhexp = Total quantity of electricity produced by the identifiable facility and exported annually, including an estimate of transmission losses, from the facility’s busbar, in megawatt-hours;

MWhn = Net annual production of electricity at the identifiable facility, in megawatt-hours;

EFD = Greenhouse gas emission factor for the province or North American market where the electricity is delivered, as specified in Table 17-1 in QC.17.4, in metric tons CO2 equivalent per megawatt-hour;

(2) for an identifiable facility not covered by a greenhouse gas emissions report in accordance with QC.16 and for an unidentifiable facility, using equation 17-5:

Equation 17-5

GHG = MWhexp × (EFQC - EFD)

Where:

GHG = Annual greenhouse gas emissions caused or avoided by the exportation of the electricity produced by the identifiable or unidentifiable facility, in metric tons CO2 equivalent;

MWhexp = Quantity of electricity produced by the identifiable or unidentifiable facility and exported annually, in megawatt-hours;

EFQC = Greenhouse gas emission factor for Québec, as specified in Table 17-1 in QC.17.4, in metric tons CO2 equivalent per megawatt-hour;

EFD = Greenhouse gas emission factor for the province or North American market where the electricity is delivered, in metric tons CO2 equivalent per megawatt-hour, which is either

— indicated in Table 17-1 in QC.17.4;

— when the electricity comes from an identifiable nuclear, hydroelectric, sea current, wind, solar or tidal power facility, a factor of 0;

— when the electricity comes from a non-identifiable facility, a factor of 0.

QC.17.4. Table

Table 17-1. Default greenhouse gas emission factors for Canadian provinces and certain North American markets, in metric tons CO2 equivalent per megawatt-hour

Canadian provinces and North American markets	Default emission factor (metric ton GHG/MWh)
Newfoundland and Labrador	0.016
Nova Scotia	0.664
New Brunswick	0.292
Québec	0.001
Ontario	0.028
Manitoba	0.002
Vermont	0.005
New England Independent System Operator (NE-ISO), including all or part of the following states:	0.266
— Connecticut
— Massachusetts
— Maine
— Rhode Island
— Vermont
— New Hampshire
New York Independant System Operator (NY-ISO)	0.227
Pennsylvania Jersey Maryland Interconnection Regional Transmission Organization (PJM-RTO), including all or part of the following states:	0.439
— North Carolina
— Delaware
— Indiana
— Illinois
— Kentucky
— Maryland
— Michigan
— New Jersey
— Ohio
— Pennsylvania
— Tennessee
— Virginia
— West Virginia
— District of Columbia
Midwest Independent Transmission System Operator (MISO-RTO), including all or part of the following states:	0.484
— Arkansas
— North Dakota
— South Dakota
— Minnesota
— Iowa
— Missouri
— Wisconsin
— Illinois
— Michigan
— Indiana
— Montana
— Kentucky
— Texas
— Louisiana
— Mississippi
— Manitoba
Southwest Power Pool (SPP), including all or part of the following states:	0.478
— Kansas
— Oklahoma
— Nebraska
— New Mexico
— Texas
— Louisiana
— Missouri
— Arkansas
— Iowa
— Minnesota
— Montana
— North Dakota
— South Dakota
— Wyoming

QC.18. NICKEL AND COPPER PRODUCTION

QC.18.1. Covered sources

The covered sources are all the processes used for nickel and copper production in metal smelting and refining facilities.

More specifically, the processes covered are those used to remove impurities from nickel or copper ore concentrate by adding carbonate flux reagents and to extract metals from their oxides using reducing agents, and processes involving the use of materials for slag cleaning, the consumption of electrodes in electric arc furnaces, and the use of carbon-containing raw materials, such as recycled secondary materials.

QC.18.2. Greenhouse gas reporting requirements

In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:

(1) (subparagraph revoked);

(2) the annual CO2, CH4 and N2O emissions attributable to combustion, calculated and reported in accordance with QC.1, in metric tons;

(3) the annual CO2 emissions attributable to the use of carbonate flux reagents, in metric tons;

(4) the annual CO2 emissions attributable to the use of reducing agents and other materials for slag cleaning, in metric tons;

(5) the annual CO2 emissions attributable to the carbon contained in the nickel or copper ore processed, in metric tons;

(6) the annual CO2 emissions attributable to the consumption of carbon electrodes in electric arc furnaces, in metric tons;

(7) the annual CO2 emissions attributable to the carbon contained in carbon-containing raw materials such as recycled secondary materials, in metric tons;

(8) the annual consumption of each carbonate flux reagent, in metric tons;

(9) the average annual carbon content of each carbonate flux reagent, in metric tons of carbon per metric ton of carbonate flux reagent;

(10) the annual consumption of each reducing agent and each material used for slag cleaning, in metric tons;

(11) the average annual carbon content of each reducing agent and each material used for slag cleaning, in metric tons of carbon per metric ton of reducing agent;

(12) the annual consumption of carbon electrodes, in metric tons;

(13) the average annual carbon content of carbon electrodes, in metric tons of carbon per metric ton of carbon electrode;

(14) the annual quantity of nickel or copper ore processed, in metric tons;

(15) the average annual carbon content of the nickel or copper ore processed, in metric tons of carbon per metric ton of ore;

(16) the annual consumption of each other raw material that contributes 0.5% or more of the total carbon in the process, in metric tons;

(17) the average annual carbon content of the other raw materials that contribute 0.5% or more of the total carbon in the process, in metric tons of carbon per metric ton of feedstock;

(18) the number of times that the methods for estimating missing data in QC.18.5 were used;

(19) (subparagraph revoked);

(20) the quantity of nickel produced, in metric tons;

(21) the quantity of copper produced, in metric tons.

Subparagraphs 9, 11, 13, 15 and 17 of the first paragraph do not apply to the CO2 emissions of an emitter who calculates emissions using data from a continuous emission monitoring and recording system. When the emissions referred to in subparagraphs 3 to 7 of the first paragraph are measured by the same continuous emission monitoring and recording system, the emissions may be declared as a whole.

For the purposes of subparagraph 8 of the first paragraph of section 6.2:

(1) the emissions referred to in subparagraphs 3 to 7 of the first paragraph are emissions attributable to fixed processes;

(2) the emissions referred to in subparagraph 2 of the first paragraph are emissions attributable to combustion.

QC.18.3. Calculation methods for CO2 emissions

The annual CO2 emissions attributable to nickel and copper production must be calculated using one of the calculation methods in QC.18.3.1 and QC.18.3.2.

QC.18.3.1. Use of a continuous emission monitoring and recording system

The annual CO2 emissions attributable to nickel and copper production may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.1.3.4.

QC.18.3.2. Calculation by mass balance

The annual CO2 emissions attributable to nickel and copper production must be calculated using the methods in paragraphs 1 to 6, depending on the process used, expressed:

(1) for the processes used in nickel and copper production, using equation 18-1:

Equation 18-1

CO2 = CO2,CR + CO2,RA + CO2,ORE + CO2,CE + CO2,RM

Where:

CO2 = Annual CO2 emissions attributable to nickel and copper production, in metric tons;

CO2,CR = Annual CO2 emissions attributable to the use of carbonate flux reagents, calculated in accordance with equation 18-2, in metric tons;

CO2,RA = Annual CO2 emissions attributable to the use of reducing agents and materials used for slag cleaning, calculated in accordance with equation 18-3, in metric tons;

CO2,ORE = Annual CO2 emissions attributable to carbon contained in the nickel or copper ore processed, calculated in accordance with equation 18-4, in metric tons;

CO2,CE = Annual CO2 emissions attributable to the consumption of carbon electrodes in electric arc furnaces, calculated in accordance with equation 18-5, in metric tons;

CO2,RM = Annual CO2 emissions attributable to carbon contained in other raw materials that contribute 0.5% or more of the total carbon in the process, calculated in accordance with equation 18-6, in metric tons;

(2) for the use of carbonate flux reagents, using equation 18-2:

Equation 18-2

Where:

CO2, CR = Annual CO2 emissions attributable to the use of carbonate flux reagents, in metric tons;

LS = Annual consumption of limestone, in metric tons;

CLS = Average annual calcium carbonate content of the limestone, in metric tons of calcium carbonate per metric ton of limestone;

44/100 = Ratio of molecular weights, CO2 to calcium carbonate;

D = Annual consumption of dolomite, in metric tons;

CD = Average annual calcium carbonate and magnesium carbonate content, in metric tons of carbonates per metric ton of dolomite;

88/184 = Ratio of molecular weights, CO2 to calcium carbonate and magnesium carbonate;

(3) for the use of reducing agents and materials used for slag cleaning, using equation 18-3:

Equation 18-3

Where:

CO2, RA = Annual CO2 emissions attributable to the use of reducing agents and materials used for slag cleaning, in metric tons;

n = Number of reducing agents and materials used for slag cleaning;

i = Reducing agent and materials used for slag cleaning;

RA = Annual consumption of each reducing agent i and material used for slag cleaning, in metric tons;

CRA = Average annual carbon content of each reducing agent i, in metric tons of carbon per metric ton of reducing agent i;

3.664 = Ratio of molecular weights, CO2 to carbon;

(4) for the nickel or copper ore processed, using equation 18-4:

Equation 18-4

CO2,ORE = ORE × CORE × 3.664

Where:

CO2,ORE = Annual CO2 emissions attributable to carbon contained in the nickel or copper ore processed, in metric tons;

ORE = Annual consumption of nickel or copper ore, in metric tons;

CORE = Average annual carbon content of nickel or copper ore, in metric tons of carbon per metric ton of ore;

3.664 = Ratio of molecular weights, CO2 to carbon;

(5) for the consumption of carbon electrodes in electric arc furnaces, using equation 18-5:

Equation 18-5

CO2,CE = CE × CCE × 3.664

Where:

CO2,CE = Annual CO2 emissions attributable to consumption of carbon electrodes in electric arc furnaces, in metric tons;

CE = Annual consumption of carbon electrodes in electric arc furnaces, in metric tons;

CCE = Average annual carbon content of the carbon electrodes, in metric tons of carbon per metric ton of carbon electrodes;

3.664 = Ratio of molecular weights, CO2 to carbon;

(6) for the consumption of other carbon-containing raw materials, using equation 18-6:

Equation 18-6

Where:

CO2,RM = Annual CO2 emissions attributable to raw materials that contribute 0.5% or more of the total carbon in the process, in metric tons;

n = Number of raw materials that contribute 0.5% or more of the total carbon in the process;

i = Raw material;

RMi = Annual consumption of raw material i that contributes 0.5% or more of the total carbon in the process, in metric tons;

CRM,i = Average annual carbon content of raw material i, in metric tons of carbon per metric ton of raw material i;

3.664 = Ratio of molecular weights, CO2 to carbon.

QC.18.4. Sampling, analysis and measurement requirements

When the calculation method in QC.18.3.2 is used, an emitter who operates a facility or establishment producing nickel or copper must

(1) when a calculation method in QC.18.3 is used, determine annually the carbon or carbonate content of each material used, either by using data from the material supplier or by using the following methods:

(a) for coal and coke, the most recent version of ASTM D5373 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal and Coke”, or any other analysis method published by an organization listed in QC.1.5;

(b) for petroleum-based liquid fuels and liquid waste-derived fuels, the most recent version of ASTM D5291 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants”, the elementary analysis method or calculations specified in the most recent version of ASTM D3238 “Standard Test Method for Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by the n-d-M Method”, and the most recent version of either ASTM D2502 “Standard Test Method for Estimation of Molecular Weight (Relative Molecular Mass) of Petroleum Oils From Viscosity Measurements” or ASTM D2503 “Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure”, or any other analysis method published by an organization listed in QC.1.5;

(c) for gaseous fuels, the most recent version of ASTM D1945 “Standard Test Method for Analysis of Natural Gas by Gas Chromatography” or ASTM D1946 “Standard Practice for Analysis of Reformed Gas by Gas Chromatography”, or any other analysis method published by an organization listed in QC.1.5;

(d) for limestone and dolomite, the most recent version of ASTM C25 “Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime”, or any other analysis method published by an organization listed in QC.1.5;

(e) for other raw materials, any other analysis method published by an organization listed in QC.1.5;

(2) calculate the annual consumption of each carbon-containing material by weighing the materials using the same plant instruments as those used for inventory purposes, such as weigh hoppers or belt weight feeders, or using calculations based on data from the process control system.

QC.18.5. Methods for estimating missing data

When, as part of an emitter’s sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.

When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:

(1) an emitter who uses one of the calculation methods provided for in this Protocol must,

(a) when the missing data concern carbon content or carbonate content,

i. determine the sampling or measurement rate using the following equation:

Equation 18-7

R = QS Act/QS Required

Where:

R = Actual sampling or measurement rate, expressed as a percentage;

QS Act = Quantity of actual samples or measurements obtained by the emitter;

QS Required = Quantity of samples or measurements required under QC.18.4;

ii. for data that require sampling or analysis,

— if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;

— if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;

— if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;

(b) when the missing data concern raw material consumption, carbonate consumption, reducing agent consumption, carbon electrode consumption, recycled material consumption or copper production, the replacement data must be estimated on the basis of all the data relating to the processes used;

(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.

QC.19. FERROALLOY PRODUCTION

QC.19.1. Covered sources

The covered sources are all the processes that use pyrometallurgical techniques for ferrochromium, ferromanganese, ferromolybdenum, ferronickel, ferrosilicon, ferrotitanium, ferrotungsten, ferrovanadium, silicomanganese or silicon metal production.

QC.19.2. Greenhouse gas reporting requirements

In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:

(1) (subparagraph revoked);

(2) for each electric arc furnace:

(a) the annual CO2 emissions attributable to ferroalloy production, in metric tons;

(b) the annual CH4 emissions attributable to production of the ferroalloys listed in Table 19-1, in metric tons;

(c) the annual production of each ferroalloy, in metric tons;

(d) the annual consumption of each material that contributes 0.5% or more of the total carbon in the process, in metric tons;

(e) the average annual carbon content of each material or product that contributes 1% or more of the total carbon in the process, in metric tons of carbon per metric ton of material or product;

(f) the annual production of material other than alloys, in metric tons;

(3) the annual CO2, CH4 and N2O emissions attributable to the use of fixed combustion units, calculated and reported in accordance with QC.1, in metric tons;

(4) the annual CO2, CH4 and N2O emissions attributable to the use of biomass in electric arc furnaces, other than biomass used as reducing agent, calculated and reported in accordance with QC.1, in metric tons;

(5) the number of times that the methods for estimating missing data in QC.19.6 were used;

(6) (subparagraph revoked).

Subparagraph e of subparagraph 2 of the first paragraph does not apply to the CO2 emissions of an emitter who calculates emissions using data from a continuous emission monitoring and recording system.

For the purposes of subparagraph 8 of the first paragraph of section 6.2:

(1) the emissions referred to in subparagraph a of subparagraph 2 of the first paragraph are emissions attributable to fixed processes;

(2) the emissions referred to in subparagraph 3 and CH4 and N2O emissions referred to in subparagraph 4 of the first paragraph are emissions attributable to combustion;

(3) the emissions referred to in subparagraph b of subparagraph 2 of the first paragraph are other emissions.

QC.19.3. Calculation methods for CO2 emissions

The annual CO2 emissions attributable to processes that use pyrometallurgical techniques for ferroalloy production must be calculated using one of the calculation methods in QC.19.3.1 and QC.19.3.2.

QC.19.3.1. Calculation method using a continuous emission monitoring and recording system

The annual CO2 emissions attributable to processes that use pyrometallurgical techniques for ferroalloy production may be calculated using a continuous emission monitoring and recording system in accordance with QC.1.3.4.

QC.19.3.2. Calculation method for CO2 emissions by mass balance

The annual CO2 emissions attributable to ferroalloy production using an electric arc furnace must be calculated using equation 19-1; materials entering the electric arc furnace and products that contribute less than 1% of the total carbon in the pyrometallurgical process may be excluded.

Equation 19-1

Where:

CO2 = Annual CO2 emissions attributable to ferroalloy production using an electric arc furnace, in metric tons;

n = Number of electric arc furnaces;

i = Electric arc furnace;

RA = Annual consumption of reducing agents, in metric tons;

CRA = Average annual carbon content of reducing agents, in metric tons of carbon per metric ton of reducing agent;

CE = Annual consumption of carbon electrodes, in metric tons;

CCE = Average annual carbon content of carbon electrodes, in metric tons of carbon per metric ton of carbon electrodes;

ORE = Annual consumption of ore, in metric tons;

CORE = Average annual carbon content of ore, in metric tons of carbon per metric ton of ore;

FM = Annual consumption of flux material, in metric tons;

CFM = Average annual carbon content of flux material, in metric tons of carbon per metric ton of flux material;

FEA = Annual production of ferroalloys, in metric tons;

CFEA = Average annual carbon content ferroalloy products, in metric tons of carbon per metric ton of ferroalloy;

NAM = Annual production of non-alloy materials, in metric tons;

CNAM = Average annual carbon content of the non-alloy materials produced, in metric tons of carbon per metric ton of material;

3.664 = Ratio of molecular weights, CO2 to carbon.

QC.19.4. Calculation method for CH4 emissions

The annual CH4 emissions attributable to ferroalloy production listed in Table 19-1 must be calculated using equation 19-2:

Equation 19-2

Where:

CH4 = Annual CH4 emissions attributable to ferroalloy production listed in Table 19-1, in metric tons;

n = Number of electric arc furnaces;

i = Electric arc furnace;

m = Number of ferroalloys;

j = Type of ferroalloy;

FEAj = Annual production of ferroalloy j, in metric tons;

EFj = CH4 emission factor for ferroalloy j as specified in Table 19-1, in metric tons of CH4 per metric ton of ferroalloy j.

QC.19.5. Sampling, analysis and measurement requirements

When the calculation method in QC.19.3.2 is used, an emitter who operates a facility or establishment that uses a pyrometallurgical process for ferroalloy production must

(1) determine annually the carbon content of each material that contributes at least 1% of the total carbon in the process, based on either the data indicated by the supplier or the analysis of a minimum of 3 representative samples per year using any analysis method published by an organization listed in QC.1.5, or the following methods:

(a) for metal ores and ferroalloy products, the most recent version of ASTM E1941 “Standard Test Method for Determination of Carbon in Refractory and Reactive Metals and Their Alloys by Combustion Analysis”;

(b) for carbonaceous reducing agents and carbon electrodes, the most recent version of ASTM D5373 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal”;

(c) for flux materials, the most recent version of ASTM C25 “Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime”;

(2) calculate the annual consumption of each carbon-containing material entering the electric arc furnace by weighing the materials using the same plant instruments as those used for inventory purposes, such as weigh hoppers or belt weight feeders.

QC.19.6. Methods for estimating missing data

When, as part of an emitter’s sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.

When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:

(1) an emitter who uses one of the calculation methods provided for in this Protocol must,

(a) when the missing data concern carbon content or carbonate content,

i. determine the sampling or measurement rate using the following equation:

Equation 19-3

R = QS Act/QS Required

Where:

R = Actual sampling or measurement rate, expressed as a percentage;

QS Act = Quantity of actual samples or measurements obtained by the emitter;

QS Required = Quantity of samples or measurements required under QC.19.5;

ii. for data that require sampling or analysis,

— if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;

— if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;

— if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;

(b) when the missing data concern raw material consumption, carbonate consumption, reducing agent consumption, flux material consumption, carbon electrode consumption, ferroalloy production or by-product production, the replacement data must be estimated on the basis of all the data relating to the processes used;

(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.

QC.19.7. Table

Table 19-1. CH4 emission factors by electric arc furnace charging mode, in metric tons of CH4 per metric ton of ferroalloy product

(QC.19.4)

 _________________________________________________________________________________
|                    |                                                            |
| Ferroalloy         |        Electric arc furnace charging mode                  |
|                    |____________________________________________________________|
|                    |                |                |                          |
|                    | Batch-charging | Sprinkle-      |  Sprinkle-charging and   |
|                    |                | charginga      |  > 750 °Cb                |
|____________________|________________|________________|__________________________|
|                    |                |                |                          |
| Silicon metal      |     0.0015     |     0.0012     |          0.0007          |
|____________________|________________|________________|__________________________|
|                    |                |                |                          |
| Ferrosilicon 90%   |     0.0014     |     0.0011     |          0.0006          |
|____________________|________________|________________|__________________________|
|                    |                |                |                          |
| Ferrosilicon 75%   |     0.0013     |     0.0010     |          0.0005          |
|____________________|________________|________________|__________________________|
|                    |                |                |                          |
| Ferrosilicon 65%   |     0.0013     |     0.0010     |          0.0005          |
|____________________|________________|________________|__________________________|
|                                                                                 |
| a Sprinkle-charging is charging intermittently every minute.                    |
| b Temperature measured in off-gas channel downstream of the furnace hood.       |
|_________________________________________________________________________________|                        

QC.20. MAGNESIUM PRODUCTION

QC.20.1. Covered sources

The covered sources are all the processes used for magnesium production through smelting, electrolytic smelting, refining or remelting, or processes in which molten magnesium is used in alloying, casting, drawing, extruding, forming or rolling operations.

QC.20.2. Greenhouse gas reporting requirements

In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:

(1) the annual emissions of each greenhouse gas listed in Schedule A.1, attributable to their use as a cover gas or carrier gas in magnesium production, in metric tons;

(2) the annual CO2, CH4 and N2O emissions attributable to the use of fixed combustion units, calculated and reported in accordance with QC.1, in metric tons;

(3) the annual quantity of magnesium produced or processed, by process type, in metric tons;

(4) the number of times that the methods for estimating missing data provided for in QC.20.5 were used;

(5) an explanation of any change greater than 30% in the cover gas usage rate;

(6) a description of any new melt protection technologies adopted to account for a change in the greenhouse gas emissions attributable to their use as cover gas or carrier gas;

(7) (subparagraph revoked).

For the purposes of subparagraph 8 of the first paragraph of section 6.2:

(1) the emissions referred to in subparagraph 2 of the first paragraph are emissions attributable to combustion;

(2) the emissions referred to in subparagraph 1 of the first paragraph are other emissions.

QC.20.3. Calculation methods for annual greenhouse gas emissions attributable to use of cover gas and carrier gas

The annual greenhouse gas emissions attributable to the use of cover gas and carrier gas in magnesium production must be calculated using one of the calculation methods in QC.20.3.1 and QC.20.3.2.

QC.20.3.1. Calculation based on changes in inventory

The annual greenhouse gas emissions attributable to the use of cover gas and carrier gas in magnesium production may be calculated on the basis of inventory changes using equation 20-1:

Equation 20-1

GHGk = GInv-Begin − GInv-End + GPurchased − GDelivered

Where:

GHGk = Annual emissions of gas k used as a cover gas or carrier gas, in metric tons;

GInv-Begin = Quantity of gas k in inventory at the beginning of the year, in metric tons;

GInv-End = Quantity of gas k in inventory at the end of the year, in metric tons;

GPurchased = Quantity of gas k purchased during the year, in metric tons;

GDelivered = Quantity of gas k transferred off-site during the year, in metric tons;

k = Cover gas or carrier gas.

QC.20.3.2. Calculation based on the monitoring of changes in individual storage containers

The annual greenhouse gas emissions attributable to the use of cover gas and carrier gas in magnesium production may be calculated by monitoring changes in the mass of individual storage containers using equation 20-2:

Equation 20-2

Where:

GHGk = Annual emissions of gas k used as a cover gas or carrier gas, in metric tons;

n = Number of periods of use;

i = Period of use;

CBegin = Quantity of gas k in the container at the beginning of period of use n, in metric tons;

CEnd = Quantity of gas k in the container at the end of period of use n, in metric tons.

When the facility is equipped with flowmeters to track and record mass flow data, the mass of each gas must replace “(CBegin − CEnd)” for period of use n;

k = Cover gas or carrier gas.

QC.20.4. Sampling, analysis and measurement requirements

An emitter who operates a facility or establishment that uses cover gases or carrier gasses in magnesium production must

(1) calibrate, prior to the first emissions report and thereafter at the minimum frequency specified by the manufacturer, all flowmeters, load cells and scales used to measure quantities of cover gas or carrier gas;

(2) measure the mass flow of the cover gas or carrier gas into the gas distribution system. If flowmeters are used, the minimum accuracy must be of 1% of their full scale;

(3) determine annually the quantities of gas used using the following methods:

(a) for an emitter who calculates emissions under QC.20.3.1, by measuring all quantities of cover gas or carrier gas using scales or load cells with a minimum accuracy of 1% of their full scale, taking into account the mass of the empty container;

(b) for an emitter who calculates emissions using QC.20.3.2, by keeping a full record of the contents and mass of containers entering or leaving storage. The mass of containers returning to storage must be measured immediately before the containers are put back into storage. In addition, the emitter must measure all quantities of cover gas or carrier gas using scales or load cells with a minimum accuracy of 1% of their full scale, taking into account the mass of the empty container;

(4) ensure that the quantities of gas obtained from the supplier of the cover gas or carrier gas are determined in accordance with subparagraph b of paragraph 3.

QC.20.5. Methods for estimating missing data

When, as part of an emitter’s sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.

When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:

(1) each missing value concerning the calculation of emissions attributable to cover gas or carrier gas must be replaced by multiplying the magnesium production during the missing data period by the cover gas or carrier gas usage rate, calculated using equation 20-3. The data must be taken from the most recent period when operating conditions were similar to those for the missing data period;

Equation 20-3

      Ck
Rk = ____
      Mg                        

Where:

Rk = Usage rate of cover gas or carrier gas k during the period when operating conditions were similar to those for the missing data period, in metric tons of gas per metric ton of metallic magnesium;

Ck = Consumption of cover gas or carrier gas k during the period of comparable operation, in metric tons;

Mg = Quantity of magnesium produced or fed into the process during the period of comparable operation, in metric tons;

k = Cover gas or carrier gas;

(2) if the precise gas weights before and after use are not available, the emitter must assume that the container was emptied in the process and that the quantity of gas used is equal to the quantity of gas purchased;

(3) when the missing data concern magnesium production, the replacement data must be estimated on the basis of all the data relating to the processes used.

QC.21. NITRIC ACID PRODUCTION

QC.21.1. Covered sources

The covered sources are all nitric acid production units.

QC.21.2. Greenhouse gas reporting requirements

In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:

(1) the annual N2O emissions attributable to nitric acid production, in metric tons;

(2) the annual CO2, CH4 and N2O emissions attributable to the use of fixed combustion units, calculated and reported in accordance with QC.1, in metric tons;

(3) for each nitric acid production unit:

(a) annual nitric acid production, in metric tons, 100% acid basis;

(b) annual nitric acid production when the antipollution system is used, in metric tons, 100% acid basis;

(c) average N2O emission factor, in kilograms of N2O per metric ton of nitric acid produced, 100% acid basis;

(4) the number of times that the methods for estimating missing data in QC.21.5 were used;

(5) (subparagraph revoked).

Subparagraph c of subparagraph 3 of the first paragraph does not apply to the N2O emissions of an emitter who calculates emissions using data from a continuous emission monitoring and recording system.

For the purposes of subparagraph 8 of the first paragraph of section 6.2:

(1) the emissions referred to in subparagraph 2 of the first paragraph are emissions attributable to combustion;

(2) the emissions referred to in subparagraph 1 of the first paragraph are other emissions.

QC.21.3. Calculation methods for annual N2O emissions

The annual N2O emissions attributable to nitric acid production must be calculated using one of the calculation methods in QC.21.3.1 and QC.21.3.2.

QC.21.3.1. Calculation method using a continuous emission monitoring and recording system

The annual N2O emissions attributable to nitric acid production may be calculated using a continuous emission monitoring and recording system in accordance with QC.1.3.4.

QC.21.3.2. Calculation method using the N2O emission factor and production data

The annual N2O emissions attributable to nitric acid production must be calculated using equations 21-1 to 21-4:

Equation 21-1

Where:

N2O = Annual N2O emissions attributable to nitric acid production, in metric tons;

n = Number of nitric acid production units;

k = Nitric acid production unit;

N2Ok = Annual N2O emissions attributable to nitric acid production for production unit k, calculated in accordance with equation 21-2, in metric tons;

Equation 21-2

Where:

N2Ok = Annual N2O emissions attributable to nitric acid production for production unit k, in metric tons;

n = Total number of types of antipollution equipment used;

i = Type of antipollution equipment;

FD,k = Destruction factor for antipollution equipment i used in production unit k, in kilograms of N2O per kilogram of gas processed;

FU,k = Use factor for antipollution equipment i used in production unit k, calculated in accordance with equation 21-3;

EFk = Average N2O emission factor for production unit k, calculated in accordance with equation 21-4, in kilograms of N2O per ton of nitric acid, 100% acid basis;

Pk = Annual nitric acid production for production unit k, in tons of nitric acid produced, 100% acid basis;

0.001 = Conversion factor, kilograms to metric tons;

k = Nitric acid production unit;

Equation 21-3

       Pki,EA
FUki = ______
        Pk                        

Where:

FUki = Use factor for antipollution equipment i at production unit k;

Pki,EA = Annual nitric acid production at production unit k when antipollution equipment i is used, in metric tons, 100% acid basis;

Pk = Annual nitric acid production at production unit k, in metric tons, 100% acid basis;

i = Type of antipollution equipment;

k = Nitric acid production unit;

Equation 21-4

Where:

EFk = Average N2O emission factor for production unit k, in kilograms of N2O per metric ton of nitric acid, 100% acid basis;

n = Number of performance tests;

i = Performance test conducted in accordance with QC.21.4;

CN2O = N2O concentration in the gas stream during performance test i, in ppm;

Qfg = Volumetric flow of gas stream during performance test i, in cubic metres at standard conditions per hour;

1.826 × 10-6 = Conversion factor of ppm, kilograms per cubic metre at standard conditions;

PR = Nitric acid production rate during performance test i, in metric tons per hour, 100% acid basis;

k = Nitric acid production unit.

QC.21.4. Sampling, analysis and measurement requirements

When the method in QC.21.3.2 is used, an emitter who operates a facility or establishment that produces nitric acid must

(1) conduct a performance test under normal operating conditions and without using the antipollution system. The test must be conducted annually and when changes occur at the production unit, including when an antipollution system is installed. During the test, the emitter must

(a) determine the average N2O emission factor for each nitric acid production unit;

(b) determine the N2O concentration in accordance with one of the following methods:

i. Method 320 in Appendix A of Part 63 of Title 40 of the Code of Federal Regulations “Measurement of Vapor Phase Organic and Inorganic Emissions by Extractive Fourier Transform Infrared (FTIR) Spectroscopy”, published by the U.S. Environmental Protection Agency (USEPA);

ii. the most recent version of ASTM D6348 “Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy”, or any other analysis method published by an organization listed in QC.1.5;

(c) determine the production rate and N2O concentration in the gas stream for each production unit in accordance with one of the following methods:

i. using a measuring instrument such as a flowmeter or weigh scales;

ii. using the same plant instruments as those used for inventory purposes, such as weigh hoppers or belt weight feeders;

(d) keep a full record of each performance test conducted, including raw data, sampling results, the calculations used to determine the N2O emission factors and the information used to determine the nitric acid production rate;

(2) determine monthly nitric acid production for each production unit, both with and without the antipollution system, using one of the methods in subparagraph c of paragraph 1;

(3) determine the destruction factor using one of the following methods:

(a) by using the manufacturer’s specified destruction factor;

(b) by estimating the destruction factor based on all data from the processes used;

(c) by conducting an additional performance test on gas stream from the antipollution system.

QC.21.5. Methods for estimating missing data

When, as part of an emitter’s sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.

When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:

(1) an emitter who uses one of the calculation methods provided for in this Protocol must,

(a) when data determined on the basis of the performance test provided for in QC.21.4 is missing, conduct a new performance test;

(b) when the missing data concern temperature, gas pressure or gas concentration, other than data prescribed in the performance test,

i. determine the sampling or measurement rate using the following equation:

Equation 21-5

R = QS Act/QS Required

Where:

R = Actual sampling or measurement rate, expressed as a percentage;

QS Act = Quantity of actual samples or measurements obtained by the emitter;

QS Required = Quantity of samples or measurements required under QC.21.4;

ii. for data that require sampling or analysis,

— if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;

— if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;

— if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;

(c) when the missing data concern nitric acid production or a gas flow rate, the replacement data must be estimated on the basis of all the data relating to the processes used;

(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.

QC.22. PHOSPHORIC ACID PRODUCTION

QC.22.1. Covered sources

The covered sources are all wet-process processes used to produce phosphoric acid by reacting phosphate rock with acid.

QC.22.2. Greenhouse gas reporting requirements

In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:

(1) the annual CO2 emissions attributable to phosphoric acid production, in metric tons;

(2) the annual CO2, CH4 and N2O emissions attributable to the use of fixed combustion units, calculated and reported in accordance with QC.1, in metric tons;

(3) the annual quantity of phosphoric acid produced, in metric tons;

(4) the annual average inorganic carbon content of the phosphate rock, in metric tons of carbon per metric ton of phosphate rock;

(5) the annual consumption of phosphate rock, in metric tons;

(6) the number of times that the methods for estimating missing data in QC.22.5 were used;

(7) (subparagraph revoked).

Subparagraph 4 of the first paragraph does not apply to the CO2 emissions of an emitter who calculates emissions using data from a continuous emission monitoring and recording system.

For the purposes of subparagraph 8 of the first paragraph of section 6.2:

(1) the emissions referred to in subparagraph 1 of the first paragraph are emissions attributable to fixed processes;

(2) the emissions referred to in subparagraph 2 of the first paragraph are emissions attributable to combustion.

QC.22.3. Calculation methods for annual CO2 emissions

For each process, the annual CO2 emissions attributable to phosphoric acid production must be calculated using one of the calculation methods in QC.22.3.1 and QC.22.3.2.

QC.22.3.1. Use of a continuous emission monitoring and recording system

The annual CO2 emissions may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.1.3.4.

QC.22.3.2. Calculation of annual CO2 emissions attributable to phosphoric acid production

The annual CO2 emissions attributable to phosphoric acid production may be calculated using equation 22-1:

Equation 22-1

Where:

CO2 = Annual CO2 emissions attributable to phosphoric acid production, in metric tons;

i = Month;

PRi = Consumption of phosphate rock for month i, in metric tons;

Ci = Monthly carbon content of phosphate rock for month i, in metric tons of carbon per metric ton of phosphate rock;

3.664 = Ratio of molecular weights, CO2 to carbon.

QC.22.4. Sampling, analysis and measurement requirements

When the calculation method in QC.22.3.2 is used, an emitter who operates a facility or establishment that produces phosphoric acid must

(1) take a monthly sample of each type of phosphate rock when the rock comes from different sources, or produce a composite sample by combining representative samples;

(2) determine the inorganic carbon content of each phosphate rock sample taken monthly from the feed system in accordance with the method in “Analytical Methods Manual in 2010 (10th edition), version 1.92” published by the Association of Fertilizer and Phosphate Chemists or any other analysis method published by an organization listed in QC.1.5;

(3) determine the monthly consumption of phosphate rock using the same plant instruments as those used for inventory purposes, such as weigh hoppers or belt weight feeders.

QC.22.5. Methods for estimating missing data

When, as part of an emitter’s sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.

When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:

(1) an emitter who uses one of the calculation methods provided for in this Protocol must,

(a) when the missing data concern carbon content,

i. determine the sampling or measurement rate using the following equation:

Equation 22-2

R = QS Act/QS Required

Where:

R = Actual sampling or measurement rate, expressed as a percentage;

QS Act = Quantity of actual samples or measurements obtained by the emitter;

QS Required = Quantity of samples or measurements required under QC.22.4;

ii. for data that require sampling or analysis,

— if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;

— if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;

— if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;

(b) when the missing data concern phosphate rock consumption or phosphoric acid production, the replacement data must be estimated on the basis of all the data relating to the processes used;

(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.

QC.23. AMMONIA PRODUCTION

QC.23.1. Covered sources

The covered sources are all the ammonia manufacturing processes in which ammonia is manufactured via steam reforming of fossil-based feedstocks or the gasification of solid and liquid raw material.

QC.23.2. Greenhouse gas reporting requirements

In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:

(1) the annual CO2 emissions attributable to ammonia production via steam reforming or gasification processes, in metric tons;

(2) the annual CO2, CH4 and N2O emissions attributable to the use of fixed combustion units, calculated and reported in accordance with QC.1, in metric tons;

(3) the annual consumption of each raw material used in ammonia production, expressed

(a) in bone dry metric tons, when the quantity is expressed as a mass;

(b) in thousands of cubic metres at standard conditions, when the quantity is expressed as a volume of gas;

(c) in kilolitres, when the quantity is expressed as a volume of liquid;

(4) the average annual carbon content of each raw material used in ammonia production, namely,

(a) in kilograms of carbon per kilogram of raw material in the case of gases and solids;

(b) in kilograms of carbon per kilolitre of raw material in the case of liquids;

(5) the annual CO2 emissions attributable to the combustion of gas from the waste recycle stream, in metric tons;

(6) the annual consumption of gaseous fuels from the waste recycle stream, in cubic metres at standard conditions;

(7) the average annual carbon content of gas from the waste recycle stream, in kilograms of carbon per kilogram of gas;

(8) the annual production of ammoniac, in metric tons;

(9) if CO2 from ammonia production is used to produce urea, the annual production of urea, in metric tons;

(10) the number of times that the methods for estimating missing data provided for in QC.23.5 were used;

(11) (subparagraph revoked).

Subparagraphs 4 and 7 of the first paragraph do not apply to the CO2 emissions of an emitter who calculates emissions using data from a continuous emission monitoring and recording system.

For the purposes of subparagraph 8 of the first paragraph of section 6.2:

(1) the emissions referred to in subparagraph 1 of the first paragraph are emissions attributable to fixed processes;

(2) the emissions referred to in subparagraphs 2 and 5 of the first paragraph, excluding emissions attributable to the combustion or use of biomass or biomass fuels, are emissions attributable to combustion.

QC.23.3. Calculation methods for annual CO2 emissions

For each process used, the annual CO2 emissions attributable to ammonia production must be calculated using one of the calculation methods in QC.23.3.1 and QC.23.3.2 and the annual CO2 emissions attributable to the combustion of gas from the waste recycle stream must be calculated in accordance with QC.23.3.3.

QC.23.3.1. Use of a continuous emission monitoring and recording system

The annual CO2 emissions may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.1.3.4.

QC.23.3.2. Calculation of annual CO2 emissions attributable to ammonia production

The annual CO2 emissions attributable to ammonia production must be calculated using equations 23-1 to 23-4:

Equation 23-1

Where:

CO2 = Annual CO2 emissions attributable to ammonia production, in metric tons;

n = Total number of ammonia production units;

k = Ammonia production unit;

CO2,G = Annual CO2 emissions attributable to ammonia production for production unit k from feedstock the quantity of which is expressed as a volume of gas, calculated in accordance with equation 23-2, in metric tons;

CO2,L = Annual CO2 emissions attributable to ammonia production for production unit k from feedstock the quantity of which is expressed as a volume of liquid, calculated in accordance with equation 23-3, in metric tons;

CO2,S = Annual CO2 emissions attributable to ammonia production for production unit k from feedstock the volume of which is expressed as a mass, calculated in accordance with equation 23-4, in metric tons;

Equation 23-2

Where:

CO2,G = Annual CO2 emissions attributable to ammonia production for production unit k from feedstock the quantity of which is expressed as a volume of gas, in metric tons;

i = Month;

Fdstki = Consumption of feedstock the quantity of which is expressed as a volume of gas for month i, in thousands of cubic metres at standard conditions, or, when a mass flowmeter is used, in metric tons;

Ci = Carbon content of feedstock the quantity of which is expressed as a volume of gas consumed in month i, in kilograms of carbon per kilogram of feedstock;

MW = Molecular weight of feedstock the quantity of which is expressed as a volume of gas, in kilograms per kilomole or, when a mass flowmeter is used, replace

 _  _
|    |
| MW |
|----| by 1;
|MVC |
|_  _|                        

MVC = Molar volume conversion factor (24.06 m3 per kilomole at standard conditions);

3.664 = Ratio of molecular weights, CO2 to carbon;

1 = Conversion factor, kilograms to metric tons and thousands of cubic metres to cubic metres;

Equation 23-3

Where:

CO2,L = Annual CO2 emissions attributable to ammonia production for production unit k from feedstock the quantity of which is expressed as a volume of liquid, in metric tons;

i = Month;

Fdstki = Consumption of feedstock the quantity of which is expressed as a volume of liquid for month i, in kilolitres;

Ci = Carbon content of the feedstock the quantity of which is expressed as a volume of liquid consumed in month i, in metric tons of carbon per kilolitre of feedstock;

3.664 = Ratio of molecular weights, CO2 to carbon;

Equation 23-4

Where:

CO2,S = Annual CO2 emissions attributable to ammonia production at production unit k from feedstock the quantity of which is expressed as a mass, in metric tons;

i = Month;

Fdstki = Consumption of feedstock the quantity of which is expressed as a mass for month i, in metric tons;

Ci = Carbon content of the feedstock the quantity of which is expressed as a mass consumed in month i, in kilograms of carbon per kilogram of feedstock;

3.664 = Ratio of molecular weights, CO2 to carbon.

QC.23.3.3. Calculation of annual CO2 emissions attributable to the combustion of gas from the waste recycle stream

The annual CO2 emissions attributable to the combustion of gas from the waste recycle stream of each ammonia production unit must be calculated using equation 23-5:

Equation 23-5

Where:

CO2,WR = Annual CO2 emissions attributable to the combustion of gas from the waste recycle stream of each production unit, in metric tons;

i = Month;

WRGi = Quantity of gas from the waste recycle stream for month i, in thousands of cubic metres at standard conditions or, when a mass flowmeter is used, in metric tons;

Ci = Carbon content of gas from the waste recycle stream for month i, in kilograms of carbon per kilogram of gas;

MW = Molecular weight of gas from the waste recycle stream, in kilograms per kilomole or, when a mass flowmeter is used, replace

 _  _
|    |
| MW |
|----| by 1;
|MVC |
|_  _|                        

MVC = Molar volume conversion factor (24.06 m3 per kilomole at standard conditions);

3.664 = Ratio of molecular weights, CO2 to carbon;

1 = Conversion factor, kilograms to metric tons and thousands of cubic metres to cubic metres.

QC.23.4. Sampling, analysis and measurement requirements

An emitter who operates a facility or establishment that produces ammoniac must

(1) determine the consumption of feedstocks using the following methods:

(a) using flowmeters for liquid and gaseous feedstocks and for gas from the waste recycle stream;

(b) using the same plant instruments as those used for inventory purposes for solid feedstocks and the ammonia and urea produced;

(2) when the calculation method in QC.23.3.2 is used, determine monthly the carbon content and the average molecular weight of each feedstock consumed and of gas from the waste recycle stream, either by using data from the material supplier or by using one of the following methods:

(a) the most recent version of ASTM D1945 “Standard Test Method for Analysis of Natural Gas by Gas Chromatography”;

(b) the most recent version of ASTM D1946 “Standard Practice for Analysis of Reformed Gas by Gas Chromatography”;

(c) the most recent version of ASTM D2502 “Standard Test Method for Estimation of Molecular Weight (Relative Molecular Mass) of Petroleum Oils From Viscosity Measurements”;

(d) the most recent version of ASTM D2503 “Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure”;

(e) the most recent version of ASTM D3238 “Standard Test Method for Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by the n-d-M Method”;

(f) the most recent version of ASTM D5291 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants”;

(g) the most recent version of ASTM D3176 “Standard Practice for Ultimate Analysis of Coal and Coke”;

(h) the most recent version of ASTM D5373 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal”;

(i) any other analysis method published by an organization listed in QC.1.5;

(3) calibrate all flowmeters used for liquid or gaseous fuels, except those used for gas billing, and measure tank levels in accordance with the methods in QC.1.5.

QC.23.5. Methods for estimating missing data

When, as part of an emitter’s sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.

When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:

(1) an emitter who uses one of the calculation methods provided for in this Protocol must,

(a) when the missing data concern carbon content or molecular mass,

i. determine the sampling or measurement rate using the following equation:

Equation 23-6

R = QS Act/QS Required

Where:

R = Actual sampling or measurement rate, expressed as a percentage;

QS Act = Quantity of actual samples or measurements obtained by the emitter;

QS Required = Quantity of samples or measurements required under QC.23.4;

ii. for data that require sampling or analysis,

— if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;

— if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;

— if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;

(b) when the missing data concern raw material quantity, ammoniac production or waste gas consumption, the replacement data must be estimated on the basis of all the data relating to the processes used;

(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.

QC.24. ELECTRICITY TRANSMISSION AND DISTRIBUTION AND USE OF EQUIPMENT TO PRODUCE ELECTRICITY

QC.24.1. Covered sources

The covered sources are all equipment not covered by the calculation methods provided for in QC.16 used for the transmission and distribution of electricity and those used for producing electricity, in particular, transmission and distribution systems, substations, high-voltage circuit breakers and switches, that use sulphur hexafluoride (SF6) and perfluorocarbons (PFCs).

Fugitive emissions attributable to equipment at an enterprise are also covered.

QC.24.2. Greenhouse gas reporting requirements

In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:

(1) annual fugitive SF6 emissions attributable to electrical equipment, in metric tons;

(2) annual fugitive emissions of each PFC attributable to electrical equipment, in metric tons;

(3) the number of times that the methods for estimating missing data in QC.24.5 were used;

(4) (subparagraph revoked).

For the purposes of subparagraph 8 of the first paragraph of section 6.2, the emissions referred to in subparagraphs 1 and 2 of the first paragraph are other emissions.

QC.24.3. Calculation methods for fugitive SF6 and PFC emissions

Fugitive SF6 and PFC emissions must be calculated in accordance with the calculation methods in QC.24.3.1 to QC.24.3.3.

QC.24.3.1. Calculation of fugitive emissions by mass balance

Fugitive SF6 and PFC emissions must be calculated using a mass-balance method that systematically accounts for all use of SF6 and PFC by the emitter. For the purposes of the calculation, all quantities of SF6 and PFC that cannot be accounted for are assumed to have been emitted.

Annual fugitive emissions must be calculated using equations 24-1 to 24-5:

Equation 24-1

Equation 24-2

Equation 24-3

SACQ = SCvl + SEquip + SReturned

Where:

SACQ = Quantity of gas j acquired during the year, contained in electrical equipment or storage containers, in kilograms;

SCvl = Quantity of gas j acquired, contained in containers, in kilograms;

SEquip = Quantity of gas j acquired, contained in electrical equipment, in kilograms;

SReturned = Quantity of gas j returned to the enterprise after off-site recycling, in kilograms;

j = Type of gas;

Equation 24-4

SSOLD = SSales + SReturns + SDestruct + SRecyc

Where:

SSOLD = Quantity of gas j sold or transferred to other facilities or establishments during the year, in storage containers or electrical equipment, in kilograms;

SSales = Quantity of gas j sold to other facilities or establishments, including gas left in electrical equipment that is sold, in kilograms;

SReturns = Quantity of gas j returned to suppliers, in kilograms;

SDestruct = Quantity of gas j sent to destruction facilities, in kilograms;

SRecyc = Quantity of gas j sent off-site for recycling, in kilograms;

j = Type of gas;

Equation 24-5

QC.24.3.2. Calculation of fugitive emissions by direct measurement

Fugitive SF6 and PFC emissions must be calculated by directly measuring the mass of gas added to electrical equipment during operation and the quantity of gas collected from decommissioned equipment, using equations 24-6 to 24-8:

Equation 24-6

GHGj = (SO + SD)j × 0.001

Where:

GHGj = Annual emissions of gas j attributable to the operation and decommissioning of electrical equipment, in metric tons;

SO = Annual emissions of gas j during operation phase, calculated in accordance with equation 24-7, in kilograms;

SD = Annual emissions of gas j during decommissioning phase, calculated in accordance with equation 24-8, in kilograms;

0.001 = Conversion factor, kilograms to metric tons;

j = Type of gas;

Equation 24-7

Where:

SO = Annual fugitive emissions of gas j during operation phase, in kilograms;

n = Number of additions of gas j during the year;

i = Addition;

Si = Quantity of gas j added to electrical equipment during addition i, in kilograms;

j = Type of gas;

Equation 24-8

Where:

SD = Annual emissions of gas j during decommissioning phase of electrical equipment, in kilograms;

n = Number of units of electrical equipment decommissioned during the year;

i = Electrical equipment decommissioned;

NC = Nameplate capacity of decommissioned electrical equipment i, in kilograms;

SC = Quantity of gas j collected from decommissioned electrical equipment i, in kilograms;

j = Type of gas.

QC.24.3.3. Calculation of fugitive emissions by mass balance and by direct measurement

Fugitive SF6 and PFC emissions may be calculated using a mixed method by applying the mass balance method to operations and the direct measurement method to decommissioned equipment.

For the purposes of the calculation, all quantities of SF6 and PFC that cannot be accounted for are assumed to have been emitted.

The fugitive emissions must be calculated using equations 24-9 to 24-13:

Equation 24-9

GHGj = (SO - SREC + SDC) × 0.001

Where:

GHGj = Annual emissions of gas j attributable to operations and to the decommissioning of electrical equipment, in metric tons;

SO = Annual emissions of gas j from electrical equipment during the operating phase, calculated using equation 24-10, in kilograms;

SREC = Annual quantity of gas j recovered from electrical equipment during the operating phase, calculated using equation 24-13, in kilograms;

SDC = Annual emissions of gas j from decommissioned electrical equipment, calculated using equation 24-8, in kilograms;

0.001 = Conversion factor, kilograms to metric tons;

j = Type of gas;

Equation 24-10

SO = (SEmpty) × (1 - fj,i)

Where:

SO = Annual emissions of gas j during operating phase of electrical equipment, in kilograms;

SEmpty = Annual quantity of gas j contained in containers used for operations, expressed as the quantity initially contained in containers returned empty to the supplier, in kilograms;

fj,i = Fraction of gas j remaining in containers of type i returned empty to the supplier, calculated using equation 24-11 when the gas from the container is transferred to electrical equipment without a recovery system or using equation 24-12 when a recovery system is used transfer the gas from the container to the electrical equipment;

i = Type of container;

j = Type of gas;

Equation 24-11

Where:

fj,i = Average fraction of gas j remaining in containers of type i returned empty to the supplier;

Mres,j = Average residual mass of gas j in empty containers, determined in accordance with equation 24-12.1 or measured or weighed in accordance with QC.24.4.4, in kilograms;

Minitial,j = Initial mass of gas j, based on the average weight of gas indicated by the supplier, in kilograms;

i = Type of container;

j = Type of gas;

Equation 24-12

Where:

fj,i = Average fraction of gas j remaining in containers of type i returned empty to the supplier;

Pdischarge,j = Average discharge pressure of gas j in empty containers i, in kilopascals;

Pcharge,j = Average charging pressure of gas j in container i, in kilopascals;

i = Type of container;

j = Type of gas;

Equation 24-12.1

Where:

Mres,j = Residual mass of gas j, in grams;

Mj = Molar mass of gas j, in grams per mole;

Pj = Absolute pressure of gas j, in pascals;

Vj = Volume of gas j, in cubic metres;

Zj = Compressibility factor of gas j, calculated using equation 24-12.2;

R = Perfect gas constant of 8.314 joules per kelvin-mole;

Tj = Absolute temperature of gas j, in kelvins;

Equation 24-12.2

Equation 24-12.3

Where:

Prj = Reduced pressure of gas j, in pascals;

Pj = Absolute pressure of gas j, in pascals;

Pcj = Critical pressure of gas j, in pascals;

Equation 24-12.4

Trj = Reduced temperature of gas j, in kelvins;

Tj = Absolute temperature of gas j, in kelvins;

Tcj = Critical temperature of gas j, in kelvins;

Equation 24-12.5

Where:

Bj(0) = First parameter of the virial coefficient of gas j;

Trj = Reduced temperature of gas j, calculated using equation 24-12.4, in kelvins;

Equation 24-12.6

Where:

Bj(1) = Second parameter of the virial coefficient of gas j;

Trj = Reduced temperature of gas j, calculated using equation 24-12.4, in kelvins;

SREC = SDestruct + SRecyc

Where:

SREC = Annual quantity of gas j recovered from electrical equipment during the operating phase, in kilograms;

SDestruct = Quantity of gas j sent to destruction facilities, in kilograms;

SRecyc = Quantity of gas j sent to off-site recycling facilities, in kilograms;

j = Type of gas.

QC.24.4. Sampling, analysis and measurement requirements

When using the calculation methods in QC.24.3.2 and QC.24.3.3, an emitter who operates an electricity transmission or distribution enterprise or uses electrical equipment must

(1) measure additions of SF6 or PCFs during the operation phase using a measuring instrument such as a flowmeter or weigh scale. If a weigh scale is used, the SF6 or PFC container must be weighed before and after its contents are added to the electrical equipment, with the difference being equal to the quantity of SF6 or PFC added to the equipment;

(2) calibrate the instruments used to measure the mass of SF6 or PFC used to re-charge electrical equipment, using one of the following methods:

(a) by following the instructions of the manufacturer for the use of a flowmeter;

(b) every 6 months, by weighing objects of pre-determined mass and zeroing the weigh scale accordingly.

QC.24.5. Methods for estimating missing data

When, as part of an emitter’s sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.

When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:

(1) when the missing data concern sampled data,

(a) determine the sampling or measurement rate using the following equation:

Equation 24-14

R = QS Act/QS Required

Where:

R = Actual sampling or measurement rate, expressed as a percentage;

QS Act = Quantity of actual samples or measurements obtained by the emitter;

QS Required = Quantity of samples or measurements required under QC.24.4;

(b) for data that require sampling or analysis,

i. if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;

ii. if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;

iii. if R < 0,75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;

(2) when the missing data concern gas quantity, the replacement data must be estimated on the basis of all the data relating to the processes used;

(3) when the missing data concern equipment capacity, the replacement data must be estimated on the basis of an equivalent nominal SF6 and PFC gas capacity, and on repair, replacement and maintenance data for similar pieces of equipment.

QC.25. CARBONATES USE

QC.25.1. Covered sources

The covered sources are all process equipment that uses carbonates such as limestone, dolomite, ankerite, magnesite, siderite, rhodochrosite, sodium carbonate or strontium carbonate.

All equipment that uses carbonates or carbonate-containing raw materials that are consumed in the production of cement, ferroalloys, glass, iron and steel, lead, lime, phosphoric acid, sodium carbonate or zinc and for which special calculation methods are provided for in this Schedule is excluded.

Carbonates contained in the sorbents used in acid gas scrubbing equipment for fluidized bed boilers are also excluded, the emissions from which must be quantified and reported in accordance with QC.1.3.6.

QC.25.2. Greenhouse gas reporting requirements

In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:

(1) the annual CO2 emissions attributable to the use of carbonates or carbonate-based raw materials, in metric tons;

(2) the annual consumption of each carbonate or carbonate-based raw material, in metric tons;

(3) when the calculation method in QC25.3.2 is used,

(a) the average annual calcination fraction for carbonates, in tons of carbonate obtained per metric ton of carbonates in the carbonate-based raw material;

(b) the average annual carbonate content of each carbonate-based raw material, in metric tons of carbonates per metric ton of carbonate-based raw material;

(4) when the calculation method in QC.25.3.3 is used:

(a) the annual quantity of carbonate-based material output, in metric tons;

(b) the average annual carbonate content of each material input and output, in metric tons of carbonate per metric ton of material;

(5) the number of times that the methods for estimating missing data in QC.25.5 were used;

(6) (subparagraph revoked).

Subparagraph 3 and subparagraph b of subparagraph 4 of the first paragraph do not apply to the CO2 emissions of an emitter who calculates emissions using data from a continuous emission monitoring and recording system.

For the purposes of subparagraph 8 of the first paragraph of section 6.2, the emissions referred to in subparagraph 1 of the first paragraph are emissions attributable to fixed processes.

QC.25.3. Calculation methods for annual CO2 emissions

For each process, the annual CO2 emissions attributable to the use of carbonate-based raw materials must be calculated using one of the calculation methods in QC.25.3.1 to QC.25.3.3.

QC.25.3.1. Use of a continuous emission monitoring and recording system

The annual CO2 emissions may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.1.3.4.

QC.25.3.2. Calculation method for CO2 emissions using the calcination fraction

The annual CO2 emissions attributable to the use of carbonates or carbonate-based raw materials may be calculated using the calcination fraction, using equation 25-1:

Equation 25-1

Where:

CO2 = Annual CO2 emissions attributable to the use of carbonate-based raw materials, in metric tons;

n = Number of carbonates contained in the raw materials;

i = Carbonate;

m = Number of carbonate-based raw materials used;

j = Raw material;

RMj,i = Annual consumption of raw material j containing carbonate i, in metric tons;

CCj,i = Average annual content of carbonate i in raw material j, in metric tons of carbonate per metric ton of raw material;

EFi = Emission factor for carbonate i as specified in Table 25-1 in QC.25.6, in metric tons of CO2 per metric ton of carbonate;

Fi = Calcination fraction for carbonate i, in metric tons of carbonate obtained per metric ton of carbonate in the raw material, a value of 1.0 corresponding to complete calcination.

QC.25.3.3. Calculation method for CO2 emissions by mass balance

The annual CO2 emissions attributable to the use of carbonates or carbonate-based raw materials may be calculated by mass balance, using equation 25-2:

Equation 25-2

Where:

CO2 = Annual CO2 emissions attributable to the use of carbonates or carbonate-based raw materials, in metric tons;

n = Number of carbonates contained in raw materials;

i = Carbonate;

m = Number of carbonate-based raw materials;

j = Raw material;

RMj,i = Annual consumption of carbonate or raw material j containing carbonate i, in metric tons;

CCj,i = Average annual content of carbonate i in raw material j, in metric tons of carbonate per metric ton of raw material;

EFi = Emission factor for carbonate i as specified in Table 25-1 in QC.25.6, in metric tons of CO2 per metric ton of carbonate;

p = Number of carbonate-containing output materials;

k = Carbonate-containing output material;

OMk,i = Annual quantity of output material k containing carbonate i, in metric tons;

CCOMk,i = Average annual content of carbonate i in output material k, in metric tons of carbonate per metric ton of material.

QC.25.4. Sampling, analysis and measurement requirements

An emitter who operates a facility or establishment that uses carbonate-based raw materials must

(1) when the calculation method in QC.25.3.2 is used, determine annually the calcination fraction for each carbonate used by sampling and chemical analysis, using an analysis method published by an organization listed in QC.1.5, or the value of 1.0;

(2) when the calculation method in QC.25.3.2 or QC.25.3.3 is used, determine the average annual carbonate content by calculating the arithmetic average of the monthly data obtained from raw material suppliers by sampling and chemical analysis using one of the following methods:

(a) the most recent version of ASTM C25 “Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime”;

(b) the most recent version of ASTM C1301 “Standard Test Method for Major and Trace Elements in Limestone and Lime by Inductively Coupled Plasma-Atomic Emission Spectroscopy (ICP) and Atomic Absorption (AA)”;

(c) the most recent version of ASTM C1271 “Standard Test Method for X-ray Spectrometric Analysis of Lime and Limestone”;

(d) any other analysis method published by an organization listed in QC.1.5;

(e) the value of 1.0;

(3) determine the annual quantity of each input carbonate and each input carbonate-based raw material, and of each carbonate-based output material, by direct weight measurement once a month using the same plant instruments used for inventory purposes, such as weigh hoppers or belt weigh feeders, or using calculations based on data from the process control system or using a balance based on inventories at the start and end of the year.

QC.25.5. Methods for estimating missing data

When, as part of an emitter’s sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.

When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to obtain 100% of the data. The emitter must then use replacement data, established as follows:

(1) an emitter who uses one of the calculation methods provided for in this Protocol must,

(a) when the missing data concern carbonate content in raw materials or in carbonate-based material output, use the default value of 1.0;

(b) when the missing data concern carbon content,

i. determine the sampling or measurement rate using the following equation:

Equation 25-3

R = QS Act/QS Required

Where:

R = Actual sampling or measurement rate, expressed as a percentage;

QS Act = Quantity of actual samples or measurements obtained by the emitter;

QS Required = Quantity of samples or measurements required under QC.25.4;

ii. for data that require sampling or analysis,

— if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;

— if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;

— if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;

(c) when the missing data concern raw material consumption or carbonate consumption, the replacement data must be estimated on the basis of all the data relating to the processes used;

(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.

QC.25.6. Table

Table 25-1. CO2 emission factors for various carbonates

(QC.25.3.2, QC.25.3.3)

 _________________________________________________________________________________
|                      |                                                          |
| Mineral name -       |     CO2 emission factor (metric tons of CO2 per metric    |
| Carbonate            |     ton of carbonate)                                    |
|______________________|__________________________________________________________|
|                      |                                                          |
| Limestone - CaCO3    |                   0.43971                                |
|______________________|__________________________________________________________|
|                      |                                                          |
| Magnesite - MgCO3    |                   0.52197                                |
|______________________|__________________________________________________________|
|                      |                                                          |
| Dolomite - CaMg(CO3)2 |                   0.47732                                |
|______________________|__________________________________________________________|
|                      |                                                          |
| Siderite - FeCO3     |                   0.37987                                |
|______________________|__________________________________________________________|
|                      |                                                          |
| Ankerite -           |                   0.47572                                |
| Ca(Fe,Mg,Mn)(CO3)2    |                                                          |
|______________________|__________________________________________________________|
|                      |                                                          |
| Rhodochrosite -      |                                                          |
| MnCO3                |                   0.38286                                |
|______________________|__________________________________________________________|
|                      |                                                          |
| Sodium Carbonate/    |                   0.41492                                |
| Soda Ash - Na2CO3     |                                                          |
|______________________|__________________________________________________________|
|                      |                                                          |
| Strontium Carbonate  |                                                          |
| - SrCO3              |                   0.29811                                |
|______________________|__________________________________________________________|
|                      |                                                          |
| Others               | quantity of (CO3-) in carbonate X molecular weight of CO2 |
|                      | ________________________________________________________ |
|                      |                                                          |
|                      |                molecular weight of carbonate             |
|______________________|__________________________________________________________|                        

QC.26. GLASS PRODUCTION

QC.26.1. Covered sources

The covered sources are glass melting furnaces used to produce flat glass, container glass, pressed and blown glass or wool fibreglass.

QC.26.2. Greenhouse gas reporting requirements

In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:

(1) (subparagraph revoked);

(2) the annual CO2 emissions attributable to the use of carbonate-containing raw materials for glass production, in metric tons;

(3) (subparagraph revoked);

(4) the annual CO2, CH4 and N2O emissions attributable to the use of stationary combustion equipment, calculated in accordance with QC.1, in metric tons;

(5) the annual consumption of each carbonate-containing raw material used in a furnace, in metric tons;

(6) the average annual carbonate content of each carbonate-based raw material used in a furnace, in metric tons of carbonate per metric ton of raw material;

(7) the calcination fraction of the carbonates contained in raw materials, in metric tons of carbonate obtained per metric ton of carbonate in the raw material;

(8) the annual quantity of glass produced, in metric tons;

(9) the number of times that the methods for estimating missing data in QC.26.5 were used;

(10) (subparagraph revoked).

Subparagraphs 5, 6 and 7 of the first paragraph do not apply to the CO2 emissions of an emitter who calculates emissions using data from a continuous emission monitoring and recording system.

For the purposes of subparagraph 8 of the first paragraph of section 6.2:

(1) the emissions referred to in subparagraph 2 of the first paragraph are emissions attributable to fixed processes;

(2) the emissions referred to in subparagraphs 3 and 4 of the first paragraph are emissions attributable to combustion.

QC.26.3. Calculation methods for annual CO2 emissions

For each glass melting furnace, the annual CO2 emissions attributable to glass production must be calculated using one of the calculation methods in QC.26.3.1 and QC.26.3.2.

QC.26.3.1. Use of a continuous emission monitoring and recording system

The annual CO2 emissions may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.1.3.4.

QC.26.3.2. Calculation method for annual CO2 emissions

The annual CO2 emissions attributable to the use of carbonate-containing raw materials may be calculated using equation 26-1:

Equation 26-1

Where:

CO2 = Annual CO2 emissions attributable to the use of carbonate-containing raw materials for glass production in all glass melting furnaces, in metric tons;

n = Number of glass melting furnaces;

i = Glass melting furnace;

CO2,i = Annual CO2 emissions attributable to the use of carbonate-containing raw materials for glass production in glass melting furnace i, calculated in accordance with QC.25.3.2, in metric tons.

QC.26.4. Sampling, analysis ans measurement requirements

When the calculation method in QC.26.3.2 is used, an emitter who operates a facility or establishment that produces glass must determine annually, in accordance with QC.25.4,

(1) the average carbonate content of each raw material, or use the value 1.0;

(2) the calcination fraction of each carbonate, or use the value 1.0;

(3) the quantity of each carbonate-containing raw material.

QC.26.5. Methods for estimating missing data

When, as part of an emitter’s sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.

When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:

(1) an emitter who uses one of the calculation methods provided for in this Protocol must,

(a) when the missing data concern carbonate content in raw materials or in carbonate-based material output, use the default value of 1.0;

(b) when the missing data concern carbon content,

i. determine the sampling or measurement rate using the following equation:

Equation 26-2

R = QS Act/QS Required

Where:

R = Actual sampling or measurement rate, expressed as a percentage;

QS Act = Quantity of actual samples or measurements obtained by the emitter;

QS Required = Quantity of samples or measurements required under QC.26.4;

ii. for data requiring sampling and/or analysis,

— if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;

— if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;

— if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;

(c) when the missing data concern raw material consumption, glass production or carbonate consumption, the replacement data must be estimated on the basis of all the data relating to the processes used;

(2) an emitter who uses a continuous emission monitoring system must use the procedure in the SPE 1/PG/7 protocol entitled Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation published in November 2005 by Environment Canada or apply to the missing parameters the method specified in subparagraph a of paragraph 2 of QC.1.6.

QC.27. MOBILE EQUIPMENT

QC.27.1. Covered sources

The covered sources are all mobile equipment used at a facility or establishment for the on-site transportation or movement of substances, materials or products, and any other mobile equipment such as tractors, mobile cranes, log transfer equipment, mining machinery, graders, backhoes and bulldozers, and other mobile industrial equipment. All mobile equipment used by subcontractors for the purposes of activities under the operational control of the facility or establishment is also covered.

Vehicles used for activities that are not directly or indirectly connected with production, such as lawn maintenance and snow clearing vehicles, as well as road vehicles within the meaning of the Highway Safety Code (chapter C-24.2), aircraft and ships, are excluded.

QC.27.2. Greenhouse gas reporting requirements

In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:

(1) the annual greenhouse gas emissions attributable the combustion of fossil fuels and biomass fuels, in metric tons, specifying, by fuel type,

(a) CO2 emissions;

(b) CH4 emissions;

(c) N2O emissions;

(2) the annual consumption of each fuel type, in kilolitres.

QC.27.3. Calculation methods for CO2 emissions

The annual CO2 emissions attributable to mobile equipment must be calculated in accordance with the calculation method in QC.27.3.1.

For mixtures of biomass fuels and fossil fuels, the CO2 emissions attributable to the biomass fuel portion and to the fossil fuel portion must be calculated separately.

QC.27.3.1. Calculation of CO2 emissions based on the quantity of fuel used

The annual CO2 emissions attributable to mobile equipment used on-site at a facility or establishment must be calculated, for each type of fuel used, using equation 27-1:

Equation 27-1

CO2 = Fuel × EF × 1000 × 0.001

Where:

CO2 = Annual CO2 emissions attributable to each type of fuel used by the mobile equipment, in metric tons;

Fuel = Annual volume of fuel used by the mobile equipment, in kilolitres;

EF = CO2 emission factor for the fuel, as specified in Table 27-1 in QC.27.7, in kilograms per litre;

1000 = Conversion factor, litres to kilolitres;

0.001 = Conversion factor, kilograms to metric tons.

QC.27.3.2. (Revoked).

QC.27.3.3. (Revoked).

QC.27.4. Calculation methods for CH4 and N2O emissions

The annual CH4 and N2O emissions attributable to mobile equipment must be calculated using the calculation method in QC.27.4.1.

For mixtures of biomass fuels and fossil fuels, the CH4 and N2O emissions attributable to the biomass fuel portion and to the fossil fuel portion must be calculated separately.

QC.27.4.1. Calculation of CH4 and N2O emissions based on the quantity of fuel consumed

The annual CH4 and N2O emissions attributable to mobile equipment used on-site at a facility or establishment must be calculated, for each type of fuel used, using equation 27-2:

Equation 27-2

CH4 or N2O = Fuel × EF × 1000 × 0.000001

Where:

CH4 or N2O = Annual CH4 or N2O emissions attributable to each fuel type used by the mobile equipment, in metric tons;

Fuel = Annual volume of fuel used by the mobile equipment, in kilolitres;

EF = CH4 or N2O emission factor for the fuel, as specified in Table 27-1 in QC.27.7, in grams per litre;

1000 = Conversion factor, litres to kilolitres;

0.000001 = Conversion factor, grams to metric tons.

QC.27.4.2. (Revoked).

QC.27.4.3. (Revoked).

QC.27.5. Sampling, analysis and measurement requirements

An emitter who uses mobile equipment on-site at a facility or establishment must

(1) for a mixture of biomass fuels and fossil fuels, determine during each delivery the portion of biomass fuels and the portion of fossil fuels based on the data indicated by the supplier;

(2) determine annually the volumes of fuel used, using the same plant instruments as those used for inventory purposes, such as purchase invoices or a gauge reading for each unit of mobile equipment;

(3) (paragraph revoked);

QC.27.6. Methods for estimating missing data

The emitter must demonstrate that everything has been done to capture 100% of the data.

When the missing data concern fuel consumption, the replacement data must be estimated on the basis of all the data relating to the processes used.

QC.27.7. Table

Table 27-1. Emission factors by fuel type

(QC.27.3.1, QC.27.4.1)

 _________________________________________________________________________________
|                                       |             |             |             |
| Mobile equipment                      |     CO2     |     CH4      |     N20     |
|                                       |    (kg/l)   |    (g/l)    |    (g/l)    |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| Liquefied natural gas vehicle         |    1.178    |    N/A      |   N/A       |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| Compressed natural gas vehicle        |1.907 × 10-3 |    N/A      |   N/A       |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| Propane vehicle                       |    1.510    |    0.64     |    0.028    |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| Gasoline vehicle                      |    2.289    |    2.7      |    0.050    |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| Diesel vehicle                        |    2.663    |    0.15     |    1.1      |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| Diesel train                          |    2.663    |    0.15     |    1.1      |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| Biodiesel vehicle                     |    2.449    |    0.15     |    1.1      |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| Ethanol vehicle                       |    1.494    |    2.7      |    0.050    |
|_______________________________________|_____________|_____________|_____________|                        

QC.28. ELECTRONICS MANUFACTURING

QC.28.1. Covered sources

The covered sources are all facilities or establishments that manufacture semiconductors, liquid crystal displays, micro-electro-mechanical systems and photovoltaic cells. The following manufacturing processes are also targeted:

(1) plasma etching, in other words the process in which plasma-generated fluorine atoms and other reactive fluorine-containing fragments chemically react with exposed thin-films constituted of dielectric materials and metals, and in contact with silicon;

(2) the periodical cleaning of the chambers used for depositing thin films using plasma-generated fluorine atoms and other reactive fluorine-containing fragments from fluorinated and other gases;

(3) the cleaning of semiconductor wafers using plasma-generated fluorine atoms or other reactive fluorine-containing fragments to remove residual material from wafer surfaces;

(4) the transformation of fluorinated compounds, in other words the process by which fluorinated compounds can be transformed into different fluorinated compounds which are then exhausted, unless abated, into the atmosphere;

(5) chemical vapour deposition processes or any other electronics manufacturing processes using N2O;

(6) equipment cooling, in other words the process in which fluorinated gases are used as heat transfer fluids to cool process equipment, control temperature during device testing, and solder semiconductor devices to circuit boards.

QC.28.2. Greenhouse gas reporting requirements

In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:

(1) the annual greenhouse gas emissions attributable to electronics manufacturing processes, in metric tons;

(2) the annual CO2, CH4 and N2O emissions attributable to the use of stationary combustion equipment, calculated and reported in accordance with QC.1, in metric tons;

(3) the greenhouse gas calculations methods used pursuant to QC.28.3;

(4) production in terms of substrate surface area, such as silica, photovoltaic cells and liquid crystal displays, in square metres;

(5) the emission factors used to determine process utilization and by-product formation rates and the source for each factor;

(6) a description of each calculation method used, when different from the methods in QC.28.3;

(7) the annual consumption of each greenhouse gas and the quantity of gas remaining in the container after use, in metric tons;

(8) the quantity of each fluorinated gas injected in each process or process category used, as determined in QC.28.4.2;

(9) a description of the engineering model used to apportion the consumption of fluorinated bases in each process or process category used;

(10) the annual consumption of each greenhouse gas, calculated in accordance with the method used to determine the apportioning of each fluorinated gas when that method allows an estimate that is independent of the estimate obtained using equation 28-6 in QC.28.3.4, in metric tons;

(11) the data used to calculate the mass balance of each greenhouse gas for any heat transfer fluid used, using equation 28-5 provided for in QC.28.3.3;

(12) (subparagraph revoked);

(13) the number of times the methods for estimating missing data provided for in QC.28.5 were used.

For the purposes of subparagraph 8 of the first paragraph of section 6.2:

(1) the emissions referred to in subparagraph 2 of the first paragraph are emissions attributable to combustion;

(2) the emissions referred to in subparagraph 1 of the first paragraph are other emissions.

QC.28.3. Greenhouse gas calculation methods

The annual greenhouse gas emissions attributable to all electronics manufacturing processes must be calculated using equation 28-1:

Equation 28-1

Where:

GHG = Annual greenhouse gas emissions attributable to all electronics manufacturing processes, in metric tons;

n = Total number of input gases;

i = Type of input gas;

GHGP,j = Annual greenhouse gas emissions of input gas i from individual process or process category j, calculated in accordance with QC.28.3.1, in metric tons;

GHGB,i = Annual emissions of by-product gas formed from input gas i during individual process or process category j, calculated in accordance with QC.28.3.1, in metric tons;

GHGTF,i = Annual greenhouse gas emissions attributable to the use of heat transfer fluid i, calculated in accordance with QC.28.3.3, in metric tons;

N2O = Annual N2O emissions attributable to each electronics manufacturing process, calculated in accordance with QC.28.3.2, in metric tons;

j = Individual process or process category.

QC.28.3.1. Calculation method for fluorinated gas emissions

The annual fluorinated gas emissions attributable to all electronics manufacturing processes must be calculated using equations 28-2 and 28-3 and in accordance with the second paragraph.

Equation 28-2

Where:

GHGP,j = Annual greenhouse gas emissions of input gas i from individual process or process category j, in metric tons;

m = Total number of individual processes or process categories;

j = Individual process or process category;

Cj = Consumption of input gas i in individual process or process category j, calculated using equation 28-6 and apportioned in accordance with QC.28.4.2, in kilograms;

Uj = Process utilization for input gas i during individual process or process category j;

aj = Volumetric fraction of input gas i used in individual process or process category j with antipollution systems, in percentage expressed in the form of a decimal;

dj = Volumetric fraction of input gas i destroyed by the antipollution system connected to individual process or process category j, during process use time, determined in accordance with paragraph 2 of QC.28.4.4, in percentage expressed in the form of a decimal, or a default value of 0;

0.001 = Conversion factor, kilograms to metric tons;

i = Input gas;

Equation 28-3

Where:

GHGD,i = Annual emissions of by-product gas k formed from input gas i during individual process or process category j, in metric tons;

m = Total number of individual processes or process categories;

j = Individual process or process category;

p = Total number of by-product gases;

k = By-product gas;

Pjk = Emission factor of by-product gas k from consumption of input gas i during individual process or process category j;

Cj = Consumption of input gas i during process j, calculated using equation 28-6 and apportioned in accordance with QC.28.4.2, in kilograms;

aj = Volumetric fraction of input gas i used in individual process or process category j with antipollution systems, in percentage expressed in the form of a decimal;

djk = Volumetric fraction of input gas i destroyed by the antipollution system connected to individual process or process category j, during process use time, determined in accordance with paragraph 2 of QC.28.4.4, in percentage expressed in the form of a decimal, or a default value of 0;

0.001 = Conversion factor, kilograms to metric tons;

i = Input gas.

For the purpose of calculating emissions, the emitter must determine the rate of use of the input gas during the individual process or process category and the rate of production of the by-product gas from consumption of the input gas during the individual process or process category using the following methods:

(1) for a facility that manufactures semiconductors on wafers 300 mm or less in diameter:

(a) using the emission factors (1-Ui) or Pjk indicated in Tables 28-1, 28-2 and 28-3 in QC.28.6;

(b) by measuring the rates in accordance with QC.28.4.3;

(2) for a facility that manufactures semiconductors on wafers measuring more than 300 mm in diameter, by measuring the rates in accordance with QC.28.4.3;

(3) for all other electronics manufacturing facilities, using the emission factors (1-Ui) or Pjk indicated in Tables 28-4, 28-5 and 28-6 in QC.28.6.

QC.28.3.2. Calculation method for N2O emissions

The annual N2O emissions attributable to all electronics manufacturing processes must be calculated using equation 28-4 and in accordance with the second paragraph.

Equation 28-4

Where:

N2O = Annual emissions of N2O attributable to each electronics manufacturing process, in metric tons;

m = Total number of processes used;

j = Type of process used;

Cj = Consumption of N2O during process j, calculated using equation 28-6 and apportioned to N2O-using process j, in kilograms;

Uj = Rate of utilization of N2O during process j;

aj = Volumetric fraction of N2O used in N2O-using process j with an antipollution system, in percentage expressed in the form of a decimal;

dj = Volumetric fraction of N2O destroyed by the antipollution systems connected to process j, during process use time, determined in accordance with paragraph 2 of QC.28.4.4, or a default value of 0;

0.001 = Conversion factor, kilograms to metric tons.

For the purpose of calculating emissions, the emitter must:

(1) determine the N2O utilization rate by measuring it in accordance with QC.28.4.3 or, when the rate cannot be measured, using a default value of 20% for chemical vapour deposition processes and a value of 0% for all other manufacturing processes;

(2) for a facility equipped with antipollution systems, calculate the reduction in N2O emissions attributable to the use of such systems, in accordance with QC.28.4.4.

QC.28.3.3. Calculation method for fluorinated gas emissions attributable to heat transfer fluids

The annual fluorinated gas emissions attributable to the use of each heat transfer fluid must be calculated using equation 28-5:

Equation 28-5

QC.28.3.4. Calculation method for the consumption of fluorinated gases and N2O

The annual consumption of fluorinated gases and N2O used in electronics manufacturing processes must be calculated in accordance with QC.28.4.1 using equations 28-6 and 28-7:

Equation 28-6

Ci = (IDi − IFi + Ai − Si) × 0.001

Where:

Ci = Annual consumption of input gas i, in metric tons;

IDi = Quantity of gas i in inventory in all containers at the beginning of the year, including heels, in kilograms;

IFi = Quantity of gas i in inventory in all containers at the end of the year, including heels, in kilograms;

Ai = Quantity of gas i acquired during the year, including heels in containers returned to the establishment or facility, in kilograms;

Si = Quantity of gas i sold or transferred during the year, including heels in containers returned to the gas supplier, calculated using equation 28-7, in kilograms;

0.001 = Conversion factor, kilograms to metric tons;

i = Input gas;

Equation 28-7

Where:

Si = Quantity of gas i sold or transferred during the year, including heels in containers returned to the gas supplier, in kilograms;

q = Total number of types of container;

l = Type of container;

fi,l = Fraction of gas i remaining in container of type l, determined in accordance with QC.28.4.1;

Ni,l = Number of containers of type l returned to the gas supplier containing the heel of gas i calculated in accordance with paragraph 2 of QC.28.4.1;

NCi,l = Total nameplate capacity of containers of type l containing gas i, in kilograms;

Xi = Any other quantity of gas i sold or transferred during the year, calculated in accordance with paragraph 3 of QC.28.4.1, in kilograms;

i = Gas sold or transferred.

QC.28.4. Sampling, analysis and measurement requirements

QC.28.4.1. Determination of gas heel remaining in a container

An emitter operating an electronics manufacturing facility or establishment must determine the gas heel remaining in a container, for each type of gas and type of container, using the following methods:

(1) by determining the fraction of gas heel remaining in a container using equation 28-8:

Equation 28-8

Where:

fi,j = Gas heel i remaining in a container of type j;

wr,i = Residual weight of gas i, calculated in accordance with paragraph 2, in grams;

minitial,i = Initial mass of gas i, determined by measuring or based on the weight of the gas indicated by the supplier, in grams;

(2) by measuring the residual weight or pressure of a container when replacing it and, when the pressure is measured, by determining the residual weight using equation 28-9:

Equation 28-9

       Mi × pi × Vi
Wr,i = _____________
       Zi × R × Ti
                        

Where:

Wr,i = Residual weight of gas i, in grams;

Mi = Molar weight of gas i, in grams per mole;

pi = Absolute pressure of gas i, in pascals;

Vi = Volume of gas i, in cubic metres;

Zi = Compressibility factor of gas i;

R = Perfect gas constant of 8.314 joules per kelvin-mole;

Ti = Absolute temperature of gas i, in kelvin;

(3) if a container is replaced when the residual weight or pressure of the gas is over 20% higher than the weight or pressure used to calculate the gas heel remaining in the container, by weighing the container or by measuring the pressure using a pressure gauge and using either value to replace the gas heel calculated previously;

(4) by recalculating the gas heel remaining in the container calculated previously when the residual weight or pressure of gas determined when the container is replaced differs by more than 1% from the initial value used to calculate the gas heel remaining in the container.

QC.28.4.2. Apportionment of the consumption of fluorinated gases by process category

The emitter must apportion the consumption of fluorinated gases by process category, as defined in the tables in QC.28.6, or by individual process, using an engineering model based on the number of wafer passes.

QC.28.4.3. Determination of the utilization rates for fluorinated gases and N2O and the formation rates for by-product gases

The utilization rates for fluorinated gases and N2O and the formation rates for by-product gases determined by the emitter or by the equipment manufacturer must comply with the “International SEMATECH Manufacturing Initiative’s Guideline for Environmental Characterization of Semiconductor Process Equipment – Revision 2”.

QC.28.4.4. Calculation of N2O emissions reductions attributable to the use of an antipollution system

An emitter who calculates reductions in fluorinated gases and N2O emissions attributable to the use of an antipollution system must

(1) ensure that the antipollution system is designed to reduce fluorinated gas and N2O emissions and is installed, operated and maintained according to the manufacturer’s instructions, and keep the certification;

(2) determine the time of use of the antipollution system when using an destruction factor to calculate the reduction in fluorinated gas and N2O emissions, and calculate the use factor by adding together the system’s operational productive, standby, and stoppage times and dividing the result by the total operations time of its associated manufacturing equipment, in accordance with SEMI E-10-0304E “Specification for Definition and Measurement of Equipment Reliability, Availability, and Maintainability” published by the Semiconductor Equipment and Materials International (SEMI);

(3) use a default destruction factor of 60%, or determine the destruction factor using the following methods:

(a) in accordance with EPA 430-R-10-003 “Protocol for Measuring Destruction or Removal Efficiency of Fluorinated Greenhouse Gas Abatement Equipment in Electronics Manufacturing” published by the U.S. Environmental Protection Agency (USEPA);

(b) by selecting annually a random sample of antipollution systems and measuring their destruction factor using the following methods:

i. the random sample must come from 3 antipollution systems or 20% of the total number of installed antipollution systems, whichever is greater, for each category of antipollution system. When the percentage does not equate to a whole number, it must be rounded up to the nearest whole number;

ii. all the antipollution systems in each category must be subject to a random sampling at least once every 5 years;

(c) for each antipollution system whose destruction factor has been measured during the previous 2 years, by calculating the reduction in emissions using that factor;

(d) for each antipollution system whose destruction factor has not been measured during the previous 2 years, by using the average destruction factor of the systems in the same category;

(e) when an emergency antipollution system is utilized, the utilization time may be included in the total utilization time for the antipollution systems, calculated annually.

QC.28.4.5. Instrument calibration and accuracy

The emitter must calibrate all the instruments used to determine the concentration of fluorinated gases and N2O in process streams immediately before measuring the destruction factor, gas utilization factor for the process, or by-product gas formation factor. The calibration must be based on representative samples with known concentrations, for which the fractions by mass of the same gases are similar to those of the process samples. The emitter may also use high-concentration fluorinated gases or N2O certified representative samples using a gas dilution system that meets the requirements specified in Method 205, 40 CFR part 51, Appendix M of the Code of Federal Regulations “Verification of Gas Dilution Systems for Field Instrument Calibrations”.

When the emitter uses flow meters, weigh scales, pressure gauges or thermometers, their minimum accuracy must be 1% of full scale.

QC.28.5. Methods for estimating missing data

When, as part of an emitter’s sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.

When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:

(1) an emitter who uses one of the calculation methods provided for in this Protocol must,

(a) when the missing data concern volumetric fraction or fluid density,

i. determine the sampling or measurement rate using the following equation:

Equation 28-10

R = QS Act/QS Required

Where:

R = Actual sampling or measurement rate, expressed as a percentage;

QS Act = Quantity of actual samples or measurements obtained by the emitter;

QS Required = Quantity of samples or measurements required under QC.28.4;

ii. for data that require sampling or analysis,

— if R ≥ 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;

— if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;

— if R < 0.75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;

(b) when the missing data concern gas quantity or substrate quantity, the replacement data must be estimated on the basis of all the data relating to the processes used;

(c) when one or more values used to calculate the emissions attributable to heat transfer fluids using equation 28-5 is missing, the emitter must estimate greenhouse gas emissions using the arithmetic average of the emission rates for the previous year and for 2 months following the missing data period. When those emission rates cannot be obtained, the emitter must estimate the greenhouse gas emissions using data from the suppliers of the heat transfer fluids.

QC.28.6. Tables

Table 28-1. Default greenhouse gas emission factors for fluorinated compounds for processes and process categories for semiconductor manufacturing for 150 mm wafer size

(QC.28.3.1, QC.28.4.2)

Table 28-2. Default greenhouse gas emission factors for fluorinated compounds for processes and process categories for semiconductor manufacturing for 200 mm wafer size

(QC.28.3.1, QC.28.4.2)

Table 28-3. Default emission factors for processes and process categories for semiconductor manufacturing for 300 mm wafer size

(QC.28.3.1, QC.28.4.2)

Table 28-4. Default emission factors for micro-electrical-mechanical systems manufacturing

(QC.28.3.1, QC.28.4.2)

Table 28-5. Default emission factors for LCD screen manufacturing

(QC.28.3.1, QC.28.4.2)

Table 28-6. Default emission factors for photovoltaic cell manufacturing

(QC.28.3.1, QC.28.4.2)

QC.29. PROCESSES AND EQUIPMENT USED TO TRANSPORT AND DISTRIBUTE NATURAL GAS

QC.29.1. Covered sources

The covered sources are the processes and equipment used for the transmission and distribution of natural gas:

(1) onshore natural gas transmission compression, which includes any stationary combination of compressors that move natural gas at elevated pressure from production fields or natural gas processing facilities in transmission pipelines to natural gas distribution pipelines or into storage, and any equipment required for liquids separation, natural gas dehydration, and tanks for the storage of water and hydrocarbon liquids;

(2) underground natural gas storage, which includes depleted gas or oil reservoirs and salt dome caverns that store natural gas that has been transferred from its original location for the primary purpose of load balancing, natural gas underground storage processes and operations, including compression, dehydration and flow measurement, and all the wellheads connected to the compression units that inject and recover natural gas into and from the underground reservoirs;

(3) liquefied natural gas (LNG) storage, which includes LNG storage vessels located above ground, equipment for liquefying natural gas, compressors to capture and re-liquefy boil-off-gas, and vaporization units for re-gasification of the liquefied natural gas;

(4) LNG import and export equipment, which includes, in the case of LNG import equipment, all onshore or offshore equipment that receives imported LNG via ocean transport, stores LNG, re-gasifies LNG, and delivers re-gasified natural gas to a natural gas transmission or distribution system and, in the case of LNG export equipment, all onshore or offshore equipment that receives natural gas, liquefies natural gas, stores LNG, and transfers the LNG via ocean transportation to its destination;

(5) natural gas transmission pipelines, which include high pressure pipelines and associated equipment transporting sellable quality natural gas from production or natural gas processing to natural gas distribution stations before delivery to customers but including the pipelines and equipment necessary for deliveries to a customer located close to a transmission pipeline;

(6) natural gas distribution, which includes all natural gas equipment downstream of the station yard inlet valves of natural gas transmission pipelines at stations where pressure reduction and/or measuring first occurs for eventual delivery of natural gas to consumers.

QC.29.2. Greenhouse gas reporting requirements

In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:

(1) (subparagraph revoked);

(2) the annual CO2, CH4 and N2O emissions attributable to the use of stationary combustion equipment, calculated and reported in accordance with QC.1, in metric tons;

(3) the annual CO2, CH4 and N2O emissions attributable to the compression of natural gas and onshore pipelines, in metric tons, specifying:

(a) compressor venting, including:

i. emissions from natural gas pneumatic continuous high bleed devices and pumps, calculated in accordance with QC.29.3.1;

ii. emissions from natural gas pneumatic continuous low bleed and intermittent bleed devices, including emissions from pneumatic devices during compressor startups, calculated in accordance with QC.29.3.2;

iii. emissions from blowdown vent stacks, calculated in accordance with QC.29.3.3;

iv. emissions from centrifugal compressors, calculated in accordance with QC.29.3.5;

v. emissions from reciprocating compressors, calculated in accordance with QC.29.3.6;

vi. emissions from other venting emissions sources, calculated in accordance with QC.29.3.11;

(b) annual fugitive CO2 and CH4 emissions from compressor equipment, such as valves, connectors, open ended lines, pressure relief valves and meters, calculated in accordance with QC.29.3.7 or QC.29.3.8;

(c) annual CO2, CH4 and N2O emissions from compressor station flaring or incinerators, calculated in accordance with QC.29.3.4;

(d) other annual fugitive CO2 and CH4 emissions from compressor stations, calculated in accordance with QC.29.3.11;

(e) annual fugitive CO2 and CH4 emissions from above ground meters and regulators and all custody transfer gate station equipment, such as connectors, block valves, control valves, pressure relief valves, orifice meters, regulators and open ended lines, calculated in accordance with QC.29.3.7 or QC.29.3.8;

(f) annual fugitive CO2 and CH4 emissions from above ground meters and regulators at non-custody transfer gate stations, including equipment components, calculated in accordance with QC.29.3.8, but excluding fugitive emissions from customer meters;

(g) annual CO2, CH4 and N2O emissions from pipeline flaring or incinerators, calculated in accordance with QC.29.3.4;

(h) annual fugitive CO2 and CH4 emissions from below ground meters and regulators, calculated in accordance with QC.29.3.8;

(i) other annual fugitive CO2 and CH4 emissions from transmission pipeline not covered in subparagraphs e to h, emissions attributable to pressure reduction stations, emissions attributable to tubing systems less than 2.54 cm in diameter and emissions attributable to customer meters, calculated in accordance with QC.29.3.11;

(j) annual CO2 and CH4 emissions from other sources of venting emissions transmission pipelines, calculated in accordance with QC.29.3.11;

(k) annual CO2 and CH4 emissions from natural gas transmission storage tanks, calculated in accordance with QC.29.3.10;

(l) annual CH4 emissions attributable to third party pipeline hits, calculated in accordance with QC.29.3.9;

(4) the annual CO2, CH4 and N2O emissions from underground natural gas storage, in metric tons, specifying:

(a) annual emissions from venting, including:

i. emissions from natural gas pneumatic continuous high bleed devices and pumps, calculated in accordance with QC.29.3.1;

ii. emissions from pneumatic low bleed and intermittent bleed devices, calculated in accordance with QC.29.3.2;

iii. emissions from centrifugal compressors, calculated in accordance with QC.29.3.5;

iv. emissions from reciprocating compressors, calculated in accordance with QC.29.3.6;

v. fugitive emissions from other sources, calculated in accordance with QC.29.3.11;

(b) annual fugitive CO2 and CH4 emissions from equipment components such as valves, connectors, open ended lines, pressure relief valves and meters, calculated in accordance with QC.29.3.7 or QC.29.3.8;

(c) annual CO2, CH4 and N2O emissions from flares or incinerators, calculated in accordance with QC.29.3.4;

(d) fugitive emissions from other sources, calculated in accordance with QC.29.3.11;

(5) annual CO2, CH4 and N2O emissions from LNG storage, in metric tons, specifying:

(a) venting emissions, including:

i. emissions from centrifugal compressors, calculated in accordance with QC.29.3.5;

ii. emissions from reciprocating compressors, calculated in accordance with QC.29.3.6;

iii. emissions from other venting sources, calculated in accordance with QC.29.3.11;

iv. emissions from screw compressors, calculated in accordance with QC.29.3.6;

(b) annual fugitive CO2 and CH4 emissions from equipment components, such as valves, pump seals, connectors and vapour recovery compressors, calculated in accordance with QC.29.3.7 or QC.29.3.8;

(c) annual CO2, CH4 and N2O emissions from flares or incinerators, calculated in accordance with QC.29.3.4;

(d) fugitive emissions from other emissions sources, calculated in accordance with QC.29.3.11;

(6) annual CO2, CH4 and N2O emissions from LNG import and export equipment, in metric tons, specifying:

(a) venting emissions, including:

i. emissions from blowdown vent stacks, calculated in accordance with QC.29.3.3;

ii. emissions from centrifugal compressors, calculated in accordance with QC.29.3.5;

iii. emissions from reciprocating compressors, calculated in accordance with QC.29.3.6;

iv. emissions from other venting sources, calculated in accordance with QC.29.3.11;

v. annual CH4 emissions attributable to third party pipeline hits, calculated in accordance with QC.29.3.9;

(b) annual fugitive CO2 and CH4 emissions from equipment components, such as valves, pump seals, connectors and vapour recovery compressors, calculated in accordance with QC.29.3.7 or QC.29.3.8;

(c) annual CO2, CH4 and N2O emissions from flares or incinerators, calculated in accordance with QC.29.3.4;

(d) fugitive emissions from other emissions sources, calculated in accordance with QC.29.3.11;

(7) annual CO2, CH4 and N2O emissions attributable to natural gas distribution, in metric tons, specifying:

(a) annual CO2 and CH4 fugitive emissions from above ground meters and regulators and all custody transfer gate station equipment, such as connectors, block valves, control valves, pressure relief valves, orifice meters, regulators and open ended lines, calculated in accordance with QC.29.3.7 or QC.29.3.8, but excluding fugitive emissions from customer meters;

(b) annual CO2 and CH4 fugitive emissions from above ground meters and regulators at non-custody transfer gate stations, including station equipment, calculated in accordance with QC.29.3.7 or QC.29.3.8, but excluding fugitive emissions from customer meters;

(b.1) (subparagraph revoked);

(c) annual CO2 and CH4 fugitive emissions from below ground meters, regulators and other underground station equipment, calculated in accordance with QC.29.3.7 or QC.29.3.8;

(d) annual CO2 and CH4 fugitive emissions from distribution pipelines, calculated in accordance with QC.29.3.7 or QC.29.3.8;

(e) annual CO2 and CH4 fugitive emissions from service pipes, calculated in accordance with QC.29.3.7 or QC.29.3.8;

(f) annual CO2, CH4 and N2O fugitive emissions from flares or incinerators of distribution system and equipment, calculated in accordance with QC.29.3.4;

(g) (subparagraph revoked);

(h) other annual CO2 and CH4 fugitive emissions from distribution pipelines, including emissions attributable to pressure reduction connections and emissions attributable tubing systems less than 2.54 cm in diameter, calculated in accordance with QC.29.3.11;

(i) annual CO2 and CH4 fugitive emissions from connection equipment, calculated in accordance with QC.29.3.7 or QC.29.3.8;

(j) annual CH4 emissions attributable to third party pipeline hits, calculated in accordance with QC.29.3.9;

(k) annual venting emissions, namely:

i. emissions from continuous high bleed pneumatic devices and natural gas pumps, calculated in accordance with QC.29.3.1;

ii. emissions from continuous low bleed and intermittent bleed pneumatic devices, calculated in accordance with QC.29.3.2;

iii. venting emissions from other sources of emissions, calculated in accordance with QC.29.3.11;

(8) annual CO2, CH4 and N2O emissions attributable to the use of portable combustion equipment, calculated and reported using the methods for stationary combustion equipment in QC.1, in metric tons;

(9) the following data for each emissions source in subparagraphs 3 to 7:

(a) the number of natural gas pneumatic devices used by type, namely high bleed, low bleed and intermittent bleed;

(b) the number of natural gas driven pneumatic pumps;

(c) total pipeline length, in kilometres;

(d) if glycol dehydrators are used, the number of dehydrators, specifying

i. the number of dehydrators with a capacity of less than 11,328 m3 per day at standard conditions;

ii. the number of dehydrators with a capacity greater than 11,328 m3 per day at standard conditions;

(d.1) the emission factors used in replacement of those specified in Tables 29-1 to 29-5 in QC.29.6;

(e) if dehydrators other than glycol hydrators are used, the number of dehydrators used;

(f) for each compressor used:

i. compressor type;

ii. compressor nameplate capacity, in kilowatts;

iii. number of blowdowns per year;

iv. operating mode during the year, as determined in QC.29.4.6;

v. number of compressor starts during the year;

(g) when the calculation methods in QC.29.3.7 are used, the total number of leaks found in annual leak detection surveys by type of leak for which an emission factor is provided;

(g.1) when the calculation methods in QC.29.3.8 are used, the component count for each source for which an emission factor is provided in Tables 29-1 to 29-5 in QC.29.6, except components of below grade meter and regulator stations and transmission and distribution pipelines. For the purposes of those calculation methods, a below grade meter and regulator station is considered to be a component;

(h) for natural gas distribution:

i. the number of custody transfer gate stations;

ii. the number of non-custody transfer gate stations;

iii. the number of third party pipeline hits by volume of gas emitted to the atmosphere;

(10) the number of times that the methods for estimating missing data provided for in QC.29.5 were used;

(11) (subparagraph revoked).

Emissions attributable to venting or other sources of fugitive emissions referred to in subparagraph vi of subparagraph a and subparagraphs d, i, j and k of subparagraph 3, subparagraph v of subparagraph a and subparagraph d of subparagraph 4, subparagraph iii of subparagraph a and subparagraph d of subparagraph 5, subparagraph iv of subparagraph a and subparagraph d of subparagraph 6 and subparagraphs g and h of subparagraph 7 of the first paragraph are not required to be reported if the emissions from that source are below 0.5% of the emitter’s total emissions and total emissions not reported under this paragraph do not exceed 1% of the emitter’s total emissions.

For the purposes of subparagraph 8 of the first paragraph of section 6.2:

(1) the emissions referred to in subparagraphs 2 and 8 of the first paragraph are emissions attributable to combustion;

(2) the emissions referred to in subparagraphs 3 to 7 of the first paragraph are other emissions.

QC.29.3. Calculation methods for CO2, CH4 and N2O emissions

The annual CO2, CH4 and N2O emissions attributable to natural gas transmission and distribution must be calculated in accordance with one of the calculation methods in QC.29.3.1 to QC.29.3.11.

When no calculation method for an emissions source, the emitter must use industry inventory practices.

QC.29.3.1. Calculation of CO2 and CH4 emissions attributable to continuous high bleed pneumatic device venting and natural gas driven pneumatic pump venting

The annual CO2 and CH4 emissions attributable to the venting of continuous high bleed pneumatic devices, in other words devices with a venting flow rate above 0.17 m3 per hour, and the venting of natural gas driven pneumatic pumps must be calculated in accordance with equations 29-1 to 29-4:

Equation 29-1

GHGi = GHGm,i + GHGn-m,i

Where:

GHGi = Annual emissions of greenhouse gas i attributable to continuous high bleed pneumatic device venting and natural gas driven pneumatic pump venting, in metric tons;

GHGm,i = Annual emissions of greenhouse gas i attributable to continuous high bleed pneumatic device venting and natural gas driven pneumatic pump venting, calculated using equation 29-2 when the annual volume of natural gas consumed by the devices or pumps is measured, in metric tons;

GHGn-m,i = Annual emissions of greenhouse gas i attributable to continuous high bleed pneumatic device venting and natural gas driven pneumatic pump venting, when the annual volume of natural gas consumed by the devices or pumps is not measured, calculated using equation 29-3 for high bleed pneumatic devices and using equation 29-4 for natural gas driven pneumatic pumps, in metric tons;

i = CO2 or CH4;

Equation 29-2

GHGm,i = VNG × MFi × MWi/MVC × 0.001

Where:

GHGm,i = Annual emissions of greenhouse gas i attributable to continuous high bleed pneumatic device venting or natural gas driven pneumatic pump venting, in metric tons;

VNG = Measured annual volume of natural gas consumed by the continuous high bleed pneumatic devices or natural gas driven pneumatic pumps, in cubic metres at standard conditions;

MFi = Molar fraction of gas i in natural gas, determined in accordance with paragraph 3 of QC.29.4;

MWi = Molecular weight of gas i, in kilograms per kilomole or, when a mass flowmeter is used, replace

 _  _
|    |
| MW |
|----| by 1;
|MVC |
|_  _|                        

MVC = Molar volume conversion factor (24.06 m3 per kilomole at standard conditions);

0.001 = Conversion factor, kilograms to metric tons;

i = CO2 or CH4;

Equation 29-3

Equation 29-3.1

Fj = SPCj × SPj

Where:

Fj = Natural gas flow rate for pneumatic device j, in cubic metres per hour at standard conditions;

SPCj = Supply pressure coefficient at controller of pneumatic device j, determined using Table 29-6 in QC.29.6, in cubic metres per hour per kilopascal. If that data is not available, use the coefficient of a similar device;

SPj = Supply pressure at controller of pneumatic device j, in kilopascals. If that data is not available, use the supply pressure of a similar device;

j = High bleed pneumatic device.

Equation 29-4

Equation 29-4.1

FPPk = [SPCk × SPk] + [DPCk × DPk ] + [SMCk × SMk ]

Where:

FPPk = Natural gas flow for natural gas driven pneumatic pumps k, in cubic metres per hour at standard conditions;

SPCk = Supply pressure coefficient of pneumatic pump k determined using Table 29-6 in QC.29.6, in cubic meters per hour per kilopascal. When that data is not available, use the coefficient of a similar device;

SPk = Supply pressure of pneumatic pump k, en kilopascals. When that data is not available, use the data for a similar device;

k = pneumatic pump;

DPCk = Discharge pressure coefficient of pneumatic pump k determined using Table 29-6 in QC.29.6, in cubic meters per hour per kilopascal. When that data is not available, use the coefficient of a similar device;

DPk = Discharge pressure of pneumatic pump k, in kilopascals. When that data is not available, use the data for a similar device;

SMCk = Strokes per minute coefficient of pneumatic pump k determined using Table 29-6 in QC.29.6, in cubic meters per hour at standard conditions, per strokes per minute. When that data is not available, use the coefficient of a similar device;

SMk = Number of strokes per minute of pneumatic pump k. When that data is not available, use the data for a similar device;

Equation 29-4.2

FPPk = Fk × EFk

Where:

FPPk = Natural gas flow for natural gas driven pneumatic pumps k, in cubic metres per hour at standard conditions;

Fk = Flow of liquid pumped by pneumatic pump k, in litres per hour;

EFk = Emission factor of gas bleed of pneumatic pump k determined in accordance with paragraph 4 of QC.29.4.1, in cubic metres per litre at standard conditions;

k = Pneumatic pump;

QC.29.3.2. Calculation of CO2 and CH4 emissions attributable to continuous low bleed or intermittent bleed natural gas pneumatic device venting

The annual CO2 and CH4 emissions attributable to continuous low bleed or intermittent bleed natural gas pneumatic device venting must be calculated separately using equation 29-5:

Equation 29-5

Equation 29-5.1

EFj = SPCj × SPj

Where:

EFj = Emission factor of intermittent bleed pneumatic devices of type j, in cubic metres per hour at standard conditions;

SPCj = Supply pressure coefficient at controller of intermittent bleed pneumatic device j, determined using Table 29-6 in QC.29.6, in cubic metres per hour, per kilopascal. When that data is not available, use the coefficient of a similar device;

SPj = Supply pressure at controller of intermittent bleed pneumatic device j, in kilopascals. When that data is not available, use the data for a similar device;

j = Intermittent bleed pneumatic device;

QC.29.3.3. Calculation of CO2 and CH4 emissions attributable to natural gas emissions to the atmosphere from equipment blowdown vent stacks

The CO2 and CH4 emissions attributable to natural gas emissions to the atmosphere from equipment blowdown vent stacks to reduce pressure during planned or emergency shutdowns or the maintenance of equipment, except emissions during depressurization to a flare, over-pressure relief, operating pressure control venting and purging of gases other than greenhouse gases, must be calculated in accordance with equation 29-6:

Equation 29-6

QC.29.3.4. Calculation of CO2, CH4 and N2O emissions attributable to flares or incinerators

Annual CO2, CH4 and N2O emissions attributable to flares or incinerators must be calculated in accordance with the following methods:

(1) annual CO2 emissions attributable to or incinerators flares must be calculated using equation 29-7:

Equation 29-7

(2) annual CH4 emissions attributable to or incinerators flares must be calculated using equation 29-8:

Equation 29-8

(3) annual N2O emissions attributable to or incinerators flares must be calculated using equation 29-9:

Equation 29-9

N2O = VG × HHV × EFN2O × 0.001

Where:

N2O = Annual N2O emissions attributable to flares or incinerators, in metric tons;

VG = Annual volume of gas directed to flares, determined in accordance with QC.29.4.4, in cubic metres at standard conditions;

HHV = High heat value of gas as specified in Tables 1-1 and 1-2 in QC.1.7 or high heat value of 4.579 × 10-2 GJ per cubic metre for gas emissions from equipment venting or determined in accordance with QC.1.5.4, in gigajoules per cubic metre at standard conditions;

EFN2O = Emission factor for N2O of 9.52 × 10-5 kg per gigajoule;

0.001 = Conversion factor, kilograms to metric tons.

QC.29.3.5. Calculation of CO2 and CH4 emissions attributable to centrifugal compressor venting

The annual CO2 and CH4 emissions attributable to centrifugal compressor venting must be calculated in accordance with the following methods:

(1) for each centrifugal compressor, the emitter must determine, in accordance with AC.29.4.5, the volume of vapours from a wet seal or dry seal oil degassing tank sent to an atmospheric vent and the volume of gas sent to a flare;

(2) the annual CO2 and CH4 emissions attributable to centrifugal compressor vapours sent to an atmospheric vent must be calculated using equation 29-10:

Equation 29-10

(3) the annual CO2 and CH4 emissions attributable to gas sent to a flare must be calculated in accordance with the calculation methods in QC.29.3.4.

QC.29.3.6. Calculation of CO2 and CH4 emissions attributable to reciprocating compressor venting

The annual CO2 and CH4 emissions attributable to reciprocating compressor vents must be calculated using equation 29-11, except emissions attributable to gas sent to a common flare, which must be calculated in accordance with QC.29.3.4:

Equation 29-11

QC.29.3.7. Calculation of the CO2 and CH4 emissions attributable to leaks identified following a leak detection survey

Except for emissions from emission sources for which the total weight of CO2 and CH4 in the natural gas is below 10%, which must be calculated in accordance with QC.29.3.11, the annual fugitive CO2 and CH4 emissions attributable to leaks identified following a leak detection survey must be calculated in accordance with the following methods:

(1) the leak detection survey must be carried out in accordance with paragraph 2 of QC.29.4 for each of the following sources:

(a) fugitive emissions from equipment components during:

i. underground natural gas storage;

ii. liquid natural gas storage;

iii. liquid natural gas imports and exports;

(b) fugitive emissions leaks from compressor components during the compression of natural gas for onshore pipeline transmission;

(c) fugitive emissions from above ground meters and regulators at custody transfer gate stations during

i. the compression of natural gas for onshore pipeline transmission;

ii. natural gas distribution;

(2) for each source where leaks have been detected, the fugitive emissions must be calculated using equation 29-12 or 29-13, depending on the unit of the leaker emission factor used:

Equation 29-12

Equation 29-13

Where:

GHGi = Annual greenhouse gas i, for each source of fugitive emissions, in metric tons;

n = Total number of component types, for each source of fugitive emissions;

j = Component type;

Nj = Total number of components of type j;

EFj = Emission factor for leaks from component type j, determined in accordance with QC.29.4.7, in metric tons per hour at standard conditions;

tj = Time during which component type j was leaking, determined in accordance with QC.29.4.7, in hours;

Ci = Concentration in natural gas of greenhouse gas i, determined in accordance with subparagraph 4 of QC.29.4.8;

i = CO2 or CH4.

QC.29.3.8. Calculation of fugitive CO2 and CH4 emissions attributable to all components not subject to a detection survey

Except for emissions from emission sources for which the total weight of CO2 and CH4 in the natural gas is below 10%, which do not need to be calculated, the annual fugitive CO2 and CH4 emissions attributable to all components not subject to a detection survey must be calculated in accordance with the following methods:

(1) the annual fugitive emissions must be calculated for each of the following sources:

(a) fugitive emissions from equipment components during:

i. underground natural gas storage;

ii. liquid natural gas storage;

iii. imports and exports of liquid natural gas;

(b) fugitive emissions from above grade meters and regulators at non-custody transfer gate stations during:

i. the compression of natural gas for onshore pipeline transmission in the case of stations with emissions below 10,000 metric tons CO2 equivalent;

ii. natural gas distribution;

(c) fugitive emissions from below grade meters and regulators during:

i. the compression of natural gas for onshore pipeline transmission;

ii. natural gas distribution;

(d) fugitive emissions from the transmission and distribution pipelines and service pipe;

(2) the annual fugitive emissions must be calculated using equation 29-14 or 29-15, depending on the emission factor used:

Equation 29-14

Equation 29-15

Where:

GHGi = Annual greenhouse gas i, for each source of fugitive emissions, in metric tons;

n = Total number of component types, for each source of fugitive emissions;

j = Component type;

Nj = Total number of components of type j;

EFj = Emission factor component type j, determined in accordance with QC.29.4.8, in metric tons per hour;

tj = Time during which component type j, associated with fugitive emissions, was operational, in hours;

Ci = Concentration in natural gas of greenhouse gas i, determined in accordance with QC.29.4.8;

i = CO2 or CH4.

To calculate fugitive emissions from the pipeline system and service pipe, equations 29-14 and 29-15 may be amended as provided in the most recent version of Methodology Manual: Estimation of Air Emissions from the Canadian Natural Gas Transmission, Storage and Distribution System, published by Clearstone Engineering Ltd.

QC.29.3.9. Calculation of CH4 emissions attributable to third party pipeline hits

The annual CH4 emissions attributable to third party pipeline hits that are equal to or greater than 1.416 m3 of CH4 at standard conditions must be calculated using equations 29-16 and 29-18, as determined under paragraph 1 of QC.29.4.9.

Equation 29-16

Equation 29-17

Where:

M = Mach number of the flow;

K = Specific heat ratio of CH4, namely 1.299;

Pa = Absolute pressure inside the pipe, determined in accordance with paragraph 2 of QC.29.4.9, in kilopascals;

Pe = Absolute pressure at the damage point, in kilopascals;

Equation 29-18

QC.29.3.10. Calculation of CO2 and CH4 emissions attributable to transmission storage tanks

Except for emissions sent to flares, which must be calculated in accordance with QC.29.3.4 using the quantities measured in accordance with paragraph 1 of QC.29.4.10, the annual CH4 and CO2 emissions attributable to compressor scrubber dump valve leakage from condensate storage tanks for either water or hydrocarbon connected to transmission storage tanks, must be calculated using equation 29-19:

Equation 29-19

QC.29.3.11. Calculation of emissions from other sources

Emissions from other sources that are not calculated using the methods in QC.29.3.1 to QC.29.3.10 must be calculated in accordance with the following methods:

(1) the methods in the most recent version of “Methodology Manuel: Estimation of Air Emissions from the Canadian Natural Gas Transmission, Storage and Distribution System” published by Clearstone Engineering Ltd.;

(2) a sector specific method published by the Canadian Gas Association.

QC.29.4. Sampling, analysis and measurement requirements

An emitter who operates a natural gas transmission and distribution enterprise must

(1) ensure that all instruments used for sampling, analysis and measurement are calibrated before the first emissions report and that for subsequent years they are calibrated and used in accordance with the instructions of the manufacturer or the methods and frequency published by the following organizations:

(a) Canadian Standards Association;

(b) Canadian Gas Association;

(c) Canadian Association of Petroleum Producers;

(d) American National Standards Institute;

(e) American Society of Testing and Materials;

(f) American Petroleum Institute;

(g) American Society of Mechanical Engineers;

(h) North American Energy Standards Board;

(i) Canadian Energy Pipeline Association;

(j) Measurement Canada;

(2) conduct leak detection surveys and manage transmission and distribution system integrity in accordance with CSA Z662-11 “Oil and gas pipeline systems” published by the Canadian Standards Association in June 2011 and in accordance with the Construction Code (chapter B-1.1, r. 2) a maximum period of 36 months must be respected between each detection period;

(3) determine the mole fraction of CO2 and CH4 in natural gas by calculating the annual average of the following mole fractions:

(a) the mole fraction in natural gas during compression for onshore pipeline transmission;

(b) the mole fraction in natural gas in underground storage facilities;

(c) the mole fraction in natural gas in liquid natural gas storage facilities;

(d) the mole fraction in natural gas in liquid natural gas import and export facilities;

(e) the mole fraction in natural gas for distribution through the system.

All high bleed pneumatic devices and natural gas driven pneumatic pumps must be equipped with meters.

QC.29.4.1. High bleed pneumatic device venting and natural gas driven pneumatic pump venting

For high bleed pneumatic device venting and natural gas driven pneumatic pump venting, the emitter must

(1) when using equation 29-2, determine the annual volume of natural gas consumed by high bleed pneumatic devices or natural gas driven pneumatic pumps using the measuring equipment installed on the device;

(2) when using equation 29-3, obtain from the device manufacturer the natural gas flow for each high bleed pneumatic device during normal operating conditions or, when the data are not available, use the flow from a similar device. If there is no similar device, the emitter must perform the calculation using the generic factors in Table 29-6 in QC.29.6;

(3) when using equation 29-4, obtain from the pneumatic pump manufacturer the natural gas flow for each pneumatic pump model in normal operating conditions or, when that data is not available, use the data for a similar device. If there is no similar device, the emitter must perform the calculation using the data in Table 29-6 in QC.29.6;

(4) obtain from the device manufacturer the specific emission factor for exhaust gas in cubic metres per litre. When that data is not available, use the factor for a similar device.

QC.29.4.2. Natural gas low bleed or intermittent bleed pneumatic device venting

For low bleed or intermittent bleed natural gas pneumatic device venting, the emitter must determine the number of natural gas low bleed pneumatic devices and the number of natural gas intermittent bleed pneumatic devices in the following manner:

(1) for the first emission report year, by counting all the devices according to type or estimating the total number of devices and apportion that number according to the estimated percentage of each type of device;

(2) for subsequent years, by updating the number of low bleed pneumatic devices and the number of intermittent bleed pneumatic devices to take annual changes into account.

QC.29.4.3. Equipment blowdown vent stacks

For equipment blowdown vent stacks, the emitter must

(1) calculate the volume of gas in blowdown equipment chambers, between isolation valves of each equipment type using a recognized estimation method based on the best data available;

(2) if the volume is greater than or equal to 1.42 m3 at standard conditions, log the annual number of blowdowns for each equipment type;

(3) (paragraph revoked).

QC.29.4.4. Flares or incinerators

For flares or incinerators, the emitter must

(1) determine the volume of gas directed to flares or incinerators, using one of the following methods:

(a) using the volumetric gas flow when the flare or incinerator is equipped with a continuous flow monitoring and recording system;

(b) estimating the unmeasured gas flow using a recognized estimation method based on the best data available when part or all of the gas is not measured by a system referred to in subparagraph a;

(2) determine the gas composition using one of the following methods:

(a) using a continuous gas composition monitoring and recording system;

(b) when the flare is not equipped with a continuous gas composition monitoring and recording system, by determining, using a recognized estimation method based on the best data available or from the supplier’s information:

i. the mole fraction of CO2 and CH4 of the gas when the stream going to the flare is natural gas;

ii. the mole fraction of the methane, ethane, propane, butane, pentane, hexane and hexane-plus when the stream going to the flare is a hydrocarbon product stream.

QC.29.4.5. Centrifugal compressors venting

For centrifugal compressors, the emitter must

(1) determine the volume of gas from a wet seal or dry seal oil degassing tank sent to an atmospheric vent and the volume of gas sent to a flare or an incinerator and the volume of emissions from isolation and drain valve vents using one of the methods described in subparagraph a of paragraph 1 of QC.29.4.6, for each operating mode, namely:

(a) the centrifugal compressor is in operating mode and the emissions are from wet seal or dry seal vents and leaks in drain valves through the blowdown vent stack;

(b) the centrifugal compressor is in standby or pressurized mode, the emissions are from wet seal or dry seal vents and leaks in drain valves through the blowdown vent stack;

(c) the centrifugal compressor is not operating and is depressurized and the emissions are from isolation valve leakage through the blowdonwn vent stack. In that case:

i. a centrifugal compressor that is not equipped with a blind flange must be sampled at least once in every 3 consecutive years;

ii. sampling is not required if a centrifugal compressor has been equipped with a blind flange for at least 3 consecutive years;

(2) when a centrifugal compressor is used for peaking purposes for less than 200 hours per year and is not equipped with a flow meter, determine the flow using a calculation method based on a device having similar specifications and operating conditions or using the emission factors of the most recent version of “Methodology Manual: Estimation of Air Emissions from the Canadian Natural Gas Transmission, Storage and Distribution System” published by Clearstone Engineering Ltd determined using equivalent sources based on the operating mode;

(3) calibrate the flow meters in accordance with the methods in paragraph 1 of QC.29.4;

(4) determine the quantity of the gas that is recovered using a vapour recovery system or destined for another use, expressed in percentage, based on the number of hours of operation of the recovery system and the quantity of gas sent to the fuel gas system.

QC.29.4.6. Reciprocating compressors venting

For reciprocating compressors, the emitter must

(1) determine the gas flow from reciprocating compressor venting using the following methods:

(a) if the reciprocating rod packing and blowdown vent is connected to an open ended vent line, the emitter must use one of the following methods to calculate the gas flow:

i. measuring the flow from all vents, including gas manifolded to common vents, using calibrated bagging in accordance with paragraph 3 or a high volume sampler in accordance with paragraph 4;

ii. measuring the flow from all vents, including gas manifolded to common vents, using a temporary or permanent flow meter in accordance with the methods in paragraph 1 of QC.29.4. In the absence of a permanent flow meter, a port for the insertion of a temporary or permanent flow meter may be installed on the vents;

iii. for through-valve leakage to open ended vents, such as deactivated unit isolation valves and depressurized compressors and blowdown valves on pressurized compressors, using an acoustic detection device in accordance with paragraph 2 of QC.29.4;

(b) when the compressor rod packing case is not equipped with a vent line, the emitter must

i. detect equipment leaks in accordance with paragraph 2 of QC.29.4;

ii. measure the gas flow using calibrated bagging in accordance with paragraph 3, a high volume sampler in accordance with paragraph 4 or a flow meter in accordance with paragraph 1 of QC.29.4;

(2) measure annually the gas flow from rod packing vents, isolation valve vents and reciprocating compressor vents, including gas manifolded to common vents, in the operating mode in which the compressor is used during the measurement period:

(a) the reciprocating compressor is in operating mode and the emissions from rod-packing vents and leaks in drain valves through the blowdown vent stack;

(b) the reciprocating compressor is in standby pressurized mode and the emissions are from rod-packing vents and leaks in drain valves through the blowdown vent stack;

(c) the compressor is in not operating, depressurized mode; the gas emitted is from isolation valve leakage through the blowdown vent stack. In that case,

i. a reciprocating compressor that is not equipped with blind flanges must be sampled at least once in every 3 consecutive years if no compressor is in this mode during the annual measurement period;

ii. flow measurement is not required when a reciprocating compressor has been equipped with blind flanges for at least 3 consecutive years;

iii. (subparagraph revoked);

(d) the reciprocating compressor is used for peaking purposes for no more than 200 hours per year and is not equipped with a meter; the flow must be determined using one of the calculation method based on a device having similar specifications and operating conditions or using the emission factors of the most recent version of “Methodology Manual: Estimation of Air Emissions from the Canadian Natural Gas Transmission, Storage and Distribution System”published by Clearstone Engineering Ltd determined using equivalent sources based on the operating mode;

(3) when using calibrated bags to measure the gas flow emitted by the reciprocating compressor vent, use the bags only where the emissions are at a pressure similar to atmospheric pressure and hydrogen sulphide levels are such that it is safe to handle. The calibrated bags must be used according to the manufacturer’s instructions and only if the entire emissions volume can be encompassed for measurement. The emitter must also

(a) record the time required to fill the bag and if the bag inflates in less than 1 second, the emitter must round up to 1 second;

(b) perform 3 measurements of the time required to fill the bag, and use the average of the measurements to calculate the gas flow;

(4) when using a high volume sampler, the measurements must be taken in accordance with the manufacturer’s instructions. The emitter must also calibrate the sampler, in accordance with the manufacturer’s instructions, at 2.5% CH4 with 97.5% air and 100% CH4 by using representative samples of known concentrations.

For the purposes of subparagraph a of subparagraph 1 of the first paragraph, the flow measurements taken may be used for a maximum period of 3 years If one of the measurements cannot be taken for safety reasons, use the emission factors of the most recent version of “Methodology Manual: Estimation of Air Emissions from the Canadian Natural Gas Transmission, Storage and Distribution System” published by Clearstone Engineering Ltd determined using equivalent sources based on the operating mode.

QC.29.4.7. Leaks identified following a detection survey

An emitter who conducts a leak detection survey must

(1) in the first emission reporting year, determine the leaker emission factor for leaks from each component type in accordance with the following methods:

(a) based on specific data for the operation of the enterprise’s devices and according to sector-specific methods;

(b) using the data in Tables 29-1 to 29-5 in QC.29.6 depending on the type of activity, namely:

i. for the compression of natural gas for onshore pipeline transmission, the emission factors shown in Table 29-1 for fugitive emissions from connectors, valves, pressure relief valves, meters and open ended lines;

ii. for underground natural gas storage, the emission factors shown in Table 29-2 for fugitive emissions from connectors, valves, pressure relief valves, meters and open ended lines;

iii. for liquefied natural gas storage, the emission factors shown in Table 29-3 for fugitive emissions from valves, pump seals, connectors and all other types of equipment components;

iv. for liquid natural gas imports and exports, the emission factors shown in Table 29-4 for fugitive emissions from valves, pump seals, connectors and all other types of equipment components;

v. for natural gas distribution, for above ground meters and regulators at custody transfer gate stations, the emission factors shown in Table 29-5 for fugitive emissions from connectors, block valves, control valves, pressure relief valves, orifice meters, regulators and open ended lines;

(2) in subsequent emission reporting years, determine emission factor for leakage from each type of device using the following methods:

(a) based on specific data for the operation of the enterprise’s devices;

(b) using the method specified in the most recent edition of “Methodology Manual: Estimation of Air Emissions from the Canadian Natural Gas Transmission, Storage and Distribution System” published by Clearstone Engineering Ltd.;

(3) determine the time during which a component was leaking, using the following methods:

(a) when one leak detection survey is conducted per year, the emitter must assume the component was leaking from the start of the year until the leak was repaired. If the leak was not repaired, the emitter must assume the component was leaking for the entire year;

(b) if multiple leak detection surveys are conducted per year, the emitter must assume that the component found to be leaking has been leaking since the previous survey. If the leak was directed during the previous survey, the emitter must assume the unrepaired component was leaking for the entire year.

QC.29.4.8. Fugitive emissions from population count and emission factors (all components)

For fugitive emissions from all components, the emitter must

(1) determine the total number of components for each component type using one of the following methods:

(a) the method in Appendix E of the most recent edition of “Methodology Manual: Estimation of Air Emissions from the Canadian Natural Gas Transmission, Storage and Distribution System” published by Clearstone Engineering Ltd.;

(b) a sector-specific method published by the Canadian Gas Association or Canadian Association of Petroleum Producers;

(c) using enterprise-specific data. The instrumentation and process plans may be used to obtain a representative average of the number of components of a piece of equipment;

(d) using the number of average components mentioned in the forms of the most recent version of “Methodology Manual: Estimation of Air Emissions from the Canadian Natural Gas Transmission, Storage and Distribution System” published by Clearstone Engineering Ltd. when the equipment is difficult to inventory;

(2) for the first emission reporting year, use the emission factor for each component type depending on the type of activity, namely,

(a) for underground natural gas storage, the emission factors shown in Table 29-2 for fugitive emissions from connectors, valves, pressure relief valves, meters and open ended lines;

(b) for liquefied natural gas storage, the emission factors shown in Table 29-3 for fugitive emissions from vapour recovery compressors except for liquefied natural gas storage on liquid natural gas import and export sites covered under subparagraph c;

(c) for imports and exports of liquid natural gas, the emission factors shown in Table 29-4 for fugitive emissions from vapour recovery compressors;

(d) for natural gas distribution:

i. the emission factors shown in Table 29-5 for fugitive emissions from below grade meters and regulators;

ii. emission factor calculated using equation 29-20 for above ground meters and regulators at non-custody transfer gate stations:

Equation 29-20

iii. the calculation of fugitive emissions from leaks from the main devices in the transmission and distribution systems may be changed to comply with the methods described in the most recent edition of “Methodology Manual: Estimation of Air Emissions from the Canadian Natural Gas Transmission, Storage and Distribution System” published by Clearstone Engineering Ltd.;

(e) for compression of natural gas for onshore transmission, use the emission factors shown in Table 29-1 for fugitive emissions from connectors, valves, pressure relief valves, meters and open ended lines;

(3) in the subsequent emission reporting years, determine the emission factor from leaks from each type of component, in accordance with the following methods:

(a) based on data specific to the operation of the enterprise’s equipment and according to the sector-specific methods, in particular methods published by the Canadian Gas Association;

(b) using the emission factors published in the most recent version of “Methodology Manual: Estimation of Air Emissions from the Canadian Natural Gas Transmission, Storage and Distribution System” published by Clearstone Engineering Ltd.;

(c) when an emission factor specific to the operation of equipment cannot be determined, using the factors provided for in Tables 29-1 to 29-5 in accordance with paragraph 2;

(4) determine the CO2 and CH4 concentrations in natural gas in accordance with the methods in the most recent edition of “Methodology Manual: Estimation of Air Emissions from the Canadian Natural Gas Transmission, Storage and Distribution System” published by Clearstone Engineering Ltd.

QC.29.4.9. Emissions attributable to third party pipeline hits

For emissions attributable to third party pipeline hits, the emitter must

(1) for a pipeline puncture incident, determine the value of P Atm / Pa

Where:

Pa = Absolute pressure inside the pipe, determined in accordance with paragraph 2 of QC.29.4.9, in kilopascals;

PAtm = Absolute pressure at the damage point, in kilopascals;

If PAtm / Pa ≥ 0.546 or if the damage is on a distribution line, calculate emissions using equation 29-18. For a pipeline puncture incident, the method may be used individually or in aggregate for all punctures of pipes of a given type and pressure, using mass balance averages.

If PAtm / Pa < 0.546 or if the damage is on a transmission line, calculate emissions using equations 29-16 and 29-17.

When the leak flow rate is determined by measuring instruments, use a standard method applied in the industrial sector.

(2) determine the pressure inside the pipe by measurement or an engineering estimation:

(a) for a catastrophic pipeline rupture, at the place where the ruptured pipeline joins a larger pipeline;

(b) for a pipeline puncture incident, at the damage point;

(3) determine the pipeline leak area by measurement or an engineering estimation.

QC.29.4.10. Fugitive emissions from transmission storage tanks

For transmission storage tanks, the emitter must

(1) to measure compressor scrubber dump valve leakage from condensate storage tanks connected to transmission storage tanks, determine the emission factor for leaks from each type of component using the following methods:

(a) using equipment specific factors for the operation of the enterprise’s equipment;

(b) using the method in the most recent version of “Methodology Manuel: Estimation of Air Emissions from the Canadian Natural Gas Transmission, Storage and Distribution System” published by Clearstone Engineering Ltd.;

(2) determine the duration of the equipment leakage, using the following methods:

(a) when only one leak detection survey is conducted each year, the emitter must assume that the component was leaking from the start of the year until the leak was repaired. If the leak was not repaired, the emitter must assume that the component was leaking for the entire year;

(b) when more than one leak detection survey is conducted each year, the emitter must assume that the component has been leaking since the last survey. If a leak was detected at the last survey, the emitter must assume that the component, unless the leak has been repaired, was leaking for the entire year.

QC.29.5. Methods for estimating missing data

When, as part of an emitter’s sampling activities, the emitter is unable to obtain analytical data, the emitter must, using the methods prescribed in this Protocol, re-analyze the original sample, a backup sample or a replacement sample for the same measurement and sampling period.

When sampling or measurement data required by this Protocol for the calculation of emissions is missing, the emitter must demonstrate that everything has been done to capture 100% of the data. The emitter must then use replacement data, established as follows:

(1) when the missing data concern carbon content, high heat value, molecular mass, molar fraction, temperature, pressure or sampled data,

(a) determine the sampling or measurement rate using the following equation:

Equation 29-21

R = QS Act/QS Required

Where:

R = Actual sampling or measurement rate, expressed as a percentage;

QS Act = Quantity of actual samples or measurements obtained by the emitter;

QS Required = Quantity of samples or measurements required under QC.29.4;

(b) for data that require sampling or analysis,

i. if R ≥ 0.9: replace the missing data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. If no data are available from before that period, the emitter must use the first available data from after the period for which the data is missing;

ii. if 0.75 ≤ R < 0.9: replace the missing data by the highest data value sampled or analyzed during the report year for which the calculation is made;

iii. if R < 0,75: replace the missing data by the highest data value sampled or analyzed during the 3 preceding years;

(2) when the missing data concern operating time, gas quantity, liquid quantity or gas flow rate, the replacement data must be estimated on the basis of all the data relating to the processes used.

QC.29.6 Tables

Table 29-1. Emission factors for natural gas leaks by component type during compression for onshore transmission or for any component using non-odorized natural gas

(QC.29.3.2, QC.29.3.4(2), QC.29.4.7(1), QC.29.4.8(1) and (3))

Leaker emission factors by component type
Component type	Components not in detection survey	Components in detection survey
	Naturas gas (metric tons/hour)	Naturas gas (metric tons/hour)
Connector	4.471 × 10-7	4.484 × 10-5
Block valve	4.131 × 10-6	1.275 × 10-4
Control valve	1.650 × 10-5	8.205 × 10-5
Compressor blowdown valve	3.405 × 10-3	5.691 × 10-3
Pressure relief valve	1.620 × 10-4	5.177 × 10-4
Orifice meter	4.,863 × 10-5	2.076 × 10-4
Other flow meter	9.942 × 10-9	3.493 × 10-7
Regulator	7.945 × 10-6	1.125 × 10-4
Open ended line	9.183 × 10-5	1.580 × 10-4
Fugitive emission factors for each component type
Component type		Total organic carbon (m3/hour)
Low bleed pneumatic device		3.88 × 10-2
High bleed pneumatic device		2.605 × 10-1
Intermittent bleed pneumatic device (high bleed)		2.476 × 10-1
Intermittent bleed pneumatic device (low bleed)		6.65 × 10-2
Diaphragm pumps		1.0542
Piston pumps		5.917 × 10-1

Table 29-2. Emission factors for natural gas leaks by component type during underground storage

(QC.29.3.2, QC.29.3.4(2), QC.29.4.7(1), QC.29.4.8(2))

 _________________________________________________________________________________
|                                                              |                  |
| Component type                                               |   Natural gas    |
|                                                              |    (m3/hour)     |
|______________________________________________________________|__________________|
|                                                                                 |
| Leaker emission factors by component type following detection survey            |
|_________________________________________________________________________________|
|                                                              |                  |
| Valve                                                        |      0.4268      |
|______________________________________________________________|__________________|
|                                                              |                  |
| Connector                                                    |      0.1600      |
|______________________________________________________________|__________________|
|                                                              |                  |
| Open ended line                                              |      0.4967      |
|______________________________________________________________|__________________|
|                                                              |                  |
| Pressure relief valve                                        |      1.140       |
|______________________________________________________________|__________________|
|                                                              |                  |
| Meter                                                        |      0.5560      |
|______________________________________________________________|__________________|
|                                                                                 |
| Fugitive emission factors for component group                                   |
|_________________________________________________________________________________|
|                                                              |                  |
| Connector                                                    |    2.8 x 10-4    |
|______________________________________________________________|__________________|
|                                                              |                  |
| Valve                                                        |    2.8 x 10-3    |
|______________________________________________________________|__________________|
|                                                              |                  |
| Pressure relief valve                                        |    4.8 x 10-3    |
|______________________________________________________________|__________________|
|                                                              |                  |
| Open ended line                                              |    8.5 x 10-4    |
|______________________________________________________________|__________________|
|                                                              |                  |
| Low bleed pneumatic device                                   |    3.88 x 10-2   |
|______________________________________________________________|__________________|
|                                                              |                  |
| High bleed pneumatic device                                  |    2.605 x 10-1  |
|______________________________________________________________|__________________|
|                                                              |                  |
| Intermittent bleed pneumatic device (high bleed)             |    2.476 x 10-1  |
|______________________________________________________________|__________________|
|                                                              |                  |
| Intermittent bleed pneumatic device (low bleed)              |    6.65 x 10-2   |
|______________________________________________________________|__________________|
|                                                              |                  |
| Diaphragm pumps                                              |    1.0542        |
|______________________________________________________________|__________________|
|                                                              |                  |
| Piston pumps                                                 |    5.917 x 10-1  |
|______________________________________________________________|__________________|    

Table 29-3. Emission factors for natural gas leaks by component type during liquefied natural gas storage

(QC.29.4.7(1), QC.29.4.8(2))

 _________________________________________________________________________________
|                                                              |                  |
| Component type                                               |    Natural gas   |
|                                                              |     (m3/hour)    |
|______________________________________________________________|__________________|
|                                                                                 |
| Leaker emission factor by component type following leak detection survey        |
|_________________________________________________________________________________|
|                                                              |                  |
| Valve                                                        |    3.43 x 10-2   |
|______________________________________________________________|__________________|
|                                                              |                  |
| Pump seal                                                    |    1.15 x 10-1   |
|______________________________________________________________|__________________|
|                                                              |                  |
| Connector                                                    |     9.9 x 10-3   |
|______________________________________________________________|__________________|
|                                                              |                  |
| Other                                                        |    5.10 x 10-2   |
|______________________________________________________________|__________________|
|                                                                                 |
| Fugitive emission factor by component type                                      | 
|_________________________________________________________________________________|
|                                                              |                  |
| Vapor recovery compressor                                    |    1.20 x 10-1   | 
|______________________________________________________________|__________________|                        

Table 29-4. Emission factors for natural gas leaks by component type during imports and exports of liquid natural gas

(QC.29.4.7(1), QC.29.4.8(2))

 _________________________________________________________________________________
|                                                              |                  |
| Component type                                               |    Natural gas   |
|                                                              |     (m3/hour)    |
|______________________________________________________________|__________________|
|                                                                                 |
| Leaker emission factor by component type following leak detection survey        |
|_________________________________________________________________________________|
|                                                              |                  |
| Valve                                                        |    3.43 x 10-2   |
|______________________________________________________________|__________________|
|                                                              |                  |
| Pump seal                                                    |    1.15 x 10-1   |
|______________________________________________________________|__________________|
|                                                              |                  |
| Connector                                                    |    9.90 x 10-3   |
|______________________________________________________________|__________________|
|                                                              |                  |
| Other                                                        |    5.10 x 10-2   |
|______________________________________________________________|__________________|
|                                                                                 |
| Fugitive emission factor by component type                                      | 
|_________________________________________________________________________________|
|                                                              |                  |
| Vapor recovery compressor                                    |    1.20 x 10-1   | 
|______________________________________________________________|__________________|                        

Table 29-5. Emission factors for natural gas leaks by component during natural gas distribution or for any component using odorized natural gas

(QC.29.4.7(1), QC.29.4.8(2))

Leak emission factors by component type following detection survey
Component type	Components not in detection survey Natural gas (tonnes/hour)	Components in detection survey Natural gas (tonnes/hour)
Connector	8.227 x 10-8	6.875 x 10-6
Block valve	5.607 x 10-7	1.410 x 10-5
Control valve	1.949 x 10-5	7.881 x 10-5
Pressure relief valve	3.944 x 10-6	3.524 x 10-5
Orifice meter	3.011 x 10-6	8.091 x 10-6
Other flow meter	7.777 x 10-9	2.064 x 10-7
Regulator	6.549 x 10-7	2.849 x 10-5
Open ended line	6.077 x 10-5	1.216 x 10-4
Fugitive emission factors for component group
Component type		Natural gas m3/hour
Below grade meter and regulator, inlet pressure greater than 300 psig		3.681 x 10-2
Below grade meter and regulator, inlet pressure between 100 and 300 psig		5.663 x 10-3
Below grade meter and regulator, inlet pressure below 100 psig		2.832 x 10-3
Fugitive emission factors for each type of transmission pipeline
Pipeline type		Natural gas m3/hour
Unprotected steel		2.427 x 10-1
Protected steel		6.829 x 10-3
Plastic		7.969 x 10-3
Fugitive emission factors for each type of service pipe
Pipeline type		Natural gas m3/hour/service pipe
Unprotected steel		5.953 x 10-3
Protected steel		6.270 x 10-4
Plastic		4.036 x 10-5
Copper		8.829 x 10-4

Table 29-6. Manufacturer bleed and pressure coefficients for leaks from high bleed pneumatic devices, intermittent bleed pneumatic devices (high bleed), level controllers, pressure and pump controllers and equivalent devices

(QC.29.3.1, QC.29.3.2)

QC.30. FUEL DISTRIBUTION

QC.30.1. Covered sources

For the purposes of this protocol, “fuel” means automotive gasolines, diesels, propane, butane, kerosene, coal coke, petroleum coke, coal, distillation gas, ethanol, biodiesel, biomethane, natural gas and heating fuel oils, with the exception of

(1) fuel used in air or water navigation;

(2) hydrocarbons used as a raw material by industries that use chemical and petrochemical processes to transform hydrocarbon molecules;

(3) (subparagraph revoked);

For the purposes of the emissions report referred to in the third paragraph of section 6.1 and this protocol, whoever is the first in Québec to perform one of the following activities for fuels is considered an emitter who distributes fuels:

(1) any form of trade or sale by a person or municipality, for consumption in Québec, of fuels that are refined, manufactured, mixed, prepared or distilled in Québec by that person or municipality;

(1.1) the sale or trade in Québec, for consumption, trade or sale in Québec, of fuel from outside Québec, other than natural gas distributed by a natural gas distributor within the meaning of section 2 of the Act respecting the Régie de l’énergie (chapter R-6.01);

(2) the importing into Québec, for consumption, trade or sale in Québec, of fuels, other than natural gas distributed by a natural gas distributor within the meaning of section 2 of the Act respecting the Régie de l’énergie;

(3) the distribution of natural gas for consumption in Québec by a natural gas distributor within the meaning of section 2 of the Act respecting the Régie de l’énergie.

For the purposes of subparagraph 1 1 of the second paragraph, the sale is considered made in Québec when the fuels brought into Québec are owned by a seller from outside Québec.

For the purposes of subparagraph 2 of the second paragraph, the importation is considered made in Québec

(1) where the fuels come from outside Canada, when they are owned by a buyer in Québec who imports within the meaning of the Customs Act (R.S.C. 1985, c. 1 (2nd Suppl.)) at the time they are brought into Québec; and

(2) where the fuels come from another province or a territory of Canada, when they are owned by a buyer in Québec at the time they are brought into Québec.

Despite the foregoing, the buyer and the seller referred to in the third and fourth paragraphs may enter into an agreement in which they identify which of them is considered an emitter distributing fuel for the purposes of the emissions report referred to in the third paragraph of section 6 1 and for the purposes of this protocol The person thus designated must comply with all the requirements imposed on a fuel distributor under this Regulation If the designated person fails to declare the emissions covered by the agreement, the person who should have declared the emissions under this Regulation if no agreement had been entered into is required to remedy the situation as soon as possible.

Subparagraphs 1.1 and 2 of the second paragraph do not apply to fuels contained in the fuel tank installed as standard equipment to supply a vehicle’s engine or to fuels in a sealed container of 1 litre or less.

QC.30.2. Greenhouse gas reporting requirements

The greenhouse gas emissions report referred to in section 6.2 must include the following information and documents:

(1) the annual emissions attributable to the use of fuel distributed for consumption in Québec, in metric tons CO2 equivalent, excluding fuels, other than those used for transport purposes, used by an emitter referred to in the first paragraph or in subparagraph 3 of the second paragraph of section 2 or section 2.1 of the Regulation respecting a cap-and-trade system for greenhouse gas emission allowances (chapter Q-2, r. 46.1) and that is required to cover its greenhouse gas emissions under that Regulation;

(2) for each type of fuel, the total annual quantity of fuel distributed for consumption in Québec, including firstly and excluding secondly the total annual quantities of fuels used by an emitter referred to in subparagraph 1, and fuels acquired outside Québec by the emitter for the emitter’s own consumption;

(3) the name and contact information of the establishments of each emitter referred to in the first paragraph or in subparagraph 3 of the second paragraph of section 2 or section 2.1 of the Regulation respecting a cap-and-trade system for greenhouse gas emission allowances and required to cover its greenhouse gas emissions under that Regulation to which the emitter has distributed fuel during the year, along with the total annual quantity distributed to each of those establishments, by type of fuel;

(3.1) the name and contact information of the establishments of each person to whom the emitter distributed fuel outside Québec, and the total annual quantity distributed to each establishment, by type of fuel;

(3.2) in the cases referred to in subparagraphs 3 and 3.1 and in the case where an emitter is able to show that the quantity of fuel distributed by the emitter in Québec was ultimately redistributed to the establishment of an emitter referred to in the first paragraph or in subparagraph 3 of the second paragraph of section 2 or section 2.1 of the Regulation respecting a cap-and-trade system for greenhouse gas emission allowances or to a person outside Québec, an attestation signed by the person responsible for the declaration at the establishment or in the case of a person outside Québec, by the person who actually received the fuel from the emitter who confirms the total quantity received during the year, for each type of fuel, and the numbers of the protocols associated with the consumption of the types of fuel, for each establishment concerned;

(3.3) in the case where an agreement has been entered into between the seller and the buyer under the fifth paragraph of QC.30.1, the name and contact information of each of the parties, the date on which the agreement was entered into and the type and total annual quantity of fuel covered by the agreement;

(4) the number of times the methods for estimating missing data provided for in QC.30.5 were used.

For the purposes of the first paragraph, the quantities must be expressed in thousands of cubic metres at standard conditions in the case of fuel the quantity of which is expressed as a volume of gas, in kilolitres in the case of fuel the quantity of which is expressed as a volume of liquid and in bone dry metric tons in the case of fuel the quantity of which is expressed as a mass.

QC.30.3. Calculation methods for CO2 emissions

The annual CO2 equivalent emissions attributable to the use of fuel distributed for consumption in Québec must be calculated using equation 30-1:

Equation 30-1

Where:

CO2 = Annual emissions attributable to the use of fuel distributed for consumption in Québec, in metric tons CO2 equivalent;

n = Number of fuels distributed for consumption in Québec;

i = Fuel;

Qi = Annual quantity of distributed fuel i, calculated using equation 30-2, expressed

— in thousand cubic metres at standard conditions, in the case of fuels the quantity of which is expressed in gas volume;

— in kilolitres, in the case of fuels the quantity of which is expressed in liquid volume;

EFi = Emission factor for fuel i, as indicated in Table 30-1 in QC.30.6, expressed

— in metric tons of CO2 equivalent per thousand cubic metre at standard conditions, in the case of fuels the quantity of which is expressed in gas volume;

— in metric tons of CO2 equivalent per kilolitre, in the case of fuels the quantity of which is expressed in liquid volume;

Equation 30-2

Qi = QiT − QiG                        

Where:

Qi = Annual quantity of fuel i distributed,

— in thousands of cubic metres at standard conditions, in the case of fuels the quantity of which is expressed in gas volume;

— in kilolitres, in the case of fuels the quantity of which is expressed in liquid volume;

QiT = Total annual quantity of fuel i distributed for consumption in Québec or acquired outside Québec by the emitter for the emitter’s own consumption, measured in accordance with QC.30.4, that is,

— in thousands of cubic metres at standard conditions, in the case of fuels the quantity of which is expressed in gas volume;

— in kilolitres, in the case of fuels the quantity of which is expressed in liquid volume;

QiG = Total annual quantity of fuel i, other than fuel used for transport purposes, distributed to an emitter for the emitter’s establishments referred to in the first paragraph or in subparagraph 3 of the second paragraph of section 2 or section 2.1 of the Regulation respecting a cap-and-trade system for greenhouse gas emission allowances that is required to cover greenhouse gas emissions (chapter Q-2, r. 46.1) pursuant to that Regulation, measured in accordance with QC.30.4, that is,

— in thousands of cubic metres at standard conditions, in the case of fuels the quantity of which is expressed in gas volume;

— in kilolitres, in the case of fuels the quantity of which is expressed in liquid volume.

QC.30.4. Sampling, analysis and measurement requirements

An emitter who operates an enterprise that distributes fuel must ensure that the instruments used to measure quantities of fuel are calibrated in accordance with one of the following methods:

(1) calibrate, prior to the first emissions report and for subsequent years in accordance with the instructions of the manufacturer, at the maximum frequency specified by the manufacturer or once per year;

(2) in accordance with the methods, frequency and specifications determined by Measurement Canada.

An emitter who operates an enterprise that distributes fuel must measure the quantity of fuel at the following points, according to the type of activity carried out:

(1) for the activities referred to in subparagraphs 1, 1.1 and 2 of the second paragraph of QC.30.1, at the primary distribution point or, as the case may be, at the point of consumption, or, if such measurement cannot be made, the emitter must obtain the quantities from the supplier;

(2) for the activity referred to in subparagraph 3 of the second paragraph of QC.30.1, at the point of delivery.

For the purposes of subparagraph 1 of the second paragraph, an emitter who adds hydrocarbons to fuel that is to be reported by another emitter must subtract those quantities of fuel from the quantities of fuel measured.

QC.30.5. Method for estimating missing data

The emitter must be able to demonstrate that everything has been done to capture 100% of the data.

When the missing data concern the quantity of fuel distributed, the replacement data must be estimated on the basis of all the data relating to the processes used of or the data used for inventory purposes.

QC.30.6. Table

Table 30-1. Fuel emission factors, in CO2 equivalent

(QC.30.3)

Liquid fuels	Emission factor (metric tons CO2 equivalent per kilolitre)
Automotive gasolines	2.371
Diesels	2.995
Kerosene	2.543
Light oils (0, 1 and 2)	2.734
Heavy oils (4, 5 and 6)	3.146
Propane	1.543
Butane	1.763
Liquified natural gas	1.178
Liquified petroleum coke	3.837
Ethanol (100%)*	0.082
Biodiesel (100%)*	0.123
Gaseous fuels	Emission factor (metric tons CO2 equivalent per thousand cubic metres)
Natural gas	1.889
Compressed natural gas	1.923
Biomethane*	0.011
Distillation gas (refinery)	1.757
Solid fuels	Emission factor (metric tons CO2 equivalent per metric ton)
Coal coke	2.487
Petroleum coke	3.454
Coal	2.397

* Emission factor excluding CO2 emissions.

QC.31. TITANIUM DIOXIDE PRODUCTION

QC.31.1. Covered sources

The covered sources are all the chloride processes used for the production of titanium dioxide.

QC.31.2. Greenhouse gas reporting requirements

In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:

(1) the annual CO2, CH4 and N2O emissions attributable to the use of stationary combustion units, calculated and reported in accordance with QC.1, in metric tons;

(2) the annual CO2 emissions attributable to the coke used in the chloride process as a reducing agent, in metric tons;

(3) the annual quantity of coke used in the chloride process as a reducing agent, in metric tons;

(4) the average annual carbon content of the coke used in the chloride process as a reducing agent, in metric tons of carbon per metric ton of coke;

(5) the annual quantity of waste, in dry metric tons;

(6) the average annual carbon content of the waste, in metric tons of carbon per dry metric ton of waste;

(6.1) the annual quantity of limestone used, in metric tons;

(6.2) the average annual carbon content of the limestone used, in metric tons of carbon per metric ton of limestone;

(7) the number of times that the methods for estimating missing data provided for in QC.31.5 were used;

(8) the annual quantity of each product used to calculate the quantity of titanium oxide pigment equivalent, in metric tons;

(9) the annual quantity of titanium oxide pigment equivalent, in metric tons.

Subparagraphs 4, 6 and 6.2 of the first paragraph do not apply to the CO2 emissions of an emitter who calculates emissions using data from a continuous emission monitoring and recording system.

For the purposes of subparagraph 8 of the first paragraph of section 6.2:

(1) the emissions referred to in subparagraph 2 of the first paragraph are emissions attributable to fixed processes;

(2) the emissions referred to in subparagraph 1 of the first paragraph are emissions attributable to combustion.

QC.31.3. Calculation methods for CO2 emissions attributable to titanium dioxide processes

The annual CO2 emissions attributable to titanium dioxide production processes must be calculated in accordance with one of the methods in QC.31.3.1 and QC.31.3.2.

QC.31.3.1. Use of a continuous emission monitoring and recording system

The annual CO2 emissions may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.1.3.4.

QC.31.3.2. Calculation by mass balance

The annual CO2 emissions attributable to the carbonaceous materials used in the chloride process as reducing agents may be calculated using equation 31-1:

Equation 31-1

CO2 = [(RA × CCRA) - (Mwaste × CCwaste) + (LS × CCLS)] × 3.664

Where:

CO2 = Annual CO2 emissions attributable to the coke used in the chloride process as a reducing agent, in metric tons;

RA = Annual consumption of coke used in the chloride process as a reducing agent, in metric tons;

CCRA = Average annual carbon content of the coke used in the chloride process as a reducing agent, in metric tons of carbon per metric ton of coke;

Mwaste = Annual quantity of waste used, in dry metric tons;

CCwaste = Average annual carbon content of waste, in metric tons of carbon per dry metric ton of waste;

LS = Annual quantity of limestone used, in metric tons;

CCLS = Average annual carbon content of limestone, in metric tons of carbon per metric ton of limestone;

3.664 = Ratio of molecular weights, CO2 to carbon.

QC.31.4. Sampling, analysis and measurement requirements

When the calculation method in QC.31.3.2 is used, an emitter who operates a facility or establishment that produces titanium dioxide must

(1) determine the carbon content of the coke, either by using data from the material supplier or by analyzing a minimum of 3 representative samples per year using one of the following methods:

(a) the most recent version of ASTM D5373 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal”;

(b) the most recent version of ASTM D3176 “Standard Practice for Ultimate Analysis of Coal and Coke”;

(c) any other analysis method published by an organization listed in QC.1.5;

(2) calculate the annual quantity of coke used, using the same plant instruments used for inventory purposes, such as weigh hoppers or belt weigh feeders or using the supply documentation;

(3) based on the data determined in accordance with paragraph 1, calculate annually the average annual carbon content of the coke using equation 1-18 in QC.1.5.5 by replacing the quantity of fuel by the quantity of coke;

(4) determine annually the average carbon content of the waste using an annual composite sample based on monthly composite samples in accordance with the most recent version of method MA. 310-CS 1 of the Centre d’expertise en analyse environnementale du Québec;

(5) determine annually the average carbon content of limestone in accordance with an analysis method published by an organization referred to in QC.1.5;

(5.1) calculate the annual quantity of limestone used by weighing the limestone using the same plant instruments used for inventory purposes, such as mass balances, weight hoppers or belt weight feeders;

(6) calculate the annual quantity of waste used by weighing the waste using the same plant instruments as those used for inventory purposes, such as mass balances, weigh hoppers or belt weight feeders;

(7) calculate the annual quantity of each product used to determine the annual quantity of titanium oxide pigment equivalent by weighing the products using the same plant instruments as those used for inventory purposes, such as weigh hoppers or belt weight feeders.

QC.31.5. Methods for estimating missing data

When, in conducting sampling activities, an emitter is unable to obtain analytical data, the original sample, back-up sample or replacement sample must be analyzed again, using the methods prescribed in this protocol, for the same measurement and sampling periods.

When sampling or measurement data required by this protocol for the calculation of emissions is missing, the emitter must demonstrate that everything possible has been done to ensure that 100% of the data is sampled. The emitter must then use replacement data determined as follows:

(1) for an emitter who uses one of the calculation methods in this protocol:

(a) when the missing value concerns carbon content or other sampled data, the emitter must

i. determine the sampling or measurement rate using the following equation:

Equation 31-2

S = QEReal/QEReq

Where:

S = Actual sampling rate or measurement rate, expressed as a percentage;

QEReal = Actual number of samples or measurements carried out by the emitter;

QEReq = Number of samples or measurements required under QC.31.4;

ii. for data requiring sampling or analysis, the emitter must

— when T ≥ 0.9: replace the missing value by the arithmetic average of the data sampled or measured immediately preceding and following the missing data period. If no data are available prior to the missing data period, the emitter must use the first data obtained after the missing data period;

— when 0.75 ≤ T < 0.9: replace the missing value by the highest value sample or analyzed during the report year for which the calculation is made;

— when T < 0.75: replace the missing value by the highest value sample or analyzed during the 3 preceding years;

(b) when the missing value concerns coke consumption, the annual quantity of each product used to determine the annual quantity of titanium oxide pigment equivalent, the quantity of waste or the quantity of limestone, the replacement value must be estimated on the basis of all the data relating to the processes used;

(2) for an emitter who uses a continuous emission monitoring system, apply the procedure in the EPS 1/PG/7 protocol entitled “Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation” published in November 2005 by Environment Canada or apply the method in subparagraph a of paragraph 2 of QC.1.6 to the missing parameters.

QC.32. TITANIUM DIOXIDE SLAG FROM ILMENITE REDUCTION AND MOLTEN CAST IRON TREATMENT

QC.32.1. Covered sources

The covered sources are processes of titanium dioxide slag production from ilmenite reduction and molten cast iron treatment.

QC.32.2. Greenhouse gas reporting requirements

In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:

(1) the total annual CO2 emissions attributable to ilmenite reduction, in metric tons;

(2) the total annual CO2 emissions attributable to molten cast iron treatment, in metric tons;

(3) the annual CO2, CH4 and N2O emissions attributable to the use of stationary combustion units, calculated and reported in accordance with QC.1, in metric tons;

(4) for the ilmenite reduction process:

(a) the annual consumption of each type of ilmenite, in metric tons;

(b) the annual consumption of each material used, other than ilmenite, that contributes 0.5% or more of the total carbon in the process, in metric tons;

(c) the annual consumption of carbon electrodes, in metric tons;

(d) the annual production of molten cast iron, in metric tons;

(e) the annual production of titanium dioxide (TiO2) cast at the reduction furnaces slag, in metric tons;

(f) the annual quantity of air pollution control residue collected, in metric tons;

(g) the annual quantity of waste other than those referred to in subparagraph f, in metric tons;

(5) in the calculation of the treatment of molten cast iron:

(a) in the annual consumption of molten cast iron, in metric tons;

(b) in the annual consumption of each material used, other than molten cast iron, that contributes 0.5% or more of the total carbon in the process, in metric tons;

(c) the annual production of treated cast iron, in metric tons;

(d) the annual quantity of slag produced, in metric tons;

(e) the annual quantity of waste from the antipollution system, in metric tons;

(f) the annual quantity of waste other than those referred to in subparagraph e, in metric tons;

(6) the carbon content of the materials and products in the ilmenite reduction process and molten cast iron treatment process referred to in subparagraphs 4 and 5 that contribute 0.5% or more of the total carbon in the process, in metric tons of carbon per metric ton of material and products;

(7) the number of times that the methods for estimating missing data provided for in QC.32.5 were used.

Subparagraph 6 of the first paragraph does not apply to the CO2 emissions of an emitter who calculates emissions using data from a continuous emission monitoring and recording system.

For the purposes of subparagraph 8 of the first paragraph of section 6.2:

(1) the emissions referred to in paragraphs 1 and 2 of the first paragraph are emissions attributable to fixed processes;

(2) the emissions referred to in paragraph 3 of the first paragraph are emissions attributable to combustion.

QC.32.3. Calculation methods for CO2 emissions

The emitter must calculate the annual CO2 emissions attributable to ilmenite reduction and molten cast iron treatment processes in accordance with one of the methods in QC.32.3.1 to QC.32.3.3.

QC.32.3.1. Use of a continuous emission monitoring and recording system

The annual CO2 emissions attributable to ilmenite reduction and molten cast iron treatment processes may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.1.3.4.

QC.32.3.2. Calculation of annual CO2 emissions attributable to the ilmenite reduction process

The annual CO2 emissions attributable to the ilmenite reduction process may be calculated using equation 32-1. Materials or products whose carbon content contributes less than 0.5% of the carbon in the process do not need to be considered in the calculation.

Equation 32-1

Where:

CO2 = Annual CO2 emissions attributable to ilmenite reduction, in metric tons;

n = Number of types of ilmenite;

i = Type of ilmenite;

ILi = Annual consumption of ilmenite i, in metric tons;

CCIL,i = Average annual carbon content of ilmenite i, in metric tons of carbon per metric ton of ilmenite i;

p = Number of materials other than ilmenite used;

k = Material other than ilmenite used;

Mk = Annual quantity of each material k other than ilmenite used, in metric tons;

CCM,k = Average annual carbon content of each material k other than ilmenite used, in metric tons of carbon per metric ton of material k;

EL = Annual consumption of carbon electrodes, in metric tons;

CCEL = Average annual carbon content of the carbon electrodes, in metric tons of carbon per metric ton of carbon electrodes;

I = Annual production of molten cast iron, in metric tons;

CCI = Average annual carbon content of the molten cast iron produced, in metric tons of carbon per metric ton of molten cast iron;

SL = Annual production of TiO2 slag, in metric tons;

CCSL = Average annual carbon content of the TiO2 slag, in metric tons of carbon per metric ton of TiO2 slag;

R = Annual quantity of air pollution control residue collected, in metric tons;

CCR = Average annual carbon content of the air pollution control residue collected or a default value of 0, in metric tons of carbon per metric ton of residue;

W = Annual quantity of other waste produced, in metric tons;

CCW = Average annual carbon content from other waste produced or a default value of 0, in metric tons of carbon per metric ton of waste;

3.664 = Ratio of molecular weights, CO2 to carbon.

QC.32.3.3. Calculation of annual CO2 emissions attributable to the treatment of molten cast iron

The annual CO2 emissions attributable to the treatment of molten cast iron may be calculated using equation 32.2. Materials or products whose carbon content contributes less than 0.5% of the carbon in the process do not need to be considered in the calculation.

Equation 32-2

Where:

CO2 = Annual CO2 emissions attributable to the treatment of molten cast iron, in metric tons;

IT = Annual quantity of molten cast iron treated, in metric tons;

CIT = Average annual carbon content of molten cast iron treated, in metric tons of carbon per metric ton of molten cast iron;

p = Number of materials used other than molten cast iron;

k = Material used other than molten cast iron;

Mk = Annual quantity of each material k used, other than molten cast iron, in metric tons;

CM,k = Annual average carbon content of each material k used, other than molten cast iron, in metric tons of carbon per metric ton of material;

IPi = Annual quantity of molten cast iron produced after treatment, in metric tons;

CIP,i = Average annual carbon content of molten cast iron after treatment, in metric tons of carbon per metric ton of molten cast iron after treatment;

n = Number of types of molten cast iron;

i = Type of molten cast iron;

SL = Annual quantity of slag produced, in metric tons;

CSL = Average annual carbon content of slag produced or a default value of 0, in metric tons of carbon per metric ton of slag produced;

R = Annual quantity of air pollution control residue collected, in metric tons;

CR = Average annual carbon content of air pollution control residue collected or a default value of 0, in metric tons of carbon per metric ton of residue;

Rp = Annual quantity of other residue produced, in metric tons;

CRp = Average annual carbon content of other residue produced or a default value of 0, in metric tons of carbon per metric ton of residue;

3.664 = Ratio of molecular weights, CO2 to carbon.

QC.32.4. Sampling, analysis and measurement requirements

QC.32.4.1. Carbon content

When the calculation methods in QC.32.3.2 and QC.32.3.3 are used, the emitter who operates a facility or establishment that uses an ilmenite reduction process and a molten cast iron treatment process must, for materials or products whose carbon content contributes 0.5% or more of the carbon in the process, use the data provided by the supplier or determine the carbon content by analyzing a minimum of 3 representative samples per year using the following methods:

(1) for fossil fuels, in accordance with QC.1.5.5;

(2) for the materials used in the ilmenite reduction process or the TiO2 slag produced, in accordance with an analysis method published by an organization referred to in QC.1.5;

(3) for coal, coke and the carbon electrodes used in electric arc furnaces, using the most recent version of ASTM D5373 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal”, or using any other analysis method published by an organization listed in QC.1.5;

(4) for fuels, feedstock or liquid products, using the most recent version of ASTM D7582 “Standard Test Methods for Proximate Analysis of Coal and Coke by Macro Thermogravimetric Analysis”, or using any other analysis method published by an organization listed in QC.1.5;

(5) for molten cast iron, using the most recent version of ASTM E1019 “Standard Test Methods for Determination of Carbon, Sulfur, Nitrogen, and Oxygen in Steel, Iron, Nickel, and Cobalt Alloys by Various Combustion and Fusion Techniques” or ASTM E415 “Standard Test Method for Atomic Emission Vacuum Spectrometric Analysis of Carbon and Low-Alloy Steel”, or using any other analysis method published by an organization listed in QC.1.5;

(6) for slag, air pollution control residue or other residue, using an analysis method published by an organization listed in QC.1.5 or using a default value of 0.

QC.32.4.2. Consumption of process materials

The emitter must determine the quantity of solid, liquid and gaseous materials and the quantities required for the calculation in equation 32-1 or 32-2 using the same plant instruments as those used for inventory purposes, such as weigh hoppers or belt weigh feeders.

QC.32.5. Methods for estimating missing data

When, in conducting sampling activities, an emitter is unable to obtain analytical data, the original sample, back-up sample or replacement sample must be analyzed again, using the methods prescribed in this protocol, for the same measurement and sampling periods.

When sampling or measurement data required by this protocol for the calculation of emissions is missing, the emitter must demonstrate that everything possible has been done to ensure that 100% of the data is sampled. The emitter must then use replacement data determined as follows:

(1) for an emitter who uses one of the calculation methods in this protocol:

(a) when the missing value concerns carbon content or another sampled value, the emitter must

i. determine the sampling or measurement rate using the following equation:

Equation 32-3

S = QEReal/QEReq

Where:

S = Actual sampling rate or measurement rate, expressed as a percentage;

QEReal = Actual number of samples or measurements carried out by the emitter;

QEReq = Number of samples or measurements required under QC.32.4;

ii. for data requiring sampling or analysis, the emitter must

— when T ≥ 0.9: replace the missing value by the arithmetic average of the data sampled or measured immediately preceding and following the missing data period. If no data are available prior to the missing data period, the emitter must use the first data obtained after the missing data period;

— when 0.75 ≤ T < 0.9: replace the missing value by the highest value sample or analyzed during the report year for which the calculation is made;

— when T < 0.75: replace the missing value by the highest value sample or analyzed during the 3 preceding years;

(b) when the missing value concerns the consumption of ilmenite, the consumption of raw materials, the consumption of carbon electrodes, the quantity of molten cast iron treated, the production of slag, the production of molten cast iron or the production of other by-products, the replacement value must be estimated on the basis of all the data relating to the processes used;

(2) for an emitter who uses a continuous emission monitoring system, apply the procedure in the EPS 1/PG/7 protocol entitled “Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation” published in November 2005 by Environment Canada or apply the method in subparagraph a of paragraph 2 of QC.1.6.

QC.33. OIL AND NATURAL GAS EXPLORATION AND PRODUCTION AND NATURAL GAS PROCESSING

QC.33.1. Covered sources

The covered sources are the following processes and equipment used for

(1) offshore petroleum and natural gas exploration and production from any temporary or permanent platform, which includes

(a) the use of equipment to extract hydrocarbons from submerged land;

(b) the use of equipment to transfer oil or natural gas to storage, transport vessels, or onshore, including secondary platform structures and storage tanks associated with the platform structure;

(2) onshore oil and natural gas exploration and production, which includes

(a) the use of equipment associated with wells, such as compressors, generators, storage facilities and piping, such as flowlines or intra-facility gathering lines;

(b) the use of portable non-self-propelled equipment, such as well drilling, completion and workover equipment;

(c) the use of gravity separation equipment;

(d) the use of auxiliary non-transportation-related equipment, including leased, rented or contracted equipment used in exploration and production, extraction, recovery, lifting, stabilization, separation or treating of petroleum and natural gas, including condensate;

(e) storage facilities and all systems engaged in gathering produced gas from multiple wells;

(f) all enhanced oil recovery (EOR) operations using CO2;

(g) all exploration and production facilities located on islands, artificial islands or structures connected by a causeway to land or to an island or artificial island;

(3) onshore natural gas processing, which includes

(a) oil and condensate removal;

(b) water extraction;

(c) the separation of natural gas liquids;

(d) hydrogen sulphide (H2S) and CO2 removal;

(e) fractionation of natural gas liquids;

(f) the capture of CO2 separated from natural gas streams for delivery outside the facility;

(g) field gathering or boosting stations that gather and process natural gas from multiple wellheads, and compress and transport natural gas (including but not limited to flowlines or intra-facility gathering lines or compressors) as feed to the natural gas processing plants;

(h) any other treatment process.

QC.33.2. Greenhouse gas reporting requirements

In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:

(1) the annual CO2, CH4 and N2O emissions attributable to the use of stationary combustion units calculated and reported in accordance with QC.1 or, when process vent gas, field gas or any other type of gas is used, in accordance with QC.33.3.19, in metric tons;

(2) the annual CO2, CH4 and N2O emissions attributable to the use of portable equipment, calculated and reported in accordance with QC.1 or, when process vent gas, field gas or any other type of gas is used, in accordance with QC.33.3.19, in metric tons;

(3) the annual fugitive emissions of CO2, CH4 and N2O from offshore oil and gas exploration and production facilities originating from equipment leaks, venting and flares, calculated in accordance with QC.33.3.21, in metric tons;

(4) the annual CO2, CH4 and N2O emissions from onshore oil and gas exploration and production facilities, in metric tons, specifying

(a) the annual CO2 and CH4 emissions attributable to high bleed pneumatic device venting and natural gas driven pneumatic pump venting, calculated in accordance with QC.33.3.1;

(b) the annual CO2 and CH4 emissions attributable to natural gas driven low bleed and intermittent bleed pneumatic device venting, calculated in accordance with QC.33.3.2;

(c) the annual CO2 emissions attributable to acid gas scrubbing equipment, calculated in accordance with QC.33.3.3;

(d) the annual CO2, CH4 and N2O emissions attributable to dehydrator venting, calculated in accordance with QC.33.3.4;

(e) the annual CO2 and CH4 emissions attributable to well venting for liquids unloading, calculated in accordance with QC.33.3.5;

(f) the annual CO2 and CH4 emissions attributable to natural gas well venting during completions or workovers, calculated in accordance with QC.33.3.6;

(g) the annual CO2 and CH4 emissions attributable to blowdown vent stacks, calculated in accordance with QC.33.3.7;

(h) the annual CH4 emissions attributable to third party line hits, calculated in accordance with QC.33.3.8;

(i) the annual CO2, CH4 and N2O emissions attributable to venting from storage tanks associated with onshore oil and natural gas exploration, production, processing and storage facilities, calculated in accordance with QC.33.3.9;

(j) the annual CO2, CH4 and N2O emissions attributable to transmission storage tanks, calculated in accordance with QC.33.3.10;

(k) the annual CO2, CH4 and N2O emissions attributable to well testing venting and flaring, calculated in accordance with QC.33.3.11;

(l) the annual CO2, CH4 and N2O emissions attributable to associated gas venting and flaring, calculated in accordance with QC.33.3.12;

(m) the annual CO2, CH4 and N2O emissions attributable to flare stacks, calculated in accordance with QC.33.3.13;

(n) the annual CO2 and CH4 emissions attributable to centrifugal compressor venting, calculated in accordance with QC.33.3.14;

(o) the annual CO2 and CH4 emissions attributable to reciprocating compressor venting, calculated in accordance with QC.33.3.15;

(p) the annual fugitive CO2 and CH4 emissions attributable to gathering pipeline equipment leaks, calculated in accordance with QC.33.3.17;

(q) the annual fugitive CO2 and CH4 emissions from equipment components such as valves, connectors, open ended lines, pressure relief valves, pumps, flanges, metrological instruments, loading arms, safety valves, stuffing boxes, compressor seals, dump lever arms, and breather caps for crude oil processing, calculated in accordance with QC.33.3.17;

(r) the annual CO2 and CH4 emissions attributable to Enhanced Oil Recovery (EOR) injection pump blowdown, calculated in accordance with QC.33.3.18;

(s) the annual fugitive emissions from other sources of fugitive emissions, calculated in accordance with QC.33.3.20;

(5) the annual CO2, CH4 and N2O emissions from onshore natural gas processing facilities, in metric tons, specifying

(a) the annual CO2 emissions attributable to acid gas scrubbing equipment, calculated in accordance with QC.33.3.3;

(b) the annual CO2, CH4 and N2O emissions attributable to dehydrator venting, calculated in accordance with QC.33.3.4;

(c) the annual CO2 and CH4 emissions attributable to blowdown vent stacks, calculated in accordance with QC.33.3.7;

(d) the annual CO2, CH4 and N2O emissions attributable to natural gas storage, calculated in accordance with QC.33.3.9;

(e) the annual CO2, CH4 and N2O emissions attributable to flare stacks, calculated in accordance with QC.33.3.13;

(f) the annual CO2 and CH4 emissions attributable to centrifugal compressor venting, calculated in accordance with QC.33.3.14;

(g) the annual CO2 and CH4 emissions attributable to reciprocating compressor venting, calculated in accordance with QC.33.3.15;

(h) the annual fugitive CO2 and CH4 emissions from equipment components such as valves, connectors, open ended lines, pressure relief valves and meters, calculated in accordance with QC.33.3.16;

(i) the annual fugitive CO2 and CH4 emissions attributable to gathering pipeline component leaks, calculated in accordance with QC.33.3.17;

(j) the annual fugitive emissions from other fugitive emission sources, such as reciprocating compressor rod-packing vents and centrifugal compressor wet and dry seal vents, calculated in accordance with QC.33.3.20;

(6) the following data for each emission source referred to in paragraphs 2 to 4:

(a) the specific emission factors used in place of the values indicated in Tables 33-1 and 33-2 in QC.33.6;

(b) the number of natural gas driven pneumatic devices used, by type, namely high bleed, low bleed or intermittent bleed;

(c) the number of natural gas driven pneumatic pumps;

(d) the total throughput of acid gas scrubbing equipment, in thousands of cubic metres;

(e) if glycol dehydrators are used, the number of dehydrators operated, specifying

i. the number of dehydrators with throughput less than 11,328 m3 per day at standard conditions;

ii. the number of dehydrators with throughput equal to or greater than 11,328 m3 per day at standard conditions;

(f) the number of wells vented to the atmosphere for liquids unloading;

(g) the number of third party line hits, including volumes of natural gas emitted to the atmosphere by hit;

(h) the number of gas wells venting during well completions, specifying

i. the number of conventional well completions;

ii. the number of well completions employing hydraulic fracturing;

(i) the number of wells vented during workovers;

(j) for each compressor used:

i. the type of compressor;

ii. where the aggregate rated power for the sum of compressors at the establishment is equal to or greater than 186.4 kW:

— the compressor driver capacity in kilowatts;

— the annual number of blowdowns;

iii. the number of compressor starts during the year;

(k) the number of EOR injection pump blowdowns;

(l) the number of wells tested;

(m) the number of wells venting or flaring associated gas;

(n) the number of wells being unloaded for liquids;

(o) the number of wells worked over;

(p) when the calculation methods in QC.33.3.16 and QC.33.3.17 are used:

i. the components of each emission source;

ii. the emission factors determined in accordance with QC.33.4.16 and QC.33.4.17;

iii. the total number of leaks detected during annual leak detection surveys;

(q) the annual quantity of oil produced, in kilolitres;

(r) the quantity of natural gas produced, in thousands of cubic metres;

(7) the number of times that the methods for estimating missing data provided for in QC.33.5 were used.

The emissions attributable to well venting or to other fugitive emission sources or to the venting referred to in subparagraphs q and s of subparagraph 4 and in subparagraph j of subparagraph 5 of the first paragraph do not need to be reported when the emissions from a given source are less than 0.5% of the emitter’s total emissions and when the total of the unreported emissions under this paragraph does not exceed 1% of the emitter’s total emissions.

For the purposes of subparagraph 8 of the first paragraph of section 6.2:

(1) the emissions referred to in subparagraphs 1 and 2 of the first paragraph are emissions attributable to combustion;

(2) the emissions referred to in subparagraphs 3 to 5 of the first paragraph are other emissions.

QC.33.3. Calculation methods for CO2, CH4 and N2O emissions

The annual CO2, CH4 and N2O emissions attributable to oil and natural gas exploration and production and to natural gas processing must be calculated in accordance with one of the methods in QC.33.3.1 to QC.33.3.20.

When no calculation method is specified for an emissions source, the emitter must use sector-specific inventory practices.

QC.33.3.1. Calculation of CO2 and CH4 emissions attributable to high bleed pneumatic device venting and natural gas driven pneumatic pump venting

The annual CO2 and CH4 emissions attributable to venting from high bleed pneumatic devices, in other devices that bleed to the atmosphere at a rate in excess of 0.17 m3 per hour, and to natural gas driven pneumatic pumps, must be calculated using equations 33-1 to 33-4:

Equation 33-1

GHGi = GHGm,i + GHGn-m,i

Where:

GHGi = Annual emissions of greenhouse gas i attributable to high bleed pneumatic device and natural gas driven pneumatic pump venting, in metric tons;

GHGm,i = Annual emissions of greenhouse gas i attributable to high bleed pneumatic device and natural gas driven pneumatic pump venting, calculated using equation 33-2 when the annual volume of natural gas consumed is metered, in metric tons;

GHGn-m,i = Annual emissions of greenhouse gas i attributable to high bleed pneumatic device and natural gas driven pneumatic pump venting, calculated, when the annual volume of natural gas consumed by the devices is not metered, using equation 33-3 for high bleed pneumatic devices and equation 33-4 for natural gas driven pneumatic pumps, in metric tons;

i = CO2 or CH4;

Equation 33-2

GHGm,i = VNG × MFi × MWi/MVC × 0.001

Where:

GHGm,i = Annual emissions of greenhouse gas i attributable to high bleed pneumatic device and natural gas driven pneumatic pump venting, in metric tons;

VNG = Annual volume of natural gas consumed by the high bleed pneumatic devices or natural gas driven pneumatic pumps, measured in accordance with paragraph 1 of QC.33.4.1, in cubic metres at standard conditions;

MFi = Molar fraction of gas i in natural gas, determined in accordance with paragraph 3 of QC.33.4;

MWi = Molecular weight of gas i, in kilograms per kilomole;

MVC = Molar volume conversion factor (24.06 m3 per kilomole at standard conditions);

0.001 = Conversion factor, kilograms to metric tons;

i = CO2 or CH4;

Equation 33-3

Equation 33-4

QC.33.3.2. Calculation of CO2 and CH4 emissions attributable to natural gas driven low or intermittent bleed pneumatic device venting

The annual CO2 and CH4 emissions attributable to natural gas driven low or intermittent bleed pneumatic device venting must be calculated separately using equation 33-5:

Equation 33-5

QC.33.3.3. Calculation of CO2 emissions attributable to acid gas scrubbing equipment

Except where acid gases emissions are re-injected into an oil/gas field or manifolded to a common flare stack or other equipment, which must be calculated in accordance with QC.33.3.13, the CO2 emissions attributable to acid gas scrubbing equipment must be calculated in accordance with one of the following methods:

(1) using data obtained from a continuous emission monitoring and recording system in accordance with QC.1.3.4;

(2) when there is no continuous emission monitoring and recording system but an equipment to measure the quantity of gas emitted is available, using equation 33-6:

Equation 33-6

(3) when there is no continuous emission monitoring and recording system and no equipment to measure the quantity of gas emitted, using equation 33-7:

Equation 33-7

QC.33.3.4. Calculation of CO2, CH4 and N2O emissions attributable to dehydrator vents

The annual CO2, CH4 and N2O emissions attributable to dehydrator vents must be calculated using one of the following methods:

(1) determine the CO2 and CH4 emissions using a simulation software package such as GRI-GLYCalc, version 4, or AspenTech HYSYSMD, or a similar software tool. The software or tool must use the Peng-Robinson equation of state to calculate the equilibrium coefficient, speciate CH4 and CO2 emissions from dehydrators and have provisions to include regenerator control devises, a separator flash tank, stripping gas and a gas injection pump or gas assist pump, specifying the following parameters:

(a) feed natural gas flow rate;

(b) feed natural gas water content;

(c) outlet natural gas water content;

(d) the type of absorbent circulation pump, namely natural gas pneumatic or air pneumatic or electric;

(e) absorbent circulation rate;

(f) absorbent type, such as triethylene glycol, diethylene glycol or ethylene glycol;

(g) use of stripping gas;

(h) use of flash tank separator and disposition of recovered gas;

(i) hours operated;

(j) wet natural gas temperature and pressure;

(k) wet natural gas composition, determined in accordance with QC.33.4.4;

(2) for dehydrators that use desiccant, the emissions must be calculated from the amount of natural gas vented from the vessel every time it is depressurized for the desiccant refilling process, using equation 33-8:

Equation 33-8

(3) when the emissions attributable to dehydrator vents are directed to flares, the CO2, CH4 and N2O emissions must be calculated in accordance with the method in QC.33.3.13, using the gas volume and composition determined in accordance with paragraph 1.

For the purposes of the emissions calculation under the first paragraph, where the dehydrator has a vapour recovery system, the emissions must be adjusted downward based on the emissions recovered.

QC.33.3.5. Calculation of CO2 and CH4 emissions attributable to well venting for liquids unloading

The annual CO2 and CH4 emissions attributable to well venting for liquids unloading must be calculated using one of the following methods:

(1) the annual CO2 and CH4 emissions attributable to well venting for liquids unloading may be calculated using equation 33-9:

Equation 33-9

(2) for wells venting for liquid unloading with plunger assist, the emissions may be calculated using equation 33-10:

Equation 33-10

QC.33.3.6. Calculation of CO2, CH4 and N2O emissions attributable to natural gas well venting during completions or workovers

The annual CO2, CH4 and N2O emissions attributable to natural gas well venting during completions or workovers must be calculated using one of the following methods:

(1) where the vented gas is directed to flares, according to the method in QC.33.3.13, using the volumes determined in accordance with paragraph 1 of QC.33.4.6;

(2) using equation 33-11:

Equation 33-11

(3) where the flow regime is sonic or subsonic, using equation 33-12:

Equation 33-12

(a) by determining the quantity of natural gas emitted during sonic flow conditions using the following method:

Equation 33-13

Where:

Vve-s = Quantity of natural gas emitted during sonic flow conditions from venting of well j, in cubic metres at standard conditions;

A = Cross sectional area of the orifice, in square metres;

187.08 = Constant, in square metres per second squared per degree kelvin;

Tup = Temperature of gas upstream from the choke point, in kelvin;

ts = Annual duration of venting from well j in during sonic flow conditions, in hours;

3600 = Conversion factor, seconds to hours;

TSC = Temperature at standard conditions of 293.15 kelvin;

Twv = Temperature at well vent, in kelvin;

Pwv = Absolute pressure at well vent, in kilopascals;

PSC = Pressure at standard conditions of 101.325 kPa;

j = Gas well;

(b) by determining the quantity of gas emitted during subsonic flow conditions from the venting of a well by calculating the total volume under the curve of a plot having the instantaneous flow rate of natural gas to the vent, determined using equation 33-14, as the Y-axis, and time as the X-axis, for the time period during which the well was flowing during subsonic conditions.

Equation 33-14

Where:

Dss = Instantaneous flow rate of gas emitted during subsonic flow conditions from venting of well j, in cubic metres per hour at standard conditions;

A = Cross sectional area of the choke point, in square metres;

3430 = Constant, in square metres per second squared per degree kelvin;

Tup = Temperature of gas upstream from the choke point, in kelvin;

Pdo = Absolute pressure downstream from the choke point, in kilopascals;

Pup = Absolute pressure upstream from the choke point, in kilopascals;

j = Gas well;

3600 = Conversion factor, seconds to hours;

TSC = Temperature at standard conditions of 293.15 kelvin;

Twv = Temperature at well vent, in kelvin;

Pwv = Absolute pressure at well vent, in kilopascals;

PSC = Pressure at standard conditions of 101.325 kPa;

QC.33.3.7. Calculation of CO2 and CH4 emissions attributable to blowdown vent stacks

The CO2 and CH4 emissions attributable to natural gas emissions to the atmosphere from equipment blowdown vent stacks, except equipment depressurizing to a flare, which must be calculated using QC.33.3.13, a dehydrator, which must be calculated using QC.33.3.4, over-pressure relief valve, which must be calculated using QC.33.3.16, or operating pressure control vale, which must be calculated using QC.33.3.1 and QC.33.3.3, must be calculated using equation 33-15:

Equation 33-15

QC.33.3.8. Calculation of CH4 emissions attributable to third party line hits

The annual CH4 emissions attributable to third party line hits that result in emissions equal to or greater than 1.416 m3 of CH4 at standard conditions must be calculated using equations 33-16 and 33-17 for catastrophic pipeline ruptures and pipeline puncture incidents when the flow is choked and using equation 33-18 for pipeline puncture incidents when the flow is not choked:

Equation 33-16

Equation 33-17

Where:

M = Mach number of the flow;

Pa = Absolute pressure inside pipe, determined in accordance with paragraph 2 of QC.33.4.8, in kilopascals;

Pe = Absolute pressure of ambient air at the damage point, in kilopascals;

K = Specific heat ratio of CH4, namely 1.299;

Equation 33-18

QC.33.3.9. Calculation of CO2, CH4 and N2O emissions attributable to venting from storage tanks associated with onshore oil and natural gas exploration, production, processing and storage facilities

The CO2, CH4 and N2O emissions attributable to atmospheric pressure fixed roof storage tanks receiving hydrocarbon produced liquids from onshore oil and natural gas exploration and production facilities and onshore natural gas processing facilities must be calculated using one of the following methods:

(1) when the gas is directed to flares, using the method in QC.33.3.13 and the volumes determined in accordance with paragraph 6 of QC.33.4.9;

(2) in other cases, using equation 33-19:

Equation 33-19

(3) using the latest software package for E&P Tank (exploration and production tank) of the American Petroleum Institute and the following parameters to characterize emissions:

(a) separator oil composition;

(b) separator temperature;

(c) separator pressure;

(d) sales oil API gravity;

(e) sales oil production rate;

(f) sales oil Reid vapour pressure;

(g) ambient air temperature;

(h) ambient air pressure.

QC.33.3.10. Calculation of CO2, CH4 and N2O emissions attributable to transmission storage tanks

Except for emissions sent to flares, which must be calculated in accordance with QC.33.3.13, the annual CH4, CO2 and N2O emissions attributable to compressor scrubber dump valve leakage from condensate storage tanks, connected to transmission storage tanks for water or hydrocarbon, must be calculated using equations 33-20:

Equation 33-20

Where:

GHGi = Annual emissions of greenhouse gas i attributable to compressor scrubber dump valve leakage from condensate storage tanks connected to transmission storage tanks, in metric tons;

n = Number of equipments;

j = Device;

EF = Emission factor for leakage from device j, determined in accordance with QC.33.4.10, in metric tons per hour;

t = Duration of leak from device j, determined in accordance with QC.33.4.10, in hours;

MFi = Molar fraction of greenhouse gas i in gas from reciprocating compressor venting, determined in accordance with paragraph 3 of QC.33.4;

i = CO2 or CH4.

QC.33.3.11. Calculation of CO2, CH4 and N2O emissions attributable to venting and flaring during well testing

The CO2, CH4 and N2O emissions vented and flared during well testing must be calculated using one of the following methods:

(1) if the gas is directed to flares, using the method in QC.33.3.13 and the volumes determined in accordance with paragraph 2 of QC.33.4.11;

(2) in other cases, when the quantity of liquid is sufficient to calculate a natural gas to liquid ratio (GLR), using equation 33-21:

Equation 33-21

Equation 33-22

QC.33.3.12. Calculation of CO2, CH4 and N2O emissions attributable to associated gas from wells

The annual CO2, CH4 and N2O emissions attributable to associated gas from wells, except emissions attributable to production tests, which must be calculated in accordance with QC.33.3.11, must be calculated using one of the following methods:

(1) using the method in QC.33.3.13 where the gas is directed to flares, using the volumes determined by multiplying the volume of liquid produced by the gas to liquid ration determined in accordance with QC.33.4.12;

(2) in other cases, using equation 33-23:

Equation 33-23

QC.33.3.13. Calculation of CO2, CH4 and N2O emissions attributable to flaring

The annual CO2, CH4 and N2O emissions attributable to flaring must be calculated using the following methods:

(1) the annual CO2 emissions attributable to flaring must be calculated using equation 33-24:

Equation 33-24

(2) the annual CH4 emissions attributable to flaring must be calculated using equation 33-25:

Equation 33-25

(3) the annual N2O emissions attributable to flaring must be calculated using equation 33-26:

Equation 33-26

N2O = VG × HHV × EFN2O × 0.001

Where:

N2O = Annual N2O emissions attributable to flaring, in metric tons;

VG = Annual volume of gas flared, determined in accordance with QC.33.4.13, in cubic metres at standard conditions;

HHV = High heat value of gas as specified in Tables 1-1 and 1-2 in QC.1.7 or high heat value of 4.579 × 10-2 GJ per cubic metre for gas from equipment venting or determined in accordance with QC.1.5.4, in gigajoules per cubic metre at standard conditions;

EFN2O = N2O emission factor, namely 9.52 × 10-5 kg per gigajoule;

0.001 = Conversion factor, kilograms to metric tons.

QC.33.3.14. Calculation of CO2 and CH4 emissions attributable to centrifugal compressor venting

The annual CO2 and CH4 emissions attributable to centrifugal compressor venting must be calculated using the following methods:

(1) for each centrifugal compressor, the emitter must determine, in accordance with QC.33.4.14, the volume of gas from the wet seal oil degasing tank that is vented to the atmosphere and the volume of gas directed to flares;

(2) the annual CO2 and CH4 emissions attributable to gas vented to the atmosphere from centrifugal compressors must be calculated using equation 33-27 where the aggregate rated power for the sum of centrifugal compressors at the establishment is equal to or greater than 186.4 kW and using equation 33-28 where the aggregate rated power of the centrifugal compressors at the establishment is less than 186.4 kW:

Equation 33-27

Equation 33-28

(3) the annual CO2 and CH4 emissions attributable to the gas directed to flares must be calculated in accordance with the calculation methods in QC.33.3.13 using the volumes of gas determined in accordance with QC.33.4.14.

QC.33.3.15. Calculation of CO2 and CH4 emissions attributable to reciprocating compressor venting

The annual CO2 and CH4 emissions attributable to reciprocating compressor venting must be calculated using the following methods:

(1) for each reciprocating compressor, the emitter must determine the gas flow from the venting in accordance with paragraph 1 of QC.33.4.15;

(2) the annual CO2 and CH4 emissions attributable to gas vented to the atmosphere from centrifugal compressors must be calculated using equation 33-29 where the aggregate rated power of the centrifugal compressors at the establishment is equal to or greater than 186.4 kW or using equation 33-30 where the aggregate rated power of the reciprocating compressors at the establishment is less than 186.4 kW:

Equation 33-29

Equation 33-30

(3) the annual CO2 and CH4 emissions attributable to gas directed to flares must be calculated in accordance with the calculation methods in QC.33.3.13 using the gas flow rates determined in accordance with QC.33.4.15.

QC.33.3.16. Calculation of CO2 and CH4 emissions attributable to leaks identified following a leak detection survey

Except for emissions from emission sources for which the total weight of CO2 and CH4 in the natural gas is below 10%, which must be calculated in accordance with QC.33.3.20, the annual fugitive CO2 and CH4 emissions attributable to leaks identified following a leak detection survey must be calculated for each source for which leaks are detected using equation 33-31:

Equation 33-31

QC.33.3.17. Calculation of fugitive CO2 and CH4 emissions attributable to all components

Except for emissions from emission sources with gas containing less than 10% CO2 plus CH4 by weight, which do not need to be calculated, annual fugitive CO2 and CH4 emissions must be calculated equation 33-32 for all centrifugal or reciprocating compressor components used in natural gas and oil exploration and production, or using equation 33-33 for gathering pipeline components:

Equation 33-32

Where:

GHGi = Annual emissions of greenhouse gas i for each source of fugitive emissions, in metric tons;

k = Type of service listed in Tables 33-1 and 33-2 in QC.33.6, namely Gas/Vapour or Fuel Gas or Light Liquid or Heavy Liquid;

j = Type of component;

Nj,k = Total number of components of type j, determined in accordance with QC.33.4.17;

EFj,k = Emission factor for each type of component j, determined in accordance with QC.33.4.17, in metric tons of total hydrocarbon per component per hour;

THCk = Mass fraction of total hydrocarbons in service k;

Fri,k = Mass fraction of greenhouse gas i in service k;

t = Total time the component type at the origin of the fugitive emissions was operational, in hours;

i = CO2 or CH4;

Equation 33-33

GHGi = EFi × L × t

Where:

GHGi = Annual emissions of greenhouse gas i attributable to gathering pipeline components, in metric tons;

EFi = Emission factor associated with gathering pipeline components, namely 2.66 × 10-5 for CH4 and 6.35 × 10-6 for CO2, in metric tons per kilometre per hour;

L = Length of the gathering pipeline, in kilometres;

t = Total time the gathering pipeline was operational in the year, in hours;

i = CO2 or CH4.

QC.33.3.18. Calculation of CO2 and CH4 emissions attributable to EOR injection pump blowdown

The annual CO2 and CH4 emissions attributable to EOR injection pump blowdown must be calculated using equation 33-34:

Equation 33-34

QC.33.3.19. Calculation of CO2, CH4 and N2O emissions attributable to the combustion of field gas and process vent gas

The annual CO2, CH4 and N2O emissions attributable to the combustion of field gas and process vent gas must be calculated in accordance with QC.33.4.19.

QC.33.3.20. Calculation of fugitive emissions from other sources

Fugitive emissions from other sources that are not calculated using the methods in QC.33.3.1 to QC.33.3.19 must be calculated using the methods in the most recent version of

(1) “Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Natural Gas Industry” published in August 2009 by the American Petroleum Institute;

(2) Table 6-22, “A National Inventory of Greenhouse Gas (GHG)”, published by Clearstone Engineering Ltd.;

(3) “Criteria Air Contaminant (CAC) and Hydrogen Sulphide (H2S) Emissions by the Upstream Oil and Gas Industry, Volume 5”, published in September 2004 by the Canadian Association of Petroleum Producers.

QC.33.3.21. Calculation of annual CO2, CH4 and N2O fugitive emissions at offshore oil and gas exploration and production facilities from equipment leaks, venting and flaring

The annual CO2, CH4 and N2O fugitive emissions at offshore oil and gas exploration and production facilities from equipment leaks, venting and flaring must be calculated using the data estimation and collection method of the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE), and in accordance with the method in Parts 250.302 to 304 of Title 30 of the Code of Federal Regulations published by the U.S. Environmental Protection Agency (USEPA).

QC.33.4. Sampling, analysis and measurement requirements

An emitter operating an oil or natural gas exploration and production or natural gas processing establishment must

(1) ensure that all the instruments used for sampling, analysis and measurement are calibrated before the first emissions report and for the following years, that they are calibrated and operated in accordance with the manufacturer’s instructions or in accordance with the methods and calibration intervals published by the following organizations:

(a) Canadian Standards Association;

(b) Canadian Gas Association;

(c) Canadian Association of Petroleum Producers;

(d) American National Standards Institute;

(e) American Society of Testing and Materials;

(f) American Petroleum Institute;

(g) American Society of Mechanical Engineers;

(h) North American Energy Standards Board;

(i) Canadian Energy Pipeline Association;

(j) Measurement Canada;

(k) Centre d’expertise en analyse environnementale du Québec;

(2) conduct leak detection surveys and manage transmission and distribution system integrity in accordance with the most recent version of CSA Z662-11 “Oil and gas pipeline systems” published by the Canadian Standards Association in June 2011 and in accordance with the Construction Code (chapter B-1.1, r. 2);

(3) determine the mole fraction of CO2 and CH4 in the natural gas by calculating the annual average of the following mole fractions in accordance with the second paragraph;

(4) from 1 January 2015, ensure that all high bleed pneumatic devices and all natural gas driven pneumatic pumps are equipped with meters.

The molar fraction of CO2 and CH4 must be determined as follows:

(1) for oil or natural gas exploration or production, by determining the molar fraction in the gas produced;

(a) if the facility is equipped with a continuous gas composition analyzer, using the average annual value;

(b) if the facility is not equipped with a continuous gas composition analyzer, using the annual average of the known gas composition for (in required order of preference):

i. the establishment;

ii. the company for the same oil or gas field operated during the same reporting period or, if not available, the previous reporting period;

(2) for natural gas processing, in the feed natural gas:

(a) for all equipment downstream of the de-methanizer or dew point control, by determining the molar fraction for all gas sources upstream of the de-methanizer or dew point control and in the gas going to transmission pipeline systems;

(b) for facilities that solely fractionate a liquid stream, by determining the molar fraction in the feed natural gas;

(c) for a facility that is equipped with a continuous gas composition analyzer in the feed gas stream, using the average annual value;

(d) for a facility that is not equipped with a continuous gas composition analyzer, using the annual average of the known gas composition for (in required order of preference):

i. the establishment;

ii. the company for the same oil or gas field operated during the same reporting period or, if not available, the previous reporting period.

QC.33.4.1. High bleed pneumatic device venting and natural gas driven pneumatic pump venting

For high bleed pneumatic device venting and natural gas driven pneumatic pump venting, the emitter must determine the number of high bleed pneumatic devices and natural gas driven pneumatic pumps as follows:

(1) for the first emissions report year, count all equipment by type or estimate the total equipment count and break down the result by the estimated percentage of each equipment type;

(2) for subsequent years, update the number of high bleed pneumatic devices and natural gas driven pneumatic pumps to reflect the annual changes.

In addition, the emitter must

(1) when using equation 33-2, determine the annual volume of natural gas consumed by the high bleed pneumatic devices or the quantity of natural gas consumed by the natural gas driven pneumatic pump using measuring equipment, such as a meter, installed on the equipment;

(2) when using equation 33-3, obtain from the equipment manufacturer the natural gas emission factor for each high bleed pneumatic device under normal operating conditions or, when those data are not available, use the flow for similar equipment. If there is no similar equipment, the emitter must use the data from Table 33-3 or 33-4 in QC.33.6;

(3) when using equation 33-4:

(a) obtain from the manufacturer the quantity of natural gas consumed per volume of liquid pumped in normal operating conditions for each model of pneumatic pump under normal operating conditions or, when those data are not available, use data for similar equipment;

(b) maintain a log of the quantity of liquid pumped annually by each natural gas driven pneumatic pump venting.

QC.33.4.2. Natural gas driven low or intermittent bleed pneumatic device venting

For natural gas driven low or intermittent bleed pneumatic device venting, the emitter must

(1) determine the number of natural gas driven low bleed pneumatic devices and the number of natural gas driver intermittent bleed pneumatic devices as follows:

(a) for the first emissions report year, by counting all devices by type or estimating the total device count and breaking down the result by the estimated percentage of each device type;

(b) for subsequent years, by updating the number of low bleed pneumatic devices and intermittent bleed devices to reflect annual changes;

(2) determine the emission factor for each type of pneumatic device as follows:

(a) for low bleed pneumatic devices, using the values specified in Table 33-3 in QC.33.6;

(b) for intermittent bleed pneumatic devices that maintain operating conditions such as liquid level, pressure, pressure differential or temperature, using the data available in the following order:

i. the values specified in Table 33-4;

ii. the emission factor for a similar device;

iii. the emission factor for intermittent bleed pneumatic devices specified in Table 33-3;

(c) for intermittent bleed pneumatic devices used for compressor startup, using the emission factor provided by the manufacturer.

QC.33.4.3. Acid gas scrubbing equipment

For acid gas scrubbing equipment, the emitter must

(1) measure the annual volume of processed gas output from the acid gas scrubbing equipment using appropriate measuring equipment in accordance with a method published by one of the organizations listed in paragraph 1 of QC.33.4;

(2) measure the mole fraction of CO2 in the input and output natural gas of the acid gas scrubbing equipment using a continuous gas composition analyzer or, when the equipment is not equipped with an analyzer, by taking a monthly sample;

(3) measure the mole fraction of H2S in the input and output natural gas of the acid gas scrubbing equipment using a continuous gas composition analyzer or, when the equipment is not equipped with an analyzer, using an analysis method published by an organization listed in QC.1.5.

QC.33.4.4. Dehydrator vents

To determine wet natural gas composition for dehydrator vents, the emitter must

(1) when the dehydrator is equipped with a continuous gas composition analyzer, use the average annual value;

(2) when the dehydrator is not equipped with a continuous gas composition analyzer, use the annual average of the measured gas composition for the establishment;

(3) use a method published by an organization listed in paragraph 1 of QC.33.4;

(4) when only the dry natural gas composition output from the dehydrator is available, assume that the wet input gas is saturated.

QC.33.4.5. Well venting for liquids unloading

For well venting for liquids unloading, the emitter must

(1) group the wells by well diameter and pressure in each gas producing field where wells are vented to the atmosphere;

(2) for each group of wells, install a meter on a representative well in the group;

(3) determine the average gas flow rate measured on the vent line used to vent gas from the well using the following method:

(a) by dividing the volume of gas measured on the vent line from the well by the total annual venting time for each liquid unloaded;

(b) by applying the average flow rate to all the wells in each group determined in accordance with paragraph 1;

(c) by recalculating the average flow rate for the group each year.

For a new producing field or a new horizon combination, the average flow rate must be calculated beginning in the first year of production.

QC.33.4.6. Natural gas well venting during completions or workovers

For natural gas well venting during completions or workovers, the emitter must

(1) measure the volume of natural gas vented from gas wells during completions or workovers using a flowmeter installed on the vent;

(2) when the method in paragraph 3 of QC.33.3.6 is used:

(a) make a series of measurements of upstream pressure and downstream pressure across a choke during the entire completion and workover period, at a sufficient frequency to determine the flow regime in accordance with subparagraph b;

(b) determine the flow regime by calculating the “downstream pressure over upstream pressure” ratio at the choke as follows:

Sonic flow regime if Pav / Pam ≤ 0.542

Subsonic flow regime if Pav / Pam > 0.542

Where:

Pam = Absolute vent pressure upstream from choke point, in kilopascals;

Pav = Absolute vent pressure downstream from choke point, in kilopascals.

QC.33.4.7. Blowdown vent stacks

For blowdown vent stacks, the emitter must

(1) calculate the volume of natural gas in blowdown chambers between the isolation valves for each piece of equipment;

(2) when the volume is equal to or greater than 1.42 m3 at standard conditions, log the annual number of blowdowns for each piece of equipment.

QC.33.4.8. Third party line hits

For fugitive emissions attributable to third party line hits, the emitter must

(1) for a pipeline puncture incident, determine whether or not the flow is choked, using the following method:

If PAtm / Pa ≥ 0.546 flow is not choked;

If PAtm / Pa < 0.546 flow is choked;

Where:

Pa = Absolute pressure inside pipe, determined in accordance with paragraph 3 of QC.33.4.8, in kilopascals;

PAtm = Absolute pressure at the damage point, in kilopascals;

(2) for a catastrophic pipeline rupture, determine the pressure inside the pipe at the place where the ruptured pipeline joins a larger pipeline;

(3) for a pipeline puncture incident, determine the pressure inside the pipe at the damage point.

QC.33.4.9. Emissions attributable to venting from oil and natural gas storage tanks associated with onshore exploration, production and processing facilities

For emissions attributable to atmospheric pressure fixed roof storage tanks receiving hydrocarbon produced liquids from onshore oil and gas exploration and production facilities and onshore natural gas processing facilities, the emitter must, to calculate the gas oil ratio,

(1) collect a pressurized sample of produced liquids from the separator at a location upstream of the storage tank; the sample must be collected at the pressure of the final separation device before the transition to a storage tank at atmospheric pressure using one of the following methods:

(a) the most recent revision of “E&P TANK Version 2.0 User’s Manual Appendix C, Sampling Protocol Section”, published by the American Petroleum Institute;

(b) the guidance document “Oil and Gas Production Facilities, Chapter 6, Section 2 Permitting Guidance, Appendix D Sampling and Analysis of Hydrocarbon Liquids and Natural Gas”, published in August 2011 by the Wyoming Department of Environmental Quality Air Quality Division;

(c) “Standard 2174-93, Obtaining Liquid Hydrocarbon Samples for Analysis by Gas Chromatography” published by the Gas Processors Association (GPA);

(2) measure the sample pressure at the time of collection and again prior to analysis to insure that sample integrity has been maintained;

(3) measure the liquid temperature at the time of collection;

(4) conduct sampling and analysis at the frequency prescribed below at a time when operational parameters are representative of normal operating conditions:

 _________________________________________________________________________________
|                                        |                                        |
|    Oil production rate (m3 per day)    |           Sampling frequency           |
|________________________________________|________________________________________|
|                                        |                                        |
| 1.75 < rate ≤ 15.9                     |  Annual                                |
|________________________________________|________________________________________|
|                                        |                                        |
| 15.9 < rate ≤ 79.5                     |  Semi-annual                           | 
|________________________________________|________________________________________|
|                                        |                                        |
| rate > 79.5                            |  Quarterly                             |
|________________________________________|________________________________________|                        

(5) collect an additional sample if

(a) the production rate changes more than 20% compared to the normal rate for time periods in excess of one week;

(b) the separator operating pressure changes by more than 10% compared to the normal operating pressure;

(6) measure the volume of liquid produced during the sampling interval using equipment calibrated to be accurate to within 5%.

QC.33.4.10. Emissions attributable to transmission storage tanks

For transmission storage tanks, the emitter must

(1) to measure compressor scrubber dump valve leakage from condensate storage tanks connected to transmission storage tanks for water or hydrocarbon, determine the emission factor for leaks from each type of component using the following methods:

(a) using specific data related to the operation of the equipment by the emitter;

(b) using the method in the most recent version of “Methodology Manuel: Estimation of Air Emissions from the Canadian Natural Gas Transmission, Storage and Distribution System” published by Clearstone Engineering Ltd.;

(2) determine the duration of the equipment leakage using the following methods:

(a) when only one leak detection survey is conducted each year, the emitter must assume that the component was leaking from the start of the year until the leak was repaired. If the leak was not repaired, the emitter must assume that the component was leaking for the entire year;

(b) when more than one leak detection survey is conducted each year, the emitter must assume that the component has been leaking since the last survey. If a leak was detected at the last survey, the emitter must assume that the component, unless the leak has been repaired, was leaking for the entire year.

QC.33.4.11. Emissions attributable to well testing venting

To calculate emissions from well testing, the emitter must

(1) when using equation 33-21, determine the gas to liquid ratio (GLR) using a method published by one of the organizations listed in paragraph 1 of QC.33.4;

(2) when using equation 33-22, determine the average gas flow rate from well venting using measuring equipment installed on the vent.

QC.33.4.12. Associated gas emissions

To calculate associate gas emissions, the emitter must, when using equation 33-23, determine the gas to liquid ratio (GLR) using a method published by one of the organizations listed in paragraph 1 of QC.33.4.

QC.33.4.13. Emissions from flaring

To calculate emissions from flaring, the emitter must

(1) determine the volume of gas directed to flares using one of the following methods:

(a) when the flare is equipped with a continuous gas flow monitoring and recording system, using the gas volume flow or, when part of the gas is not measured by such a system, by estimating the unmeasured gas flow using a sector specific method;

(b) using a method published by an organization listed in paragraph 1 of QC.33.4;

(2) determine the gas composition using one of the following methods:

(a) using a continuous gas composition monitoring and recording system;

(b) when the flare is not equipped with a continuous gas composition analyzer and the exploration and production well is located onshore, using the annual average of the measured gas composition for the establishment;

(c) when the flare is not equipped with a continuous gas composition analyzer, using,

i. for gas processing facilities where the flare is feeded with natural gas, the molar fraction of the feed gas for equipment upstream of the de-methanizer;

ii. for sources downstream of the de-methanizer, the molar fraction of the output gas;

iii. for facilities that solely fractionate a liquid stream, the molar fraction of the feed gas for the de-methanizer;

iv. when the gas directed to the flare is composed of methane, ethane, propane, butane, pentane, hexane or hexanes-plus, the molar fraction determined by engineering calculation or based on available process data for the process concerned.

QC.33.4.14. Centrifugal compressor venting

For centrifugal compressors, the emitter must

(1) determine the gas flow from the wet seal oil degasing vent to the atmosphere and the gas flow directed to flares using a temporary or permanent flow meter in the operating mode in which it is found during the measurement period, namely:

(a) the centrifugal compressor is in operating, standby-pressurized mode and the gas emitted is from blowdown vent leakage;

(b) the centrifugal compressor is in operating mode;

(c) the centrifugal compressor is not operating and is in depressurized mode and the gas emitted is from isolation-valve leakage through the blowdown vent stack. In this case,

i. each centrifugal compressor that is not equipped with blind flanges must be sampled at least once in every 3 consecutive years;

ii. each centrifugal compressor that has been equipped with blind flanges for at least 3 consecutive years does not need to be sampled;

(2) when a centrifugal compressor is used for peaking purposes for no more than 200 hours per year and is not equipped with a meter, determine the volume of gas using data from meters installed on similar equipment;

(3) calibrate the meters in accordance with the methods in paragraph 1 of QC.33.4;

(4) determine the quantity of gas that is recovered using a vapour recovery system or destined for another use, expressed as a percentage, using the number of hours the recovery system is in operation and the quantity of gas directed to the combustible gas system;

(5) add the rated power of all centrifugal compressors at the establishment to determine if the aggregated power is greater than or below 186.4 kW.

QC.33.4.15. Reciprocating compressor venting

For reciprocating compressors, the emitter must

(1) determine the gas flow from reciprocating compressor venting using the following methods:

(a) when the reciprocating rod packing and blowdown vent for the compressor is connected to an open ended vent line, the emitter must determine the gas flow using one of the following methods:

i. by measuring the gas flow from all vents, including gas manifolded to common vents, using calibrated bagging in accordance with paragraph 3 or a high-flow sampler in accordance with paragraph 4;

ii. by measuring the gas flow from all vents, including gas manifolded to common vents, using a temporary or permanent flow meter in accordance with the methods in paragraph 1 of QC.33.4;

iii. for leaks from valves connected to a vent line, such as the isolation valves of compressors that are not operating and pressurized and the blowdown valves of compressors that are pressurized, using an acoustic detection device in accordance with paragraph 2 of QC.33.4;

(b) when the compressor rod packing case is not equipped with a vent line:

i. detect equipment leaks in accordance with paragraph 2 of QC.33.4;

ii. measure the gas flow using a calibrated bag in accordance with paragraph 3, a high-flow sampler in accordance with paragraph 4 or a meter in accordance with a method published by an organization listed in paragraph 1 of QC.33.4;

(2) measure, annually, the gas flow from the reciprocating rod-packing vents, isolation valve vents and blowdown-valve vents of each reciprocating compressor, including gas manifolded to common vents, in the operating mode in which it is found during the measurement period, namely:

(a) reciprocating compressor is in operating, standby-pressurized mode and the gas emitted is from blowdown vent leakage;

(b) the reciprocating compressor is in operating mode and the gas emitted is from the reciprocating rod-packing;

(c) the compressor is not operating and is in depressurized mode and the gas emitted is from isolation valve leakage through the blowdown vent stack. In this case,

i. each reciprocating compressor that is not equipped with blind flanges must be sampled at least once in every 3 consecutive years;

ii. each reciprocating compressor that has been equipped with blind flanges for at least 3 consecutive years does not need to be sampled;

(3) when a reciprocating compressor is used for peaking purposes for no more than 200 hours per year and is not equipped with a flowmeter, determine the volume of gas using data from flowmeters installed on similar equipment;

(4) when using calibrated bags to measure the gas flow from reciprocating compressor venting, use bags only where the emissions are at near-atmospheric pressure and the concentration of hydrogen sulphide is such that it is safe to handle. The calibrated bag must be used according to the manufacturer’s instructions and must be able to capture all the gas emitted during the measurement period. The emitter must also

(a) record the time required to completely fill the bag; if the bag inflates in less than once second, assume one second inflation time;

(b) perform 3 measurements of the time required to fill the bag, and use the average of the 3 measurements to determine the gas flow;

(5) when a high-flow sampler is used, measurements must be made in accordance with the manufacturer’s instructions. The emitter must also calibrate the sampler following the manufacturer’s instructions, at 2.5% CH4 and 97.5% air and 100% CH4 using gas samples representative of known concentrations;

(6) to determine the quantity of gas from reciprocating compressor venting recovered by vapour recovery system, maintain a log of operating times and quantities of gas directed to the recovery system.

QC.33.4.16. Leaks identified following a leak detection survey

An emitter must conduct leak detection surveys in accordance with paragraph 2 of QC.33.4, and must

(1) determine the emission leak factor from each type of component using the following methods:

(a) using specific data related to the operation of the equipment by the emitter and sector-specific methods;

(b) using data from Table W-2 in Part W of Title 40 of the Code of Federal Regulations published by the U.S. Environmental Protection Agency (USEPA), converting the factors into units appropriate for use in equation 33-31;

(c) using data from the Methodology Manuals of the Canadian Association of Petroleum Producers, converting the factors into units appropriate for use in equation 33-31;

(2) determine the duration of leakage from a component using the following methods:

(a) when only one leak detection survey is conducted each year, the emitter must assume that the component was leaking from the start of the year until the leak was repaired. If the leak was not repaired, the emitter must assume that the component was leaking for the entire year;

(b) when more than one leak detection survey is conducted each year, the emitter must assume that the component has been leaking since the last survey. If a leak was detected at the last survey, the emitter must assume that the component, unless the leak has been repaired, was leaking for the entire year.

QC.33.4.17. Fugitive emissions from all components

For fugitive emissions from all components, the emitter must

(1) determine the total number of components of each type, for each type of service, using one of the following methods:

(a) a sector specific method published by the Canadian Gas Association or the Canadian Association of Petroleum Producers;

(b) using enterprise-specific data;

(2) for the first emissions report year, use the emission factor for each type of component, by type of service, using the data in Tables 33-1 and 33-2 in QC.33.6. If no emission factor is specified in the Tables, the emitter must use a factor from Tables W-iA and W-2 in Part 98.230 of Title 40 of the Code of Federal Regulations published by the U.S. Environmental Protection Agency (USEPA), or the most recent version of “A National Inventory of Greenhouse Gas (GHG), Criteria Air Contaminant (CAC) and Hydrogen Sulphide (H2S) Emissions by the Upstream Oil and Gas Industry”, published by Clearstone Engineering Ltd.;

(3) for subsequent emissions report years, determine the emission factor for leaks from each type of component, for each type of service, using the following methods:

(a) using equipment specific factors for the operation of the enterprise’s equipment and a method published by an organization listed in paragraph 1 of QC.33.4;

(b) by updating the emission factors at least every 3 years;

(4) determine CO2 and CH4 concentration in natural gas in accordance with the methods in the most recent version of “Methodology Manuel: Estimation of Air Emissions from the Canadian Natural Gas Transmission, Storage and Distribution System” published by Clearstone Engineering Ltd.

QC.33.4.18. Enhanced oil recovery (EOR) injection pump blowdown

For EOR injection pump blowdown, the emitter must

(1) determine the volume of gas per blowdown for each pump by calculating the internal volume of the blowdown equipment between the isolation valves;

(2) maintain a log of the number of blowdown for each injecting pump during enhanced oil recovery;

(3) determine the density of critical phase greenhouse gas using a method published by an organization listed in paragraph 1 of QC.33.4 or, if those organizations have published no method, using an industry recognized method.

QC.33.4.19. Emissions attributable to the combustion of field gas and vent gas

An emitter who calculates the emissions attributable to the combustion of field gas and vent gas using equation 1-7 in subparagraph 3 of QC.1.3.3 must determine the carbon content and molecular fraction of the gas in accordance with QC.1.5.5.

QC.33.5. Methods for estimating missing data

When, in conducting sampling activities, an emitter is unable to obtain analytical data, the original sample, back-up sample or replacement sample must be analyzed again, using the methods prescribed in this protocol, for the same measurement and sampling periods.

When sampling or measurement data required by this protocol for the calculation of emissions is missing, the emitter must demonstrate that everything possible has been done to ensure that 100% of the data is sampled. The emitter must then use replacement data determined as follows:

(1) for an emitter who uses one of the calculation methods in this protocol:

(a) when the missing value concerns carbon content, high heat value, molecular weight, molar fraction, mass fraction, gas oil ratio, temperature, pressure or sampled data, the emitter must

i. determine the sampling or measurement rate using the following equation:

Equation 33-35

S = QEReal / QEReq

Where:

S = Actual sampling rate or measurement rate, expressed as a percentage;

QEReal = Actual number of samples or measurements carried out by the emitter;

QEReq = Number of samples required or measurements carried out in accordance with QC.33.4;

ii. for data requiring sampling or analysis:

— when T ≥ 0.9: replace the missing value by the arithmetic average of the data sampled or measured immediately preceding and following the missing data period. If no data are available prior to the missing data period, the emitter must use the first data obtained after the missing data period;

— when 0.75 ≤ T < 0.9: replace the missing value by the highest value sample or analyzed during the report year for which the calculation is made;

— when T < 0.75: replace the missing value by the highest value sample or analyzed during the 3 preceding years;

(b) when the missing value concerns time, quantity of gas, quantity of liquid, liquid flow or gas flow, the replacement value must be estimated on the basis of all the data relating to the processes used;

(2) for an emitter who uses a continuous emission monitoring system, apply the procedure in the EPS 1/PG/7 protocol entitled “Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation” published in November 2005 by Environment Canada or apply the method in subparagraph a of paragraph 2 of QC.1.6 to the missing parameters.

QC.33.6. Tables

Table 33-1. Average emission factors for a natural gas exploration or production facility or a natural gas processing facility

(QC.33.3.17)

 _________________________________________________________________________________
|                                                                                 |
| Emission factor by component type                                               |
|_________________________________________________________________________________|
|                                             |                                   |
| Component - Type of service                 | Metric tons THC /component - hour |
|_____________________________________________|___________________________________|
|                                             |                                   |
| Valves - fuel gas                           |  2.81 x 10-06                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Valves - light liquid                       |  3.52 x 10-06                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Valves - gas/vapour - all                   |  2.46 x 10-06                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Valves - gas/vapour - sour                  |  1.16 x 10-06                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Valves - gas/vapour - sweet                 |  2.81 x 10-06                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Connectors - fuel gas                       |  8.18 x 10-07                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Connectors - light liquid                   |  5.51 x 10-07                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Connectors - gas/vapour - all               |  7.06 x 10-07                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Connectors - gas/vapour - sour              |  1.36 x 10-07                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Connectors - gas/vapour - sweet             |  8.18 x 10-07                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Control valves - fuel gas                   |  1.62 x 10-05                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Control valves - light liquid               |  1.77 x 10-05                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Control valves - gas/vapour - all           |  1.46 x 10-05                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Control valves - gas/vapour - sour          |  9.64 x 10-06                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Control valves - gas/vapour - sweet         |  1.62 x 10-05                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Pressure relief valves - fuel gas and       |  1.70 x 10-05                     |
| gas/vapour                                  |                                   |
|_____________________________________________|___________________________________|
|                                             |                                   |
| Pressure relief valves - light liquid       |  5.39 x 10-06                     |
|_____________________________________________|___________________________________|
|                                             |                                   |
| Pressure regulators - fuel gas and          |  8.11 x 10-06                     | 
| gas/vapour                                  |                                   | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Pressure regulators - gas/vapour - sour     |  4.72 x 10-08                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Pressure regulators - gas/vapour - sweet    |  8.39 x 10-06                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Open ended lines - fuel gas                 |  4.67 x 10-04                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Open ended lines - light liquid             |  1.83 x 10-05                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Open ended line - gas/vapour - all          |  4.27 x 10-04                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Open ended lines - gas/vapour - sour        |  1.89 x 10-04                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Open ended lines - gas/vapour - sweet       |  4.67 x 10-04                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Pump seals - light liquid                   |  2.32 x 10-05                     | 
|_____________________________________________|___________________________________|                        

Table 33-2. Average emission factors for an oil exploration and production facility

(QC.33.2, QC.33.3.17, Q.33.4.17)

 _________________________________________________________________________________
|                                             |                                   |
| Component - Type of service                 | Metric tons THC /component - hour |
|_____________________________________________|___________________________________|
|                                             |                                   |
| Valves - fuel gas and gas/vapour            |  1.51 x 10-06                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Valves - heavy liquid                       |  8.40 x 10-09                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Valves - light liquid                       |  1.21 x 10-06                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Connectors - fuel gas and gas/vapour        |  2.46 x 10-06                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Connectors - heavy liquid                   |  7.50 x 10-09                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Connectors - gas/vapour - all               |  1.90 x 10-07                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Control Valves - fuel gas and gas/vapour    |  1.46 x 10-05                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Control Valves - light liquid               |  1.75 x 10-05                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Pressure relief valves - fuel gas and       |  1.63 x 10-05                     |
| gas/vapour                                  |                                   |
|_____________________________________________|___________________________________|
|                                             |                                   |
| Pressure relief valves - heavy liquid       |  3.20 x 10-08                     |
|_____________________________________________|___________________________________|
|                                             |                                   |
| Pressure relief valves - light liquid       |  7.50 x 10-05                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Pressure regulators - fuel gas and          |  6.68 x 10-06                     |
| gas/vapour                                  |                                   |
|_____________________________________________|___________________________________|
|                                             |                                   |
| Open ended lines - fuel gas and gas/vapour  |  3.08 x 10-04                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Open ended lines - light liquid             |  3.73 x 10-06                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Pump seals - heavy liquid                   |  3.20 x 10-08                     | 
|_____________________________________________|___________________________________|
|                                             |                                   |
| Pump seals - light liquid                   |  2.32 x 10-05                     | 
|_____________________________________________|___________________________________|                        

Table 33-3. Average emission factors for natural gas driven pneumatic devices

(QC.33.4.1, QC.33.4.2)

 _________________________________________________________________________________
|                                                                |                |
| Component                                                      |m3 at standard  |
|                                                                |conditions per  |
|                                                                |hour per        |
|                                                                |component       |
|________________________________________________________________|________________|
|                                                                |                |
| High bleed pneumatic device venting                            |     1.3620     | 
|________________________________________________________________|________________| 
|                                                                |                | 
| Intermittent bleed pneumatic device venting                    |     0.4927     | 
|________________________________________________________________|________________| 
|                                                                |                | 
| Low bleed pneumatic device venting                             |     0.0510     | 
|________________________________________________________________|________________| 
|                                                                |                | 
| Pneumatic pump                                                 |     0.3766     | 
|________________________________________________________________|________________|                        

Table 33-4. Manufacturer-specified emission rates for leaks from liquid level controllers, positioners, pressure controllers, transducers and transmitters

(QC.33.3.1, QC.33.3.2)

 __________________________________________________________________________________
|                        |              |              |              |            |
| Description            | Manufacturer | Model        | Operating    |Manufacturer|
|                        |              |              | condition    |rate        |
|                        |              |              |              |(m3/hour)   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Liquid level controller| Bristol      | Series 5453- | Continuous   |   0.0850   | 
|                        | Babcock      | Model 624-II |              |            | 
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Liquid level controller| Fisher       | 2100         | Continuous   |   0.0283   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Liquid level controller| Fisher       | 2500         | Continuous   |   1.1893   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Liquid level controller| Fisher       | 2660         | Continuous   |   0.0283   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Liquid level controller| Fisher       | 2680         | Continuous   |   0.0283   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Liquid level controller| Fisher       | 2900         | Continuous   |   0.6513   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Liquid level controller| Fisher       | L2           | Continuous   |   0.0425   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Liquid level controller| Invalco      | AE-155       | Continuous   |   1.5008   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Liquid level controller| Invalco      | CT Series    | Continuous   |   1.1327   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Liquid level controller| Norriseal    | 1001 (A)     | Intermittent |   0.0000   |
|                        |              | 'Envirosave’ |              |            | 
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Liquid level controller| Norriseal    | 1001 (A) snap| Intermittent |   0.0057   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Liquid level controller| Norriseal    | 1001 (A)     | Intermittent |   0.0002   |
|                        |              | throttle     |              |            | 
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Liquid level controller| Wellmark     | 2001 (snap)  | Intermittent |   0.0057   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Liquid level controller| Wellmark     | 2001         | Intermittent |   0.0002   |
|                        |              | (throttling) |              |            | 
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Positioner             | Becker       | EFP-2.0      | Intermittent |   0.0000   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Positioner             | Becker       | HPP-5        | Continuous   |   0.1416   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Positioner             | Fisher       | 3582         | Continuous   |   0.4531   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Positioner             | Fisher       | 3590         | Continuous   |   0.8495   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Positioner             | Fisher       | 3660         | Continuous   |   0.1982   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Positioner             | Fisher       | 3661         | Continuous   |   0.2959   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Positioner             | Fisher       | 3582i        | Continuous   |   0.5833   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Positioner             | Fisher       | 3610J        | Continuous   |   0.4531   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Positioner             | Fisher       | 3620J        | Continuous   |   0.7532   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Positioner             | Fisher       | DVC 5000     | Continuous   |   0.2832   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Positioner             | Fisher       | DVC 6000     | Continuous   |   0.3964   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Positioner             | Fisher       | Fieldview    | Continuous   |   0.8920   |
|                        |              | Digital      |              |            | 
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Positioner             | Masoneilan   | 7400         | Continuous   |   1.0477   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Positioner             | Masoneilan   | 4600B Series | Continuous   |   0.6796   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Positioner             | Masoneilan   | 4700B Series | Continuous   |   0.6796   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Positioner             | Masoneilan   | 4700E        | Continuous   |   0.6796   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Positioner             | Masoneilan   | SV           | Continuous   |   0.1133   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Positioner             | Moore        | 73N-B        | Continuous   |   1.0194   |
|                        | Products     |              |              |            | 
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Positioner             | Moore        | 750P         | Continuous   |   1.1893   |
|                        | Products     |              |              |            | 
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Positioner             | PMV          | D5 Digital   | Continuous   |   0.0283   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Positioner             | Sampson      | 3780 Digital | Continuous   |   0.0283   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Positioner             | VCR          | VP700 PtoP   | Continuous   |   0.0283   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Pressure controller    | Ametek       | Series 40    | Continuous   |   0.1699   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Pressure controller    | Becker       | HPP-SB       | Continuous   |   0.0000   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Pressure controller    | Becker       | VRP-B-CH     | Continuous   |   0.1416   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Pressure controller    | Becker       | VRP-SB       | Continuous   |   0.0000   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Pressure controller    | Becker       | VRP-SB Gap   | Continuous   |   0.0000   |
|                        |              | Controller   |              |            | 
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Pressure controller    | Becker       | VRP-SB-CH    | Continuous   |   0.0000   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Pressure controller    | Becker       | VRP-SB-PID   | Continuous   |   0.0000   |
|                        |              | Controller   |              |            | 
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Pressure controller    | Bristol      | Series 5453- | Continuous   |   0.0850   |
|                        | Babcock      | Model 10F    |              |            | 
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Pressure controller    | Bristol      | Series 5455- | Continuous   |   0.0708   |
|                        | Babcock      | Model 624-III|              |            | 
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Pressure controller    | CSV          | 4150         | Continuous   |   0.6853   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Pressure controller    | CSV          | 4160         | Continuous   |   0.6853   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Pressure controller    | Dyna-Flow    | 4000         | Continuous   |   0.6853   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Pressure controller    | Fisher       | 2506         | Continuous   |   0.6853   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Pressure controller    | Fisher       | 2516         | Continuous   |   0.6853   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Pressure controller    | Fisher       | 4150         | Continuous   |   0.7362   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Pressure controller    | Fisher       | 4160         | Continuous   |   0.7362   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Pressure controller    | Fisher       | 4194         | Continuous   |   0.1203   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Pressure controller    | Fisher       | 4195         | Continuous   |   0.1203   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Pressure controller    | Fisher       | 4660         | Continuous   |   0.1416   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Pressure controller    | Fisher       | 4100 (large  | Continuous   |   1.4158   |
|                        |              | orifice)     |              |            | 
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Pressure controller    | Fisher       | 4100 (small  | Continuous   |   0.4248   |
|                        |              | orifice)     |              |            | 
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Pressure controller    | Fisher       | C1           | Continuous   |   0.1472   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Pressure controller    | Fisher       | DVC 6010     | Continuous   |   0.0878   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Pressure controller    | Foxboro      | 43AP         | Continuous   |   0.5097   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Pressure controller    | ITT Barton   | 338          | Continuous   |   0.1699   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Pressure controller    | ITT Barton   | 358          | Continuous   |   0.0510   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Pressure controller    | ITT Barton   | 359          | Continuous   |   0.0510   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Pressure controller    | ITT Barton   | 335P         | Continuous   |   0.1699   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Transducer             | Bristol      | 9110-00A     | Continuous   |   0.0119   |
|                        | Babcock      |              |              |            | 
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Transducer             | Bristol      | Series 502   | Continuous   |   0.1671   |
|                        | Babcock      | A/D          |              |            | 
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Transducer             | Fairchild    | TXI 7800     | Continuous   |   0.2407   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Transducer             | Fisher       | 546          | Continuous   |   0.8495   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Transducer             | Fisher       | 646          | Continuous   |   0.2209   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Transducer             | Fisher       | 846          | Continuous   |   0.3398   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Transducer             | Fisher       | i2P-100      | Continuous   |   0.2832   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Transmitter            | Bristol      | Series 5457- | Continuous   |   0.0850   |
|                        | Babcock      | 70F          |              |            | 
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Transmitter            | ITT Barton   | 273A         | Continuous   |   0.0850   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Transmitter            | ITT Barton   | 274A         | Continuous   |   0.0850   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Transmitter            | ITT Barton   | 284B         | Continuous   |   0.0850   |
|________________________|______________|______________|______________|____________|
|                        |              |              |              |            |
| Transmitter            | ITT Barton   | 285B         | Continuous   |   0.0850   |
|________________________|______________|______________|______________|____________|
                         

QC.34. IRON AND STEEL POWDER PRODUCTION

QC.34.1. Covered sources

The covered sources are all the processes used for iron and steel powder production.

QC.34.2. Greenhouse gas reporting requirements

In accordance with subparagraph 3 of the first paragraph of section 6.2, the greenhouse gas emissions report must, in particular, include the following information:

(1) the annual CO2 emissions attributable to the atomization process of molten cast iron, in metric tons;

(2) the annual CO2 emissions attributable to the decarburization process of iron powder, in metric tons;

(3) the annual CO2 emissions attributable to the steel grading process, in metric tons;

(4) the annual CO2 emissions attributable to the annealing process of steel powder, in metric tons;

(5) the annual CO2, CH4 and N2O emissions attributable to the use of stationary combustion units, calculated and reported in accordance with QC.1, in metric tons;

(6) in the case of the atomization process for molten cast iron:

(a) the annual consumption of molten cast iron, in metric tons;

(b) the annual quantity of every other added material that contributes 0.5% or more of the total carbon in the process, in metric tons;

(c) the annual production of atomized cast iron, in metric tons;

(d) the annual quantity of each by-product that contributes 0.5% or more of total carbon in the process, in metric tons;

(e) the average annual carbon content of each material or product referred to in subparagraphs a to d, in metric tons of carbon per metric ton of material;

(7) in the case of the decarburization process for iron powder:

(a) the annual consumption of iron powder, in metric tons;

(b) the annual production of decarburized powder, in metric tons;

(c) the annual quantity of each by-product that contributes 0.5% or more of total carbon in the process, in metric tons;

(d) the average annual carbon content of each material or product referred to in subparagraphs a to c, in metric tons of carbon per metric ton of material or product;

(8) in the case of the steel grading process:

(a) the annual quantity of molten steel feeding the furnace, in metric tons;

(b) the annual consumption of each additive that contributes 0.5% or more of total carbon in the process, in metric tons;

(c) the annual consumption of carbon electrodes, in metric tons;

(d) the annual production of molten steel, in metric tons;

(e) the annual quantity of slag produced, in metric tons;

(f) the annual quantity of air pollution control residue collected, in metric tons;

(g) the annual quantity of other residue produced that contributes 0.5% or more of total carbon in the process, in metric tons;

(h) the average annual carbon content of the materials and products referred to in subparagraphs a to g, in metric tons of carbon per metric ton or materials or products;

(9) in the case of the annealing process for steel powder:

(a) the annual consumption of steel powder, in metric tons;

(b) the annual quantity of steel powder output from annealing furnaces, in metric tons;

(c) the annual quantity of by-products that contribute 0.5% of more of total carbon in the process, in metric tons;

(d) the annual average carbon content of each material or product referred to in subparagraphs a to c, in metric tons of carbon per metric ton of material or product;

(10) the number of times that the methods for estimating missing data provided for in QC.34.5 were used;

(11) the total annual quantity of iron powder and steel powder at bagging, after additives, produced, in metric tons.

Subparagraph e of subparagraph 6, subparagraph d of subparagraph 7, subparagraph h of subparagraph 8 and subparagraph d of subparagraph 9 of the first paragraph do not apply to the CO2 emissions of an emitter who calculates emissions using data from a continuous emission monitoring and recording system.

For the purposes of subparagraph 8 of the first paragraph of section 6.2:

(1) the emissions referred to in subparagraphs 1 to 4 of the first paragraph are emissions attributable to fixed processes;

(2) the emissions referred to in subparagraph 5 of the first paragraph are emissions attributable to combustion.

QC.34.3. Calculation methods for CO2 emissions attributable to iron and steel powder production processes

The annual CO2 emissions attributable to iron and steel powder production must be calculated in accordance with one of the methods in QC.34.3.1 to QC.34.3.5.

QC.34.3.1. Use of a continuous emission monitoring and recording system

The annual CO2 emissions may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.1.3.4.

QC.34.3.2. Calculation of CO2 emissions attributable to the molten cast iron atomization process

The annual CO2 emissions attributable to the molten cast iron atomization process must be calculated using equation 34-1. Materials or products whose carbon content contribute less than 0.5% of the carbon in the process do not have to be considered in this calculation.

Equation 34-1

Where:

CO2 = Annual CO2 emissions attributable to the molten cast iron atomization process, in metric tons;

MI = Quantity of molten iron fed into the process, in metric tons;

CMI = Average annual carbon content of molten cast iron, in metric tons of carbon per metric ton of molten cast iron;

p = Number of materials used other than molten cast iron;

k = Material used other than molten cast iron;

Mk = Annual quantity of each material k other than molten cast iron used, in metric tons;

CM,k = Annual average carbon content of each material k used, other than molten cast iron, in metric tons of carbon per metric ton of material k;

AI = Annual quantity of atomized cast iron, in metric tons;

CAI = Average annual carbon content of atomized cast iron, in metric tons of carbon per metric ton of atomized cast iron;

j = Number of by-products;

m = By-product;

BPj = Annual quantity of by-product j output from the process, in metric tons;

CBP,j = Annual average carbon content of by-product j, or a default value of 0, in metric tons of carbon per metric ton of by-product j;

3.664 = Ratio of molecular weights, CO2 to carbon.

QC.34.3.3. Calculation of CO2 emissions attributable to the iron powder decarburization process

Annual CO2 emissions attributable to the iron powder decarburization process must be calculated using equation 34-2. Materials or products whose carbon content contributes less than 0.5% of the carbon in the process do not have to be included in this calculation.

Equation 34-2

Where:

CO2 = Annual CO2 emissions attributable to the iron powder decarburization process, in metric tons;

IPf = Quantity of iron powder fed into the process, in metric tons;

CIPf = Annual average carbon content of iron powder, in metric tons of carbon per metric ton of iron powder;

IPd = Annual quantity of decarburized iron powder, in metric tons;

CIPd = Annual average carbon content of decarburized iron powder, in metric tons of carbon per metric ton of decarburized iron powder;

j = Number of by-products;

m = By-product;

BPj = Annual quantity of by-product j output from the process, in metric tons;

CBP,j = Annual average carbon content of by-product j, or a default value of 0, in metric tons of carbon per metric ton of by-product j;

3.664 = Ratio of molecular weights, CO2 to carbon.

QC.34.3.4. Calculation of CO2 emissions attributable to the steel grading process

Annual CO2 emissions attributable to the steel grading process must be calculated using equation 34-3. Materials or products whose carbon content contributes less than 0.5% of the carbon in the process do not have to be included in this calculation.

Equation 34-3

Where:

CO2, SGP = Annual CO2 emissions attributable to the steel grading process, in metric tons;

MIf = Annual quantity of molten steel fed into the process, in metric tons;

CMIf = Annual average carbon content of molten steel, in metric tons of carbon per metric ton of molten steel;

j = Additive;

m = Number of additives;

ADj = Annual consumption of additive j, in metric tons;

CAD,j = Annual average carbon content of additive j, in metric tons of carbon per metric ton of additive j;

EL = Annual consumption of carbon electrodes, in metric tons;

CEL = Annual average carbon content of carbon electrodes, in metric tons of carbon per metric ton of carbon electrodes;

MS = Annual production of molten steel, in metric tons;

CMS = Annual average carbon content of molten steel, in metric tons of carbon per metric ton of molten steel;

SL = Annual production of slag, in metric tons;

CSL = Annual average carbon content of slag, or a default value of 0, in metric tons of carbon per metric ton of slag;

R = Annual quantity of air pollution control residue, in metric tons;

CR = Annual average carbon content of air pollution control residue, or a default value of 0, in metric tons of carbon per metric ton of residue;

Rp = Annual quantity of other residue produced, in metric tons;

CRp = Annual average carbon content of other residue produced, or a default value of 0, in metric tons of carbon per metric ton of residue;

3.664 = Ratio of molecular weights, CO2 to carbon.

QC.34.3.5. Calculation of CO2 emissions attributable to the steel powder annealing process

The annual CO2 emissions attributable to the steel powder annealing process may be calculated using equation 34-4:

Equation 34-4

Where:

CO2 = Annual CO2 emissions attributable the steel powder annealing process, in metric tons;

Pa = Annual quantity of steel powder fed into annealing furnaces, in metric tons;

CPa = Average annual carbon content of steel powder fed into annealing furnaces, in kilograms of carbon per kilogram of steel powder;

SPp = Annual quantity of steel powder output from the annealing furnaces, in metric tons;

CSPp = Annual average carbon content of the steel powder output from the annealing furnaces, in metric tons of carbon per metric ton of steel powder;

j = Number of by-products;

m = By-product;

BPj = Annual quantity of by-product j output from the annealing furnaces, in metric tons;

CBP,j = Annual average carbon content of by-product j, or a default value of 0, in metric tons of carbon per metric ton of by-product j;

3.664 = Ratio of molecular weights, CO2 to carbon.

QC.34.4. Sampling, analysis and measurement requirements

When the calculation methods in QC.34.3.2 to QC.34.3.5 are used, the emitter who operates a facility or establishment that produces iron powder and steel powder must:

(1) determine annually the carbon content of each material or product that contributes 0.5% or more of the total carbon in the process, either by using the data provided by the supplier, or by using the following methods:

(a) for iron or iron powder, using the most recent version of ASTM E1019 “Standard Test Methods for Determination of Carbon, Sulfur, Nitrogen, and Oxygen in Steel, Iron, Nickel, and Cobalt Alloys by Various Combustion and Fusion Techniques” or ASTM E415 “Standard Test Method for Atomic Emission Vacuum Spectrometric Analysis of Carbon and Low Alloy Steel”, or using any other analysis method published by an organization listed in QC.1.5;

(b) for steel or steel powder, using one of the following methods:

i. the most recent version of ASM CS-104 UNS G10460 “Carbon Steel of Medium Carbon Content” published by ASM International;

ii. the most recent version of ISO/TR 15349-1 “Unalloyed steel - Determination of low carbon content - Part 1: Infrared absorption method after combustion in an electric resistance furnace (by peak separation)”;

iii. the most recent version of ISO/TR 15349-3 “Unalloyed steel - Determination of low carbon content - Part 3: Infrared absorption method after combustion in an electric resistance furnace (with preheating)”;

iv. the most recent version of ASTM E415 “Standard Test Method for Atomic Emission Vacuum Spectrometric Analysis of Carbon and Low-Alloy Steel”;

v. any other analysis method published by an organization referred to in QC.1.5;

(c) for carbon electrodes, the most recent version of ASTM D5373 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal”, or any other analysis method published by an organization listed in QC.1.5;

(d) for slag, by-products, air pollution control residue or other residue, an analysis method published by an organization listed in QC.1.5 or using a default value of 0;

(2) calculate the annual quantity of each material and product by direct weight measurement using the same plant instruments used for inventory purposes, such as weigh hoppers or belt weigh feeders.

QC.34.5. Methods for estimating missing data

When, in conducting sampling activities, an emitter is unable to obtain analytical data, the original sample, back-up sample or replacement sample must be analyzed again, using the methods prescribed in this protocol, for the same measurement and sampling periods.

When sampling or measurement data required by this protocol for the calculation of emissions is missing, the emitter must demonstrate that everything possible has been done to ensure that 100% of the data is sampled. The emitter must then use replacement data determined as follows:

(1) for an emitter who uses one of the calculation methods in this protocol:

(a) when the missing value concerns carbon content or another sampled value, the emitter must

i. determine the sampling or measurement rate using the following equation:

Equation 34-5

S = QEReal / QEReq

Where:

S = Actual sampling rate or measurement rate, expressed as a percentage;

QEReal = Actual number of samples or measurements carried out by the emitter;

QEReq = Number of samples or measurements required under QC.34.4;

ii. for data requiring sampling or analysis, the emitter must

— when T ≥ 0.9: replace the missing value by the arithmetic average of the data sampled or measured immediately preceding and following the missing data period. If no data are available prior to the missing data period, the emitter must use the first data obtained after the missing data period;

— when 0.75 ≤ T < 0.9: replace the missing value by the highest value sample or analyzed during the report year for which the calculation is made;

— when T < 0.75: replace the missing value by the highest value sample or analyzed during the 3 preceding years;

(b) when the missing value concerns the consumption of molten cast iron, the consumption of carbon electrodes, the quantity of molten steel, the consumption of additive, the quantity of iron or steel powder, the production of atomized cast iron, the quantity of slag, the quantity of by-products, the quantity of residue or the quantity of other materials, the replacement value must be estimated on the basis of all the data relating to the processes used;

(2) for an emitter who uses a continuous emission monitoring system, apply the procedure in the EPS 1/PG/7 protocol entitled “Protocols and performance specifications for continuous monitoring of gaseous emissions from thermal power generation” published in November 2005 by Environment Canada or apply the method in subparagraph a of paragraph 2 of QC.1.6 to the missing parameters.

M.O. 2010-12-06, Sch. A.2; M.O. 2011-12-16, s. 12; M.O. 2012-09-05, s. 8; M.O. 2012-12-11, s. 20; M.O. 2013-12-11, s. 12; I.N. 2014-05-01; M.O. 2014-12-16, s. 11; M.O. 2015-12-14, s. 4; I.N. 2016-01-01; M.O. 2016-12-21, s. 7; I.N. 2017-01-01; M.O. 2017-12-18, s. 9; I.N. 2018-03-01; M.O. 2018-12-05, s. 1; M.O. 2019-12-05, s. 8; M.O. 2020-12-01, s. 12; M.O. 2021-11-29, s. 1; M.O. 2022-12-16, s. 8; M.O. 2023-1009, s. 9.

SCHEDULE B

(Revoked)

M.O. 2007-09-26, Sch. B; M.O. 2010-12-06, s. 13; M.O. 2012-12-11, s. 21.

TRANSITIONAL

2021

(M.O. 2021-11-29) SECTION 2. The greenhouse gas emissions report for 2021, communicated to the Minister not later than 1 June 2022 in accordance with section 6.2 of the Regulation respecting mandatory reporting of certain emissions of contaminants into the atmosphere, includes the information and documents as amended by subparagraph 4 of the first paragraph of section 1 of this Regulation.

2020

(M.O. 2020-12-01) SECTION 13. For the 2020 emissions report, an emitter may use the calculation methods as amended by this Regulation, except the global warming potentials amended by section 11, which must be used only as of the 2021 emissions report.

2019

(M.O. 2019-12-05) SECTION 9. For the 2019 emissions report, an emitter may use the calculation methods as amended by this Regulation.

2017

(M.O. 2017-12-18) SECTION 11. The emitter referred to in the third paragraph of section 6.1 whose fuel distributed and reported for 2016 falls below the threshold determined in subparagraph 2 of the second paragraph of section 2 of the Regulation respecting a cap-and-trade system for greenhouse gas emission allowances is not required to send a verification report on the emissions report for 2017.

2015

(M.O. 2015-12-14) SECTION 5. For the 2015 annual emissions report, an emitter may use the calculation methods as amended by this Regulation and the measurement points in the second paragraph of QC.30.4 of protocol QC.30 of Schedule A.2 as amended by subparagraph b of paragraph 5 of section 4.

SECTION 6. The emitter referred to in subparagraphs 1.1 and 2 of the second paragraph of QC.30.4 of protocol QC.30 of Schedule A.2 who measured fuel at the point of receipt for the purposes of the 2015 annual emissions report is not required to measure again the fuel at the measurement points amended by subparagraph i of subparagraph b of paragraph 5 of section 4 for subsequent emissions reports.

2014

(M.O. 2014-12-16) SECTION 12. For the 2014 annual emissions report, an emitter may use the calculation methods as amended by this Regulation.

2013

(M.O. 2013-12-11) SECTION 13. For the 2013 emissions report, an emitter may use the calculation methods as amended by this Regulation.

2012

(M.O. 2012-12-11) SECTION 22. For the 2012 emissions report:

(1) an emitter required by section 6.1 of the Regulation respecting mandatory reporting of certain emissions of contaminants into the atmosphere (chapter Q-2, r. 15), as it read prior to 1 January 2013, to communicate monthly and quarterly data to the Minister that are no longer required as of that date must retain the data but is no longer required to communicate them;

(2) an emitter may use the calculation methods as amended by this Regulation;

(3) an emitter does not need to have the emissions referred to in the second paragraph of section 6.6, as amended by section 11 of this Regulation, verified.

(M.O. 2012-09-05) SECTION 9. Emitters referred to in the third paragraph of section 6.1, as amended by section 1 of this Regulation, are only required to report their greenhouse gas emissions in accordance with the Regulation respecting mandatory reporting of certain emissions of contaminants into the atmosphere (chapter Q-2, r. 15) beginning on 1 January 2013.

2011

(M.O. 2011-12-16) SECTION 13. For 2012 emissions reports, despite section 6.3 of the Regulation respecting mandatory reporting of certain emissions of contaminants into the atmosphere (chapter Q-2, r. 15), an emitter is not required to use the following methods prescribed in Schedule A.2:

(1) for the transportation and distribution of electricity and the use of equipment to produce electricity, the methods in QC.24;

(2) for mobile equipment, the methods in QC.27;

(3) for the transmission and distribution of natural gas, the methods in QC.29.3.1, QC.29.3.2, QC.29.3.7 and QC.29.3.8.

2010

(M.O. 2010-12-06) SECTION 14. For report year 2010, emitters must report their greenhouse gas emissions in accordance with the Regulation respecting mandatory reporting of certain emissions of contaminants into the atmosphere as it read on 29 December 2010.

SECTION 15. From report year 2011,

(1) despite the first paragraph of section 6.3 of the Regulation respecting mandatory reporting of certain emissions of contaminants into the atmosphere, introduced by section 8 of this Regulation, emitters are not required to use the calculation methods prescribed in QC.2 to QC.17 of Schedule A.2;

(2) sections 6.6 to 6.9 of the Regulation respecting mandatory reporting of certain emissions of contaminants into the atmosphere, introduced by section 8 of this Regulation, do not apply.

REFERENCES

M.O. 2007-09-26, 2007 G.O. 2, 2833

M.O. 2010-12-06, 2010 G.O. 2, 3862A

S.Q. 2010, c. 7, s. 282

S.Q. 2011, c. 20, s. 56

M.O. 2011-12-16, 2011 G.O. 2, 3756B

M.O. 2012-09-05, 2012 G.O. 2, 2759

M.O. 2012-12-11, 2012 G.O. 2, 3665

M.O. 2013-12-11, 2013 G.O. 2, 3836

M.O. 2014-12-16, 2014 G.O. 2, 2930

M.O. 2015-12-14, 2015 G.O. 2, 3491

M.O. 2016-12-21, 2016 G.O. 2, 4203A

M.O. 2017-12-18, 2017 G.O. 2, 3875A

M.O. 2018-12-05, 2018 G.O. 2, 5291

M.O. 2019-12-05, 2019 G.O. 2, 3152

M.O. 2020-12-01, 2020 G.O. 2, 3415

M.O. 2021-11-29, 2021 G.O. 2, 5103

M.O. 2022-12-16, 2022 G.O. 2, 4373

M.O. 2023-1009, 2023 G.O. 2, 3187