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

Updated to 1 September 2012

This document has official status.

chapter Q-2, r. 15

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

Environment Quality Act

(chapter Q-2, ss. 2.2, 46.2, 115.27, 115.34 and 124.1).

DIVISION I SCOPE, PURPOSE AND INTERPRETATION

1. This Regulation applies to every operator whose enterprise, facility or establishment emits a contaminant listed in Schedules A and A.1 into the atmosphere at a level that is equal to or greater than the reporting threshold prescribed for the contaminant.

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 calculation methods in QC.22.3.1 and QC.22.3.2.

QC.22.3.1. Use of a continuous emission monitoring and recording system

The annual CO2 emissions may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.1.3.4.

QC.22.3.2. Calculation of annual CO2 emissions attributable to phosphoric acid production

The annual CO2 emissions attributable to phosphoric acid production may be calculated using equation 22-1:

Equation 22-1

Where:

CO2 = Annual CO2 emissions attributable to phosphoric acid production, in metric tons;

i = Month;

PRi = Consumption of phosphate rock for month i, in metric tons;

Ci = Carbon content of phosphate rock for month i, in metric tons of carbon per metric ton of phosphate rock;

3.664 = Ratio of molecular weights, CO2 to carbon.

QC.22.4. Sampling, analysis and measurement requirements

An emitter who operates a facility or establishment that produces phosphoric acid must

(1) take a monthly sample of each type of phosphate rock when the rock comes from different sources, or produce a composite sample by combining representative samples;

(2) determine the inorganic carbon content of each phosphate rock sample taken monthly from the feed system in accordance with the method in “Analytical Methods Manual in 2010 (10th edition), version 1.92” published by the Association of Fertilizer and Phosphate Chemists;

(3) determine the monthly consumption of phosphate rock using the same plant instruments as those used for inventory purposes, such as weigh hoppers or belt weight feeders.

QC.22.5. Methods for estimating missing data

When 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 the inorganic carbon content of the phosphate rock, the replacement value must be the arithmetic average of the data sampled 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;

(2) for each missing value concerning the monthly consumption of phosphate rock, the missing data must be estimated using all the data relating to the processes used or data used for inventory purposes.

QC.23. AMMONIA PRODUCTION

QC.23.1. Covered sources

The covered sources are all the ammonia manufacturing processes in which ammonia is manufactured via steam reforming of fossil-based feedstocks or the gasification of solid and liquid raw material.

QC.23.2. Greenhouse gas reporting requirements

The greenhouse gas emissions report referred to in section 6.2 must include the following information:

(1) the annual CO2 emissions attributable to ammonia production via steam reforming or gasification processes, in metric tons;

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

(3) the monthly and annual consumption of each raw material used in ammonia production, expressed

(a) in cubic metres at standard conditions for gases;

(b) in kilolitres for liquids;

(c) in metric tons for solids;

(4) the monthly carbon content of each raw material used in ammonia production, namely,

(a) in kilograms of carbon per kilogram of raw material in the case of gases and solids;

(b) in kilograms of carbon per kilolitre of raw material in the case of liquids;

(5) the annual CO2 emissions attributable to the combustion of gas from the waste recycle stream, in metric tons;

(6) the annual consumption of gaseous fuels from the waste recycle stream, in cubic metres at standard conditions;

(7) the monthly carbon content of gas from the waste recycle stream, in kilograms of carbon per kilogram of gas;

(8) the annual production of ammoniac, in metric tons;

(9) if CO2 from ammonia production is used to produce urea, the annual production of urea, in metric tons;

(10) the number of times that the methods for estimating missing data provided for in QC.23.5 were used;

(11) 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 total of the emissions referred to in subparagraphs 2 and 5, excluding emissions attributable to the combustion or fermentation of biomass and biofuels, in metric tons CO2 equivalent.

Subparagraphs 4 to 7 of the first paragraph do not apply to the CO2 emissions of an emitter who calculates emissions using data from a continuous emission monitoring and recording system.

QC.23.3. Calculation methods for annual CO2 emissions

For each process used, the annual CO2 emissions attributable to ammonia production must be calculated using one of the calculation methods in QC.23.3.1 and QC.23.3.2 and the annual CO2 emissions attributable to the combustion of gas from the waste recycle stream must be calculated in accordance with QC.23.3.3.

QC.23.3.1. Use of a continuous emission monitoring and recording system

The annual CO2 emissions may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.1.3.4.

QC.23.3.2. Calculation of annual CO2 emissions attributable to ammonia production

The annual CO2 emissions attributable to ammonia production must be calculated using equations 23-1 to 23-4:

Equation 23-1

Where:

CO2 = Annual CO2 emissions attributable to ammonia production, in metric tons;

n = Total number of ammonia production units;

k = Ammonia production unit;

CO2,G = Annual CO2 emissions attributable to ammonia production for production unit k from gaseous feedstock, calculated in accordance with equation 23-2, in metric tons;

CO2,L = Annual CO2 emissions attributable to ammonia production for production unit k from liquid feedstock, calculated in accordance with equation 23-3, in metric tons;

CO2,S = Annual CO2 emissions attributable to ammonia production for production unit k from solid feedstock, calculated in accordance with equation 23-4, in metric tons;

Equation 23-2

Where:

CO2,G = Annual CO2 emissions attributable to ammonia production for production unit k from gaseous feedstock, in metric tons;

i = Month;

Fdstki = Consumption of gaseous feedstock for month i, in cubic metres at standard conditions, or, when a mass flowmeter is used, in kilograms;

Ci = Carbon content of gaseous feedstock consumed in month i, in kilograms of carbon per kilogram of feedstock;

MW = Molecular weight of gaseous feedstock in kilograms per kilomole or, when a mass flowmeter is used, replace MW/MVC by 1;

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;

Equation 23-3

Where:

CO2,L = Annual CO2 emissions attributable to ammonia production for production unit k from liquid feedstock, in metric tons;

i = Month;

Fdstki = Consumption of liquid feedstock for month i, en kilolitres;

Ci = Carbon content of the liquid feedstock consumed in month i, 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;

Equation 23-4

Where:

CO2,S = Annual CO2 emissions attributable to ammonia production at production unit k from solid feedstock, in metric tons;

i = Month;

Fdstki = Consumption of solid feedstock for month i, in metric tons;

Ci = Carbon content of the solid feedstock consumed in month i, in kilograms of carbon per kilogram of feedstock;

3.664 = Ratio of molecular weights, CO2 to carbon.

QC.23.3.3. Calculation of annual CO2 emissions attributable to the combustion of gas from the waste recycle stream

The annual CO2 emissions attributable to the combustion of gas from the waste recycle stream of each ammonia production unit must be calculated using equation 23-5:

Equation 23-5

Where:

CO2,WR = Annual CO2 emissions attributable to the combustion of gas from the waste recycle stream of production unit, in metric tons;

i = Month;

WRGi = Quantity of gas from the waste recycle stream for month i, in cubic metres at standard conditions or, when a mass flowmeter is used, in kilograms;

Ci = Carbon content of gas from the waste recycle stream for month i, in kilograms of carbon per kilogram of feedstock;

MW = Molecular weight of the gas from the waste recycle stream, in kilograms per kilomole or, when a mass flowmeter is used, replace MW/MVC by 1;

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.23.4. Sampling, analysis and measurement requirements

An emitter who operates a facility or establishment that produces ammoniac must

(1) determine the consumption of feedstocks using the following methods:

(a) using flowmeters for liquid and gaseous feedstocks and for gas from the waste recycle stream;

(b) using the same plant instruments as those used for inventory purposes for solid feedstocks and the ammonia and urea produced;

(2) determine monthly the carbon content and the average molecular weight of each feedstock consumed and of gas from the waste recycle stream, either by using data from the material supplier or by using the following methods:

(a) ASTM D1945-03 (2010) “Standard Test Method for Analysis of Natural Gas by Gas Chromatography”;

(b) ASTM D1946-90 (2006) “Standard Practice for Analysis of Reformed Gas by Gas Chromatography”;

(c) ASTM D2502-04 (2009) “Standard Test Method for Estimation of Molecular Weight (Relative Molecular Mass) of Petroleum Oils From Viscosity Measurements”;

(d) ASTM D2503-92 (2007) “Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure”;

(e) 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”;

(f) ASTM D5291-10 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants”;

(g) ASTM D3176-09 “Standard Practice for Ultimate Analysis of Coal and Coke”;

(h) ASTM D5373-08 “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal”;

(3) calibrate all flowmeters used for liquid or gaseous fuels, except those used for gas billing, and measure tank levels in accordance with the methods in QC.1.5.

QC.23.5. Methods for estimating missing data

When 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 feedstock or gas from the waste recycle stream consumed, the missing data must be estimated using all the data relating to the processes used or data used for inventory purposes.

QC.24. ELECTRICITY TRANSMISSION AND DISTRIBUTION AND USE OF EQUIPMENT TO PRODUCE ELECTRICITY

QC.24.1. Covered sources

The covered sources are all equipment not covered by the calculation methods provided for in QC.16 used for the transmission and distribution of electricity and those used for producing electricity, in particular, transmission and distribution systems, substations, high-voltage circuit breakers and switches, that use sulphur hexafluoride (SF6) and perfluorocarbons (PFCs).

Fugitive emissions attributable to equipment at an enterprise are also covered.

QC.24.2. Greenhouse gas reporting requirements

The greenhouse gas emissions report referred to in section 6.2 must include the following information:

(1) annual fugitive SF6 emissions attributable to electrical equipment, in metric tons;

(2) annual fugitive emissions of each PFC attributable to electrical equipment, in metric tons;

(3) the number of times that the methods for estimating missing data in QC.24.5 were used;

(4) the annual emissions of greenhouse gas in the “other” category, corresponding to the total of the emissions referred to in paragraphs 1 and 2, in metric tons CO2 equivalent.

QC.24.3. Calculation methods for fugitive SF6 and PFC emissions

Fugitive SF6 and PFC emissions must be calculated in accordance with the calculation methods in QC.24.3.1 and QC.24.3.2.

QC.24.3.1. Calculation of fugitive emissions by mass balance

Fugitive SF6 and PFC emissions must be calculated using a mass-balance method that systematically accounts for all use of SF6 and PFC by the emitter. For the purposes of the calculation, all quantities of SF6 and PFC that cannot be accounted for are assumed to have been emitted.

Annual fugitive emissions must be calculated using equations 24-1 to 24-5:

Equation 24-1

Where:

GHGj = Annual fugitive emissions of gas j, in metric tons;

/\SINV = Change in inventory of gas j stored in storage containers, other than electrical equipment, calculated in accordance with equation 24-2, in kilograms;

SACQ = Quantity of gas j acquired during the year, contained in electrical equipment or storage containers, calculated in accordance with equation 24-3, in kilograms;

SSOLD = Quantity of gas j sold or transferred to other facilities or establishments during the year, contained in electrical equipment or storage containers, calculated in accordance with equation 24-4, in kilograms;

/\SCAP = Net increase in total nameplate capacity of equipment using gas j, calculated in accordance with equation 24-5, in kilograms;

0.001 = Conversion factor, kilograms to metric tons;

j = Type of gas;

Equation 24-2

Where:

/\SINV = Change in inventory of gas j stored in storage containers, other than electrical equipment, in kilograms;

SBegin = Quantity of gas j stored at the beginning of the year in storage containers, other than electrical equipment, in kilograms;

SEnd = Quantity of gas j stored at the end of the year in storage containers, other than electrical equipment, in kilograms;

j = Type of gas;

Equation 24-3

SACQ = SCvl + SEquip + SReturned

Where:

SACQ = Quantity of gas j acquired during the year, contained in electrical equipment or storage containers, in kilograms;

SCvl = Quantity of gas j acquired, contained in containers, in kilograms;

SEquip = Quantity of gas j acquired, contained in electrical equipment, in kilograms;

SReturned = Quantity of gas j returned to the enterprise after off-site recycling, in kilograms;

j = Type of gas;

Equation 24-4

SSOLD = SSales + SReturns + SDestruct + SRecyc

Where:

SSOLD = Quantity of gas j sold or transferred to other facilities or establishments during the year, in storage containers or electrical equipment, in kilograms;

SSales = Quantity of gas j sold to other facilities or establishments, including gas left in electrical equipment that is sold, in kilograms;

SReturns = Quantity of gas j returned to suppliers, in kilograms;

SDestruct = Quantity of gas j sent to destruction facilities, in kilograms;

SRecyc = Quantity of gas j sent off-site for recycling, in kilograms;

j = Type of gas;

Equation 24-5

Where:

/\SCAP = Net increase in total nameplate capacity of electrical equipment using gas j, in kilograms;

SNew = Total nameplate capacity of new electrical equipment, in kilograms;

SRetire = Total nameplate capacity of retired or sold electrical equipment, in kilograms;

j = Type of gas.

QC.24.3.2. Calculation of fugitive emissions by direct measurement

Fugitive SF6 and PFC emissions must be calculated by directly measuring the mass of gas added to electrical equipment during operation and the quantity of gas collected from decommissioned equipment, using equations 24-6 to 24-8:

Equation 24-6

GHGj = (SO + SD)j × 0.001

Where:

GHGj = Annual emissions of gas j attributable to the operation and decommissioning of electrical equipment, in metric tons;

SO = Annual emissions of gas j during operation phase, calculated in accordance with equation 24-7, in kilograms;

SD = Annual emissions of gas j during decommissioning phase, calculated in accordance with equation 24-8, in kilograms;

0.001 = Conversion factor, kilograms to metric tons;

j = Type of gas;

Equation 24-7

Where:

SO = Annual fugitive emissions of gas j during operation phase, in kilograms;

n = Number of additions of gas j during the year;

i = Addition;

Si = Quantity of gas j added to electrical equipment during addition i, in kilograms;

j = Type of gas;

Equation 24-8

Where:

SD = Annual emissions of gas j during decommissioning phase, in kilograms;

n = Number of units of electrical equipment decommissioned during the year;

i = Electrical equipment;

NC = Nameplate capacity of decommissioned electrical equipment i, in kilograms;

SC = Quantity of gas j collected from decommissioned electrical equipment i, in kilograms;

j = Type of gas.

QC.24.4. Sampling, analysis and measurement requirements

An emitter who operates an electricity transmission or distribution enterprise or uses electrical equipment must

(1) measure additions of SF6 or PCFs during the operation phase using a measuring instrument such as a flowmeter or weigh scale. If a weigh scale is used, the SF6 or PFC container must be weighed before and after its contents are added to the electrical equipment, with the difference being equal to the quantity of SF6 or PFC added to the equipment;

(2) calibrate the instruments used to measure the mass of SF6 or PFC used to re-charge electrical equipment, using one of the following methods:

(a) by following the instructions of the manufacturer for the use of a flowmeter;

(b) every 6 months, by weighing objects of pre-determined mass and zeroing the weigh scale accordingly.

QC.24.5. Methods for estimating missing data

When sampling or measurement data required by this Regulation for the calculation of emissions is missing, an emitter must use a replacement value based on data from equipment with a similar nameplate capacity for SF6 and PFCs, and data from similar equipment repair, replacement, and maintenance operations.

QC.25. CARBONATES USE

QC.25.1. Covered sources

The covered sources are all process equipment that uses carbonates such as limestone, dolomite, ankerite, magnesite, siderite, rhodochrosite, sodium carbonate or strontium carbonate.

All equipment that uses carbonates or carbonate-containing raw materials that are consumed in the production of cement, ferroalloys, glass, iron and steel, lead, lime, phosphoric acid, sodium carbonate or zinc and for which special calculation methods are provided for in this Schedule is excluded.

Carbonates contained in the sorbents used in acid gas scrubbing equipment are also excluded, the emissions from which must be quantified and reported in accordance with QC.1.3.6.

QC.25.2. Greenhouse gas reporting requirements

The greenhouse gas emissions report referred to in section 6.2 must include the following information:

(1) the annual CO2 emissions attributable to the use of carbonates or carbonate-based raw materials, in metric tons;

(2) the annual consumption of each carbonate or carbonate-based raw material, in metric tons;

(3) when the calculation method in QC25.3.2 is used,

(a) the calcination fraction for carbonates, in tons of carbonate obtained per metric ton of carbonates in the carbonate-based raw material;

(b) the average annual carbonate content of each carbonate-based raw material, in metric tons of carbonates per metric ton of carbonate-based raw material;

(4) the annual quantity of each carbonate-based material output, in metric tons, when the calculation method in QC.25.3.3 is used;

(5) the number of times that the methods for estimating missing data in QC.25.5 were used;

(6) the annual emissions attributable to fixed processes, corresponding to the emissions referred to subparagraph 1, in metric tons CO2 equivalent.

Subparagraph 3 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.25.3. Calculation methods for annual CO2 emissions

For each process, the annual CO2 emissions attributable to the use of carbonate-based raw materials must be calculated using one of the calculation methods in QC.25.3.1 to QC.25.3.3.

QC.25.3.1. Use of a continuous emission monitoring and recording system

The annual CO2 emissions may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.1.3.4.

QC.25.3.2. Calculation method for CO2 emissions using the calcination fraction

The annual CO2 emissions attributable to the use of carbonates or carbonate-based raw materials may be calculated using the calcination fraction, using equation 25-1:

Equation 25-1

Where:

CO2 = Annual CO2 emissions attributable to the use of carbonate-based raw materials, in metric tons;

n = Number of carbonates contained in the raw materials;

i = Carbonate;

m = Number of carbonate-based raw materials used;

j = Raw material;

RMj,i = Annual consumption of raw material j containing carbonate i, in metric tons;

CCj,i = Average annual content of carbonate i in raw material j, in metric tons of carbonate per metric ton of raw material;

EFi = Emission factor for carbonate i as specified in Table 25-1 in QC.25.6, in metric tons of CO2 per metric ton of carbonate;

Fi = Calcination fraction for carbonate i, in metric tons of carbonate obtained per metric ton of carbonate in the raw material, a value of 1.0 corresponding to complete calcination.

QC.25.3.3. Calculation method for CO2 emissions by mass balance

The annual CO2 emissions attributable to the use of carbonates or carbonate-based raw materials may be calculated by mass balance, using equation 25-2:

Where:

CO2 = Annual CO2 emissions attributable to the use of carbonates or carbonate-based raw materials, in metric tons;

n = Number of carbonates contained in raw materials;

i = Carbonate;

m = Number of carbonate-based raw materials;

j = Raw material;

RMj,i = Annual consumption of carbonate or raw material j containing carbonate i, in metric tons;

CCRMj,i = Average annual content of carbonate i in raw material j, in metric tons of carbonate per metric ton of raw material;

EFi = Emission factor for carbonate i as specified in Table 25-1 in QC.25.6, in metric tons of CO2 per metric ton of carbonate;

p = Number of carbonate-containing output materials;

k = Carbonate-containing output material;

OMk,i = Annual quantity of output material k containing carbonate i, in metric tons;

CCOMk,i = Average annual content of carbonate i in output material k, in metric tons of carbonate per metric ton of material.

QC.25.4. Sampling, analysis and measurement requirements

An emitter who operates a facility or establishment that uses carbonate-based raw materials must

(1) determine annually the calcination fraction for each carbonate consumed by sampling and chemical analysis, using an industry-recognized method such as ASTM, ASME or API, an x-ray fluorescence method, or the value 1.0;

(2) determine annually the average carbonate content by calculating the arithmetic average of the monthly data obtained from raw material suppliers, by conducting sampling and chemical analysis, or using the value 1.0;

(3) determine the annual quantity of each input carbonate and each input carbonate-based raw material, and of each carbonate-based output material, by direct weight measurement once a month using the same plant instruments used for inventory purposes, such as weigh hoppers or belt weigh feeders, or using calculations based on data from the process control system.

QC.25.5. 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 monthly quantity of input or output carbonate-based raw materials, the missing data must be estimated using all the data relating to the processes used or the data used for inventory purposes;

(3) when the missing data concerns the carbonate content of raw materials or of output carbonate-based materials, the replacement value must be the default value 1.0.

QC.25.6. Tables

Table 25-1. CO2 emission factors for various carbonates

(QC.25.3.2, QC.25.3.3)

 _________________________________________________________________________________
|                      |                                                          |
| Mineral name -       |     CO2 emission factor (metric tons of CO2 per metric    |
| Carbonate            |     ton of carbonate)                                    |
|______________________|__________________________________________________________|
|                      |                                                          |
| Limestone - CaCO3    |                   0.43971                                |
|______________________|__________________________________________________________|
|                      |                                                          |
| Magnesite - MgCO3    |                   0.52197                                |
|______________________|__________________________________________________________|
|                      |                                                          |
| Dolomite - CaMg(CO3)2 |                   0.47732                                |
|______________________|__________________________________________________________|
|                      |                                                          |
| Siderite - FeCO3     |                   0.37987                                |
|______________________|__________________________________________________________|
|                      |                                                          |
| Ankerite -           |                   0.47572                                |
| Ca(Fe,Mg,Mn)(CO3)2    |                                                          |
|______________________|__________________________________________________________|
|                      |                                                          |
| Rhodochrosite -      |                                                          |
| MnCO3                |                   0.38286                                |
|______________________|__________________________________________________________|
|                      |                                                          |
| Sodium Carbonate/    |                   0.41492                                |
| Soda Ash - Na2CO3     |                                                          |
|______________________|__________________________________________________________|
|                      |                                                          |
| Strontium Carbonate  |                                                          |
| - SrCO3              |                   0.29811                                |
|______________________|__________________________________________________________|
|                      |                                                          |
| Others               | quantity of (CO3-) in carbonate X molecular weight of CO2 |
|                      | ________________________________________________________ |
|                      |                                                          |
|                      |                molecular weight of carbonate             |
|______________________|__________________________________________________________|    

QC.26. GLASS PRODUCTION

QC.26.1. Covered sources

The covered sources are glass melting furnaces used to produce flat glass, container glass, pressed and blown glass or wool fibreglass.

QC.26.2. Greenhouse gas reporting requirements

The greenhouse gas emissions report referred to in section 6.2 must include the following information:

(1) the annual CO2 emissions attributable to glass production, in metric tons;

(2) the annual CO2 emissions attributable to the use of carbonate-containing raw materials for glass production, calculated in accordance with QC.25, in metric tons;

(3) the annual CO2, CH4 and N2O emissions attributable to the combustion of fuels in glass melting furnaces, calculated in accordance with QC.1, in metric tons;

(4) the annual CO2, CH4 and N2O emissions attributable to the use of fixed combustion units, except glass melting furnaces, calculated in accordance with QC.1, in metric tons;

(5) the annual consumption of each carbonate-containing raw material used in a furnace, in metric tons;

(6) the average annual carbonate content of each carbonate-based raw material used in a furnace, in metric tons of carbonate per metric ton of raw material;

(7) the calcination fraction of the carbonates contained in raw materials, in metric tons of carbonate obtained per metric ton of carbonate in the raw material;

(8) the annual quantity of glass produced, in metric tons;

(9) the number of times that the methods for estimating missing data in QC.26.5 were used;

(10) 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 2, in metric tons CO2 equivalent;

(b) the annual combustion emissions corresponding to the total of the emissions referred to in subparagraphs 3 and 4, in metric tons CO2 equivalent.

Subparagraphs 2, 3, 5, 6 and 7 of the first paragraph do not apply to the CO2 emissions of an emitter who calculates emissions using data from a continuous emission monitoring and recording system.

QC.26.3. Calculation methods for annual CO2 emissions

For each glass melting furnace, the annual CO2 emissions attributable to glass production must be calculated using one of the calculation methods in QC.26.3.1 and QC.26.3.2.

QC.26.3.1. Use of a continuous emission monitoring and recording system

The annual CO2 emissions may be calculated using data from a continuous emission monitoring and recording system in accordance with QC.1.3.4.

QC.26.3.2. Calculation method for annual CO2 emissions

The annual CO2 emissions attributable to the use of carbonate-containing raw materials may be calculated using equation 26-1:

Equation 26-1

Where:

CO2 = Annual CO2 emissions attributable to the use of carbonate-containing raw materials for glass production in all glass melting furnaces, in metric tons;

n = Number of glass melting furnaces;

i = Glass melting furnace;

CO2,i = Annual CO2 emissions attributable to the use of carbonate-containing raw materials for glass production in glass melting furnace i, calculated in accordance with QC.25.3.2, in metric tons.

QC.26.4. Sampling, analysis ans measurement requirements

An emitter who operates a facility or establishment that produces glass must determine annually, in accordance with QC.25.4,

(1) the average carbonate content of each raw material, or use the value 1.0;

(2) the calcination fraction of each carbonate, or use the value 1.0;

(3) the quantity of each carbonate-containing raw material.

QC.26.5. Methods for estimating missing data

When 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 monthly quantity of carbonate-based raw materials, the missing data must be estimated using all the data relating to the processes used or the data used for inventory purposes;

(3) when the missing data concerns the carbonate content of carbonate-based raw materials, the replacement value must be the value 1.0.

QC.27. MOBILE EQUIPMENT

QC.27.1. Covered sources

The covered sources are all mobile equipment used at a facility or establishment for the on-site transportation or movement of substances, materials or products, and any other mobile equipment such as tractors, mobile cranes, log transfer equipment, mining machinery, graders, backhoes and bulldozers, and other mobile industrial equipment. All mobile equipment used by subcontractors for the purposes of activities under the operational control of the facility or establishment is also covered.

Vehicles used for activities that are not directly or indirectly connected with production, such as lawn maintenance and snow clearing vehicles, as well as road vehicles within the meaning of the Highway Safety Code (c. C-24.2), aircraft and ships, are excluded.

QC.27.2. 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 the combustion of fossil fuels and biomass fuels, in metric tons, specifying, by fuel type,

(a) CO2 emissions;

(b) CH4 emissions;

(c) N2O emissions;

(2) annual and quarterly consumption of each fuel type, in litres.

QC.27.3. Calculation methods for CO2 emissions

The annual CO2 emissions attributable to mobile equipment must be calculated in accordance with the calculation methods in QC.27.3.1 to QC.27.3.3.

For mixtures of biomass fuels and fossil fuels, the CO2 emissions attributable to the biomass fuel portion and to the fossil fuel portion must be calculated separately.

QC.27.3.1. Calculation method for CO2 emissions based on the quantity of fuel used

When the quantity of fuel used is known, the annual CO2 emissions attributable to mobile equipment used on-site at a facility or establishment must be calculated using equation 27-1:

Equation 27-1

Where:

CO2 = Annual CO2 emissions attributable to each fuel type used by the mobile equipment, in metric tons;

i = Quarter;

Fueli = Volume of fuel used by the mobile equipment during quarter i, in litres;

EF = CO2 emission factor for the fuel as specified in Table 1-2 in QC.1.7 or Table 27-1 in QC.27.6, in kilograms per litre;

0.001 = Conversion factor, kilograms to metric tons.

QC.27.3.2. Calculation method for CO2 emissions based on operating conditions of the mobile equipment

When the quantity of fuel used cannot be determined, the annual CO2 emissions attributable to mobile equipment used on-site at a facility or establishment must be calculated using equation 27-2:

Equation 27-2

Where:

CO2 = Annual CO2 emissions attributable to each fuel type used by the mobile equipment, in metric tons;

i = Quarter;

n = Number of mobile equipment units;

j = Mobile equipment;

Hj = Quarterly hours of operation of mobile equipment j, in hours;

Pj = Rated power of mobile equipment j, in kilowatts;

LFj = Load factor for mobile equipment j, determined by the emitter;

SFCj = Specific consumption of each fuel type by mobile equipment j, in litres per kilowatt-hour;

EF = CO2 emission factor for the fuel, as specified in Table 1-2 in QC.1.7 or Table 27-1 in QC.27.6, in kilograms per litre;

0.001 = Conversion factor, kilograms to metric tons.

QC.27.3.3. Calculation method for CO2 emissions based on emission factors determined by the emitter according to operating conditions

When the quantity of fuel used cannot be determined and the information needed to calculate CO2 emissions using the method in QC.27.3.2 is not available, the annual CO2 emissions attributable to mobile equipment used on-site at a facility or establishment must be calculated using equation 27-3:

Equation 27-3

Where:

CO2 = Annual CO2 emissions attributable to mobile equipment, in metric tons;

n = Number of mobile equipment operating conditions;

j = Operating condition;

Hj = Annual hours of use of mobile equipment in operating condition j, in hours;

AFCj = Average fuel consumption of mobile equipment in operating condition j, in litres per hour;

EFj = CO2 emission factor for mobile equipment operating condition j, determined by the emitter, in kilograms per litre;

0.001 = Conversion factor, kilograms to metric tons.

QC.27.4. Calculation methods for CH4 and N2O emissions

The annual CH4 and N2O emissions attributable to mobile equipment must be calculated using the calculation methods in QC.27.4.1 to QC.27.4.3.

For mixtures of biomass fuels and fossil fuels, the CH4 and N2O emissions attributable to the biomass fuel portion and to the fossil fuel portion must be calculated separately.

QC.27.4.1. Calculation method for annual CH4 and N2O emissions based on the quantity of fuel consumed

When the quantity of fuel is known, the annual CH4 and N2O emissions attributable to mobile equipment used on-site at a facility or establishment must be calculated using equation 27-4:

Equation 27-4

Where:

CH4 or N2O = Annual CH4 or N2O emissions attributable to each fuel type used by the mobile equipment, in metric tons;

i = Quarter;

Fueli = Volume of fuel used by mobile equipment during quarter i, in litres;

EF = CH4 or N2O emission factor for the fuel, as specified in Table 1-3 in QC.1.7 or Table 27-1 in QC.27.6, in grams per litre;

0.000001 = Conversion factor, grams to metric tons.

QC.27.4.2. Calculation method for CH4 and N2O emissions based on use of the mobile equipment

When the quantity of fuel used cannot be determined, the annual CH4 and N2O emissions attributable to mobile equipment used on-site at a facility or establishment must be calculated using equation 27-5:

Equation 27-5

Where:

CH4 or N2O = Annual CH4 or N2O emissions attributable to each fuel type used by the mobile equipment, in metric tons;

i = Quarter;

n = Number of mobile equipment units;

j = Mobile equipment;

Hj = Quarterly hours of operation of mobile equipment j, in hours;

Pj = Rated power of mobile equipment j, in kilowatts;

LFj = Load factor for mobile equipment j, determined by the emitter;

SFCj = Specific consumption of each fuel type by mobile equipment j, in litres per kilowatt-hour;

EF = CH4 or N2O emission factor for the fuel, as specified in Table 1-3 in QC.1.7 or Table 27-1 in QC.27.6, in grams per litre;

0.000001 = Conversion factor, grams to metric tons.

QC.27.4.3. Calculation method for CH4 or N2O emissions based on emission factors determined by the emitter according to operating conditions

When the quantity of fuel used cannot be determined and the information needed to calculate CH4 or N2O emissions using the method in QC.27.4.2 is not available, the annual CH4 or N2O emissions attributable to mobile equipment used on-site at a facility or establishment must be calculated using equation 27-6:

Equation 27-6

Where:

CH4 or N2O = Annual CH4 or N2O emissions attributable to mobile equipment, in metric tons;

n = Number of mobile equipment operating conditions;

j = Operating condition;

Hj = Annual hours of use of mobile equipment in operating condition j, in hours;

AFCj = Average fuel consumption of mobile equipment in operating condition j, in litres per hour;

EFj = CH4 or N2O emission factor for mobile equipment operating condition j, determined by the emitter, in kilograms per litre;

0.001 = Conversion factor, kilograms to metric tons.

QC.27.5. Sampling, analysis and measurement requirements

An emitter who uses mobile equipment on-site at a facility or establishment must

(1) for a mixture of biomass fuels and fossil fuels, determine during each delivery the portion of biomass fuels and the portion of fossil fuels based on the data indicated by the supplier;

(2) determine quarterly the volumes of fuel used, using the same plant instruments as those used for inventory purposes, such as purchase invoices or a gauge reading for each unit of mobile equipment;

(3) determine annually the operating conditions during which mobile equipment is used when the calculation methods in QC.27.3.3 and QC.27.4.3 are used.

QC.27.6. Tables

Table 27-1. Emission factors by fuel type

(QC.27.3.1, QC.27.3.2, QC.27.3.3, QC.27.4.1, QC.27.4.2)

 _________________________________________________________________________________
|                                       |             |             |             |
|  Mobile equipment                     |     CO2     |     CH4      |     N20     |
|                                       |    (kg/L)   |    (g/L)    |    (g/L)    |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| Light-duty gasoline vehicle           |             |             |             |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| - tier 1                              |    2.289    |    0.12     |    0.16     |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| - tier 0                              |    2.289    |    0.32     |    0.66     |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| - oxidation catalyst                  |    2.289    |    0.52     |    0.20     |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| - non-catalytic controlled            |    2.289    |    0.46     |    0.028    |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| Light-duty gasoline truck             |             |             |             |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| - tier 1                              |    2.289    |    0.13     |    0.25     |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| - tier 0                              |    2.289    |    0.21     |    0.66     |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| - oxidation catalyst                  |    2.289    |    0.43     |    0.20     |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| - non-catalytic controlled            |    2.289    |    0.56     |    0.028    |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| Heavy-duty gasoline vehicle           |             |             |             |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| - 3-way catalyst                      |    2.289    |    0.068    |    0.20     |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| - non-catalytic controlled            |    2.289    |    0.29     |    0.047    | 
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| - uncontrolled                        |    2.289    |    0.49     |    0.084    |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| Light-duty diesel vehicle             |             |             |             |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| - advance control                     |    2.663    |    0.051    |    0.22     | 
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| - moderate control                    |    2.663    |    0.068    |    0.21     |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| - uncontrolled                        |    2.663    |    0.10     |    0.16     |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| Light-duty diesel truck               |             |             |             |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| - advance control                     |    2.663    |    0.068    |    0.22     |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| - moderate control                    |    2.663    |    0.068    |    0.21     |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| - uncontrolled                        |    2.663    |    0.085    |    0.16     |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| Heavy-duty diesel vehicle             |             |             |             |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| - advance control                     |    2.663    |    0.12     |    0.082    |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| - moderate control                    |    2.663    |    0.14     |    0.082    |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| - uncontrolled                        |    2.663    |    0.15     |    0.075    |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| Natural gas vehicle                   |    0.00189  |    0.009    |    0.00006  |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| Propane vehicle                       |    1.510    |    0.64     |    0.028    |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| Off-road gasoline                     |    2.289    |    2.7      |    0.05     |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| Off-road diesel                       |    2.663    |    0.15     |    1.1      |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| Diesel train                          |    2.663    |    0.15     |    1.1      | 
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| Biodiesel vehicle                     |    2.449    |    -1       |    -1        |
|_______________________________________|_____________|_____________|_____________|
|                                       |             |             |             |
| Ethanol vehicle                       |    1.494    |    -2       |    -2        |
|_______________________________________|_____________|_____________|_____________|
|                                                                                 |
| 1 Diesel CH4 and N2O emission factors (by vehicle type) are used for biodiesel.  |   
|                                                                                 |
| 2 Gasoline CH4 and N2O emission factors (by vehicle type) are used for ethanol.  |
|_________________________________________________________________________________|                                                                                                                                                                                                                                                                        

QC.28. ELECTRONICS MANUFACTURING

QC.28.1. Covered sources

The covered sources are all facilities or establishments that manufacture semiconductors, liquid crystal displays, micro-electro-mechanical systems and photovoltaic cells. The following manufacturing processes are also targeted:

(1) plasma etching, in other words the process in which plasma-generated fluorine atoms and other reactive fluorine-containing fragments chemically react with exposed thin-films constituted of dielectric materials and metals, and in contact with silicon;

(2) the periodical cleaning of the chambers used for depositing thin films using plasma-generated fluorine atoms and other reactive fluorine-containing fragments from fluorinated and other gases;

(3) the cleaning of semiconductor wafers using plasma-generated fluorine atoms or other reactive fluorine-containing fragments to remove residual material from wafer surfaces;

(4) the transformation of fluorinated compounds, in other words the process by which fluorinated compounds can be transformed into different fluorinated compounds which are then exhausted, unless abated, into the atmosphere;

(5) chemical vapour deposition processes or any other electronics manufacturing processes using N2O;

(6) equipment cooling, in other words the process in which fluorinated gases are used as heat transfer fluids to cool process equipment, control temperature during device testing, and solder semiconductor devices to circuit boards.

QC.28.2. Greenhouse gas reporting requirements

The greenhouse gas emissions report referred to in section 6.2 must include the following information:

(1) the annual greenhouse gas emissions attributable to electronics manufacturing processes, in metric tons;

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

(3) the greenhouse gas calculations methods used pursuant to QC.28.3;

(4) production in terms of substrate surface area, such as silica, photovoltaic cells and liquid crystal displays, in square metres;

(5) the emission factors used to determine process utilization and by-product formation rates and the source for each factor;

(6) a description of each calculation method used, when different from the methods in QC.28.3;

(7) the annual consumption of each greenhouse gas and the quantity of gas remaining in the container after use, in metric tons;

(8) the apportioning factors for the production processes, in other words the quantity of each gas fed into each individual process used;

(9) a description of the engineering model used to apportion the consumption of fluorinated bases;

(10) the annual consumption of each greenhouse gas, calculated in accordance with the method used to determine the apportioning factors when that method allows an estimate that is independent of the estimate obtained using equation 28-6 in QC.28.3.4, in metric tons;

(11) the data used to calculate the mass balance of each greenhouse gas for any heat transfer fluid used, using equation 28-5 provided for in QC.28.3.3;

(12) the annual greenhouse gas emissions for each type of emissions, namely:

(a) the annual greenhouse gas emissions attributable to combustion, corresponding to the total emissions referred to in paragraph 2, in metric tons CO2 equivalent;

(b) the annual greenhouse gas emissions in the “other” category, corresponding to the total emissions referred to in paragraph 1, in metric tons CO2 equivalent.

QC.28.3. Greenhouse gas calculation methods

The annual greenhouse gas emissions attributable to all electronics manufacturing processes must be calculated using equation 28-1:

Equation 28-1

Where:

GHG = Annual greenhouse gas emissions attributable to all electronics manufacturing processes, in metric tons;

n = Total number of input gases;

i = Type of input gas;

GHGP,j = Annual greenhouse gas emissions of input gas i from individual process or process category j, calculated in accordance with QC.28.3.1, in metric tons;

GHGB,i = Annual emissions of by-product gas formed from input gas i during individual process or process category j, calculated in accordance with QC.28.3.1, in metric tons;

GHGTF,i = Annual greenhouse gas emissions attributable to the use of heat transfer fluid i, calculated in accordance with QC.28.3.3, in metric tons;

N2O = Annual N2O emissions attributable to each electronics manufacturing process, calculated in accordance with QC.28.3.2, in metric tons;

j = Individual process or process category.

QC.28.3.1. Calculation method for fluorinated gas emissions

The annual fluorinated gas emissions attributable to all electronics manufacturing processes must be calculated using equations 28-2 and 28-3 and in accordance with the second paragraph.

Equation 28-2

Where:

GHGP,j = Annual greenhouse gas emissions of input gas i from individual process or process category j, in metric tons;

m = Total number of individual processes or process categories;

j = Individual process or process category;

Cj = Consumption of input gas i in individual process or process category j, calculated using equation 28-6 and apportioned in accordance with QC.28.4.2, in kilograms;

Uj = Process utilization for input gas i during individual process or process category j;

aj = Volumetric fraction of input gas i used in individual process or process category j with antipollution systems, in percentage expressed in the form of a decimal;

dj = Volumetric fraction of input gas i destroyed by the antipollution system connected to individual process or process category j, during process use time, determined in accordance with paragraph 2 of QC.28.4.4, in percentage expressed in the form of a decimal, or a default value of 0;

0.001 = Conversion factor, kilograms to metric tons;

i = Input gas;

Equation 28-3

Where:

GHGD,i = Annual emissions of by-product gas k formed from input gas i during individual process or process category j, in metric tons;

m = Total number of individual processes or process categories;

j = Individual process or process category;

p = Total number of by-product gases;

k = By-product gas;

Pjk = Rate of production of by-product gas k from consumption of input gas i during individual process or process category j;

Cj = Consumption of input gas i during process j, calculated using equation 28-6 and apportioned in accordance with QC.28.4.2, in kilograms;

aj = Volumetric fraction of input gas i used in individual process or process category j with antipollution systems, in percentage expressed in the form of a decimal;

djk = Volumetric fraction of input gas i destroyed by the antipollution system connected to individual process or process category j, during process use time, determined in accordance with paragraph 2 of QC.28.4.4, in percentage expressed in the form of a decimal, or a default value of 0;

0.001 = Conversion factor, kilograms to metric tons;

i = Input gas.

For the purpose of calculating emissions, the emitter must determine the rate of use of the input gas during the individual process or process category and the rate of production of the by-product gas from consumption of the input gas during the individual process or process category using the following methods:

(1) for a facility that manufactures semiconductors on wafers 300 mm or less in diameter:

(a) using the rates indicated in Tables 28-1, 28-2 and 28-3 in QC.28.6;

(b) by measuring the rates in accordance with QC.28.4.3;

(2) for a facility that manufactures semiconductors on wafers measuring more than 300 mm in diameter, by measuring the rates in accordance with QC.28.4.3;

(3) for all other electronics manufacturing facilities, using the rates indicated in Tables 28-4, 28-5 and 28-6 in QC.28.6.

QC.28.3.2. Calculation method for N2O emissions

The annual N2O emissions attributable to all electronics manufacturing processes must be calculated using equation 28-4 and in accordance with the second paragraph.

Equation 28-4

Where:

N2O = Annual emissions of N2O attributable to each electronics manufacturing process, in metric tons;

m = Total number of processes used;

j = Type of process used;

Cj = Consumption of N2O during process j, calculated using equation 28-6 and apportioned to N2O-using process j, in kilograms;

Uj = Rate of utilization of N2O during process j;

aj = Volumetric fraction of N2O used in N2O-using process j with an antipollution system, in percentage expressed in the form of a decimal;

dj = Volumetric fraction of N2O destroyed by the antipollution systems connected to process j, during process use time, determined in accordance with paragraph 2 of QC.28.4.4, or a default value of 0;

0.001 = Conversion factor, kilograms to metric tons.

For the purpose of calculating emissions, the emitter must:

(1) determine the N2O utilization rate by measuring it in accordance with QC.28.4.3 or, when the rate cannot be measured, using a default value of 20% for chemical vapour deposition processes and a value of 0% for all other manufacturing processes;

(2) for a facility equipped with antipollution systems, calculate the reduction in N2O emissions attributable to the use of such systems, in accordance with QC.28.4.4.

QC.28.3.3. Calculation method for fluorinated gas emissions attributable to heat transfer fluids

The annual fluorinated gas emissions attributable to the use of each heat transfer fluid must be calculated using equation 28-5:

Equation 28-5

Where:

GHGHT,i = Annual greenhouse gas emissions attributable to the use of heat transfer fluid i, in metric tons;

pi = Density of heat transfer fluid i, in kilograms per litre;

ID,i = Quantity of heat transfer fluid i in inventory in containers at the beginning of the year, in litres;

IF,i = Quantity of heat transfer fluid i in inventory in containers at the end of the year, in litres;

NCR,i = Total nameplate capacity of equipment that uses heat transfer fluid i and that is removed from the facility during the year, in litres;

NCN,i = Total nameplate capacity of equipment that uses heat transfer fluid i and that is newly installed during the year, in litres;

TFA,i = Quantity of heat transfer fluid i acquired during the year, including amounts obtained from chemical suppliers and equipment suppliers and amounts of fluid returned to the facility after recycling, in litres;

TFT,i = Quantity of heat transfer fluid i transferred or sold during the year, including amounts returned to chemical suppliers, sent off-site for recycling or destroyed, in litres;

0.001 = Conversion factor, kilograms to metric tons;

i = Heat transfer fluid.

QC.28.3.4. Calculation method for the consumption of fluorinated gases and N2O

The annual consumption of fluorinated gases and N2O used in electronics manufacturing processes must be calculated in accordance with QC.28.4.1 using equations 28-6 and 28-7:

Equation 28-6

Ci = (IDi − IFi + Ai − Si) × 0.001

Where:

Ci = Annual consumption of input gas i, in metric tons;

IDi = Quantity of gas i in inventory in all containers at the beginning of the year, including heels, in kilograms;

IFi = Quantity of gas i in inventory in all containers at the end of the year, including heels, in kilograms;

Ai = Quantity of gas i acquired during the year, including heels in containers returned to the establishment or facility, in kilograms;

Si = Quantity of gas i sold or transferred during the year, including heels in containers returned to the gas supplier, calculated using equation 28-7, in kilograms;

0.001 = Conversion factor, kilograms to metric tons;

i = Input gas;

Equation 28-7

Where:

Si = Quantity of gas i sold or transferred during the year, including heels in containers returned to the gas supplier, in kilograms;

q = Total number of types of container;

l = Type of container;

fi,l = Fraction of gas i remaining in container of type l, determined in accordance with QC.28.4.1;

Ni,l = Number of containers of type l returned to the gas supplier containing the heel of gas i calculated in accordance with paragraph 2 of QC.28.4.1;

NCi,l = Total nameplate capacity of containers of type l containing gas i, in kilograms;

Xi = Any other quantity of gas i sold or transferred during the year, calculated in accordance with paragraph 3 of QC.28.4.1, in kilograms;

i = Gas sold or transferred.

QC.28.4. Sampling, analysis and measurement requirements

QC.28.4.1. Determination of gas heel remaining in a container

An emitter operating an electronics manufacturing facility or establishment must determine the gas heel remaining in a container, for each type of gas and type of container, using the following methods:

(1) by determining the fraction of gas heel remaining in a container using equation 28-8:

Equation 28-8

Where:

fi,j = Gas heel i remaining in a container of type j;

wr,i = Residual weight of gas i, calculated in accordance with paragraph 2, in grams;

minitial,i = Initial mass of gas i, determined by measuring or based on the weight of the gas indicated by the supplier, in grams;

(2) by measuring the residual weight or pressure of a container when replacing it and, when the pressure is measured, by determining the residual weight using equation 28-9:

Equation 28-9

       Mi × pi × Vi
Wr,i = _____________
       Zi × R × Ti
                                                                                                                                                                                                                

Where:

wr,i = Residual weight of gas i, in grams;

Mi = Molar weight of gas i, in grams per mole;

pi = Absolute pressure of gas i, in pascals;

Vi = Volume of gas i, in cubic metres;

Zi = Compressibility factor of gas i;

R = Perfect gas constant of 8.314 joules per kelvin-mole;

Ti = Absolute temperature of gas i, in kelvins;

(3) if a container is replaced when the residual weight or pressure of the gas is over 20% higher than the weight or pressure used to calculate the gas heel remaining in the container, by weighing the container or by measuring the pressure using a pressure gauge and using either value to replace the gas heel calculated previously;

(4) by recalculating the gas heel remaining in the container calculated previously when the residual weight or pressure of gas determined when the container is replaced differs by more than 1% from the initial value used to calculate the gas heel remaining in the container.

QC.28.4.2. Apportionment of the consumption of fluorinated gases by process category

The emitter must apportion the consumption of fluorinated gases by process category, as defined in the tables in QC.28.6, or by individual process, using an engineering model based on the number of wafer passes.

QC.28.4.3. Determination of the utilization rates for fluorinated gases and N2O and the formation rates for by-product gases

The utilization rates for fluorinated gases and N2O and the formation rates for by-product gases determined by the emitter or by the equipment manufacturer must comply with the “International SEMATECH Manufacturing Initiative’s Guideline for Environmental Characterization of Semiconductor Process Equipment – Revision 2”.

QC.28.4.4. Calculation of N2O emissions reductions attributable to the use of an antipollution system

An emitter who calculates reductions in fluorinated gases and N2O emissions attributable to the use of an antipollution system must

(1) ensure that the antipollution system is designed to reduce fluorinated gas and N2O emissions and is installed, operated and maintained according to the manufacturer’s instructions, and keep the certification;

(2) determine the time of use of the antipollution system when using an destruction factor to calculate the reduction in fluorinated gas and N2O emissions, and calculate the use factor by adding together the system’s operational productive, standby, and stoppage times and dividing the result by the total operations time of its associated manufacturing equipment, in accordance with SEMI E-10-0304E “Specification for Definition and Measurement of Equipment Reliability, Availability, and Maintainability” published by the Semiconductor Equipment and Materials International (SEMI);

(3) use a default destruction factor of 60%, or determine the destruction factor using the following methods:

(a) in accordance with EPA 430-R-10-003 “Protocol for Measuring Destruction or Removal Efficiency of Fluorinated Greenhouse Gas Abatement Equipment in Electronics Manufacturing” published by the U.S. Environmental Protection Agency (USEPA);

(b) by selecting annually a random sample of antipollution systems and measuring their destruction factor using the following methods:

i. the random sample must come from 3 antipollution systems or 20% of the total number of installed antipollution systems, whichever is greater, for each category of antipollution system. When the percentage does not equate to a whole number, it must be rounded up to the nearest whole number;

ii. all the antipollution systems in each category must be subject to a random sampling at least once every 5 years;

(c) for each antipollution system whose destruction factor has been measured during the previous 2 years, by calculating the reduction in emissions using that factor;

(d) for each antipollution system whose destruction factor has not been measured during the previous 2 years, by using the average destruction factor of the systems in the same category;

(e) when an emergency antipollution system is utilized, the utilization time may be included in the total utilization time for the antipollution systems, calculated annually.

QC.28.4.5. Instrument calibration and accuracy

The emitter must calibrate all the instruments used to determine the concentration of fluorinated gases and N2O in process streams immediately before measuring the destruction factor, gas utilization factor for the process, or by-product gas formation factor. The calibration must be based on representative samples with known concentrations, for which the fractions by mass of the same gases are similar to those of the process samples. The emitter may also use high-concentration fluorinated gases or N2O certified representative samples using a gas dilution system that meets the requirements specified in Method 205, 40 CFR part 51, Appendix M of the Code of Federal Regulations “Verification of Gas Dilution Systems for Field Instrument Calibrations”.

When the emitter uses flow meters, weigh scales, pressure gauges or thermometers, their minimum accuracy must be 1% of full scale.

QC.28.5. Methods for estimating missing data

When one or more values used to calculate the fluorinated gas emissions attributable to heat transfer fluids using equation 28-5 are missing, the emitter must estimate greenhouse gas emissions using the arithmetic average of the emissions rates for the previous year and for 2 months following the missing data period. When those emission rates cannot be obtained, the emitter must estimate the greenhouse gas emissions using data from the suppliers of the heat transfer fluids.

QC.28.6. Tables

Table 28-1. Default greenhouse gas emission factors for fluorinated compounds for process categories for semiconductor manufacturing for 150 mm wafer size

(QC.28.3.1, QC.28.4.2)

Table 28-2. Default greenhouse gas emission factors for fluorinated compounds for process categories for semiconductor manufacturing for 200 mm wafer size

(QC.28.3.1, QC.28.4.2)

Table 28-3. Default emission factors for process categories for semiconductor manufacturing for semiconductor manufacturing for 300 mm wafer size

(QC.28.3.1, QC.28.4.2)

Table 28-4. Default emission factors for micro-electrical-mechanical systems manufacturing

(QC.28.3.1, QC.28.4.2)

Table 28-5. Default emission factors for LCD screen manufacturing

(QC.28.3.1, QC.28.4.2)

Table 28-6. Default emission factors for photovoltaic cell manufacturing

(QC.28.3.1, QC.28.4.2)

QC.29. NATURAL GAS TRANSMISSION AND DISTRIBUTION

QC.29.1. Covered sources

The covered sources are the processes and equipment used for the transmission and distribution of natural gas:

(1) onshore natural gas transmission compression, which includes any stationary combination of compressors that move natural gas at elevated pressure from production fields or natural gas processing facilities in transmission pipelines to natural gas distribution pipelines or into storage, and any equipment required for liquids separation, natural gas dehydration, and tanks for the storage of water and hydrocarbon liquids;

(2) underground natural gas storage, which includes depleted gas or oil reservoirs and salt dome caverns that store natural gas that has been transferred from its original location for the primary purpose of load balancing, natural gas underground storage processes and operations, including compression, dehydration and flow measurement, and all the wellheads connected to the compression units that inject and recover natural gas into and from the underground reservoirs;

(3) liquefied natural gas (LNG) storage, which includes LNG storage vessels located above ground, equipment for liquefying natural gas, compressors to capture and re-liquefy boil-off-gas, and vaporization units for re-gasification of the liquefied natural gas;

(4) LNG import and export equipment, which includes, in the case of LNG import equipment, all onshore or offshore equipment that receives imported LNG via ocean transport, stores LNG, re-gasifies LNG, and delivers re-gasified natural gas to a natural gas transmission or distribution system and, in the case of LNG export equipment, all onshore or offshore equipment that receives natural gas, liquefies natural gas, stores LNG, and transfers the LNG via ocean transportation to its destination;

(5) natural gas transmission pipelines, which include high pressure pipelines and associated equipment transporting sellable quality natural gas from production or natural gas processing to natural gas distribution stations before delivery to customers;

(6) natural gas distribution, which includes all natural gas equipment downstream of the station yard inlet shut-off valves of natural gas transmission pipelines at stations where pressure reduction and/or measuring first occurs for eventual delivery of natural gas to consumers.

QC.29.2. Greenhouse gas reporting requirements

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, CH4 and N2O emissions attributable to the use of stationary combustion equipment, calculated in accordance with QC.1, in metric tons;

(3) the annual CO2, CH4 and N2O emissions attributable to the compression of natural gas for onshore pipeline transmission, in metric tons, specifying:

(a) compressor venting, including:

i. emissions from natural gas pneumatic high bleed devices and pumps, calculated in accordance with QC.29.3.1;

ii. emissions from natural gas low bleed and intermittent bleed devices, calculated in accordance with QC.29.3.2;

iii. emissions from blowdown vent stacks, calculated in accordance with QC.29.3.3;

iv. emissions from centrifugal compressors, calculated in accordance with QC.29.3.5;

v. emissions from reciprocating compressors, calculated in accordance with QC.29.3.6;

vi. emissions from other fugitive emissions or venting emissions sources, calculated in accordance with QC.29.3.9;

(b) annual fugitive CO2 and CH4 emissions from compressor equipment, such as valves, connectors, open ended lines, pressure relief valves and meters, calculated in accordance with QC.29.3.7;

(c) annual CO2, CH4 and N2O emissions from compressor station flaring, calculated in accordance with QC.29.3.4;

(d) other annual fugitive CO2 and CH4 emissions from compressor stations, calculated in accordance with QC.29.3.9;

(e) annual fugitive CO2 and CH4 emissions from pipeline above ground meters and regulators at custody transfer gate stations, and fugitive equipment leaks from connectors, block valves, control valves, pressure relief valves, orifice meters, regulators, and open ended lines, calculated in accordance with QC.29.3.7;

(f) annual fugitive CO2 and CH4 emissions from above ground meters and regulators at non-custody transfer gate stations, including station equipment leaks, calculated in accordance with QC.29.3.8, but excluding fugitive emissions from customer meters;

(g) annual CO2, CH4 and N2O emissions from pipeline flaring, calculated in accordance with QC.29.3.4;

(h) annual fugitive CO2 and CH4 emissions from below ground meters and regulators, calculated in accordance with QC.29.3.8;

(i) other annual fugitive CO2 and CH4 emissions from the pipeline system not covered in subparagraphs e to h, including third party hits, farm taps, tubing systems less than 2.54 cm diameter and customer meter sets, calculated in accordance with QC.29.3.9;

(j) annual CO2 and CH4 emissions other than pipeline venting emissions, calculated in accordance with QC.29.3.9;

(k) annual CO2, and CH4 emissions from natural gas transmission storage tanks, calculated in accordance with QC.29.3.9;

(4) the annual CO2, CH4 and N2O emissions from underground natural gas storage, in metric tons, specifying:

(a) annual emissions from venting, including:

i. emissions from natural gas pneumatic continuous high bleed devices and pumps, calculated in accordance with QC.29.3.1;

ii. emissions from pneumatic low bleed and intermittent bleed devices, calculated in accordance with QC.29.3.2;

iii. emissions from centrifugal compressors, calculated in accordance with QC.29.3.5;

iv. emissions from reciprocating compressors, calculated in accordance with QC.29.3.6;

v. fugitive emissions from other sources, calculated in accordance with QC.29.3.9;

(b) annual fugitive CO2 and CH4 emissions from equipment components such as valves, connectors, open ended lines, pressure relief valves and meters, calculated in accordance with QC.29.3.7 or QC.29.3.8;

(c) annual CO2, CH4 and N2O emissions from flares, calculated in accordance with QC.29.3.4;

(d) fugitive emissions from other sources, calculated in accordance with QC.29.3.9;

(5) annual CO2, CH4 and N2O emissions from LNG storage, in metric tons, specifying:

(a) venting emissions, including:

i. emissions from centrifugal compressors, calculated in accordance with QC.29.3.5;

ii. emissions from reciprocating compressors, calculated in accordance with QC.29.3.6;

iii. emissions from other venting sources, calculated in accordance with QC.29.3.9;

(b) annual fugitive CO2 and CH4 emissions from equipment components, such as valves, pump seals, connectors and vapour recovery compressors, calculated in accordance with QC.29.3.7 or QC.29.3.8;

(c) annual CO2, CH4 and N2O emissions from flares, calculated in accordance with QC.29.3.4;

(d) fugitive emissions from other emissions sources, calculated in accordance with QC.29.3.9;

(6) annual CO2, CH4 and N2O emissions from LNG import and export equipment, in metric tons, specifying:

(a) venting emissions, including:

i. emissions from blowdown vent stacks, calculated in accordance with QC.29.3.3;

ii. emissions from centrifugal compressors, calculated in accordance with QC.29.3.5;

iii. emissions from reciprocating compressors, calculated in accordance with QC.29.3.6;

iv. emissions from other venting sources, calculated in accordance with QC.29.3.9;

(b) annual fugitive CO2 and CH4 emissions from equipment components, such as valves, pump seals, connectors and vapour recovery compressors, calculated in accordance with QC.29.3.7 or QC.29.3.8;

(c) annual CO2, CH4 and N2O emissions from flares, calculated in accordance with QC.29.3.4;

(d) fugitive emissions from other emissions sources, calculated in accordance with QC.29.3.9;

(7) annual CO2, CH4 and N2O emissions attributable to natural gas distribution, in metric tons, specifying:

(a) annual CO2 and CH4 fugitive emissions from above ground meters and regulators at custody transfer gate stations, including leaks from station equipment such as connectors, block valves, control valves, pressure relief valves, orifice meters, regulators and open ended lines, calculated in accordance with QC.29.3.7, but excluding fugitive emissions from customer meters;

(b) annual CO2 and CH4 fugitive emissions from above ground meters and regulators at non-custody transfer gate stations, including station equipment leaks, calculated in accordance with QC.29.3.8, but excluding fugitive emissions from customer meters;

(c) annual fugitive CO2 and CH4 emissions from below ground meters and regulators and other underground station equipment, calculated in accordance with QC.29.3.8;

(d) annual fugitive CO2 and CH4 emissions from transmission system equipment, calculated in accordance with QC.29.3.8;

(e) annual fugitive CO2 and CH4 emissions from distribution system equipment, calculated in accordance with QC.29.3.8;

(f) annual CO2, CH4 and N2O emissions from transmission and distribution system flares, calculated in accordance with QC.29.3.4;

(g) emissions from other venting sources, calculated in accordance with QC.29.3.9;

(h) other annual CO2 and CH4 fugitive missions from pipelines, including emissions attributable to third party hits, farm taps, tubing systems less than 2.54 cm diameter, and customer meter sets, calculated in accordance with QC.29.3.9;

(8) annual CO2, CH4 and N2O emissions attributable to the use of portable combustion equipment, calculated using the methods for stationary combustion equipment in QC.1, in metric tons;

(9) the following data for each emissions source in subparagraphs 3 to 7:

(a) the number of natural gas pneumatic devices used by type, namely high bleed, low bleed and intermittent bleed;

(b) the number of natural gas driven pneumatic pumps;

(c) total pipeline length, in kilometres;

(d) if glycol dehydrators are used, the number of dehydrators, specifying

i. the number of dehydrators with a capacity of less than 11,328 m3 per day at standard conditions;

ii. the number of dehydrators with a capacity greater than 11,328 m3 per day at standard conditions;

(e) if dehydrators other than glycol hydrators are used, the number of dehydrators used;

(f) for each compressor used:

i. compressor type;

ii. compressor capacity in horsepower;

iii. number of blowdowns per year;

iv. operating mode during the year, as determined in QC.29.4.6;

(g) when the calculation methods in QC.29.3.7 and QC.29.3.8 are used:

i. the component count for each source for which an emission factor is provided in Tables 29-1 to 29-5 in QC.29.6;

ii. the total number of leaks found in annual leak detection surveys by type of leak for which an emission factor is provided;

(h) for natural gas distribution:

i. the number of custody transfer gate stations;

ii. the number of non-custody transfer gate stations;

(10) the number of times that the methods for estimating missing data provided for in QC.29.5 were used;

(11) total emissions of greenhouse gas for each type of emissions, namely,

(a) annual greenhouse gas emissions attributable to combustion corresponding to the emissions referred to in paragraphs 2 and 8, in metric tons CO2 equivalent;

(b) annual greenhouse gas emissions of the “other” category corresponding to the total of the emissions referred to in paragraphs 3 to 7, in metric tons CO2 equivalent.

Emissions attributable to venting or other sources of fugitive emissions referred to in subparagraph vi of subparagraph a and subparagraphs d, i, j and k of subparagraph 3, subparagraph v of subparagraph a and subparagraph d of subparagraph 4, subparagraph iii of subparagraph a and subparagraph d of subparagraph 5, subparagraph iv of subparagraph a and subparagraph d of subparagraph 6 and subparagraphs g and h of subparagraph 7 of the first paragraph are not required to be reported if the emissions from that source are below 0.5% of the emitter’s total emissions and total emissions not reported under this paragraph do not exceed 1% of the emitter’s total emissions.

QC.29.3. Calculation methods for CO2, CH4 and N2O emissions

The annual CO2, CH4 and N2O emissions attributable to natural gas transmission and distribution must be calculated in accordance with one of the calculation methods in QC.29.3.1 to QC.29.3.9.

When no calculation method for an emissions source, the emitter must use industry inventory practices.

QC.29.3.1. Calculation of CO2 and CH4 emissions attributable to high bleed pneumatic device venting and natural gas driven pneumatic pump venting

The annual CO2 and CH4 emissions attributable to high bleed pneumatic device venting and natural gas driven pneumatic pump venting must be calculated in accordance with equations 29-1 to 29-4:

Equation 29-1

GHGi = GHGdv,i + GHGpv,i

Where:

GHGi = Emissions of greenhouse gas i attributable to high bleed pneumatic device venting and pneumatic pump venting, in metric tons;

GHGdv,i = Emissions of greenhouse gas i attributable to high bleed pneumatic device venting, calculated using equation 29-2 or 29-3, in metric tons;

GHGpv,i = Emissions of greenhouse gas i attributable to pneumatic pump venting, calculated using equation 29-4, in metric tons;

i = CO2 or CH4;

Equation 29-2

                     MWi
GHGdv,i = VNG × MFi × ____ × 0.001
                    MVC 
                                                                                                                                                              

Where:

GHGdv,i = Emissions of greenhouse gas i attributable to high bleed pneumatic device venting, in metric tons;

VNG = Annual volume of natural gas consumed by high bleed pneumatic devices, determined in accordance with paragraph 1 of QC.29.4.1, in cubic metres at standard conditions;

MFi = Mole fraction of gas i in natural gas, determined in accordance with paragraph 3 of QC.29.4;

MWi = Molecular weight of gas i, in kilograms per kilomole;

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

0.001 = Conversion factor, kilograms to metric tons;

i = CO2 or CH4;

Equation 29-3

Where:

GHGev,i = Emissions of greenhouse gas i attributable to high bleed pneumatic device venting, in metric tons;

n = Total number of high bleed pneumatic devices;

j = High bleed pneumatic device;

Fj = Natural gas flow for pneumatic device j, determined in accordance with paragraph 2 of QC.29.4.1, in cubic metres per minute at standard conditions;

tj = Annual operating time for pneumatic device j, in minutes;

MFi = Mole fraction of greenhouse gas i in natural gas, determined in accordance with paragraph 3 of QC.29.4;

Pi = Density of greenhouse gas i that is 1.893 kg per cubic metre for CO2 and 0.690 kg per cubic metre for CH4 at standard conditions;

0.001 = Conversion factor, kilograms to metric tons;

i = CO2 or CH4;

Equation 29-4

Where:

GHGPV,i = Emissions of greenhouse gas i attributable to pneumatic pump venting, in metric tons;

m = Total number of pneumatic pumps;

k = Pneumatic pump;

QNG,k = Quantity of natural gas consumed by pneumatic pump k, determined in accordance with paragraph 3 of QC.29.4.1, in cubic metres per litre of liquid pumped at standard conditions;

Vk = Annual volume of liquid pumped, in litres;

MFi = Mole fraction of greenhouse gas i in natural gas, determined in accordance with paragraph 3 of QC.29.4;

Pi = Density of greenhouse gas i that is 1.893 kg per cubic metre for CO2 and 0.690 kg per cubic metre for CH4 at standard conditions;

0.001 = Conversion factor, kilograms to metric tons;

i = CO2 or CH4.

QC.29.3.2. Calculation of CO2 and CH4 emissions attributable to low bleed or intermittent bleed natural gas pneumatic device venting

The annual CO2 and CH4 emissions attributable to low bleed or intermittent bleed natural gas pneumatic device venting must be calculated separately using equation 29-5:

Equation 29-5

Where:

GHGi = Annual emissions of greenhouse gas i attributable to low bleed or intermittent bleed natural gas pneumatic device venting, in metric tons;

j = Type of low bleed or intermittent bleed natural gas pneumatic device;

Nj = Number of pneumatic devices j determined in accordance with QC.29.4.2;

EFj = Emission factor for pneumatic device j as specified in Tables 29-1 and 29-2 in QC.29.6, in cubic metres per hour;

tj = Annual operating time for pneumatic device j, in hours;

Pi = Density of greenhouse gas i, of 1.893 kg per cubic metre for CO2 and 0.690 kg per cubic metre for CH4 at standard conditions;

0.001 = Conversion factor, kilograms to metric tons;

i = CO2 or CH4.

QC.29.3.3. Calculation of CO2 and CH4 emissions attributable to natural gas emissions to the atmosphere from equipment blowdown vent stacks

The CO2 and CH4 emissions attributable natural gas emissions to the atmosphere from equipment blowdown vent stacks, except equipment depressurizing to a flare, over-pressure relief and operating pressure control venting, must be calculated using equation 29-6:

Equation 29-6

Where:

GHGi = Emissions of greenhouse gas i attributable to natural gas emissions to the atmosphere from equipment blowdown vent stacks, in metric tons;

n = Total number of types of equipment;

j = Type of equipment with the same gas volume in the blowdown equipment chambers between isolation valves;

Nj = Annual number of blowdowns for each equipment type j, determined in accordance with QC.29.4.3;

Vj = Total volume of gas in blowdown equipment chambers, between isolation valves, for equipment type j, determined in accordance with QC.29.4.3, in cubic metres;

TSC = Temperature at standard conditions of 293.15 K;

TB = Temperature at blowdown conditions, in kelvin;

PB = Pressure at blowdown conditions, in kilopascals;

PSC = Pressure at standard conditions of 101.325 kP;

PFj = Purge factor that is 1 if the equipment of type j is not purged or 0 if the equipment of type j is purged using a gas other than a greenhouse gas;

MFi = Mole fraction of greenhouse gas i in natural gas, determined in accordance with paragraph 3 of QC.29.4;

Pi = Density of greenhouse gas i, of 1.893 kg per cubic metre for CO2 and 0.690 kg per cubic metre for CH4 at standard conditions;

0.001 = Conversion factor, kilograms to metric tons;

i = CO2 or CH4.

QC.29.3.4. Calculation of CO2, CH4 and N2O emissions attributable to flares

Annual CO2, CH4 and N2O emissions attributable to flares must be calculated in accordance with the following methods:

(1) annual CO2 emissions attributable to flares must be calculated using equation 29-7:

Equation 29-7

Where:

CO2 = Annual CO2 emissions attributable to flares, in metric tons;

VG = Annual volume of gas directed to flares, determined in accordance with QC.29.4.4, in cubic metres;

MFCO2 = Mole fraction of CO2 in the gas directed to flares, determined in accordance with QC.29.4.4;

m = Total number of hydrocarbon gas constituents;

k = Hydrocarbon gas constituent;

MFk = Mole fraction of hydrocarbon gas constituent k, determined in accordance with QC.29.4.4;

CAk = Number of carbon atoms in hydrocarbon gas constituent k, that is 1 for methane, 2 for ethane, 3 for propane, 4 for butane and 5 for pentanes plus;

efft = Flare combustion efficiency from manufacturer or a default value of 0.98;

TSC = Temperature at standard conditions of 293.15 K;

Tt = Temperature during flaring, in kelvin;

Pt = Pressure during flaring, in kilopascals;

PSC = Pressure at standard conditions of 101.325 kPa;

PCO2 = Density of CO2, of 1.893 kg per cubic metre at standard conditions;

0.001 = Conversion factor, kilograms to metric tons;

(2) annual CH4 emissions attributable to flares must be calculated using equation 29-8:

Equation 29-8

Where:

CH4 = Annual CH4 emissions attributable to flares, in metric tons;

VG = Annual volume of gas directed to flares, determined in accordance with QC.29.4.4, in cubic metres;

MFCH4 = Mole fraction of CH4 in the gas directed to flares, determined in accordance with QC.29.4.4;

efft = Flare combustion efficiency from manufacturer or a default value of 0.98;

TSC = Temperature at standard conditions of 293.15 K;

Tt = Temperature during flaring, in kelvin;

Pt = Pressure during flaring, in kilopascals;

PSC = Pressure at standard conditions of 101.325 kPa;

pCH4 = Density of CH4 of 0.690 kg per cubic metre at standard conditions;

0.001 = Conversion factor, kilograms to metric tons;

(3) annual N2O emissions attributable to flares must be calculated using equation 29-9:

Equation 29-9

N2O = VG × HHV × EFN2O × 0.001

Where:

N2O = Annual N2O emissions attributable to flares, in metric tons;

VG = Annual volume of gas directed to flares, determined in accordance with QC.29.4.4, in cubic metres;

HHV = High heat value of gas as specified in Tables 1-1 and 1-2 in QC.1.7 or high heat value of 4.579 x 10-2 GJ per cubic metre for gas emissions from equipment venting or determined in accordance with QC.1.5.4, in gigajoules per cubic metre;

EFN2O = Emission factor for N2O of 9.52 × 10-5 kg per gigajoule;

0.001 = Conversion factor, kilograms to metric tons.

QC.29.3.5. Calculation of CO2 and CH4 emissions attributable to centrifugal compressor venting

The annual CO2 and CH4 emissions attributable to centrifugal compressor venting must be calculated in accordance with the following methods:

(1) for each centrifugal compressor, the emitter must determine, in accordance with AC.29.4.5, the volume of vapours from a wet seal oil degassing tank sent to an atmospheric vent and the volume of gas sent to a flare;

(2) the annual CO2 and CH4 emissions attributable to centrifugal compressor vapours sent to an atmospheric vent must be calculated using equation 29-10:

Equation 29-10

Where:

GHGi = Annual greenhouse gas i emissions attributable to atmospheric centrifugal compressor vents, in metric tons;

n = Total number of centrifugal compressors;

j = Centrifugal compressor;

FG,i = Gas flow from the atmospheric vent of centrifugal compressor j determined in accordance with QC.29.4.5, in cubic metres per hour;

tj = Annual operating time of centrifugal compressor j equipped with a wet seal oil degassing tank, in hours;

FGj = Quantity of the gas from the atmospheric vent of centrifugal compressor j that is recovered using a vapour recovery system or destined for another use, determined in accordance with QC.29.4.5, expressed in percentage;

MFi = Mole fraction of greenhouse gas i in the gas from atmospheric vents, determined in accordance with paragraph 3 of QC.29.4;

TSC = Temperature at standard conditions of 293.15 K;

Tcc = Temperature at the atmospheric vent of the centrifugal compressor, in kelvin;

Pcc = Pression at the atmospheric vent of the centrifugal compressor, in kilopascals;

PSC = Pressure at standard conditions of 101.325 kPa;

Pi = Density of greenhouse gas i, of 1.893 kg per cubic metre for CO2 and 0.690 kg per cubic metre for CH4 at standard conditions;

0.001 = Conversion factor, kilograms in metric tons;

i = CO2 or CH4.

(3) the annual CO2 and CH4 emissions attributable to gas sent to a flare must be calculated in accordance with the calculation methods in QC.29.3.4.

QC.29.3.6. Calculation of CO2 and CH4 emissions attributable to reciprocating compressor venting

The annual CO2 and CH4 emissions attributable to reciprocating compressor vents must be calculated using equation 29-11, except emissions attributable to gas sent to a common flare, which must be calculated in accordance with QC.29.3.4:

Equation 29-11

Where:

GHGi = Annual greenhouse gas i attributable to reciprocating compressor vents, in metric tons;

n = Total number of reciprocating compressors;

j = Reciprocating compressor;

FG,i = Gas flow from the vent of reciprocating compressor j determined in accordance with QC.29.4.6, in cubic metres per hour;

tj = Annual operating time of reciprocating compressor j in the mode determined in QC.29.4.6, in hours;

FGj = Quantity of gas from the vent of reciprocating compressor j that is recovered using a vapour recovery system, determined in accordance with paragraph 4 of QC.29.4.5, expressed in percentage;

MFi = Mole fraction of greenhouse gas i in the gas from reciprocating compressor vents, determined in accordance with paragraph 3 of QC.29.4;

TSC = Temperature at standard conditions of 293.15 K;

Tca = Temperature at the reciprocating compressor vent, in kelvin;

Pca = Pressure at the reciprocating compressor vent, in kilopascals;

PSC = Pressure at standard conditions of 101.325 kPa;

Pi = Density of greenhouse gas i, of 1.893 kg per cubic metre for CO2 and 0.690 kg per cubic metre for CH4 at standard conditions;

0.001 = Conversion factor, kilograms in metric tons;

i = CO2 or CH4.

QC.29.3.7. Calculation of the CO2 and CH4 emissions attributable to leaks identified following a leak detection survey

Except for emissions from emissions sources for which the total weight of CO2 and CH4 in the natural gas is below 10%, which do not have to be calculated, and emission leaks from pipelines with a diameter of 1.27 cm or less, which must be calculated in accordance with QC.29.3.9, the annual fugitive CO2 and CH4 emissions attributable to leaks identified following a leak detection survey must be calculated in accordance with the following methods:

(1) the leak detection survey must be carried out in accordance with paragraph 2 of QC.29.4 for each of the following sources:

(a) fugitive emissions from equipment components during:

i. underground natural gas storage;

ii. liquid natural gas storage;

iii. liquid natural gas imports and exports;

(b) fugitive emissions leaks from compressor components during the compression of natural gas for onshore pipeline transmission;

(c) fugitive emissions from above ground meters and regulators at custody transfer gate stations during

i. the compression of natural gas for onshore pipeline transmission;

ii. natural gas distribution;

(2) for each source where leaks have been detected, the fugitive emissions must be calculated using equation 29-12 or 29-13, depending on the unit of the leaker emission factor used:

Equation 29-12

Where:

GHGi = Annual greenhouse gas i, for each source of fugitive emissions, in metric tons;

n = Total number of component types, for each source of fugitive emissions;

j = Component type;

Nj = Total number of components for each component type j;

EFj = Emission factor for leaks from component type j, determined in accordance with QC.29.4.7, in cubic metres per hour;

tj = Time during which component type j was leaking, determined in accordance with QC.29.4.7, in hours;

Ci = Concentration in natural gas of greenhouse gas i, of 0.011 for CO2 and 1 for CH4;

Pi = Density of greenhouse gas i, of 1.893 kg per cubic metre for CO2 and 0.690 kg per cubic metre for CH4 at standard conditions;

0.001 = Conversion factor, kilograms to metric tons;

i = CO2 or CH4;

Equation 29-13

Where:

GHGi = Annual greenhouse gas i, for each source of fugitive emissions, in metric tons;

n = Total number of component types, for each source of fugitive emissions;

j = Component type;

Nj = Total number of components for each component type j;

EFj = Emission factor for leaks from component type j, determined in accordance with QC.29.4.7, in metric tons per hour;

tj = Time during which component type j was leaking, determined in accordance with QC.29.4.7, in hours;

Ci = Concentration in natural gas of greenhouse gas i, determined in accordance with QC.29.4.7;

i = CO2 or CH4.

QC.29.3.8. Calculation of fugitive CO2 and CH4 emissions attributable to population count and emission factors (all components)

Except for emissions from emissions sources for which the total weight of CO2 and CH4 in the natural gas is below 10% that do not have to be calculated and emission leaks from pipelines with a diameter of 1.27 cm or less, which must be calculated in accordance with QC.29.3.9, the annual fugitive CO2 and CH4 emissions attributable to all components must be calculated in accordance with the following methods:

(1) the annual fugitive emissions must be calculated for each of the following sources:

(a) fugitive emissions from equipment components during:

i. underground natural gas storage;

ii. liquid natural gas storage;

iii. imports and exports of liquid natural gas;

(b) fugitive emissions from above grade meters and regulators at non-custody transfer gate stations during:

i. the compression of natural gas for onshore pipeline transmission;

ii. natural gas distribution;

(c) fugitive emissions from below grade meters and regulators during:

i. the compression of natural gas for onshore pipeline transmission;

ii. natural gas distribution;

(d) fugitive emissions from transmission system and distribution system equipment.

(2) the annual fugitive emissions must be calculated using equation 29-14 or 29-15, depending on the emission factor used:

Equation 29-14

Where:

GHGi = Annual greenhouse gas i, for each source of fugitive emissions, in metric tons;

n = Total number of component types, for each source of fugitive emissions;

j = Component type;

Nj = Total number of components for each component type j, determined in accordance with QC.29.4.8;

EFj = Emission factor for component type j, determined in accordance with QC.29.4.8, in cubic metres per hour;

tj = Time during which component type j, associated with fugitive emissions, was operational, in hours;

Ci = Concentration in natural gas of greenhouse gas i, of 0.011 for CO2 and 1 for CH4;

Pi = Density of greenhouse gas i, of 1.893 kg per cubic metre for CO2 and 0.690 kg per cubic metre for CH4 at standard conditions;

0.001 = Conversion factor, kilograms to metric tons;

i = CO2 or CH4;

Equation 29-15

Where:

GHGi = Annual greenhouse gas i, for each source of fugitive emissions, in metric tons;

n = Total number of component types, for each source of fugitive emissions;

j = Component type;

Nj = Total number of components for each component type j;

EFj = Emission factor component type j, determined in accordance with QC.29.4.8, in metric tons per hour;

tj = Time during which component type j, associated with fugitive emissions, was operational, in hours;

Ci = Concentration in natural gas of greenhouse gas i, determined in accordance with QC.29.4.8;

i = CO2 or CH4.

QC.29.3.9. Calculation of other fugitive emissions sources

Emissions from fugitive emissions sources that are not calcuated using the methods in QC.29.3.1 to QC.29.3.8 must be calculated in accordance with the following methods:

(1) the methods in the most recent edition of “Methodology Manual: Estimation of Air Emissions from the Canadian Natural Gas Transmission, Storage and Distribution System” published by Clearstone Engineering Ltd.;

(2) a sector-specific method published by the Canadian Gas Association.

QC.29.4. Sampling, analysis and measurement requirements

An emitter who operates a natural gas transmission and distribution enterprise must

(1) ensure that all instruments used for sampling, analysis and measurement are calibrated before the first emissions report and annually thereafter, and operate in accordance with the manufacturer’s instructions or in accordance with the methods published by the following organizations:

(a) Canadian Standards Association;

(b) Canadian Gas Association;

(c) Canadian Association of Petroleum Producers;

(d) American National Standards Institute;

(e) American Society of Testing and Materials;

(f) American Petroleum Institute;

(g) American Society of Mechanical Engineers;

(h) North American Energy Standards Board;

(i) Canadian Energy Pipeline Association;

(j) Measurement Canada;

(2) conduct leak detection surveys and manage transmission and distribution system integrity in accordance with CSA Z662-11 “Oil and gas pipeline systems” published by the Canadian Standards Association in June 2011 and in accordance with the Construction Code (c. B-1.1, r. 2);

(3) determine the mole fraction of CO2 and CH4 in natural gas by calculating the annual average of the following mole fractions:

(a) the mole fraction in natural gas during compression for onshore pipeline transmission;

(b) the mole fraction in natural gas in underground storage facilities;

(c) the mole fraction in natural gas in liquid natural gas storage facilities;

(d) the mole fraction in natural gas in liquid natural gas import and export facilities;

(e) the mole fraction in natural gas for distribution through the system.

QC.29.4.1. High bleed pneumatic device venting and natural gas driven pneumatic pump venting

For high bleed pneumatic device venting and natural gas driven pneumatic pump venting, the emitter must

(1) when using equation 29-2, determine the annual volume of natural gas consumed by high bleed pneumatic devices using statistical data, which must be developed using representative samples of all the high bleed pneumatic devices and revised at least every 3 years;

(2) when using equation 29-3, obtain from the device manufacturer the natural gas flow for each high bleed pneumatic device during normal operating conditions or, when the data are not available, use the flow from a similar device;

(3) when using equation 29-4:

(a) obtain from the manufacturer the quantity of natural gas consumed by volume of liquid pumped for each pneumatic pump model in normal operating conditions or, when the data are not available, use data from a similar device;

(b) keep a log of the quantity of liquid pumped annually by each pneumatic pump.

QC.29.4.2. Natural gas low bleed or intermittent bleed pneumatic device venting

For low bleed or intermittent bleed natural gas pneumatic device venting, the emitter must determine the number of natural gas low bleed pneumatic devices and the number of natural gas intermittent bleed pneumatic devices in the following manner:

(1) for the first emission report year, by counting all the devices according to type or estimating the total number of devices and apportion that number according to the estimated percentage of each type of device;

(2) for subsequent years, by updating the number of low bleed pneumatic devices and the number of intermittent bleed pneumatic devices to take annual changes into account.

QC.29.4.3. Equipment blowdown vent stacks

For equipment blowdown vent stacks, the emitter must

(1) calculate the volume of gas in blowdown equipment chambers, between isolation valves, for each equipment type;

(2) if the volume is greater than or equal to 1.42 m3 at standard conditions, log the annual number of blowdowns for each equipment type;

(3) calculate the total volume of gas for which the volume in the blowdown equipment chamber, between isolation valves, is the same.

QC.29.4.4. Flares

For flares, the emitter must

(1) determine the volume of gas directed to flares, using one of the following methods:

(a) using the volumetric gas flow when the flare is equipped with a continuous flow monitoring and recording system or, when part of the gas is not measured by such a system, estimating the unmeasured gas flow must be estimated using a sector-recognized method;

(b) using a sector-recognized method;

(2) determine the gas composition using one of the following methods:

(a) using a continuous gas composition monitoring and recording system;

(b) when the flare is not equipped with a continuous gas composition monitoring and recording system, by determining, using a sector-recognized method:

i. the mole fraction of CO2 and CH4 in the gas when the stream going to the flare is natural gas;

ii. the mole fraction of the methane, ethane, propane, butane and pentane-plus when the stream going to the flare is a hydrocarbon product stream.

QC.29.4.5. Centrifugal compressors venting

For centrifugal compressors, the emitter must

(1) determine the volume of gas from a wet seal oil degassing tank sent to an atmospheric vent or the volume of gas sent to a flare, using a temporary or permanent flow meter;

(2) when a centrifugal compressor is used for peaking purposes and is not equipped with a flow meter, determine the volume of gas using data from flow meters installed on similar devices;

(3) calibrate the flow meters in accordance with the methods in paragraph 1 of QC.29.4;

(4) determine the quantity of the gas that is recovered using a vapour recovery system or destined for another use, expressed in percentage, based on the number of hours of operation of the recovery system and the quantity of gas sent to the fuel gas system.

QC.29.4.6. Reciprocating compressors venting

For reciprocating compressors, the emitter must

(1) determine the gas flow from reciprocating compressor venting using the following methods:

(a) if the reciprocating rod packing and blowdown vent is connected to an open ended vent line, the emitter must use one of the following methods to calculate the gas flow:

i. measuring the flow from all vents, including gas manifolded to common vents, using calibrated bagging in accordance with paragraph 3 or a high volume sampler in accordance with paragraph 4;

ii. measuring the flow from all vents, including gas manifolded to common vents, using a temporary or permanent flow meter in accordance with the methods in paragraph 1 of QC.29.4. In the absence of a permanent flow meter, a port for the insertion of a temporary or permanent flow meter may be installed on the vents;

iii. for through-valve leakage to open ended vents, such as unit isolation valves on not operating, depressurized compressors and blowdown valves on pressurized compressors, using an acoustic detection device in accordance with paragraph 2 of QC.29.4;

(b) when the compressor rod packing case is not equipped with a vent line, the emitter must

i. detect equipment leaks in accordance with paragraph 2 of QC.29.4;

ii. measure the gas flow using calibrated bagging in accordance with paragraph 3, a high volume sampler in accordance with paragraph 4 or a flow meter in accordance with paragraph 1 of QC.29.4;

(2) measure annually the gas flow from rod packing vents, isolation valve vents and reciprocating compressor vents, including gas manifolded to common vents, in the operating mode in which the compressor is used during the measurement period:

(a) the reciprocating compressor is in operating or standby pressurized mode and the gas emitted is from leaks in the blowdown vent stack;

(b) the reciprocating compressor is in operating mode and the gas emitted is from the rod packing;

(c) the compressor is in not operating, depressurized mode; the gas emitted is from isolation valve leakage through the blowdown vent stack. In that case,

i. a reciprocating compressor that is not equipped with blind flanges must be sampled at least once in every 3 consecutive years if no compressor is in this mode during the annual measurement period;

ii. flow measurement is not required when a reciprocating compressor is equipped with blind flanges for the entire 3 consecutive year period;

iii. if a reciprocating compressor is in standby, depressurized mode, is not equipped with blind flanges and is not used for a period of 3 consecutive years, it must be sampled in that mode;

(3) when using calibrated bags to measure the gas flow emitted by the reciprocating compressor vent, use the bags only where the emissions are at a pressure similar to atmospheric pressure and hydrogen sulphide levels are such that it is safe to handle. The calibrated bags must be used according to the manufacturer’s instructions and only if the entire emissions volume can be encompassed for measurement. The emitter must also

(a) record the time required to fill the bag and if the bag inflates in less than 1 second, the emitter must round up to 1 second;

(b) perform 3 measurements of the time required to fill the bag, and use the average of the measurements to calculate the gas flow;

(4) when using a high volume sampler, the measurements must be taken in accordance with the manufacturer’s instructions. The emitter must also calibrate the sampler, in accordance with the manufacturer’s instructions, at 2.5% CH4 with 97.5% air and 100% CH4 by using representative samples of known concentrations.

QC.29.4.7. Leaks identified following a detection survey

An emitter who conducts a leak detection survey must

(1) in the first emission reporting year, determine the leaker emission factor for leaks from each component type in accordance with the following methods:

(a) based on specific data for the operation of the enterprise’s devices and according to sector-specific methods;

(b) using the data in Tables 29-1 to 29-5 in QC.29.6 depending on the type of activity, namely:

i. for the compression of natural gas for onshore pipeline transmission, the emission factors shown in Table 29-1 for fugitive emissions from connectors, valves, pressure relief valves, meters and open ended lines;

ii. for underground natural gas storage, the emission factors shown in Table 29-2 for fugitive emissions from connectors, valves, pressure relief valves, meters and open ended lines;

iii. for liquefied natural gas storage, the emission factors shown in Table 29-3 for fugitive emissions from valves, pump seals, connectors and all other types of equipment components;

iv. for liquid natural gas imports and exports, the emission factors shown in Table 29-4 for fugitive emissions from valves, pump seals, connectors and all other types of equipment components;

v. for natural gas distribution, for above ground meters and regulators at custody transfer gate stations, the emission factors shown in Table 29-5 for fugitive emissions from connectors, block valves, control valves, pressure relief valves, orifice meters, regulators and open ended lines;

(2) in subsequent emission reporting years, determine the CO2 and CH4 concentrations in natural gas using one of the following methods:

(a) based on specific data for the operation of the enterprise’s devices;

(b) using the method specified in the most recent edition of “Methodology Manual: Estimation of Air Emissions from the Canadian Natural Gas Transmission, Storage and Distribution System” published by Clearstone Engineering Ltd.;

(3) determine the time during which a component was leaking, using the following methods:

(a) when one leak detection survey is conducted per year, the emitter must assume the component was leaking from the start of the year until the leak was repaired. If the leak was not repaired, the emitter must assume the component was leaking for the entire year;

(b) if multiple leak detection surveys are conducted per year, the emitter must assume that the component found to be leaking has been leaking since the previous survey. If the leak was directed during the previous survey, the emitter must assume the unrepaired component was leaking for the entire year.

QC.29.4.8. Fugitive emissions from population count and emission factors (all components)

For fugitive emissions from all components, the emitter must

(1) determine the total number of components for each component type using one of the following methods:

(a) the method in Appendix E of the most recent edition of “Methodology Manual: Estimation of Air Emissions from the Canadian Natural Gas Transmission, Storage and Distribution System” published by Clearstone Engineering Ltd.;

(b) a sector-specific method published by the Canadian Gas Association or Canadian Association of Petroleum Producers;

(c) using enterprise-specific data;

(2) for the first emission reporting year, use the emission factor for each component type depending on the type of activity, namely,

(a) for underground natural gas storage, the emission factors shown in Table 29-2 for fugitive emissions from connectors, valves, pressure relief valves, meters and open ended lines;

(b) for liquefied natural gas storage, the emission factors shown in Table 29-3 for fugitive emissions from vapour recovery compressors;

(c) for imports and exports of liquid natural gas, the emission factors shown in Table 29-4 for fugitive emissions from vapour recovery compressors;

(d) for natural gas distribution:

i. the emission factors shown in Table 29-5 for fugitive emissions from below grade meters and regulators;

ii. the emission factor calculated using equation 29-16 for above grade meters and regulators at non-custody transfer gate stations:

Equation 29-16

      GHGi
EFi = ____
       N                    

Where:

EFi = Enterprise-specific emission factor for above grade meters and regulators at non-custody transfer gate stations, in metric tons per component;

GHGi = Annual emissions of greenhouse gas i from leaks from above grade meters and regulators at custody transfer gate stations, calculated in accordance with equation 29-12, in metric tons;

N = Total number of components, namely above grade meters and regulators, at custody-transfer gate stations;

i = CH4 or CO2;

iii. the calculation of fugitive emissions from leaks from the main devices in the transmission and distribution systems may be changed to comply with the methods described in the most recent edition of “Methodology Manual: Estimation of Air Emissions from the Canadian Natural Gas Transmission, Storage and Distribution System” published by Clearstone Engineering Ltd.;

(3) in the subsequent emission reporting years, determine the emission factor from leaks from each type of component, in accordance with the following methods:

(a) based on data specific to the operation of the enterprise’s equipment and according to the sector-specific methods, in particular methods published by the Canadian Gas Association;

(b) by updating the emission factors at least every 3 years;

(c) when an emission factor specific to the operation of equipment cannot be determined, using the factors provided for in Tables 29-1 to 29-5 in accordance with paragraph 2;

(4) determine the CO2 and CH4 concentrations in natural gas in accordance with the methods in the most recent edition of “Methodology Manual: Estimation of Air Emissions from the Canadian Natural Gas Transmission, Storage and Distribution System” published by Clearstone Engineering Ltd.

QC.29.5. 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) the measurement or estimate of emissions for each source concerned must be repeated as soon as possible, either during the reporting year or during the following reporting year. In the latter case, the replacement data cannot be re-used to estimate emissions for that reporting year. In addition, at least 30 days must separate emissions estimation or measurements carried out for the previous year emissions and the estimation or measurements of emissions for the current year;

(2) when missing data are temperature, pressure or data estimated using a continuous monitoring and recording system, the replacement data must be estimated in accordance with sector-specific inventory practices.

QC.29.6 Tables

Table 29-1. Emission factors for total organic carbon in natural gas during compression for onshore transmission

(QC.29.3.2, QC.29.3.4(2), QC.29.4.7(1))

 _________________________________________________________________________________
|                                                                                 |
| Leaker emission factor by component type                                        | 
|_________________________________________________________________________________|
|                                                              |                  |
| Component type                                               |  Total organic   | 
|                                                              |  carbon (metric  |
|                                                              |  (tons/hour)     |
|______________________________________________________________|__________________|
|                                                              |                  |
| Connector                                                    |  4.471 × 10-7    |
|______________________________________________________________|__________________|
|                                                              |                  |
| Block valve                                                  |  4.131 × 10-6     |
|______________________________________________________________|__________________|
|                                                              |                  |
| Control valve                                                |  1.650 × 10-2     |
|______________________________________________________________|__________________|
|                                                              |                  |
| Compressor blowdown valve                                    |  3.405 × 10-3     |
|______________________________________________________________|__________________|
|                                                              |                  |
| Pressure relief valve                                        |  1.620 × 10-4     |
|______________________________________________________________|__________________|
|                                                              |                  |
| Orifice meter                                                |  4.863 × 10-5     |
|______________________________________________________________|__________________|
|                                                              |                  |
| Other meter                                                  |  9.942 × 10-6     |
|______________________________________________________________|__________________|
|                                                              |                  |
| Regulator                                                    |  7.945 × 10-6     |
|______________________________________________________________|__________________| 
|                                                              |                  |
| Open ended line                                              |  9.183 × 10-5     |
|______________________________________________________________|__________________|
|                                                                                 |
| Fugitive emission factors by component type                                     |
|_________________________________________________________________________________|
|                                                              |                  |
| Component type                                               |  Total organic   |
|                                                              |  carbon          |
|                                                              |  (m3/hour)       |
|______________________________________________________________|__________________|
|                                                              |                  |
| Low bleed pneumatic device                                   |  3.99 × 10-2      |
|______________________________________________________________|__________________|
|                                                              |                  |
| High bleed pneumatic device                                  |  5.32 × 10-1      |
|______________________________________________________________|__________________|
|                                                              |                  |
| Intermittent bleed pneumatic device                          |  5.32 × 10-1      | 
|______________________________________________________________|__________________|        

Table 29-2. Emission factors for total organic carbon in natural gas during underground storage

(QC.29.3.2, QC.29.3.4(2), QC.29.4.7(1), QC.29.4.8(2))

 _________________________________________________________________________________
|                                                              |                  |
| Component type                                               |  Total organic   | 
|                                                              |  oarbon          |
|                                                              |  (m3/hour)       |
|______________________________________________________________|__________________|
|                                                                                 |
| Leaker emission factor by component type                                        |
|_________________________________________________________________________________|
|                                                              |                  |
| Valve                                                        |  0.4265          |
|______________________________________________________________|__________________|
|                                                              |                  |
| Connector                                                    |  0.1600          |
|______________________________________________________________|__________________|
|                                                              |                  |
| Open ended line                                              |  0.4964          |
|______________________________________________________________|__________________|
|                                                              |                  |
| Pressure relief valve                                        |  1.1396          |
|______________________________________________________________|__________________|
|                                                              |                  |
| Meter                                                        |  0.5555          |
|______________________________________________________________|__________________|
|                                                                                 |
| Fugitive emission factors component type                                        |
|_________________________________________________________________________________|
|                                                              |                  |
| Connector                                                    |  2.83 × 10-4      |
|______________________________________________________________|__________________|
|                                                              |                  |
| Valve                                                        |  2.83 × 10-3      |
|______________________________________________________________|__________________|
|                                                              |                  |
| Pressure relief valve                                        |  4.81 × 10-3      |
|______________________________________________________________|__________________|
|                                                              |                  |
| Open ended line                                              |  8.49 × 10-4      |
|______________________________________________________________|__________________|
|                                                              |                  |
| Low bleed pneumatic device                                   |  3.99 × 10-2      |
|______________________________________________________________|__________________|
|                                                              |                  |
| High bleed pneumatic device                                  |  5.32 × 10 -1     |
|______________________________________________________________|__________________|
|                                                              |                  |
| Intermittent bleed pneumatic device                          |  5.32 × 10-1      |
|______________________________________________________________|__________________|
                                                                                          

Table 29-3. CH4 emission factors for liquefied natural gas storage

(QC.29.4.7(1), QC.29.4.8(2))

 _________________________________________________________________________________ 
|                                                              |                  |
| Component type                                               |  CH4             | 
|                                                              |  (m3/hour)       |
|______________________________________________________________|__________________|
|                                                                                 |
| Leaker emission factor by component type                                        |
|_________________________________________________________________________________|
|                                                              |                  |
| Valve                                                        |  3.42 × 10-2      |
|______________________________________________________________|__________________|
|                                                              |                  |
| Pump seal                                                    |  1.15 × 10-1      |
|_________________________________________________________________________________|
|                                                              |                  |
| Connector                                                    |  9.91 × 10-3      |
|______________________________________________________________|__________________|
|                                                              |                  |
| Other                                                        |  5.09 × 10-2      |
|______________________________________________________________|__________________|
|                                                                                 |
| Fugitive emission factors component type                                        |
|_________________________________________________________________________________|
|                                                              |                  |
| Vapor recovery compressor                                    |  1.20 × 10-1      |
|______________________________________________________________|__________________|    

Table 29-4. CH4 emission factors during imports and exports of liquid natural gas

(QC.29.4.7(1), QC.29.4.8(2))

 _________________________________________________________________________________ 
|                                                              |                  |
| Component type                                               |  CH4             | 
|                                                              |  (m3/hour)       |
|______________________________________________________________|__________________|
|                                                                                 |
| Leaker emission factor by component type                                        |
|_________________________________________________________________________________|
|                                                              |                  |
| Valve                                                        |  3.42 × 10-2      |
|______________________________________________________________|__________________|
|                                                              |                  |
| Pump seal                                                    |  1.15 × 10-1      |
|_________________________________________________________________________________|
|                                                              |                  |
| Connector                                                    |  9.90 × 10-3      |
|______________________________________________________________|__________________|
|                                                              |                  |
| Other                                                        |  5.09 × 10-2      |
|______________________________________________________________|__________________|
|                                                                                 |
| Fugitive emission factors component type                                        |
|_________________________________________________________________________________|
|                                                              |                  |
| Vapor recovery compressor                                    |  1.20 × 10-1      |
|______________________________________________________________|__________________|    

Table 29-5. Emission factors for total organic carbon and CH4 in natural gas during distribution

(QC.29.4.7(1), QC.29.4.8(2))

 _________________________________________________________________________________
|                                                                                 |
| Leaker emission factor by component type                                        | 
|_________________________________________________________________________________|
|                                                              |                  |
| Component type                                               |  Total organic   | 
|                                                              |  carbon (metric  |
|                                                              |  tons/hour)      |
|______________________________________________________________|__________________|
|                                                              |                  |
| Connector                                                    |  8.227 × 10-8     |
|______________________________________________________________|__________________|
|                                                              |                  |
| Block valve                                                  |  5.607 × 10-7     |
|______________________________________________________________|__________________|
|                                                              |                  |
| Control valve                                                |  1.949 × 10-5     |
|______________________________________________________________|__________________|
|                                                              |                  |
| Pressure relief valve                                        |  3.944 × 10-6     |
|______________________________________________________________|__________________|
|                                                              |                  |
| Orifice meter                                                |  3.011 × 10-6     |
|______________________________________________________________|__________________|
|                                                              |                  |
| Regulator                                                    |  6.549 × 10-7     |
|______________________________________________________________|__________________| 
|                                                              |                  |
| Open ended line                                              |  6.077 × 10-5     |
|______________________________________________________________|__________________|
|                                                                                 |
| Fugitive emission factors by component type                                     |
|_________________________________________________________________________________|
|                                                              |                  |
| Component type                                               |  CH4             | 
|                                                              |  (m3/hour)       |
|______________________________________________________________|__________________|
|                                                              |                  |
| Below ground meter and regulator, inlet pressure             |  3.74 × 10-2      |
| >300 psig                                                   |                  |
|______________________________________________________________|__________________|
|                                                              |                  |
| Below ground meter and regulator, inlet pressure             |  5.66 × 10-3      |
| 100 to 300 psig                                              |                  |
|______________________________________________________________|__________________|
|                                                              |                  |
| Below ground meter and regulator, inlet pressure <100 psig   |  2.83 × 10-3      |                   
|______________________________________________________________|__________________|
|                                                                                 |
| Fugitive emission factors by type of distribution pipeline                      |
|_________________________________________________________________________________|
|                                                              |                  |
| Type of pipeline                                             |  CH4             |
|                                                              |  (m3/hour)       |
|______________________________________________________________|__________________|
|                                                              |                  |
| Unprotected steel                                            |  1.83 × 10-1      |
|______________________________________________________________|__________________|
|                                                              |                  |
| Protected steel                                              |  7.22 × 10-2      |
|______________________________________________________________|__________________|
|                                                              |                  |
| Plastic                                                      |  7.75 × 10-2      |
|______________________________________________________________|__________________|
|                                                              |                  |
| Cast iron                                                    |  7.83 × 10-1      |
|______________________________________________________________|__________________|
|                                                                                 |
| Fugitive emission factors by type of distribution pipeline                      |
|_________________________________________________________________________________|
|                                                              |                  |
| Type of pipeline                                             |  CH4             |
|                                                              |  (m3/hour)       | 
|______________________________________________________________|__________________|
|                                                              |                  |
| Unprotected steel                                            |  7.08 × 10-2      |
|______________________________________________________________|__________________|
|                                                              |                  |
| Protected steel                                              |  3.25 × 10-2      |
|______________________________________________________________|__________________|
|                                                              |                  |
| Plastic                                                      |  1.05 × 10-2      |
|______________________________________________________________|__________________|
|                                                              |                  |
| Copper                                                       |  2.66 × 10-2      |
|______________________________________________________________|__________________|
      

M.O. 2010-12-06, Sch. A.2; M.O. 2011-12-16, s. 12.

SCHEDULE B

(ss. 4, 5)

REPORTING OF ANNUAL EMISSIONS, REPORT OF FUELS, PRODUCTS, RAW MATERIALS AND EMISSION FACTORS

Part I: Identification

Name of enterprise:

Name of establishment:

Address of establishment

          Civic number, street:
          ____________________________________________________________________

          City or Town:
          ____________________________________________________________________

          Postal Code:

Director of establishment

Name:

          Address (If different from establishment):

          Civic number, street:

          City or Town:

          Postal Code:

          Telephone number:

          Fax number:

          E-mail:

Person responsible for the environment
(If different from the director of the establishment)

Name:

          Address (If different from establishment)

              Civic number:

              Street:

              City or Town:

              Postal Code:

          Telephone number:

          Fax number:

          E-mail:

Person responsible for reporting
(If different from the person responsible for the environment)

Name:

          Address (If different from establishment):

              Civic number:

              Street:

              City or Town:

              Postal Code:

          Telephone number:

          Fax number:

          E-mail:
    

Part II: Annual emissions report

Types        Contaminants                         Total           Units of 
                                                  emissions       measure

             Total fluorides (TF)
Contaminants_________________________________________________________________
that cause
toxic        Polycyclic aromatic hydrocarbons 
pollution   (PAHs)
             _________________________________________________________________

             Total reduced sulphur compounds
    

Part III: Fuels, products and raw materials report

The operator must identify the activities, processes or equipment that are the source of contaminant emissions into the atmosphere.

Identification of emission source                Hours of operation
    

For each emission source identified, Tables A, B, C and D must be completed using the best data the operator of the enterprise, facility or establishment has, may reasonably be expected to have or may obtain by means of appropriate data processing.

Table A

                              Characteristics 
                        ______________________________

Identification of fuel      %       %       Heating       Quantity    Unit of
                          Sulphur  Water     value                     measure

    

Table B

Identification of               %Sulphur       Volume of           Unit of measure
product                                        production


                    

Table C

Identification   of  raw        %Sulphur       Quantity            Unit of measure
material        
         

Table D

Contaminant  Emission   Unit of   Product, raw material    Origin or emission
             factor     measure   or fuel related to       factor reference 
                                  the emission factor      used(3)
    

(3) For each contaminant emitted for which the operator takes into account an emission factor to quantify its emissions, the operator must indicate the origin of the emission factor and, if it comes from a published documentary source, indicate its reference.

M.O. 2007-09-26, Sch. B; M.O. 2010-12-06, s. 13.

TRANSITIONAL

2011

(M.O. 2011-12-16) SECTION 13. For 2012 emissions reports, despite section 6.3 of the Regulation respecting mandatory reporting of certain emissions of contaminants into the atmosphere (c. Q-2, r. 15), an emitter is not required to use the following methods prescribed in Schedule A.2:

(1) for the transportation and distribution of electricity and the use of equipment to produce electricity, the methods in QC.24;

(2) for mobile equipment, the methods in QC.27;

(3) for the transmission and distribution of natural gas, the methods in QC.29.3.1, QC.29.3.2, QC.29.3.7 and QC.29.3.8.

2010

(M.O. 2010) SECTION 14. For report year 2010, emitters must report their greenhouse gas emissions in accordance with the Regulation respecting mandatory reporting of certain emissions of contaminants into the atmosphere as it read on 29 December 2010.

SECTION 15. From report year 2011,

(1) despite the first paragraph of section 6.3 of the Regulation respecting mandatory reporting of certain emissions of contaminants into the atmosphere, introduced by section 8 of this Regulation, emitters are not required to use the calculation methods prescribed in QC.2 to QC.17 of Schedule A.2;

(2) sections 6.6 to 6.9 of the Regulation respecting mandatory reporting of certain emissions of contaminants into the atmosphere, introduced by section 8 of this Regulation, do not apply.

REFERENCES

M.O. 2007, 2007 G.O. 2, 2833

M.O. 2010, 2010 G.O. 2, 3862A

S.Q. 2010, c. 7, s. 282

S.Q. 2011, c. 20, s. 56

M.O. 2011-12-16, 2011 G.O. 2, 3756B