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

Full text
chapter Q-2, r. 15
Regulation respecting mandatory reporting of certain emissions of contaminants into the atmosphere
ENVIRONMENT QUALITY — EMISSIONS OF CONTAMINANTS
Environment Quality Act
(chapter Q-2, ss. 2.2, 46.2, 115.27, 115.34 and 124.1).
Q-2
September 1 2012
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.
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.
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. 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.
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.
M.O. 2007-09-26, s. 3; M.O. 2010-12-06, s. 3; M.O. 2011-12-16, 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 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 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 information must include any data pertaining to production, fuels used and raw materials relevant to the calculation or assessment of the quantities of contaminants emitted on an annual basis, and the emission factors used for the calculation or assessment.
In addition, the information must be provided in the form in Parts I to III of Schedule B.
For the purposes of the second paragraph, fuels integral to a process or used to supply transportation machinery integral to a process must be taken into account, as must fuels used to heat facilities.
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, for each of them, the quantity of fuels and raw materials used, and the volume of production.
In addition, when an facility or an establishment changes operator during a year, the report 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 facility or establishment was under his or her responsibility.
M.O. 2007-09-26, s. 4; M.O. 2010-12-06, s. 5; M.O. 2011-12-16, s. 2.
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, without delay, transmit to the Minister any information transmitted to the Minister by electronic means of the Environment of Canada concerning any of those contaminants emitted into the atmosphere by the facility or establishment.
The operator must also provide the Minister with all data pertaining to production, fuels used and raw materials that were used to calculate the quantities of contaminants reported to the Minister of the Environment of Canada, along with the information referred to in the first paragraph, and the emission factors used for the calculation. The operator must identify the activities, processes or equipment that are the source of contaminant emissions by indicating separately, for each of them, the quantity of fuels and raw materials used, and the volume of production. That information must be provided in the form in Parts I and III of Schedule B.
In addition, if the operator is required under a public notice given pursuant to section 46 of the Canadian Environmental Protection Act (1999) to notify the Minister of the Environment of Canada that the facility or establishment ceases to meet the prescribed reporting criteria, the operator must so notify the Minister at the same time.
M.O. 2007-09-26, s. 5; M.O. 2010-12-06, s. 6; M.O. 2011-12-16, s. 3.
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 factor resulting from an emissions sampling; or
(4.1)  a model for the estimation of emissions;
(5)  (paragraph replaced);
(6)  (paragraph replaced).
A report by the operator or a person authorized by the operator stating that the data transmitted was established in conformity with the best practices that apply and the requirements of this Regulation must also be transmitted to the Minister by the operator, along with the information required by section 4 or the copy of the report referred to in section 5.
M.O. 2007-09-26, s. 6; M.O. 2010-12-06, s. 7; M.O. 2011-12-16, s. 4.
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 until such time as the emissions have been below the reporting threshold for 4 consecutive years.
Where an establishment has more than 1 facility, the data pertaining to each facility must be identified separately.
In the case of a person or municipality that operates an enterprise that purchases electricity produced outside Québec for its own consumption or for sale in Québec, or that exports, transports or distributes electricity, an enterprise that transports or distributes natural gas, or an enterprise that carries on gas or oil exploration or development, the threshold reporting provided for in the first paragraph applies to the enterprise, which is considered as an establishment for the purposes of this Division.
In addition, when an enterprise, a facility or an establishment changes operator during a year, the declaration 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 or third paragraph closes an establishment for which the greenhouse gas emissions reached or exceeded the reporting threshold during the preceding calendar year, it must, within 6 months of closing the establishment, send to the Minister an emissions report for the period during which the establishment was operating but was not covered by such a report.
M.O. 2010, s. 8; M.O. 2011-12-16, s. 5.
6.2. An emitter referred to in section 6.1 must, not later than 1 June each year, communicate electronically to the Minister a greenhouse gas emissions report for the preceding calendar year, including
(1)  the total quantity of the emitter’s CO2 equivalent greenhouse gas emissions, calculated using the following equation:
Where:
CO2e = Annual greenhouse gas emissions, in metric tons of carbon dioxide equivalent;
GHGi = 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 quantity of emissions of each type of greenhouse gas referred to in Schedule A.1 attributable to the operation of each type of enterprise, facility and establishment and, where applicable, attributable to the pursuit of each type of activity or the use of each type of process or equipment, excluding CO2 emissions attributable to the combustion of biomass or biomass fuels and those that have been captured, stored or eliminated;
(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;
(4.1)  the total quantity of CO2 emissions attributable to fermentation of biomass and biofuels;
(4.2)  the type of biomass used, such as post-consumer residues, processing residues or wood waste;
(5)  the total quantity of CO2 emissions that is captured, stored, re-used, eliminated or transferred out of the establishment, the quantity of emissions generated by each operation and the location of each operating or transfer site;
(6)  the calculation methods used in accordance with section 6.3 and, where applicable, the quantity of greenhouse gas emissions in CO2 equivalent and the emission sources for which a calculation method was used pursuant to the second paragraph of that section;
(7)  the emission factors used and their origin or method of determination;
(8)  the total greenhouse gas emissions of each type, excluding the emissions referred to in the second paragraph of section 6.6, namely:
(a)  the annual fixed process emissions, in metric tons CO2 equivalent;
(b)  the annual combustion emissions, in metric tons CO2 equivalent;
(c)  the annual “other” category emissions, in metric tons CO2 equivalent;
(9)  in the case of an emitter required to cover greenhouse gas emissions pursuant to section 46.6 of the Environment Quality Act (c. Q-2), the annual quantity of benchmark units relating to the emitter’s activities.
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, s. 8; M.O. 2011-12-16, s. 6.
6.3. The quantities of greenhouse gas emissions reported under the first paragraph of section 6.2 must be calculated using one of the calculation methods 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 from one or more sources of emissions when the emissions attributable to them represent no more than 3% of the emitter’s total emissions in CO2 equivalent, up to a maximum of 20,000 metric tons CO2 equivalent; or
(2)  if no calculation method 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 methods for each annual report.
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, s. 8.
6.4. An emitter referred to in section 6.1 must submit, with the information communicated pursuant to section 6.2, the following information:
(1)  the name and address of the enterprise, facility or establishment as well as the name of and contact information for its representative;
(2)  the emitter’s telephone and fax numbers and electronic address;
(3)  the business number assigned to the emitter 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.
6.5. An emitter whose annual greenhouse gas emissions report includes one or more errors or omissions must, as soon as possible, communicate a revised emissions report electronically to the Minister, along with a notice of correction detailing
(1)  the difference between the initial report and revised report;
(2)  the circumstances that led to the errors or omissions and, where applicable, the corrections made;
(3)  the quantity of greenhouse gas emissions represented by the errors or omissions, calculated using the equation referred to in subparagraph 1 of the first paragraph of section 6.7.
M.O. 2010-12-06, s. 8.
6.6. An emitter who, in accordance with section 6.2, reports annual greenhouse gas emissions equal to or greater than 25,000 metric tons CO2 equivalent, excluding emissions referred to in the second paragraph, must, not later than 1 June, send to the Minister a verification report on the 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.
For the purposes of the verification threshold referred to in the first paragraph, the following emissions are excluded:
(1)  CO2 emissions attributable to the combustion or fermentation 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 attributable to mobile equipment on the site of an establishment and referred to in QC.27 in Schedule A.2;
(4)  until 31 December 2014, CH4 emissions attributable to petroleum refinery operations and referred to in QC.9.3.6, QC.9.3.9 and QC.9.3.12 in Schedule A.2;
(5)  until 31 December 2014, CH4 and N2O emissions attributable to the anaerobic treatment of wastewater and referred to in Schedule A.2, specifically in QC.9.3.7 in the case of a petroleum refinery, QC.10.2.7 in the case of a pulp and paper plant, and QC.12.3.7 in the case of petrochemical product manufacturing;
(6)  until 31 December 2012, CO2, CH4 and N2O emissions attributable to the transmission and distribution of natural gas and referred to in QC.29.3.1, QC.29.3.2, QC.29.3.7, QC.29.3.8 and QC.29.3.9 in Schedule A.2.
The emitter must have the annual report verified by a verifying organization that
(1)  has not acted as a consultant to the emitter for the quantification or greenhouse gas emissions report during the 3 preceding years;
(2)  has 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 other than the organization that verified the report the preceding year but that verified a report for previous years, the organization must not have carried out a verification for the emitter in the 3 previous years.
An emitter must have the emitter’s annual report verified until such time as the emitter’s greenhouse gas emissions fall below the verification threshold provided for in the first paragraph for 4 consecutive years.
Despite the first paragraph, the verification report on the emissions report for 2012 may be sent to the Minister not later than 1 September 2013.
M.O. 2010, s. 8; M.O. 2011-12-16, s. 7.
6.7. A revised emissions report referred to in section 6.5 must include a verification report completed in accordance with this Regulation where
(1)  the emissions initially reported were equal to or greater than 25,000 metric tons CO2 equivalent and where the errors or omissions represented over 5% of those emissions based on the following equation:
Where:
PE = Percentage of error;
SEO = Sum of CO2 equivalent emissions erroneously calculated or omitted, in metric tons;
TER = Total CO2 equivalent emissions initially reported, in metric tons; or
(2)  after correction of the errors or omissions, the total greenhouse gas emissions are equal to or greater than 25,000 metric tons CO2 equivalent.
In the case referred to in subparagraph 2 of the first paragraph, the verification report for the emissions report must also cover the initial emissions report.
M.O. 2010-12-06, s. 8.
6.8. The verification of an initial or revised 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 at least 1 visit of the enterprise, facility or establishment covered by the report by the verifier designated by the verification organization.
In the case of an emitter who transports or distributes electricity or natural gas, the visit referred to in subparagraph 2 of the first paragraph must allow a representative sampling of the emitter’s facilities.
M.O. 2010-12-06, s. 8; M.O. 2011-12-16, s. 8.
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 as well as the name of and contact information for the verifier 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 and the date of any visit to the enterprise, facility or establishment;
(4)  a description of any error or omission observed in the emissions report or relating to the data, information or methods used;
(5)  an assessment of the errors or omissions referred to in paragraph 4, calculated using the equation referred to in subparagraph 1 of the first paragraph of section 6.7;
(6)  where applicable, the corrections made to the emissions report following the verification;
(7)  the total quantity of the emitter’s CO2 equivalent emissions for the report year, as well as the total quantity of CO2 emissions attributable to the combustion of biomass and biofuels; and
(8)  the conclusions of the verification concerning the accuracy and reliability of the emissions report.
M.O. 2010, 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 for a minimum of 7 years from the date on which they were produced.
M.O. 2007-09-26, s. 7; M.O. 2010-12-06, s. 9.
7.1. Any device, system or equipment required under this Regulation must be maintained in good working order and operate optimally during operating hours.
M.O. 2010-12-06, s. 10.
DIVISION III
OFFENCES
8. Whoever fails to communicate to the Minister data, information, notices and documents prescribed by this Regulation, communicates false or inaccurate data or information, fails to use the calculation methods prescribed by this regulation or fails to retain the data, information and documents for the period prescribed is liable
(1)  to a fine of $2,000 to $12,000 in the case of a natural person; and
(2)  to a fine of $5,000 to $25,000 in the case of a legal person.
M.O. 2007-09-26, s. 8; S.Q. 2011, c. 20, s. 56.
9. In the case of a second or subsequent offence, the fines in section 8 are doubled.
M.O. 2007-09-26, s. 9.
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)


- total fluorides 7782-41-4 10 tons
____________________________________________
- polycyclic aromatic hydrocarbons
(PAHs):
- Fluorene; 86-73-7
____________________________________________
- Phenanthrene; 85-01-8
____________________________________________
- Anthracene 120-12-7
____________________________________________
- Pyrene 129-00-0
____________________________________________
- Fluoranthene 206-44-0
____________________________________________
- Chrysene 218-01-09
____________________________________________
Contaminants - Benzo (a) anthracene 56-55-3 50 kg
that cause ____________________________________________ on an annual
toxic pollution - Benzo (a) pyrene 50-32-8 basis for all the
____________________________________________ contaminants in
- Benzo (e) pyrene 192-97-2 the PAH category
____________________________________________
- 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
_______________________________________________________________
- total reduced sulphur 10 tons on an
compounds: annual basis for
- hydrogen sulphide (H2S); 7783-06-4 all the
____________________________________________ contaminants in
- methyl mercaptan (CH3SH); 74-93-1 the category of
____________________________________________ total reduced
- dimethyl sulphide (CH3)2S 75-18-3 sulphur compounds
- dimethyl disulphide S2(CH3)2 624-92-0

Part II



Types Contaminants Reporting
____________________________________________ thresholds (2)
Identification CAS(1)


- sulphur dioxide (SO2); 7446-09-05
____________________________________________
- nitrogen oxides (NOX); 11104-93-1
Contaminants ____________________________________________
that cause acid - volatile organic compounds;
rain and smog ____________________________________________
- carbon monoxide (CO); 630-08-0
____________________________________________
- total particulate matter;
- particulate matter <10 microns;
- particulate matter <2.5 microns;
- ammonia (NH3).


- mercury (Hg) and its compounds;
- lead (Pb) and its compounds;
- cadmium (Cd) and its compounds;
Contaminants - polychlorodibenzo-p-dioxines;
that cause toxic - polychlorinated dibenzofurans;
pollution ____________________________________________
- benzene; 71-43-2
____________________________________________
- hexachlorobenzene; 118-74-1
____________________________________________
- formaldehyde; 50-00-0
____________________________________________
- arsenic and its compounds;
- hexavalent chromium compounds.

(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).
M.O. 2007-09-26, Sch. A; M.O. 2010-12-06, s. 11; M.O. 2011-12-16, ss. 9 and 10.
SCHEDULE A.1
(ss. 1, 6.1 and 6.2)
Greenhouse gases and global warming potentials
_________________________________________________________________________________
| | | |
| Greenhouse gas - identification | CAS1 | Global warming |
| | | potential (GWP) |
|_______________________________________|___________|_____________________________|
| | | |
| - Carbon dioxide (CO2) | 124-38-9 | 1 |
|_______________________________________|___________|_____________________________|
| | | |
| - Methane (CH4) | 74-82-8 | 21 |
|_______________________________________|___________|_____________________________|
| | | |
| - Nitrous oxide (N2O) |10024-97-2 | 310 |
|_______________________________________|___________|_____________________________|
| | | |
| - Sulphur hexafluoride (SF6) | 2551-62-4 | 23 900 |
|_______________________________________|___________|_____________________________|
| |
| - Hydrofluorocarbons (HFCs): |
|_________________________________________________________________________________|
| | | |
| • HFC-23 (CHF3) | 75-46-7 | 11 700 |
|_______________________________________|___________|_____________________________|
| | | |
| • HFC-32 (CH2F2) | 75-10-5 | 650 |
|_______________________________________|___________|_____________________________|
| | | |
| • HFC-41 (CH3F) | 593-53-3 | 150 |
|_______________________________________|___________|_____________________________|
| | | |
| • HFC-43-10mee (C5H2F10) |138495-42-8| 1 300 |
|_______________________________________|___________|_____________________________|
| | | |
| • HFC-125 (C2HF5) | 354-33-6 | 2 800 |
|_______________________________________|___________|_____________________________|
| | | |
| • HFC-134 (CHF2CHF2) | 359-35-3 | 1 000 |
|_______________________________________|___________|_____________________________|
| | | |
| • HFC-134a (CH2FCF3) | 811-97-2 | 1 300 |
|_______________________________________|___________|_____________________________|
| | | |
| • HFC-143 (CHF2CH2F) | 430-66-0 | 300 |
|_______________________________________|___________|_____________________________|
| | | |
| • HFC-143a (CF3CH3) | 420-46-2 | 3 800 |
|_______________________________________|___________|_____________________________|
| | | |
| • HFC-152a (CH3CHF2) | 75-37-6 | 140 |
|_______________________________________|___________|_____________________________|
| | | |
| • HFC-161 (C2H5F) | 353-36-6 | 12 |
|_______________________________________|___________|_____________________________|

| | | |
| • HFC-227ea (C3HF7) | 431-89-0 | 2 900 |
|_______________________________________|___________|_____________________________|
| | | |
| • HFC-236cb (C3H2F6) | 677-565 | 1 300 |
|_______________________________________|___________|_____________________________|
| | | |
| • HFC-236ea (C3H2F6) | 431-63-0 | 1 200 |
|_______________________________________|___________|_____________________________|
| | | |
| • HFC-236fa (C3H2F6) | 690-39-1 | 6 300 |
|_______________________________________|___________|_____________________________|
| | | |
| • HFC-245ca (C3H3F5) | 679-86-7 | 560 |
|_______________________________________|___________|_____________________________|
| | | |
| • HFC-245fa (C3H3F5) | 460-73-1 | 950 |
|_______________________________________|___________|_____________________________|
| | | |
| • HFC-365mfc (C4H5F5) | 406-58-6 | 890 |
|_______________________________________|___________|_____________________________|
| |
| - Perfluorocarbons (PFCs) |
|_________________________________________________________________________________|
| | | |
| • Perfluoromethane (CF4) | 75-73-0 | 6 500 |
|_______________________________________|___________|_____________________________|
| | | |
| • Perfluoroethane (C2F6) | 76-16-4 | 9 200 |
|_______________________________________|___________|_____________________________|
| | | |
| • Perfluoropropane (C3F8) | 76-19-7 | 7 000 |
|_______________________________________|___________|_____________________________|
| | | |
| • Perfluorobutane (C4F10) | 355-25-9 | 7 000 |
|_______________________________________|___________|_____________________________|
| | | |
| • Perfluorocyclobutane (c-C4F8) | 115-25-3 | 8 700 |
|_______________________________________|___________|_____________________________|
| | | |
| • Perfluoropentane (C5F12) | 678-26-2 | 7 500 |
|_______________________________________|___________|_____________________________|
| | | |
| • Perfluorohexane (C6F14) | 355-42-0 | 7 400 |
|_______________________________________|___________|_____________________________|
| | | |
| - 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.
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
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 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
The greenhouse gas emissions report referred to in section 6.2 must 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;
(2) the annual consumption of each type of fuel, expressed
(a) in cubic metres at standard conditions, for gases;
(b) in kilolitres, for liquids;
(c) in metric tons, for solids other than biomass solid fuels; and
(d) in bone dry metric tons, for biomass solid fuels;
(3) where carbon content is used to calculate CO2 emissions, the average 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 high heat value of each type of fuel, expressed
(a) in gigajoules per metric ton, for solid fuels;
(b) in gigajoules per kilolitre, for liquid fuels; and
(c) in gigajoules per cubic metre, for gaseous fuels;
(5) for stationary combustion units that burn biomass fuels or municipal solid waste, the annual steam generation in kilograms, where it is used to calculate emissions;
(6) in the case of acid gas scrubbing equipment, the annual quantity of sorbent used, in metric tons.
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, 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) with the exception of an emitter to whom section 6.6 of this Regulation applies, for any type of fuel for which an emission factor is specified in Table 1-3, 1-4, 1-5 or 1-6, as indicated in QC.1.7, and a high heat value is specified in Table 1-1 or 1-2;
(2) for natural gas with a high heat value that is greater than or equal to 36.3 MJ/ m3 but less than or equal to 40.98 MJ/m3, 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 operated for more than 1,000 hours during at least one of the 3 preceding years;
(3) for any fuel in Table 1-2;
(4) for municipal solid waste when no steam is generated;
(5) for a biomass fuel specified in Table 1-3 except if it is targeted by another calculation method 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 × HMV × EF × 0.001
Where:
CO2 = Annual CO2 emissions attributable to the combustion of each type of fuel, in metric tons;
Mass or volume of the fuel combusted during the year, expressed
— as a mass in metric tons, for solid fuels;
— as a volume in cubic metres at standard conditions, for gaseous fuels;
— as a volume in kilolitres, for liquid fuels;
HHV = High heat value of the fuel specified in Tables 1-1 and 1-2, expressed
— in gigajoules per metric ton, for solid fuels;
— in gigajoules per kilolitre, for liquid fuels;
— in gigajoules per cubic metre, for gaseous fuels;
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 × 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
— as a mass in kilograms, for solid fuels;
— as a volume in cubic metres at standard conditions, for gaseous fuels;
— as a volume in litres, for liquid fuels;
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 kilogram, for solid fuels;
— in kilograms of CO2 per cubic metre at standard conditions, for gaseous fuels;
— in kilograms of CO2 per litre, for liquid fuels;
0.001 = Conversion factor, kilograms to metric tons.
QC.1.3.2. Calculation method using the fuel-specific default CO2 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) using equation 1-2
(a) with the exception of an emitter to whom section 6.6 of this Regulation applies, for 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;
(b) for natural gas with a high heat value that is greater than or equal to 36.3 MJ/ m3 but less than or equal to 40.98 MJ/m3;
(c) for a fuel specified in Table 1-2 or a biomass fuel.
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
— as a mass in metric tons, for solid fuels;
— as a volume in cubic metres at standard conditions, for gaseous fuels;
— as a volume in kilolitres, for liquid fuels;
HHVi = High heat value of the fuel for the measurement period i, expressed
— in gigajoules per metric ton, for solid fuels;
— in gigajoules per kilolitre, for liquid fuels;
— in gigajoules per cubic metre, for gaseous fuels;
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;
(2) using equation 1-3 for the use of municipal solid waste, except by an emitter to whom section 6.6 of this Regulation applies, and for any biomass solid fuel specified in Table 1-3 in QC.1.7, when the combustion of the fuels produces steam.
Equation 1-3
C02 = 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, 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 CO2emissions may be calculated using equations 1-4 to 1-7, depending on the type of fuel, by any emitter to whom section 6.6 applies who combusts fuels other than those specified in QC.1.3.2 (1) (b) and (c) and by any emitter using stationary units with a rated heat capacity above 264 GJ/h that operated over 1,000 hours during at least 1 of the 3 preceding years:
(1) for solid fuels, 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 = Mass of solid fuel combusted during measurement period i, in metric tons;
CCi = Average carbon content of the solid 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 solid 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
C02 = 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 liquid fuels, the emitter must use equation 1-6:
Equation 1-6
Where:
CO2 = Annual CO2 emissions attributable to the combustion of each type of liquid fuel, 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 liquid 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 gaseous fuels, the emitter must use equation 1-7:
Equation 1-7
Where:
CO2 = Annual CO2 emissions attributable to the combustion of each type of gaseous fuel, 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 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;
0.001 = Conversion factor, kilograms to metric tons.
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.
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.
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:
(a) use the applicable equations in QC.1.3.1 to QC.1.3.4 to calculate the total CO2 emissions;
(b) if the fuels contain over 5% of biomass by weight or if waste-derived fuels make up over 30% by weight of the fuels combusted during the year, calculate the emissions in accordance with ASTM D6866-101"Standard Test Methods for Determining the Biobased Content of Solid, Liquid, and Gaseous Samples Using Radiocarbon Analysis";
(c) conduct, at least every 3 months, an analysis on a representative fuel or exhaust gas sample in accordance with ASTM D6866-10, the analysis being conducted on the exhaust gas stream when waste-derived fuels are combusted, and collect exhaust gas stream samples over a period of at least 24 consecutive hours in accordance with ASTM D7459-08 "Standard Practice for Collection of Integrated Samples for the Speciation of Biomass (Biogenic) and Fossil-Derived Carbon Dioxide Emitted from Stationary Emissions Sources";
(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 ASTM D6866-10 on the stationary combustion unit of the emitter’s choice if there is a common fuel source for multiple units;
(3) when equation 1-1 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
The annual CO2 emissions attributable to acid gas scrubbing equipment 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, 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.1.4.4.
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 et de 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 CO2emissions may be calculated using equation 1-10 with respect to the use:
(1) with the exception of an emitter to whom section 6.6 of this Regulation applies, of any type of fuel for which an emission factor is specified in Table 1-3, 1-6, 1-7 or 1-8 in QC.1.7 and a high heat value is specified in Table 1-1 or 1-2, subject to the emissions attributable to the combustion of coal which must be calculated using equation 1-11;
(2) of natural gas with a high heat value greater than or equal to 36.3 MJ/m3 but less than or equal to 40.98 MJ/m3;
(3) of a fuel specified in Table 1-2 or of a biomass fuel.
Equation 1-10
CH4 or N20 = Fuel × HHV × EF × 0.000001
Where:
CH4 or N20 = Annual CH4 or N20 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
— as a mass in metric tons, for solid fuels;
— as a volume in cubic metres at standard conditions, for gaseous fuels;
— as a volume in kilolitres, for liquid fuels;
HHV = High heat value of the fuel specified in Table 1-1 or 1-2, expressed
— in gigajoules per metric ton, for solid fuels;
— in gigajoules per kilolitre, for liquid fuels;
— in gigajoules per cubic metre, for gaseous fuels;
EF = CH4 or N20 emission factor for the fuel 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, or emission factor specified in the document “AP-42, Compilation of Air Pollutant Emission Factors” published by the U.S. Environmental Protection Agency (USEPA), in grams of CH4 or N20 per gigajoule;
0.000001 = Conversion factor, grams to metric tons.
Equation 1-11
CH4 or N20 = Fuel × EFc × 0.000001
Where:
CH4 or N20 = Annual CH4 or N20 emissions attributable to the combustion of coal, in metric tons;
Fuel = Mass of the coal combusted during the year, in metric tons;
EFc = CH4 or N20 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 ou N20 per metric ton of coal;
0.000001 = Conversion factor, grams 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
— as a mass in metric tons, for solid fuels;
— as a volume in cubic metres at standard conditions, for gaseous fuels;
— as a volume in kilolitres, for liquid fuels;
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 metric ton, for solid fuels;
— in gigajoules per kilolitre, for liquid fuels;
— in gigajoules per cubic metre, for gaseous fuels;
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 specified in Table 1-3 or 1-7 in QC.1.7, or emission factor specified in 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 of required annually as specified in QC.1.5.1;
i = Measurement period;
Fueli = Mass of the coal combusted during the measurement period i, in metric tons;
EFc = CH4 or N2O demission 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 metric ton of coal;
0.000001 = 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 emitterr
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.1.5. Sampling, analysis and measurement requirements
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;
(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;
(5) at each delivery, for coal and any other fuel not referred to in paragraphs 1 to 4.
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, tank drop measurements may also be used;
(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.
A flow meter measuring the mass flow of liquid fuels may be used when the mass flow can be used to determine the volume flow. The density must in such cases be measured at the same frequency as the carbon content using method ASTM D1298-99 (2005) “Standard Test Method for Density, Relative Density (Specific Gravity), or API Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method”. An emitter using one of the methods specified in QC.1.3.1 or QC.1.3.2 may, however, use the densities specified in Table 1-10.
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, either:
— in gigajoules per ton, for solid fuels;
— in gigajoules per kilolitre, for liquid fuels;
— in gigajoules per cubic metre, for gaseous fuels;
n = Number of measurements of high heat value;
i = Measurement;
HHVi = High heat value for measurement period i, either:
— in gigajoules per ton, for solid fuels;
— in gigajoules per kilolitre, for liquid fuels;
— in gigajoules per cubic metre, for gaseous fuels;
Fueli = Mass or volume of fuel combusted during measurement period i, either:
— as a mass in metric tons, for solid fuels;
— as a volume in kilolitres, for liquid fuels;
— as a volume in cubic metres at standard conditions, for gaseous fuels.
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 ASTM D1826-94 (2003) "Standard Test Method for Calorific (Heating) Value of Gases in Natural Gas Range by Continuous Recording Calorimeter", ASTM D3588-98 (2003) "Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuels", ASTM D4891-89 (2006) "Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion" and GPA 2261-00 "Analysis for natural gas and similar gaseous mixtures by gas chromatography" published by the Gas Processors Association (GPA);
(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 megajoules per cubic metre at standard conditions;
LHV = Low heat value of the fuel or fuel mixture, in megajoules per cubic metre at standard conditions;
CF = Conversion factor for converting low heat value to high heat value, established as follows:
(a) for natural gas, 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 ASTM D240-09 "Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter" or ASTM D4809-09a "Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method)";
(3) for biomass solid fuel, in accordance with ASTM D5865-07a "Standard Test Method for Gross Calorific Value of Coal and Coke";
(4) for waste-derived fuels, in accordance with ASTM D5865-07a or ASTM D5468-02 (2007) "Standard Test Method for Gross Calorific and Ash Value of Waste Materials" and, when the waste-derived fuels are not pure biomass fuels, by calculating the biomass fuel portion of CO2 emissions in accordance with subparagraph 2 of the fifth paragraph of QC.1.3.4.
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, either:
— in metric tons of carbon per ton, for solid fuels;
— in metric tons of carbon per kilolitre, for liquid fuels;
— in kilograms of carbon per kilogram, for gaseous fuels;
n = Number of measurements of carbon content;
i = Measurement;
CCi = Carbon content of the fuel for measurement period i, either:
— in metric tons of carbon per ton, for solid fuels;
— in metric tons of carbon par kilolitre, for liquid fuels;
— in kilograms of carbon per kilogram, for gaseous fuels;
Fueli = Mass or volume of fuel combusted during measurement period i, either:
— as a mass in metric tons, for solid fuels;
— as a volume in cubic metres at standard conditions, for gaseous fuels;
— as a volume in kilolitres, for liquid fuels.
The carbon content and molecular weight or molar fraction of gaseous fuels 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 ASTM D5373-08 "Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal";
(2) for petroleum-based liquid fuels and liquid waste-derived fuels, in one of the following ways:
(a) in accordance with ASTM D5291-02 (2007) "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 ASTM D3238-95 (2005) "Standard Test Method for Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by n-d-M Method" and either ASTM D2502-04 "Standard Test Method for Estimation of Molecular Weight (Relative Molecular Mass) of Petroleum Oils from Viscosity Measurements" or ASTM D2503-92 (2007) "Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurements of Vapor Pressure";
(3) for gaseous fuels, by applying ASTM D1945-03 “Standard Test Method for Analysis of Natural Gas by Gas Chromatography”, ASTM D1946-90 (2006) “Standard Practice for Analysis of Reformed Gas by Gas Chromatography” or ASTM D2163-07 “Standard Test Method for Determination of Hydrocarbons in Liquefied Petroleum (LP) Gases and Propane/Propene Mixtures by Gas Chromatography” 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 and biogas;
(b) daily, for all other types of gaseous fuel.
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, the emitter is unable to obtain fuel analytical data covering at least 80% of the emitter’s emissions, the emissions from that source must be considered unverifiable for the report year;
(2) when, in sampling fuels, the emitter’s fuel analytical data capture rate is at least 80% but less than 100% for any emissions source to which this Schedule applies, the emitter must use the methods specified in QC.1.6 to substitute the missing values for the period of missing data.
QC.1.5.7. Interim method for fuel sampling
When an emission calculation method requires the continuous measurement of emissions or periodic fuel sampling, and when the necessary equipment is not operational, the emitter may use an interim method for fuel sampling until the equipment is repaired or replaced, if
(1) the breakdown may result in a loss of more than 20% of the source’s fuel data, such that emissions for the affected source cannot be verified pursuant to section 6.6 of this Regulation;
(2) the fuel sampling equipment cannot be promptly repaired or replaced without shutting down the stationary combustion unit concerned, or without significantly affecting facility operations;
(3) the interim method is the most reliable sampling method that can be used.
An emitter who uses an interim method must advise the Minister that the equipment is not operational within 30 days of the event and provide the following information:
(1) a description of the interim method used and the start and end dates for its use;
(2) a detailed description of the data affected by the non-operability;
(3) an analysis of the reliability of the data gathered using the interim method compared to the normally-gathered data;
(4) proof that the conditions in subparagraph 1 to 3 of the first paragraph have been met.
QC.1.6. Estimation methods for missing data
When sampling or measurement data required by this Regulation for the calculation of emissions is missing, replacement data must be used, determined as follows:
(1) an emitter who uses one of the calculation methods specified in QC.1.3.1 to QC.1.3.3 and QC.1.4.2 must
(a) when the missing data concerns the high heat value, carbon content or molecular mass of a fuel, replace that data by the arithmetic mean of the sampling or measurement data from immediately before and after the period for which the data is missing. However,
i. if the data from after that period cannot be obtained in time to calculate the greenhouse gas emissions, the emitter may use only the data from before that period or an estimate based on all the data relating to the processes used;
ii. if no data is available from before that period, the emitter must use the data from the first sampling or measurement after the period for which the data is missing;
(b) when the missing data concerns CO2 concentration, stack gas flow rate, water content, fuel consumption or the quantity of sorbent used, replace that data by an estimate based on all the data relating to the processes used;
(2) an emitter who uses one of the calculation methods specified in QC.1.3.4 and QC.1.4.4 must determine the replacement data for the high heat value of the fuel, carbon content, CO2concentration, exhaust gas stream flow, volume flow or energy input of the fuel 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.
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 & Road Oil | 44.46 |
|_________________________________________________________|_______________________|
| | |
| Aviation Gazoline | 33.52 |
|_________________________________________________________|_______________________|
| | |
| Diesel | 38.30 |
|_________________________________________________________|_______________________|
| | |
| Aviation Trubo Fuel | 37.40 |
|_________________________________________________________|_______________________|
| | |
| Kerosene | 37.68 |
|_________________________________________________________|_______________________|
| | |
| Propane | 25.31 |
|_________________________________________________________|_______________________|
| | |
| Ethane | 17.22 |
|_________________________________________________________|_______________________|
| | |
| Butane | 28.44 |
|_________________________________________________________|_______________________|
| | |
| Lubricants | 39.16 |
|_________________________________________________________|_______________________|
| | |
| Motor Gazoline - Off-Road | 35.00 |
|_________________________________________________________|_______________________|
| | |
| Light Fuel Oil No. 1 | 38.78 |
|_________________________________________________________|_______________________|
| | |
| Light Fuel Oil No. 2 | 38.50 |
|_________________________________________________________|_______________________|
| | |
| Residual Fuel Oil (# 5 & 6) | 42.50 |
|_________________________________________________________|_______________________|
| | |
| Crude Oil | 38.32 |
|_________________________________________________________|_______________________|
| | |
| Naphtha | 35.17 |
|_________________________________________________________|_______________________|
| | |
| Petrochemical Feedstocks | 35.17 |
|_________________________________________________________|_______________________|
| | |
| Petroleum Coke - Refinery Use | 46.35 |
|_________________________________________________________|_______________________|
| | |
| Petroleum Coke - Upgader Use | 40.57 |
|_________________________________________________________|_______________________|
| | |
| Ethanol (100%) | 23.41 |
|_________________________________________________________|_______________________|
| | |
| Biodiesel (100%) | 35.67 |
|_________________________________________________________|_______________________|
| | |
| Rendered Animal Fat | 34.84 |
|_________________________________________________________|_______________________|
| | |
| Vegetable Oil | 33.44 |
|_________________________________________________________|_______________________|
| | High heat value |
| Solid fuels | (GJ/metric ton)
|
|_________________________________________________________|_______________________|
| | |
| Antracite 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 Wood Waste | 18.00 |
|_________________________________________________________|_______________________|
| | |
| Spent Puling Liquor | 14.00 |
|_________________________________________________________|_______________________|
| | |
| Municipal solid waste | 11.57 |
|_________________________________________________________|_______________________|
| | |
| Tires | 31.18 |
|_________________________________________________________|_______________________|
| | |
| Agricultural By-products | 9.60 |
|_________________________________________________________|_______________________|
| | |
| Biomass By-products | 30.05 |
|_________________________________________________________|_______________________|
| | |
| Gaseaous fuels | High heat value |
| | (GJ/m3) |
|_________________________________________________________|_______________________|
| | |
| Natural Gas | 0.03832 |
|_________________________________________________________|_______________________|
| | |
| Coke Oven Gas | 0.01914 |
|_________________________________________________________|_______________________|
| | |
| Still Gas - Refineries | 0.03608 |
|_________________________________________________________|_______________________|
| | |
| Still Gas - Upgraders | 0.04324 |
|_________________________________________________________|_______________________|
| | |
| Landfill Gas (methane portion) | 0.03590 |
|_________________________________________________________|_______________________|
| | |
| Biogas (methane portion) | 0.03130 |
|_________________________________________________________|_______________________|
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 CO2
(kg/L) CO2
(kg/GJ) CH4
(g/L) CH4
(g/GJ) N2O
(g/L) N2O
(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/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
- All other uses 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 - Off-Road Vehicles 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/Institutional 2.725 70.23 0.026 0.670 0.031 0.799
Residual Fuel Oil (#5 & 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/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 0.500 14.22 N/A N/A N/A N/A
Petroleum Coke - Refinery Use 3.826 82.55 0.12 2.589 0.0265 0.572
Petroleum Coke - Upgrader Use 3.494 86.12 0.12 2.958 0.0231 0.569
Biomass and other solid fuels CO2
(kg/kg) CO2
(kg/GJ) CH4
(g/kg) CH4
(g/GJ) N2O
(g/kg) N2O
(g/GJ)
Landfill Gas 2.989 54.63 0.60 1.0 0.06 0.1
Wood Waste with 50% H2O content 0.840 46.67 0.09 5.0 0.02 1.111
Spent Pulping Liquor with 50% H2O content 0.891 63.6 0.02 1.43 0.02 1.43
Agricultural By-products N/A 112 N/A N/A N/A N/A
Biomass By-products N/A 100 N/A N/A N/A N/A
Biogas (methane portion) N/A 49.4 N/A N/A N/A N/A
Ethanol (100%) N/A 64.9 N/A N/A N/A N/A
Biodiesel (100%) N/A 70 N/A N/A N/A N/A
Rendered Animal Fat N/A 67.4 N/A N/A N/A N/A
Vegetable Oil N/A 77.3 N/A N/A N/A N/A
Coal Coke 2.480 86.02 0.03 1.041 0.02 0.694
Tires N/A 85.0 N/A N/A N/A N/A

Gaseous fuels CO2
(kg/m3) CO2
(kg/GJ) CH4
(g/m3) CH4
(g/GJ) N2O
(g/m3) N2O
(g/GJ)
Coke Oven Gas 1.60 83.60 0.037 1.933 0.0350 1.829
Still Gas - Refineries 1.75 48.50 N/A N/A 0.0222 0.615
Still Gas - Upgraders 2.14 49.49 N/A N/A 0.0222 0.513

Table 1-4. CO2 emission factors for natural gas
(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 | 1.5 |
|_______________________|___________________|__________________|__________________|
Table 1-7. CH4 and N2O emission factors for natural gas 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 located at a petroleum refinery that combust gaseous fuels such as refinery fuel gas, flexigas or associated gas.
QC.2.2. Greenhouse gas reporting requirements
The greenhouse gas emissions report referred to in section 6.2 must 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;
(2) the annual consumption of gaseous fuel, in millions of cubic metres at standard conditions;
(3) the average 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 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 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.
QC.2.3. Calculation methods for CO2, CH4 and N2O emissions
The annual CO2 emissions attributable to stationary combustion units located at a petroleum refinery 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 combustion units located at a petroleum refinery that uses refinery fuel gas, flexigaz and associated gas 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 fuel gas or flexigas, in metric tons;
n = Number of days of operation in the year;
i = Day;
m = Number of supply systems;
j = Supply system;
Fuelij = Consumption of refinery fuel gas or flexigas in supply system j for day i, in cubic metres at standard conditions;
CCij = Carbon content of the sample of refinery fuel 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 fuel gas or flexigas in supply system j for day i, in kilograms per kilomole;
MVC = Molar volume conversion factor of 24.06 m3 per kilomole at standard conditions;
3.664 = Ratio of molecular weights, CO2 to carbon;
0.001 = Conversion factor, kilograms to metric tons.
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
The carbon content and molecular weight of gaseous fuels must be measured 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 Regulation for the calculation of emissions is missing, the emitter must use replacement data determined in accordance with 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
The greenhouse gas emissions report referred to in section 6.2 must 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 in accordance with QC.1, in metric tons;
(7) the monthly and annual liquid aluminum production, in metric tons;
(8) for the use of the prebaked anodes process:
(a) the monthly net prebaked anode consumption for liquid aluminum production, in metric tons of anodes per metric ton of liquid aluminum;
(b) the monthly net sulphur content in prebaked anodes, in kilograms of sulphur per kilogram of prebaked anodes;
(c) the monthly ash content in prebaked anodes, in kilograms of ash per kilogram of prebaked anodes;
(d) (subparagraph revoked);
(9) for the use of the Søderberg anodes process:
(a) the monthly anode paste consumption, in metric tons of paste per metric ton of liquid aluminum;
(b) the monthly emissions of benzene-soluble matter (BSM) or the International Aluminium Institute factor used, in kilograms of BSM per metric ton of liquid aluminum;
(c) the monthly average pitch content in paste, in kilograms of pitch per kilogram of paste;
(d) the monthly sulphur content in the pitch, in kilograms of sulphur per kilogram of pitch;
(e) the monthly ash content in the pitch, in kilograms of ash per kilogram of pitch;
(f) the monthly hydrogen content in the pitch, in kilograms of hydrogen per kilogram of pitch or the International Aluminium Institute factor used;
(g) the monthly sulphur content of the calcinated coke, in kilograms of sulphur per kilogram of calcinated coke;
(h) the monthly ash content of the calcinated coke, in kilograms of ash per kilogram of calcinated coke;
(i) when a value of 0 is not used, the monthly reported carbon present in the dust from Søderberg electrolysis cells, in kilograms of carbon per kilogram of liquid aluminum produced;
(10) for the use of the baking process for prebaked anodes or cathodes:
(a) the monthly consumption of packing material, in metric tons of packing material per metric ton of baked anodes or cathodes;
(b) the monthly and annual production of baked anodes or cathodes, in metric tons;
(c) the monthly ash content in the packing material, in kilograms of ash per kilogram of packing material;
(d) the monthly sulphur content in the packing material, in kilograms of sulphur per kilogram of packing material;
(e) (subparagraph revoked);
(f) the monthly consumption of green anodes or cathodes, in metric tons;
(g) the monthly pitch content of green anodes or cathodes, in kilograms of pitch per kilogram of green anodes or cathodes;
(h) the monthly quantity of tar recovered from the baking of anodes or cathodes, in metric tons;
(11) for the use of the coke calcination process:
(a) the monthly consumption of green coke, in metric tons;
(b) the monthly humidity content in the green coke, in kilograms of water per kilogram of green coke;
(c) the monthly volatiles content of the green coke, in kilograms of volatiles per kilogram of green coke;
(d) the monthly sulphur content of the green coke, in kilograms of sulphur per kilogram of green coke;
(e) the monthly sulphur content of the calcinated coke, in kilograms of sulphur per kilogram of calcinated coke;
(f) the monthly and annual quantity of calcinated coke produced, in metric tons;
(g) the monthly quantity of under-calcinated coke produced, in metric tons;
(h) the monthly emissions of coke dust, 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) the anode effect frequency, in anode effect minutes per pot-day, calculated monthly for each series of pots using the same technology;
(c) the anode effect duration, in minutes per anode effect for each series of pots using the same technology;
(d) the liquid aluminum production per month, in metric tons for each series of pots using the same technology;
(e) the number of operating days per year for each series of pots;
(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) the monthly anode effect overvoltages, in millivolts per pot for each series of pots using the same technology;
(h) the current efficiency of the aluminum production process, expressed as a fraction for each series of pots using the same technology;
(13) for emissions of SF6 used as a cover gas:
(a) the annual quantity of SF6 purchased, in metric tons;
(b) the quantity of SF6 shipped out of the establishment during the year, in metric tons;
(c) the quantity of SF6 in storage at the beginning of the year, in metric tons;
(d) the quantity of SF6 in storage at the end of the year, in metric tons;
(e) the monthly quantity of cover gas input to electrolysis cells, in metric tons;
(f) the monthly SF6 concentration in the gas input to the electrolysis cells, in metric tons;
(g) the monthly quantity of gas containing SF6 collected and shipped out of the establishment, in metric tons;
(h) the monthly concentration of SF6 in the gas collected and shipped out of the establishment, in metric tons;
(14) the number of times that the methods for estimating missing data provided for in QC.3.7 were used;
(15) the total greenhouse gas emissions for each type of emissions, namely:
(a) the annual fixed process emissions corresponding to the total of the emissions referred to in subparagraphs 1, 2 and 4, in metric tons CO2 equivalent;
(b) the annual combustion emissions corresponding to the emissions referred to in subparagraph 6, in metric tons CO2 equivalent;
(c) the annual “other” category emissions corresponding to the total of the emissions referred to in subparagraphs 3 and 5, in metric tons CO2 equivalent;
(16) the annual quantity of aluminum hydrate produced, in metric tons.
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.
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:
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.
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;
BSM = Emissions of benzene-soluble matter (BSM) or the International Aluminium Institute factor used, in kilograms of BSM per metric ton of liquid aluminum;
BC = Average pitch content in paste for month i, in kilograms of pitch per kilogram of paste;
Sb = Sulphur content in pitch for month i, in kilograms of sulphur per kilogram of pitch;
Ashp = Ash content in pitch, in kilograms of ash per kilogram of pitch;
Hb = Hydrogen content in pitch, in kilograms of hydrogen per kilogram of pitch 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 pitch coking 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 = Production of baked anodes or cathodes 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 pitch coking, using equation  3-5:
Equation 3-5
Where:
CO2 P = Annual CO2 emissions attributable to pitch coking, in metric tons;
i = Month;
GAW = Consumption of green anodes or cathodes for month i, in metric tons;
BAC = Production of baked anodes or cathodes for month i, in metric tons;
Hp = Hydrogen content in pitch for month i or the International Aluminium Institute factor used, in kilograms of hydrogen per kilogram of pitch;
PC = Pitch content of green anodes or cathodes for month i, in kilograms of pitch 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 CO2emissions;
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:
ECF4 = 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 and per day, for month i;
AEF = Anode effect frequency, in anode effect minutes per pot and per day, calculated for month i;
MP = Monthly production of liquid aluminum, in metric tons;
Equation 3-8
Where:
ECF4 = Annual CF4 emissions attributable to anode effects, in metric tons;
m = Number of series of pots;
j = One 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:
EC2F6 = Annual C2F6 emissions, in metric tons;
i = Month;
ECF4 = Monthly CF4 emissions, in metric tons, for month i;
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 de SF6 in the cover gas entering the electrolysis cells for month i, in metric tons;
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.
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 benzene-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.
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 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 again whenever
(1) 36 months have passed since the last tests;
(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.
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 sampling or measurement data required by this Regulation for the calculation of emissions is missing, the emitter must use replacement data determined as follows:
(1) when emissions are calculated using a continuous emission monitoring and recording system, the method in paragraph 2 of QC.1.6 must be used;
(2) for each parameter needed to calculate greenhouse gas emissions, except data on aluminum production or feedstock consumption, the missing data must be replaced 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;
(3) for data on aluminum production or feedstock consumption, the missing data must be estimated using all the data relating to the processes used.
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 |
|_____________________________________|__________________________|
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
The greenhouse gas emissions report referred to in section 6.2 must include the following information:
(1) the annual CO2, CH4 and N2O emissions, in metric tons;
(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 monthly quantity of clinker produced, in metric tons;
(c) the monthly content of calcium oxide in the clinker, in metric tons of calcium oxide per metric ton of clinker;
(d) the monthly content of magnesium oxide in the clinker, in metric tons of magnesium oxide per metric ton of clinker;
(d.1) the monthly content of non-calcined calcium oxide in the clinker, in metric tons of non-calcined calcium oxide per metric ton of clinker;
(d.2) the monthly content of non-calcined magnesium oxide in the clinker, in metric tons of non-calcined magnesium oxide per metric ton of clinker;
(e) the monthly quantity of non-carbonate raw material, in metric tons;
(f) the monthly content of calcium oxide in the non-carbonate raw material, in metric tons of calcium oxide per metric ton of non-carbonate raw material;
(g) the monthly content of magnesium oxide in the non-carbonate raw material, in metric tons of magnesium oxide per metric ton of non-carbonate raw material;
(h) the quarterly CO2 emission factors for the dust discarded that is not recycled to the cement kiln, in metric tons of CO2 per metric ton of dust;
(h.1) the quarterly content of non-calcined calcium oxide in the dust discarded that is not recycled to the cement kiln, in metric tons of non-calcined calcium oxide per metric ton of dust;
(h.2) the quarterly content of non-calcined magnesium oxide in the dust discarded that is not recycled to the cement kiln, in metric tons of non-calcined magnesium oxide per metric ton of dust;
(i) the quarterly quantity of the dust discarded 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 raw material:
(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) the annual CO2, CH4 and N2O emissions attributable to fuel combustion in all cement kilns, calculated in accordance with QC.4.3.2(2), in metric tons;
(8) the annual CO2, CH4 and N2O emissions attributable to the use of stationary combustion units, with the exception of cement kilns, calculated 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) the total greenhouse gas emissions for each type of emissions, namely:
(a) the annual fixed process emissions corresponding to the total of the emissions referred to in subparagraphs 2 and 4, in metric tons CO2 equivalent;
(b) the annual combustion emissions corresponding to the total of the emissions referred to in subparagraphs 6 and 7, in metric tons CO2 equivalent;
(11) the annual quantities of gypsum and limestone added to the clinker produced by the establishment, in metric tons.
QC.4.3. Calculation method for CO2 emissions from the use of cement kilns
The annual CO2 emissions attributable from the use of cement kilns must be calculated using one of the two calculation methods in QC.4.3.1 and QC.4.3.2.
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 paragraph 2 of QC.4.3.2.
QC.4.3.2. Calculation by mass balance
The annual CO2 emissions may be calculated using the following calculation methods:
(1) the CO2 emissions from 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 material, calculated in accordance with the following methods:
(a) CO2 emissions attributable to calcination must be calculated using equations 4-1 to 4-3:
Equation 4-1
Where:
CO2 - C = CO2 emissions attributable to calcination, in metric tons;
i = Month;
Cli = 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 discarded that is not recycled to the cement kiln, in metric tons;
EFCKD = Quarterly CO2 emission factor for the dust discarded 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
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, 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 is the sum of the calcium oxide that enters the kiln as a non-carbonate species in the raw material and the calcium oxide remaining in the clinker after oxidation. These values must be measured using, respectively, the methods in 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, 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 is the sum of the magnesium oxide that enters the kiln as a non-carbonate species in the raw material and the magnesium oxide remaining in the clinker after oxidation. These values must be measured using, respectively, the methods in 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) x 0.785 + (MgOCKD - MgONCD) x 1.092
Where:
EFCKD = Quarterly CO2 emission factor for the dust discarded 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 discarded that is not recycled to the cement kiln, in metric tons of calcium oxide per metric ton of dust;
CaONCD = Quarterly content of non-calcined calcium oxide in the dust discarded 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 is the sum of the calcium oxide that enters the kiln as a non-carbonate species and the calcium oxide remaining in the discarded kiln dust that is not recycled following oxidation. These values must be measured using respectively the methods in 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 dust discarded that is not recycled to the cement kiln, in metric tons of magnesium oxide per metric ton of dust;
MgONCD = Quarterly content of non-calcined magnesium oxide in the dust discarded 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 is the sum of the magnesium oxide that enters the kiln as a non-carbonate species and the magnesium oxide remaining in the discarded kiln dust that is not recycled following oxidation. These values must be measured using respectively the methods in 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;
(b) 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
CO2,RM = TOCRM x RM x 3.664
Where:
CO2,RM = CO2 emissions resulting from the oxidation of the raw material, in metric tons;
TOCRM = Total organic carbon content in raw material, measured using the method in QC.4.4 (3), or using a default value of 0.002 (0.2%) metric tons of total organic carbon content per metric ton of raw material;
RM = Quantity of raw material in metric tons;
3.664 = Ratio of molecular weights, CO2 to carbon.
(2) the CO2, CH4 and N2O emissions from fuel combustion in each cement kiln must be calculated 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
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 and of the non-carbonate raw material, in accordance with ASTM C114-11 “Standard Test Methods for Chemical Analysis of Hydraulic Cement”, 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 inventory purposes, such as weigh hoppers or belt weigh feeders;
(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;
(4) determine monthly the calcium oxide and magnesium oxide content of the clinker that enters the kiln as a non-carbonate species in the raw material or use the value of 0;
(5) determine monthly the calcium oxide and magnesium oxide content remaining in the clinker after oxidation or use the value of 0;
(6) determine quarterly the calcium oxide and magnesium oxide content in the dust discarded that is not recycled to the cement kiln and in the feedstock in accordance with ASTM C114-11, 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 discarded dust that is not recycled that enters the kiln as a non-carbonate species or use the value of 0;
(8) determine quarterly the calcium oxide and magnesium oxide content remaining in the discarded kiln dust that is not recycled following oxidation or use the value of 0;
(9) determine quarterly the quantity of discarded kiln dust 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;
(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 ASTM C114-11.
QC.4.5. Methods for estimating missing data
When sampling or measurement data required by this Regulation for the calculation of emissions is missing, the emitter must use replacement data determined as follows:
(1) when emissions are calculated using a continuous emission monitoring and recording system, the method in paragraph 2 of QC.1.6 must be used;
(2) for the data needed to calculate CO2 emissions attributable to calcination and the oxidation of organic carbon, a new analysis must be conducted;
(3) for each missing value concerning clinker production, the emitter must use the first data estimated after the missing data period or use the maximum daily production capacity and multiply by the number of days in the month;
(4) for each missing value concerning raw material consumption, the emitter must use the first data estimated after the missing data period or use the maximum daily raw material throughput of the kiln and multiply by the number of days in the month.
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
The greenhouse gas emissions report referred to in section 6.2 must 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) the annual greenhouse gas emissions in the “other” category corresponding to the emissions referred to in paragraph 1, in metric tons CO2 equivalent.
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
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
The greenhouse gas emissions report referred to in section 6.2 must 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 millions of cubic metres at standard conditions, for gases;
(b) in kilolitres, for liquids;
(c) in metric tons for non-biomass solids;
(d) in bone dry metric tons, for biomass-derived solid fuels;
(3) the annual hydrogen produced, in millions of cubic metres at standard conditions;
(4) the average carbon content of each feedstock type;
(5) the annual CO2, CH4 and N2O emissions attributable to combustion, calculated 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) the total greenhouse gas emissions for each type of emissions, namely:
(a) the annual fixed process emissions corresponding to the emissions referred to in subparagraph 1, in metric tons CO2 equivalent;
(b) the annual combustion emissions corresponding to the emissions referred to in subparagraph 5, in metric tons CO2 equivalent.
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.
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) for gaseous feedstocks, 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 cubic metres at standard conditions;
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 kilograms of carbon per kilogram of feedstock;
MW = Molecular weight of feedstock, 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 of 24.06 m3 per kilomole, at standard conditions;
3.664 = Ratio of molecular weights, CO2 to carbon;
0.001 = Conversion factor, kilograms to metric tons;
(2) for liquid feedstocks, 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 liquid feedstock 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 kilograms of carbon per kilolitre of feedstock;
3.664 = Ratio of molecular weights, CO2 to carbon;
0.001 = Conversion factor, kilograms to metric tons;
(3) for solid feedstocks, 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 solid feedstock consumed in month j, in kilograms;
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 kilograms of carbon per kilogram of feedstock;
3.664 = Ratio of molecular weights, CO2 to carbon;
0.001 = Conversion factor, kilograms to metric tons.
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) collect samples of each type of feedstock consumed and analyze each sample for average carbon content using the methods specified in paragraph 5,
(a) daily, for all feedstocks except natural gas, by collecting the sample from a location that provides samples representative of the feedstock consumed in the hydrogen production process;
(b) monthly, when natural gas is used as a feedstock and not mixed with another feedstock prior to consumption;
(3) determine the hydrogen produced daily;
(4) determine, quarterly, the quantity of CO2 and of carbon monoxide transferred off-site;
(5) use the following analysis methods to measure the average carbon content of each type of feedstock:
(a) for solid feedstocks, ASTM D2013/D2013M - 09 “Standard Practice for Preparing Coal Samples for Analysis”, ASTM D2234/D2234M - 10 “Standard Practice for Collection of a Gross Sample of Coal”, ASTM D3176-09 “Standard Practice for Ultimate Analysis of Coal and Coke”, ASTM D6609-08 “Standard Guide for Part-Stream Sampling of Coal”, ASTM D6883-04 “Standard Practice for Manual Sampling of Stationary Coal from Railroad Cars, Barges, Trucks, or Stockpiles” or ASTM D7430-10b “Standard Practice for Mechanical Sampling of Coal”;
(b) for liquid feedstocks, ASTM D2597-10 “Standard Test Method for Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing Nitrogen and Carbon Dioxide by Gas Chromatography”, ASTM D4057-06 “Standard Practice for Manual Sampling of Petroleum and Petroleum Products”, ASTM D4177-95 (2010) “Standard Practice for Automatic Sampling of Petroleum and Petroleum Products”, ISO 3170:2004 “Petroleum Liquids—Manual sampling” or ISO 3171:1988 “Petroleum liquids—Automatic pipeline sampling”;
(c) for gaseous feedstocks, UOP539-97 “Refinery Gas Analysis by Gas Chromatography” or GPA 2261-00 “Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography”.
QC.6.5. Methods for estimating missing data
When sampling or measurement data required by this Regulation for the calculation of emissions is missing, the emitter must use replacement data determined as follows:
(1) when emissions are calculated using a continuous emission monitoring and recording system, the method in paragraph 2 of QC.1.6 must be used;
(2) for each missing value concerning feedstock consumption, the replacing data must be estimated using all the data relating to the processes used;
(3) each missing value concerning the carbon content or molecular weight must be replaced 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.
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
The greenhouse gas emissions report referred to in section 6.2 must include the following information:
(1) for all types of facility:
(a) the annual CO2 and CH4 emissions calculated for each facility, in metric tons;
(b) the annual CO2, CH4 and N2O emissions attributable to the use of stationary combustion units, calculated 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 carbon content of the material inputs for the production of metallurgical coke listed in subparagraphs b to g.1 and of the material outputs, in metric tons of carbon per metric ton of material;
(h.1) the CH4 emission factors determined by the emitter and the methods used to estimate them;
(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 carbon content of the materials used in iron and steel production, referred to in subparagraphs b to g, and of derivatives of those materials, in metric tons of carbon per metric ton of material;
(i) the CH4 emission factors determined by the emitter and the methods used to estimate them;
(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 that contributes 0.5% or more of the total carbon in the process, in metric tons;
(c) the annual consumption of each raw material used in sinter production, other than carbonaceous materials, 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 carbon content of the materials used in sinter production, referred to in subparagraphs b to e, and of derivatives of those materials, in metric tons of carbon per metric ton of material;
(g) the CH4 emission factors determined by the emitter and the methods used to estimate them;
(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 carbon content of the materials used in steel production, referred to in subparagraphs b to i, and of derivatives of those materials, in metric tons of carbon per metric ton of material;
(k) the CH4 emission factors determined by the emitter and the methods used to estimate them;
(6) for the argon-oxygen decarburization of molten steel:
(a) the annual CO2 and CH4 emissions attributable to the argonoxygen decarburization of molten steel, in metric tons;
(b) the annual quantity of molten steel charged to the process, in metric tons;
(c) the carbon content of the molten steel before decarburization, in metric tons of carbon per metric ton of molten steel;
(d) the 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 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 carbon content of the materials used in iron production, referred to in subparagraphs b to f, and of derivatives of those materials, in metric tons of carbon per metric ton of material;
(h) the CH4 emission factors determined by the emitter and the methods used to estimate them;
(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 carbon content of the materials used in iron production, referred to in subparagraphs b to g, and of derivatives of those materials, in metric tons of carbon per metric ton of material;
(i) the CH4 emission factors determined by the emitter and the methods used to estimate them;
(9) for the indurating of iron ore pellets:
(a) the annual CO2 and CH4 emissions attributable to the indurating of iron ore 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 carbon content of the materials used in the production of pellets referred to in subparagraphs b to d, and of derivatives of those materials, in metric tons of carbon per metric ton of material;
(f) the annual quantities of each raw material used, other than greenball pellets, in metric tons;
(g) the annual emissions of each type of iron ore pellets produced, in metric tons CO2 equivalent;
(10) the number of times that the methods for estimating missing data provided for in QC.7.6 were used;
(11) the total greenhouse gas emissions for each type of emissions, namely:
(a) the annual fixed process emissions corresponding to the total of the emissions referred to in subparagraph a of subparagraphs 2 to 9, in metric tons CO2 equivalent;
(b) the annual combustion emissions corresponding to the emissions referred to in subparagraph b of subparagraph 1, in metric tons CO2 equivalent;
(c) the annual other CH4 emissions corresponding to the total of the emissions referred to in subparagraph a of each of subparagraphs 2 to 9, in metric tons CO2 equivalent;
(12) the annual quantity of steel exiting each rolling mill, in metric tons;
(13) the annual quantity of forged steel produced, 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.
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
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 indurating 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 the argonoxygen decarburization process, calculated in accordance with equation 7-6, in metric tons;
CO2, DR = Annual CO2 emissions attributable to iron production by direct reduction, 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;
(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 = Carbon content of coking coal, in metric tons of carbon per metric ton of coking coal;
GOC = Quantity of coke oven gas transferred off-site during the year, in metric tons;
CGOC = 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 = 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 = Carbon content of the collection and air cleaning system, 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 = Carbon content of coke oven by-product i transferred off-site during the year, in metric tons of carbon per metric ton of by-product i;
n = Number of coke oven by-products transferred off-site 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
_ _
| (MI x CMI) + (SC x CSC) + (FL x CFL) + (CAR x CCAR) |
CO2, BOF | | x 3.664
| - (ST x CST) - (SL x CSL) - (BOG x CBOG) - (R x CR) |
|_ _|
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 = 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 = Carbon content of ferrous scrap, in metric tons of carbon per metric ton of ferrous scrap;
FL = Annual quantity of each flux material used, in metric tons;
CFL = Carbon content of each flux material, in metric tons of carbon per metric ton of flux material;
CAR = Annual consumption of each carbonaceous material that contributes 0.5% or more of total carbon in the process, in metric tons;
CCAR = Carbon content of each carbonaceous material, in metric tons of carbon per metric ton of carbonaceous material;
ST = Annual production of molten steel, in metric tons;
CST = 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 = Carbon content of slag, in metric tons of carbon per metric ton of slag;
BOG = Quantity of basic oxygen furnace gas transferred off-site during the year, in metric tons;
CBOG = Carbon content of the 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 consumption of air pollution control residue, in metric tons;
CR = Carbon content of the air pollution control residue, 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;
CARj = Annual consumption of each carbonaceous material i that contributes 0.5% or more of total carbon in the process, in metric tons;
CCAR,j = Carbon content of each carbonaceous material i, in metric tons of carbon per metric ton of 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, in metric tons;
CRM, j = Carbon content of raw material j other than carbonaceous materials, required for sinter production, in metric tons of carbon per metric ton of raw material j;
SINTER = Sinter production, in metric tons;
CSINTER = 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 = Carbon content of air pollution control residue, 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 pellets, in metric tons;
CI = Carbon content of direct reduced iron pellets, in metric tons of carbon per metric ton of direct reduced iron pellets;
SC = Annual consumption of ferrous scrap, in metric tons;
CSC = Carbon content of ferrous scrap, in metric tons of carbon per metric ton of ferrous scrap;
FL = Annual quantity of each flux material used, in metric tons;
CFL = Carbon content of each flux material used, in metric tons of carbon per metric ton of flux material;
EL = Annual consumption of carbon electrodes, in metric tons;
CEL = Carbon content of the carbon electrodes, in metric tons of carbon per metric ton of carbon electrodes;
n = Total number of carbonaceous material;
i = Carbonaceous material;
CARi = Annual consumption of carbonaceous material i that contributes 0.5% or more of total carbon in the process, in metric tons;
CCAR, i = 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 = 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 = Carbon content of slag, in metric tons of carbon per metric ton of slag;
R = Annual consumption of air pollution control residue, in metric tons;
CR = Carbon content of the air pollution control residue, in metric tons of carbon per metric ton of residue;
3.664 = Ratio of molecular weights, CO2 to carbon;
(6) for the argon-oxygen decarburization process, using equation 7-6:
Equation 7-6
_ _
| |
CO2,AOD = |Steel x (CSteel,in - CSteel,out) - (R x CR)| x 3.664
|_ _|
Where:
CO2,AOD = Annual CO2 emissions attributable to the argonoxygen decarburization process, in metric tons;
Steel = Quantity of molten steel charted to the argonoxygen decarburization process, in metric tons;
CSteel,in = Carbon content of molten steel before decarburization, in metric tons of carbon per metric ton of molten steel;
CSteel,out = Carbon content of molten steel after decarburization, in metric tons of carbon per metric ton of molten steel;
R = Annual consumption of air pollution control residue, in metric tons;
CR = Carbon content of the air pollution control residue, 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 = 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, in metric tons;
CRM, i = 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 = 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 = 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 = 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 = Carbon content of the air pollution control residue, 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, in metric tons;
CRM, i = 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 = 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 = 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 = 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 = 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 = 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 = Carbon content of the air pollution control residue, 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:
Equation 7-9
_ _
| |
CO2,IP = |(GBP x CGBP) - (FP x CFP) - (R x CR)| x 3.664
|_ _|
Where:
CO2, IP = Annual CO2 emissions attributable to the indurating of iron ore pellets, in metric tons;
GBP = Consumption of greenball pellets, in metric tons;
CGBP = Carbon content of greenball pellets, in metric tons of carbon per metric ton of greenball pellets;
FP = Quantity of fired pellets produced by the indurating process, in metric tons;
CFP = 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 = Carbon content of the air pollution control residue, 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 and QC.7.4.2.
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.1.3.4.
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.7.5. Sampling, analysis and measurement requirements
QC.7.5.1. Carbon content
An emitter who operates a facility or establishment that produces iron or steel or who operates the indurating of iron ore pellets must use the data provided by the supplier or determine carbon content by analyzing a minimum of 3 representative samples using 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 ASTM C25-06 “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 ASTM D5373-08 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal” or, for fuels, raw materials or liquid products, ASTM D7582-10 “Standard Test Methods for Proximate Analysis of Coal and Coke by Macro Thermogravimetric Analysis”;
(5) for iron and ferrous scrap, using ASTM E1019-08 “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) ASM CS-104 UNS G10460 “Carbon Steel of Medium Carbon Content” published by ASM International;
(b) ISO/TR 15349-1:1998 “Unalloyed steel – Determination of low carbon content, Part 1: Infrared absorption method after combustion in an electric resistance furnace (by peak separation)”;
(c) ISO/TR 15349-3:1998 “Unalloyed steel – Determination of low carbon content, Part 3: Infrared absorption method after combustion in an electric resistance furnace (with preheating)”;
(d) ASTM E415-08 “Standard Test Method for Atomic Emission Vacuum Spectrometric Analysis of Carbon and Low-Alloy Steel”;
(7) for baked or greenball iron ore pellets, using ASTM E1915- 09 “Standard Test Methods for Analysis of Metal Bearing Ores and Related Materials for Carbon, Sulfur, and Acid-Base Characteristics”.
QC.7.5.2. Consumption of process materials
The emitter must determine the quantity of solid, liquid and gaseous process inputs and outputs and the quantity of by-products used in the production of iron and steel using the same plant instruments used for inventory purposes, such as weigh hoppers or belt weigh feeders.
QC.7.6. Methods for estimating missing data
When sampling or measurement data required by this Regulation for the calculation of emissions is missing, the emitter must use replacement data determined as follows:
(1) missing data on carbon content must be replaced 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;
(2) missing data on the quantity of raw materials consumed monthly must be estimated using all the data relating to the processes used.
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
The greenhouse gas emissions report referred to in section 6.2 must include the following information:
(1) the annual CO2, CH4 and N2O emissions, in metric tons;
(2) the annual CO2 emissions attributable to the lime production process, 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 monthly and annual production, in metric tons;
(c) the monthly content of calcium oxide in the lime, in metric tons of calcium oxide per metric ton of lime;
(d) the monthly content of magnesium oxide in the lime, in metric tons of magnesium oxide per metric ton of lime;
(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 quarterly production of calcined by-products or wastes, in metric tons;
(c) the quarterly content of calcium oxide in calcined by-products and wastes, in metric tons of calcium oxide per metric ton of calcined by-products or wastes;
(d) the quarterly content of magnesium oxide in calcined by-products and wastes, in metric tons of magnesium oxide per metric ton of calcined by-products or wastes;
(e) the annual quantity of calcined by-products and residue sold, in metric tons;
(5) the annual CO2, CH4 and N2O emissions attributable to fuel combustion in all kilns, calculated in accordance with QC.8.3.2, (2), in metric tons;
(6) the annual CO2, CH4 and N2O emissions attributable to the use of stationary combustion units, with the exception of lime kilns, calculated 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) the total greenhouse gas emissions for each type of emission, namely:
(a) the annual fixed process emissions corresponding to the emissions referred to in subparagraph 2, in metric tons CO2 equivalent;
(b) the annual combustion emissions corresponding to the total of the emissions referred to in subparagraphs 5 and 6, in metric tons CO2 equivalent.
QC.8.3. Calculation methods for CO2 emissions from kilns
The annual CO2 emissions from kilns must be calculated in according with one of the 2 calculation methods specified in QC.8.3.1 and QC.8.3.2.
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 may be calculated using the following methods:
(1) The CO2 emissions from kilns must be calculated, for each type of lime, using equation 8-1:
Equation 8-1
Where:
CO2 = CO2 emissions from kilns, in metric tons;
i = Month;
k = Total number of types of lime;
j = Type of lime;
L = Production of lime j for month i, in metric tons;
EFL = CO2 emission factor of lime j for 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 wastes;
CBP = Production of calcined by-products and wastes y in quarter x, including lime kiln dust, scrubber sludge and other calcined wastes, in metric tons;
EFCBP = 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;
(a) the monthly CO2 emission factor for lime (EFL) must be calculated, for each type of lime, using equation 8-2:
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;
(b) the quarterly CO2 emission factor for calcined by-products and wastes (EFCBP) must be calculated, for each type of calcined by-products and wastes, using equation 8-3:
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.
(2) The CO2, CH4 and N2O emissions attributable to the combustion of fuels in kilns must be calculated 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 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 ASTM C25-06 “Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime” or the National Lime Association’s “CO2 Emissions Calculation Protocol for the Lime Industry”, revised in February 2008;
(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 National Lime Association’s “CO2 Emissions Calculation Protocol for the Lime Industry”, revised in February 2008.
QC.8.5. Methods for estimating missing data
When sampling or measurement data required by this Regulation for the calculation of emissions is missing, the emitter must use replacement data determined as follows:
(1) when emissions are calculated using a continuous emission monitoring and recording system, the method in paragraph 2 of QC.1.6 must be used;
(2) for each missing value concerning the quantity of lime produced and the quantity of calcined by-products and wastes, the missing data must be estimated using all the data relating to the processes used;
(3) for the data needed to estimate the monthly calcium oxide and magnesium oxide contents, a new analysis must be conducted.
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
The greenhouse gas emissions report referred to in section 6.2 must 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 in accordance with QC.2, in metric tons;
(2) the annual CO2, 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 other than flares and antipollution devices, calculated in accordance with QC.1.3 and QC.1.4, in metric tons;
(6.1) the annual CO2 emissions attributable to hydrogen production processes, calculated 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 millions of cubic metres at standard conditions, for gases;
(b) in kilolitres, for liquids;
(c) in metric tons for non-biomass solids;
(d) in bone dry metric tons, for biomass-derived solid fuels;
(13) the annual consumption of each type of fuel that emits CO2, CH4 or N2O, expressed
(a) in millions of cubic metres at standard conditions, for gases;
(b) in kilolitres, for liquids;
(c) in metric tons for non-biomass solids;
(d) in bone dry metric tons, for biomass-derived solid fuels;
(14) the annual CO2, CH4 and N2O emissions from coke calcining, in metric tons;
(15) the annual CH4 emissions from purging systems, in metric tons;
(16) the annual CH4 emissions from loading operations, in metric tons;
(17) the annual CH4 emissions from delayed coking, in metric tons;
(18) the number of times that the methods for estimating missing data provided for in QC.9.5 were used;
(19) the total greenhouse gas emissions for each type of emissions, namely:
(a) the annual fixed process emissions corresponding to the total of the emissions referred to in paragraphs 2, 6.1, 14 and 17, in metric tons CO2 equivalent;
(b) the annual combustion emissions corresponding to the total of the emissions referred to in paragraphs 1 and 6, in metric tons CO2 equivalent;
(c) the “other” category emissions corresponding to the total of the emissions referred to in paragraphs 3 to 5, 7 to 11, 15 and 16, in metric tons CO2 equivalent;
(20) the annual quantity of crude oil refined, in kilolitres;
(21) the total charge of the refinery feed, in kilolitres.
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.9.3.9.
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 kilograms;
C = Carbon content of coke burned, in kilograms of carbon per kilogram of coke burned;
3.664 = Ratio of molecular weights, CO2 to carbon;
0.001 = Conversion factor, kilograms to metric tons;
Equation 9-2
CBJ = K1Qr x (%CO2 + %CO) + K2Qa - K3Qr x (%CO/2 + %CO2 + %O2) + K3Qoxy x %O2,oxy
Where:
CBj = Hourly coke burn, in kilograms;
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 by volume on a dry basis;
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.
When there is no post-combustion device, the percentage is zero;
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;
CB = Quantity of coke burned, in kilograms per cycle of regeneration 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;
0.001 = Conversion factor, kilograms to metric tons;
(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 = CH4 emissions from catalyst regeneration, in metric tons;
CO2 = Annual CO2 emissions from catalyst regeneration, calculated using equation 9-1, in metric tons;
EFCH4 = CH4 emission factor, 2.8 x 10-3 kg per gigajoule;
EFCO2 = CO2 emission factor, 97 kg per gigajoule;
(5) the N2O emissions attributable to catalyst regeneration must be calculated using equation 9-5.2:
Equation 9-5.2
EFN20
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 x, where x = CO2, CH4 or N2O, from process vents,in metric tons;
n = Number of venting events during the year;
i = Venting event;
VRi = Vent rate 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;
MWx = Molecular weight (molecular mass) of x 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);
VTi = Duration of venting event i, 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 x EFBP,CO2
Where:
CO2 = Annual CO2 emissions attributable to uncontrolled bituminous product blowing operations, in metric tons;
QBP = Annual 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 x 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 x CBP x 0.98 x 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 x EFBP,CH4 x 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 gas to 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 hydrogen sulphide 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 flare gas combusted during measurement period p, in 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);
Cp = Average carbon content of flare gas 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 = Combustion efficiency of flare;
0.001 = Conversion factor, kilograms to metric tons;
(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 flare gas during measurement period p, in 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 cubic metre;
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
MCV
Flarep (m3) = Flarep (kg) × ___
MWP
Where:
Flarep (m3) = Volume of flare gas combusted during measurement period p, in cubic metres;
Flarep (kg) = Masse 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 during measurement period p, in kilograms per kilomole;
(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 malfunction, in metric tons;
n = Annual number of startups, shutdowns or malfunctions;
p = Periods of startup, shutdown or malfunction;
FlareSSM,p = Volume of flare gas combusted during startup, shutdown or malfunction period p, in cubic metres at standard conditions;
MWp = Average molecular weight of flare gas during measurement period p, in kilograms per kilomole;
MVC = Molar volume conversion factor (24.06 m3 per kilomole at standard conditions);
Cp = Average carbon content of flare gas during measurement period p, in kilograms of carbon per kilogram of flare gas;
3.664 = Ratio of molecular weights, CO2 to carbon;
0.98 = Combustion efficiency of flare;
0.001 = Conversion factor, kilograms to metric tons;
(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
EFN20
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 cubic metres at standard conditions or in kilograms for a mass balance;
Cp = Carbon content of gas p, in kilograms of carbon per kilogram of gas;
MWp = Molecular weight of the gas 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;
0.001 = Conversion factor, kilograms to metric tons.
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 = QCO × 0.1
Where:
CH4 = Annual CH4 emissions from storage tanks, in metric tons;
Qco = Annual quantity of crude oil and intermediate products received from off-site that are processed at the establishment, in millions of barrels;
0.1 = Default emission factor for storage tanks, in metric tons of CH4 per million barrels;
(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;
4086.44 = Equation correlation factor, in cubic meter at standard conditions per million barrels per kilopascals;
Qun = Annual quantity of unstabilized crude oil, in millions of barrels;
/\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);
0.001 = Conversion factor, kilograms to metric tons.
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 × EFN20 × 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 x 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
EFN20
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 x 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
Where:
CH4 = Annual CH4 emissions attributable to delayed coking processes, in metric tons;
N = Annual number of vessel openings for all vessels of the same dimensions in the coking unit;
H = Height of coking vessel, in metres;
Pcv = Gauge pressure of the coking vessel when opened to the atmosphere prior to coke cutting or, if the method in paragraph 2 is used, gauge pressure of the coking vessel when depressurization gases are first routed to the atmosphere, in kilopascals;
101.325 = Atmospheric pressure, in kilopascals;
fvoid = Volumetric void fraction of coking vessel prior to the injection of water or steam, in cubic metres of gas at standard conditions per cubic metre of vessel;
¶ = Pi, i.e. 3.1416;
D2 = Diameter of coking vessel, in square metres;
16 = Molecular weight of CH4, in kilograms per kilomole;
MVC = Molar volume conversion factor (24.06 m3 per kilomole at standard conditions);
MFCH4 = Average mole fraction of CH4 in coking vessel gas based on the analysis of at least 2 samples per year, collected at least 4 months apart, in kilomoles of CH4 per kilomole of gas, wet basis;
0.001 = Conversion factor, kilograms to metric tons;
(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) 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 hydrogen sulphide.
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 the method in subparagraph 1 of the second paragraph of QC.9.3.5, measure the parameters used to determine the carbon content of the flare gas daily;
(3) if using the method in subparagraph 2 of the second paragraph of QC.9.3.5, 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) ASTM D3176-09 “Standard Practice for Ultimate Analysis of Coal and Coke”;
(2) ASTM D5291-10 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants”;
(3) ASTM D5373-08 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal”.
QC.9.5. Methods for estimating missing data
When sampling or measurement data required by this Regulation is missing, the emitter must use replacement data determined as follows:
(1) each missing value concerning the carbon content, molecular weight and high heat value of the fuel must be replaced 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;
(2) for each missing value concerning CO2, CH4, N2O, carbon monoxide and oxygen concentrations, and gas flow rate, the replacement data must be estimated using all the data relating to the processes used.
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
The greenhouse gas emissions report referred to in section 6.2 must 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 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 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 in accordance with QC.25.3, in metric tons;
(3.1) the annual CO2, CH4 and N2O emissions attributable to production of electricity, calculated 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 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 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) the annual greenhouse gas emissions for each type of emissions, namely:
(a) the annual fixed process emissions corresponding to the total of the emissions referred to in paragraphs 1 and 3, in metric tons CO2 equivalent;
(b) the annual combustion emissions corresponding to the total of the emissions referred to in paragraphs 3.1 and 4, in metric tons CO2 equivalent;
(c) the “other” category emissions corresponding to the emissions referred to in paragraph 2, in metric tons CO2 equivalent;
(10) the annual production of each pulp and paper product manufactured, in metric tons of air-dried marketable products.
QC.10.3. Calculation methods for CO2, CH4 and N2O emissions
The annual CO2, CH4 and N2O emissions attributable to the manufacture of pulp and paper products must be calculated in accordance with the calculation methods in QC.10.3.1 to QC.10.3.3.
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.
The high heat value or carbon content of the biomass must be determined by the emitter in accordance with QC.10.4.
QC.10.3.2. 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 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 a continuous monitoring and recording system;
(1.1) determine the high heat value of the black liquor in accordance with TAPPI T 684 om-11 (R2011) “Gross heating value of black liquor”;
(2) measure the monthly carbon content of the black liquor in accordance with ASTM D5373-08 “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”;
(3) to determine carbonate material consumption, either use records provided by the material supplier or monitor carbonate material consumption using the same plant instruments used for inventory purposes, such as weigh hoppers or belt weigh feeders;
(4) measure the carbonate content of each carbonate material by
(a) using the carbonate content data provided by the material supplier;
(b) using the emission factor specified in Table 25-1 in QC.25.6; or
(c) collecting monthly samples of each carbonate material consumed in accordance with ASTM C25-06 “Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime”, ASTM C1301-95 (2009) e1 “Standard Test Method for Major and Trace Elements in Limestone and Lime by Inductively Coupled Plasma-Atomic Emission Spectroscopy (ICP) and Atomic Absorption (AA)” or ASTM C1271-99 (2006) “Standard Test Method for X-ray Spectrometric Analysis of Lime and Limestone”.
QC.10.5. Methods for estimating missing data
When sampling or measurement data required by this Regulation for the calculation of emissions is missing, the emitter must use replacement data determined as follows:
(1) when the missing data concerns the carbon content or high heat value of the black liquor, a new analysis must be conducted in accordance with QC.10.4;
(2) when the missing data concerns the quantity or the mass flow rate of the black liquor produced, the replacement value must be the lesser of the maximum mass or flow entering the kiln and the maximum mass of flow that can be measured by the continuous monitoring and recording system;
(3) when the missing data concerns the monthly quantity of carbonate materials, the missing data must be estimated using all the data relating to the processes used or the data used for inventory purposes;
(4) when the missing data concerns the carbonate content of the carbonate materials, the replacement value must be the default value of 1.0.
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
The greenhouse gas emissions report referred to in section 6.2 must 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 in accordance with QC.1, in metric tons;
(3) the monthly 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) the total greenhouse gas emissions for each type of emissions, namely:
(a) the annual fixed process emissions corresponding to the emissions referred to in paragraph 1 in metric tons CO2 equivalent;
(b) the annual combustion emissions corresponding to the emissions referred to in paragraph 2 in metric tons CO2 equivalent;
(5) (paragraph revoked);
(6) (paragraph revoked);
(7) (paragraph revoked);
(8) (paragraph revoked);
(9) (paragraph revoked).
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 = [(CC02 × 10,000 × 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;
10,000 = Conversion factor, percentage to ppm;
4.16 x 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, in accordance with ASTM E359-00 (2005) e1 “Standard Test Methods for Analysis of Soda Ash (Sodium Carbonate)”;
(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 sampling or measurement data required by this Regulation for the calculation of emissions is missing, the emitter must use replacement data determined as follows:
(1) when emissions are calculated using a continuous emission monitoring and recording system, the method in paragraph 2 of QC.1.6 must be used;
(2) each missing monthly value concerning the inorganic carbon content of the trona or sodium carbonate must be replaced 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;
(3) for each missing monthly value concerning the quantity of trona or sodium carbonate, the missing data must be estimated using all the data relating to the processes used or using the same plant instruments as those used for inventory purposes;
(4) for each missing value of hourly CO2 concentration, the stack gas volumetric flow rate or the average process vent flow from the mine water stripper/evaporator during a performance test, a new performance test must be conducted;
(5) for each missing monthly value concerning the vent flow rate from the mine water stripper/evaporator, the missing data must be estimated using all the data relating to the processes used or the lesser of the maximum vent capacity or the maximum flow rate the flowmeter can measure.
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 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 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
The greenhouse gas emissions report referred to in section 6.2 must include
(1) the annual CO2, CH4 and N2O emissions attributable to the use of stationary combustion units, calculated 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 in accordance with QC.2, in metric tons;
(2.1) the annual CO2 emissions attributable to hydrogen production processes, calculated in accordance with QC.6, in metric tons;
(3) the annual CO2, CH4 and N2O emissions attributable to each petrochemical process, calculated in accordance with QC.12.3.1, in metric tons;
(4) the annual CO2 emissions attributable to catalyst regeneration, calculated in accordance with QC.12.3.2, in metric tons;
(5) the annual CO2, CH4 and N2O emissions attributable to flares and antipollution devices, calculated in accordance with QC.12.3.3, in metric tons;
(6) the annual CO2, CH4 and N2O emissions from process vents, calculated in accordance with QC.12.3.4, in metric tons;
(7) the annual CH4 emissions from leaks from equipment components, calculated in accordance with QC.12.3.5, in metric tons;
(8) the annual CH4 emissions from storage tanks, calculated in accordance with QC.12.3.6, in metric tons;
(9) the annual CH4 and N2O emissions from wastewater treatment, calculated in accordance with QC.12.3.7, in metric tons;
(10) the annual CH4 emissions attributable to oil-water separators, calculated in accordance with QC.12.3.8, in metric tons;
(11) the annual consumption of each type of feedstock that emits CO2, CH4 or N2O, expressed
(a) in millions of cubic metres at standard conditions, for gases;
(b) in kilolitres, for liquids;
(c) in metric tons for non-biomass solids;
(d) in bone dry metric tons, for biomass-derived solid fuels;
(12) the average monthly carbon content of the feedstock materials consumed or materials produced, in kilograms of carbon per kilogram of feedstock materials consumed or kilograms of carbon per kilogram of materials produced;
(13) the average monthly molecular mass of the feedstock consumed or materials produced, 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) the total greenhouse gas emissions for each type of emissions, namely:
(a) the annual fixed process emissions corresponding to the total of the emissions referred to in paragraphs 2.1, 3 and 4, in metric tons CO2 equivalent;
(b) the annual combustion emissions corresponding to the total of the emissions referred to in paragraphs 1 and 2, in metric tons CO2 equivalent;
(c) the “other” category emissions corresponding to the total of the emissions referred to in paragraphs 5 to 10 in metric tons CO2 equivalent.
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.12.3.8.
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 feedstock and product are gases, using equation 12-1:
Equation 12-1
Where:
CO2 = Annual CO2 emissions attributable to each petrochemical process, in metric tons;
n = Month;
j = Number of feedstock materials;
k = Number of products;
i = Type of gas;
(VGI)i,n = Volume of gas i input for month n, in cubic metres at standard conditions;
(CGI)i,n= Average carbon content of gas i input for month n, in kilograms of carbon per kilogram of gas input;
(MMGI)i = Monthly average molecular mass of gas i, in kilograms per kilomole;
MVC = Molar volume conversion factor (24.06 m3 per kilomole at standard conditions);
(VGP)i,n = Volume of gas i produced in month n, in cubic metres at standard conditions;
(CGP)i,n = Average carbon content of gas i produced in month n, in kilograms of carbon per kilogram of gas produced;
(MMGP)i = Monthly average molecular mass of gas i, in kilograms per kilomole or, when a mass flowmeter is used to measure the gas input flow in kilograms for month n, replace
_ _
| |
|MWGP |
|----| by 1;
|MVC |
|_ _|
3.664 = Ratio of molecular weights, CO2 to carbon;
0.001 = Conversion factor, kilograms to metric tons.
(2) where the feedstock and the product are liquids or solids, using equation 12-2:
Equation 12-2
Where:
CO2 = Annual CO2 emissions attributable to each petrochemical process, in metric tons;
n = Month;
j = Number of feedstock materials;
k = Number of products;
i = Type of feedstock material;
(QF)i,n = Quantity of feedstock i consumed in month n, in kilograms;
(CF)i,n= Average carbon content of feedstock i for month n, in kilograms of carbon per kilogram of feedstock;
(QP)i,n = Quantity of product i for month n, in kilograms;
(CP)i,n = Average carbon content of product i for month n, in kilograms of carbon per kilogram of product;
3.664 = Ratio of molecular weights, CO2 to carbon;
0.001 = Conversion factor, kilograms to metric tons.
QC.12.3.2. Calculation of CO2 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 x 10-3 kg per gigajoule for CH4 and 5.7 x 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. Calculation of CH4 and N2O emissions attributable to wastewater treatment
The annual CH4 and N2O emissions attributable to wastewater treatment must be calculated in accordance with QC.9.3.7.
QC.12.3.8. Calculation of CH4 emissions attributable to oil-water separators
The annual CH4 emissions attributable to oil-water separators must be calculated in accordance with QC.9.3.8.
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. Fugitive emissions from system components
For fugitive emissions from system components, the emitter must measure the parameters in accordance with QC.9.4.9.
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 sampling or measurement data required by this Regulation for the calculation of emissions is missing, the emitter must use replacement data determined as follows:
(1) each missing value concerning carbon content or molecular weight must be replaced 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;
(2) for each missing value concerning a quantity of feedstock or product, the missing data must be estimated using all the data relating to the processes used.
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
The greenhouse gas emissions report referred to in section 6.2 must 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 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) the total greenhouse gas emissions for each type of emissions, namely:
(a) the annual combustion emissions corresponding to the emissions referred to in subparagraph 1.1, in metric tons CO2 equivalent;
(b) the annual “other” category emissions corresponding to the emissions referred to in subparagraph 1, in metric tons CO2 equivalent.
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, in ppm;
Qfg = Volumetric flow of gas stream during performance test i, in cubic metres at standard conditions per hour;
1.826 x 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
CN20 × Qfg × 1.826 × 10-6
EFN20 = _________________________
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 x 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) ASTM D6348-03 (2010) “Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy”;
(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 sampling or measurement data required by this Regulation for the calculation of emissions is missing, the emitter must use replacement data determined as follows:
(1) every missing monthly value concerning adipic acid production must be estimated based on data from all the processes used or using the same plant instruments as those used for inventory purposes;
(2) for each missing value from the performance test, including the N2O emission factor, the production rate and the N2O concentration, a new performance test must be conducted.
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
The greenhouse gas emissions report referred to in section 6.2 must include the following information:
(1) the annual CO2 emissions attributable to lead production, in metric tons;
(2) the annual CO2 emissions attributable to the use in the furnace of each material containing carbon, in metric tons;
(2.1) the annual CO2, CH4 and N2O emissions attributable to the use of stationary combustion equipment, calculated in accordance with QC.1, in metric tons;
(3) the annual quantity of each material containing carbon used in the furnace, in metric tons;
(4) the carbon content of each material containing carbon used in the furnace, in metric tons of carbon per metric ton of material;
(5) the number of times that the methods for estimating missing data in QC.14.5 were used;
(6) the total greenhouse gas emissions for each type of emissions, namely:
(a) the annual fixed process emissions corresponding to the emissions referred to in paragraph 2, in metric tons CO2 equivalent;
(b) the annual combustion emissions corresponding to the emissions referred to in paragraph (2.1), in metric tons CO2 equivalent;
(7) the annual quantity of lead produced, in metric tons;
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 material i used except a material contributing less than 0.5% of the carbon in the process, which may be excluded by the emitter, in metric tons;
CCi = Carbon content of material i used, in kilograms of carbon per kilogram of material;
3.664 = Ratio of molecular weights, CO2 to carbon.
QC.14.4. Sampling, analysis and measurement requirements
An emitter who operates a facility or establishment that produces lead must:
(1) obtain annually the carbon content of each carbon-containing material used in the furnace, either by using the data provided by the material supplier or the following methods, based on a minimum of 3 representative samples:
(a) for solid carbonaceous reducing agents and carbon electrodes, in accordance with ASTM D5373-08 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal”;
(b) for liquid reducing agents, in accordance with ASTM D2502-04 (2009) “Standard Test Method for Estimation of Molecular Weight (Relative Molecular Mass) of Petroleum Oils From Viscosity Measurements”, ASTM D2503-92 (2007) “Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure”, ASTM D3238-95 (2010) “Standard Test Method for Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by the n-d-M Method” or ASTM D5291-10 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants”;
(c) for gaseous reducing agents, in accordance with ASTM D1945-03 (2010) “Standard Test Method for Analysis of Natural Gas by Gas Chromatograph” or ASTM D1946-90 (2006) “Standard Practice for Analysis of Reformed Gas by Gas Chromatography”;
(d) for waste-based carbon-containing materials, by operating the furnace both with and without the waste-reducing agents while keeping the composition of other carbon-containing materials introduced constant;
(2) calculate the annual quantity of each material containing carbon used in the furnace by adding together the monthly quantities of the material, 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 sampling or measurement data required by this Regulation for the calculation of emissions is missing, the emitter must use replacement data determined as follows:
(1) when emissions are calculated using a continuous emission monitoring and recording system, the method in paragraph 2 of QC.1.6 must be used;
(2) for each missing value concerning carbon content, a new analysis must be conducted;
(3) for each missing value concerning a quantity of carbon-containing material, the missing data must be estimated using all the data relating to the processes used or using the same plant instruments as those used for inventory purposes.
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
The greenhouse gas emissions report referred to in section 6.2 must include the following information:
(1) the annual CO2 emissions attributable to zinc production, in metric tons;
(2) the annual CO2 emissions attributable to use in the furnace of each material containing carbon, in metric tons;
(2.1) the annual CO2, CH4 and N2O emissions attributable to combustion, calculated in accordance with QC.1, in metric tons;
(3) the annual quantity of each material containing carbon used in the furnace, in metric tons;
(4) the carbon content of each material containing carbon used in the furnace, 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) the total greenhouse gas emissions for each type of emissions, namely:
(a) the annual fixed process emissions corresponding to the emissions referred to in paragraph 2, in metric tons CO2 equivalent;
(b) the annual combustion emissions corresponding to the emissions referred to in paragraph 2.1, in metric tons CO2 equivalent;
(7) the annual quantity of cathodic zinc produced, in metric tons;
(8) the iron content of the ore, in metric tons.
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 material i used except a material contributing less than 0.5% of the carbon in the process, which may be excluded by the emitter, in metric tons;
CCi = Carbon content of material i used, in kilograms of carbon per kilogram ofmaterial;
3.664 = Ratio of molecular weights, CO2 to carbon.
QC.15.4. Sampling, analysis and measurement requirements
An emitter who operates a facility or establishment that produces zinc must:
(1) obtain annually the carbon content of each material containing carbon used in the furnace, either by using the data provided by the supplier, or by using the following methods:
(a) for ores containing zinc, ASTM E1941-04 “Standard Test Method for Determination of Carbon in Refractory and Reactive Metals and Their Alloys”;
(b) for carbonaceous reducing agents and carbon electrodes, ASTM D5373-08 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal”;
(c) for flux materials, ASTM C25-06 “Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime”;
(d) for waste-based carbon-containing material, by operating the furnace both with and without the waste-based materials while keeping the composition of other carbon-containing materials constant;
(2) calculate the annual quantity of each material 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 sampling or measurement data required by this Regulation for the calculation of emissions is missing, the emitter must use replacement data determined as follows:
(1) when emissions are calculated using a continuous emission monitoring and recording system, the method in paragraph 2 of QC.1.6 must be used;
(2) for each missing value concerning carbon content, a new analysis must be conducted;
(3) for each missing value concerning a quantity of carbon-containing material, the missing data must be estimated using all the data relating to the processes used or using the same plant instruments as those used for inventory purposes.
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
The greenhouse gas emissions report referred to in section 6.2 must 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 cubic metres at standard conditions, for gases;
(b) in kilolitres, for liquids;
(c) in metric tons, for solids other than biomass solid fuels;
(d) in bone dry metric tons, for biomass solid fuels;
(3) where carbon content is used to calculate CO2 emissions, the average 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 high heat value of each type of fuel, expressed:
(a) in gigajoules per metric ton, for solid fuels;
(b) in gigajoules per kilolitre, for liquid fuels;
(c) in gigajoules per cubic metre, for gaseous fuels;
(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 and acid gas reagent, 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 CO2 from coal storage calculated in accordance with QC.5, in metric tons;
(12) the annual quantity of sorbent used in acid gas scrubbing equipment, 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) the total greenhouse gas emissions for each type of emissions, namely:
(a) the annual fixed process emissions corresponding to the emissions referred to in subparagraph 8, in metric tons CO2 equivalent;
(b) the annual combustion emissions corresponding to the emissions referred to in subparagraph 1, except emissions from the combustion of biomass, in metric tons CO2 equivalent;
(c) the annual “other” category emissions corresponding to the total of the emissions referred to in subparagraphs 9 and 10, in metric tons CO2 equivalent.
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.
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, CH4 and N2O 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;
(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.1.3.2;
(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.1.3.2;
(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 and 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 and QC.1.3.4.
QC.16.3.3. Calculation of CO2 emissions from acid gas scrubbing
The annual CO2 emissions from acid gas scrubbing 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
C02 = 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.
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 emissions of HFC attributable to cooling units used in electricity production in metric tons;
n = Number of new cooling units brought into operation during the year;
i = Unit brought into operation;
Q NEWi = Quantity of HFC used to fill unit i, in kilograms;
NC NEWi = Nameplate capacity of unit i, in kilograms;
m = Number of maintenance operations, either to recharge or recover, completed during the year;
j = Unit maintained;
Q RECHj = Quantity of HFC used to recharge the unit j during maintenance, in kilograms;
Q RECOj = Quantity of HFC recovered from unit j, in kilograms;
p = Number of cooling units retired during the year;
k = Unit retired;
NC RETk = Nameplate generating capacity of 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.
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.
QC.16.6.3. Acid gas scrubbing
The emitter 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 sampling or measurement data required by this Regulation for the calculation of emissions is missing, a replacement value must be used in accordance with 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 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
The greenhouse gas emissions report referred to in section 6.2 must 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 total annual CO2 emissions attributable to the production of electricity referred to in subparagraph a, calculated in accordance with QC.17.3.1, in metric tons;
(c) for each identifiable facility covered by a CO2 emissions report made to Environment Canada under section 71 of the Canadian Environmental Protection Act (1999) (1999, c.33), 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 National Pollutant Release Inventory of Environment Canada, 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 CO2 emissions attributable to the production of electricity acquired from the facility, in metric tons;
vi. the annual CO2 emissions of the facility, in metric tons;
(d) for each identifiable facility not covered by a CO2 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 type of fuel used to produce electricity and its high heat value, expressed
— in gigajoules per metric ton, for solid fuels;
— in gigajoules per kilolitre, for liquid fuels;
— in gigajoules per cubic metre, for gaseous fuels;
(e) for each identifiable facility for which the information needed to calculate CO2 emissions using equation 17-1 or 17-2 is not available, and for each unspecified facility:
i. the province or state from which the electricity is acquired;
ii. the total quantity of electricity acquired, in megawatt-hours, for each province or state,;
iii. the annual CO2 emissions attributable to the electricity acquired, in metric tons, from each province or 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 total annual CO2 emissions caused or avoided by the exportation of the electricity, calculated in accordance with QC.17.3.2, in metric tons;
(c) for each identifiable facility covered by a CO2 emissions report in accordance with this Regulation, for each destination province or state:
i. the annual CO2 emissions caused or avoided by the exportation of the electricity produced by the facility, in metric tons;
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 CO2 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 quantity of electricity produced by the facility that is exported annually, in megawatt-hours.
Where, with regard to an identifiable facility, the information referred to in subparagraphs iii to vi of subparagraph c of paragraph 1 of QC.17.3.2 is not available for a report year, the emitter may provide and use for calculating the emissions of the facility, in accordance with QC.17.3.1, the information of the most recent year that does not precede the report year by more than 3 years.
QC.17.3. Calculation methods for CO2 emissions
The annual CO2 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 CO2 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 CO2 emissions attributable to the production of electricity acquired outside Québec and sold or consumed within Québec
The annual CO2 emissions attributable to electricity produced outside Québec and sold or consumed within Québec must be calculated by adding the CO2 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 identifable facility covered by a CO2 emissions report made to Environment Canada under section 71 of the Canadian Environmental Protection Act (1999) (1999, c. 33), 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

MWh
CO2 = C02,i × imp
MWhn
Where:
CO2 = Annual CO2 emissions attributable to the production of electricity acquired outside Québec and produced by the identifiable facility, in metric tons;
CO2,i = Annual CO2 emissions attributable to the identifiable facility, in metric tons;
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 a specified facility not covered by a CO2 emissions report made to one of the organizations referred to in paragraph (1), using equation 17-2:
Equation 17-2
Where:
CO2 = Annual CO2 emissions attributable to the production of electricity acquired outside Québec and produced by the identifiable facility, in metric tons;
n = Number of fuels used annually by the facility;
j = Type of fuel;
Qj+ Quantity of fuel j, expressed
— in metric tons, for solid fuels;
— in kilolitres, for liquid fuels;
— in cubic metres, for gaseous fuels;
HHVj = High heat value of fuel j consumed for electricity production, as indicated in Table 1-1 or 1-2 specified in QC.1.7, expressed
— in gigajoules per metric ton, for solid fuels;
— in gigajoules per kilolitre, for liquid fuels;
— in gigajoules per cubic metre, for gaseous fuels;
EFj = CO2 emission factor for fuel j as indicated in Table 1-2, 1-3, 1-4, 1-5 or 1-6 specified in QC.1.7, in kilograms of CO2 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 megawatthours;
0.001 = Conversion factor, kilograms to metric tons.
(3) for an identifiable facility for which the information needed to calculate CO2 emissions using equation 17-1 or 17-2 is not available, and for an unidentifiable facility, using equation 17-3:
Equation 17-3
CO2 = MWhimp × EFD
Where:
CO2 = Annual CO2 emissions attributable to the production of electricity acquired outside Québec and produced by the identifiable or unidentifiable facility, in metric tons;
MWhimp = Quantity of electricity acquired from the identifiable or unidentifiable facility and consumed or sold annually in Québec, in megawatt-hours;
EFD = CO2 emission factor for the province or North American market from which the electricity comes, as indicated in Table 17-1 for QC.17.4, in metric tons of CO2 per megawatt-hour, or, where 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, use a factor of 0.999.
QC.17.3.2. Calculation of CO2 emissions caused or avoided by the exportation of the electricity
The annual CO2 emissions caused or avoided by the exportation of the electricity must be calculated by adding the CO2 emissions attributable to the exportation of electricity produced by identifiable facilities to the CO2 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 CO2 emissions report in accordance with QC.16, using equation 17-4:
Equation 17-4
- -
| MWhexp |
CO2 = | CO2,t × ______ | - (MWhexp × EFD)
| |
| MWhn |
- -
Where:
CO2 = Annual CO2 emissions caused or avoided by the exportation of the electricity produced by the specified facility, in metric tons;
CO2t = Total annual CO2 emissions attributable to the identifiable facility, in metric tons;
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 = CO2 emission factor for the province or North American market where the electricity is delivered, as indicated in Table 17-1 for QC.17.4, in metric tons of CO2 per megawatt-hour;
(2) for an identifiable facility not covered by a CO2 emissions report made in accordance with QC.16 and for an unspecified facility, using equation 17-5:
Equation 17-5
CO2 = MWhexp × (EFQC - EFD)
Where:
CO2 = Annual CO2 emissions caused or avoided by the exportation of the electricity produced by the identifiable or unidentifiable facility, in metric tons;
MWhexp = Quantity of electricity produced by the identifiable or unidentifiable facility and exported annually, in megawatt-hours;
EFQC = CO2 emission factor for Québec, as indicated in Table 17-1 for QC.17.4, in metric tons of CO2 per megawatt-hour;
EFD = CO2 emission factor for the province or North American market where the electricity is delivered, as indicated in Table 17-1 for QC.17.4, in metric tons of CO2 per megawatt-hour, or, where the electricity comes from an identifiable nuclear, hydroelectric, sea current, wind, solar or tidal power facility, a factor of 0.
QC.17.4. Table
Table 17-1. Default CO2 emission factors for Canadian provinces and certain North American markets, in metric tons of CO2 per megawatt-hour
(QC.17.3.1, (3), QC.17.3.2, (1) and (2))

__________________________________________________________________________________
| | |
| Canadian province and North American | Default emission factor (t/MWh) |
| market | |
|_____________________________________________|____________________________________|
| | |
| Newfoundland and Labrador | 0.021 |
|_____________________________________________|____________________________________|
| | |
| Nova Scotia | 0.833 |
|_____________________________________________|____________________________________|
| | |
| New Brunswick | 0.544 |
|_____________________________________________|____________________________________|
| | |
| Québec | 0.002 |
|_____________________________________________|____________________________________|
| | |
| Ontario | 0.167 |
|_____________________________________________|____________________________________|
| | |
| Vermont | 1.332 |
|_____________________________________________|____________________________________|
| | |
| New England Independent System Operator | 0.457 |
| (NE-ISO), including all or part of the | |
| following states: | |
| | |
| - Connecticut | |
| - Massachusetts | |
| - Maine | |
| - Rhode Island | |
| - Vermont | |
| - New Hampshire | |
|_____________________________________________|____________________________________|
| | |
| New York Independent System Operator | 0.567 |
| (NY-ISO) | |
|_____________________________________________|____________________________________|
| | |
| Pennsylvania Jersey Maryland | 0.933 |
| Interconnection Regional Transmission | |
| Organization (PJM-RTO), including all or | |
| part of the following states: | |
| - Delaware | |
| - Indiana | |
| - Illinois | |
| - Kentucky | |
| - Maryland | |
| - Michigan | |
| - New Jersey | |
| - Ohio | |
| - Pennsylvania | |
| - Virginia | |
| - West Virginia | |
| - District of Columbia | |
|_____________________________________________|____________________________________|
| | |
| Midwest Independent Transmission System | 0.999 |
| Operator (MISO-RTO), including all or part | |
| of the following province and states: | |
| - North Dakota | |
| - South Dakota | |
| - Minnesota | |
| - Iowa | |
| - Missouri | |
| - Wisconsin | |
| - Illinois | |
| - Michigan | |
| - Indiana | |
| - Ohio | |
| - Montana | |
| - Kentucky | |
|_____________________________________________|____________________________________|
1 The ASTM standards mentioned in this Schedule are published by the American Society of Testing and Materials (ASTM International).
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
The greenhouse gas emissions report referred to in section 6.2 must include the following information:
(1) the annual CO2 emissions attributable to the production of nickel and copper, in metric tons;
(2) the annual CO2, CH4 and N2O emissions attributable to combustion, calculated 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 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 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 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 carbon content of the nickel or copper ore processed, in metric tons of carbon per metric ton of ore;
(16) the annual consumption of other carbon-containing raw materials, that contributes to 0.5% or more of the total carbon in the process, in metric tons;
(17) the carbon content of the other carbon-containing raw materials, in metric tons of carbon per metric ton of raw materials;
(18) the number of times that the methods for estimating missing data in QC.18.5 were used;
(19) the total greenhouse gas emissions for each type of emissions, namely:
(a) the annual fixed process emissions corresponding to the total of the emissions referred to in paragraphs 3 to 7, in metric tons CO2 equivalent;
(b) the annual combustion emissions corresponding to the emissions referred to in paragraph 2, in metric tons CO2 equivalent;
(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.
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 carbon-containing raw materials, 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 = 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 = 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 = 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 = 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 = 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 carbon contained in other raw materials, in metric tons;
n = Number of raw materials;
i = Raw material;
RMi = Annual consumption of raw material i, that contributes to 0.5% or more of the total carbon in the process, in metric tons;
CRM,i = 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
An emitter who operates a facility or establishment producing nickel or copper must
(1) obtain annually the carbon content of each carbon-containing material used, either by using data from the material supplier or by using the following methods:
(a) for coal and coke, ASTM D5373-08 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal and Coke”;
(b) for petroleum-based liquid fuels and liquid waste-derived fuels, ASTM D5291-10 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants”, the ultimate analysis method or calculations in ASTM D3238-95(2010) “Standard Test Method for Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by the n-d-M Method” and either ASTM D2502-04(2009) “Standard Test Method for Estimation of Molecular Weight (Relative Molecular Mass) of Petroleum Oils From Viscosity Measurements” or ASTM D2503-92(2007) “Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure”;
(c) for gaseous fuels, ASTM D1945-03(2010) “Standard Test Method for Analysis of Natural Gas by Gas Chromatography” or ASTM D1946-90(2006) “Standard Practice for Analysis of Reformed Gas by Gas Chromatography”;
(d) for limestone and dolomite, ASTM C25-06 “Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime”;
(e) for other raw materials, the methods in QC.1.5.1 and QC.1.5.5;
(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 sampling or measurement data required by this Regulation for the calculation of emissions is missing, the emitter must use replacement data determined as follows:
(1) when emissions are calculated using a continuous emission monitoring and recording system, the method in paragraph 2 of QC.1.6 must be used;
(2) when the missing data concerns the carbon content, a new analysis must be conducted in accordance with QC.18.4;
(3) when the missing data concerns the quantity of raw materials consumed, the missing data must be estimated using all the data relating to the processes used or data used for inventory purposes.
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
The greenhouse gas emissions report referred to in section 6.2 must include the following information:
(1) the annual CO2 and CH4 emissions attributable to processes that use pyrometallurgical techniques;
(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 carbon-containing material, in metric tons;
(e) the average carbon content of each carbon-containing material, in metric tons of carbon per ton of material;
(3) the annual CO2, CH4 and N2O emissions attributable to the use of fixed combustion units, calculated 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, calculated 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) the total greenhouse gas emissions for each type of emissions, namely:
(a) the annual fixed process emissions corresponding to the total of the emissions referred to in subparagraph a of subparagraph 2, in metric tons CO2 equivalent;
(b) the annual combustion emissions corresponding to the emissions referred to in subparagraph 3 and the CH4 and N2O emissions referred to in subparagraph 4, in metric tons CO2 equivalent;
(c) the “other” category emissions corresponding to the emissions referred to in subparagraph b of subparagraph 2, in metric tons CO2 equivalent.
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.
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 = 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 = 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 = Carbon content of ore, in metric tons of carbon per metric ton of ore;
FM = Annual consumption of flux material, in metric tons;
CFM = 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 = 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 = 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
An emitter who operates a facility or establishment that uses a pyrometallurgical process for ferroalloy production must
(1) obtain annually the carbon content of each carbon-containing material used in the electric arc furnaces based on the data indicated by the supplier or the analysis of a minimum of 3 representative samples and using the following methods:
(a) for metal ores and ferroalloy products, ASTM E1941-10 “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, ASTM D5373-08 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal”;
(c) for flux materials, ASTM C25-06 “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 sampling or measurement data required by this Regulation for the calculation of emissions is missing, the emitter must use replacement data determined as follows:
(1) when emissions are calculated using a continuous emission monitoring and recording system, the method in paragraph 2 of QC.1.6 must be used;
(2) when the missing data concerns the carbon content, the replacement value must be 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 sampled or measured after the missing data period;
(3) when the missing data concerns the quantity of raw material consumed or products produced, the missing data must be estimated using all the data relating to the processes used or the data used for inventory purposes.
QC.19.7. Table
Table 19-1. CH4 emission factors by electric arc furnace charging mode
(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
The greenhouse gas emissions report referred to in section 6.2 must 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 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) the total greenhouse gas emissions for each type of emissions, namely:
(a) the annual combustion emissions corresponding to the emissions referred to in paragraph 2, in metric tons CO2 equivalent;
(b) the “other” category emissions corresponding to the emissions referred to in paragraph 1, in metric tons CO2 equivalent.
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 sampling or measurement data required by this Regulation for the calculation of emissions is missing, the emitter must use replacement data determined 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.
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
The greenhouse gas emissions report referred to in section 6.2 must 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 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) the total greenhouse gas emissions for each type of emissions, namely:
(a) the annual combustion emissions corresponding to the emissions referred to in paragraph 2, in metric tons CO2 equivalent;
(b) the annual “other” category emissions corresponding to the emissions referred to in paragraph 1, in metric tons CO2 equivalent.
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 x 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
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. ASTM D6348-03 (2010) “Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy”;
(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 b 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 sampling or measurement data required by this Regulation for the calculation of emissions is missing, the emitter must use replacement data determined as follows:
(1) for each missing monthly value concerning nitric acid production, the missing data must be estimated using all the data relating to the processes used or using the same plant instruments as those used for inventory purposes;
(2) for each missing value determined following the performance test, including the N2O emission factor, the production rate and the N2O concentration, a new performance test must be conducted.
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
The greenhouse gas emissions report referred to in section 6.2 must 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 in accordance with QC.1, in metric tons;
(3) the annual quantity of phosphoric acid produced, in metric tons;
(4) the monthly inorganic carbon of the phosphate rock, in metric tons of carbon per metric ton of phosphate rock;
(5) the monthly and 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) the total greenhouse gas emissions for each type of emissions, namely:
(a) the annual fixed process emissions corresponding to the emissions referred to in paragraph 1, in metric tons CO2 equivalent;
(b) the annual combustion emissions corresponding to the emissions referred to in paragraph 2, in metric tons CO2 equivalent.
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.
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