Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity: SOR/2018-261

Canada Gazette, Part II, Volume 152, Number 25

Registration

SOR/2018-261 November 30, 2018

CANADIAN ENVIRONMENTAL PROTECTION ACT, 1999

P.C. 2018-1482 November 29, 2018

Whereas, pursuant to subsection 332(1) footnote a of the Canadian Environmental Protection Act, 1999 footnote b, the Minister of the Environment published in the Canada Gazette, Part I, on February 17, 2018, a copy of the proposed Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity, substantially in the annexed form, and persons were given an opportunity to file comments with respect to the proposed Regulations or to file a notice of objection requesting that a board of review be established and stating the reasons for the objection;

Whereas, pursuant to subsection 93(3) of that Act, the National Advisory Committee has been given an opportunity to provide its advice under section 6 footnote c of that Act;

And whereas, in accordance with subsection 93(4) of that Act, the Governor in Council is of the opinion that the proposed Regulations do not regulate an aspect of a substance that is regulated by or under any other Act of Parliament in a manner that provides, in the opinion of the Governor in Council, sufficient protection to the environment and human health;

Therefore, Her Excellency the Governor General in Council, on the recommendation of the Minister of the Environment and the Minister of Health, pursuant to subsections 93(1) and 330(3.2) footnote d of the Canadian Environmental Protection Act, 1999 footnote b, makes the annexed Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity.

Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity

Overview

Purpose

1 These Regulations establish a regime for limiting carbon dioxide (CO2) emissions that result from the generation of electricity by means of thermal energy from the combustion of natural gas, whether in conjunction with other fuels, except coal, or not.

Interpretation

Definitions

2 (1) The following definitions apply in these Regulations.

Act means the Canadian Environmental Protection Act, 1999. (Loi)

API means the American Petroleum Institute. (API)

ASTM means ASTM International, formerly known as the American Society for Testing and Materials. (ASTM)

auditor means a person who

authorized official means

biomass means a fuel that consists only of non-fossilized, biodegradable organic material that originates from plants or animals but does not originate from a geological formation, and includes gases and liquids that are recovered from the decomposition of organic waste. (biomasse)

boiler unit means a unit that consists of at least one boiler but does not have a combustion engine. (groupe chaudière)

capacity means

combustion engine means an engine, other than an engine that is self-propelled or designed to be propelled while performing its function, that

combustion engine unit means a unit that consists of at least one combustion engine and, if applicable, a heat recovery system, but does not have a boiler. (groupe moteur à combustion)

continuous emission monitoring system or CEMS means equipment for the sampling, conditioning and analyzing of emissions from a given source and the recording of data related to those emissions. (système de mesure et d’enregistrement en continu des émissions ou SMECE)

facility means all buildings, other structures and equipment, whether the equipment is stationary or not, that are located on a single site or adjacent sites and that are operated as a single integrated site. (installation)

fossil fuel means a fuel other than biomass. (combustible fossile)

heat recovery system means equipment, other than a boiler, that extracts heat from a combustion engine’s exhaust gases in order to generate steam or hot water. (système de récupération de la chaleur)

heat to electricity ratio means, in respect of a unit, the total useful thermal energy production in a calendar year, expressed in GWh, divided by the total gross electricity generation in that calendar year, expressed in GWh. (rapport chaleur-électricité)

natural gas means a mixture of hydrocarbons — such as methane, ethane or propane — that is in a gaseous state at standard conditions and that is composed of at least 70% methane by volume or that has a higher heating value that is not less than 35 MJ/standard m3 and not more than 41 MJ/standard m3. It excludes landfill gas, digester gas, gas from wastewater treatment systems, refinery gas, sour gas, blast furnace gas, producer gas, coke oven gas, gas derived from petroleum coke or coal — including synthetic gas — or any gaseous fuel produced in a process that might result in highly variable sulphur content or heating value. (gaz naturel)

operator means a person who has the charge, management or control of a unit. (exploitant)

performance test verifier means a person who

potential electrical output means the quantity of electricity that would be generated by a unit in a calendar year if the unit were to operate at capacity at all times during that calendar year. (production potentielle d’électricité)

Reference Method means the document entitled Reference Method for Source Testing: Quantification of Carbon Dioxide Releases by Continuous Emission Monitoring Systems from Thermal Power Generation, June 2012, published by the Department of the Environment. (Méthode de référence)

responsible person means an owner or operator of a unit. (personne responsable)

standard conditions means a temperature of 15˚C and a pressure of 101.325 kPa. (conditions normales)

standard m3 means a volume expressed in cubic metres — at standard conditions. (m3 normalisé)

unit means an assembly comprised of a boiler or combustion engine and any other equipment that is physically connected to either, including duct burners and other combustion devices, heat recovery systems, steam turbines, generators and emission control devices and that operate together to generate electricity and, if applicable, produce useful thermal energy, from the combustion of natural gas. (groupe)

useful life, in respect of a boiler unit referred to in subsection 3(4), has the same meaning as in subsection 2(1) of the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations. (vie utile)

useful thermal energy means energy in the form of steam or hot water that is destined for a use — other than the generation of electricity — that would have required the consumption of energy in the form of fuel or electricity had that steam or hot water not been used. (énergie thermique utile)

Interpretation of documents incorporated by reference

(2) For the purposes of interpreting documents that are incorporated by reference into these Regulations, “should” must be read to mean “must” and any recommendation or suggestion must be read as an obligation.

Standards incorporated by reference

(3) Any standard of the ASTM, Gas Processors Association or the API that is incorporated by reference into these Regulations is incorporated as amended from time to time.

Application

New generation of electricity — boiler units

3 (1) These Regulations apply to any boiler unit that has a capacity of 25 MW or more, that begins generating electricity on or after January 1, 2019, beginning on January 1 of the calendar year during which it meets the following conditions:

New generation of electricity — combustion engine units

(2) These Regulations apply to any combustion engine unit that has a capacity of 25 MW or more, that begins generating electricity on or after January 1, 2021, beginning on January 1 of the calendar year during which it meets the following conditions:

Existing generation of electricity

(3) These Regulations also apply to any unit referred to in subsection (1) or (2) that generated electricity at a facility before January 1, 2019 in the case of a boiler unit and before January 1, 2021 in the case of a combustion engine unit and

Significantly modified — conversion to natural gas

(4) These Regulations also apply to any boiler unit referred to in subsection (1) that was registered under subsection 4(1) of the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations, and that generated electricity before January 1, 2019, beginning on January 1 of the calendar year following that in which the unit ceases to combust coal.

Hybrid configuration

(5) If a combustion engine unit and a boiler unit share the same steam turbine, the provisions of these Regulations apply as follows:

Non-application

(6) These Regulations do not apply to units with respect to a calendar year in which they generate electricity and, if applicable, produce useful thermal energy from the combustion of coal as defined in subsection 2(1) of the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations.

Requirements

Emission Intensity Limits

General

4 (1) A responsible person for a unit must not emit from the unit an amount of CO2 from the combustion of fossil fuels in the unit, that is, during a calendar year, on average, greater than any of the following intensity limits, as applicable:

Significantly modified boiler units

(2) It is prohibited for a responsible person for a boiler unit referred to in subsection 3(4) to emit from the boiler unit an amount of CO2, from the combustion of fossil fuels in the unit, that is, during a calendar year, on average, greater than 420 tonnes of CO2 emissions/GWh of energy produced, as applicable, beginning in

Quantification of energy and emissions

(3) For the purposes of subsections (1) and (2),

Special Rules

(4) For the purposes of subsection (3), if, in the calendar year, one of the combustion engines of the unit is repaired or maintained and one or more replacement combustion engines are temporarily installed, the quantity of energy and CO2 emissions produced during the replacement period, to a maximum of 90 days per calendar year, are excluded from the calculation referred to in that paragraph.

Exception — boiler unit

(5) Despite subsection (1), a boiler unit that, in a calendar year, does not meet one of the conditions set out in subsection 3(1), is not subject to the emission intensity limit for that calendar year.

Exception — combustion engine

(6) Despite subsection (1), a combustion engine unit that, in a calendar year, does not meet one of the conditions set out in subsection 3(2), is not subject to the emission intensity limit for that calendar year.

Performance Tests — Significantly Modified Boiler Units

Initial performance test

5 (1) An initial performance test must be conducted in the presence of the performance test verifier and in accordance with subsection (3) to determine the CO2 emission intensity for a boiler unit referred to in subsection 3(4) within 12 months following

Annual performance test

(2) Performance tests are to be subsequently conducted annually to determine the CO2 emission intensity for the boiler unit in question, in accordance with subsection (3), for as long as the responsible person for that boiler unit does not have to meet the emission limit referred to in subsection 4(2).

Conditions — test

(3) The initial and annual performance test must consist of a continuous test that lasts at least two hours and does not exceed 100% of the unit’s capacity.

Quantification

(4) For the purposes of subsections (1) and (2),

Adaptation

(5) For the performance test, the reference to “calendar year” in sections 11, 12, 15, 17 and 18 and in the Reference Method is replaced with a reference to “performance test period”.

Requirement

6 A responsible person for a unit referred to in subsection 3(4) must obtain an annual performance test result that shows less than a 2% increase in emission intensity from the previous performance test.

Emergency Circumstances

Application for exemption

7 (1) A responsible person for a unit may, under an emergency circumstance described in subsection (2), apply to the Minister for an exemption from the application of subsection 4(1) or (2) in respect of the unit if, as a result of the emergency, the operator of the electricity grid in the province in which the unit is located or an official of that province responsible for ensuring and supervising the electricity supply orders the responsible person to produce electricity to avoid a threat to the supply or to restore that supply.

Definition of emergency circumstance

(2) An emergency circumstance is a circumstance

Deadline for application

(3) The application for the exemption must be provided to the Minister within 15 days after the day on which the emergency circumstance arises. The application must include the information referred to in section 1 and paragraphs 2(a), (b) and (d) of Schedule 1 or the unit’s registration number, if any, the date on which the emergency circumstance arose and information, along with supporting documents, to demonstrate that the conditions set out in subsection (1) are met.

Minister’s decision

(4) If the Minister is satisfied that the conditions set out in subsection (1) are met, the Minister must, within 30 days after the day on which the application is received,

Duration of exemption

(5) The exemption becomes effective on the day on which the emergency circumstance arises and ceases to have effect on the earliest of

Application for extension of exemption

8 (1) If the conditions set out in subsection 7(1) will continue to exist after the day on which the exemption granted under paragraph 7(4)(a) is to cease to have effect, the responsible person may, before that day, apply to the Minister for an extension of the exemption.

Contents of application

(2) The application must include the unit’s registration number and information, along with supporting documents, to demonstrate that

Minister’s decision

(3) If the Minister is satisfied that the elements referred to in paragraphs (2)(a) and (b) have been demonstrated, the Minister must grant the extension within 15 days after the day on which the application is received.

Duration of extension

(4) The extension ceases to have effect on the earliest of

Accuracy of Data

Measuring devices — installation, maintenance and calibration

9 (1) A responsible person for a unit must install, maintain and calibrate a measuring device — other than a continuous emission monitoring system and a measuring device that is subject to the Electricity and Gas Inspection Act — that is used for the purposes of these Regulations in accordance with the manufacturer’s instructions or any applicable generally recognized national or international industry standard.

Frequency of calibration

(2) The responsible person must calibrate each of the measuring devices at the greater of the following frequencies:

Accuracy of measurements

(3) The responsible person must use measuring devices that enable measurements to be made with a degree of accuracy of ± 5%.

Certification of CEMS

10 The responsible person must certify the CEMS in accordance with section 5 of the Reference Method, before it is used for the purposes of these Regulations.

Quantification Rules

Production of Energy

Quantity of energy

11 (1) The quantity of energy produced by a given unit is determined by the formula

G + (0.75 × Hpnet)

where

Quantity of electricity — hybrid configuration

(2) The quantity of electricity generated by a given unit is determined by the formula

Gce + Gs − Gext

where

Formula-Detailed information can be found in the surrounding text.

where

Net quantity of useful thermal energy

(3) In the case of a unit that simultaneously generates electricity and produces useful thermal energy from the fuel combusted by a combustion engine or boiler, as the case may be, the net quantity of useful thermal energy produced by the unit in a calendar year, expressed in GWh, is determined by the formula

Formula-Detailed information can be found in the surrounding text.

where

CO2 Emissions

Quantification Methods

Choice of method

12 The quantity of CO2 emissions resulting from the combustion of fossil fuels in a unit in a calendar year must be determined

Continuous Emission Monitoring System

Unit not combusting biomass

13 Subject to section 15, the quantity of CO2 emissions resulting from combustion of fossil fuels in a unit that does not combust biomass that is measured using a CEMS must be calculated in accordance with sections 7.1 to 7.7 of the Reference Method.

Unit combusting biomass

14 (1) Subject to section 15, the quantity of CO2 emissions resulting from the combustion of fossil fuels in a unit combusting biomass in a calendar year that is measured using a CEMS must be determined in accordance with the following formula:

Eu × (Vff ⁄ VT) − Es

where

Formula-Detailed information can be found in the surrounding text.

where

Formula-Detailed information can be found in the surrounding text.

S × R × (44⁄MMs)

where

Higher heating value

(2) The higher heating value of a fuel is to be measured

Multiple CEMS per unit

15 (1) For the purposes of sections 13 and 14, the total quantity of CO2 emissions from a unit equipped with multiple CEMS is determined by adding together the quantity of emissions measured for each CEMS.

Units sharing common stack

(2) If a unit is located at a facility where there is one or more other units and a CEMS measures emissions from that unit and other units at a common stack rather than at the exhaust duct of that unit and of each of those other units that brings those emissions to the common stack, then the quantity of emissions attributable to that unit is determined based on the ratio of the heat input of that unit to the total of the heat input of that unit and of all of those other units sharing the common stack in accordance with the following formula:

Formula-Detailed information can be found in the surrounding text.

where

If using a CEMS

16 (1) A responsible person who uses a CEMS must ensure compliance with the Reference Method.

Auditor’s report

(2) For each calendar year during which the responsible person used a CEMS, they must obtain a report, signed by the auditor, that contains the information required by Schedule 3 and send it to the Minister with the report referred to in section 21.

Fuel-based Method

Quantification

17 The quantity of CO2 emissions resulting from the combustion of fossil fuels in a unit in a calendar year, that is not measured using a CEMS, is determined by the formula

Formula-Detailed information can be found in the surrounding text.

where

S × R × (44⁄MMs)

where

Measured carbon content

18 (1) The quantity of CO2 emissions, that is attributable to the combustion of a fossil fuel in a unit in a calendar year is determined by one of the following formulas, whichever applies:

Vf × CCA × (MMA⁄MVcf) × 3.664 × 0.001

where

Vf × CCA × 3.664

where

Mf × CCA × 3.664

where

Weighted average

(2) The weighted average “CCA” referred to in paragraphs (1)(a) to (c) is determined by the formula

Formula-Detailed information can be found in the surrounding text.

where

Sampling and Missing Data

Sampling

19 (1) Subject to subsection (2), the determination of the value of the elements related to carbon content referred to in section 18 must be based on fuel samples taken in accordance with this section.

Carbon content provided by the supplier

(2) If the supplier of the fuel has provided the carbon content of the fuel, the responsible person can obtain from that supplier the carbon content of the fuel for the specified sampling period and at the specified minimum sampling frequency rather than taking samples in accordance with subsection (3).

Frequency

(3) Each fuel sample must be taken at a time and location in the fuel handling system of the facility that provides the following representative samples of the fuel combusted at the applicable minimum frequency:

Additional samples

(4) For greater certainty, the responsible person who, for the purposes of these Regulations, takes more samples than the minimum required under subsection (3) must make the determination referred to in subsection (1) based on each sample taken — and in the case of composite samples, each sub-sample taken — including those additional samples.

Significantly modified boiler units

(5) In the case of a boiler unit referred to in subsection 3(4), one fuel sample is required for the initial performance test and each subsequent performance test and it must be taken in accordance with one of the applicable standards set out in subparagraphs (3)(a)(i) to (iv).

Missing data

20 (1) Except in the case of an initial performance test or any subsequent performance test referred to in section 5, if, for any reason beyond the responsible person’s control, the emission intensity referred to in subsection 4(1) or 4(2) cannot be determined in accordance with a formula set out in any of sections 11, 17 and 18 because data required to determine the value of an element of that formula is missing for a given period in a calendar year, replacement data for that given period must be used to determine that value.

Replacement data — CEMS

(2) If a CEMS is used to determine the value of an element of a formula set out in section 17 but data is missing for a given period, the replacement data must be obtained in accordance with Section 3.5.2 of the Reference Method.

Replacement data — fuel-based methods

(3) If a fuel-based method is used to determine the value of any element — related to the carbon content or molecular mass of a fuel — of a formula set out in section 17 or 18 but data is missing for a given period, the replacement data is to be the average of the available data for that element, using the fuel-based method in question, during the equivalent period prior to and, if the data is available, subsequent to that given period. However, if no data is available for that element for the equivalent period prior to that given period, the replacement data to be used is the value determined for that element, using the fuel-based method in question, during the equivalent period subsequent to the given period.

Replacement data — multiple periods

(4) Replacement data may be used in relation to a maximum of 28 days in a calendar year.

Reporting, Sending, Recording and Retaining Information

Annual reports

21 (1) Subject to subsection (2), a responsible person for a unit must send one of the following reports, to the Minister on or before the June 1 that follows the calendar year that is the subject of the report:

Significantly modified boiler units

(2) A responsible person for a boiler unit referred to in subsection 3(4) must send the reports referred to in subsection (1), beginning in the year in which it must meet the emission limit referred to in subsection 4(2).

Permanent cessation of electricity generation

(3) If a unit permanently ceases to generate electricity in a calendar year, a responsible person for the unit must so notify the Minister in writing not later than 60 days after the day on which the unit ceases generating electricity. A report is not necessary in respect of the calendar years following the calendar year in which the unit ceases generating electricity.

Registration number

(4) On receipt of a first report in respect of a unit referred to in paragraph (1)(a), the Minister must assign a registration number to the unit and inform the responsible person of that number.

Change of information

(5) If there is a change to the information referred to in section 1 of Schedule 1 that was provided in the most recent report, the responsible person must notify the Minister of the change in writing not later than 30 days after the day on which the change is made.

Performance test reporting

22 (1) A responsible person for a boiler unit referred to in subsection 3(4) must send, to the Minister, a report containing the information referred to in Schedule 4 in relation to the performance test identified in section 5 no later than 60 days after the performance test was conducted.

Performance test verifier’s report — initial test

(2) In the case of a boiler unit referred to in subsection 3(4), the responsible person must obtain a report, signed by the performance test verifier, on the initial performance test, that contains the information referred to in Schedule 5 and send it to the Minister with their report referred to in subsection (1).

Electronic report, notice and application

23 (1) A report or notice that is required, or an application that is made, under these Regulations must be sent electronically in the form specified by the Minister and must bear the electronic signature of an authorized official of the responsible person.

Paper report or notice

(2) If the Minister has not specified an electronic form or if the person is unable to send the report, notice or application electronically in accordance with subsection (1) because of circumstances beyond the person’s control, the report, notice or application must be sent on paper, in the form specified by the Minister, if applicable, and be signed by an authorized official of the responsible person.

Maintain copy

24 (1) A responsible person for a unit must make a record containing the following documents and information:

30 days

(2) The record referred to in subsection (1) must be made as soon as feasible but not later than 30 days after the day on which the information and documents to be included in it become available.

Retention of records and reports

25 A responsible person who is required under these Regulations to make a record or send a report or notice must keep the record or a copy of the report or notice, along with the supporting documents, at their principal place of business in Canada for at least seven years after they make the record or send the report or notice.

Coming into Force

Registration

26 (1) Subject to subsection (2), these Regulations come into force on January 1, 2019.

Deferred application

(2) These Regulations become applicable to combustion engine units on January 1, 2021.

SCHEDULE 1

(Subsection 7(3), paragraphs 21(1)(a) and (b) and subsection 21(5))

Annual Report — Information Required

1 The following information respecting the responsible person:

2 The following information respecting the unit:

3 The following information respecting the emission intensity referred to in subsection 4(1) or (2) of these Regulations resulting from the combustion of fossil fuel in the unit during the calendar year:

4 The following information:

5 A copy of the auditor’s report referred to in subsection 16(2) of these Regulations.

6 The following information respecting the replacement data referred to in section 20 of these Regulations that were used for a given period during the calendar year, if applicable:

SCHEDULE 2

(Subsections 14(1) and 15(2))

List of Fuels

Item

Column 1

Fuel type

Column 2

Default higher heating value (GJ/kL) table 1 note 2

Table 1 Notes

Table 1 Note 1

The default higher heating value and the default CO2 emission factor for propane are only for pure gas propane. The product commercially sold as propane is to be considered LPG for the purpose of these Regulations.

Return to table 1 note 1 referrer

Table 1 Note 2

The default higher heating value for pipeline quality natural gas is expressed in GJ/standard m3

Return to table 1 note 2 referrer

1

Distillate fuel oil No.1

38.78

2

Distillate fuel oil No. 2

38.50

3

Distillate fuel oil No. 4

40.73

4

Kerosene

37.68

5

Liquefied petroleum gases (LPG)

25.66

6

Propane (pure, not mixtures of LPGs) table 1 note 1

25.31

7

Propylene

25.39

8

Ethane

17.22

9

Ethylene

27.90

10

Isobutane

27.06

11

Isobutylene

28.73

12

Butane

28.44

13

Butylene

28.73

14

Natural gasoline

30.69

15

Motor gasoline

34.87

16

Aviation gasoline

33.52

17

Kerosene-type aviation

37.66

18

Pipeline quality natural gas

0.03793table 1 note 2

SCHEDULE 3

(Subsection 16(2))

CEMS Auditor’s Report — Information Required

1 The name, civic address and telephone number of the responsible person.

2 The name, civic address, telephone number and qualifications of the auditor and, if any, the auditor’s email address and fax number.

3 The procedures followed by the auditor to assess whether

4 A statement of the auditor’s opinion as to whether

5 A statement of the auditor’s opinion as to whether the responsible person has ensured that the Quality Assurance/Quality Control manual has been updated in accordance with sections 6.1 and 6.5.2 of the Reference Method.

SCHEDULE 4

(Subsection 22(1))

Performance Test Report — Information Required

1 The following information respecting the responsible person:

2 The following information respecting the unit:

3 The following information respecting the emission intensity referred to in subsection 4(2) of these Regulations resulting from the combustion of fuel in the unit during the performance test period:

4 The date that the test was performed.

SCHEDULE 5

(Subsection 22(2))

Initial Performance Test Verifier’s Report — Information Required

1 The name, civic address and telephone number of the responsible person.

2 The name, civic address, telephone number and qualifications of the performance test verifier and, if any, the performance test verifier’s email address and fax number.

3 The procedures followed by the performance test verifier to assess whether the performance test result was obtained in accordance with section 5 of these Regulations.

4 A statement of the performance test verifier’s opinion as to whether the performance test result was obtained in accordance with section 5 of these Regulations.

REGULATORY IMPACT ANALYSIS STATEMENT

(This statement is not part of the regulations.)

Issues

Significant investments in the electricity sector are expected as it phases out the use of coal to generate electricity (coal-fired electricity generation) in Canada. As there are no federal regulations controlling greenhouse gas (GHG) emissions from natural gas-fired electricity generation in Canada, clarity on the federal regulatory approach to control these emissions is needed to reduce uncertainty, help create a more stable investment climate and incentivize investment in lower-emitting forms of electricity generation in Canada. The Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity (the Regulations) set performance standards for new and significantly modified natural gas-fired electricity units, providing regulatory certainty on the level of such standards.

Background

The Government of Canada (the Government) is committed to reducing GHG emissions to mitigate the impact of climate change. In 2016, Canada ratified the Paris Agreement and committed to a 30% reduction in overall GHG emissions below 2005 levels by 2030. In the same year, First Ministers from federal, provincial (except Saskatchewan), and territorial governments released the Pan-Canadian Framework on Clean Growth and Climate Change, which includes a commitment to expand clean electricity sources, supported by infrastructure investments and regulations for coal and natural gas-fired electricity generation. footnote 1 The 2017 federal budget committed $21.9 billion over 11 years in green infrastructure. Natural gas-fired electricity generation capacity will be necessary to back up renewable sources of electricity generation coming online in the future in Canada, including those accessed through the funds committed in the 2017 federal budget. On February 17, 2018, the Department of the Environment (the Department) published the proposed Regulations Amending the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations and the proposed Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity in the Canada Gazette, Part I.

The two regulations were developed in parallel to provide regulatory certainty about the federal approach to controlling GHG emissions from electricity generation in Canada footnote 2 and to ensure that any new and significantly modified natural gas-fired electricity units built to replace coal-fired electricity units meet emission performance standards.

Electricity generation GHG emissions

In 2015, Canada’s GHG emissions from the electricity sector were about 79 megatonnes (Mt) footnote 3 of carbon dioxide equivalent (CO2e) footnote 4 and about 12 Mt CO2e of those came from natural gas-fired electricity generation. It is estimated that by 2035, in a business-as-usual scenario, while Canada’s emissions from the electricity sector are expected to drop to 34 Mt CO2e, emissions from natural gas-fired electricity generation would rise to about 22 Mt CO2e. The estimated 56% decrease in overall GHG emissions is due in large part to the expected phase-out of the use of coal to generate electricity in Canada. The projected rise in GHG emissions from natural gas-fired electricity generation is a result of replacement generation coming on line as coal-fired electricity generation is phased out.

Summary of natural gas-fired electricity generation technologies

Utility-scale, natural gas-fired generation technologies generally fall into one of the following types: a combustion engine (e.g. gas turbine or reciprocating engine), or a boiler. This includes boilers that were previously coal-fired and are converted to burn natural gas (coal-to-gas conversion). An overview of the technologies used to generate electricity using natural gas in Canada is presented below.

1. Combustion engines

There are two different types of combustion engines that may burn natural gas to generate electricity:

2. Boilers

In these units, fuel is combusted in a boiler to convert water into steam. The steam spins a steam turbine that drives a generator to produce electricity. Boiler units can burn a variety of fuels, including but not limited to coal, petroleum coke, heavy fuel oil, natural gas, and biomass, alone or in combination.

The number of natural-gas fired boilers has been in decline, mainly due to improvements in the efficiency and flexibility of gas turbine technology.

3. Coal-to-gas conversion

Conversion to combust natural gas could be as simple as installing a gas nozzle on an existing coal burner and tying into the existing natural gas supply system, or the conversion could be more complex, requiring the installation of completely new burners, boiler modifications, boiler auxiliary equipment modifications or replacements, and entirely new off-site and on-site natural gas supply systems. The degree of the required modifications would depend on the unit being considered for modification.

In 2017, TransAlta announced that its Board of Directors approved six coal-to-gas conversions footnote 5 in Alberta. The six coal-to-gas conversions are expected to

Objectives

The objective of the Regulations is to limit CO2 emissions from natural gas-fired electricity generation by ensuring new and significantly modified natural gas-fired electricity units are subject to emission performance standards. In doing so, the Regulations will provide regulatory certainty on the level of such standards. This is expected to facilitate the planning and investment decision-making processes associated with the phase out of the use of coal-fired electricity generation and the construction of new natural gas-fired electricity generation capacity in Canada.

Description

The Regulations will impose performance standards (CO2 emission intensity-based limits) on new and significantly modified natural gas-fired electricity generating units. footnote 7

New units include

Significantly modified units include

Below is a summary of the performance standards and other requirements under the Regulations.

1. Performance standards for combustion engine units (gas turbines and reciprocating engines) — new, significantly modified or moved to a new facility

For combustion engine units that are new, significantly modified or moved to a new facility, the performance standard that applies is based on the size of the individual combustion engines of the unit. For units equipped with one or more combustion engines with a capacity larger than 150 megawatts (MW) footnote 8 (> 150 MW), the performance standard will apply on an annual average basis and be 420 tonnes (t) of CO2 for each gigawatt hour (GWh) of energy produced. The performance standard for combustion engine units equipped with engines with a capacity of 150 MW or less (≤ 150 MW) will also apply on an annual average basis and be 550 t of CO2/GWh of energy produced.

The Regulations will apply to combustion engine units (gas turbines and reciprocating engines) that meet all of the following conditions:

2. Performance standards for natural gas boiler units — new or moved to a new facility

The performance standard for natural gas boiler units that are new or moved to a new facility will apply on an annual average basis and be 420 t of CO2/GWh of energy produced.

The Regulations will apply to natural gas boiler units that meet the following conditions:

3. Performance standards for coal boilers significantly modified to burn natural gas to generate electricity (coal-to-gas conversion)

Significantly modified coal boiler units that cease using coal as a fuel footnote 14 and continue operating using natural gas to generate electricity will be allowed to operate without meeting a performance standard for a limited period of time, after which they must meet a performance standard. The performance standard for coal-to-gas conversions will be deferred for a prescribed period (either 0, 5, 8 or 10 years after the unit’s end of useful life footnote 15) determined by an initial coal-to-gas converted boiler performance test.

The initial performance test and the emission intensity determined from this test must be reported under the Regulations, generally within 12 months after the coal-to-gas conversion is completed. The emission intensity during the initial performance test will establish how many years the coal-to-gas converted unit could operate without meeting a performance standard of 420 t of CO2/GWh, where units that are more efficient will be allowed to operate longer without meeting the standard.

For coal-to-gas converted boiler units, the performance standard of 420 t of CO2/GWh of energy produced would not apply for a given number of years as follows:

Subsequent annual performance tests must be conducted to determine the CO2 emission intensity of a converted unit. The CO2 emission intensity of the converted unit during these tests must show less than a 2% increase in the emission intensity from the previous performance test to be in compliance.

The Regulations will apply to converted coal-to-gas boiler units if they meet the conditions below:

Reporting obligations

Owners or operators will be required to submit annual reports for units to which the Regulations apply. In the case of units that have met the application criteria in previous years, but cease to meet any of the application criteria in a given year, only a shortened report is required for this year. Owners or operators of converted coal-to-gas boiler units will be required to submit their annual performance test reports for the period during which the performance emission standard does not apply to that unit. Once the period expires, and the unit is subject to the performance standard, the owner or operator will be required to submit full annual reports for that unit to comply with the Regulations. The Regulations provide two methods to quantify CO2 emissions: Continuous Emission Monitoring System (CEMS) footnote 18 and a fuel-based method. footnote 19

Emergency circumstances

A provision is included in the Regulations to ensure grid reliability during emergency circumstances. If a unit needs to operate to mitigate the consequences of an emergency disruption or in the event of a significant risk of disruption to the electricity supply, such a unit could apply for a temporary exemption from the performance standard.

Regulations Designating Regulatory Provisions for the Purposes of Enforcement (Canadian Environmental Protection Act, 1999)

The Regulations Designating Regulatory Provisions for the Purposes of Enforcement (Canadian Environmental Protection Act, 1999) will be amended to list subsections 4(1) and 4(2) of the Regulations and make the contravention of these provisions punishable by appropriate penalties.

Summary of the Regulations

Application

Rationale

The Regulations will not apply to natural gas-fired electricity combustion engine units that are in use in Canada before January 1, 2021, with a few exemptions. For example, an existing combustion engine unit generating electricity that was moved to another facility on or after January 1, 2021, would be covered. footnote 20

Avoids costs associated with retrofitting existing units to meet performance standards. However, based on analysis of seven large and three small units in use in Canada, GHG emissions from these units meet or out-perform the requirements set in the Regulations.

The Regulations will not apply to natural gas-fired electricity combustion engine units that start producing electricity on or after January 1, 2021, and that sell or distribute less than 33% of their potential electrical output to the grid.

Avoids costs associated with units that are not expected to be a major source of GHG emissions in Canada, while providing flexibility for operators to meet demands during peak hours.

Emission performance standards

Rationale

The Regulations will align emission performance standards for new and significantly modified natural gas-fired combustion engine units — expected to sell or distribute 33% or more of their potential electrical output to the grid — with those of available efficient technologies.

Historical annual average emission intensity (t of CO2/GWh) data on existing natural gas-fired electricity generation units, using efficient technologies, shows that the emission performance standards can be met by new and significantly modified combustion engines.

The Regulations will require significantly modified boilers converted to burn natural gas to generate electricity to meet a performance standard after a prescribed period.

Converted units are expected to meet this requirement21 as the emission performance test parameters were based on information provided by operators based on the current efficiency of affected coal boilers.

“One-for-One” Rule

The Regulations are expected to result in a minor increase in administrative burden; therefore, the Regulations are considered an “IN” under the “One-for-One” Rule. Following the Treasury Board’s standard costing model, and using a 7% discount rate, the expected annualized administrative cost to all business subject to the Regulations is approximately $10,752 (in 2012 Canadian dollars) and $758 per business. These new costs will require equal and offsetting administrative cost reduction to existing regulations, and as these are new Regulations, the Department will also be required to repeal at least one existing regulation within two years. footnote 21

One-time (upfront) costs

Small business lens

The small business lens does not apply to the Regulations, as none of the affected businesses are small businesses. footnote 23

Consultation

On December 17, 2016, the notice of intent (NOI) to develop GHG regulations for electricity generation in Canada was published in the Canada Gazette, Part I, for a 60-day public comment period. The NOI advised of the intent of the Government to amend the Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations published on September 12, 2012, and to develop regulatory requirements for natural gas-fired electricity generation. During the 60-day public comment period, 21 comments were received from stakeholders (industry associations, natural gas or renewable sources electricity generators, provinces, non- governmental organizations and others). As a result of these comments, and based on new data received, gathered and generated by the Department, several aspects of the Regulations were reconsidered, resulting in some adjustments. For example, in the NOI, a combustion engine with a capacity of more than 100 MW was initially considered to be large and therefore subject to average annual performance standard of 420 t of CO2/GWh. Under the revised approach, combustion engines with a capacity of more than 150 MW are now considered to be large.

On February 17, 2018, the Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity were published in the Canada Gazette, Part I, for a 60-day public comment period, which included a summary of comments received on the NOI and Government responses to these comments. During the 60-day public comment period, the Department received comments from 22 stakeholders on the proposed definitions, performance standard level, reporting requirements, quantification methods, coal-to-gas conversions, and policy objectives. Below is a summary of these comments and the response by the Government.

Definitions

Some industry stakeholders suggested adding the concept of maximum continuous rating (MCR) to define the electricity generation capacity of a unit because although terminology may vary by jurisdiction or company, the meaning is widely understood by industrial stakeholders. The Department agreed with this suggestion and incorporated this concept into the Regulations.

One industrial stakeholder recommended that the definition of “natural gas” be amended to exclude gas from wastewater treatment systems. Since this type of gas is compositionally similar to landfill or digester gas, which are already excluded from the definition of natural gas, the Department agreed, and the definition was modified.

One industry stakeholder proposed defining “existing units” as facilities that are currently operating and those that have permits to operate but are not yet built, and exempting them from the Regulations. The Department clarified that the Regulations will apply to some existing units in the specific circumstances described in subsection 3(3) of the Regulations. Additionally, the Department noted that a two-year grace period was added to the coming into force date for combustion engine units so that units currently under construction could be commissioned before the coming into force date of the Regulations.

Performance standard level

Some stakeholders suggested that the standards be at least to the level of best available technology (BAT). This approach would require a standard in the range of 360–400 t of CO2/GWh for large combustion engine units, instead of the 420 t of CO2/GWh set in the policy; and 500 t of CO2/GWh for small units, instead of the 550 t of CO2/GWh set in the policy. One stakeholder proposed to prohibit the operation of stand-alone natural gas-fired units after 2040 except as peaking units and others proposed that the performance standards be tightened from time to time in the future. The Department clarified that the main objective of the policy is to ensure new and significantly modified natural gas-fired electricity units are subject to emission performance standards and to provide regulatory certainty on the level of such standards. This is expected to help facilitate investment decision-making processes as the electricity sector transitions away from coal-fired electricity generation to lower and non-emitting forms of electricity generation in Canada.

The Department acknowledges that due to uncertainties about the future supply mix of electricity generation in Canada related to the impact of replacing coal-fired electricity generation capacity, some natural gas-fired electricity units may need to operate above BAT optimal levels from time to time. It is also expected that as more renewable sources of electricity generation come online, the share of natural gas-fired electricity generation in Canada would decrease. The 2017 federal budget committed $21.9 billion over 11 years in green infrastructure investments in alternative fuelling networks, technology demonstration projects, energy efficiency standards, renewable energy demonstration projects, and smart grids.

Two stakeholders suggested that new natural gas combustion engine units should be exempt from the Regulations for the first two years of operation to allow for the stabilization and optimization of such units. The Department determined, based on available information, that stabilization and optimization activities should not have a significant effect on a unit’s annual average emission intensity and thus the exemption was not deemed necessary.

Several industrial stakeholders recommended that the performance standard be calculated on a three-year rolling average (instead of a one-year average) to allow for performance variability of units and/or the integration of renewable sources of electricity. One stakeholder commented that in the event that smaller simple-cycle (SC) units are built, rather than combined-cycle (CC) units, to support the growing amount of intermittent renewable electricity generation, some of these SC units would need to operate above the 33% capacity threshold set in the policy and thus would be subject to the performance standard of 550 t of CO2/GWh set in the Regulations. The Department engaged stakeholders to discuss their proposal. Based on the outcome of these discussions and information provided by an electric system operator, the Department concluded that granting the three-year rolling average was not warranted at this time. The Department noted that there are SC gas turbines currently available for sale that could meet the 550 t of CO2/GWh average annual performance standard required for combustion engines with a capacity of 150 MW or less.

Reporting requirements

One stakeholder commented that the annual monitoring of CO2 emissions should not only include emission intensity (t of CO2/GWh) at a unit level, but also the total volume of emissions produced annually by that unit and that this data be made available for public access. The Department clarified that unit-level CO2 emissions (total volume and emission intensity) will be reported publicly through the Greenhouse Gas Reporting Program (GHGRP). footnote 24

Another recommendation was to include requirements for independent monitoring of all upstream emissions, such as from gas wells, pipelines and processing facilities for methane leakage. The Department noted that the policy is designed to limit end-use emissions of natural gas-fired electricity generation. Regarding upstream methane leakage, in April 2018, the Department published Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) that are estimated to reduce methane emissions from the upstream oil and gas sector by 40 to 45 percent from 2012 levels by 2025. These Regulations require three comprehensive leak inspections per year at most upstream oil and gas facilities, in addition to equipment standards for key methane sources.

Quantification methods

Industrial stakeholders proposed that the fuel-based quantification methods used to report emissions should be aligned with existing protocols such as the quantification methods used in the GHGRP, the Western Climate Initiative, or with protocols prescribed by provincial governments for emissions reporting. The Department reviewed existing quantification methods and modified some fuel sampling requirements to further bring the Regulation’s fuel-based quantification method in line with the GHGRP.

Another recommendation was to allow for the use of provincial protocols for CEMS, for example Alberta’s CEMS Code to be used instead of the Reference Method. footnote 25 The Department did not provide the option for units in Alberta to use the province’s CEMS Code. The Department noted that the Alberta CEMS Code is currently under revision. Further, few units are expected to choose CEMS as a quantification method to measure and report emissions under the Regulations.

Some stakeholders recommended that the emission intensity limits for units equipped with both large (>150 MW) and small (≤150 MW) combustion engines, be applied in a similar manner to the hybrid configuration concept (as described at subsection 3(5), meaning a combination where a combustion engine and a boiler share a common steam turbine). Under the current approach, any unit equipped with both large and small combustion engines would be subject to the large performance standard of 420 t of CO2/GWh. Applying the hybrid configuration concept to these types of units would allow the unit to be subdivided and subject to different performance standards. That is, the small combustion engine (and any other equipment connected to it including the steam turbine that it shares with the large combustion engine) would be subject to the 550 t of CO2/GWh performance standard. And, vice-versa, the large combustion engine (and any other equipment connected to it including the steam turbine that it shares with the small combustion engine) would be subject to the 420 t of CO2/GWh performance standard. The Department engaged stakeholders following the comment period to better understand this suggestion. The Department subsequently concluded that this type of configuration, where a unit is equipped with both large and small combustion engines, is not common industry practice and where it does exist, it is the result of a retrofit. Therefore, this recommendation was not incorporated into the Regulations.

One stakeholder recommended including a requirement related to the emergency clause, such that if a unit operates under this clause that it be required to compensate for emissions above the relevant performance standard. Suggested mechanisms included purchasing emission allowances or offset credits. The Department clarified that the emergency clause is meant to allow operators to call units online to avert emergencies and thus these units should not be penalized.

Coal-to-gas conversions

Some stakeholders commented that the prescribed period for which a converted coal-to-gas boiler unit may operate without meeting a performance standard was too long (up to 10 years after the unit’s end of useful life). They suggested that coal-to-gas conversions that cannot meet a performance standard of 420 t of CO2/GWh should be forced to cease operations by December 31, 2029, or within 8 to 10 years after conversion, whichever comes first. They argued that this should include coal-to-gas conversions under any potential federal-provincial equivalency agreements. The Department concluded that based on available information on the announced six coal-to-gas conversions in Alberta, which are expected to occur between 2020 and 2022, and considering technological/economic constraints, most of these units are not expected to operate beyond December 31, 2029.

While one stakeholder proposed increasing the level of the 2% performance decay annual allowance for coal-to-gas converted boilers, another opposed limiting annual performance decay to 2%, arguing that it could interfere with maintenance scheduling. The Department noted that the 2% is very achievable and it was determined that the level of this performance decay allowance is enough to achieve the objective of preventing significant degradation of coal-to-gas converted boilers from year to year. The 2% performance decay allowance is needed to ensure that operators will maintain their coal-to-gas converted boilers in good operating condition.

An industrial stakeholder suggested including additional and specific parameters for emission performance testing. For example, that the initial performance test be completed within six months after a coal-to-gas conversion, and that the required emissions testing parameters be based on normal operating conditions and not staged in unrealistic and under-optimal conditions as set in the policy. The Department clarified that the emission intensity levels set for the initial performance tests were chosen acknowledging that the parameters in the Regulations allow for operators to choose their best window for an initial performance test and subsequent annual performance testing.

Policy objective

Some stakeholders commented that the policy facilitates the phase-out of one fossil fuel by its replacement with another fossil fuel (coal to natural gas) and does not send meaningful market and/or price signals to investors on natural gas and therefore decreases the policy’s role in the energy mix in Canada. The Department noted that the policy objective of the Regulations is to ensure new and significantly modified natural gas-fired electricity units are subject to emission performance standards and to provide regulatory certainty to stakeholders about the level of such standards, while supporting one of the objectives of the Pan-Canadian Framework on Clean Growth and Climate Change, to accelerate the reduction of GHG emissions from coal-fired electricity generation in Canada. There are other federal initiatives, such as the Greenhouse Gas Pollution Pricing Act and clean fuel standard (under development) that are expected to send market and/or price signals to the sector that could result in investments of lower or non-emitting forms of electricity generation in the future in Canada.

One of the issues arising from the Department’s engagement with industry stakeholders was a concern that federal climate change policies affecting the electricity sector, including the regulations to accelerate GHG reductions from coal-fired electricity generation, the clean fuel standard, and the output-based carbon pricing system, were being developed at a challenging pace and were overlapping each other. The Department established The Multi-Stakeholder Committee on GHG Regulatory Measures and Programs to serve as a forum for stakeholders to identify issues of interest or concern and share views on the interactions (synergistic and overlapping) among climate change programs and regulations, as well as on the cumulative GHG emissions and socioeconomic impacts.

Rationale

In Canada, significant investment is expected in the electricity sector as it phases out the use of coal to generate electricity. Investment decisions to build electricity generation capacity are a complex process that involves analyses of several factors such as a forecast of energy/capacity demand and of market pricing/constraints. Other factors, such as lack of clarity of regulatory frameworks, could affect the sector in the future and influence investment decisions on how to replace coal-fired electricity generation capacity. As a result, the Regulations will set GHG emission intensity limits for new and significantly modified natural gas-fired electricity generation units in Canada and provide regulatory certainty on the level of such standards. This is expected to help ensure the transition to lower emitting electricity generation and is consistent with the Government’s overall strategy to reduce GHG emissions.

Impacts on Canadians, the Government and businesses

Canadians

The Regulations are not expected to have an impact on Canadian consumers.

The Government

Minor additional resources are anticipated to process annual emission reports as a result of the Regulations. As affected units are expected to be compliant with the performance standards, no significant incremental costs associated with compliance promotion or enforcement activities are anticipated.

Businesses

Owners and operators choosing to replace coal-fired electricity generation capacity or meet increasing demand of electricity in Canada with new natural gas-fired electricity generation, specifically with combustion engines, are expected to do so by using existing efficient technologies that are compliant with the emission performance standards set out in the Regulations. This is because these technologies minimize fuel consumption and emit about 40% to 50% less GHG emissions than coal-fired electricity generation. These factors combined help respond to changes in market structure and carbon pricing or carbon reducing policies that governments have implemented, or plan to implement. Owners and operators choosing to convert their coal boilers to burn natural gas to produce electricity (coal-to-gas conversion), as a short-term transition away from coal, are expected to comply with the performance test parameters and operate within the timeframe set out in the Regulations. This is based on the analysis of the information obtained from operators and generated by the Department. As a result, the Regulations are not expected to have a significant impact on businesses choosing to build new natural gas-fired electricity generation capacity in Canada, including coal-to-gas conversions.

For each calendar year during which a natural gas-fired electricity generation unit is subject to the Regulations, owners and operators will be required to submit a report on the unit’s average annual emissions intensity. To comply with the reporting of average annual emissions, the two methods to quantify emissions (i.e. CEMS and fuel-based) required by the Regulations are not expected to have a significant impact on businesses. This is due to the alignment of these reporting requirements with those under the changes to the GHGRP, which are expected to come into force before the Regulations. Similarly, for coal-to-gas conversion units, owners and operators will be required to submit annual performance test reports, which consist of a single test run, lasting at least two hours. This requirement is not expected to have a significant impact on businesses. In both cases, regulatees will need to make and keep records of these reports for a period of seven years.

Based on available information provided by industry and generated by the Department, the Regulations will not have a significant impact on businesses.

Strategic environmental assessment

The Regulations were developed under the Pan-Canadian Framework for Clean Growth and Climate Change. A strategic environmental assessment (SEA) was completed for this framework in 2016. The SEA concluded that regulations under the framework will help reduce GHG emissions and are in line with the 2016–2019 Federal Sustainable Development Strategy. The Regulations are an important part of the Strategy and align with the clean energy goals for Canadians to have access to affordable, reliable and sustainable energy. footnote 26

Implementation, enforcement and service standards

Once the Regulations come into force, the Department will develop and deliver implementation activities. This may include posting information on the Department’s website, advising stakeholders of the final regulatory publication, responding to information or clarification requests, and sending reminder letters (as appropriate).

Enforcement

Enforcement officers will, when verifying compliance with the Regulations, apply the Compliance and Enforcement Policy (the Policy) for the Canadian Environmental Protection Act, 1999 (CEPA). footnote 27 The Policy sets out the range of possible responses to alleged violations, including warnings, directions, environmental protection compliance orders, tickets, ministerial orders, injunctions, prosecution and environmental protection alternative measures (which are an alternative to a court prosecution after the laying of charges for a CEPA violation). In addition, the Policy explains when the Department will resort to civil suits by the Crown for cost recovery.

To verify compliance, enforcement officers may conduct an inspection. An inspection may identify an alleged violation, and alleged violations may also be identified by the Department’s technical personnel, or through complaints received from the public. Whenever a possible violation of regulatory requirements is identified, enforcement officers may carry out investigations.

When, following an inspection or an investigation, an enforcement officer discovers an alleged violation, the officer will choose the appropriate enforcement action based on the following factors:

The Regulations will also require related changes to the Regulations Designating Regulatory Provisions for Purposes of Enforcement (Canadian Environmental Protection Act, 1999). These Regulations designate the regulatory provisions from CEPA regulations that refer to an increased fine regime following a conviction of an offence involving harm or risk of harm to the environment, or obstruction of authority.

Contacts

Paola Mellow
Director
Electricity and Combustion Division
Environment and Climate Change Canada
351 Saint-Joseph Boulevard
Gatineau, Quebec
K1A 0H3
Email: ec.electricite-electricity.ec@canada.ca

Matthew Watkinson
Director
Regulatory Analysis and Valuation Division
Environment and Climate Change Canada
200 Sacré-Cœur Boulevard, 10th Floor
Gatineau, Quebec
K1A 0H3
Email: eccc.darv-ravd.eccc@canada.ca