Vol. 150, No. 13 — June 29, 2016

Registration

SOR/2016-151 June 17, 2016

CANADIAN ENVIRONMENTAL PROTECTION ACT, 1999

Multi-Sector Air Pollutants Regulations

P.C. 2016-567 June 17, 2016

Whereas, pursuant to subsection 332(1) (see footnote a) of the Canadian Environmental Protection Act, 1999 (see footnote b), the Minister of the Environment published in the Canada Gazette, Part I, on June 7, 2014 a copy of the proposed Multi-Sector Air Pollutants Regulations, substantially in the annexed form, and persons were given an opportunity to file comments with respect to the proposed Regulations or to file a notice of objection requesting that a board of review be established and stating the reasons for the objection;

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 (see 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, His Excellency the Governor General in Council, on the recommendation of the Minister of the Environment and the Minister of Health, pursuant to subsections 93(1) and 330(3.2) (see footnote d) of the Canadian Environmental Protection Act, 1999 (see footnote e), makes the annexed Multi-Sector Air Pollutants Regulations.

TABLE OF PROVISIONS

MULTI-SECTOR AIR POLLUTANTS REGULATIONS

Overview

1 Parts 1, 2 and 3

Interpretation

2 Definitions

Responsibility

3 Who must comply

PART 1

Boilers and Heaters

Interpretation

4 Definitions

Application

5 Rated capacity at least 10.5 GJ/h

Main Requirements

6 Modern boilers

7 Modern heaters

8 Determination of type of gaseous fossil fuel

9 Transitional boilers and heaters

10 Redesigned boilers and heaters — NOx emission intensity

11 Class 80 and class 70

12 Pre-existing boilers and heaters — classification

13 Major modifications — class 80 and class 70

14 Exception — impossibility

Quantification

Elements of Requirements

15 Input energy from gaseous fossil fuel

Type of Gas

16 Percentage of methane

17 Fixed HHV of commercial grade natural gas

Thermal Efficiency

18 Modern boiler

19 Determination of Ldfg

20 Determination of Lw

21 Commercial grade natural gas — determined or fixed

22 Required HHV methods

23 Constituents of fuel

24 Difference of temperature — preheated air

Determination of NOx Emission Intensity
Stack Test or CEMS Test

25 Conditions

26 Identification — exception to paragraph 25(b)

Stack Tests

27 Three test runs

28 Concentrations of NOx and O2

29 Determination of NOx emission intensity

30 NOx emission intensity — average

31 NOx emission intensity — deemed hours

Continuous Emission Monitoring System

32 Rolling hourly average

Testing

33 Initial test

34 Classification NOx emission intensity — on registration

35 Classification NOx emission intensity — after registration

36 Redetermination after election under subparagraph 34(1)(b)(vi)

37 Redetermination after triggering event

38 Compliance tests — stack or CEMS test

Operation, Maintenance and Design

39 Specifications

Reporting

40 Initial report

41 Classification reports — sections 34 and 35

42 Compliance report

43 Change report

Recording of Information

44 Record-making

PART 2

Stationary Spark-ignition Engines

Interpretation

45 Definitions

Application

46 Pre-existing and modern engines

47 Non-application — low revenue and power

48 Non-application — new owners

49 Synthetic gas and still gas

General

50 Regular-use engines

51 Low-use engines — election

52 Designation as rich-burn engine

53 Applicable units — NOx emission intensity limit

Modern Engines

54 Regular-use — limit

55 Low-use — limit

Pre-existing Engines

Groups

56 Establishment

NOx Emission Intensity Limits

57 Engines not belonging to a group

58 Engines belonging to a group after 2025

59 Engines belonging to a group from 2021 to 2025

Yearly Average NOx Emission Intensity Limits — on Election

60 After 2025 and from 2021 to 2025

61 Election

62 Revocation — on notice

63 Revocation — after conviction

64 Replacement units

65 Designation of subgroups

66 Assignment of default NOx emission value

67 Assignment of non-default NOx emission value

68 NOx emission intensity limit — non-default NOx emission values

Determination of NOx Emission Intensity

Performance Tests

69 NOx emission intensity limits

70 Three test runs

71 Sampling ports

72 Concentration of NOx

73 ppmvd15%

74 g/kWh

75 NOx emission intensity — average

76 NOx emission intensity — deemed days

77 Performance tests

78 Subsequent performance test

Emissions Checks

79 When emissions check required for certain engines

80 Using electrochemical analyzer

81 Calibration error checks and interference responses

82 Analyzer — operation and maintenance

83 Sequence of calibration error checks

84 Reading for CO and NO interference responses

85 Invalid emissions check — calibration and interference

86 Emissions check — sampling ports

87 Operating conditions for emissions checks

88 Emissions check — sampling procedure

89 Concentration of O2, CO, NO and NO2 — average

90 Invalid emissions check — temperature

Performance Tests and Emissions Checks

91 Periods when not conducted

92 Extended period for new owners

93 Extended period — last day

Engine Management

94 Nameplate

95 Operation and maintenance

96 Air-fuel ratio

Registry, Reporting and Recording of Information

97 Engine registry

98 Change of information — engine registry

99 Compliance reports

100 Record-making

PART 3

Cement

101 Definitions

102 Application — grey cement

103 Obligation — over two consecutive years

104 Emission limit — NOx

105 Emission limit — SO2

106 Quantity of NOx and SO2 — CEMS

107 Quantity of clinker

108 Compliance report

PART 4

General

Continuous Emission Monitoring Systems

109 CEMS Reference Method — compliance

110 Annual audit

Measuring Devices

111 Installation, operation, maintenance and calibration

Alternative Rules

112 Application

113 Approval

114 Application of approved alternative rule

115 Notice to apply replaced rule

116 Refusal — false, misleading or incomplete information

117 Revocation by Minister

118 Revocation under law

119 Rule after notification or revocation

Reporting, Providing, Recording and Retention of Information

120 Electronic provision

121 Record-making

122 Corrections

123 Notification of testing

Amendments to these Regulations

124 Section 11

125 Subsection 12(1)

126 Paragraph 26(4)(a)

127 Paragraph 33(3)(c)

128 Section 35 and 36

129 Subsection 37(1)

130 Subsection 41(1)

131 Paragraph 43(1)(g)

132 Section 45 — definition subset

133 Section 49

134 Section 53

135 Section 57

136 Sections 58 and 59

137 Section 60

138 Paragraph 62(2)(c)

139 Paragraph 63(2)(b)

140 Section 69

141 Paragraph 77(b)

142 Subsection 94(1)

143 Paragraph 95(1)(b)

144 Paragraph 96(b)

145 Reference to Schedule 5

146 Paragraph 3(n) of Schedule 9

147 Section 4 of Schedule 10

Coming into Force

148 Registration

SCHEDULE 1

EC CEMS Code Modifications

SCHEDULE 2

Alberta CEMS Code Modifications

SCHEDULE 3

Default Higher Heating Values

Table 1

Solid Fuels

Table 2

Liquid Fuels

Table 3

Gaseous Fuels

SCHEDULE 4

Loss of Thermal Efficiency — Watertube Boilers

SCHEDULE 5

Classification Report (Boilers and Heaters) — Information Required

SCHEDULE 6

Initial Report (Boilers and Heaters) — Information Required

SCHEDULE 7

Compliance Report (Boilers and Heaters) — Information Required

SCHEDULE 8

Non-application (Engines) — Information Required

SCHEDULE 9

Engine Registry — Information Required

SCHEDULE 10

Compliance Report (Engines) — Information Required

SCHEDULE 11

Compliance Report (Cement Manufacturing Facilities) — Information Required

SCHEDULE 12

Auditor’s Report — Information Required

Multi-Sector Air Pollutants Regulations

Overview

Parts 1, 2 and 3

1 (1) For the purpose of protecting the environment and human health, Parts 1, 2 and 3 of these Regulations establish, respectively, requirements for the emission of the following air pollutants:

Part 4 — General

(2) Part 4 sets out general rules related to

Interpretation

Definitions

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

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

Alberta CEMS Code means the method entitled Continuous Emission Monitoring System (CEMS) Code (Pub. No.: Ref. 107) — published in May 1998 by Her Majesty the Queen in right of Alberta, as represented by the Minister responsible for Alberta Environmental Protection — as read in accordance with subsection (4). (Code SMECE de l’Alberta)

alumina facility means a facility that is used or designed to produce alumina from bauxite for use in the production of aluminum. (installation de production d’alumine)

aluminum facility means a facility that is used or designed

asphalt refinery means a facility — other than a petroleum refinery — at which the annual volume of asphalt produced is greater than 33% of the annual volume of liquid petroleum products produced and that is used or designed to process, using distillation,

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

ASTM D6522-11 means the method entitled Standard Test Method for Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in Emissions from Natural Gas-Fired Reciprocating Engines, Combustion Turbines, Boilers, and Process Heaters Using Portable Analyzers, published by ASTM . (méthode ASTM D6522-11)

authorized official means

base metals facility means a pyrometallurgical or hydrometallurgical facility that is used or designed to recover or refine at least one of the following metals from feedstock that comes primarily from ore:

boiler means combustion equipment — other than combustion equipment that is used only in the production of electricity for sale — that is used or designed to transfer thermal energy from the combustion of a fuel to water or steam or another fluid. (chaudière)

cement manufacturing facility means a facility that is used or designed to produce clinker. (cimenterie)

CEMS Reference Method means the EC CEMS Code or the Alberta CEMS Code. (méthode de référence des SMECE)

CFR means Title 40, Chapter I of the Code of Federal Regulations of the United States. (CFR)

chemicals facility means a facility that is used or designed to manufacture chemical substances from feedstock as its primary activity and where at least one of the following substances is manufactured:

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)

diesel fuel means a fuel that can evaporate at atmospheric pressure, that boils at a temperature of at least 130ºC and at most 400ºC and that is for use in diesel engines. (carburant diesel)

EC CEMS Code means the method entitled Protocols and Performance Specifications for Continuous Monitoring of Gaseous Emissions from Thermal Power Generation (EPS 1/PG/7) — published with revisions in December 2005 by Her Majesty the Queen in right of Canada, as represented by the Minister — as read in accordance with subsection (3). (Code SMECE d’EC)

EC Method A means the method known as Method A: Determination of Sampling Site and Traverse Points in Reference Method EPS 1/RM/8. (méthode A de l’EC)

EC Method B means the method known as Method B: Determination of Stack Gas Velocity and Volumetric Flow Rate in Reference Method EPS 1/RM/8. (méthode B de l’EC)

EC Method D means the method known as Method D: Determination of Moisture Content in Reference Method EPS 1/RM/8. (méthode D de l’EC)

engine means an engine that

EPA means the Environmental Protection Agency of the United States. (EPA)

EPA Method 1 means the method entitled Method 1 — Sample and Velocity Traverses for Stationary Sources, set out in Appendix A-1 to Part 60 of the CFR. (méthode 1 de l’EPA)

EPA Method 1A means the method entitled Method 1A — Sample and Velocity Traverses for Stationary Sources With Small Stacks or Ducts, set out in Appendix A-1 to Part 60 of the CFR. (méthode 1A de l’EPA)

EPA Method 2 means the method entitled Method 2 — Determination of Stack Gas Velocity and Volumetric Flow Rate (Type S pitot tube), set out in Appendix A-1 to Part 60 of the CFR. (méthode 2 de l’EPA)

EPA Method 3A means the method entitled Method 3A — Determination of Oxygen and Carbon Dioxide Concentrations in Emissions From Stationary Sources (Instrumental Analyzer Procedure), set out in Appendix A-2 to Part 60 of the CFR. (méthode 3A de l’EPA)

EPA Method 4 means the method entitled Method 4 — Determination of Moisture Content in Stack Gases, set out in Appendix A-3 to Part 60 of the CFR. (méthode 4 de l’EPA)

EPA Method 6C means the method entitled Method 6C — Determination of Sulfur Dioxide Emissions From Stationary Sources (Instrumental Analyzer Procedure), set out in Appendix A-4 to Part 60 of the CFR. (méthode 6C de l’EPA)

EPA Method 7E means the method entitled Method 7E — Determination of Nitrogen Oxides Emissions from Stationary Sources (Instrumental Analyzer Procedure), set out in Appendix A-4 to Part 60 of the CFR. (méthode 7E de l’EPA)

facility means the buildings, other structures and stationary equipment that are located on a single site or on adjacent sites that function as a single integrated site. (installation)

gaseous fuel means a fuel that is gaseous at a temperature of 15.6ºC and an absolute pressure of 101.325 kPa. (combustible gazeux)

gasoline means a petroleum distillate, or a blend of petroleum distillates, oxygenates or additives, that is suitable for use in a spark-ignition engine and that has the following characteristics, as determined by the applicable test method listed in the National Standard of Canada CAN/CGSB-3.5-2011, Automotive Gasoline:

heater means combustion equipment, other than a boiler, that is used or designed to transfer thermal energy from the combustion of a fuel to a material that is being processed outside the combustion chamber. (four industriel)

iron ore pelletizing facility means a facility that is used or designed to produce iron ore pellets from iron ore concentrate using an induration furnace. (installation de bouletage du minerai de fer)

iron, steel and ilmenite facility means a facility — other than a foundry that produces iron or steel castings — that is used or designed to produce at least one of the following products:

liquid petroleum product means

nitrogen-based fertilizer facility means a facility that is used or designed to manufacture at least one of the following substances:

NOx means oxides of nitrogen, which is the sum of nitric oxide (NO) and nitrogen dioxide (NO2). (NOx)

oil and gas facility means a facility, including an asphalt refinery or underground storage facility for gaseous fuel, that is used or designed

It does not include an oil sands facility, petroleum refinery, chemicals facility, nitrogen-based fertilizer facility or facility — other than an underground storage facility for gaseous fuel — that is primarily engaged in the local distribution of natural gas. (installation d’exploitation pétrolière et gazière)

oil sands facility means a facility — other than a chemicals facility, nitrogen-based fertilizer facility or asphalt refinery — that is used or designed to engage in at least one of the following activities:

operator means a person who has the charge, management or control of a boiler, heater, engine or cement manufacturing facility. (exploitant)

petroleum refinery means a facility at which the combined annual volume of gasoline, diesel fuel and lubricant basestock produced is greater than 40% of the annual volume of liquid petroleum products produced and that is used or designed to process, using distillation,

potash facility means a facility that is used or designed to produce potash, including a facility that is used or designed to extract potash-bearing ore. (installation de production de potasse)

power plant means a facility that is used or designed to produce electricity for sale via the electric grid as its primary activity. (centrale électrique)

ppmvd means parts per million, by volume on a dry basis. (ppmvs)

pulp and paper facility means a facility that is used or designed to produce

Reference Method EPS 1/RM/8 means the document entitled Reference Method for Source Testing: Measurement of Releases of Particulate from Stationary Sources, published in December 1993 by Her Majesty the Queen in right of Canada, as represented by the Minister. (Méthode de référence SPE 1/RM/8)

responsible person means an owner or operator of a boiler or heater, an engine or a cement manufacturing facility. (personne responsable)

SO2 means sulphur dioxide. (SO2)

thermal method means a method of crude oil or bitumen extraction that involves the introduction of thermal energy into a geological formation in order to enhance the fluidity of crude oil or bitumen and to facilitate its extraction. It includes steam-assisted gravity drainage, cyclic steam stimulation, Toe-to-Heel Air Injection (THAI®), in situ combustion, flooding with heated water, solvent-assisted thermal methods and electro-thermal methods. (méthode thermique)

underground storage facility for gaseous fuel means a facility — other than an oil sands facility, petrol refinery or asphalt facility — that is used or designed to store gaseous fuel underground. (installation de stockage souterrain de combustibles gazeux)

year means a calendar year. (année)

Interpretation of documents incorporated by reference

(2) For the purpose of interpreting any document that is incorporated by reference into these Regulations, “should” must be read to mean “must” and any recommendation or suggestion must be read as an obligation, unless the context requires otherwise. For greater certainty, the context of the accuracy or precision of a measurement can never require otherwise.

EC CEMS Code

(3) The EC CEMS Code is to be read as set out in Schedule 1.

Alberta CEMS Code

(4) The Alberta CEMS Code is to be read as set out in Schedule 2.

EPA discretion

(5) Any EPA method that is incorporated by reference into these Regulations must be read without reference to the exercise of discretion by the EPA or by the Administrator of the EPA.

Inconsistency

(6) In the event of an inconsistency between a provision of these Regulations and a document that is incorporated by reference into these Regulations, the provision prevails to the extent of the inconsistency.

Methods incorporated by reference

(7) Any method of the EPA or ASTM that is incorporated by reference into these Regulations is incorporated as amended from time to time.

Responsibility

Who must comply

3 Unless the context requires that a particular responsible person complies, a requirement set out in these Regulations in respect of, respectively, a boiler or heater, an engine or a cement manufacturing facility, including a requirement in respect of a kiln located in it, must be complied with by a responsible person for the boiler or heater, engine or cement manufacturing facility.

PART 1

Boilers and Heaters

Interpretation

Definitions

4 The following definitions apply in this Part and in Schedules 3 to 7.

alternative gas means a gaseous fossil fuel other than natural gas. (gaz de remplacement)

anode-baking furnace means a heater that bakes green anodes to produce blocks of carbon for use in the production of aluminum. (four de cuisson d’anodes)

ASTM D1945-03 means the method entitled Standard Test Method for Analysis of Natural Gas by Gas Chromatography, published by ASTM. (méthode ASTM D1945-03)

ASTM D1946-90 means the method entitled Standard Practice for Analysis of Reformed Gas by Gas Chromatography, published by ASTM. (méthode ASTM D1946-90)

biomass means a fuel that consists only of non-fossilized, biodegradable organic material that originates from plants or animals but does not come from a geological formation, notably

biomass boiler means a boiler that can reach its rated capacity by combusting only biomass. (chaudière à biomasse)

blast furnace stove means a vertical cylindrical regenerator filled with refractory and used to preheat ambient air that is then introduced into a blast furnace used in ironmaking. (récupérateur de haut fourneau)

CEMS test means a determination, by means of a CEMS in accordance with section 32, of the NOx emission intensity of a boiler or heater. (essai SMECE)

chemical recovery boiler means a boiler whose fuel includes spent pulping liquor and that recovers chemical constituents from the combustion of that spent pulping liquor. (chaudière de récupération chimique)

class 40, in relation to a pre-existing boiler or heater, describes a class 40 boiler or heater within the meaning of section 12. (classe 40)

class 70, in relation to a pre-existing boiler or heater, describes a class 70 boiler or heater within the meaning of section 12. (classe 70)

class 80, in relation to a pre-existing boiler or heater, describes a class 80 boiler or heater within the meaning of section 12. (classe 80)

coke oven means an oven that converts coal to coke through distillation. (four à coke)

coke oven battery means a heater that consists of a combustion chamber, with more than one burner, whose exhaust gas circulate between coke ovens. (batterie de fours à coke)

commercial grade natural gas means natural gas that is supplied by a commercial supplier. (gaz naturel de qualité commerciale)

commissioning date means the day on which a boiler or heater begins to produce thermal energy primarily for use in production or to provide heat. (date de mise en service)

ethylene cracker means a heater that transforms a mixture of steam and hydrocarbons into hydrocarbon gases, notably ethylene. (craqueur d’éthylène)

gaseous fossil fuel includes gaseous fossil fuel that is a by-product of an industrial process, or industrial operation, and that has constituents with thermal energy value. (combustible fossile gazeux)

heat-recovery steam generator means equipment that captures useful thermal energy from the hot exhaust gas of a gas turbine, or from a set of reciprocating engines, to produce steam. (générateur de vapeur à récupération de chaleur)

modern, in relation to a boiler or heater, describes a boiler or heater that is not transitional whose commissioning date is on or after the day on which these Regulations are registered. (moderne)

natural gas means a gaseous fossil fuel that consists of at least 90% methane by volume. (gaz naturel)

NOx emission intensity means the quantity of NOx emitted by a boiler or heater, expressed in grams of NOx emitted per gigajoule of thermal energy in the fuel (g/GJ), based on the higher heating value of the fuel combusted. (intensité d’émission de NOx)

packaged, in relation to a boiler or heater, describes a boiler or heater that is received at the facility in a state of near-complete assembly and that requires, at the facility,

pre-existing, in relation to a boiler or heater, describes a boiler or heater whose commissioning date is before the day on which these Regulations are registered. (préexistant)

preheated air means air that is preheated above ambient air temperature before it is introduced into the combustion chamber of a boiler or heater. (air préchauffé)

rated capacity, in relation to a boiler or heater, means the maximum thermal energy — based on the higher heating value of the fuel combusted — that the boiler or heater is, on its commissioning date, capable of producing in an hour, expressed in GJ/h, as specified on the nameplate affixed to the boiler or heater by its manufacturer or, in the absence of such a nameplate, as set out in a document provided by the manufacturer. (capacité nominale)

recommissioning date means the day on which a boiler or heater begins to produce thermal energy primarily for use in production or to provide heat after

reheat furnace means a heater in which steel is reheated for hot rolling into basic shapes. (four de réchauffage)

stack test means a determination, in accordance with sections 27 to 31, of the NOx emission intensity of a boiler or heater. (essai en cheminée)

standard m3 has the meaning assigned to a cubic metre at standard pressure and standard temperature by the definition standard volume in subsection 2(1) of the Electricity and Gas Inspection Regulations. (m3 normalisé)

steady state means an operating state that is other than start-up, shutdown or upset. (état stable)

steam methane reformer means a heater that transforms a mixture of steam and hydrocarbons in the presence of a catalyst to produce hydrogen and carbon oxides and includes — if it shares a common stack with the heater — any integrated auxiliary boiler that is used to produce that steam or other integrated equipment that heats that steam. (reformeur de méthane à la vapeur)

transitional, in relation to a boiler or heater, describes a boiler or heater that is located in a regulated facility set out in subsection 5(2) on its commissioning date and whose commissioning date occurs in the period that begins on the day on which these Regulations are registered and ends

Application

Rated capacity at least 10.5 GJ/h

5 (1) This Part applies in respect of a pre-existing, transitional or modern boiler or heater located in a regulated facility that is used or designed to combust gaseous fossil fuel and that has a rated capacity of at least 10.5 GJ/h.

Regulated facilities

(2) The following are the regulated facilities:

Excluded boilers and heaters

(3) Despite subsections (1) and (2), this Part does not apply in respect of the following types of boiler or heater:

Main Requirements

Modern boilers

6 (1) Subject to section 10, the NOx emission intensity of a modern boiler that, for a given hour, has at least 50% of the input energy in its combustion chamber resulting from the introduction of gaseous fossil fuel set out in column 1 of the table to this subsection and that has a thermal efficiency set out in column 2 must not, for that hour, exceed the limit set out in column 3.

TABLE

Modern Boilers — NOX Emission Intensity Limits

Item

Column 1


Gaseous Fossil Fuel

Column 2


Thermal Efficiency

Column 3



NOx Emission Intensity Limit (g/GJ)

1

Natural gas

< 80%

16

2

Natural gas

≥ 80% and ≤ 90%

16 + (E – 80)/5, where E is the thermal efficiency of the boiler

3

Natural gas

> 90%

18

4

Alternative gas

< 80%

20.8

5

Alternative gas

≥ 80% and ≤ 90%

20.8 + (E – 80)/4.54, where E is the thermal efficiency of the boiler

6

Alternative gas

> 90%

23
Thermal efficiency

(2) For the purpose of subsection (1), the thermal efficiency of a modern boiler for the given hour

Modern heaters

7 (1) Subject to section 10, the NOx emission intensity of a modern heater — that, for a given hour, has at least 50% of the input energy in its combustion chamber resulting from the introduction of gaseous fossil fuel set out in column 1 of the table to this subsection and that has a difference between the temperature of its preheated air and the ambient air set out in column 2 must not, for that hour, exceed the limit set out in column 3.

TABLE

Modern Heaters — NOX Emission Intensity Limits

Item

Column 1



Gaseous Fossil Fuel

Column 2

Difference between Temperature of Preheated Air and Ambient Air (°C)

Column 3



NOx Emission Intensity Limit (g/GJ)

1

Natural gas

0

16

2

Natural gas

> 0 and ≤ 150

16 × [1 + (2 x 10-4T) + (7 x 10-6T2)], where T is the difference, expressed in °C, between the temperature of its preheated air and the ambient air

3

Natural gas

> 150

19

4

Alternative gas

0

20.8

5

Alternative gas

> 0 and ≤ 155

20.8 × [1 + (2 x 10-4T) + (7 x 10-6T2)], where T is the difference, expressed in °C, between the temperature of its preheated air and the ambient air

6

Alternative gas

> 155

25
Preheated air

(2) For the purpose of subsection (1), the difference between the temperature of a modern heater’s preheated air and the ambient air, expressed in °C, for the given hour

Determination of type of gaseous fossil fuel

8 For the purpose of determining the type of gaseous fossil fuel — natural gas or alternative gas — introduced into the combustion chamber of a boiler or heater, the percentage of methane in the fuel must be determined in accordance with section 16.

Transitional boilers and heaters

9 The NOx emission intensity of a transitional boiler or heater that, for a given hour, has at least 50% of the input energy in its combustion chamber resulting from the introduction of gaseous fossil fuel must not, for that hour, exceed the following limit:

Redesigned boilers and heaters — NOx emission intensity

10 (1) The NOx emission intensity of a redesigned boiler or heater that, for a given hour, has at least 50% of the input energy in its combustion chamber resulting from the introduction of gaseous fossil fuel must not, for that hour, exceed the limit of 26 g/GJ.

Redesigned boilers and heaters

(2) A redesigned boiler or heater is one that

Class 80 and class 70

11 The NOx emission intensity of a pre-existing boiler or heater that is class 80 or class 70 — other than those referred to in subsections 13(1) and 14(1) and (2) — and that, for a given hour, has at least 50% of the input energy in its combustion chamber resulting from the introduction of gaseous fossil fuel must not, for that hour, exceed the limit of 26 g/GJ, as of

Pre-existing boilers and heaters — classification

12 (1) A pre-existing boiler or heater is classified — in accordance with its classification NOx emission intensity determined in accordance with subsection 34(1) or 35(1) or redetermined in accordance with subsection 36(1) or 37(1) — as follows:

Before classification — deemed class 80

(2) A pre-existing boiler or heater — other than a redesigned boiler or heater referred to in subsection 10(2) — that is not classified under subsection (1) is deemed to be class 80 and to have a classification NOx emission intensity of 80 g/GJ.

Major modifications — class 80 and class 70

13 (1) Subject to section 14, the NOx emission intensity of a class 80 or class 70 boiler or heater that has undergone a major modification before, respectively, January 1, 2026 or January 1, 2036 must not, as of its recommissioning date — for each hour during which at least 50% of the input energy in its combustion chamber results from the introduction of gaseous fossil fuel — exceed the limit of 26 g/GJ.

Major modifications

(2) A major modification is

Exception — impossibility

14 (1) The NOx emission intensity of a class 80 or class 70 boiler or heater that undergoes a major modification that involves the use of combustion modification techniques must, as of its recommissioning date following the major modification, not — for each hour during which at least 50% of the input energy in its combustion chamber results from the introduction of gaseous fossil fuel — exceed the limit of 50% of its classification NOx emission intensity, if

Major modification before registration

(2) The NOx emission intensity of a class 80 or class 70 boiler or heater referred to in clause 34(1)(b)(i)(B) that has undergone a major modification that involved the use of combustion modification techniques must, as of the day that is 12 months after the day on which these Regulations are registered, not — for each hour during which at least 50% of the input energy in its combustion chamber results from the introduction of gaseous fossil fuel — exceed the limit of 50% of its classification NOx emission intensity, if

Combustion modification techniques

(3) For the purpose of this section, combustion modification techniques are techniques to reduce the formation of thermal NOx in the combustion chamber of a boiler or heater by modifying the combustion process. They include the use of low-NOx burners and of flue gas recirculation.

Quantification

Elements of Requirements
Input energy from gaseous fossil fuel

15 The percentage of the input energy in a boiler’s or heater’s combustion chamber resulting from the introduction of gaseous fossil fuel, for a given hour while the boiler or heater is in a steady state, must be determined by the formula

(Ecng + Egff)/(Ecng + Egff + Eo + Es) × 100

where

Ecng is the input energy resulting from the introduction of commercial grade natural gas for the given hour, determined by the formula

Qcng × HHVcng

where

Qcng is the quantity of the commercial grade natural gas combusted during the given hour, as measured by a flow meter on the input, expressed in standard m3, and

HHVcng is the higher heating value of the commercial grade natural gas combusted during the given hour, expressed in GJ/standard m3, being

Egff is the input energy resulting from the introduction of gaseous fossil fuel, other than commercial grade natural gas, for the given hour, determined by the formula

Qgff × HHVgff

where

Qgff is the quantity of the gaseous fossil fuel, other than commercial grade natural gas, combusted during the given hour, as measured by a flow meter on the input, expressed in standard m3, and

HHVgff is the higher heating value of the gaseous fossil fuel, other than commercial grade natural gas, combusted during the given hour, expressed in GJ/standard m3, determined in accordance with any of the required HHV methods set out in section 22 that apply;

Eo is the input energy resulting from the introduction of a fuel other than gaseous fossil fuel during the given hour, determined by the formula

Σi(Qi × HHVi)

where

Qi is the quantity of the ith fuel other than gaseous fossil fuel combusted during the given hour as measured by a flow meter on the input, expressed in a given unit,

HHVi is the higher heating value of the ith fuel other than gaseous fossil fuel combusted during the given hour, expressed in GJ/the given unit, being

i is the ith fuel other than gaseous fossil fuel combusted, where i goes from 1 to n and where n is the number of those fuels combusted; and

Es is the input energy, expressed in GJ, that originates from a source other than the combustion of fuel in the boiler’s or heater’s combustion chamber during the given hour, determined in accordance with generally accepted engineering principles.

Type of Gas
Percentage of methane

16 (1) The percentage of methane in the gaseous fossil fuel introduced into the combustion chamber of a boiler or heater, for a given hour, must be determined, by volume, as a weighted average by the formula

[(CH4 ng × Qng) + (CH4 alt × Qalt)] × 100/(Qng + Qalt)

where

Gas introduced into combustion chamber

(2) The concentration of methane in the gaseous fossil fuel introduced into the combustion chamber is

Fixed HHV of commercial grade natural gas

17 If the concentration of methane in the commercial grade natural gas introduced into the combustion chamber is fixed as 95%, in accordance with subparagraph 16(2)(a)(ii), the higher heating value of the commercial grade natural gas must, for the purpose of paragraph 29(b), be fixed as 0.03793 in accordance with subparagraph (a)(ii) of the description of HHVi in that paragraph.

Thermal Efficiency
Modern boiler

18 The thermal efficiency of a modern boiler, for a given day, must be determined by the formula

100% – Ldfg – Lw – Lrc – Lo

where

Ldfg is the percentage of loss of thermal efficiency due to the thermal energy contained in the boiler’s flue gas determined on a dry basis for an hour in the given day, determined in accordance with section 19;

Lw is the percentage of loss of thermal efficiency due to the thermal energy contained in the water in the boiler’s flue gas for an hour in the given day, determined in accordance with section 20;

Lrc is the percentage of loss of thermal efficiency due to radiation and to convection of the boiler’s surfaces for an hour in the given day, being

Lo is the percentage of loss of thermal efficiency due to other sources, which is deemed to be 0.1%.

Determination of Ldfg

19 Ldfg referred to in section 18 must be determined for an hour in the given day by the formula

1.005 × (Tg – Ti)/HHVm × Mg × 100

where

Tg is the average temperature, expressed in °C, of the flue gas, as measured in the stack, during that hour;

Ti is the average temperature , expressed in °C, of the air introduced into the combustion chamber during that hour;

HHVm is the higher heating value of the fuel combusted during that hour, expressed on a mass basis in kJ/kg, being

Mg is the average ratio of the mass of the flue gas to the mass of the fuel combusted, expressed in kg/kg, during that hour, determined by the formula

0.962 × [1 + %O2/(20.9 – %O2)] × Ms

where

%O2 is the percentage of oxygen, determined by volume on a dry basis, in the flue gas, determined in accordance with EPA Method 3A or ASTM D6522-11,

Ms is the ratio of the stoichiometric mass of the flue gas to the mass of the fuel combusted, expressed in kg/kg, being

12.492C + 26.296H + N + 5.305S – 3.313O

Determination of Lw

20 Lw referred to in section 18 must be determined for an hour of the given day by the formula

8.94H × [2450 + 1.989(Tg – Ti)]/HHVm × 100

where

H is the concentration of hydrogen in the fuel combusted during that hour, expressed in kg of hydrogen per kg of that fuel, being

Tg is the average temperature, expressed in °C, of the flue gas, as measured in the stack during that hour;

Ti is the average temperature, expressed in °C, of the air introduced into the combustion chamber during that hour; and

HHVm is the higher heating value of the fuel combusted during that hour, expressed on a mass basis in kJ/kg, being

Commercial grade natural gas — determined or fixed

21 The value for commercial grade natural gas for HHVm in sections 19 and 20, for Ms in section 19 and for H in section 20 must all be either

Required HHV methods

22 The required HHV methods are

Constituents of fuel

23 (1) The concentration of carbon, hydrogen, nitrogen, sulphur and oxygen per kilogram of fuel introduced into the combustion chamber must be determined as a weighted average of the concentration of each of the constituents of each fuel in accordance with subsection (2).

Required concentration standards and calculation methods

(2) The concentration of the constituents of fuel must be determined

Difference of temperature — preheated air

24 For a modern heater that is equipped to preheat air, the difference between the temperature of its preheated air and the ambient air, for a given hour, must be determined by the formula

Tp − Ta

where

Tp is the average temperature, expressed in °C, of the heater’s preheated air introduced into the combustion chamber during the given hour, as measured at the point of introduction to the combustion chamber; and

Ta is the average temperature, expressed in °C, of the ambient air introduced into the preheater during the given hour, as measured at the point of introduction to the air preheater.

Determination of NOx Emission Intensity
Stack Test or CEMS Test

Conditions

25 The NOx emission intensity of a boiler or heater must be determined by means of

Identification — exception to paragraph 25(b)

26 (1) The NOx emission intensity of a boiler or heater that is to be determined under paragraph 25(b) must be determined for a given hour in accordance with subsection (2), if the boiler or heater

Greater of stack test and CEMS test

(2) The NOx emission intensity of a boiler or heater referred to in paragraph (1)(a) for each hour is the greater of

Identification

(3) A boiler or heater referred to in paragraph (1)(a) may be identified with another boiler or heater referred to in paragraph (1)(b) if the following conditions are met:

When identification made

(4) The identification is made as of

Identification by recording

(5) The identification is made on the recording of the following information:

At most four identifications

(6) At most four boilers or heaters may be identified under subsection (5) with a given other boiler or heater referred to in paragraph (1)(b).

Stack Tests

Three test runs

27 (1) A stack test consists of three consecutive test runs conducted within a period of 48 hours, each of which lasts at least 30 minutes and results in a determination of the boiler’s or heater’s NOx emission intensity .

Operating conditions for test runs

(2) The test runs must be conducted while the boiler or heater meets the following conditions:

Concentrations of NOx and O2

28 (1) For each test run, the measurements of the concentration of NOx, expressed in ppmvd, and the concentration of O2, expressed as a percentage determined by volume on a dry basis, in the boiler’s or heater’s flue gas must be made simultaneously and in accordance with either

Exception — EC Method A

(2) Despite subsection (1), the location of the sampling port and its traverse points may be determined for the purpose of that subsection in accordance with EC Method A.

Determination of NOx emission intensity

29 Based on the concentrations of NOx and O2 as measured in accordance with section 28, the NOx emission intensity, expressed in g/GJ, of the boiler or heater must be determined for each test run

(NOx × 1.88 × 10-3 × Fg)/Σi(Fi × HHVi)

where

NOx is the concentration of NOx ,

Fg is the flow rate of the flue gas, expressed in m3/h at 25°C and 101.325 kPa, as measured in the test run and determined in accordance with EPA Method 4 or EC Method D and converted to its flow rate on a dry basis in accordance with EPA Method 2 or EC Method B,

Fi is the flow rate of the ith fuel combusted, expressed for a solid or liquid fuel in a given unit/h and for a gaseous fuel in m3/h at 25°C and 101.325 kPa ,

HHVi is the higher heating value of the ith fuel combusted, being

i is the ith fuel combusted, where i goes from 1 to n and n is the number of fuels combusted.

NOx emission intensity — average

30 The NOx emission intensity of the boiler or heater determined by means of a stack test is the average of the three determinations — one for each test run — of its NOx emission intensity.

NOx emission intensity — deemed hours

31 The average referred to in section 30 is deemed to be the NOx emission intensity of the boiler or heater

Continuous Emission Monitoring System

Rolling hourly average

32 (1) Subject to subsection (3), the NOx emission intensity of a boiler or heater determined by means of a CEMS for a given hour is the rolling hourly average for the given hour in an averaging period, established as follows:

Averaging period

(2) The averaging period is each period that consists of consecutive hours when at least 50% of the input energy in the boiler’s or heater’s combustion chamber results from the introduction of gaseous fossil fuel.

Modern — new averaging period

(3) For a modern boiler or heater, a new averaging period begins whenever the type of gaseous fossil fuel changes from natural gas to alternative gas, or vice versa.

Reference period — new averaging period

(4) Despite subsections (2) and (3), an averaging period begins when a reference period begins — and an averaging period ends when a reference period ends — for an initial test, a determination or redetermination of a classification NOx emission intensity, a compliance test or a change report in respect of a change referred to in paragraph 43(1)(e) or (f).

Hourly NOx emission intensity

(5) The hourly NOx emission intensity for a given hour is the average over the hour of the NOx emission intensities of the boiler or heater, determined in accordance with

Testing

Initial test

33 (1) During the reference period described in subsections (3) and (4), an initial test must be conducted to determine the NOx emission intensity of a boiler or heater referred to in any of sections 6, 7, 9 to 11, 13 and 14, whether or not it is subject to a limit referred to in that section for any hour of the reference period.

Stack test or CEMS test

(2) The boiler’s or heater’s NOx emission intensity for the initial test must be determined

Beginning of reference period

(3) The reference period begins on

End of reference period

(4) The reference period ends on the earlier of

Periods for stack test determinations

(5) An initial test that is conducted by means of one or more stack tests must include at least one stack test that is conducted during each of the following periods within the reference period:

Determination of type of fuel

(6) The type of fuel — natural gas or alternative gas — that is combusted in a boiler’s or heater’s combustion chamber must be determined for each hour during the initial test.

Classification NOx emission intensity — on registration

34 (1) The classification NOx emission intensity of a pre-existing boiler or heater — in respect of which this Part applies on the day on which these Regulations are registered and that has not undergone a major modification since that day — must, during the reference period that consists of the 12-month period that begins on that day, be determined

Identification

(2) A boiler or heater for which a record is to be made of the assignment of its classification NOx emission intensity in accordance with subparagraph (1)(b)(iii), (iv) or (v) may be identified with each of the other boilers or heaters referred to in that subparagraph if it and all of the other boilers and heaters meet the following conditions:

Identification by recording

(3) The identification is made on the recording of the following information:

At most four identifications

(4) At most four boilers or heaters may be identified under subsection (3) with a given other boiler or heater referred to in clause (1)(b)(iii)(B) or (iv)(B).

Classification NOx emission intensity — after registration

35 (1) The classification NOx emission intensity of a pre-existing boiler or heater, other than a redesigned boiler or heater referred to in subsection 10(2), — in respect of which this Part first applies, other than because of a relocation, after the day on which these Regulations are registered and on or before December 31, 2022 and that has not undergone a major modification — must be determined by making a record of

Six months or December 31, 2022

(2) The determination must be made by the earlier of

Redetermination after election under subparagraph 34(1)(b)(vi)

36 (1) The classification NOx emission intensity of a boiler or heater for which an election under subparagraph 34(1)(b)(vi) is made to have a classification NOx emission intensity of 80 g/GJ assigned to it may, until December 31, 2022, be redetermined during a reference period described in subsection (3).

Stack test or CEMS test

(2) The redetermination must be made by means of

Reference period

(3) The reference period for the redetermination begins on the day on which these Regulations are registered and ends on the day that is chosen by a responsible person for the boiler or heater.

Redetermination — NOx emission intensity

(4) The classification NOx emission intensity that is redetermined under subsections (1) to (3) replaces the classification NOx emission intensity of 80 g/GJ assigned as a result of the election made under subparagraph 34(1)(b)(vi).

Redetermination after triggering event

37 (1) Subject to subsection (6), the classification NOx emission intensity of the following boilers or heaters must be redetermined after the occurrence of a triggering event:

Replacement

(2) The redetermination under subsection (1) replaces the most recent classification NOx emission intensity for the boiler or heater determined under subsection 34(1) or 35(1) or redetermined under subsection 36(1) only if the redetermined classification NOx emission intensity is greater than that most recent classification NOx emission intensity.

Triggering event

(3) There are two kinds of triggering event, namely,

Redetermination

(4) The redetermination is to be made in accordance with paragraph 34(1)(a) or any of subparagraphs 34(1)(b)(i) to (vi) during a reference period referred to in subsection (5) while the boiler or heater is

Reference period

(5) The reference period begins on the day on which the triggering event occurs and ends on the earlier of

Only one redetermination

(6) For each kind of triggering event described in subsection (3), only one redetermination must be made under subsection (1), no matter how many triggering events of that kind may occur.

Compliance tests — stack or CEMS test

38 (1) During a reference period referred to in subsection (4), a compliance test must be conducted to determine the NOx emission intensity of a boiler or heater that has a rated capacity of greater than 105 GJ/h if

Stack test or CEMS test

(2) The NOx emission intensity for the compliance test must be determined

Stack and CEMS tests — first compliance test

(3) Despite paragraph (2)(b), if the NOx emission intensity of a boiler or heater that has a rated capacity of more than 262.5 GJ/h — as determined for the initial test conducted under section 33 by means of one or more stack tests — is at least 80% of the NOx emission intensity limit applicable to the boiler or heater under any of sections 6, 7, 9 to 11, 13 and 14, 9 to 11, 13 and 14, the boiler’s or heater’s NOx emission intensity in respect of the reference period for the first compliance test conducted under this section must be determined by means of

Reference period

(4) The reference period is

Periods for stack test determinations

(5) A compliance test conducted on a boiler or heater under subparagraph (2)(a)(i) or (c)(i) or paragraph (3)(a) must include at least one stack test that is conducted during each of the following periods within the reference period for the compliance test:

Determination of type of fuel

(6) The type of fuel — natural gas or alternative gas — that is combusted in a boiler’s or heater’s combustion chamber must be determined for each hour during the compliance test.

Operation, Maintenance and Design

Specifications

39 A boiler or heater must be operated and maintained in accordance with the specifications set out by its manufacturer or required by its design.

Reporting

Initial report

40 An initial report in respect of an initial test conducted under section 33 that contains the information set out in Schedule 6 must be provided to the Minister not later than the June 1 following the end of the reference period for the initial test.

Classification reports — sections 34 and 35

41 (1) A classification report — in respect of a determination of a boiler’s or heater’s classification NOx emission intensity made under subsection 34(1) or 35(1) — that contains the information set out in Schedule 5 must be provided to the Minister not later than

Classification reports — 2023, 2024 and 2025

(2) A classification report — in respect of a pre-existing boiler or heater that, in 2023, 2024 or 2025, is deemed under subsection 12(2) to be class 80 and to have a classification NOx emission intensity of 80 g/GJ — that contains the information set out in Schedule 5 must be provided to the Minister by the earlier of

Compliance report

42 (1) A compliance report — in respect of a boiler or heater that has a rated capacity of more than 105 GJ/h and for which an initial report has been provided under section 40 — that contains the information set out in Schedule 7 must be provided to the Minister in respect of the following reporting period:

June 1

(2) The compliance report must be provided by the June 1 following the end of the reporting period.

Change report

43 (1) If the information in respect of a boiler or heater that was provided in a report changes, a change report must be provided to the Minister that identifies the name of the boiler’s or heater’s manufacturer, along with its serial number, make and model, and that contains the updated information, as follows:

Reference period

(2) For a change referred to in paragraph (1)(e) or (f), or a subsequent change referred to in subsection (4), the reference period begins on the day on which the boiler or heater begins to combust gaseous fossil fuel after the change and ends on the day that is six months after that day.

Subsequent change of gaseous fossil fuel

(3) No matter how many subsequent changes in the type of gaseous fossil fuel combusted — from natural gas to alternative gas, or vice versa — may occur, no further reports are required to be provided after the change report referred to in paragraph (1)(e) is provided.

Subsequent change after other change

(4) Despite subsection (3), if a change referred to in paragraph (1)(f) occurs and there is also a subsequent change in the type of gaseous fossil fuel combusted as compared to the type of gaseous fossil fuel combusted during the determination referred to in that paragraph, the result of a determination — under section 25 of the boiler’s or heater’s NOx emission intensity made in the reference period when the type of gaseous fossil fuel combusted was natural gas or alternative gas, whichever type was not combusted during the determination provided in the most recent report before that subsequent change — must be provided to the Minister within six months after the end of the reference period.

Recording of Information

Record-making

44 Records in respect of a boiler or heater that contain the following information and documents must be made:

PART 2

Stationary Spark-ignition Engines

Interpretation

Definitions

45 The following definitions apply in this Part and in Schedules 8 to 10.

ASTM D6348-12e1 means the method entitled Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy, published by ASTM. (méthode ASTM D6348-12e1)

EC Method AP-77-3 means the method entitled Standard Reference Methods for Source Testing: Measurement of Emissions of Nitrogen Oxides from Stationary Sources AP-77-3, published in April 1979 by Her Majesty the Queen in right of Canada, as represented by the Minister. (méthode AP-77-3 d’EC)

emergency means a situation during which an engine is operated

emissions check means a determination in accordance with sections 80 to 84 and 86 to 89 of the concentration of NOx in the exhaust gas of an engine. (vérification des émissions)

engine registry means the engine registry established under section 97. (registre des moteurs)

EPA Method 7 means the method entitled Method 7 — Determination of Nitrogen Oxide Emissions from Stationary Sources, set out in Appendix A-4 to Part 60 of the CFR. (méthode 7 de l’EPA)

EPA Method 7A means the method entitled Method 7A — Determination of Nitrogen Oxide Emissions from Stationary Sources — Ion Chromatographic Method, set out in Appendix A-4 to Part 60 of the CFR. (méthode 7A de l’EPA)

EPA Method 7C means the method entitled Method 7C — Determination of Nitrogen Oxide Emissions from Stationary Sources — Alkaline-Permanganate/Colorimetric Method, set out in Appendix A-4 to Part 60 of the CFR. (méthode 7C de l’EPA)

EPA Method 19 means the method entitled Method 19 — Determination of Sulfur Dioxide Removal Efficiency and Particulate, Sulfur Dioxide and Nitrogen Oxides Emission Rates, set out in Appendix A-7 to Part 60 of the CFR. (méthode 19 de l’EPA)

EPA Method 320 means the method entitled Method 320 — Measurement of Vapor Phase Organic and Inorganic Emissions by Extractive Fourier Transform Infrared (FTIR) Spectroscopy, set out in Appendix A to Part 63 of the CFR. (méthode 320 de l’EPA)

group means a notional collection of engines that are designated in accordance with section 56 as belonging to a responsible person’s group and, for the purpose of sections 60 to 68, includes a replacement unit referred to in section 64. (groupe)

lean-burn describes an engine other than a rich-burn engine. (à mélange pauvre)

low-use describes an engine that is referred to in section 50 as being low-use. (à faible utilisation)

modern describes an engine that is referred to in subsection 46(3). (moderne)

NOx emission intensity means the quantity of NOx emitted in the exhaust gas of an engine as represented by

performance test means a determination, in accordance with sections 70 to 75, of the NOx emission intensity of an engine. (essai de rendement)

ppmvd15% means parts per million, by volume on a dry basis and corrected to 15% oxygen. (ppmvs15%)

pre-existing describes an engine that is referred to in subsection 46(2). (préexistant)

rated brake power means the maximum brake power of an engine or a replacement unit as specified by its manufacturer either on its nameplate or otherwise. (puissance au frein nominale)

regular-use describes an engine referred to in section 50 as being regular-use. (à utilisation régulière)

rich-burn describes an engine for which the oxygen content in the exhaust gas, before any dilution, is less than 4%, determined by volume on a dry basis. (à mélange riche)

SCADA system means a computer system, known as a supervisory control and data acquisition system, that measures an engine or replacement unit’s operating state, manages the parameters controlling its operating state and stores data related to its operating state. (système SCADA)

still gas means a gas that is produced by distillation, cracking or reforming in a petroleum refinery, in an asphalt refinery or in an oil sands facility that is used or designed to engage in the activity of upgrading. (gaz de distillation)

subgroup means a notional collection of pre-existing engines and replacement units that belong to a responsible person’s group established in accordance with section 65. (sous-groupe)

subset means a notional collection of engines that belong to a responsible person’s group described in section 59. (sous-ensemble)

synthetic gas means a gas that is derived from the gasification of coal or from the gasification of by-products, residual products or waste products of an industrial process. (gaz de synthèse)

Application

Pre-existing and modern engines

46 (1) This Part applies in respect of a pre-existing or modern engine, located in a regulated facility, that combusts gaseous fuel.

Pre-existing engines

(2) An engine is pre-existing if one of the following dates is before the 90th day after the day on which these Regulations are registered:

Modern engines

(3) An engine is modern if it is not pre-existing.

Regulated facilities — modern engines

(4) The following are the regulated facilities in respect of modern engines:

Regulated facilities — pre-existing engines

(5) Oil and gas facilities, other than asphalt refineries, are the regulated facilities in respect of pre-existing engines.

Non-application — low revenue and power

47 (1) This Part does not apply in respect of a pre-existing engine for a period of 36 months after the first day on which the following conditions are met:

Extension

(2) A period of non-application referred to in subsection (1) is extended by 36 months if, on a day that occurs within the last six months of that period,

Meaning of gross revenue

(3) In paragraph (1)(b) and Schedule 8, gross revenue has the same meaning as in section 248 of the Income Tax Act.

Meaning of affiliates

(4) In paragraph (1)(b) and Schedule 8, affiliates has the same meaning as in subsection 2(1) of the Canada Business Corporations Act.

Non-application — new owners

48 (1) Subject to subsection (3), this Part does not apply in respect of a pre-existing engine to an owner of it for a period of at most 275 days after the date on which they become its owner, if

End of period of non-application

(2) The period of non-application under subsection (1) ends on the first day that is within those 275 days on which the following conditions are met:

No period of non-application

(3) There is no period of non-application under subsection (1) if the conditions set out in subsection (2) are not met within those 275 days.

Synthetic gas and still gas

49 Sections 54, 55, 57 and 58, paragraph 59(1)(b) and section 68 do not apply in respect of an engine — for any period during which the fuel combusted consists of more than 50% synthetic gas, still gas or any combination of those gases — if records are kept that establish, based on a calculation of the mass flow, that the fuel combusted in that period consists of that proportion of those gases.

General

Regular-use engines

50 Every engine that has operated for at least one hour during a year is a regular-use engine unless an election is in effect to have the engine be low-use.

Low-use engines — election

51 (1) The election is made when a responsible person for the engine provides to the Minister a notice of the election for inclusion in the engine registry that specifies the year as of which the election takes effect, which may be

Obligations under an election

(2) An engine for which an election is in effect must

Election ceases to be in effect

(3) An election ceases to be in effect if

Re-election

(4) Nobody who is a responsible person for the engine when an election ceases to be in effect may re-elect to have the engine be low-use before January 1 of the year that begins at least three years after that election took effect.

Designation as rich-burn engine

52 (1) An engine that is designated by its manufacturer as being a rich-burn engine is presumed to be a rich-burn engine.

Rebuttal — lean-burn engine

(2) The presumption is rebutted if the responsible person for the engine establishes that the oxygen content in the exhaust gas, before any dilution, is at least 4%, determined by volume on a dry basis.

Applicable units — NOx emission intensity limit

53 The applicable NOx emission intensity limit for an engine referred to in section 54, 57 or 58 or paragraph 59(1)(b) is the limit that is expressed in

Modern Engines

Regular-use — limit

54 The NOx emission intensity of a modern engine that is regular-use and has a rated brake power of at least 75 kW must not exceed the limit of 160 ppmvd15% or 2.7 g/kWh, whichever applies.

Low-use — limit

55 The NOx emission intensity of a modern engine that is low-use and has a rated brake power of at least 100 kW must not exceed the limit of 160 ppmvd15%.

Pre-existing Engines

Groups
Establishment

56 (1) For the purposes of sections 58 to 68, a responsible person for pre-existing engines that are regular-use and have a rated brake power of at least 250 kW establishes their group by designating which of those engines is to belong to the group.

One group

(2) A responsible person may have at most one group.

Designation date

(3) An engine is designated as belonging to a responsible person’s group as of

Ceasing to belong

(4) An engine that belongs to a responsible person’s group ceases to belong to the group if

Deemed not belonging to any group

(5) An engine that has been designated as belonging to more than one group is deemed not to belong to any group.

NOx Emission Intensity Limits
Engines not belonging to a group

57 As of January 1, 2021, the NOx emission intensity of a pre-existing engine that is regular-use, has a rated brake power of at least 250 kW and does not belong to any group must not exceed the limit of 210 ppmvd15% or 4 g/kWh, whichever applies.

Engines belonging to a group after 2025

58 Subject to section 60, as of January 1, 2026, the NOx emission intensity of an engine that belongs to a group must not exceed the limit of 210 ppmvd15% or 4 g/kWh, whichever applies.

Engines belonging to a group from 2021 to 2025

59 (1) Subject to section 60, in the period that begins on January 1, 2021 and ends on December 31, 2025, within each group of engines there must be a subset of engines that has the following characteristics:

Ceasing to belong

(2) For the purpose of paragraph (1)(a), even if an engine that has been registered under subsection 97(3) ceases to belong to the group, its rated brake power may be included in the total rated brake power of both the subset referred to in paragraph (1)(a) and the group.

Yearly Average NOx Emission Intensity Limits — on Election
After 2025 and from 2021 to 2025

60 A responsible person who makes an election in accordance with subsection 61(1) to opt out of the application of section 58 or 59 must — for each year after 2020 that follows the making of the election — ensure that the yearly average NOx emission intensity of each subgroup that they establish under section 65 does not exceed the following limit:

Election

61 (1) The responsible person must — by the October 31 immediately before the first year in respect of which the limit referred to in section 60 is to apply — make the election by providing the Minister with the following information for inclusion in the engine registry for each subgroup that they establish under section 65:

Yearly average NOx emission intensity

(2) The yearly average NOx emission intensity of a subgroup for a year is determined by the formula

ΣiΣj(Eij ×Pi × Tij)/ΣiΣj(Pi × Tij)

where

Eij is the jth NOx emission value, expressed in ppmvd15% or g/kWh, assigned under subsection 66(1) or 67(1) to the ith engine or replacement unit that belongs to the subgroup;

Pi is the rated brake power, expressed in kW, of the ith engine or replacement unit that belongs to the subgroup;

Tij is — excluding any period referred to in section 49 —

i is the ith engine or replacement unit that belongs to the subgroup, where i goes from 1 to m and where m is the number of those engines and replacement units that belong to the subgroup; and

j is the jth assignment under subsection 66(1) or 67(1) of a NOx emission value to the ith engine or replacement unit that belongs to the subgroup, where j goes from 1 to n and where n is the number of assignments of NOx emission values under those subsections to that engine or replacement unit during the year.

Number of hours

(3) The number of hours during a year referred to in paragraph (a) of the description of Tij in subsection (2) must be determined

Continuous operation

(4) The non-resettable hour meter, the other non-resettable device or the SCADA system must operate continuously, other than during periods when it is undergoing normal servicing or timely repairs.

Revocation — on notice

62 (1) A responsible person may revoke their election by providing the Minister with a notice of revocation for inclusion in the engine registry by October 31 of a given year.

Applicable limits

(2) As of the first year that begins after the day on which the notice was provided,

Revocation — after conviction

63 (1) An election that is made by a responsible person who is convicted of an offence under the Act in respect of these Regulations is revoked on the January 1 that follows the period of 36 months after their conviction.

After revocation

(2) As of the revocation,

Replacement units

64 (1) For the purpose of section 60, the responsible person may replace in their group any pre-existing engine that ceases to belong to it by an eligible replacement unit if

Eligible replacement units

(2) The following are eligible replacement units:

Ceasing to belong

(3) A replacement unit that no longer meets a condition that is set out in paragraph (1)(c) or (d) ceases to belong to the responsible person’s group.

Effective date of replacement

(4) The replacement of the pre-existing engine by the replacement unit takes effect on the day on which the responsible person provides the Minister with the following information for inclusion in the engine registry:

Reintroduction of replaced engines

(5) A pre-existing engine that has been replaced may be reintroduced into the responsible person’s group if replacement units — having a total rated brake power that is at least the rated brake power of the engine — are removed from the group.

Designation of subgroups

65 (1) A responsible person who is subject to a limit set out in section 60 must establish one or more subgroups by, for each subgroup,

Engines in subgroups

(2) Each pre-existing engine and replacement unit that belongs to their group must be included in exactly one subgroup.

Designation date

(3) An engine or replacement unit is designated as belonging to the subgroup as of

Engine registry

(4) For each of those designations, the responsible person must, by July 1 of the year after the year that includes the date of the designation, provide the Minister with the information that is contained in the record described in paragraph (3)(a) or (b) for inclusion in the engine registry.

Assignment of default NOx emission value

66 (1) Subject to section 67, the applicable default NOx emission value that is set out in subsection (2) is assigned to a pre-existing engine or replacement unit that belongs to a subgroup of a responsible person who is subject to a limit set out in section 60.

Default NOx emission values

(2) The default NOx emission value — expressed in the same units, ppmvd15% or g/kWh, that are selected under paragraph 65(1)(c) for the subgroup to which the pre-existing engine or replacement unit belongs — is

Assignment 90 days earlier

(3) Despite subsection (1) and subparagraph (2)(a)(i), the default NOx emission value referred to in that subparagraph is, under subsection (1), assigned to a pre-existing four-stroke lean-burn engine on the date on which the responsible person for the engine became its owner, if the conditions described in clauses (2)(a)(i)(A) to (C) are met in respect of the engine and that responsible person at most 90 days after that date.

Assignment of non-default NOx emission value

67 (1) A NOx emission value that is different from the default NOx emission value set out in subsection 66(2) may be assigned to a pre-existing engine, or a replacement unit that is a modern engine, if

Taking effect of assignment

(2) The assignment takes effect as of

NOx emission intensity limit — non-default NOx emission values

68 A responsible person who assigns a NOx emission value to an engine that is different from its default NOx emission value must, as of that assignment, ensure that its NOx emission intensity — expressed in the same units, ppmvd15% or g/kWh, that are selected under paragraph 65(1)(c) for the subgroup to which the engine belongs — does not exceed a limit that is that different NOx emission value.

Determination of NOx Emission Intensity

Performance Tests
NOx emission intensity limits

69 For the purpose of sections 54, 55, 57 and 58, paragraph 59(1)(b) and section 68, the NOx emission intensity of an engine must be determined by means of a performance test.

Three test runs

70 (1) A performance test consists of three consecutive test runs conducted within the same day, each of which lasts at least 20 minutes and results in a determination of the engine’s NOx emission intensity.

Operating conditions for test-runs

(2) Each test run must be conducted while the engine is

Sampling ports

71 (1) The location of the sampling port, and its traverse points, in the exhaust pipe for each test run must be determined in accordance with

Pre-existing engines without sampling port

(2) If a pre-existing engine does not have a sampling port that meets the requirements of any of those methods, each test run must

After-treatment control devices

(3) If an after-treatment control device is used, either

Concentration of NOx

72 (1) The concentration of NOx in the engine’s exhaust gas for each test run must be determined in accordance with

Concentration of O2

(2) The concentration of O2 in the engine’s exhaust gas for each test run must be determined in accordance with

Moisture content

(3) For each test run, if the concentration of NOx in the engine’s exhaust gas is measured on a wet basis or if the NOx emission intensity of the engine is to be expressed in g/kWh, the moisture content in that gas must be determined in accordance with

Volumetric flow rate

(4) If the NOx emission intensity of the engine is to be expressed in g/kWh, the volumetric flow rate of the engine’s exhaust gas must be expressed in m3/h, at 25°C and 101.325 kPa, and be determined in accordance with

Simultaneous measurement

(5) For each test run, the following measurements must be taken simultaneously at the same traverse point in accordance with section 71:

ppmvd15%

73 If the NOx emission intensity of the engine is to be expressed in ppmvd15%, it must be determined for each test run by the formula

5.9Cd/(20.9 – %O2)

where

Cd is the concentration of NOx in the engine’s exhaust gas, expressed in ppmvd, determined at a given percentage of oxygen (%O2) in accordance with subsection 72(1); and

%O2 is the number that represents the percentage of oxygen in the engine’s exhaust gas as determined by volume on a dry basis, based on the concentration of O2 determined in accordance with subsection 72(2).

g/kWh

74 (1) If the NOx emission intensity of the engine is to be expressed in g/kWh, it must be determined for each test run by the formula

(1.88 × 10-3 × C × Q × T)/BW

where

C is the concentration of NOx in the engine’s exhaust gas, expressed in parts per million by volume, determined at a given percentage of oxygen (%O2) in accordance with subsection 72(1);

Q is the volumetric flow rate of the engine’s exhaust gas, expressed in m3/h, determined in accordance with subsection 72(4);

T is the duration of the test run, expressed in hours to two decimal places; and

BW is the brake work of the engine during the test run, expressed in kWh.

Wet or dry basis

(2) The elements C and Q described in subsection (1) must be expressed on the same basis, whether wet or dry.

NOx emission intensity — average

75 The NOx emission intensity of the engine determined by means of a performance test is the average of the three determinations — one for each test run — of its NOx emission intensity.

NOx emission intensity — deemed days

76 The average described in section 75 is deemed to be the NOx emission intensity of the engine

Performance tests

77 In addition to a performance test referred to in section 69, a performance test to determine the NOx emission intensity, expressed in ppmvd15% or g/kWh, of a regular-use engine must be conducted

Subsequent performance test

78 An engine with a rated brake power of at least 375 kW on which a performance test has been conducted under section 77 or this section must have a subsequent performance test conducted to determine its NOx emission intensity, expressed in ppmvd15% or g/kWh,

Emissions Checks
When emissions check required for certain engines

79 An emissions check to determine the concentration of NOx in the exhaust gas must be conducted

Using electrochemical analyzer

80 (1) An emissions check must be conducted by means of an electrochemical analyzer.

Electrochemical analyzers

(2) The electrochemical analyzer must

Calibration error checks and interference responses

81 Before an electrochemical analyzer is used for the first time to conduct an emissions check on an engine,

Analyzer — operation and maintenance

82 (1) An electrochemical analyzer must be operated and maintained in accordance with the manufacturer’s specifications, including the specifications on

Analyzer — set-up

(2) Before a calibration error check or an emissions check is conducted in a given location,

Analyzer — measurement system for introduction of gas

(3) The measurement system for the introduction of gas into the analyzer must

Sequence of calibration error checks

83 (1) A sequence of calibration error checks consists of two calibration error checks on each of the electrochemical cells of an analyzer, one involving the introduction of a zero gas and the other involving the introduction of a span gas.

Calibration error checks

(2) A calibration error check on an electrochemical cell of an analyzer is conducted by introducing into the analyzer, at a constant flow rate, a calibration gas — namely, a zero gas or a span gas — for each of the gases referred to in subsection (3) to which that cell is designed to respond in order to determine the difference between

Calibration gases

(3) The zero gas and the span gas for the following gases to which a cell is designed to respond are

Certified concentration

(4) A concentration of O2, CO, NO or NO2 in a calibration gas is certified if the manufacturer of the gas certifies that

Stabilization periods and records

(5) The stabilization period for a sequence of calibration error checks on an analyzer is the longest period among the periods required for each electrochemical cell to have a stable response, following the introduction of a span gas into the analyzer, to the gas to which the cell is designed to respond. The duration of each of those periods must be recorded.

Calibration error

(6) The calibration error — for each calibration error check involving the introduction of the zero gas or of the span gas — must be at most

Reading for CO and NO interference responses

84 (1) When a reading of an electrochemical cell’s response to a span gas for NO or NO2 is taken under subsection 83(1), a reading must also be taken — for the purpose of determining the CO and NO interference responses — of the response of the following other cells of the analyzer to that span gas:

CO interference response

(2) The CO interference response — namely, the response of the CO cell to the presence of NO and NO2 in the introduced span gas — is the percentage determined by the formula

[(RCO−NO/CNOG × CNOS/CCOS) + (RCO−NO2/CNO2G × CNO2S/CCOS)] × 100

where

RCO−NO is the CO response to span gas for NO, expressed in ppm of CO;

CNOG is the certified concentration of NO in the span gas for NO, expressed in ppm of NO;

CNOS is the concentration of NO in the exhaust gas of the engine, as determined in accordance with section 89 for the most recent emissions check that was conducted by means of the analyzer referred to in subsection (1), expressed in ppm of NO;

CCOS is the concentration of CO in the exhaust gas of the engine, as determined in accordance with section 89 for that most recent emissions check, expressed in ppm of CO;

RCO−NO2 is the CO response to span gas for NO2, expressed in ppm of CO;

CNO2Gis the certified concentration of NO2 in the span gas for NO2, expressed in ppm of NO2; and

CNO2S is the concentration of NO2 in the exhaust gas of the engine, as determined in accordance with section 89 for that most recent emissions check, expressed in ppm of NO2.

NO interference response

(3) The NO interference response — namely, the response of the NO cell to the presence of NO2 in the introduced span gas — is the percentage determined by the formula

RNO−NO2/CNO2G × CNO2S/CNOxS × 100

where

RNO−NO2 is the NO response to span gas for NO2, expressed in ppm of NO;

CNO2G is the certified concentration of NO2 in the span gas for NO2, expressed in ppm of NO2;

CNO2S is the concentration of NO2 in the exhaust gas of the engine, as determined in accordance with section 89 for the most recent emissions check that was conducted by means of the analyzer referred to in subsection (1), expressed in ppm of NO2; and

CNOxS is the concentration of NOx in the exhaust gas of the engine, as determined in accordance with section 89 for that most recent emissions check, expressed in ppm of NOx.

No prior emissions check

(4) If there is no prior emissions check conducted by means of the analyzer referred to in subsection (1),

Interference response ≤ 5%

(5) The CO interference response and the NO interference response must each be at most 5%.

Invalid emissions check — calibration and interference

85 If a calibration error check on a cell of an analyzer does not meet the requirements of subsection 83(6) or a determination — based on the readings taken during a sequence of calibration error checks that includes that calibration error check — of the CO interference response made under subsection 84(2), or of the NO interference response made under subsection 84(3), is more than 5%,

Emissions check — sampling ports

86 (1) The location in the exhaust pipe of the sampling port and its traverse points — or the single traverse point — at which an emissions check is to be conducted must be

Single point

(2) A single traverse point at the centre of the exhaust pipe at the sampling port may be used to take samples instead of multiple traverse points.

Operating conditions for emissions checks

87 The emissions check must be conducted while the engine is

Emissions check — sampling procedure

88 (1) The emissions check must be conducted — on an engine’s exhaust gas introduced into the analyzer at a constant flow rate — during a 15-minute sampling period by

NO cell temperature

(2) If the emissions check is conducted with an analyzer that does not display negative concentrations, the NO cell temperature must be recorded at least once each minute during the 15-minute sampling period.

Beginning of sampling period

(3) The sampling period begins after the end of the period that begins with the introduction of the engine’s exhaust gas into the analyzer for the emissions check and that has a duration determined by the formula

2Ts + {π/4 × [(dE2 × LE)/QE − (dC2 × LC)/QC]}

where

Ts is the stabilization period, expressed in seconds, referred to in subsection 83(5) for the most recent sequence of calibration error checks conducted on the analyzer;

dE is the greatest diameter, expressed in m, of any tube that is used in the measurement system through which the engine’s exhaust gas flows from the sampling port or traverse point to the analyzer during the emissions check;

LE is the total length, expressed in m, of those tubes that are used during the emissions check;

QE is the flow rate, expressed in m3/s, of the engine’s exhaust gas measured by the analyzer during the emissions check;

dC is the smallest diameter, expressed in m, of any tube that is used in the measurement system through which the span gas flows from the point where it is introduced into the measurement system to the analyzer during the most recent sequence of calibration error checks conducted on the analyzer;

LC is the total length, expressed in m, of those tubes that are used during the most recent sequence of calibration error checks conducted on the analyzer; and

QC is the flow rate, expressed in m3/s, of the span gas for NO measured by the analyzer during the most recent sequence of calibration error checks conducted on the analyzer.

Concentration of O2, CO, NO and NO2 — average

89 (1) The concentration of O2, CO, NO and NO2, as the case may be, in the exhaust gas determined by the emissions check is the average of the concentrations of the gas in each reading taken or recording made in accordance with subsection 88(1).

Concentration of NOx

(2) The concentration of NOx in the exhaust gas, expressed in ppmvd15%, must be determined by the formula

5.9Cd/(20.9 – %O2)

where

Cd is the sum of the concentrations of NO and NO2 in the engine’s exhaust gas as determined in accordance with subsection (1), expressed in ppmvd, at the concentration of O2, determined in accordance with that subsection; and

%O2 is the number that represents the percentage of oxygen in the engine’s exhaust gas based on the concentration of O2 determined in accordance with that subsection.

Invalid emissions check — temperature

90 (1) If there is a difference of more than 3°C between any two NO cell temperatures that are recorded in accordance with subsection 88(2), the emissions check in question and any concentration that is determined in accordance with section 89 are invalid.

Invalid emissions check — cell measuring range

(2) If any reading taken of an electrochemical cell’s response, or recording that is made of the average of the responses of that cell, in accordance with subsection 88(1) during an emissions check with an analyzer to determine a concentration in accordance with section 89 is outside the measuring range for that cell specified by the analyzer’s manufacturer,

Performance Tests and Emissions Checks
Periods when not conducted

91 A performance test or an emissions check must not be conducted during any period referred to in section 49.

Extended period for new owners

92 Despite any of paragraphs 77(a) to (c) or section 78 or 79, a person who becomes an owner of an engine — on a date during the last 90 days of the period for conducting a performance test or emissions check on the engine referred to in that provision with no performance test or emissions check on the engine having yet been conducted in that period — may conduct the performance test or emissions check within a period of 90 days after that date.

Extended period — last day

93 Despite any of paragraphs 77(a) to (c) or section 78, 79 or 92, a performance test or emissions check that is referred to in that provision and that has not been conducted by the last day of the period for conducting the performance test or emissions check referred to in that provision must be conducted

Engine Management

Nameplate

94 (1) An engine that is low-use or that is subject to a NOx emission intensity limit referred to in any of sections 54 and 57 to 59 — or an engine or replacement unit that belongs to a subgroup — must have a nameplate that is permanently affixed to it in a visible location and that indicates

Serial number

(2) The serial number must be the serial number provided by the engine or replacement unit’s manufacturer

Unique alphanumeric identifier

(3) If the serial number is not known or cannot be obtained, the responsible person for a pre-existing engine or a replacement unit that is not a modern engine may apply to the Minister for a unique alphanumeric identifier for the engine or replacement unit by providing the Minister with

Refusal

(4) The Minister must refuse the application if the Minister has reasonable grounds to believe that the applicant has provided false or misleading information in the application.

Operation and maintenance

95 (1) The recommendations of the manufacturer concerning the operation and maintenance of the systems and components referred to in subsection (2) that are related to an engine must be treated as requirements and be complied with,

Systems and components

(2) The following are the systems and components:

No obligation to comply

(3) Despite subsection (1), no recommendation referred to in that subsection need be treated as a requirement and complied with by the responsible person described in that subsection if they have a record that establishes that without that compliance the NOx emission intensity of the engine is unlikely to exceed the following limit or value:

Air-fuel ratio

96 The responsible person described in subsection 95(1) must verify, maintain and adjust the air-fuel ratio of the engine so as to ensure that its NOx emission intensity, during the diverse ambient conditions anticipated during a year, does not exceed the following limit or value:

Registry, Reporting and Recording of Information

Engine registry

97 (1) The Minister is to establish an engine registry in order to carry out the purpose of this Part by facilitating the provision to the Minister of information that is

Regular-use and low-use engines

(2) The following engines must be registered in the engine registry:

Registration date — engines in group

(3) A responsible person for a regular-use engine that they have designated as belonging to their group must register the engine on or before

Registration date — engines not in group

(4) An engine referred to in subsection (2) that does not belong to a group must be registered on or before

Re-registration

(5) An engine that has been registered in accordance with subsection (4) — or re-registered under this subsection — must be re-registered on or before July 1 of the year that follows the last year during which there remains at least one responsible person for the engine who has registered or re-registered the engine.

Registration

(6) The registration occurs when the Minister is provided with the information for inclusion in the engine registry in respect of the engine that is set out in Schedule 9.

Change of information — engine registry

98 (1) If there is a change in the information provided to the Minister for inclusion in the engine registry in respect of an engine or a replacement unit, the Minister must be provided with the updated information

Responsible person

(2) The updated information must be provided by

Compliance reports

99 (1) A compliance report must, on or before July 1 of a year, be provided that contains the information set out in Schedule 10 in respect of the preceding year to the Minister in respect of

Responsible person

(2) The compliance report must be provided by the responsible person for the engine or replacement unit who

Record-making

100 In addition to any records otherwise required under these Regulations, a record in respect of an engine or replacement unit that contains the following information or documents must be made:

PART 3

Cement

Definitions

101 The following definitions apply in this Part and in Schedule 11.

cement means a powder that results from the grinding of clinker and the blending of the ground clinker with other materials. (ciment)

clinker means solid nodules that are produced by the pyroprocessing of feedstock in a kiln. (clinker)

feedstock means a ground blend of calcium carbonate, silica, alumina, ferrous oxide and any other material that is used to produce clinker. (matière première)

grey cement means cement that is manufactured from clinker that contains more than 0.5% by weight of ferric oxide. (ciment gris)

kiln means a thermally insulated chamber into which blended feedstock is introduced for pyroprocessing in order to produce clinker. (four)

long dry kiln means a kiln that

precalciner kiln means a kiln that is equipped with a system for precalcining dry feedstock using, before the feedstock is introduced into the kiln, a secondary burner that has a tertiary supply of combustion air. (four à précalcinateur)

preheater kiln means a kiln that is equipped with a system for preheating dry feedstock with at least three stages of preheating before the feedstock is introduced into the kiln. (four à préchauffeur)

wet kiln means a kiln into which feedstock is introduced as a fine slurry with a water content of more than 20% by weight. (four à voie humide)

Application — grey cement

102 This Part applies in respect of cement manufacturing facilities that produce clinker for use in the manufacture of grey cement.

Obligation — over two consecutive years

103 (1) As of January 1, 2020, a cement manufacturing facility must not — over any two consecutive years — emit NOx or SO2 in a quantity that exceeds the emission limit for each of those years for that substance, as determined in accordance with sections 104 and 105, respectively.

Obligation — yearly

(2) If a cement manufacturing facility does not comply with that emission limit for either NOx or SO2 over a period of two consecutive years, it must not — during each year after that period — emit either NOx or SO2 in a quantity that exceeds its emission limit for that year, as determined in accordance with sections 104 and 105.

Emission limit — NOx

104 (1) The emission limit for a year for the emission of NOx from a cement manufacturing facility is determined by the formula

Σi(EINOxi × Pi)/ΣiPi

where

EINOxi is the maximum emission intensity for the year for the emission of NOx from the ith kiln stack in the cement manufacturing facility — namely, the maximum quantity of NOx emitted per tonne of clinker produced at the ith kiln in the cement manufacturing facility in the year — which is

EI2006 – (0.3 × EI2006)

where

EI2006 is the quantity of NOx, expressed in kg, that was emitted at the cement manufacturing facility in 2006 per tonne of clinker produced, as reported in respect of the cement manufacturing facility to the Minister in accordance with the Notice with respect to reporting of information on air pollutants, greenhouse gases and other substances for the 2006 calendar year, published in the Canada Gazette, Part I, Volume 141, No. 49, on December 8, 2007;

i is ith kiln in the cement manufacturing facility, where i goes from 1 to n and where n is the number of kilns in the cement manufacturing facility; and

Piis the quantity of clinker, expressed in t, that is produced by the ith kiln in the cement manufacturing facility in the year.

Election — 2020

(2) A responsible person for the cement manufacturing facility who provides the Minister with a compliance report required by section 108 in respect of the year 2020 must, in that compliance report, make the election referred to in paragraph (b) of the description of EINOxi in subsection (1).

Election — subsequent years

(3) The maximum emission intensity for the emission of NOx from the ith kiln in the cement manufacturing facility for the year 2020 that is elected by the responsible person also applies for each subsequent year.

Emission limit — SO2

105 The emission limit for a year for the emission of SO2 from a cement manufacturing facility is determined by the formula

Σi(EISO2i × Pi)/ΣiPi

where

EISO2i is the maximum emission intensity for the year for the emission of SO2 from the ith kiln stack in the cement manufacturing facility — namely, the maximum quantity of SO2 emitted per tonne of clinker produced at the ith kiln in the cement manufacturing facility in the year — which is 3.0 kg/t;

i is the ith kiln in the cement manufacturing facility, where i goes from 1 to n and where n is the number of kilns in the cement manufacturing facility; and

Pi is the quantity of clinker, expressed in t, that is produced by the ith kiln in the cement manufacturing facility in the year.

Quantity of NOx and SO2 — CEMS

106 As of January 1, 2018, the quantity, expressed in kg, of NOx and SO2 emitted, during a given year, from each kiln stack in a cement manufacturing facility must be determined by means of a CEMS.

Quantity of clinker

107 (1) For the purpose of determining the value for Pi in sections 104 and 105, the quantity of clinker that is produced at each kiln in the cement manufacturing facility in the year must be determined by

Accuracy of feedstock-to-clinker conversion factor

(2) The accuracy of the feedstock-to-clinker conversion factor must be verified

Record-making

(3) A record of that verification must be made that demonstrates the accuracy of the feedstock-to-clinker conversion factor.

Compliance report

108 As of January 1, 2019, on or before June 1 of every year a compliance report that contains the information for the cement manufacturing facility that is set out in Schedule 11 in respect of the preceding year must be provided to the Minister.

PART 4

General

Continuous Emission Monitoring Systems

CEMS Reference Method — compliance

109 If a CEMS is used to determine a NOx emission intensity under Part 1 or a quantity of emissions under section 106, the CEMS Reference Method must be complied with, notably

Annual audit

110 (1) For each year during which a responsible person uses a CEMS to determine a NOx emission intensity under Part 1 or a quantity of emissions under section 106, the responsible person must ensure that an auditor evaluates whether, in the auditor’s opinion, the responsible person has complied with the CEMS Reference Method and, in particular, whether

Auditor’s report

(2) The responsible person must, within 30 days after the day on which the auditor completes their audit, obtain a report, signed by the auditor, that contains the information set out in Schedule 12.

Request for auditor’s report

(3) The responsible person must, on the Minister’s request, provide the Minister with a copy of an auditor’s report within 15 days after the request.

Provision of auditor’s report to Minister

(4) A responsible person who uses a CEMS to determine a NOx emission intensity under Part 1 must, for each year during which they use a CEMS, provide the Minister with a copy of the auditor’s report for that year by June 1 of the following year, if the opinion stated by the auditor in the report is that the responsible person has not complied with any aspect of the CEMS Reference Method.

Auditor

(5) For the purpose of this section, an auditor is a person who

Measuring Devices

Installation, operation, maintenance and calibration

111 Unless otherwise provided by these Regulations, any measuring device that is used to determine a quantity for the purpose of these Regulations must be installed, operated, maintained and calibrated in accordance with the manufacturer’s specifications or any applicable generally recognized national or international industry standard.

Alternative Rules

Application

112 (1) The Minister may — on written application by a responsible person for a boiler, heater, engine or cement manufacturing facility — approve an alternative rule in respect of the boiler, heater or engine or a kiln located in the cement manufacturing facility to replace a rule set out in a document that is incorporated by reference into these Regulations with respect to

Exception for rule to be replaced

(2) The rule that is to be replaced must not be a rule that is contained in EPA Method 7E or EPA Method 6C in relation to the conduct of relative accuracy tests and bias tests of the relative accuracy test audit (RATA) referred to in subparagraph 109(c)(i) or (ii).

Alternative rule

(3) The proposed alternative rule must be a rule that the responsible person may comply with in order to comply with a provincial law in respect of the boiler, heater, engine or kiln and be

Information for application

(4) The application must include

Paragraph (4)(e) — concentration of NOx

(5) If a proposed alternative rule described in paragraph (3)(b) concerns the determination of the concentration of NOx in a gas, other than by means of a CEMS, the demonstration referred to in paragraph (4)(e) must compare its rigour and effectiveness to the rigour and effectiveness of making that determination based on EPA Method 7E or ASTM D6522-11.

Approval

113 (1) The Minister must grant the application and approve the proposed alternative rule — with any modification, or subject to any conditions, that the Minister considers desirable — if the Minister is of the opinion that

Provision of approved alternative rule

(2) Without delay after approving an alternative rule, the Minister must provide the applicant — and every other responsible person for the boiler, heater or engine, or the cement manufacturing facility in which the kiln is located, set out in the application — with the alternative rule, as approved.

Provision of rule to another responsible person

(3) A responsible person referred to in subsection (2) must — on another person becoming a responsible person for it — provide that other person with the alternative rule, as approved.

Application of approved alternative rule

114 (1) Subject to section 115, an alternative rule, as approved by the Minister, replaces the rule in question that is set out in a document that is incorporated by reference into these Regulations and applies in respect of the boiler, heater, engine or kiln located in the cement manufacturing facility.

Interpretation of incorporated document

(2) For greater certainty, the document is to be read with reference to the alternative rule, as approved, and not the rule that the alternative rule replaces.

Notice to apply replaced rule

115 A responsible person for the boiler, heater or engine, or the cement manufacturing facility in which the kiln is located, may in writing notify the Minister and every other responsible person for it that the alternative rule, as approved, no longer applies — as of the date indicated in the notice — in respect of that boiler, heater, engine or kiln located in the cement manufacturing facility.

Refusal — false, misleading or incomplete information

116 (1) The Minister must refuse the application if the Minister has reasonable grounds to believe that the responsible person has, with their application, provided false, misleading or incomplete information.

Refusal — informing applicant

(2) Without delay after refusing the application, the Minister must inform the applicant of the refusal, along with the reasons for it.

Revocation by Minister

117 (1) The Minister must revoke the alternative rule as approved by the Minister if

Revocation — informing responsible persons

(2) Without delay after the revocation, the Minister must notify each responsible person for the boiler, heater or engine, or the cement manufacturing facility in which the kiln is located, of the revocation, along with the reasons for it and an indication of the date of the revocation.

Revocation under law

118 The alternative rule as approved by the Minister is revoked as of the day on which the responsible person no longer is able to comply with provincial law by complying with the alternative rule in respect of the boiler, heater, engine or kiln located in the cement manufacturing facility. Without delay after that day, the responsible person must notify the Minister in writing of that revocation, including an indication of the date of that day.

Rule after notification or revocation

119 The rule set out in a document that is incorporated by reference into these Regulations and referred to in subsection 112(1) that was replaced by an alternative rule, as approved by the Minister, applies in respect of the boiler, heater, engine or kiln located in the cement manufacturing facility on

Reporting, Providing, Recording and Retention of Information

Electronic provision

120 (1) A report, notice or information that is required to be provided, or an application that is made, to the Minister under these Regulations must be provided electronically in the form and format specified by the Minister and must bear the signature or electronic signature of an authorized official of the responsible person who provides it.

Provision on paper

(2) If the Minister has not specified an electronic form and format or if it is impractical to provide the report, notice, information or application in accordance with subsection (1) because of circumstances beyond the control of the responsible person, the report , notice, information or application must be provided on paper, signed by an authorized official of the responsible person, in the form and format specified by the Minister. However, if no form and format have been so specified, it may be in any form and format.

Record-making

121 (1) A record in respect of a boiler, heater, engine or cement manufacturing facility must, to the extent that it is not otherwise required under these Regulations, be made

Records — deadline

(2) Records required to be made under these Regulations must be made within 30 days after the day on which the information to be recorded becomes available.

Five or ten years’ retention

(3) A record or application that is made — or a copy of a report, notice or information that is provided — under these Regulations must be kept, along any supporting documents, after it is made or provided for

No retention

(4) Despite subsection (3), any information that has been provided to the Minister by a responsible person for inclusion in the engine registry or in an online electronic reporting site that is established by the Minister does not need to be kept if the Minister has provided the responsible person with an acknowledgment of its receipt.

Record location — Parts 1 and 3

(5) The record or copy referred to in subsection (3) — other than one that relates to an engine — must be kept at the facility where the boiler or heater is located or at the cement manufacturing facility.

Record location — Part 2

(6) The record or the copy referred to in subsection (3) that relates to an engine must be kept at

Provision of records

(7) On the Minister’s request, the record or copy referred to in subsections (5) and (6) must be provided to the Minister without delay.

Corrections

122 A responsible person must, without delay, inform the Minister of any errors contained in information that was provided to Minister under these Regulations and provide the Minister with the corrected information.

Notification of testing

123 (1) A responsible person for a boiler or heater who intends, by means of a stack test, to determine its NOx emission intensity for the purpose of sections 33 to 38 or a responsible person for an engine who intends to conduct a performance test on it under clause 66(2)(a)(i)(B) or section 77 or 78 or an emissions check on it under section 79 must, on the Minister’s request, provide the Minister with the following information:

When information provided

(2) The information must be provided

Amendments to these Regulations

Section 11

124 Section 11 of these Regulations is replaced by the following:

Class 80 and class 70

11 The NOx emission intensity of a pre-existing boiler or heater that is class 80 or class 70 — other than those referred to in subsections 13(1) and 14(1) and (2 ) — and that, for a given hour, has at least 50% of the input energy in its combustion chamber resulting from the introduction of gaseous fossil fuel must not, for that hour, exceed the limit of 26 g/GJ.

Subsection 12(1)

125 (1) The portion of subsection 12(1) of these Regulations before paragraph (a) is replaced by the following:

Pre-existing boilers and heaters — classification

12 (1) A pre-existing boiler or heater is classified — in accordance with its classification NOx emission intensity determined in accordance with subsection 34(1) or redetermined in accordance with subsection 36(1) — as follows:

Subsection 12(1)

(2) The portion of subsection 12(1) of these Regulations before paragraph (a) is replaced by the following:

Pre-existing boilers and heaters — classification

12 (1) A pre-existing boiler or heater is classified — in accordance with its classification NOx emission intensity determined in accordance with subsection 34(1) — as follows:

Paragraph 26(4)(a)

126 (1) Paragraph 26(4)(a) of these Regulations is replaced by the following:

Subsection 26(4)

(2) Subsection 26(4) of these Regulations is replaced by the following:

When identification made

(4) The identification is made as of

Paragraph 33(3)(c)

127 Paragraph 33(3)(c) of these Regulations is replaced by the following:

Section 35 and 36

128 Sections 35 and 36 of these Regulations are repealed.

Subsection 37(1)

129 (1) Subsection 37(1) of these Regulations is replaced by the following:

Redetermination after triggering event — class 40

37 (1) Subject to subsection (6), the classification NOx emission intensity of a class 40 boiler or heater must be redetermined after the occurrence of a triggering event that occurs on or before December 31, 2035.

Subsection 37(2)

(2) Subsection 37(2) of these Regulations is replaced by the following:

Replacement

(2) The redetermination under subsection (1) replaces the most recent classification NOx emission intensity for the boiler or heater redetermined under subsection 36(1) only if the redetermined classification NOx emission intensity is greater than that most recent classification NOx emission intensity.

Section 37

(3) Section 37 of these Regulations is repealed.

Subsection 41(1)

130 (1) Subsection 41(1) of these Regulations is repealed.

Subsection 41(2)

(2) Subsection 41(2) of these Regulations is repealed.

Paragraph 43(1)(g)

131 (1) Paragraph 43(1)(g) of these Regulations is replaced by the following:

Paragraph 43(1)((g)

(2) Subsection 43(1) of these Regulations is amended by adding “and” at the end of paragraph (e), by striking out “and” at the end of paragraph (f) and by repealing paragraph (g).

Section 45 — definition subset

132 The definition subset in section 45 of these Regulations is repealed.

Section 49

133 Section 49 of these Regulations is replaced by the following:

Synthetic gas and still gas

49 Sections 54, 55, 57, 58 and 68 do not apply in respect of an engine — for any period during which the fuel combusted consists of more than 50% synthetic gas, still gas or any combination of those gases — if records are kept that establish, based on a calculation of the mass flow, that the fuel combusted in that period consists of that proportion of those gases.

Section 53

134 The portion of section 53 of these Regulations before paragraph (a) is replaced by the following:

Applicable units — NOx emission intensity limit

53 The applicable NOx emission intensity limit for an engine referred to in section 54, 57 or 58 is the limit that is expressed in

Section 57

135 Section 57 of these Regulations is replaced by the following:

Engines not belonging to a group

57 The NOx emission intensity of a pre-existing engine that is regular-use, has a rated brake power of at least 250 kW and does not belong to any group must not exceed the limit of 210 ppmvd15% or 4 g/kWh, whichever applies.

Sections 58 and 59

136 Sections 58 and 59 of these Regulations are replaced by the following:

Engines belonging to a group

58 Subject to section 60, the NOx emission intensity of an engine that belongs to a group must not exceed the limit of 210 ppmvd15% or 4 g/kWh, whichever applies.

Section 60

137 Section 60 of these Regulations is replaced by the following:

Certain pre-existing engines

60 A responsible person who makes an election in accordance with subsection 61(1) to opt out of the application of section 58 must — for each year that follows the making of the election — ensure that the yearly average NOx emission intensity of each subgroup that they establish under section 65 does not exceed the limit of 210 ppmvd15% or 4 g/kWh, whichever applies.

Paragraph 62(2)(c)

138 Paragraph 62(2)(c) of these Regulations is replaced by the following:

Paragraph 63(2)(b)

139 Paragraph 63(2)(b) of these Regulations is replaced by the following:

Section 69

140 Section 69 of these Regulations is replaced by the following:

NOx emission intensity limits

69 For the purpose of sections 54, 55, 57, 58 and 68, the NOx emission intensity of an engine must be determined by means of a performance test.

Paragraph 77(b)

141 (1) Paragraph 77(b) of these Regulations is replaced by the following:

Paragraph 77(c)

(2) The portion of paragraph 77(c) of these Regulations before subparagraph (i) is replaced by the following:

Subsection 94(1)

142 The portion of subsection 94(1) of these Regulations before paragraph (a) is replaced by the following:

Nameplate

94 (1) An engine that is low-use or that is subject to a NOx emission intensity limit referred to in any of sections 54, 57 and 58 — or an engine or replacement unit that belongs to a subgroup — must have a nameplate that is permanently affixed to it in a visible location and that indicates

Paragraph 95(1)(b)

143 (1) Paragraph 95(1)(b) of these Regulations is replaced by the following:

Paragraph 95(3)(b)

(2) Subsection 95(3) of these Regulations is amended by adding “and” at the paragraph (a) and by repealing paragraph (b).

Paragraph 96(b)

144 Section 96 of these Regulations is amended by adding “and” at the paragraph (a) and by repealing paragraph (b).

Reference to Schedule 5

145 (1) Schedule 5 to these Regulations is amended by replacing the section references after the heading “SCHEDULE 5” with the following:

(Section 4 and paragraph 43(1)(g))

Paragraphs 4(l) and (m) of Schedule 5

(2) Section 4 of Schedule 5 to these Regulations is amended by adding “or” at the end of paragraph (j) and by repealing paragraphs (l) and (m).

Schedule 5

(3) Schedule 5 to these Regulations is repealed.

Paragraph 3(n) of Schedule 9

146 Section 3 of Schedule 9 to these Regulations is amended by adding “and” at the end of paragraph (m) and by repealing paragraph (n).

Section 4 of Schedule 10

147 Section 4 of Schedule 10 to these Regulations is repealed.

Coming into Force

Registration

148 (1) Subject to subsections (2) to (5), these Regulations come into force on the day on which they are registered.

January 1, 2021

(2) Section 135 comes into force on January 1, 2021.

January 1, 2023

(3) The following provisions come into force on January 1, 2023:

January 1, 2026

(4) The following provisions come into force on January 1, 2026:

January 1, 2036

(5) The following provisions come into force on January 1, 2036:

SCHEDULE 1

(Subsection 2(3))

EC CEMS Code Modifications

1 The EC CEMS Code is to be read as follows:

SCHEDULE 2

(Subsection 2(4))

Alberta CEMS Code Modifications

1 The Alberta CEMS Code is to be read as follows:

SCHEDULE 3

(Sections 4 and 15)

Default Higher Heating Values

Table 1

Solid Fuels

Item

Column 1

Type of Fuel

Column 2

Default Higher Heating Value (GJ/t)

1

Bituminous Canadian coal — Western

25.6

2

Bituminous Canadian coal — Eastern

27.9

3

Bituminous non-Canadian coal — U.S.

25.7

4

Bituminous non-Canadian coal — other countries

29.9

5

Sub-bituminous Canadian coal — Western

19.2

6

Sub-bituminous non-Canadian coal — U.S.

19.2

7

Coal — lignite

15.0

8

Coal — anthracite

27.7

9

Coal coke and metallurgical coke

28.8

10

Petroleum coke from refineries

46.4

11

Petroleum coke from upgraders

40.6

12

Municipal solid waste

11.5

13

Tires

31.2

14

Wood and wood waste (see note 1*)

19.0

15

Agricultural by-products (see note 2*)

17.0

16

Peat (see note 3*)

9.3

Table 2

Liquid Fuels

Item

Column 1

Type of Fuel

Column 2

Default Higher Heating Value (GJ/kl)

1

Diesel

38.3

2

Light fuel oil

38.8

3

Heavy fuel oil

42.5

4

Ethanol

21.0

5

Distillate fuel oil No. 1

38.78

6

Distillate fuel oil No. 2

38.50

7

Distillate fuel oil No. 4

40.73

8

Kerosene

37.68

9

Liquefied petroleum gas (LPG)

25.66

10

Natural gasoline

30.69

11

Motor gasoline

34.87

12

Aviation gasoline

33.52

13

Kerosene-type aviation

37.66

Table 3

Gaseous Fuels

Item

Column 1

Type of Fuel

Column 2

Default Higher Heating Value (GJ/standard m3)

1

Methane

0.038361

2

Biogas (captured methane)

0.0281

3

Propane

0.096926

4

Propylene

0.088424

5

Ethane

0.067587

6

Ethylene

0.060642

7

Isobutane

0.127137

8

Isobutylene

0.116035

9

Butane

0.127706

10

Butylene

0.116747

11

Hydrogen

0.012289

12

Carbon monoxide

0.012149

SCHEDULE 4

(Sections 4 and 18 )

Loss of Thermal Efficiency — Watertube Boilers

Column 1

Rated Capacity (GJ/h)

Percentage of Loss of Thermal Efficiency

Column 2

100% of Rated Capacity

Column 3

80% of Rated Capacity

Column 4


60% of Rated Capacity

10.5

1.60

2.00

2.67

21.1

1.05

1.31

1.75

31.6

0.84

1.05

1.40

42.2

0.73

0.91

1.22

52.8

0.66

0.82

1.10

63.3

0.62

0.78

1.03

73.9

0.59

0.74

0.98

84.4

0.56

0.70

0.93

95.0

0.54

0.68

0.90

105.5

0.52

0.65

0.87

126.5

0.48

0.60

0.80

147.7

0.45

0.56

0.75

168.8

0.43

0.54

0.72

189.9

0.40

0.50

0.67

211.0

0.38

0.48

0.64

422.0

0.30

0.38

0.50

633.0

0.27

0.34

0.45

844.0

0.25

0.31

0.42

1 055

0.23

0.29

0.38

2 110

0.20

0.25

0.33

SCHEDULE 5

(Sections 4 and 41 and paragraph 43(1)(g))

Classification Report (Boilers and Heaters) — Information Required

1 The following information respecting the responsible person:

2 The following information respecting the facility at which the boiler or heater is located:

3 The following information respecting the boiler or heater:

4 An indication as to which of the following provisions of these Regulations is the one under which the boiler’s or heater’s classification NOx emission intensity was determined:

5 The following information respecting a test on the boiler or heater referred to in paragraph 34(1)(a) of these Regulations conducted to determine its classification NOx emission intensity:

6 The following information respecting a stack test whoseresults are used to determine the boiler’s or heater’s classification NOx emission intensity under paragraph 34(1)(b) of these Regulations:

7 The following information respecting a CEMS test whose results are used to determine the boiler’s or heater’s classification NOx emission intensity under paragraph34(1)(b) of these Regulations:

8 The following information respecting a boiler or heater whose classification NOx emission intensity is determined under subparagraph 34(1)(b)(ii) of these Regulations:

SCHEDULE 6

(Section 4, subparagraph 14(1)(a)(i), section 40 and paragraphs 43(1)(a) to (f))

Initial Report (Boilers and Heaters) — Information Required

1 The following information respecting the responsible person:

2 The following information respecting the facility at which the boiler or heater is located:

3 The following information — if it has changed since the most recent report that the responsible person has provided to the Minister — respecting the boiler or heater:

SCHEDULE 7

(Section 4 and subsection 42(1))

Compliance Report (Boilers and Heaters) — Information Required

1 The following information respecting the responsible person:

2 The following information respecting the facility at which the boiler or heater is located:

3 The following information — if it has changed since the most recent report that the responsible person has provided to the Minister — respecting the boiler or heater:

SCHEDULE 8

(Sections 45 and 47 )

Non-application (Engines) — Information Required

1 The following information respecting the responsible person:

2 The following information respecting each of the responsible person’s pre-existing engines:

SCHEDULE 9

(Section 45, paragraphs 64(4)(b) and 94(3)(a) and subsection 97(6))

Engine Registry — Information Required

1 The following information respecting a responsible person who registers an engine in the engine registry, applies for a unique alphanumeric identifier for an engine or replaces a pre-existing engine in their group with a replacement unit:

2 The following information respecting the facility at which the engine or replacement unit is located:

3 The following information respecting the engine or replacement unit:

4 The following information respecting each subgroup that the responsible person established under section 65 of these Regulations:

SCHEDULE 10

(Section 45, clause 66(2)(a)(i)(B), subparagraphs 77(c)(i) and (d)(ii), subsection 99(1) and subclause 3(o)(iii)(B)(II) of Schedule 9)

Compliance Report (Engines) — Information Required

1 The name and telephone number of the responsible person who is providing the compliance report.

2 For each of the responsible person’s engines, the total number of hours, if any, contained in all periods referred to in section 49 of these Regulations in the preceding year for which the compliance report is provided.

3 The following information respecting each of the responsible person’s low-use engines:

4 If applicable, the following information respecting the subset referred to in section 59 of these Regulations:

5 The following information respecting each of the responsible person’s subgroups, if they made an election under subsection 61(1) of these Regulations that is in effect for the preceding year for which the compliance report is provided:

6 The following information respecting each performance test referred to in clause 66(2)(a)(i)(B) or section 77, 78, 92 or 93 of these Regulations that was conducted on an engine by the responsible person during the preceding year for which the compliance report is provided:

7 The following information respecting each engine on which an emissions check referred to in section 79, 92 or 93 of these Regulations was conducted by the responsible person during the preceding year for which the compliance report is provided:

SCHEDULE 11

(Sections 101 and 108)

Compliance Report (Cement Manufacturing Facilities) — Information Required

1 The following information respecting the responsible person:

2 The following information respecting the cement manufacturing facility:

3 If applicable, the emission intensity elected by the responsible person under subsection 104(2) of these Regulations as the value for EINOxi in subsection 104(1) of these Regulations.

SCHEDULE 12

(Subsection 110(2))

Auditor’s Report — Information Required

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

2 For each CEMS used to determine under Part 1 a NOx emission intensity of one or more boilers or heaters located in a facility or under section 106 a quantity of emissions of one or more kilns located in a cement manufacturing facility,

3 The name, civic address, telephone number and email address of the auditor and their qualifications.

4 The dates on which the audit was conducted.

5 The procedures that the auditor followed in assessing whether

6 A statement of the auditor’s opinion as to whether the responsible person has complied with the CEMS Reference Method and, in particular, as to whether

7 Any recommendation of the auditor for improvements in the CEMS or its operation.

REGULATORY IMPACT ANALYSIS STATEMENT

(This statement is not part of the Regulations.)

Executive summary

Issues: Air pollutants negatively affect human health, place a serious burden on the health care system, degrade the environment and have an adverse impact on the economy.

While progress has been made in reducing some air pollutant emissions, the current approach has not proved sufficient to adequately reduce the health and environmental risks across the country — air quality remains an ongoing issue of concern in Canada. Industrial air pollutant emissions from the cement sector and technologies, such as boilers and heaters, and engines contribute to the degradation of air quality.

Actions to manage industrial emissions currently vary across Canada and the requirements are different from one province or territory to another. In addition, air pollutants travel across provincial boundaries and to and from the United States (U.S.). Such interjurisdictional issues are federal responsibility. While federal, provincial and territorial governments continue to work together under the auspices of the Air Quality Management System, federal action is necessary to establish a nationally consistent approach to reduce industrial air pollutant emissions.

Description: The Multi-Sector Air Pollutants Regulations (the Regulations) set mandatory national performance standards for the cement sector and two equipment types used in several industrial sectors — gaseous-fossil-fuel-fired boilers and heaters (hereinafter referred to as boilers and heaters), and stationary spark-ignition gaseous-fuel-fired engines (hereinafter referred to as engines). The performance standards limits the quantity of nitrogen oxide (NOx) and sulphur dioxide (SO2) that can be emitted from cement manufacturing facilities, and it limits the rate at which NOx can be emitted from the two equipment types.

Cost-benefit statement: The Regulations are estimated to result in a reduction of approximately 2 037 kilotonnes (kt) of NOx over the 2016–2035 period. No SO2 emissions reductions are expected over this same period. A cost-benefit analysis was conducted for each sector/equipment group. For boilers and heaters, the net present value (NPV) of the Regulations is estimated to be about $320 million (M) resulting in a benefit-to-cost ratio of 5:1. For engines, the NPV is estimated to be around $6 billion (B), resulting in a benefit-to-cost ratio of 16:1. For cement, impacts are expected to be low given recent emission performance improvements by the sector, and as such only a qualitative analysis of benefits is provided. However, health and environmental benefits are expected to exceed costs.

The present value (PV) of the benefits of the Regulations is estimated to be $410M for boilers and heaters and $6.4B for engines. These benefits largely arise from avoided environmental and health impacts such as premature mortalities and emergency room visits. The benefits occur across Canada, with the largest share of benefits accruing in the province of Alberta.

The PV of the costs of the Regulations is estimated to be around $90M for boilers and heaters, $394M for engines, and close to $9M for cement. These costs are largely due to the incremental expense of adopting technologies required to reduce emissions, including retrofitting. Due to the provision of flexible compliance options, and differing requirements for new versus existing capital, virtually all capital investments involve “add-on” technologies or the purchase of lower-emitting models at the time of natural capital stock turnover, rather than early retirement of capital stock. Costs are not expected to be directly passed on to consumers given the competitive positions of the affected sectors.

“One-for-One” Rule and small business lens: The requirements associated with each performance standard in the Regulations are estimated to result in an increase in annualized administrative costs for businesses subject to the Regulations of approximately $29,410 for boilers and heaters, $238,517 for engines, and $5,608 for cement. These estimates reflect the relative number of equipment or facilities regulated under the Regulations.

No small businesses affected by the Regulations for pre-existing engines were identified. However, recognizing the possibility that some small businesses that own or operate engines above the size threshold have not self-identified to date, or that larger engines may be owned or operated by small businesses in the future, an explicit small business exclusion from the requirements for pre-existing engines has been included in the Regulations.

Domestic and international coordination and cooperation: The Government of Canada engaged provinces and territories extensively during the regulatory development process to better understand their perspectives on both the Regulations and the existing requirements that apply to the industries in their jurisdictions. Provinces and territories support the implementation of the Air Quality Management System, which includes these base-level requirements, and see it as a model of effective federal/provincial cooperation where each level of government takes distinct, coordinated and mutually reinforcing actions within the scope of their authorities.

Efforts have been made to minimize any overlap of monitoring, reporting and enforcement with existing provincial requirements. The Regulations include design elements that reinforce the opportunity for provinces and territories to be the front-line regulator. The federal government also remains open to pursuing equivalency agreements with interested provinces.

The Regulations support regulatory alignment with the United States and are important for continued engagement with the United States on transboundary flows of air pollutants through the Canada-United States Air Quality Agreement.

Background

The Government of Canada first announced its intention to regulate air pollutant emissions from industrial sources in October 2006. Since then, the federal government has actively engaged with provincial and territorial governments, along with company representatives, industry associations, equipment manufacturers, retrofit companies, testing companies and non-governmental organizations (NGO) to explore and develop approaches to address air quality concerns across Canada.

In October 2012, federal/provincial/territorial ministers of the Environment, with the exception of Quebec, agreed to implement the Air Quality Management System (AQMS). Although Quebec supports the general objectives of AQMS, Quebec will not implement the system because it considers the federal industrial emission requirements duplicative of its Clean Air Regulation. Quebec is, however, collaborating with other jurisdictions on developing some elements of the system, notably the Canadian Ambient Air Quality Standards (CAAQs), air zones and airsheds.

The AQMS is a harmonized approach to air quality management across Canada, where all levels of government work collaboratively and efficiently to respond to the different air quality challenges across the country. It includes four elements: (1) updated, more stringent CAAQS; (2) a framework for regional and local air quality management through air zones and regional airsheds; (3) Base-level Industrial Emissions Requirements (BLIERs) for certain major industries; and (4) an intergovernmental working group to improve collaboration and reduce emissions from mobile sources. The CAAQS are air quality objectives meant to drive local air quality improvements. They provide the basis for provincial and territorial governments to determine the level of action needed. The BLIERs are management instruments intended to ensure that all AQMS sectors in Canada meet a consistent, good base-level of environmental performance, regardless of the air quality where facilities are located. They are not designed to be the sole instrument used to improve air quality. Provincial and territorial governments will monitor and manage their local sources of air pollution and have the opportunity to be the front-line regulator and take additional action on all sources to achieve the CAAQS. Actions can include more stringent industrial emission standards for significant air pollutant emitters.

BLIERs were developed for major industrial sectors and for specific equipment types. The sectors under AQMS are aluminium and alumina, base metal smelting, cement, chemicals, electricity, fertilizers, iron ore pellets, iron and steel, oil sands, petroleum refining, pipelines, potash, pulp and paper, and upstream oil and gas. The equipment groups are gaseous-fuel fired boilers and heaters, stationary spark-ignition gaseous-fuel-fired engines, and natural gas-fueled stationary combustion turbines.

The Department intends to implement the BLIERs using a mix of regulatory and non-regulatory instruments. The first phase of BLIERs regulations are being implemented for the following equipment types and industrial sectors:

In subsequent phases, requirements for other sectors may be proposed for addition to the Regulations, or set out in other risk management measures under the Canadian Environmental Protection Act, 1999 (CEPA).

In June 2014, the Department published the proposed Regulations for a 60-day public comment period in the Canada Gazette, Part I (herein referred to as CGI), as well as proposed codes of practice for the aluminium sector and for the iron, steel and ilmenite sector.

In addition to the Regulations, the Department has advanced work to implement a diverse set of sectoral and equipment type BLIERs in its ongoing commitment to the AQMS and to Canadians. In May 2016, the federal government published

Issues

Air quality is important to Canadians. Air pollutants, including sulphur dioxide (SO2), nitrogen oxides (NOx), volatile organic compounds (VOCs), fine particulate matter (PM2.5) and ammonia (NH3) can negatively affect human health. They can also mix and react in the atmosphere to create ground-level ozone and secondary particulate matter, two of the common pollutants in smog. Air pollution places a burden on the health care system, degrades the environment and can adversely impact the economy.

Several studies have linked particulate matter to cardiovascular and respiratory diseases or other medical conditions like heart disease, stroke, asthma, bronchitis and emphysema. Similarly, ozone, which forms as a result of VOCs and NOx, has been shown to exacerbate a wide range of respiratory conditions. In addition to their smog-forming potential, ambient levels of NOx and SO2 have also been linked directly to poor health effects. Exposure to any of these pollutants can increase the risk of medical complications, ranging from mild breathing difficulty, to severe chest pains, hospitalization, and even an increased risk of death. There is evidence that all Canadians are at some risk from the effects of long term exposure to air pollution. Vulnerable populations who are at elevated risk for these health problems include individuals with existing respiratory or cardiovascular problems, the elderly and, due to their increased exposure levels, children. There is also growing evidence that air pollution may be associated with other health impacts like low infant birth weight and various neurological effects.

The negative health effects of air pollutants occur at all concentrations, not only at high concentrations (smog days). The higher the pollution level, the higher the risk, however, there is no such thing as a “safe” level of air pollution. Even if there are only modest amounts of pollutants in the air, research shows that there are still health effects, especially in vulnerable populations.

In addition to harming human health, air pollutants can cause a variety of negative impacts to natural vegetation, soil, water, wildlife and overall ecosystem health. Plants are vulnerable to ozone: damage can be seen as flecks, blotches, and reddening on the leaves; growth can be stunted and some seedlings may not survive. Long-term exposure to ozone may result in crop yield losses, slow timber growth, and premature livestock illnesses and deaths. Like humans, animals can experience similar health problems if exposed to air pollutants.

Emissions of SO2 and NOx contribute to the formation of acid rain (deposition). Acid deposition can lead to an alteration of the chemical composition of elements of the ecosystem which, in turn, can adversely impact the living organisms that inhabit the ecosystem, from micro-organisms up the food chain to vegetation, insects, reptiles, amphibians, fish and mammals. For some organisms, changes in acidity levels, even for brief periods, can be harmful. In addition to the poor visibility associated with tiny particles in the air, pollutants may negatively affect the enjoyment of outdoor recreational activities, participants’ well-being and tourism in general. Particulate deposition is also associated with soiling and structural damages to buildings and other public works.

Air flow carries pollutants from province to province and between Canada and the United States. Emissions from the United States are transported into Canada and contribute to the ambient levels of particulate matter and ozone, resulting in levels of these pollutants that exceed the Canadian ambient (outdoor) air quality standards in some parts of the country. Similarly, emissions from Canadian sources also impact air quality within some regions in the United States. The movement of air pollutants across borders reinforces federal responsibility to take action.

Industrial sources emit a large portion of all human-generated air pollutants in Canada. In 2014, industrial sector sources emitted: SO2 (96%), NOx (41%), VOCs (46%), PM2.5 (23%) and NH3 (59%) of national emissions (open sources excluded).

This first phase of the Regulations focuses on NOx emissions from boilers and heaters and engines, as well NOx and SO2 emissions from the cement sector. Table 1 summarizes the significance of emission sources in each sector/equipment group covered by the Regulations in relation to total industrial emissions.

Table 1: Emission profiles by sector/equipment group

Sector/equipment

2014 emissions (kt)

Emissions as percent of total Canadian industrial sources

Geographical distribution

Boilers and heaters

22 kt NOx

2.8% of industrial NOx emissions

Mainly located in Alberta, British Columbia and Ontario

Engines

314 kt NOx

40% of industrial NOx emissions

Mainly located in British Columbia and Alberta

Cement

25 kt NOx

3% of industrial NOx emissions

British Columbia, Alberta, Ontario, Quebec and Nova Scotia

15 kt SO2

2% of industrial SO2 emissions

While progress has been made in reducing some air pollutant emissions, air quality continues to be an issue of concern in many Canadian communities. More than 30% of Canadians live in communities where the current CAAQS for ozone is not being met. Pollution levels will continue to be an issue as the population grows, more vehicles travel our roadways, more pollution from other countries crosses our borders, and industry expands.

Actions to manage industrial emissions currently vary from one province or territory to another, creating a patchwork of air quality management across Canada that results in different human and environment impacts, as well as an uneven playing field for Canadian enterprises. Before AQMS, Canada lacked a nationally consistent approach to controlling industrial air pollutant emissions, and it is unlikely that consistent performance standards could be established, both across sectors and Canada-wide, in the absence of federal action. The lack of a clear national approach coupled with differences in provincial actions has also made it difficult for Canada to discuss improvements in cross-border pollution with the United States.

Objectives

The objectives of the Regulations are to

Description

The Regulations impose mandatory performance standards specific to each sector/equipment group.

Part 1: Boilers and heaters (equipment type)

A boiler burns gaseous fossil fuels, such as natural gas, to create hot water or steam for use in industrial processes and heating. A heater directly heats the material being processed. Boilers and heaters are typically comprised of a combustion chamber, burners, a pressure vessel (only for boilers), and control/monitoring equipment. The burner design determines the NOx emissions; a well-designed low-NOx burner can reduce NOx emissions by a factor of five, compared to a standard burner.

Boilers and heaters are found in most sectors of the Canadian economy. (see footnote 1) Using size thresholds that industry, provinces and NGOs agreed upon during consultations (see Table 2), only boilers and heaters having a rated capacity greater than or equal to 10.5 gigajoules of energy input per hour (GJi/hr) are subject to the Regulations.

Performance Standards for New and Existing Boilers and Heaters

The Regulations impose performance standards for both new (modern) and existing (pre-existing) boilers and heaters, as set out in Table 2 below. The performance standards differ depending on whether the equipment is a boiler or a heater, whether the equipment burns natural gas or alternative gaseous fuels, whether the heater preheats the combustion air, and whether the boiler has an efficiency (see footnote 2) of more than 80%. For each consideration, except for efficiency, the performance standards were chosen so that the technical complexity required to meet the performance standards do not depend on the specific consideration (e.g. the technical sophistication required to meet the NOx performance standard for a natural gas-fired boiler is about the same as that required to meet the NOx performance standard for an alternative gaseous fuel-fired boiler). The efficiency consideration is included so as to not provide a disincentive for more efficient fuel use (i.e. a more efficient boiler may have a higher NOx emission-intensity, but could emit the same quantity of NOx per year as a less efficient boiler).

Pre-existing boilers and heaters are those that are in service before the day the Regulations are registered. Transitional boilers and heaters are (1) packaged boilers that are brought into service within three months of the registration date of the Regulations, and (2) those that are not packaged (in some industries, these are called “field-erected”) that are brought into service within 36 months of the registration date of the Regulations.

Modern boilers and heaters are those that are not pre-existing and not transitional, and are in service after the day the Regulations are registered. Redesigned boilers and heaters are those that originally were not designed to combust gaseous fossil fuels and hence would not have been subject to the Regulations but were redesigned to combust gaseous fossil fuel and thus became subject to the Regulations at that time.

For pre-existing boilers and heaters, these performance standards can be achieved by either retrofitting or replacing the pre-existing equipment. The Regulations phase in NOx performance standards over a 20-year period for pre-existing equipment that emits more than 70 grams of NOx per gigajoule of input energy (g/GJi). Pre-existing equipment that currently emits less than 70 g/GJi are not subject to any performance standards under the Regulations. The performance standards target pre-existing equipment in regulated sectors that have no NOx controls, imposing requirements by 2026 for Class 80 boilers and heaters (i.e. those that currently emit greater than or equal to 80 g/GJi), and by 2036 for Class 70 boilers and heaters (i.e. those that emit between 70 g/GJi and 80 g/GJi).

Table 2: NOx performance standards for boilers and heaters

Equipment

Considerations affecting applicable NOx limit

NOx limit (g/GJi)

Compliance by

Pre-existing
  • Less than 70 g/GJi
  • At least 70 g/GJi

n/a

26
  • n/a
  • 2026 / 2036

Transitional
  • Rated capacity (size) [GJi/hr]
  • Packaged or non-packaged

26–40
  • Packaged: 3 months after the date of registration of the Regulations
  • All other: 36 months after the date of registration of the Regulations

Redesigned
  • None

26
  • Upon recommissioning

Modern
  • Fuel type: natural or alternative
  • For boilers: thermal efficiency
  • For heaters: air preheat

16–25
  • 2016

Note: Some AQMS sectors have no pre-existing boilers or heaters that are subject to the obligation (for example, cement has no equipment that would be considered to be a boiler or heater under the Regulations).

Monitoring Requirements for Boilers and Heaters

In addition to NOx performance standards, the Regulations also impose monitoring requirements. All boilers and heaters larger than 105 GJi/hour that are required to meet the performance standards, such as modern equipment, transitional equipment, redesigned and Class 70 and Class 80 equipment that have undergone a major modification, are required to submit compliance reports to demonstrate their continued compliance with the Regulations. Additionally, those boilers and heaters that are greater than 262.5 GJ/h are required to continually monitor their emission-intensity by using a Continuous Emission Monitoring Systems (CEMS). CEMS are generally add-on technologies used to demonstrate compliance. Large boilers and heaters can emit hundreds of tonnes of NOx each year and thus warrant additional monitoring. However, a CEMS does not need to be installed when equipment with a rated capacity of greater than 262.5 GJi/hr

Part 2: Engines (Equipment Type)

The stationary spark-ignition engines burning gaseous fuels covered by the Regulations are typically used for natural gas compression, such as maintaining well pressure or moving gas along pipelines, but can also be used for other purposes, such as driving pumps and back-up generators to provide electricity. They range in size from as small as the engine in a small car to as large as the engine found in a diesel-electric locomotive. They are a significant source of NOx emissions: in one hour of operation, an uncontrolled engine of average size emits as much NOx as a light-duty vehicle does, on average, in almost 325 000 km.

The Regulations impose performance standards for both new (modern) and existing (pre-existing) engines, as set out in Table 3 below. Modern and pre-existing engines are defined based on when they are manufactured relative to the date that the Regulations come into force (see Table 3).

Modern Engines

For modern engines, the performance standards are comparable with those of the current United States Environmental Protection Agency’s New Source Performance Standard (EPA NSPS) for Stationary Spark Ignition Internal Combustion Engines which have been adjusted for Canadian conditions such as the weather and the location of engines. They are also equivalent to British Columbia’s requirements, the jurisdiction with the most stringent limit for engines in Canada. The performance standards for modern engines apply to all regulated sectors. Owners and/or operators of modern engines that have a power greater than or equal to 75 kW must ensure that the NOx emission-intensity of each engine does not exceed 160 parts per million on a dry volumetric basis (ppmvd) or 2.7 grams per kilowatt hour produced (g/kWh). For low-use engines (i.e. those used less than 5% of the time based on a three-year average) with a power greater than or equal to 100 kW, the NOx emission-intensity limit is 160 ppmvd.

Pre-existing Engines

For pre-existing engines, the performance standard and size thresholds are based on retrofit technologies that are currently available, and have been proven in operations. The size threshold for pre-existing engines is higher than that of modern engines in recognition of the challenges and costs of retrofitting smaller engines.

The performance standards for pre-existing engines apply only to facilities in the oil and gas sectors, where more than 95% of industrial natural gas-fueled engines are used.

To minimize costs for small businesses, the Regulations include an exclusion clause for those who identify themselves to the Department. In order to qualify for the exclusion, the engine must be owned and operated by only one person, and the small business, together with its affiliates, must have a gross annual revenue of ≤ $5M and an engine fleet with a total power of ≤ 1 MW.

To take advantage of certain compliance flexibilities in the Regulations, an owner or operator may create a group of pre-existing engines. A group is a collection of pre-existing engines that are either owned or operated by a business and collected for the purpose of calculations required by the Regulations. Pre-existing engines may or may not belong to a group. For pre-existing engines that are not part of a group, the NOx emission-intensity limit is 210 ppmvd or 4 g/kWh, starting January 1, 2021. For pre-existing engines that are included in a group, there are two options: a per-engine approach and a yearly average approach. The two options require the same NOx emission-intensity limit of 210 ppmvd or 4 g/kWh to be met by 2026, but provide flexibility in how to achieve the reduction targets. Some engines can emit below the performance standard as a result of using more effective control technologies, while others can emit above, as long as the average annual emissions of the engines meets the standard.

Registration and Reporting Requirements for All Engines

These performance standards can be achieved cost-effectively by installing emission control technologies, including, but not limited to, non-selective catalytic reduction (NSCR) for rich-burn engines (which is similar to a catalytic converter used in vehicles), pre-combustion chambers for lean-burn engines and conversion of rich-burn engines to lean-burn engines using engine management systems. (see footnote 3) Lean-burn engines tend to be more efficient and produce lower NOx emissions than rich-burn engines since the excess air ensures more complete combustion of the fuel and reduces the temperature of the combustion process.

Pre-existing, low-use engines are not subject to any emission requirements but owners or operators are required to record the operating hours to prove that those engines are operating under low-use conditions. Low-use engines are expected to represent a small percentage of the total engine fleet. These engines are not a significant source of NOx emissions and are less cost-effective to retrofit than regular-use engines.

The Regulations require the owner or operator of an engine to submit information to the Government. All engines in operation are required to be registered, involving the submission of information identifying the regulated engines. For modern engines, the engine must be registered and the results of emission testing submitted annually starting one year after the engine begins to operate. However, there are no emission testing requirements for modern, low-use engines.

For pre-existing engines, registration is required as of January 1, 2019, and annual reports must be submitted as of 2022. For both modern and pre-existing engines, if there are changes to the information regarding the engine, its registration information must be updated at the time of submission of subsequent annual reports.

Table 3: Performance standards for engines

   

Modern engines

Pre-existing engines
 

Criteria

Manufactured on or after the 90th day after the day of registration of the Regulations

Manufactured before the 90th day after the day of registration of the Regulations

Regulated sectors

Aluminium and alumina, base metals, cement manufacturing, chemicals, iron ore pelletizing, iron, steel and ilmenite, nitrogen-based fertilizer, oil sands, petroleum refining, potash, power plants, pulp and paper, and oil and gas

Oil and gas (defined as upstream oil and gas, natural gas transmission pipelines and related underground storage facilities in those two sectors)

Regular-use engines

Engine size threshold (kilowatts, kW)

≥75

≥250

NOX emission limits

2.7 (g/kWh) output or 160 ppmvd corrected at 15% oxygen

Per-engine approach: 4 g/kWh output or 210 ppmvd corrected at 15% oxygen (engines comprising 50% of total power as of 2021; 100% by 2026) or Yearly-average approach: 8 g/kWh output or 421 ppmvd corrected at 15% oxygen as of 2021; 4 g/kWh or 210 ppmvd corrected at 15% oxygen as of 2026

Emission testing

Baseline performance test; ongoing tests and emission checks for engines ≥375 kW in size

Baseline performance test; ongoing tests and emission checks for some engines ≥375 kW in size

Low-use engines

Size threshold (kW)

≥100

≥250 (see note 4*)

NOX emission limits

160 ppmvd at 15% oxygen

None

Emission testing

None

None
Part 3: Cement

The most significant source of air pollutant emissions from cement manufacturing is the kiln. A kiln heats and processes limestone and other material, such as silica, alumina and ferrous oxide, to produce an intermediate product called clinker. Clinker is then ground and combined with other material to produce cement. The Regulations apply to all cement manufacturing facilities that produce clinker for the purpose of producing grey cement. There are currently four types of kilns in the cement manufacturing sector: wet kilns, long dry kilns, preheater kilns, and precalciner kilns.

The Regulations impose kiln-specific performance standards for NOx and SO2 per tonne of clinker produced, as outlined in Table 4 below. The Regulations require that CEMS be used to monitor the release of NOx and SO2, starting in 2018, and impose performance standards starting in 2020.

Table 4: Performance standards for cement kilns

AQMS sectors covered: Cement manufacturing

Pollutant

Kiln type

Performance standard

NOx

Wet kiln

2.55 kg/tonne clinker or 30% reduction in emission-intensity (kg/tonne of clinker) from 2006

Long dry kiln

Preheater kiln

2.25 kg/tonne clinker

Precalciner kiln

SO2

All kilns

3.0 kg/tonne clinker

These performance standards are realistic because they can be complied with by making operational improvements or installing emissions control technologies that are widely available and proven by the cement manufacturing sector. The requirement to use CEMS for monitoring of emissions is a well-established practice within the cement industry. For the cement sector, compliance is assessed at the facility level (i.e. using a facility level average across all kilns within that single facility). This approach provides flexibility and assists in minimizing costs by allowing individual facilities to design and implement the operational and equipment modifications based on their unique circumstances that are required to meet the environmental performance standards for NOx and SO2. For the cement sector, the regulations are designed to “backstop” provincial/territorial action, allowing provinces and territories to be front-line regulators. For cement, an offence occurs if one of the emission limits is contravened for two consecutive years. This gives provinces and territories the opportunity to act first and take appropriate compliance promotion and enforcement actions if a facility is not meeting one of the emission limits during a given year.

Regulatory and non-regulatory options considered

The Department will be implementing the BLIERs using a mix of policy instruments. For each BLIER, regulatory and non-regulatory options have been considered in order to determine the optimal approach. The following presents the outcomes of the analysis only for the BLIERs in the Regulations.

Status quo approach

Industrial emission requirements help to protect air quality and the integrity of the environment. As discussed previously, actions to manage industrial emissions vary from one province or territory to another, creating a patchwork and an uneven playing field for Canadian enterprises. Before AQMS, Canada lacked a nationally consistent approach to controlling industrial air pollutant emissions, and it is unlikely that consistent performance standards can be established both across sectors and Canada-wide in the absence of federal action. The past approach has not proved sufficient to reduce the health and environmental risks across the country. Federal action would demonstrate to Canadians and the United States that we are actively managing our air quality, putting the federal government in a stronger position to discuss further reductions in transboundary flows of air pollutants from the United States, which would have further significant benefits for Canadians.

Market-based instruments

Market-based instruments are one way to provide industry with the flexibility to choose the most cost-effective way to meet the proposed regulatory requirements. However, market mechanisms are not compatible with the fundamental objective of establishing nationally consistent emission performance across Canada. For example, a tax on air pollutant emissions would have different effects in different regional contexts as firms chose whether to pay the tax or invest in abatement equipment; hence no uniform emissions standard could be guaranteed. Since the quantity of emissions reductions cannot be controlled with a tax, this instrument is better suited when an incentive to continually reduce emissions is sought. Similarly, a cap and trade program could lead to no reductions in air pollutant emissions in certain regions where industry elects to pay for permits rather than reduce emissions. For the most part, a performance standard approach is administratively simpler and more efficient to implement compared to a cap and trade system, in a context of a national base level performance. Finally, the use of financial incentives or subsidies to industries would be inconsistent with the “polluter pays” principle.

Voluntary/alternative instrument approaches under CEPA

Under certain conditions (e.g. positive history of co-operation, small and motivated regulatory community), instruments other than regulations can be effective in achieving emission reductions while providing industry with more flexibility.

A Pollution Prevention Planning Notice (P2 Notice) (see footnote 4) and CEPA guidance instruments (such as codes of practice and environmental release guidelines) were considered as instruments for implementing the performance standards for boilers and heaters, engines, and cement facilities. These risk management tools can provide more flexibility to regulatees and are being considered for other BLIERs to determine the most appropriate policy instrument or mix of instruments to achieve public policy objectives. However, these instruments — which do not include mandatory performance requirements — would likely not be the most efficient or effective means to ensure that the AQMS sectors/equipment covered by the Regulations would achieve the objective of implementing national emissions standards to reduce air pollutant emissions across Canada. This is because of the large number of individual entities to be covered (particularly for boilers and heaters, and for engines), and significant variation in industry performance across businesses.

Regulation approach under CEPA

A regulation instrument under CEPA would:

A regulated performance standard approach provides a high level of environmental protection for Canadians, ensures that no single company is allowed to deviate from the emission standards, and can be designed to provide the flexibility necessary to operate in a competitive North American market.

During consultations, NGOs clearly indicated that they expect the federal government to require that industrial air pollutant emissions be reduced from these sources.

For engines, an alternative regulatory approach was considered that would apply to manufacturers and importers of engines rather than to owners and operators. However, manufacturers have indicated that they are not able to ensure emissions levels from in-use engines, since the level of emissions is greatly affected by minor adjustments that are regularly made by the operator of the engine. As a result, the Regulations are made under Part 5, section 93 of CEPA where the quantity or concentration of toxic substances released may be regulated.

The recommended approach is to implement consolidated regulations under section 93 of CEPA, with respect to substances on the List of Toxic Substances. This provides an efficient means of setting requirements, including common requirements such as record-keeping, while reducing administrative burden associated with individual regulations, particularly for those firms that are subject to more than one set of performance standards. Regulations under CEPA allow for potential equivalency agreements with interested provinces, provided that they meet the conditions in CEPA.

Benefits and costs

Three separate cost-benefit analyses were undertaken, one for each of the sector/equipment groups. The analyses are national in scope and take a societal perspective. They are the result of extensive information gathering and consultation with stakeholders, prior to and following prepublication of the Regulatory Impact Analysis Statement in CGI (hereinafter referred to as CGI RIAS). Several questionnaires, teleconferences, and face-to-face meetings were conducted to discuss and clarify comments, and gather additional information to inform the analyses.

The three cost-benefit analyses, sensitivity analyses, and competitiveness analyses are presented below in sections 3, 4, 5, and 6.

Incremental impacts are quantified to the extent possible and are expressed in 2015 Canadian dollars (2015 CAN$). The analytical period is 2016–2035. A real, social discount rate of 3% is used in the analyses for estimating the present value of costs and benefits, consistent with the “Canadian Cost-Benefit Analysis Guide, Regulatory Proposals” (see footnote 5) (TBS Guide). Monetary values are discounted to the base year 2016.

In CGI analyses, monetized impacts were expressed in 2012 CAN$ and the analytical period was 2013–2035. While the same real, social discount rate of 3% was used, monetary values were discounted to the base year 2013.

1. Summary of Results

The Regulations are estimated to result in an aggregate reduction of approximately 2 037 kt of NOx over the 2016–2035 period. The NPV of the Regulations is estimated to be $320M for boilers and heaters and $6B for engines. Incremental impacts of the performance standards for cement facilities are expected to be low and expected to yield an overall net benefit.

The PV of the benefits of the Regulations is estimated to be $410M for boilers and heaters and $6.4B for engines. (see footnote 6) These benefits include human health benefits such as reductions in hospitalization rates and emergency room visits, reductions in sick days experienced by Canadians, and reductions in the risk of premature mortality. The benefits also include environmental benefits such as increased agricultural productivity, reduced soiling, and improved air visibility. Benefits associated with reducing emissions from cement facilities are not monetized, as they are expected to be low.

The PV of the costs is estimated to be $90M for boilers and heaters, $394M for engines, and $9M for cement, largely due to the incremental costs of the technologies required to meet the performance standards. Due to the provision of flexible compliance options and differing requirements for modern versus existing capital, virtually all capital investments involve “add-on” technologies or the purchase of lower-emitting models at the time of natural capital stock turnover, rather than early retirement of capital stock.

Overall, these Regulations are expected to yield significant health and environmental benefits for Canadians. The benefit-to-cost ratios are 5:1 for boilers and heaters and 16:1 for engines.

2. Economic and Atmospheric Models and Data Transformation

A variety of economic and scientific models are used to estimate baseline NOx emissions, emissions reductions, changes in air concentrations, health impacts, environmental impacts, and changes in costs.

Cost-benefit analysis (CBA) models are developed to quantify changes in projected emissions and costs over a period of time. The projected changes in emissions resulting from the Regulations are then processed using the Department’s integrated Energy, Emissions and Economy Model for Canada (E3MC). E3MC assigns emissions changes by province, sector, source, and pollutant and produces emissions inventories of detailed point, area, and mobile sources. The resulting data is then transformed to fit the platform of the Department’s A Unified Regional Air-Quality Modelling System (AURAMS), which is used to determine changes in ambient air concentration. These changes in ambient air concentrations are translated into changes in human health impacts and the associated socio-economic values, which are determined by Health Canada’s Air Quality Benefits Assessment Tool (AQBAT) and changes in environmental impacts, which are determined by the Department’s Air Quality Valuation Model 2 (AQVM2).

Since the prepublication of the CGI RIAS, changes have been made to some of the models above. Key changes made to the CBA models are presented in subsections 3, 4, and 5 below, while model descriptions and data transformation are presented in Annex A.

3. Benefits and Costs: Boilers and Heaters

This section is organized as follows. First, major changes made to the CBA for boilers and heaters presented in the CGI RIAS (hereinafter referred to as CGI BH CBA) are discussed. Second, to provide a general understanding of how the updated CBA was conducted, an analytical framework is presented. This entails a review of the equipment inventory, and the business as usual (BAU) and regulatory scenarios. Lastly, incremental benefits and costs are discussed and sensitivity analyses are presented.

3.1 Notable Changes to CGI BH CBA
Inventory of boilers and heaters

The following changes have been made to the inventory:

Despite these changes, the total quantity of equipment remains relatively the same as in CGI.

BAU NOx emissions

An adjustment was made to account for the voluntary standards set out in the National Emission Guideline for Commercial/Industrial Boilers and Heaters, March 1998 (see footnote 7) (CCME Guidelines), which resulted in lower NOx emissions in the BAU scenario and lower NOx emission reductions.

Useful life of boilers and heaters

The useful life of equipment varies according to the maintenance frequency, equipment capacity, etc. In CGI, it was assumed that all boilers and heaters would be naturally replaced after 40 years in operation. Stakeholders provided feedback that, with proper maintenance, it is possible for large boilers and heaters to have an indefinite service life. It is therefore assumed that boilers and heaters with rated capacity greater than 105 GJi/hr will not be naturally replaced before the end of the analytical period (2016–2035). Even though large boilers or heaters could operate indefinitely, the burners in this equipment are expected to be replaced every 20 years. The useful life of 40 years is retained for boilers and heaters less than or equal to 105 GJi/hr. The assumed average equipment life of 40 years is based on information provided by multiple boiler manufacturers. The burners in smaller equipment are also expected to be replaced every 20 years.

Both the BAU and regulatory scenarios have the same useful life assumptions for boilers, heaters, and burners.

Technology and compliance costs

In CGI, it was assumed that equipment with conventional burners would be replaced with equipment with low NOx burners to meet the performance standards at the end of their useful life. This resulted in an incremental cost of $74,000 per boiler or heater. Stakeholder feedback conveyed that this cost, especially for larger and older boilers and heaters, does not accurately capture the total costs of complying with the Regulations.

To address this concern, the compliance cost function now accounts for greater costs associated with retrofitting larger and older equipment.

Pre-existing equipment (Class 70 and Class 80)

It is assumed that all Class 70 and Class 80 boilers and heaters will require burner replacement in order to comply with the Regulations. For the majority of cases (estimated at around 80%), accommodating a low NOx burner will involve extensive modification to the unit and the existing facility.

In these instances the incremental cost is the difference in total installed cost between installing conventional burners and installing a low NOx burners plus modifications to the equipment and facility, plus the total installed cost of a new burner management system. The average incremental cost of retrofitting these large units is now estimated to be nearly $1M, per boiler or heater.

The other 20% of affected pre-existing equipment would involve a simple burner replacement. In this case the incremental cost is the difference in total installed cost between conventional burners and low NOx burners. The average incremental cost of a simple burner replacement for this equipment is around $171,000, per boiler or heater.

Modern equipment

New packaged equipment is generally delivered pre-assembled and there is no difference in installation cost expected between conventional and low-NOx equipment. The incremental cost is essentially the difference in capital cost. The average incremental cost is about $46,000.

New units with a rated capacity greater than 88 GJi/hr would need to be field-erected. The incremental cost is the difference in installation cost and capital cost for these units. The average incremental cost is about $118,000 per boiler or heater.

Continuous emission monitoring system (CEMS)

It was proposed in CGI that CEMS, operated according to PG/7 (see footnote 8), be required for each boiler or heater with a rated capacity greater than 262.5 GJi/hr. The Regulations have been altered to allow equipment that would have required a CEMS in CGI to instead use data from identical units equipped with CEMS to demonstrate compliance. This is to harmonize with the Alberta CEMS Code, and requirements in other provinces. As such there is no incremental cost associated with CEMS.  

Health benefits

The AQBAT model is updated periodically to reflect the most current scientific and economic research, and the most current demographic information. Since the prepublication of the estimated health impacts of the proposed Regulations, AQBAT has undergone a number of updates. These include updates to the concentration response functions that relate air pollution exposure to individual risks of getting sick, updates to demographics based on the most current Statistics Canada population projections, and updates to the baseline health risks to reflect recent and projected demographic changes. As a result of these recent updates the current version of AQBAT will generate estimates of the health benefits of air quality improvements that are somewhat lower than what would have been estimated using older versions of the model.

Analytical period

The incremental costs and benefits are calculated over the period of analysis beginning in 2016 and ending in 2035. In CGI BH CBA, the analytical period was 2013–2035.

3.2 Analytical Framework

In order to identify and assess the incremental impacts of the Regulations, two scenarios are developed: the BAU scenario, and the regulatory scenario. The BAU scenario depicts what will happen in the absence of the Regulations while the regulatory scenario depicts what will happen with the application of the Regulations. In both scenarios, equipment is assumed to operate at 90% capacity, 340 days per year.

As the Regulations aim to reduce NOx emissions from boilers and heaters, it was necessary to develop an inventory of boilers and heaters to identify affected equipment in all sectors.

Equipment inventory

The quantity of boilers and heaters covered by the Regulations is based on an inventory of pre-existing boilers and heaters in 2015, and forecast growth and contraction of equipment quantities for the period of analysis (2016–2035). The inventory of pre-existing equipment has been updated since the prepublication of CGI BH CBA using information collected by Provincial Safety Authorities and input received from stakeholders (see Table 5). Changes made to the quantity of boilers and heaters are discussed in subsection 3.1 above.

Projected energy demand for industrial sectors by province was used to determine sectoral growth and contraction of equipment quantities for both the BAU and regulatory scenarios. Since the prepublication of CGI RIAS, energy demand projections have been updated. Despite a decline in oil prices, energy demand growth is still expected to be strong in the oil sands sector in Alberta. Growth is also forecast for base metal smelting in Ontario, potash and fertilizer in Saskatchewan and Alberta, and upstream oil and gas in British Columbia. Boilers and heaters are assumed to consume a constant portion of the energy demand in each province and sector throughout the analytical period. In provinces and sectors with expected increases in energy demand, modern equipment with an average rated capacity for that provincial sector is added based on the change in energy demand for that sector. For sectors in which energy demand is forecast to decline, pre-existing boilers and heaters are removed from the inventory in the year of the forecast contraction.

Tables 5 and 6 below show the expected quantity and distribution of equipment in 2035 by AQMS sector and province, respectively. The Regulations, and its associated costs, are not expected to influence the commissioning, de-commissioning, or replacement of boilers and heaters. As such, the quantity of active boilers and heaters is expected to be identical in both the BAU and regulatory scenarios.

In CGI, boilers and heaters in the fertilizer and potash sectors were merged into the same category. They are separated for this analysis.

Table 5: Projected distribution of boilers and heaters by sector, 2035

Sector

Pre-existing equipment in the inventory in 2015

Pre-existing equipment removed from the inventory due to contraction

Projected new equipment added due to economic growth

Total in 2035

Share of total in 2035 (%)

Aluminium

9

0

3

12

1

Base metal smelting

50

-4

31

75

6

Chemicals manufacturing

60

-3

33

90

7

Fertilizer

26

0

28

56

4

Iron and steel

2

0

2

4

0

Oil sands

387

0

326

713

56

Potash

39

0

15

54

4

Pulp and paper

67

0

15

82

6

Upstream oil and gas

179

-6

22

195

15

Total

819

-13

474

1280

100

Note: Totals may not add due to rounding.

Table 6: Projected distribution of boilers and heaters by province, 2035

Province

Quantity

Share of total (%)

Alberta

917

71.7

British Columbia

60

4.7

New Brunswick

7

0.5

Ontario

96

7.5

Quebec

77

6.0

Saskatchewan

123

9.6

Total

1280

100
BAU scenario

Once the inventory is developed, a NOx emission intensity is assigned to each of the pre-existing equipment in the inventory. In the absence of the Regulations, pre-existing units installed prior to 1998 are assumed to have an emission intensity equal to the relevant U.S. EPA AP-42 emission factor, (see footnote 9) which is a function of the rated capacity of the unit and year it was installed. Pre-existing units installed after 1997 are assumed to have an emission intensity equal to the emission intensity recommended in the CCME Guidelines. The CCME emission intensity for boilers and heaters with a rated capacity less than 105 GJi/hr is 26 g/GJi, while equipment with rated capacity greater than 105 GJi/hr is 40 g/GJi. Table 7 shows emission intensities in the BAU scenario.

Table 7: Assumed BAU emission intensities by equipment capacity and commissioning date

Boiler and heater rated capacity (GJi/hr)

Commissioning date

NOx emission intensity (g/GJi)

10.5 to <105

Prior to 1998

42

10.5 to <105

1998 +

26

105 and greater

Prior to 1980

117

105 and greater

1981 to 1998

79

105 and greater

1998 +

40

When pre-existing equipment with a rated capacity less than 105 g/GJi reaches its end of useful life, it is assumed that it will be replaced by a new boiler or heater with the same rated capacity but with an emission intensity equal to the applicable limits of the CCME Guidelines (see Table 7). It was assumed that there is no uptake of low NOx burners in the BAU scenario.

The quantity of modern boilers and heaters is determined by the natural turnover rate of pre-existing equipment, as well as sectoral economic growth. Modern equipment added to the inventory due to economic growth in the BAU scenario is assumed to have an emission intensity between 26 g/GJi and 40 g/GJi based on the average size of boilers and heaters already installed, for a given sector in a given province.

Using the quantity of boilers and heaters (Table 5), and emission intensities (Table 7), emission levels in the BAU scenario are estimated and are shown in Figure 1 below. The overall declining trend of BAU NOx emissions conforms with the assumption that new equipment and turnover equipment will meet the lower emission intensities of the CCME Guidelines. The exception to this overall declining trend occurs during the 2021–2023 period, when a high number of modern equipment is projected to come into operation. This is expected to raise NOx emissions more than the reductions available from equipment being replaced by units with lower NOx emitting technology.

Figure 1: Annual NOx emissions from boilers and heaters covered by the Regulations in the BAU and regulatory scenarios

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

Regulatory scenario

Table 2 shows performance standards by fuel type and certain parameters. However, for analytical purposes, Table 8 is used to assign emission intensities to equipment subject to performance standards in the regulatory scenario. For equipment that has not yet been replaced or retrofitted, the emission intensities in the BAU scenario still hold.

Table 8: Emission intensities assumed for the regulatory scenario

Type of equipment

NOx emission intensity (g/GJi)

Class 70 and Class 80

26

Modern

16

Pre-existing units that emit at least 80 g/GJi are required to meet a performance standard of 26 g/GJi by 2026. Pre-existing units emitting at least 70 g/GJi and less than 80 g/GJi are required to meet the same performance standard by 2036. Based on the inventory of pre-existing boilers and heaters, Class 70 and Class 80 units are all greater than 105 GJi/hr and are therefore assumed to have indefinite service life.

It is assumed that every Class 70 and Class 80 unit will be retrofitted to comply with the emission standard of 26 g/GJi at the time of its next burner replacement. Due to the longer flame produced by low NOx burners, extensive modifications to the unit and facility may be necessary, including a new control system.

If the next burner replacement takes place after the compliance year (2026 for Class 80, and 2036 for Class 70), then burner replacement will be accelerated to the year prior to the compliance date. Pre-existing units that emit less than 70 g/GJi will not be affected by the Regulations, until they are replaced with modern equipment. Table 9 shows the distribution of Class 70 and Class 80 units. The sectors with the greatest number of Class 70 and Class 80 equipment are pulp and paper in Quebec, chemicals manufacturing in Ontario, and oil sands in Alberta.

Table 9: Distribution of Class 70 and Class 80 equipment, by province and sector

Sector

Alberta

British Columbia

New Brunswick

Ontario

Quebec

Saskatchewan

Sector total

Aluminium

0

0

0

0

0

0

0

Base metal smelting

2

1

0

1

1

0

5

Chemicals manufacturing

5

0

0

8

0

0

13

Fertilizer

0

0

0

1

0

0

1

Iron and steel

0

0

0

0

0

0

0

Oil sands

7

0

0

0

0

0

7

Potash

0

0

0

0

0

1

1

Pulp and paper

2

1

0

4

11

0

18

Upstream

5

3

0

0

0

0

8

Provincial total

21

5

0

14

12

1

53

Modern boilers and heaters, installed either due to natural turn over or sectoral economic growth, will be required to comply with a performance standard of 16 g/GJi.

To meet the emission standard, modern equipment will be purchased pre-equipped with low NOx burners rather than conventional burners. Other options are available, including catalytic reduction and flue gas recirculation; however, these options were not retained as they are considered to be less cost-effective alternatives for reducing NOx compared to the integration of low-NOx burners. The distribution of affected modern boilers and heaters due to replacement is represented in Table 10.

Not all modern boilers and heaters are required to meet the emission standards for modern equipment. None of the modern boilers or heaters due to replacement are expected to be transitional. However, it is expected that 42 of the 474 forecast modern boilers and heaters due to economic growth, will be classified as transitional boilers or heaters. As stated in Table 2, equipment installed up to 36 months after the date of registration of the Regulations may be classified as transitional units. The emission standards for transitional equipment are the same as the limits recommended in the CCME guidelines. As such, there are no incremental costs or NOx reductions attributed to these units. The distribution of affected modern boilers and heaters due to economic growth is shown in Table 11.

Table 10: Distribution of modern equipment due to replacement, by province and sector

Sector

Alberta

British Columbia

New Brunswick

Ontario

Quebec

Saskatchewan

Sector total

Aluminium and alumina

0

1

0

0

0

0

1

Base metal smelting

0

4

0

23

1

0

28

Chemicals

23

4

0

0

1

4

32

Fertilizer

20

0

0

0

0

1

21

Iron, steel and ilmenite

0

0

0

0

0

0

0

Oil sands

80

0

0

0

0

13

93

Potash

0

0

1

0

0

30

31

Pulp and paper

1

1

3

11

19

0

35

Upstream oil and gas

83

8

0

0

0

15

106

Provincial total

207

18

4

34

21

63

347

Table 11: Distribution of modern equipment due to economic growth, by province and sector

Sector

Alberta

British Columbia

New Brunswick

Ontario

Quebec

Saskatchewan

Sector total

Aluminium and alumina

0

3

0

0

0

0

3

Base metal smelting

0

0

0

20

9

0

29

Chemicals

12

0

0

4

6

6

29

Fertilizer

13

0

0

0

0

11

25

Iron, steel and ilmenite

0

0

0

0

2

0

2

Oil sands

300

0

0

0

0

0

300

Potash

0

0

0

0

0

10

10

Pulp and paper

1

1

1

5

7

0

15

Upstream oil and gas

0

21

0

0

0

0

21

Provincial total

326

24

1

29

24

28

432

Note: Totals may not add up due to rounding.

Using the information and data above, NOx emissions in the regulatory scenario are estimated and shown in Figure 1, above.

3.3 Incremental Impacts of the Regulations

Air pollutant concentrations resulting from emissions sent to the atmosphere can travel across provincial borders following the wind flow that is typically from West to East. As a result, the health and environmental benefits associated with emission reductions achieved in one province may also be felt in neighbouring jurisdictions.

The present value of the environmental and health benefits associated with the performance standards for boilers and heaters is estimated at $410M over the analytical period. These benefits are expected mainly in Alberta and Saskatchewan.

3.3.1 Incremental Benefits

Emissions of air pollutants such as NOx are precursors to the formation of ground level ozone and secondary particulate matter. The performance standards for pre-existing and new boilers and heaters are expected to reduce NOx emissions by around 98.8 kt between 2016 and 2035, which will result in lower levels of smog and overall better air quality. NOx emissions reductions are broken down into five year periods in Table 12. In CGI, the reduction in NOx emissions was estimated to be around 227 kt. The benefit of emissions reductions has been reduced by about 50%, largely due to the adjustment made to the application of CCME Guidelines when calculating emissions in the BAU scenario.

Table 12: NOx emissions reductions (kt)

2016–2020

2021–2025

2026–2030

2031–2035

Total 2016–2035

13.82

24.60

27.19

33.13

98.75
Health benefits

While there are some direct health benefits of lower ambient levels of NOx, it is the contribution of this pollutant to the secondary formation of particulate matter (PM) and ozone in the atmosphere that has the greatest impact on human health. As shown in Table 13, approximately 60% of the health benefits from the emissions reductions are associated with lower ambient levels of ground-level ozone. Another 28% of the benefits are a result of reductions in PM2.5, with the remainder attributable to reductions in ambient NO2 levels.

Over the 2016 to 2035 period, the reductions in pollutants associated with these performance standards are expected to result in approximately 70 fewer premature mortalities, 60 fewer emergency room visits, 20 000 fewer days of asthma symptoms and 70 000 fewer days of restricted activity in non-asthmatics. The present value of these health benefits over the period is estimated to be close to $390M. The benefits by province/territory are shown in Table 13 below.

Table 13: Present value of health benefits associated with the performance standards for boilers and heaters, by province/territory and health impact (2016–2035) (see note 5*)

  Estimated number of negative health outcomes prevented by the Regulations Economic value of health benefits, by pollutant ($M)
Region Premature mortalities Cardiac and respiratory emergency room visits Asthma symptom days Days of restricted activity in non-asthmatics PM2.5 Ozone NOx Total, all pollutants
Newfoundland and Labrador <1 <1 10 33 N/A 0.18 N/A 0.18
Prince Edward Island <1 <1 <1 <1 N/A 0.38 N/A 0.38
Nova Scotia <1 <1 32 87 N/A 1.10 N/A 1.10
New Brunswick <1 <1 80 240 N/A 2.59 N/A 2.59
Quebec 15 12 3 400 12 000 19.33 57.68 8.66 85.67
Ontario 13 12 3 200 9 400 6.38 58.57 6.52 71.46
Manitoba 3 4 1 200 3 000 2.43 16.30 0.00 18.72
Saskatchewan 11 9 3 200 12 000 26.19 29.90 3.55 59.64
Alberta 27 22 8 400 31 000 50.57 56.71 35.23 142.51
British Columbia 1 2 560 1 800 0.88 4.96 0.11 5.95
Yukon <1 <1 <1 <1 N/A N/A N/A 0.00
Northwest Territories <1 <1 10 21 N/A 0.25 N/A 0.25
Nunavut <1 <1 2 2 N/A 0.00 N/A 0.00
Canada 71 62 20 000 70 000 105.78 228.61 54.07

388.45
Environmental benefits

The AQVM2 model assesses the impact of air quality improvement on agricultural productivity, soiling, and visibility. The estimated national environmental benefits associated with the implementation of the performance standards for boilers and heaters are $21.6M for the period between 2016 and 2035. Table 14 presents the estimated environmental benefits, broken down by impact and province/territory.

Table 14: Environmental benefits associated with the performance standards for boilers and heaters, by province/territory and environmental impact (2016–2035, $M)

Environmental impact

Agriculture

Soiling

Visibility

  

Economic indicator

Change in sales revenues for crop producers

Avoided costs for households

Change in welfare for households

Total

Newfoundland and Labrador

-

-

-

-

Prince Edward Island

-

-

-

-

Nova Scotia

0.02

-

-

0.02

New Brunswick

0.04

-

-

0.04

Quebec

0.71

0.26

0.62

1.59

Ontario

2.02

0.21

0.88

3.11

Manitoba

1.17

0.01

0.85

2.04

Saskatchewan

7.68

0.15

0.95

8.78

Alberta

5.37

0.13

0.44

5.95

British Columbia

0.01

-

0.04

0.05

Yukon

N/A

-

-

-

Northwest Territories

N/A

-

-

-

Nunavut

N/A

-

-

-

Canada

17.03

0.77

3.77

21.57

Note: Totals may not add up due to rounding. N/A indicates data is unavailable for this province/territory.

The performance standards for boilers and heaters will result in decreased ambient concentrations of ground-level ozone. Based on exposure-response functions for 19 different crops, AQVM2 provides the change in production (tonnes) and total sales revenue per Census Agricultural Region (CAR) due to changes in levels of ozone. The present value of the total revenue from increased agricultural productivity is expected to be approximately $17M.

AQVM2 estimates the avoided cleaning costs for Canadian households associated with different levels of particulate matter of 10 micrometres or less (PM10). Over the period, avoided household cleaning costs of $0.8M are expected. These benefits do not account for avoided cleaning costs in the commercial and industrial sectors.

All else being equal, visibility increases as ambient concentrations of particulate matter decrease. Based on willingness to pay for improved visual range, the monetary change in welfare in the residential sector is estimated to be approximately $3.8M over the period.

Other environmental impacts were not assessed due to data or methodological limitations. These include improved visibility on tourism revenues; reduced acid deposition on forests, crops and water ecosystems; and reduced smog on livestock and wildlife mortality.

3.3.2 Incremental Costs

Affected facilities are expected to carry costs to install low NOx burners and retrofitting equipment. Capital and installation costs are discussed in subsection 4.1 above.

Costs to industry

Capital and installation costs

The PV of the total capital and installation costs is estimated to be about $86.2M. As shown in Table 15, oil sands, pulp and paper, and chemicals manufacturing sectors account for about 35%, 23%, and 20% of the total costs, respectively. This is primarily due to the greater amount of Class 70 and Class 80 equipment in pulp and paper and chemicals manufacturing, and the expected growth concentrated in oil sands. Out of 53 Class 70 and Class 80 units in the inventory, 18 are in pulp and paper sector, 13 are in chemicals manufacturing, and 7 are in oil sands. It is expected that 300 out of the 432 modern units commissioned due to economic growth will be in oil sands. Nearly two-thirds of the 347 modern units replacing pre-existing equipment are in the upstream oil and gas, and oil sands sectors. The remainder is shared between the other sectors.

Geographically, of 53 Class 70 and Class 80 units, 47 are found in Alberta, Quebec and Ontario. Five other units are in British Columbia and one is in Saskatchewan. Thus, a larger share of the total costs will be in Alberta, Quebec, Ontario as reflected in Table 16.

Table 15: Present value of total capital costs by AQMS sector ($M)

Sector

2016–2020

2021–2025

2026–2030

2031–2035

Total 2015–2035

Aluminium and alumina

0.02

0.03

0.02

0.04

0.10

Base metal smelting

1.87

3.53

0.15

0.00

5.54

Chemicals manufacturing

8.58

6.36

1.36

0.94

17.24

Fertilizer

0.29

1.28

0.37

0.09

2.03

Iron, steel and ilmenite

0.00

0.02

0.02

0.02

0.06

Oil sands

11.03

10.26

6.02

3.29

30.60

Potash

0.14

0.99

0.44

0.19

1.75

Pulp and paper

7.95

6.21

5.69

0.40

20.25

Upstream oil and gas

0.31

6.75

1.24

0.36

8.66

All sectors

30.19

35.43

15.30

5.32

86.23

Note: Totals may not add up due to rounding.

Table 16: Present value of total capital costs by province ($M)

Province

2016–2020

2021–2025

2026–2030

2031–2035

Total 2015-2035

Alberta

17.33

18.30

9.22

4.35

49.20

British Columbia

0.08

4.07

0.08

0.02

4.25

New Brunswick

0.00

0.00

0.06

0.02

0.09

Ontario

5.98

6.11

2.21

0.18

14.48

Quebec

6.50

5.61

3.01

0.37

15.49

Saskatchewan

0.30

1.33

0.72

0.37

2.72

Canada

30.19

35.43

15.30

5.32

86.23

Note: Totals may not add up due to rounding.

Note the total capital and installation costs have increased from $47.9M (PV) in the CGI to about $86.2M in the updated CBA. This is mainly due to the consideration of the degree of difficulty in retrofitting Class 70 and Class 80 units in the updated CBA, which was not considered in the CGI.

Operating cost

Low NOx burner technology does not require any additional maintenance or other operating costs, so no incremental operation and maintenance costs are attributed to the Regulations.

Administrative cost

Administrative costs include estimated costs of learning about the Regulations, preparing and submitting reports and maintaining records (as described in detail in the section “One-for-One” Rule below). There will be a one-time cost associated with classification reporting of $212,000 in the first year following the date of registration of the Regulations. This is followed by annual costs of $14,300 for annual reports, change-reports, and decommissioning reports. The present value of the reporting and administrative costs over the period 2016 to 2035 is approximately $398,000.

Costs to Government

Costs to the Government fall into two principal categories: enforcement costs and administration costs.

Enforcement

A one-time amount of $209,000 will be required for the training of enforcement officers and $30,000 to meet information management requirements. For the period 2018–2035, the annual enforcement costs are estimated to be about $98,000 broken down as follows: roughly $46,500 for inspections (which includes operations and maintenance costs transportation and sampling costs), $26,500 for investigations, $4,500 for measures to deal with alleged violations (including warnings, environmental protection compliance orders and injunctions) and about $20,500 for prosecutions. The PV of the enforcement costs about is $1.7M.

Government administration

Administration costs are expected to be incurred order to develop electronic reporting infrastructure and to support submissions from regulatees on an ongoing basis. The present value of the administrative costs over the period 2016 to 2035 is approximately $1.4M.

3.4 Summary of Benefits and Costs: Boilers and Heaters

Table 17: Summary of costs and benefits ($M, discounted)

Incremental Costs and Benefits

2016–2020

2021–2025

2026–2030

2031–2035

Total 2016–2035

QUANTIFIED IMPACTS

Benefits to Canadians

Health

59.33

92.08

100.47

136.57

388.45

Environmental

3.82

5.93

5.65

6.17

21.57

Total benefits

63.15

98.01

106.11

142.74

410.02

Costs to Industry

Capital

30.15

35.40

15.44

5.24

86.23

Administrative

0.25

0.06

0.05

0.04

0.39

Total costs to industry

30.40

35.45

15.49

5.29

86.63

Costs to Government

Enforcement, and regulatory administration

1.20

0.73

0.63

0.54

3.10

Total costs

31.59

36.19

16.12

5.83

89.73

Net benefit

31.56

61.82

89.99

136.91

320.29

Benefit-to-cost ratio

-

-

-

-

4.6:1
3.5 Sensitivity Analysis

Sensitivity analysis was conducted by changing one variable at a time while holding other variables constant in order to examine the impact of risks and uncertainty on the net benefits. Key parameters considered here are

All analyses show that key results such as incremental costs and emissions reductions are not highly sensitive to changes in key parameters and that, in all cases, a net benefit is expected.

3.5.1 The Current Market for Low NOx Units

One of the assumptions in the CBA above (the central case) is that firms will not choose to install low NOx equipment in the absence of the Regulations. While low NOx burners have lower NOx emissions, they are more costly for industry and offer no productivity benefits. Table 18 shows total emissions reductions and total capital costs if 5%, 10%, or 20% of modern equipment included low NOx equipment in the BAU scenario. As shown below, changes to low NOx uptake are not expected to significantly change the total capital costs and NOx emissions reductions.

Table 18: Low NOx uptake in the BAU scenario

 

Central case (0%)

5%

10%

20%

Total costs ($M)

89.73

88.42

87.11

84.48

Total NOx emissions reductions (kt)

98.75

96.70

94.65

90.54
3.5.2 Extensive Modification vs. Simple Replacement for Class 70 and Class 80 Units

In the central case, it is assumed that 20% of Class 70 and Class 80 boilers and heaters could be easily retrofitted with low NOx burners, while 80% would require extensive modification to the unit and the facility to comply with the new emissions standard. Table 19 below shows the central case, a case where all Class 70 and Class 80 units need extensive modification (100%, 0%) and a case where 40% of Class 70 and Class 80 units need extensive retrofit (40%, 60%).

Table 19: Extensive modification / simple replacement ratio ($M)

 

Extensive retrofit / simple replacement

100%, 0%

Central case (80%, 20%)

40%, 60%

Total costs

100.83

89.73

78.63

Net benefit

309.19

320.29

331.39

As shown in Table 19, a 20% increase in share of units requiring extensive retrofit is expected to increase the total costs by about $10M while a 20% decrease is expected to decrease the total costs by about $12M.

3.5.3 Useful Life of Equipment with a Rated Capacity ≤ 105 GJi/hr

The analysis assumes a 40-year equipment life for equipment with a rated capacity ≤105 GJi/hr, which resulted in 347 of 819 pre-existing units being replaced during the period of analysis. Table 20 depicts the impacts of changing the useful life of equipment, on total costs and emissions reductions.

Table 20: Quantity of replaced boilers and heaters for shorter and longer equipment life

Sensitivity variables

Equipment life

30 years

Central case (40 years)

50 years

Quantity of boilers that would be replaced at end of useful life

450

400

240

Quantity of boilers that would be retrofitted due to the Regulations

53

53

53

Quantity of new modern boilers due to economic growth

474

474

474

Number of boilers replaced after 2035 (outside of period of analysis)

316

419

526

PV of capital cost ($M)

88.86

86.23

83.60

Total emissions reductions

99.61

98.75

96.64

As shown above, a longer equipment life implies a smaller number of units will be replaced within the period of analysis. Since Class 70 and Class 80 boilers and heaters all have a rated capacity greater than 105 GJi/hr, their service life remains “indefinite”. Altering the useful life of smaller units has a small effect on total emissions reduction and cost relative to the net benefits.

3.5.4 Equipment Growth Rate

The analysis predicts that 474 additional boilers and heaters will be added to the inventory throughout the analytical period. Table 21 shows the total costs and total emission reductions if the quantity of modern boilers and heaters added due to economic growth changed by +/-20%. The results show that changes in equipment growth rate are expected to marginally affect the total capital costs and emissions reductions.

Table 21: Growth rate of equipment

 

-20%

Central

+20%

Quantity of modern units due to economic growth

379

474

569

Total costs ($M)

84.48

89.23

94.98

NOx emissions reductions (kt)

90.54

98.75

106.97
3.5.5 Discount Rate

In the central case, a discount rate of 3% is used to calculate the PV of the benefits and costs. Table 22 shows benefits and costs when there is no discounting (undiscounted values) and when the discount rate is 7%.

Table 22: Discount rate sensitivity analysis ($M)
 

Undiscounted

3%

7%

Total costs

112.09

89.73

69.36

Total benefits

576.91

410.02

274.52

Net benefit

464.82

320.29

205.15

Benefit-to-cost ratio

5.15

4.57

3.96

4. Benefits and Costs: Engines

In the CBA for engines presented in the CGI RIAS (hereinafter referred to as CGI Engines CBA), capital and maintenance costs, fuel savings for control technologies applicable to each engine model, and useful life, were provided in a report prepared for the Department by Accurata Inc. (see footnote 10) Based on comments received after the prepublication of the proposed Regulations, several changes have been made to the underlying assumptions used in the analysis. The notable changes are discussed below. This is followed first by a review of the analytical framework, including and equipment profile, and description of the BAU and regulatory scenarios, then a summary of benefits and costs, and the sensitivity analyses.

The Regulations are expected to mainly affect the upstream oil and gas and natural gas transmission pipelines sectors, and related underground storage facilities in those two sectors. Herein it should be understood that any reference to these sectors includes related underground storage facilities. Incremental impacts on other sectors are expected to be low given that the number of engines in those sectors is expected to be less than 5% of the engine population and only a few engines are expected to be replaced with modern engines during the analytical period (see Table 3 for a complete list of regulated sectors). As a result, the analysis focuses on the incremental impacts of the Regulations on the upstream oil and gas and natural gas pipelines sectors.

4.1 Notable Changes to CGI Engines CBA
Engine inventory

Based on information provided by the Canadian Association of Petroleum Producers (CAPP), the starting inventory of pre-existing engines, which is comprised of rich-burn and lean-burn engines, has been updated with the assumption that 10% of the inventory are held in storage at the start of the analytical time frame. It is assumed these surplus engines have the same emission performance characteristics as those in the pre-existing engine inventory, and that they are used for engine replacement as required.

Also in CGI, pre-existing engines in the inventory were assumed to reach the end of their useful life at a constant annual rate based on expected life of each engine model. This assumption led to a high number of modern engines, which was not consistent with stakeholders’ expectation. It has been revised using sales data provided by engine manufacturers in 2011 that show approximately 66% of the pre-existing engines were installed after 1995 and are unlikely to be replaced prior to 2035. Therefore, it is assumed that only 34% of the pre-existing engines in the inventory are expected to be replaced at a constant rate, based on the expected useful life of each engine model. For low speed, medium speed, and high speed engines the expected useful life is 60, 40, and 20 years, respectively, which means they are replaced at a rate of 1.7%, 2.5%, and 5%, respectively.

As a result of surplus engines and changes made to the installation year, no modern engines are expected to be installed outside of British Columbia before 2031 (discussed further below).

Engine growth and contraction

CGI Engines CBA has been updated to account for contraction in the quantity of engines in service. Contraction occurs when engines were removed from service and placed in storage as a result of decreased energy demand. Conversely, when energy demand increases modern engines are commissioned to meet this demand.

Capital and maintenance costs

In response to comments received, the capital cost to install rich-to-lean engine management systems increased by 40%, and capital cost to install non-selective catalytic reduction (NSCR) decreased by 40% compared to those costs in CGI Engines CBA. Annual maintenance costs for rich-to-lean engine management systems increased by $10,000 and decreased by 50% for NSCR when the engine operates at a NOx level of 2.7 g/kWh.

Although it is possible that some lean-burn engines could be retrofitted, based on an evaluation of the most cost effective control technologies, only rich-burn engines were retrofitted to meet the performance standards in this analysis. Tables 23 and 24 present the control technologies, capital costs, and maintenance costs for modern and pre-existing rich-burn engines, respectively.

Table 23: Control technologies and capital and maintenance costs for modern rich-burn engines

Engine Power and Availability

Control Technology

One time Incremental Capital Cost per Engine ($)

Annual Incremental Maintenance Cost per Engine ($)

Annual Incremental Fuel Consumed per Engine (%)

Less than 250 kW

Non-selective catalytic reduction at 2.7 g/kWh

24,000

10,000

2

Greater than or equal to 250 kW, and still available for purchase

Non-selective catalytic reduction (NSCR) at 2.7g/kWh

21,000 to 111,000

5,000 to 20,000

2 to 4

Rich-to-lean engine management system at 2.7 g/kWh

112,000 to 223,440

-5,000

-5

Greater than or equal to 250 kW, that are obsolete

Replaced by lean-burn engines in the BAU and policy scenarios

No incremental costs

No incremental costs

No incremental impact

Table 24: Control technologies and capital and maintenance costs for pre-existing engines

Control Technology

NOx Level

One time Capital Cost per Engine ($)

Annual Incremental Operation and Maintenance Cost per engine – excluding fuel ($)

Annual Incremental Fuel Consumed per Engine (%)

Rich-to-lean Engine Management System

5.4 g/kWh

77,000 to 175,000

-5,000

-10

2.7 g/kWh

112,000 to 223,000

-5,000

-5

Non-Selective Catalytic Reduction

5.4 g/kWh

21,000 to 111,000

3,000 to 9,000

+1 to +2

2.7 g/kWh

5,000 to 20,000

+2 to +4

Replacement with lean-burn engine with pre-combustion chamber

2.7 g/kWh

720,000 to 2,800,000

-45,000 to -15,600

-24 to -10
Fuel savings

The estimated change in fuel consumption has been reduced by 5% where pre-existing rich-burn engines are expected to be replaced with modern lean-burn engines with pre-combustion chamber.

In CGI, the quantity of fuel saved was 65.6 million million British Thermal Units (MMBtu). Using a constant market price of $4 per MMBtu for processed natural gas, this savings was valued at $152.3M. Implicitly, it was assumed that gas consumed by engines was processed gas.

In the current analysis, the estimated quantity of fuel saved is 84.6 million MMBtu. However own-use fuel reported by industry is typically categorized as raw gas, rather than processed gas. Moreover, the reduction in consumption of own-use fuel occurs across the processing chain and is not limited to raw gas. Due to limited information pertaining to the proportion of engines using raw rather than processed gas, and the costs incurred in order to make it marketable, this analysis does not monetize fuel savings.

However, it is expected that the estimated fuel saved would continue to be valued in tens of millions of dollars.

GHG benefits

The benefits associated with the reduction in GHG emissions from decreased fuel consumption were estimated at $304.7M in CGI Engines CBA. Based on discussion with stakeholders prior to prepublication, the impact of control technology on methane emissions was assumed to not be significant. As a result, the previous calculation only accounted for CO2 emissions attributable to reduced fuel consumption, and not for increased methane emissions attributable to rich-to-lean engine management system operation. Comments submitted after CGI suggested that methane emissions could have a significant impact on GHG emissions. Lean-burn engines generally have higher methane emissions than rich-burn engines, especially when the engine is running very lean with low NOx emissions. However, there are a number of uncertainties around methane emission estimates as they depend on engine design, how lean an engine is running, and how well the engine is maintained. The data available for methane emissions are for engines operating at NOx levels significantly lower than the limits in the Regulations for pre-existing engines and methane emissions do not have a linear relationship with NOx emissions. It is expected that the increase in methane emissions attributable to rich-to-lean engine management system operation will offset the reduction in CO2 emissions attributable to reduced fuel consumption. As a whole, it is assumed for this analysis that the Regulations will not significantly impact GHG emissions, and GHG benefits to society are assumed to be negligible in this analysis.

Health benefits

As indicated in Section 3.1, the AQBAT model is updated periodically to reflect the most current scientific and economic research, and the most current demographic information.

4.2 Analytical framework

To assess the incremental impacts of the performance standards for engines, it is necessary to establish an engine inventory from 2016 to 2035 and to determine technologies that are expected to be applied to engines to comply with the performance standards. The resulting engine quantities and technologies are the basis of incremental benefits and costs.

Equipment profile

Stationary spark-ignition gaseous-fuel-fired engines are primarily used for the compression of natural gas in the upstream oil and gas and natural gas transmission pipelines sectors, but can also be used for other purposes, such as driving pumps and back-up generators to provide electricity. Engine fleets are largely owned and/or operated by oil and gas firms, and the size of each engine fleet ranges from a few to hundreds of engines. The firms may use other equipment such as turbines or electric drive motors for some of the equipment needs met by engines.

The population of engines is comprised of rich-burn and lean-burn engines. Lean-burn engines tend to be more efficient and produce lower NOx emissions than rich-burn engines since the excess air ensures a more complete combustion of the fuel and reduces the temperature of the combustion process. Exhaust emissions can be reduced using post-combustion control such as NSCR, or passive emission control technology for NOx such as rich-to-lean engine management systems or pre-combustion chambers.

Engine inventory

As a starting point, the analysis used a partial inventory, comprised of pre-existing engines operated by seven large Canadian companies in 2010. The partial inventory was scaled up to obtain the total number of pre-existing engines (starting inventory) using the NOx emissions data from that year in the 2015 Air Pollutant Emission Inventory, and assuming that pre-existing engines account for 85% of total NOx emitted in the upstream oil and gas sector. As a result, the number of pre-existing engines with a power rating ≥250 kW is estimated to be 6 756, spread across 226 different models (see Table 25 below). The number of pre-existing engines with a power rating between ≥75 kW and <250 kW is estimated to be 2 604, spread across 67 different models. The total number of surplus engines is estimated to be 936. The adjusted inventory forms the basis for this analysis.

Table 25: Starting and adjusted inventories of pre-existing engines, 2016-2035

Engine Power

Sector

Starting inventory

Adjusted inventory (due to net contraction)

≥250 kW

Natural gas transmission pipelines

81

81

Upstream oil and gas

6 756

6 246

Surplus

676 (10%)

1 013

≥75 kW and <250 kW

Upstream oil and gas

2 604

2 332

Surplus

260 (10%)

458

Total

10 377

10 130

For the natural gas pipelines sector, a starting inventory of pre-existing engines was provided by the Canadian Energy Pipeline Association. This inventory did not require scaling up as it is comprised of comprehensive pre-existing engine-level data.

Table 26 below shows growth and contraction of the quantity of engines for the upstream oil and gas sector for Canada.

Table 26: Expected growth and contraction in upstream oil and gas sector

 

≥250 kWh

≥75 kW and <250 kW

Province 

Growth

Contraction

NET

Growth

Contraction

NET

British Columbia

1 330

-6

1 324

709

-3

706

Alberta

181

-608

-427

96

-324

-228

Saskatchewan

63

-146

-83

33

-78

-44

At the provincial level, British Columbia is expected to have significant growth due to forecasted increases in shale gas production, and the associated need for engines to supply compression to produce, process, and transport that gas. However, no incremental benefits and costs associated with growth and contraction in British Columbia are anticipated in the analysis, since the province has the Oil and Gas Waste Regulation, which is at least as stringent as these Regulations for most modern engines.

Alberta, Saskatchewan and the rest of Canada are expected to have significant contraction of quantity of engines due to forecasted reductions in natural gas and conventional oil production. For simplicity, to account for contraction of engine quantity, pre-existing engines are removed from service and added to storage. The analysis assumes that some engines removed from service would not be used for replacement since they have a limited useful life remaining. As a result, of the 510 engines ≥250 kWh forecast to be removed from service in Alberta and Saskatchewan, 337 are expected to be added to storage. Similarly, of the 272 engines ≥75 kW and <250 kW removed from service in Alberta and Saskatchewan, 198 are expected to be added to storage. The resulting adjusted inventory is shown in Table 25 above.

No growth/contraction of the quantity of engines used in the natural gas pipelines sector is expected.

Business as usual scenario

In the BAU scenario, NOx emission intensities provided by stakeholders are applied to each engine model in the adjusted inventory. Emission intensities vary by model and type (rich-burn / lean-burn) and range from 0.7 g/kWh for lean-burn engines equipped with a pre-combustion chamber to 39 g/kWh for uncontrolled rich-burn engines.

Pre-existing engines that reach the end of their useful life are replaced with identical engines from storage. When the storage inventory is depleted, pre-existing engines are replaced with modern engines of the same power and emission intensity. If the engine model to be replaced is obsolete, it is replaced with a lean-burn engine of the same power for engines ≥450 kW and by rich-burn engines of the same power for engines <450 kW.

If a modern engine replacing a pre-existing engine is subject to provincial NOx emission regulations, it is assumed to be in compliance with those emission intensity requirements while operating at the same power rating as the engine it replaces. There are two provincial policies incorporated in the BAU:

Total NOx emissions are modelled using engine power, load, utilization, quantity of engines and emission intensity for each engine model in the inventory (see footnote 11). BAU NOx emissions from engines in the upstream oil and gas and natural gas transmission pipelines sectors are shown as the dashed line in Figure 2.

Figure 2: NOx emissions for engines in the BAU and regulatory scenarios (kt)

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

Regulatory scenario

As presented in Table 3, for pre-existing engines, operators have two options to comply with the regulatory requirements — the per engine approach, and the yearly average approach. The yearly average approach offers greater flexibility as some engines can emit below the performance standard while others can emit above, as long as the average annual emissions of the engines meets the standard.

Particularly, in this analysis, the adjusted inventory is treated as a single group of engines and that this engine group is assumed to meet a yearly average emission intensity of 8 g/kWh in 2021 and 4 g/kWh in 2026. For modern engines, a performance standard of 2.7 g/kWh must be met.

The yearly average is calculated by dividing the total emissions from the group by the total energy produced by the group. The Regulations allow operators the option of replacing pre-existing engines with modern engines, turbines or electric motors, in order to meet their yearly average limit. However, the total power of replacement units may not exceed the total power of replaced or retired pre-existing engines. As a result, modern engines replacing pre-existing ones are included in the yearly average emissions calculation, but modern engines added due to growth are not.

To meet the yearly average, pre-existing engines must be retrofitted and it is assumed only engines that have more than 10 years of useful life remaining will be retrofitted prior to the compliance date. An Engine with less than 10 years or useful life remaining would continue to operate as usual until it is replaced at the end of its useful life.

As in the BAU, pre-existing engines at the end of their useful life are expected to be replaced with identical engines from storage. Surplus engines are not required to meet 2.7 g/kWh when activated from storage as they are not modern engines as defined by their manufacturing date. They are assumed to have the emission intensities of those they replace and are retrofitted as needed to meet the yearly average emission intensity. When the storage inventory is depleted, modern engines will be purchased for engine replacement and are required to meet a performance standard of 2.7 g/kWh.

The rich-to-lean engine management system operating at 5.4 g/kWh is expected to be the primary retrofit option where applicable based on total capital, operating, and fuel consumption costs. For engine models where this technology is not applicable, NSCR is expected to be installed. In very few cases it is expected to be more cost effective to replace the unit altogether with a lean-burn engine with pre-combustion chamber. Table 27 provides a breakdown of engines by retrofit technology used.

To meet the 2021 yearly average requirement of 8 g/kWh, 323 pre-existing engines will be retrofitted with a rich-to-lean engine management system in 2020. The engine models selected for retrofits are among the highest emitting, highest power rating, and are among the most common engines in the adjusted inventory. These retrofits reduce the emission intensity for each pre-existing engine from 29.5 g/kWh to 5.4 g/kWh.

To meet the 2026 yearly average requirement of 4 g/kWh, an additional 1 579 pre-existing engines will be retrofitted, including engines activated from storage between the years 2021 and 2025. No further retrofitting is expected after the yearly average is met in 2026. However, 277 modern engines are expected to be commissioned between 2031 and 2035 as surplus engines are depleted.

Table 27: Engines requiring retrofits in the upstream oil and gas sector

Engine Category

2016-2020

2021-2025

2026-2030

2031-2035

TOTAL

≥250 kW pre-existing engines retrofitted with rich-to-lean engine management system

323

829

0

0

1 152

≥250 kW pre-existing engines retrofitted with non-selective catalyst

0

717

0

0

717

≥250 kW pre-existing engines replaced with a modern engine equipped with pre-combustion chamber

0

33

0

0

33

≥250 kW modern engines commissioned to replace pre-existing engines due to end of useful life

0

0

0

277

277

TOTAL

323

1 579

0

277

2 179

It is assumed that most engines in the natural gas transmission pipelines sector will not be naturally replaced by 2035. These engines are assumed have a useful life longer than 60 years, since they often see intermittent use, burn high-quality fuel, are well maintained. However, engines that do reach the end of their useful life in the analytic period are expected be replaced with turbines that are not subject to emission requirements under the Regulations. Table 28 categorizes the engines inventory over the period of analysis for the natural gas transmission pipelines sector.

Table 28: Engines requiring retrofits in the natural gas transmission pipelines sector

Engine Category

2016-2020

2021-2025

2026-2030

2031-2035

Total

≥250 kW pre-existing engines retrofitted with rich-to-lean engine management system

8

1

0

0

9

≥250 kW pre-existing engines retrofitted with non-selective catalyst

12

6

0

0

18

≥250 kW pre-existing engines replaced with modern engines equipped with pre-combustion chamber

3

9

0

0

12

TOTAL

23

16

0

0

39

NOx emissions in the regulatory scenario from engines in the upstream oil and gas and natural gas transmission pipelines sectors are shown as the solid line in Figure 2.

4.3 Incremental impacts of the Regulations
4.3.1 Benefits

The performance standards for modern and pre-existing engines are expected to reduce NOx emissions by about 1 932 kt between 2016 and 2035 (see table 29 below).

Reductions in NOx emissions resulting from the performance standards for engines are expected to result in lower levels of fine particulate matter and ground-level ozone, which are the two main components of smog. 

It is estimated that the PV of the total environmental and health benefits associated with the performance standards for engines will amount to about $6.4B over the period.

Table 29: NOx emissions reductions (kt)

 

2016-2020

2020-2025

2026-2030

2031-2035

Total

NOx emissions reductions

39

327

775

791

1 932
Health benefits

As shown in Table 30, approximately half of the health benefits from the emissions reductions are associated with lower ambient levels of ground-level ozone. One third of the benefits are a result of reduction in fine particulate matter, with the remainder attributable to reductions in ambient NOx levels.

Over the 2016 to 2035 period, the reductions in pollutants associated with this initiative are expected to result in approximately 1 200 fewer premature mortalities, 1 000 fewer emergency room visits, 370 000 fewer days of asthma symptoms and 1 300 000 fewer days of restricted activity in non-asthmatics. The PV of these health benefits over the period is estimated to be about $6B, of which, approximately three quarters are accrued in Alberta. The benefits by region are shown in the table below.

Table 30: PV of health benefits associated with the performance standards for engines, by Canadian province/territory and health impact (2016-2035, $M)

Province/ territory Aggregate counts of selected health impacts PV of total avoided health outcomes by pollutant ($M)
Premature mortalities Cardiac and respiratory emergency room visits asthma symptom days Days of restricted activity in non-asthmatics PM2.5 Ozone Other (NOx) TOTAL
Newfoundland and Labrador 2 2 260 740 NA 9.01 NA 9.00
Prince Edward Island <1 <1 110 270 NA 2.49 NA 2.48
Nova Scotia 4 3 680 2 400 3.37 15.65 0.06 19.06
New Brunswick 3 3 540 1 500 NA 14.65 NA 14.63
Quebec 35 34 8 800 25 000 16.38 159.19 0.69 176.25
Ontario 89 86 26 000 78 000 61.36 374.74 20.42 456.12
Manitoba 42 46 14 000 42 000 53.29 163.70 1.33 218.35
Saskatchewan 95 90 29 000 94 000 153.73 314.10 21.80 489.83
Alberta 870 710 280 000 1 100 000 1,668.25 2,063.95 790.29 4,524.86
British Columbia 26 22 8 200 30 000 37.63 87.75 4.21 129.57
Yukon <1 <1 17 41 NA 0.38 NA 0.38
Northwest Territories <1 <1 91 190 NA 1.17 0.05 1.22
Nunavut <1 <1 24 68 0.10 0.03 NA 0.13
Canada 1 200 1 000 370 000 1 300 000 1,994.09 3,206.81 838.86 6,041.89

Note: PM2.5 health impacts for Newfoundland and Labrador, Prince Edward Island and Nova Scotia are not presented as a precise assessment of these marginal changes in ambient levels of particulate matter was not possible. Totals may not add up due to rounding. A dash (-) indicates values are below $50,000.

Environmental benefits

The estimated national environmental benefits linked with the performance standards for engines are expected to be approximately $355M for the period between 2016 and 2035. Table 31 presents the estimated environmental benefits, broken down by impact and by province/territory.

Table 31: PV of environmental benefits associated with the performance standards for engines, by Canadian province/territory and environmental impact (2016-2035, $M)

Environmental impact

Agriculture

Soiling

Visibility

Total

Economic indicator

Change in sales revenues for crop producers

Avoided costs for households

Change in welfare for households

Newfoundland and Labrador

0.01

-

-

0.01

Prince Edward Island

0.13

-

-

0.13

Nova Scotia

0.15

-

-

0.15

New Brunswick

0.18

-

-

0.18

Quebec

3.44

0.46

1.36

5.26

Ontario

13.55

0.48

2.56

16.59

Manitoba

13.33

0.33

3.55

17.21

Saskatchewan

97.82

1.00

7.11

105.93

Alberta

149.1

12.94

45.83

207.89

British Columbia

0.48

0.38

1.06

1.92

Yukon

-

-

-

-

Northwest Territories

-

-

0.01

0.01

Nunavut

-

-

-

-

Canada

278.20

15.58

61.49

355.27

Note: Totals may not add up due to rounding. Benefit estimates below $5,000 are not presented.

The PV of revenue from the resulting increased agricultural productivity is expected to be approximately $278.2M.

AQVM2 estimates the avoided cleaning costs for Canadian households associated with different levels of particulate matter of 10 micrometres or less (PM10). Over the period, avoided household cleaning costs of about $15.6M are expected. These benefits should be considered as conservative as they do not account for avoided cleaning costs in the commercial and industrial sectors.

Welfare gains from improved visibility in the residential sector are approximately $61.5M over the period.

In summary, the total environmental benefits associated with the performance standards for engines are expected to be approximately $355M over the period. Most of these benefits are expected to be experienced in Alberta, followed by Saskatchewan.

Fuel savings

The estimated quantity of fuel saved is estimated to be about 84.6 million MMBtu. While this fuel savings is not monetized, it is expected that the value is significant. Table 32 shows net fuel consumption savings from the Regulations.

Table 32: Net change to fuel consumption (million MMBtu)

 

2016-2020

2021-2025

2026-2030

2031-2035

2016-2035

Net fuel savings

2.05

15.51

33.01

34.03

84.60
4.3.2 Costs

In the analysis, incremental costs are incurred when technology in the fleet of engines changes to comply with the performance standards. Engine operators also incur costs associated with testing, monitoring and reporting emissions from their equipment. The PV of the total costs is estimated to be $394.1M.

Costs to industry

Capital costs

The PV of the capital costs is $251.0M, of which $219.9M is from upstream oil and gas while the remaining $31.2M is from the natural gas transmission pipelines. Most of this cost will be incurred by engines operating in Alberta, British Columbia, and Saskatchewan. The PV of the capital costs over the period 2016 to 2035, broken down by province and five year increments is presented in Table 33.

Table 33: PV of capital costs by province ($M)

 

2016-2020

2021-2025

2026-2030

2031-2035

Total

British Columbia

6.34

30.44

-

-

36.78

Alberta

32.45

133.57

-

3.60

169.61

Saskatchewan

2.83

11.66

-

0.57

15.06

Rest of Canada

10.83

18.57

-

0.19

29.59

Total

52.45

194.23

-

4.36

251.04

Maintenance costs

As outlined in Tables 23 and 24 above, some technologies that meet the performance standards are estimated to require additional maintenance on an annual basis (NSCR) whereas others are estimated to require less maintenance (rich-to-lean engine management systems). The PV of the additional maintenance costs from retrofitting engines with NSCR over the period of analysis is $28.5M. The PV of the avoided maintenance costs over the period of analysis from converting to rich-to-lean engine management systems technology is $44.3M. The net impact of maintenance costs is a saving of $15.8M.

Administrative costs

Administrative costs include estimated costs of learning about the reporting requirements, calculating the yearly average and test results, preparing, updating and submitting information to the engine registry. This includes reporting the operating hours of low-use engines, the test results and the yearly average as well as preparing and maintaining records. It also includes notifying the Minister when a responsible person elects to use the yearly average option. Administrative requirements are described in detail in the section “One-for-One” Rule below. The PV of the reporting and administrative costs over the period 2016 to 2035 is $6.6M.

Testing, monitoring and other compliance costs

Facilities are required to conduct performance tests and emission checks to demonstrate compliance with the limits. A single test is required for engines smaller than 375 kW. For larger engines, ongoing performance tests and emission checks are required. Testing frequencies are not the same for lean-burn engines and rich-burn engines. Testing related costs include the cost to purchase, install, and maintain testing equipment and the cost to conduct the tests. Other compliance costs include estimated costs of adjustment of the air-fuel ratio, installation of hour meter on some engines and development of internal process and training for employees to comply with the technical requirements. The PV of these testing and other compliance related costs over the period 2016 to 2035 is $99.3M.

Costs to Government

Costs of the Regulations to the Government fall into three categories: compliance promotion costs, enforcement costs, and administration costs. The estimates of these are described below.

Compliance and promotion

It is anticipated that incremental compliance promotion costs for the federal government will be $1.7M from 2016 to 2035 to account for effort required to inform businesses about the Regulations. Compliance promotion activities may include technical sessions and the distribution of promotional material. Increased compliance promotion will be offered to small and medium enterprises (SMEs) and to businesses in the oil and gas sector given that the sector includes SMEs, tends to change ownership frequently, uses a much higher number of engines than other sectors, and has to comply with additional requirements. All compliance promotion activities will be adjusted according to compliance analyses or if unforeseen compliance challenges arise.

Enforcement

The Government will incur incremental costs related to training, inspections, investigations, and measures to deal with any alleged violations. With respect to enforcement costs, a one-time amount of $0.3M will be required for the training of enforcement officers and to meet information management requirements. The total PV of the enforcement costs over the period are estimated to be about $5.6M, comprised of the costs of inspections (which includes operation and maintenance costs, transportation and sampling costs), investigations, measures to deal with alleged violations (including warnings, environmental protection compliance orders and injunctions) and prosecutions.

Regulatory administration

Administration costs are expected to be incurred by the Government in order to develop electronic reporting infrastructure and to support submissions from regulatees on an ongoing basis. The PV of the reporting and administrative costs over the period 2016 to 2035 is approximately $1.5M.

The PV of the costs related to these three categories is estimated to total $8.8M over the 2016 to 2035 period.

4.4 Summary of benefits and costs: Engines

Table 34: Summary of benefits and costs ($M, discounted)

Incremental Costs and Benefits

2016–2020

2021–2025

2026–2030

2031–2035

Total 2016–2035

QUANTIFIED IMPACTS

Benefits to Canadians

Health

142.34

1,065.64

2,383.46

2,450.45

6,041.89

Environmental

9.16

68.60

145.95

131.56

355.27

Total

151.50

1,134.24

2,529.41

2,582.01

6,397.16

Benefits to Industry

Maintenance

1.23

9.24

17.87

15.95

44.29

Costs to Industry

Capital

52.45

194.23

0.00

4.36

251.04

Maintenance

0.00

3.57

13.05

11.81

28.54

Administrative

0.91

2.19

1.85

1.60

6.55

Testing and monitoring

13.63

30.21

28.51

26.91

99.27

Costs to Government

Enforcement, compliance and promotion, and regulatory administration

1.57

3.53

2.99

0.67

8.75

Total costs

68.56

233.22

45.11

44.23

394.14

Net benefits

84.17

910.26

2,502.18

2,553.73

6,047.32

Benefit-to-cost ratio

        

16:1

Quantified, Non Monetized Impacts

Net fuel savings (million MMBtu)

2.05

15.51

33.01

34.03

84.60
4.5 Sensitivity Analysis

Sensitivity analysis is conducted by changing one variable at a time while holding other variables constant in order to examine the impact of risks and uncertainty on the net benefits. Key parameters considered here are

All analyses show that key results, such as incremental costs and emissions reductions, are not highly sensitive to changes in key parameters and that in all cases, a positive net benefit is expected.

4.5.1 Capital cost

The capital cost for control technologies is presented in Tables 23 and 24. Costs were determined with input from an Accurata Inc. study and refined through consultation with engine operators and manufacturers. Table 35 shows the total capital cost if the cost of all control technologies were 20% higher, or 20% lower. No changes in emissions are expected as a result of altering these variables.

Table 35: Capital cost ($M)

 

-20%

Central case

+20%

Total capital costs

200.6

251.04

300.5

Net benefit

6,097.76

6,047.86

5,997.86

A 20% change in the capital cost of control technologies corresponds to a $50M change in total capital costs.

4.5.3 BAU emission intensities for rich-burn engines

The emission intensities assigned to the engine models in the inventory are developed with input from stakeholders. Table 36 shows the total costs, including capital and net impact on maintenance, if emission intensities were 20% higher or lower than those assumed in the central case.

Table 36: BAU emission intensities

 

-20%

Central case

+20%

Total capital costs ($M)

225.9

251.04

308.7

Net change to maintenance cost ($M)

-16.4

-15.8

-19.3

Quantity of engines retrofitted or replaced

1 764

2 179

2 453

NOx emissions reductions (kt)

1 173.2

1 923.2

2 760.4

If BAU emission intensities are 20% less than what is assumed in the model, then the yearly average is below the 2021 requirement set by the Regulations. Facilities would not be required to retrofit equipment until 2025. As a result, 415 fewer engines would require retrofit, which would reduce capital cost by $24.6M compared to the central case.

If emission intensities are 20% greater than what is assumed in the central case, more engines would need to be retrofitted in 2020 and 2025. If the control technologies only reduced the emissions intensity to 5.4 g/kWh, then 2 453 rich burn engines would need to be retrofitted before 2026 in order to comply with the required yearly average of 4 g/kWh. The additional retrofit of 274 engines is expected to cost operators an additional $58.2M in capital and save operators an additional $3.5M in maintenance.

4.5.4 Control technology allows meeting 2.7 g/kWh

In the central case, it is assumed that facilities would equip engines with a control technology that reduces emissions to 5.4 g/kWh of NOx. Table 37 shows the cost difference if facilities choose to retrofit engines to achieve 2.7 g/kWh of NOx rather than 5.4 g/kWh of NOx. Since the emission reduction target remains the same, emission reductions changes very little between this case and the central case.

Table 37: Engines operate at 2.7 g/kWh

 

5.4 g/kWh (Central Case)

2.7 g/kWh

Total capital cost ($M)

251.04

230.09

Net maintenance cost ($M)

-15.75

9.23

Total capital and maintenance cost ($M)

234.79

239.32

Quantity of engines retrofitted or replaced due

2 179

1 934

By choosing a more restrictive emission technology, facilities would save on capital cost by retrofitting fewer engines to meet the yearly average, but would incur higher maintenance and fuel costs. Note that the analysis does not monetize fuel costs or savings. In sum, the choice of technology is not expected to significantly affect the total cost.

4.5.5 Discount rate

In the central case for this analysis, the discount rate used to calculate the PV of the costs and benefits is 3%. Table 38 shows the undiscounted values for costs and benefits as well as discounted values at 7%.

Table 38: Discount rate sensitivity analysis ($M)

 

Undiscounted

3%

7%

Total costs

515.86

394.14

283.39

Total benefits

9,541.03

6,397.16

3,962.62

Net benefit

9,025.17

6,047.81

3,679.23

Benefit-to-cost ratio

18.5

16.23

13.98

5. Benefits and Costs: Cement

The CBA has been updated to reflect comments and information received from stakeholders following the prepublication of the proposed Regulations. The update reflects new trends observed and projected for the key variables in the analysis including energy prices, demand for cement, and the use of various combustibles in the cement sector such as natural gas, petroleum coke, and biomass.

With this update, the PV of the total costs for the 2016–2035 analytical period is estimated to be about $9M, a decrease of about $35M from the total costs estimated in the Canada Gazette, Part I, RIAS. For the same analytical period, the total NOx reduction is estimated to be 5.5 kt. No SO2 reductions are expected. In the Canada Gazette, Part I, total reductions of NOx and SO2 were estimated to be 96 kt and 63 kt, respectively. As incremental impacts are expected to be minimal, health and environmental benefits are qualitatively analyzed. Results are presented below.

Cement Sector Profile

Grey cement is composed of limestone, sand, clay, and several other ingredients. (see footnote 12) These raw materials are heated in kilns to produce small, hard granules called clinker. Clinker is the main component used in the cement production process.

In Canada, there are 15 grey cement production facilities distributed across five provinces, with nearly two thirds located in Quebec and Ontario. An additional grey cement facility is expected to become operational within the next few years, in Port-Daniel—Gascon, Quebec. The location and quantity of grey cement production and delivery is correlated with the level of infrastructure development in Canada and certain regions of the U.S. In 2012, production from cement facilities was approximately 13 million tonnes, valued at more than $1.7B. From this production, approximately 3.4 million tonnes (or 26%) were exported, mainly to the U.S. The industry employs over 27 000 people, producing cement, ready mixed concrete, and concrete construction materials.

About 40% of grey cement production facilities in Canada are vertically integrated, meaning that they also own and operate ready-to-use concrete, construction concrete, and aggregate production facilities. Concrete manufacturers are the main intermediaries between cement producers and final users.

Environmental performance in terms of NOx and SO2 emissions from grey cement production facilities varies considerably from one producer to another. Emissions depend on the type of kiln, the type of combustibles used as a source of energy, and the chemical properties of primary feeds. Emissions also vary by province, depending on provincial regulations and permit systems already in place.

There are four types of kilns used in Canadian cement production facilities: wet process kilns, (see footnote 13) long dry kilns, preheater kilns, and precalciner kilns. Research conducted by the United States Environmental Protection Agency (U.S. EPA) concluded that preheater and precalciner kilns are the most energy efficient, and therefore have lower emission intensities. (see footnote 14)

5.1 Main Changes to Canada Gazette, Part I, Cement CBA
Year of Compliance

The dates of compliance for the NOx and SO2 monitoring, reporting, and performance standards have been changed, to give the industry time to implement the necessary requirements (see Table 39 below). The updated CBA assumes that the cement production facilities that are expected to take action will do so in advance of the compliance dates. Therefore, for the analysis of incremental costs, it is assumed that facilities that are expected to take action to reduce their NOx and/or SO2 emissions will do so in 2019. Those who must install a CEMS (monitoring) will do so in 2017.

Table 39: Compliance dates for cement sector requirements

Requirement

Canada Gazette, Part I, proposed compliance date

Canada Gazette, Part II, compliance date

CBA assumption — cost occurrence starting

Monitoring

January 1, 2015

January 1, 2018

2017

Reporting

June 1, 2016

June 1, 2019

2018

Performance standards

January 1, 2017

January 1, 2020

2019
BAU emissions and compliance

In the Canada Gazette, Part I, it was assumed that the emission intensity levels in the BAU scenario correspond to the 2006 environmental performance levels as reported by the facilities under section 71 of the CEPA. The updated BAU scenario uses 2013 emission intensity levels as the basis for establishing emission intensity projections. It also takes into account, to the extent possible, changes to provincial policies and requirements such as the Ontario Regulation 194/05 that sets increasingly stringent emission caps between 2006 and 2015 for NOX and SO2 with tradable permits as well as amendments to facility permits issued to cement facilities under the Alberta Environmental Protection and Enhancement Act.

This update has resulted in lower projected BAU NOx and SO2 emission intensities for most facilities and in some cases higher emission intensities. The lower NOx and SO2 emissions in the BAU can be explained by factors such as the provincial regulations and permit requirements currently in place as well as cement facilities proactively reducing emissions.

Based on the updated emission intensities, for the NOx performance standards, the number of kilns expected to require modification to meet these standards has decreased from five (estimated in the Canada Gazette, Part I) to three. For the SO2 performance standards, the number of kilns expected to require modification has decreased from four to zero. For the CEMS requirement, the number of CEMS expected to be installed as a result of the monitoring requirement has decreased from three to two.

Capital and operating costs for SNCR and CEMS

Capital cost for installing selective non-catalytic reduction technology (SNCR) to reduce NOx emissions has increased by approximately $300,000 to reflect an updated report published by the European Commission on the Cement Industry in 2013. (see footnote 15) This report estimates the unit cost of SNCR at approximately $1.3M compared to approximately $1M in the previous report published in 2010.

The operating cost for SNCR has increased in comparison to the Canada Gazette, Part I analysis, going from $0.50 per tonne of clinker to $0.82 per tonne, reflecting the updated report published by the European Commission on the Cement Industry in 2013. (see footnote 16)

The capital cost for installing a CEMS has decreased from $335,000 to $229,000 to reflect lower expected cost required to modify existing infrastructures. (see footnote 17)

Reporting and administrative costs

The expected number of hours required to complete reporting activities has increased. This update is based on the input provided by the Cement Association of Canada, who surveyed some of its members on the expected number of hours required to complete each reporting activity. The total number of hours increased from 3.7 hours to 23.3 hours, and is broken down as follows:

5.2 Analytical Framework for the Cement sector
Business as Usual Scenario

The BAU scenario provides an overview of what the cement sector will look like if the performance standards for NOx and SO2 emissions are not implemented. The BAU scenario includes, to the extent possible, provincial policies currently in effect as discussed above. It assumes that the number of cement production facilities will remain the same over the analytical period with the exception of a new facility planned for Port-Daniel—Gascons, in Quebec. The new facility is assumed to come online in 2016 with or without the Regulations and employ state of the art technologies. (see footnote 18) Thus, no additional costs will be incurred by the facility to meet the performance standards.

The updated BAU scenario sets emission intensities for NOx and SO2 for each clinker kiln using 2013 emission intensity levels as a starting point. This update takes into account the NOx and SO2 emission levels reported by cement production facilities in the National Pollutant Release Inventory (NPRI). (see footnote 19) The process used to estimate the emission intensity levels for 2013 can be summarized as follows:

Regulatory Scenario

The regulatory scenario sets the emission intensity levels for the NOx and SO2 from each kiln for the analytical period with the application of performance standards for the cement sector.

There are a number of demonstrated practices and technologies in the cement sector that can be used to meet the performance standards for NOx and SO2 emissions. Technologies adopted to comply with the performance standards will likely differ across facilities based on their capacity and processes. These technologies are well established within the cement industry and can be implemented at relatively low cost to the sector.

This analysis assumes that SNCR is the technology each cement facility that needs to take actions will chose to meet the performance standards for NOx emissions. Recognizing that other options exist, that cement facilities may implement other measures to achieve the performance standards, and that these decisions will be made on a case-by-case basis, the compliance technologies assumed in this analysis are representative in that they appear to be the most commonly implemented within the sector and are globally well established as technologies that can be added on to a kiln system to reduce NOx emissions.

It is expected that all of the kilns will be compliant with the SO2 performance standards. Consequently, there are no incremental costs associated with SO2 requirements.

5.3 Incremental Impacts of the Regulations
Benefits to Human Health and Environment

The Regulations are estimated to reduce NOx emissions from Canadian cement facilities by approximately 5 500 tonnes over the next 20 years, which represents only a small reduction relative to the baseline Canadian NOx emissions. As a result, detailed atmospheric modelling and health impact analysis have not been undertaken to precisely estimate the expected health benefits.

However, it is expected that the reduction in NOx emissions resulting from the Regulations for cement facilities will result in health improvements for Canadians. Most emissions of NOx are as nitric oxide (which is rapidly converted to NO2), along with lesser quantities of NO2 itself. Exposure to ambient levels of NO2 are known to negatively impact the health of exposed individuals, increasing health risks and the risk of premature mortality. Additionally, NOx emissions contribute to the secondary formation of both ground-level ozone and fine particulate matter. Both ozone and fine particulate matter are known to have a range of negative health impacts, including exacerbation of asthma and other respiratory illnesses, increased risk of illness and worker absenteeism, increased emergency room visits and hospitalizations due to respiratory and cardiovascular problems, and increased risk of premature mortality.

It is expected that the health benefits of these emission reductions will exceed the costs. It is estimated that achieving the 5 500 tonnes reduction in NOx emissions from the cement sector will cost approximately $10.7M over the next 20 years (undiscounted). This represents a cost to industry of approximately $2,000 per tonne of NOx reduced. Across a wide range of air quality regulations and scenarios that have been analysed by Health Canada in the past, the health benefits of reducing NOx are generally more than $2,000 per tonne, and are often significantly more.

In addition to health benefits, the improvement in air quality stemming from emissions reductions could result in benefits for the environment such as an increase in agricultural productivity, lower cleaning costs due to reductions in particulate matter, improvement in visibility, positive impacts on ecosystems and wildlife, as well a reduction in emissions of short-lived climate pollutants (black carbon).

Costs to Industry

Capital and operating and maintenance costs

Capital costs are modelled as one-time costs. Table 40 below provides a summary of the capital costs of SNCR technology and CEMS based on the expected number of affected kilns.

Table 40: Capital costs for cement facilities

Technology

Number of facilities

Cost per unit ($)

Total PV (2016–2035) ($M)

Selective non-catalytic reduction (NOX)

3

1,317,742

3.6

Continuous emission monitoring systems (monitoring)

2

228,630

0.4

Total capital costs

4.1

Note: Totals may not add up due to rounding.

Facilities are expected to also incur incremental annual operating costs from 2020 to 2035 inclusively. Table 41 below shows operating costs associated with each emission control technology included in the analysis.

Table 41: Operating costs for cement facilities

Technology

Number of facilities

Annual operating cost per unit ($)

Total PV (2016–2035) ($M)

Selective non-catalytic reduction (NOX)

3

Varies by facility based on clinker production - $0.82/clinker ton

1.4

Continuous emission monitoring systems (monitoring)

2

$55,000

1.6

Total operating and maintenance costs

3.0

Note: Totals may not add up due to rounding.

The total costs of installing and operating SNCR is estimated to be $5M ($3.6M in capital costs plus $1.4M in operating costs), which is less than the total costs in the Canada Gazette, Part I, Cement CBA ($23M) due to a smaller number of non-compliant kilns and lower operating costs for SNCR in the updated CBA.

The total costs of installing and operating CEMS is estimated to be $2M ($0.4M in capital costs plus $1.6M in operating costs), which is less than the total costs in the Canada Gazette, Part I, Cement CBA ($4M) due to fewer CEMS necessary to meet the requirements.

Reporting and administrative costs

Administrative costs include the estimated costs of learning about the Regulations, preparing and submitting reports and maintaining records (as described in detail in the section “One-for-One” Rule below). The present value of the reporting and administrative costs over the period is approximately $142,000.

Costs to Government

Costs to the Government associated with the cement requirements fall into two categories: enforcement costs and regulatory administration costs.

Enforcement

The Government would incur incremental costs related to training, inspections, investigations and measures to deal with any alleged violations. Specifically, a one-time cost of about $185,000 would be required for the training of enforcement officers and to meet information management requirements. Also, total cumulative annual costs of $612,000 over the 2020–2035 period would be required for inspections, investigations, measures to deal with alleged violations (including warnings, environmental protection compliance orders and injunctions), and prosecutions. The present value of the total enforcement costs is approximately $580,000.

Regulatory administration

Administration costs are expected to be incurred by the Government in order to develop an electronic reporting infrastructure and to support submissions on an ongoing basis. The present value of the administrative costs is estimated at approximately $860,000.

5.4 Summary of Benefits and Costs: Cement

Table 42: Summary of Costs and Benefits ($M, discounted)

Incremental costs

2016–2020

2021–2025

2026–2030

2031–2035

Total 2016–2035

QUANTIFIED IMPACTS

Costs to Industry

Capital

4.12

0

0

0

4.12

Operating

0.54

0.99

0.81

0.68

3.02

Administrative

0.03

0.04

0.04

0.03

0.14

Total cost to industry

4.69

1.04

0.85

0.71

7.28

Costs to Government

Enforcement, and regulatory administration

0.42

0.47

0.29

0.25

1.44

Total costs

5.11

1.51

1.14

0.96

8.73

QUALITATIVE IMPACTS

Health Benefits to Canadians

  • Reduced risks associated with premature deaths
  • Visits to the emergency room and hospital admissions due to cardiac and respiratory problems
  • Asthma symptoms and restricted activity

Environmental Benefits to Canadians

  • Lower cleaning costs due to reductions in particulate matter
  • Improvement in visibility
  • Positive impacts on ecosystems and wildlife
  • Reduction in emissions of short-lived climate pollutants (black carbon)

Environmental Benefits to the Canadian Agricultural Sector

  • Increased agricultural productivity

6. Competitiveness Analysis

6.1 Boilers and Heaters

The estimated compliance cost impacts associated with the performance standards for boilers and heaters are expected to be distributed across sectors as follows: oil sands (35%), pulp and paper (23%), chemicals (19%), upstream oil and gas (11%), base metal smelting sectors (7%) and other sectors comprising the rest (<2% share for each sector). In line with the sector impacts, estimated costs are expected to be distributed across the country as follows: Alberta (67%), British Columbia (5%), Ontario (9%), Quebec (7%), New Brunswick (1%), and Saskatchewan (11%). All provinces and territories are expected to benefit from the performance standards; however, the largest shares of benefits are expected to be realized in Ontario, Quebec, and Alberta.

Estimated compliance costs are expected to be small compared to other capital and operating costs. For modern units, the incremental investment required would be small relative to the cost of the unit itself (1–10% higher initial capital cost), with units being a small portion of a project’s overall capital cost. Pre-existing units that would need to be modified to meet the emission requirements (i.e. those that are high emitters and likely have no NOx emission controls) would be given a lead time to comply of up to 20 years, meaning that firms would be able to align investments with capital turnover cycles and spread compliance costs over several years.

As indicated previously, the incremental cost of low NOx burner technology per unit used in this analysis is estimated to be between $11,000–$970,000, depending on the size of the boiler. (see footnote 22) On an annual basis, and taking operating costs into account, this would represent less than a 0.5–1.25% cost increase relative to the average annual cost of a non-compliant unit, which, for the vast majority of facilities in the impacted sectors, would be expected to represent a small proportion of total operating costs. (see footnote 23)

The performance standards for boilers and heaters are expected to primarily impact the oil sands sector. Project level financial modelling for a prototypical new build oil sands in situ extraction facility shows that cash flow metrics, such as the internal rate of return of a project and its net present value, remained materially unchanged by the requirements of the performance standards. For example, over the life of the project, the crude oil supply cost (the average price of oil required to deliver a 10% internal rate of return) is increased by no more than 1¢ per barrel of oil produced as a result of the proposed performance standard. This level of change in cost would not be expected to have an impact on investment decisions of a project proponent. The Department conducted extensive consultation with industry stakeholders and to the extent possible, integrated information provided by them into the analysis.

The competitive positions of the sectors that would be affected by the performance standards are varied, and firms within each sector have different capacities to respond to regulatory costs. Many of the firms in the sectors under consideration are energy intensive, are exposed to international competition, and are generally price takers for their products. Some, such as pulp and paper, are currently facing competitive pressures as a result of depressed product prices and structural change in the sector.

In order to account for the competitive pressures facing impacted sectors, the Department has sought to minimize negative impacts through the provision of compliance flexibilities, including lead times of up to 20 years to modify pre-existing boilers and heaters. This additional time would allow for companies to plan investments and time them with plant maintenance schedules, reducing overall costs incurred by companies. As a result, it is expected that the competitive position of firms within these sectors will not change because of the performance standards and market dynamics will remain a far more significant determinant to sector competitiveness. For both new and existing boilers and heaters, the emission limits set in the Regulations are of comparable stringency to those implemented by many states in their State Implementation Plans.

Overall, the compliance costs associated with the standards are expected to have very minor impacts on metrics related to investment and production decisions. Measures of profitability are more significantly impacted by total capital costs, operating costs, sustaining capital costs, product transportation costs, and more volatile variables like energy prices and exchange rates.

6.2 Engines

The estimated compliance cost impacts associated with the proposed performance standards for engines are expected to be distributed across sectors as follows: upstream oil and gas (88%) and natural gas pipelines (12%). In line with the sector impacts, estimated costs are expected to be distributed across the country as follows: British Columbia (12%), Alberta (73%), Saskatchewan (10%), Ontario (3%), and other provinces (2%). Although benefits are expected to be incurred in all provinces and territories, the largest share of benefits will occur in Alberta.

Estimated compliance costs are expected to be small compared to other capital and operating costs. For modern engines, the Regulations are comparable with current U.S. EPA regulations which have been adjusted for Canadian conditions such as the weather and the location of engines. The Regulations are unlikely to create a competitive disadvantage vis-à-vis the U.S. industry. For pre-existing engines, the proposed performance standards provide significant flexibility in both implementation and timing: the requirements include the ability for firms to comply through a yearly average calculation option and the most stringent emissions limit for pre-existing engines do not come into effect until 10 years after implementation. These provisions would reduce the potential for stranded capital and allow firms to plan compliance into maintenance schedules and capital turnover cycles.

Since pipeline tolls are regulated by the National Energy Board, there may be some ability for firms in the sector to pass on regulatory costs if the cost of service has increased, though the impact is not expected to be material given the small magnitude of the costs and the flexibility associated with the proposed performance standards.

Overall, the total undiscounted cost of the proposed performance standards over the period would represent a small increase relative to sector-wide oil and gas net cash expenditures (e.g. the total gross cost for 20 years is equivalent to approximately 0.1% of recent industry cash expenditures in one year), (see footnote 24) though costs would vary across affected firms. Furthermore, net costs to firms for these proposed performance standards are likely to be reduced as a result of fuel savings.

The competitive positions of the sectors that would be affected by the proposed performance standards are varied, and firms within each sector have different capacities to respond to regulatory costs. The upstream oil and gas sector and the firms within it are generally price takers and would not be able to pass on costs to consumers. Furthermore, the upstream oil and gas sector is a cyclical industry and oil and gas prices are at multi-year lows as a result of global oil supply growth outpacing demand growth over the past few years. The most significant determinants of the Canadian sector’s position for investment vis-à-vis competitors are capital and operating costs, along with market prices. The magnitude of these regulatory costs are small compared to these other market dynamics and, as a result, the regulatory costs would not be expected to significantly impact an investment or production decision in Canada.

6.3 Cumulative Impacts

The estimated cumulative compliance cost impacts associated with the Regulations are expected to be distributed across sectors as follows: upstream oil and gas and oil sands (77%), pipelines (10%), pulp and paper (6%), chemicals (5%) and the remaining sectors comprising the rest (<2% share for each sector).

The upstream oil and gas sector is the only sector for which compliance costs were estimated under both the boilers and heaters and the engines regulations. Since June 2014, the price of oil has decreased significantly resulting in job losses, reductions in investment, and slower economic growth in Canada, particularly in provinces reliant on the oil sector. In this context, the Department has considered the cumulative effect of both the proposed boiler and heater and engine requirements on the oil and gas industry. It is important to consider that the oil and gas industry is highly cyclical, and although oil prices are currently low, many analysts do not expect prices to continue at this level in the future, though timing of an oil price recovery is uncertain.

The upstream oil and gas and oil sands sectors are expected to face the majority of the compliance costs associated with the boilers and heater requirements (more than $25M in cumulative capital costs between 2016 and 2025 for the oil sands sector, and $9M for the upstream oil and gas sector). Similarly, the upstream oil and gas sector faces the bulk of the compliance costs arising from the engines requirements ($220M in cumulative capital costs between 2016 and 2025). Several large oil and gas companies may face requirements under both regulations if they produce conventional oil and gas as well as oil sands. These would typically be large companies given that the oil sands sector is comprises primarily of large companies.

Despite the challenges facing the sector, the estimated costs of the regulations for the upstream oil and gas sector, when considered in aggregate, are not expected to have a material impact on sector competitiveness or to change investment or production decisions of oil and gas companies. For example, the Canadian Association of Petroleum Producers estimates that capital expenditures in the Canadian oil and gas industry (including the oil sands) will total $31B in 2016; a sharp decline from the $81B spent in 2014. By comparison, the total expected capital costs for the upstream oil and gas and oil sands sectors to comply with the Regulations are expected to total $306M cumulatively between 2016 and 2025. If capital expenditures continued over the next 10 years at the relatively low levels expected in 2016, total capital expenditures (unadjusted for inflation) would total $310B in 2025. Under such a scenario, the capital costs associated with the Regulations would represent an incremental cost of less than 0.1% over the next 10 years. In addition, the Regulations are expected to result in fuel savings for the upstream oil and gas sector that would partially offset the costs of compliance. Finally, the Regulations include flexible compliance options to reduce the cost burden and enable companies to align investments with capital turnover cycles.

Overall, the upstream oil and gas sector is a cyclical industry and oil and gas prices are at multi-year lows as a result of global oil supply growth outpacing demand growth over the past few years. The most significant determinants of the Canadian sector’s position for investment vis-à-vis competitors are capital and operating costs, along with market prices. Since the magnitude of these regulatory costs are small compared to these other market dynamics, and given the important compliance flexibility options available to regulated companies to meet the proposed Regulations, regulatory costs would not be expected to significantly impact an investment or production decision in Canada.

“One-for-One” Rule

In addition to the effort regulatees will need to make to be in compliance with the performance standards in the Regulations, a number of mandatory administrative tasks will also need to take place. The Department has estimated the resulting incremental administrative burden from the Regulations. Overall, the calculations of administrative burden for each set of performance standards include learning about the Regulations, planning, collecting, processing and reporting of information, completing forms, and retaining data required by the federal government to demonstrate compliance with the Regulations. (see footnote 25)

The Regulations are expected to result in a net increase in administrative burden; therefore, the regulatory initiative is considered an “IN” under the federal government’s “One-for-One” Rule. Following the Treasury Board Secretariat’s standard costing model, and using a 7% discount rate, (see footnote 26) the expected annualized administrative cost to all businesses subject to the Regulations is approximately $273,535 (in 2012 Canadian dollars), including

Only incremental efforts are attributed to the Regulations; therefore, estimates of administrative burden differ depending on the existing reporting requirements at the provincial level. Components specific to each sector/equipment group are as follows.

Boilers and heaters

The following costs are assumed to be incurred by 260 facilities that operate a total of 819 pre-existing boilers and heaters. The wage rate used to estimate costs is around $42 per hour (weighted hourly average).

One-time costs
  1. Learning about the administrative requirements (4 to 4.5 hours per facility or 1.3 to 1.5 hours per Classification Report for a pre-existing boiler or heater); and
  2. Calculating data and preparing, verifying, briefing, signing, record keeping, and submitting information for a Classification Report for pre-existing boilers and heaters:
    • a. Facilities located in provinces that have implemented regulations covering boilers and heaters (i.e. Quebec and Alberta):
      • i. Class 40 (4.5 hours per report), and
      • ii. Class 70 and Class 80 (5.5 hours per report); and
    • b. Facilities located in provinces that have not implemented regulations covering boilers and heaters — Class 40 (5.5 hours per report), Class 70 and Class 80 (6.5 hours per report).
Ongoing costs
  1. Learning about the administrative requirements (4 to 4.5 hours per facility or 1.3 to 1.5 hours per Initial Report for a transitional or modern boiler or heater); and
  2. Calculating data and preparing, verifying, briefing, signing, record keeping, and submitting updates to the Department:
    • a. For a Change Report, e.g. due to a change in an administrative requirement, a switch in fuel type, and/or decommissioning of a unit (1.5 to 3 hours per report);
    • b. For an Initial Report for Class 70 and Class 80 boilers and heaters once modified (3 hours per report);
    • c. For an Initial Report for transitional and modern boiler and heaters:
      • i. Facility located in provinces that have implemented regulations covering boilers and heaters (i.e. Quebec and Alberta) [3.5 hours per report],
      • ii. Facility located in provinces that have not implemented regulations covering boilers and heaters (4.5 hours per report); and
    • d. For a Compliance Report (2.5 hours per report).
Engines

The following costs are assumed to be incurred by 440 businesses that operate 6 300 pre-existing engines in total. The wage rate used to estimate costs is around $42 per hour (weighted hourly average).

One-time costs
  1. Learning about the administrative requirements (5 hours per business);
  2. Preparing, verifying, briefing, signing, and submitting information for inclusion in the engine registry for pre-existing engines (3.25 hours per business and 0.75 hour per pre-existing engine greater than 250 kW);
  3. Calculating, recording and reporting baseline test results for pre-existing engines that require emission testing (0.85 hour per baseline emission test);
  4. Notifying the Minister if electing to use yearly averaging (0.5 hour per business); and
  5. Submitting the assigned emission value for pre-existing engines in the engine registry if electing to use yearly averaging (0.25 hour per pre-existing engine greater than 250 kW).
Ongoing costs
  1. Preparing, verifying, briefing, signing, and submitting updates to the engine registry if changes occur (1.5 hours per business and 0.44 hour per update; updates include the average number of modern engines installed annually and modifications of information for 5% of the pre-existing engines in service each year);
  2. Calculating the yearly average (1 hour per business and 0.25 hour per pre-existing engine greater than 250 kW);
  3. Calculating baseline emission test results for modern engines and ongoing emission test results for all engines (0.5 hour per test);
  4. Preparing, verifying, briefing, signing, and submitting an annual report [1.5 hours per business, 0.25 hour per emission test, 0.25 hour per emission check for each lean-burn engine, 0.25 hour per low-use engine to retrieve operating hours (low-use engines account for 5% of the engines covered), 0.44 hour for each pre-existing engine greater than 250 kW for retrieving information on operating hours and verifying the information required for the calculation of the yearly average]; and
  5. Record keeping (0.1 hour per emission test and emission check, 0.1 to 0.45 hour per engine covered).
Cement

The following costs are assumed to be incurred by each of the 15 covered existing cement facilities and the new facility. The wage rate used to estimate costs is around $42 per hour (weighted hourly average).

One-time costs
  1. Learning about the administrative requirements (3.5 hours per business);
  2. Modifying tombstone facility information (1 hour per business); and
  3. Preparing, retrieving, and verifying historical information for inclusion in compliance report. (1.4 hours per business)
Ongoing costs
  1. Retrieving production values and CEMS emission values (6 hours);
  2. Assessment, calculation and verification of collected values (6 hours);
  3. Reporting or submitting values (1 hour);
  4. Internal meetings to discuss reporting (2.8 hours); and
  5. Copying, distribution and filing (1.6 hours).

Small business lens

The purpose of the small business lens is to drive better analysis of small business realities and consultation at the earliest stages of regulatory design, and to consider flexible compliance approaches that minimize costs for small businesses operating in Canada.

Boilers and heaters

For boilers and heaters, the Regulations include a threshold to include only boilers and heaters with a rated capacity greater than or equal to 10.5 GJi/hr. It is expected that this size threshold would exclude all small businesses using boilers and heaters, and the small business lens therefore does not apply to the boiler and heater provisions.

Engines

A first consultation effort took place in the fall of 2012, prior to the prepublication of the Regulations in the Canada Gazette, Part I. The Department contacted the Executive Director of the Explorer and Producer Association of Canada (EPAC), the association that represents entrepreneurs in the oil and gas sector. EPAC confirmed that there are active small businesses in the sector, but was not able to provide information on the number of small businesses operating engines.

At that time, based on industry databases and two separate rounds of outreach to small businesses in the oil and gas sector, the Department estimated that there were a total of 280 businesses that could potentially operate engines and be classified as small businesses (annual net revenue of $30,000–$5M). All of the potential small businesses for which contact information was available in the database were invited to the information sessions held in 2012, but none attended. These companies were also sent a survey, but a limited number of responses were received.

Due to lack of information, the RIAS of the Regulations published on June 7, 2014, indicated that the Department would propose an exclusion from the requirements for pre-existing engines for small businesses and that the Department would seek to work with small businesses to introduce a workable exclusion.

Outreach efforts after the prepublication in the Canada Gazette, Part I, included

The small businesses in the sector that responded to the Department’s outreach have indicated that they either do not operate engines or that they operate engines that are below the size threshold already in place in the proposed Regulations (250 kW).

Recognizing the possibility that some small businesses that own or operate engines above the size threshold have not self-identified or that larger engines may be owned or operated by small businesses in the future, an explicit exclusion from the requirements for pre-existing engines has been added to the Regulations for small businesses.

Regulatory flexibility analysis

In the absence of an explicit exclusion, should a small business own or operate pre-existing engines greater than 250 kW, it is assumed that the business would choose to comply with the per-engine option, as that is the most cost-effective option for businesses with few engines. With this option, engines will have to be registered, and modified to achieve compliance and performance tests. Reporting and record keeping would also be required.

To provide regulatory flexibility for small businesses owning or operating pre-existing engines greater than 250 kW, the Regulations include an exclusion clause for those who identify themselves to the Department. In order to qualify for the exclusion, the engine must be owned and operated by only one person and the small business, together with its affiliates, must have a gross annual revenue ≤ $5M and an engine fleet with a total power ≤ 1 MW. Small businesses can apply to be excluded from the requirements for pre-existing engines by providing information that demonstrates their eligibility for the exclusion once every three years. Pre-existing engines operated by qualifying businesses do not have to meet emission limits and are not subject to registration and reporting requirements. This option provides small businesses with the flexibility to own or operate large engines that otherwise would have been retrofitted and tested, leading to reduced administrative burden and compliance costs.

In Table 43, below, the administrative and compliance costs between the per-engine option (initial option) and the exclusion (flexible option) for a hypothetical small business that owns or operates pre-existing engines greater than 250 kW. It was assumed that the business owns or operates one lean-burn engine that already emits less than the NOx limit and one rich-burn engine that must be retrofitted by 2026.

Table 43: Administrative and compliance costs for the per-engine and exclusion options for a small business that hypothetically owns or operates two pre-existing engines subject to the Regulations

 

Per-engine (Initial option)

Exclusion (Flexible option)

Short description
  • Record-keeping and reporting requirements regarding performance tests
  • The most cost-effective option for businesses who own or operate few engines (in the absence of an exclusion)
  • Submission of information that demonstrates their eligibility and related record-keeping requirements (once every three years)
  • No compliance costs
 

Annualized average ($)

PV ($)

Annualized average ($)

PV ($)

Compliance costs

Capital costs

3,852

72,000

0

0

Operation, maintenance and testing costs

11,373

244,307

0

0

Administrative costs

Submission of information that demonstrates their eligibility and record keeping

0

0

34

591

Registration, report and record keeping

147

2,841

0

0

Total cost per small business

15,373

319,148

34

591

Risk considerations

No risk

Low risk

Note: Costs have been estimated using the Standard Cost Model, using 2012 Canadian dollars, and a 20-year time horizon using a 3% discount rate. Detailed calculations are available upon request.

Table 43 demonstrates that costs for small businesses operating pre-existing engines under the exclusion option are all but eliminated. The exclusion option imposes an estimated $34 in annualized costs on a small business. The environmental risk associated with the flexible option is low; as the oil and gas sector is dominated by large businesses and the Department has not identified any small businesses that would benefit from this exclusion. As a result, the Department does not expect a significant number of engines to be excluded under these provisions, and any incremental NOx emission increases would therefore be limited and would not compromise the benefits of the Regulations.

Cement

All cement manufacturing facilities in Canada are either entirely or partially owned and operated by large, multinational firms. Therefore, the proposed Regulations would not impose any level of direct compliance cost and/or administrative cost on small businesses.

Consultation

Federal, provincial and territorial governments along with company representatives, industry associations, equipment manufacturers, retrofit companies, testing companies and NGO’s have been working together for many years on a new Canadian system for managing air quality.

Federal officials collaborated extensively with concerned stakeholders and provinces to develop a national framework for managing air pollution as part of the Comprehensive Air Management System (CAMS). The CAMS framework was developed through a collaborative consensus-based process in 2009 and 2010. For over two years under CAMS, more than 300 representatives took part in BLIERs development discussions. The working groups developed preliminary recommendations for industrial emission requirements for nine sectors and one type of industrial equipment. The BLIERs approach was accepted by most organisations involved in the discussions, where NGO’s generally expressed an interest for more stringent standards.

In 2012, the Canadian Ministers of the Environment, as part of discussions of the Canadian Council of Ministers of the Environment (CCME), agreed to move forward on the AQMS framework, which replaced the CAMS framework. Several prominent national environmental and health NGOs were involved in the development of the AQMS and have supported the creation of federal regulations. However, not all NGOs are supportive of the base-level nature of the BLIERs, and in working group discussions, were often in favour of more stringent performance standards.

After March 2012, the BLIERs working groups were dissolved and the Department began pre-regulatory technical discussions with provinces, territories and potential regulatees on the implementation of the BLIERs. In some cases, NGOs were invited to participate in these activities. Stakeholders who contributed to the BLIERs discussions were invited to review working documents and send their comments to the Department for consideration. The Department also shared documents and informed members of the Environmental Planning and Protection Committee of the CCME of progress on the proposed Regulations.

In June 2014, the Government of Canada published the proposed Multi-Sector Air Pollutants Regulations in CGI for a 60-day public comment period. Stakeholders and interested parties were identified and advised of this prepublication and comment period through regular mail, email and telephone calls. A press release and other documents were published on the Department’s web site to inform and share documents with interested parties. Following the prepublication of the proposed Regulations, the Department held several consultation sessions, meetings and webinars with over 500 representatives from over 100 organizations to inform them of the proposed Regulations.

Since the requirements in the Regulations could have an impact on international trade practices, the Department notified the World Trade Organization’s Committee on Technical Barriers to Trade in June 2014, which included reference to the prepublication of the proposed Regulations in the CGI, and the associated public comment period. None of the comments received by the Department made reference to the notification to the Committee on Technical Barriers to Trade.

The Department received a total of 58 submissions during the 60-day public comment period from companies, industry associations, provinces, equipment manufacturers, engineering firms, equipment retrofit companies, environmental testing consultants, and the general public. Comments received by the Department addressed many elements of the proposed Regulations, as well as the Regulatory Impact Analysis Statement (RIAS). Several stakeholders commented on specific provisions, their intent and function. Several comments suggested improvements to the administration provisions in the proposed Regulations. Many of these comments did not impact the general policy intent of the regulations, but were considered in the preparation of the final text of the Regulations.

Since the close of the public comment period in 2014, the Department has continued to engage boiler and heater, stationary engines, and cement sector stakeholders, as well as provincial and territorial partners. In particular, departmental officials:

During formal consultations, no notice of objection was received by the Department which could have led to a board of review being established under section 333 of CEPA.

The Department has made efforts to respond to all the comments received during the 60-day comment period. This RIAS provides a summary of key comments, with departmental responses. More detailed comments and responses are described in the “MSAPR Response to Comments Companion Document” published on the Departmental Web site at (http://www.ec.gc.ca/lcpe-cepa/eng/regulations/detailReg.cfm?intReg=220).

A. Definitions and Coverage-Related Comments
Interpretation

1.1 The Regulations state that an authorized official, in relation to a responsible person that is a corporation, is an officer of the corporation who is authorized to act on its behalf in ensuring and demonstrating compliance with regulatory requirements. Stakeholders asked that the definition of “authorized official” be changed to be clearer and adapted to their specific circumstances. For example, allow an “authorized official” to be an employee of a corporation as opposed to an officer of the corporation and recognize contractors as “certifying officials”.

Response: The Department did not change the regulatory text as a result of these comments. Broadening the definition to include individuals other than company executives would weaken the accountability of the persons affected by the Regulations. In addition, the definition of “authorized official” is consistent with the definition found in other federal regulations (e.g. Renewable Fuels Regulations SOR/2010-189).

1.2 Stakeholders suggested that the definition of “base metals facility” in the Regulations be changed to be consistent with definitions in other Department control instruments (e.g. a Canadian Environmental Protection Act, 1999 — Notice Requiring the Preparation and Implementation of Pollution Prevention Plans in Respect of Specified Toxic Substances Released from Base Metals Smelters and Refineries and Zinc Plants).

Response: The Department did not change the regulatory text as a result of this comment. Definitions of base metals facility used in the above CEPA Pollution Prevention Plan Notice (Ref. Code P2BMS) and Environmental Code of Practice for Base Metals Smelters and Refineries (2006, EPS 1/MM/11 E) are more restrictive than the definition in the Regulations and may not cover some existing facilities and any installation built after the Regulations come into force. Therefore, the definition in the Regulations more clearly describes the application of the Regulations to existing and potential new facilities.

1.3 Several stakeholders commented on the definition of “boiler”, and proposed more exclusions and alternative language, such as for the description of heat transfer fluids.

Response: The Department did not change the regulatory text as a result of these comments. More exclusions and alternative language, as was proposed, would change the definition used to describe a “boiler”, and possibly exempt boilers that are intended to be regulated under the Regulations, thus compromising regulatory outcomes.

Part 1 - Boilers and Heaters
Interpretation

2.1 In several comments, industry expressed their concerns about transitional equipment. Comments were received informing the Department that the definition for transitional equipment was ambiguous and it was also mentioned that a two year period for the application of the transitional period was too short.

Response: The regulatory text has changed as a result of these comments. The definition of transitional equipment has been clarified, by differentiating between boilers and heaters that are packaged and those that are not. Packaged is defined in the Regulations and refers to equipment at a facility that is almost ready to be used.

Also, the period for transitional equipment that is not packaged has been extended from two to three years beginning from when the Regulations are registered. It should be noted that extending the transitional period by an additional year could result in some equipment that would have needed to comply with the emission limits for modern equipment under the CGI text now having to meet the less stringent transitional emission limit. Having more equipment meet a less stringent limit is likely to decrease the amount of reductions achieved by the Regulations; however, modelling has indicated that the expected change to NOx emission reductions should not be significant.

Application

2.2 A number of stakeholders requested that biomass boilers, heat recovery steam generators, boilers that are working together as a unit with fluid coking units, and equipment that is designed to combust either blast furnace gas or coke oven gas be added to the list of excluded boilers and heaters in the Regulations.

Response: The regulatory text has changed as a result of these requests. These specialized equipment types are added to the list of excluded boilers and heaters. Each request to exclude a specific type of equipment was considered separately by assessing the technical, economic and policy arguments both for and against the exclusion of these boiler or heater types. In particular,

2.3 A number of stakeholders requested that auxiliary boilers in power plants, fired equipment used primarily to enable chemical reactions, temporary boilers, stand-by boilers, equipment in offshore facilities, carbon monoxide boilers and brine solution heaters be added to the list of excluded boilers and heaters.

Response: No changes to the regulatory text arose as a result of these requests. Each request to exclude a specific type of equipment was considered separately, by assessing the technical, economic and policy arguments both for and against the exclusion of these boiler or heater types. In these cases, where the requested exclusion was not accepted, the additional information and evidence sent to the Department during the comment period was insufficient or did not support the requests to exclude these boilers and heaters from the Regulations.

Testing

2.4 A wide range of industry stakeholders requested additional flexibility in determining the NOx emission-intensity of their equipment, such as allowing the emission-intensity data from one piece of equipment to represent the emission-intensity of another identical piece of equipment, or using the emission-intensity of a common stack to represent the emission-intensity of the individual pieces of equipment that emit through that stack.

Response: The regulatory text has changed as a result of this comment. The Regulations now allow using emission-intensity data of one piece of equipment as proxy data for other identical pieces of equipment (pre-existing, transitional or modern). The Regulations also allow the use of the emission-intensity measured at a common stack to classify the individual pre-existing pieces of equipment that emit through that stack. The Department believes that using this substitute data under parameters prescribed by the Regulations is an accurate representation of the NOx emission-intensities measurements that are required by the Regulations and will thus not significantly change the number of pre-existing boilers and heaters that are classified as Class 70 or Class 80 (equipment whose NOx emission-intensity has been determined to be greater than 70 g/GJ and greater than 80 g/GJ) under the Regulations. Note that the regulatory text no longer uses the word “original” to describe boilers and heaters commissioned before the date of registration of the Regulations; it has been replaced with “pre-existing” for clarity and consistent terminology used throughout the Regulations.

2.5 Industry requested that emission-intensities from pre-existing equipment, with a rated capacity of less than or equal to 105 GJi/hr, be estimated using the EPA emission factors instead of using actual test results. The U.S. EPA emission factors are estimates of emission-intensities, based on statistics taken from working equipment. The use of emission factors would have resulted in no pre-existing equipment with a rated capacity of less than or equal to 105 GJi/hr being classified as Class 70 or Class 80.

Response: No changes to the regulatory text arose as a result of these comments. U.S. EPA emission factors have a wide variance and are unsuitable for categorizing equipment for regulatory purposes. In fact the U.S. EPA does not recommend the use of emission factors for regulation compliance determinations. Thus the U.S. EPA emission factors cannot be used to assess the NOx emission-intensities of pre-existing boilers and heaters with a rated capacity of less than equal to 105 GJ/hr and greater than or equal to 10.5 GJi/hr. The emission-intensities of this equipment must be measured either directly or by using options available in the Regulations.

2.6 Some industry stakeholders raised concerns about the proposed requirement that all pre-existing equipment must be classified as Class 40, Class 70, or Class 80 within 12 months of the date of registration of the Regulations . These stakeholders indicated that 12 months is not enough time for some companies with large numbers of boilers and heaters, or companies that do not have the necessary testing infrastructure, to test the NOx emission intensity of their equipment.

Response: The regulatory text has changed as a result of these concerns. Four additional provisions now facilitate compliance with this requirement, either through allowing more time to classify the equipment, or through allowing more options for classification. These new provisions do not affect the NOx emission reductions that will result from the Regulations. These provisions allow regulatees, under certain circumstances, the following flexibilities:

2.7 Industry representatives shared their concerns on a proposed requirement that the NOx emission test had to be completed in the same calendar year in which the equipment was commissioned (for modern, transitional) or recommissioned (for Class 70 and Class 80 equipment after a major modification). This requirement could create situations where it would be impossible to meet the regulatory requirements associated to these tests, for equipment commissioned (or recommissioned) towards the end of the year. For some equipment, bad weather in the fall and winter could result in unsafe testing conditions for the people running the tests. Situations beyond the control could prevent completing tests before December 31.

Response: The regulatory text has changed as a result of these comments. The Regulations now require that the NOx emissions test be done within six months of commissioning (or recommissioning) or by May 25 of the next calendar year, whichever is the later date. This change provides the flexibility requested by industry with no impact on compliance and on emission reductions.

2.8 In comments, a number of industry stakeholders questioned the need for NOx emission tests every time the fuel composition switched between natural gas and alternative gaseous fuel.

Response: The regulatory text has changed as a result of these comments. The Department agrees that less frequent testing is sufficient to demonstrate compliance. For equipment with an output smaller than or equal to 105 GJi/hr, the Regulations require one NOx emission-intensity test for natural gas and one for alternative gaseous fuel be done. For equipment with an output that is greater than 105 GJi/hr, the Regulations require one NOx emission-intensity test for natural gas and one for alternative gaseous fuel be done each year.

2.9 Industry stakeholders proposed that the Regulations should not force the use of a Continuous Emissions Monitoring Systems (CEMS) to determine the emission-intensity of large transitional equipment because this requirement does not align with the requirements in some provinces.

Response: The regulatory text has changed as a result of this proposal. The Regulations allow, under certain circumstances, the use of stack testing as a way to test transitional equipment with a rated capacity that is greater than 262.5 GJi/hr.

2.10 Industry stakeholders requested that the Regulations offer the option to change a Class 80 designation for a boiler or heater whose NOx emission-intensity has been determined to be greater than 80 g/GJ, after the initial determination, by submitting test results that demonstrate that the emission-intensity is less than 80 g/GJi.

Response: The regulatory text has changed as a result of this comment. The Regulations now allow the responsible person to temporarily assign a deemed Class 80 designation to a pre-existing boiler or heater and then before December 31, 2022, re-determine its classification by way of a stack or CEMS test. The equipment will be reclassified if those test results demonstrate that the emission-intensity of the pre-existing boiler or heater is less than 80 g/GJi. This additional flexibility will have no impact on emissions.

Maintenance, Operation and Design

2.11 Industry requested the removal of the design standard, which required that modern boilers and heaters that produce more power than 262.5 GJi/hr be designed to emit substantially less (see footnote 27) than the prescribed emission obligations. A number of industry stakeholders commented that the design standard for boilers and heaters would be challenging to implement.

Response: The regulatory text has changed as a result of these comments. The design standard requirement has been removed. The Department agrees with industry’s concerns that the requirement could compromise equipment efficiency, and require a step-change in technology that could be more costly and more technically challenging than the use of low-NOx burners in modern boilers and heaters.

Cost-Benefit Analysis

2.12 A number of submissions indicated that the Department significantly underestimated the cost of installing low NOx burners. One submission indicated that the cost went beyond the capital outlay for the burners, pilots, spare parts, etc. Cost should include the purchase and installation of fuel gas coalescers with concrete foundations, changing piping, burner ring spacing, new control system and engineering, etc. Another comment identified that due to safety and environmental risks, original burners cannot be swapped out of a system for new/different burners that were designed for lower NOx.

Response: Compliance costs have been revised. The CBA now assumes all Class 70 / 80 boilers and heaters will require retrofitting to comply with the Regulation. Eighty percent of those retrofitted units will require extensive modification to accommodate a low NOx burner. The capital cost for boilers and burners is calculated as a linear function of size and a total install cost factor is used to determine total installed cost. Changes in capital and installation costs are discussed in subsection 3.1.

2.13 One submission indicated that low NOx burner technology requires additional maintenance to prevent the much smaller burner tips from plugging.

Response: The Department acknowledges that mixed-fuel boilers and heaters may require additional maintenance to prevent low NOx burner tips from plugging, but this is not expected to be an issue for natural gas fueled equipment, which makes up the overwhelming majority of affected boilers and heaters. The assumption that there would be no incremental operational cost has been retained.

2.14 A submission from a representative in the chemicals industry indicated that the projected quantity of boilers and heaters in Ontario does not align with their expectation. The conditions in Ontario suggest that any increase in demand will be met by imports. Furthermore, nationally, the projected growth in the chemicals sector (a 44% increase) is not expected. In CGI the quantity of boilers and heaters covered by the Regulations operating in the chemicals manufacturing sector in Canada increased from 71 to 102.

Response: In consultation with the Department during the summer of 2015, the Chemical Industry Association of Canada indicated that declining crude oil prices will positively affect demand in the chemicals sector. The association expected demand to increase by 3.9% in 2016. To satisfy demand, production is expected to expand. The short-term economic projections to the year 2019 for all sectors are calibrated to private sector projections used by Finance Canada from their Survey of Private Sector Economic Forecasters report, March 2015. Beyond 2019, long-term key economic assumptions are based on Finance Canada’s “Update of Economic and Fiscal Projections - 2014”. Forecasts of major energy supply projects from the National Energy Board’s Canada’s Energy Future 2016 projections were incorporated for key variables and assumptions in the model (i.e. oil and gas production and price). Since prepublication, energy demand and emissions projections for all sectors have been updated in E3MC using the latest assumptions (see above). In the new projections, the chemicals manufacturing sector is estimated to grow from 57 boilers and heaters to 90 by 2035, a 58% increase, or an annual growth rate of 2.3%. From this growth only five new boilers and heaters are expected to be added in Ontario in the next 20 years.

Sectoral growth is forecast using the economic assumptions listed above and through consultation with sector experts within the Department.

2.15 Several stakeholders asserted that boilers and heaters do not have a natural end of life. With proper maintenance, boilers and heaters can essentially last “indefinitely”, and compliance costs should reflect all the cost of a retrofit and not just the incremental cost for a low NOx burner.

Response: The Department has revised the assumption regarding useful life for boilers and heaters larger than 105 GJ/hr. For the purposes of this analysis, equipment larger than 105 GJ/hr will last at least beyond the end of analytical time frame, 2035. As a result, it is assumed all Class 80 / 70 boilers and heaters will be retrofitted to achieve the emissions standard. Retrofit costs calculated as a function of size, and account for instances where major modification to the facility and equipment is required. The assumption of a 40-year useful equipment life has been retained for equipment smaller than 105 GJ/hr. This number is consistent with information provided by equipment manufacturers and with the age distribution of equipment in the inventory.

2.16 In the context of the boiler and heater regulations, one industry stakeholder noted that the retrofit of equipment could put Canadian industry at a competitive disadvantage versus the U.S. because the U.S. has no requirement to retrofit existing equipment in air attainment zones.

Response: Many sectors covered by the boilers and heaters requirements compete with producers in the U.S. and the competitiveness position of these sectors vary, with firms in each sector having varying abilities to absorb regulatory costs. In order to account for this, the Department has sought to minimize any negative impacts to the competitive position of impacted industries through the provision of compliance flexibilities, including lead times of at least 10 years to modify pre-existing boilers and heaters. This additional time would allow for companies to plan investments and time them with plant maintenance schedules, reducing overall costs incurred by companies.

Part 2 – Engines
Application

3.1 Stakeholders requested that engines used in the aluminium, petroleum-refining and forest product sectors or engines driving generators be excluded from the scope of the Regulations. Other stakeholders supported more comprehensive coverage and indicated that all modern engines should be subject to the Regulations, not only those used by industrial sectors, but also engines used for commercial, institutional and agricultural applications.

Response: The Regulations cover modern engines located at industrial facilities, regardless of whether the engine drives a generator, a compressor or a pump. This decision is the result of extensive discussions with industry, provincial and territorial governments and non-governmental environmental organisations as part of the BLIER discussions. The AQMS framework did not address emissions from, nor consult with, commercial, institutional and agricultural users of engines. For modern engines, the performance standards are comparable to current U.S. EPA NSPS for Stationary Spark Ignition Internal Combustion Engines (which cover non-industrial engines as well), which have been adjusted for Canadian conditions such as the weather and the location of engines. They are also equivalent to British Columbia’s requirements, the jurisdiction with the most stringent limit for engines in Canada.

Obligations

3.2 Stakeholders commented that a two-year delay should be granted to meet the requirements of the Regulations when engines are acquired from other owners. This would allow time for the new owner or operator to retrofit engines to meet the yearly average for the expanded fleet, schedule performance testing and register the newly acquired engines. In the proposed Regulations, the responsible person had to ensure that all engines in their fleet met the requirements, regardless of when they were acquired.

Response: The regulatory text has changed as a result of these comments. The changes provide the flexibility needed to determine the dates on which performance testing is required for recently acquired engines and to retrofit engines that are not already equipped with control technology. While a two-year delay would have created problems with the administration of the Regulations by allowing a significant number of engines to avoid the regulatory requirements, resulting in increased emissions, the following flexibilities have been added:

1. When an engine is acquired, any performance test that would normally have been required may be postponed but must be completed no later than the end of the three-month period following the acquisition. This was added to give the responsible person time to transfer records and to schedule testing for newly acquired engines.

2. A responsible person who chooses the yearly average option has three months to designate the newly acquired engines as belonging to a subgroup and to assign the emission-value to be used to calculate the yearly average, both of which will be retroactively effective as of the date of acquisition.

3. Newly acquired engines that have never been equipped with an emission control system that ensures emissions ≤10 g/kWh have a nine-month grace period from all engine requirements in the regulations. If the engine is not retrofitted and registered by the end of the grace period, the engine may be found out of compliance retroactively. This provides owners and operators the time needed to identify the engines requiring modifications, as well as to perform those modifications.

3.3 The proposed Regulations established less stringent obligations for engines identified as low-use by the owner or operator. The election of an engine as low-use engine could only be done once to avoid the possibility of repeatedly switching between regular-use and low-use designations, thereby taking advantage of less stringent obligations even when using an engine on a regular basis. Stakeholders suggested that an owner or operator should be allowed to designate an engine as low-use engine once every three years. Stakeholders also suggested that the designation of an engine as low-use be allowed at any time during the year, provided that the engine was used as low-use for the first portion of that year.

Response: The Department has changed the regulatory text as a result of these comments to provide additional flexibility. The regulatory text now allows a responsible person to designate an engine as low-use once every three years, and this designation may occur at any time during the year. By limiting the frequency of designation to three years, concerns about switching between engine usage types are minimized.

3.4 The proposed Regulations offered owners or operators the option to replace one or more pre-existing engines that have been removed from their group with one or more modern replacement engines or with one replacement turbine or one replacement electric motor, in order to meet their yearly average limit. For each replacement that would take place, there was a time limit of one year, starting from the removal of the pre-existing engine from the group, in order to include the modern engines, the turbine or the electric motor. For each replacement that would take place, the proposed Regulations required that the modern replacement engines have a total power equal to or lower than the total power of the engines being removed from the group. This limit was designed to avoid situations where a large modern engine replaces a small pre-existing engine, thereby reducing the yearly average without a real reduction in emissions overall.

Stakeholders requested the removal of this limitation on the power of modern replacement engines included in the yearly average.

Response: The Department has changed the regulatory text as a result of these comments. The term “replacement units” now includes all modern engines, turbines, or electric motors that replace pre-existing engines in a group for the purpose of the yearly average. Although there is now a limit of maximum power for all replacement units, there is more flexibility in how to meet this limit. The Regulations no longer have a power limit for each individual replacement that would take place. Instead the requirements apply to all replacements, considered in combination rather than as individual actions. In effect, the concept of a power “bank” has been introduced. Each time a pre-existing engine is removed from the group, its rated power is added to the “bank” The total rated power of all replacement units may not exceed the rated power in the “bank”. The Department also removed the time limit of one year for the replacement of a pre-existing engine, as this power limit must be met at all times for all replacements.

The replacement provisions in the Regulations are designed to provide owners or operators the flexibility to manage their group of pre-existing engines while not compromising the environmental benefits of the Regulations. Removal of the power limit would have allowed owners or operators to meet their compliance obligations without reducing the emissions from their group of pre-existing engines.

3.5 Stakeholders commented on the testing requirements introduced in the proposed Regulations. The regulatory text proposed that performance testing be done in accordance with U.S. EPA methodologies, but not at the same frequencies. The frequency of these tests depended on whether the engine was lean-burn or rich-burn. The comments reflected opposing positions and suggestions included: less frequent testing of engines that have passed two previous tests, alignment of testing frequency with the U.S. EPA in order to have the same testing frequency for rich-burn and lean-burn engines, an increase to the testing frequency for lean-burn engines, and exemptions from testing for engines in remote locations due to the challenge of transporting calibration gases to these sites. Some stakeholders also suggested less frequent performance testing if owners or operators choose to implement more frequent, but less rigorous, emission checks between performance tests.

Response: The regulatory text has changed as a result of these comments. The Department developed a solution which offers testing options to industry without compromising the environmental benefits of the Regulations.

The approach for rich-burn engines provides default and optional testing frequencies. The default is unchanged from what was published in the proposed Regulations: performance testing is required every nine months or 4,380 operating hours, whichever comes first. Optionally, performance testing may be extended to 36 months or 8,760 operating hours, whichever comes first, provided that quarterly (less rigorous) emission checks are performed. The emission check requirements were based on consultations with manufacturers of portable analyzers and testing experts. These changes reduce the number of performance tests by approximately 20% compared to what was proposed in CGI. Performance tests are more onerous than emission checks as they take longer to be performed and the methodology is more rigorous and requires more expertise. Emission checks are already conducted by some companies to make sure that engines are properly operated and maintained.

The approach for lean-burn engines is also a compromise to address comments that recommended increasing the testing frequency for lean-burn engines and comments that suggested less frequent testing for all engines. Unlike the CGI text, pre-existing lean-burn engines subject to the per-engine limit must be tested. Also, a baseline test is required for pre-existing lean-burn engines, prior to the assignment of a default emission value of 4 g/kWh, to demonstrate that the engine is capable of emitting less than this value. The frequency of subsequent tests for lean-burn engines remains unchanged (every 36 months or 17,520 operating hours, whichever comes first). In addition, emissions monitoring of NOx, oxygen and CO must be performed annually for lean-burn engines with a rated power of at least 375 kW, replacing the annual measurement of the oxygen concentration in the exhaust gases that was proposed in CGI.

Though this approach does not align with the testing frequencies used by the U.S. EPA, experts in Canada and the U.S. consulted by the Department indicated that the approach in the Regulations addresses the varying ability of rich-burn and lean-burn engines to maintain low emissions.

As for the exemption for testing engines in remote locations, no change was made to the regulatory text because several testing methodologies are permitted by the Regulations, some of which are already suitable for testing in remote sites as a sample can be extracted and brought to a laboratory with no need to transport calibration gases to these sites.

Operation and Maintenance

3.6 In the proposed Regulations, the responsible person had to install a non-resettable hour meter on each engine to be considered as low-use and on each engine included in the calculation of the yearly average. Stakeholders requested more options by which to determine the number of operating hours in a year. It was suggested that operator logs or supervisory control and data acquisition (SCADA) systems should be allowed to determine the number of operating hours and that, in a case where calculation of operating hours was not possible, a default number of hours could be used for all engines included in a yearly average calculation. It was also requested that less frequent readings be required, moving from two to one per year, if a non-resettable hour meter was used.

Response: The regulatory text has changed as a result of these comments. The Department will now accept data from several sources for determining engine operating hours. When calculating the yearly average, new accepted sources of information include operator logs, automated data acquisition systems such as SCADA systems and replacement of hours with a number of days. This additional flexibility will not compromise the environmental benefits of the Regulations as the operating hours are only used to calculate the yearly average, giving more importance to engines that are used more often and the sources of information added are sufficiently accurate for this purpose.

For low-use engines, the Department has only added SCADA systems as a new accepted source of information. More accurate measurements are needed as engines must operate during less than 1,314 hours in each period of three calendar years (not including emergency operation) in order to be considered as “low use”. Also, for enforcement purposes, more verification is needed to ensure that an engine deemed to be a low-use engine is, in fact, eligible to be exempt from a number of other provisions in the Regulations.

If non-resettable hour meters are to be used, one annual reading, as close as possible to being one year apart, can now be used to provide the data needed, which will impose less of a burden to industry than the twice per year requirement of CGI.

Cost-Benefit Analysis

3.7 Industry stakeholders commented that modern engines projected in the CGI analysis was high and that they have a surplus of engines in storage which would be used to replace engines at their end of life.

Response: In the CGI analysis, no surplus engines were accounted for in the analysis. Based on information provided by industry, the analysis is updated to assume that an additional 10% of the engine inventory is held in storage. It is assumed these surplus engines are used for engine replacement as required and that they have the same emission performance characteristics as those they replace. As a result, fewer modern engines are expected to be purchased since surplus engines are available to be installed.

3.8 Industry commented that since pipelines no longer operate as monopolies, and must compete with other pipelines and modes of transportation, it should not be assumed that costs can be passed on to customers.

Response: Pipeline tolls are regulated by either the National Energy Board for interprovincial and international pipelines or provincial energy boards for intra-provincial pipelines. Firms are generally allowed to recover increased operating or regulatory costs and achieve a regulated rate of return on pipeline assets. Therefore, the Department notes there is a possibility for firms to pass on costs.

3.9 Comments and information on capital costs were received from stakeholders who commented that capital cost for rich-to-lean engine management system technology should be higher and that for NSCR it should be lower. A cost range of $150k–$250k, was provided for installing rich-to-lean engine management system technology. A cost range of $60k–$120k was also provided for installing NSCR. These costs were based on a breakdown of materials and labour required to purchase and install the technologies.

Response: In the CGI analysis, capital costs used were taken from a report prepared for the Department by Calgary-based consultancy Accurata Inc. For similar engine models, the Accurata cost estimates for equipping a sample engine model with a rich-to-lean engine management system ranged from $125k to $160k, and the cost to convert to NSCR ranged from $125k to $165k. The Department shared the cost breakdown with industry in September 2014 and received cost estimate information in response.

Based on the cost estimate information provided by industry, the Department has increased cost estimates for rich-to-lean engine management system technology by 40% relative to CGI estimates due to higher assumed costs related to the existing control system. NSCR capital cost estimates have also been reduced by 40% based on lower cost estimates for exhaust system modifications and field installation. These cost changes are applied to all engine model retrofit options in the inventory. The changes bring the capital cost estimates for rich-to-lean engine management system technology and NSCR into the ranges provided by stakeholders.

3.10 A firm requested that compliance costs to small business be mitigated.

Response: The Department has assessed this request. Following calls to about 250 small businesses in the oil and gas sector during summer 2014 and several outreach efforts since fall 2012, the Department has not identified any small businesses that would be affected by the requirements for pre-existing engines. Recognizing the possibility that some small businesses that own or operate engines above the size threshold have not self-identified or that larger engines may be owned or operated by small businesses in the future, an explicit exclusion from the requirements for pre-existing engines has been added to the Regulations for small businesses. Costs are mitigated for small businesses that meet the exclusion thresholds and submit the required information in order to exclude their pre-existing engines from requirements.

Part 3 - Cement
Interpretation

4.1 Stakeholders raised concerns regarding sections of the regulatory text that deal with prohibitions and how compliance would be assessed. The proposed prohibition provisions for assessing compliance with the SO2 and NOx emission standards suggested that compliance with the emission standards would be assessed on an instantaneous basis and not on an annual basis as was the intent.

Response: The regulatory text has changed as a result of these comments to clarify how the emissions standards apply.

4.2 Cement industry stakeholders expressed concerns that other equally valid methods of establishing clinker production quantities are being used by industry, other than those found in the proposed Regulations, and that these methods should also be allowed for determining production. Furthermore, the Regulations should allow the use of other methods that could be developed in the future.

Response: The regulatory text has changed as a result of these comments. One other quantification method for determining clinker production quantities is accepted and consequently the production provisions are expanded to include this method.

4.3 The Department received a comment that identified an inconsistency in the stack test requirements. Stack test provisions could be interpreted to apply exclusively to NOx. The commenters suggested that this be changed in the Regulations to cover all emission parameters or groupings of emission parameters.

Response: The regulatory text has changed as a result of these comments. The Regulations now include the reference method for sulphur dioxide (SO2) and addresses all of the emission parameters.

4.4 During the consultation process for the development of the air emission standards, the Cement Working Group reached a consensus and proposed that compliance reporting would start two years after prepublication in CGI and that compliance with the emission standards would come into force two years later. This sequencing of compliance timelines was designed to allow cement facilities the time required to design and implement the necessary measures to comply with the requirements of the Regulations. In their comments, stakeholders requested that the compliance dates, as prescribed in the proposed regulatory text, be adjusted to reflect the time elapsed between the prepublication of the proposed Regulations and the publication of the final Regulations.

Response: The regulatory text has changed as a result of these comments. Compliance and reporting timelines are aligned with the compliance period beginning on January 1st of the year following publication of the Regulations in CGII.

Cost-Benefit Analysis

4.5 One stakeholder indicated that the emission analysis for cement did not assume any capital replacement and argued that this could lead to an overestimation of emissions in the BAU scenario. The stakeholder indicated that the analysis should assume that older kilns will be replaced with more energy-efficient kilns in the future, thereby reducing the BAU emissions.

Response: Improvement in energy efficiency is considered in the updated CBA. It is modelled in E3MC, from which emissions, production, and energy efficiency projections were obtained.

4.6 One stakeholder suggested that SNCR costs provided in a U.S. EPA analysis be used for the CBA for estimating compliance costs instead of SNCR costs provided in the report published by the European Commission on the cement industry.

Response: For the purpose of estimating industry compliance costs with the NOx performance standard, the Department has considered a range of studies in the U.S. and Europe. As the costs provided in the European study are associated with a level of stringency that is more comparable with the Regulations than those in the U.S. EPA analysis, the analysis uses the costs provided in the European study. Thus, no changes were made to the CBA.

Part 4 – General
Waivers, Deferrals or Extensions

5.1 A number of stakeholders requested that the Regulations should contain provisions for waivers, deferrals or extensions for situations where an obligation of the Regulations cannot be met in a timely fashion due to circumstances beyond the regulatees’ control.

Response: Changes to the regulatory text that were made as a result of other comments limited the need for waivers, deferrals, or extensions. These changes will address, in part, the requests for waivers, deferrals or extensions.

For example, with respect to boilers and heaters, the proposed regulatory text in the CGI, required that an initial test be conducted, to verify compliance, in the same calendar year as the equipment was commissioned. Industry commented that it may be difficult to meet that timeline if the equipment was commissioned late in the calendar year. The regulatory text was revised and now allows a regulatee six months to conduct an initial test, regardless of when in the calendar year it was commissioned. As a result, an extension is no longer necessary.

For example, with respect to engines, industry commented that it may not be possible to conduct a performance test in the prescribed period when the engine is not operational. As a result, the test may be postponed until the engine is operational again. Also, a nine-month grace period was added for newly acquired engines that have never been equipped with an emission control system to provide more time to install such a system (see question 3.2).

Alternative Rules

5.2 Stakeholders were concerned that quantification methods, such as for sampling, monitoring, testing and measurement methods or protocols, that are accepted in provincial or territorial regulations are not incorporated into the proposed Regulations. In addition, stakeholders were concerned that a facility could be regulated by both federal and provincial/territorial authorities for the same pollutants but possibly with different quantification requirements.

Some stakeholders proposed adding a specific reference to the Alberta Continuous Emissions Monitoring System (CEMS) Code (1998) as an allowable reference method under the definition of “CEMS Reference Method”.

Stakeholders also requested that the Regulations allow the use of a prediction emission monitoring system (PEMS) as an acceptable alternative rule.

Response: The regulatory text has changed as a result of these comments. The Department seeks to limit overlapping regulatory requirements, and recognizes that allowing the use of data collected ’based’ on requirements accepted by provincial or territorial regulations can reduce administrative burden and still achieve federal objectives. As a result, the Alberta CEMS Code, for example, is now incorporated by reference into the Regulations.

The Regulations allow the Minister to authorize the use of alternative rule that are not the same as the ones set out in documents incorporated by reference in the Regulations. An application must be submitted to and approved by the Minister prior to the use of an alternative rule to satisfy regulatory requirements.

The Department also is open to enter into equivalency agreements with interested provinces provided that they meet the conditions in CEPA.

5.3 Stakeholders requested that the alternative rules provisions be applicable for any method, for any purpose and for any process across the entire Regulations.

Response: The regulatory text has changed as a result of this comment. The Minister may now approve alternative rules to replace any rule set out in a document incorporated by reference in the Regulations that concern sampling, analyses, tests, measurements or monitoring of emissions.

B. Policy-related comments
Equivalency / Harmonization / Regulatory Duplication / Front-line Regulator

5.4 Stakeholders suggested that the Regulations should be harmonized with existing provincial requirements to provide regulatory flexibility and reduce the burden on industry. Preference was also indicated for the provinces to be the front-line regulators, including through the development of equivalency agreements, and that in the case of conflict between federal and provincial requirements that the provincial requirements take precedence.

Response: The Regulations are designed to reduce both duplication with provincial or territorial regulations and administrative burden.

Some examples of these design features:

Also see response 5.2 regarding Alternative Rules above.

Alignment / Economic Disadvantage

5.5 Stakeholders proposed that the Regulations align with relevant U.S. requirements to prevent economic disadvantages for Canadians.

Response: The Regulations for boilers and heaters, and engines are comparable to the requirements for similar equipment in many U.S. states. For example, the U.S. EPA’s New Source Performance Standard for Stationary Spark Ignition Internal Combustion Engines was the basis for the emission standards and size threshold for modern engines. The Canadian and U.S. cement markets are integrated with approximately 50% of the Canadian sector’s production capacity coming from Ontario, and the cement NOx and SO2 emission standards are comparable to the existing Ontario regulatory emission standards without provisions for emissions trading.

Backstop/ Compliance Assessment Period

5.6 Industry stakeholders asked how the two-year compliance assessment period contained in the Regulations for cement might be applied to other sectors. Similarly, one province asked how the backstop would be consistently applied and why it applies only to the cement requirements and not for boilers and heaters and engines.

Response: For background, the ‘backstop’ concept allows provinces and territories to be the first to intervene when non-compliance is assessed. For cement, a facility needs to be out of compliance for two consecutive years before enforcement actions would be taken under the Regulations. This provides provinces and territories the opportunity to take appropriate actions to bring a facility into compliance after the first year in which the emission limit was exceeded. Federal enforcement activities could only proceed after the second year of non-compliance. In this way the federal Regulations provide a second line of defense for the environment that backstops provincial actions.

The two-year compliance assessment approach, as applied to the cement sector, is not applicable to equipment-type BLIERs because, in some cases, the equipment provisions require refurbishment and installation by a certain deadline (e.g. by 2026 for Class 80 boilers and heaters), and not just an ongoing emission limit.

In order to meet the intent of the backstop approach and allow provinces the opportunity to act first in the case of boilers and heaters and engines, the deadlines in the Regulations were delayed by one year from the dates that were agreed upon by the federal and provincial governments during the BLIERs process. For example, the Regulations require that Class 80 boilers and heaters be retrofitted by 2026, even though the originally agreed-upon date was 2025.

The application of backstop provisions for other sectors or equipment groups as part of any future regulations will be determined on a case-by-case basis as those regulations are developed.

Application

5.7 Stakeholders expressed a preference for facility-based requirements versus equipment-based requirements.

Response: The Regulations include some facility-based requirements. For pre-existing engines, the yearly average option provides a similar degree of compliance flexibility for an engine group as would have been obtained if a facility-based approach for different emission sources had been used. For the cement sector compliance will be assessed at the facility level.

For boilers and heaters, a facility-based approach was considered, but had limited discussion at the boilers and heaters BLIERs working group. The working group focused on an equipment-based approach that built on the CCME equipment-based emissions standards found in the National Emissions Guideline for Commercial/Industrial Boilers and Heaters, published by the CCME as Initiative N306, in March 1998. The Regulations reflect the outcomes of these discussions.

Linkage with AQMS

5.8 Stakeholders asked for an assessment and report comparing the principles/foundational elements of the AQMS to the Regulations. This includes describing how the Regulations relate to the AQMS elements and approaches (as described in the CCME AQMS Roles and Responsibilities document) to ensure the original intent of the BLIERs is preserved throughout their implementation.

Response: The Department has no plan to develop or publish an assessment or a report comparing how the Regulations relate to the principles or foundational elements of the AQMS of: collaborative; comprehensive; efficient; flexibility; supportive of continuous improvement; supportive of keeping clean areas clean; science-informed; transparent; and outcomes-focussed.

The Regulations were informed by the transparent, collaborative and unprecedented AQMS process, which involved provincial and territorial governments, industry and non-governmental organizations. This transparency was reinforced through the prepublication of the proposed Regulations for the 60-day public comment period.

Importantly, the Regulations are informed by the potential of currently available emissions-control technologies and leverages this knowledge to achieve important reductions in covered emissions for the benefit of human health and the environment.

Without compromising this environmental objective, the Regulations also provide flexibilities, such as the use of alternative methods to collect data, and reinforce the role of provinces and territories as the front-line regulator. In addition, the federal government remains open to entering into equivalency agreements with interested provinces and territories.

The Regulations also include more stringent requirements that will be phased in over time to support continuous improvement.

Regulatory cooperation

The collaborative work done on developing both the CAMS and the AQMS, as well as the following discussions through committees under the Canadian Council of Ministers of the Environment, has put provinces and territories more at ease with respect to the federal approach for the Regulations. Implementation of the system is strongly supported by provinces and territories, which see it as a model of effective federal/provincial cooperation, where each level of government takes distinct actions within its authority that are coordinated and mutually reinforcing.

The Government of Canada engaged provinces and territories extensively during the regulatory development process (conference calls, sharing of information, etc.) in order to better understand their perspectives on the Regulations and the relationship with existing actions affecting industries in their jurisdictions.

To minimize overlap with existing and/or new provincial requirements, the Regulations have been designed to initially assess compliance over a two-year period for the cement sector. For the equipment-based performance standards, the federal government delayed the compliance date by one year from the date agreed upon by stakeholders during the development of the performance standards. In this way, provinces have the opportunity to create or update their existing requirements (if necessary) to the levels of the performance standards within the Regulations. Provinces that have requirements that achieve a comparable environmental outcome have the opportunity to be the front-line regulator and bring facilities into compliance. In addition, the Regulations have been written to reduce duplication of reporting and monitoring, by asking potential regulatees, where possible, to generate information in a manner similar to what provinces currently require.

The Regulations introduce new requirements in some provinces and territories. The federal government is open to pursuing equivalency agreements with interested provinces and territories.

The implementation of the Regulations is not expected to affect trade. The performance standards are benchmarked to emission standards that are considered good performance where air pollution is not an issue. In many cases, the benchmarks were existing Canadian, American, or European requirements for similar facilities, equipment or sectors.

The Regulations are deemed essential for continued engagement with the United States on transboundary flows of air pollution through the Canada–United States Air Quality Agreement, which addresses NOx, SO2, and VOCs.

In terms of the CBA of the Regulations, in order to engage provinces and territories prior to the prepublication of CGI RIAS, the Department established a new cost-benefit analysis working group in December 2012. Through the working group, the federal government shared detailed information about modelling approaches as well as data and assumptions employed in the analysis of the Regulations. A set of detailed documents outlining the proposed CBA methodology for each set of performance standards was shared with provinces and territories. These methodology documents included cost estimates by technology, as well as information on key assumptions that were used to develop the total cost estimates applicable to a given sector or equipment group.

Rationale

Although progress has been made in reducing some air pollutant emissions, air quality remains an ongoing issue of concern in Canada and presents a significant risk to the health of Canadians every day. Negative health effects are experienced at even low levels of concentrations of air pollutants. Air pollution is linked to cardiovascular and respiratory illnesses such as heart disease, stroke, asthma, and bronchitis, and even premature death. There is also growing evidence that air pollution may be associated with other health impacts, such as low birth weight and various neurological effects. Moreover, air pollutants affect overall ecosystem health, including crop yields. All of these impacts lead to significant costs for the health care system and the economy, and for Canadians more broadly.

Despite significant effort across jurisdictions to reduce air pollutant emissions, poor air quality is still an issue of concern in Canada.

The lack of a clear national approach for managing air pollution from industrial sources has led to widely inconsistent industrial emission standards across the country. The BLIERs overall, and the Regulations as an initial step, will reduce inconsistencies across Canada by ensuring that facilities across Canada are subject to the same base-level requirements. Furthermore, the Regulations will improve people’s lives by reducing air pollutant emissions, particularly where there have been few requirements for emission abatement in the past, and will contribute to achieving the updated CAAQS in areas of concern.

A regulatory approach was chosen for engines, boilers and heaters and cement because it is a cost-effective way to ensure consistency and fairness. Moreover, it is broadly supported by industry as it provides policy certainty and is sensitive to industry costs and competitiveness concerns. Implementation of the AQMS is supported by provinces, which see it as a model of effective federal/provincial cooperation where each level of government takes distinct, coordinated actions within their authorities that are mutually reinforcing. Other key stakeholders, such as several major health and environmental non-governmental organizations, are also supportive.

In addition, the Regulations will reduce transboundary pollution flows from Canada to the United States and will also strengthen Canada’s position in discussions with the United States to further reduce transboundary air pollution from the United States to Canada, under the Canada–United States Air Quality Agreement.

The Regulations will result in significant net health and environmental benefits. It is expected that they will lead to a total reduction of approximately 2 036.5 kt of NOx between 2016 and 2035, reducing adverse health and environmental effects from the atmospheric formation of ozone and particulate matter. For engines alone, the net incremental benefit of achieving the NOx reductions attributable to that performance standard is $6B. Similarly, for boilers and heaters, the net incremental benefit is $320M. Although not monetized, performance standards for cement will result in a net benefit to Canadians.

Strategic environmental assessment

The strategic environmental assessment that was completed for the CAAQS and the industrial emission requirements (which include the Regulations) concluded that these Regulations support the 2013-16 Federal Sustainable Development Strategy goal and target to minimize threats to air quality and reduce air pollutants. (See https://www.ec.gc.ca/ee-ea/default.asp?lang=en&n=DDC6183A-1).

Implementation, enforcement and service standards

Compliance strategy

Compliance promotion activities are intended to assist the regulated community to achieve compliance. These activities are targeted at raising awareness and assisting the regulated community to achieve a high level of overall compliance as early as possible during the regulatory implementation process. The regulatees and other stakeholders will be well-positioned to understand that the Regulations are coming, what will be regulated and what compliance with the Regulations will entail.

Compliance promotion activities may include:

Particular emphasis will be placed on the new emission standards and reporting requirements for new industry sectors with little prior experience with CEPA regulations, and on explaining these activities to small- and medium-sized enterprises. Efforts will also include responding to and tracking inquiries in addition to contributing to the compliance promotion database. As the regulated community becomes more familiar with the requirements of the Regulations, these activities are expected to decline to a maintenance level. The compliance promotion activities will be adjusted according to compliance analyses or if unforeseen compliance challenges arise.

Assessments of compliance with the Regulations will be carried out through review and analysis of reports submitted, and may require follow-up with regulatees.

Enforcement

The Regulations are made under CEPA, so enforcement officers will, when verifying compliance with the Regulations, apply the Compliance and Enforcement Policy for CEPA. (see footnote 28) This 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 carry out an inspection. An inspection may identify an alleged violation, and alleged violations may also be identified by the Department’s technical personnel, through information transmitted to the Department by the Canada Border Services Agency or through complaints received from the public. Whenever a possible violation of the Regulations 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:

Performance measurement and evaluation

The Performance Measurement and Evaluation Plan (PMEP) describes the desired outcomes of the Regulations and establishes indicators to assess the performance of the Regulations in achieving these outcomes. The PMEP package (available upon request) is composed of three documents:

The three documents complement each other and allow the reader to gain a clear understanding of the outcomes of the Regulations, the performance indicators, as well as the evaluation process.

Outcomes

The PMEP details the suite of outcomes as regulatees comply with the Regulations. These outcomes include the following:

Performance indicators and evaluation

Detailed, quantitative indicators and targets were defined for each sector and equipment type. These targets will be tracked on an annual, biannual or five-year basis, depending on emissions. In addition, an assessment will be conducted periodically to gauge the performance of every indicator against the identified targets. This regular review process will allow the Government of Canada to clearly detail the impact of the Regulations on the industrial sectors and equipment types, and to evaluate the performance of the Regulations in reaching the intended targets. These performance indicators are listed in a Performance Measurement and Evaluation Plan (PMEP) indicators table.

Contacts

Departmental Contact and BLIERs policy:

Jennifer Kerr
Acting Director
Air Emissions Priorities Division
Department of the Environment
Telephone: 819-420-7742
Email: ec.airpur-cleanair.ec@canada.ca

Economic analysis:

Brenda Tang
Manager
Economic Analysis and Valuation Division
Department of the Environment
Telephone: 873-469-1495
Email: ec.darv-ravd.ec@canada.ca

Annex A: Model Descriptions and Data Transformation

1. The Energy, Emissions and Economy Model for Canada

Air pollutant projections to 2035 were developed using the Department’s E3MC model. This model has the ability to capture the interactions that exist between policies and the economy and is capable of analyzing the wider impacts of environmental policies, such as performance standards, in terms of how the policies will affect the economy, energy prices, emissions, and other macroeconomic indicators.

E3MC has two components: Energy 2020, which models Canada’s energy supply and demand, and The Informetrica Model (TIM), a macroeconomic model of the Canadian economy. Energy 2020, which includes many regions and sectors of the North-American economy, (see footnote 29) has the capacity to simulate the supply, price and demand for all fuels. The model can determine energy output and prices for each sector, both in regulated and unregulated markets. It simulates how such factors as energy prices and government measures affect the choices that consumers and businesses make when they buy and use energy. The model’s outputs include changes in energy use, energy prices, greenhouse gas emissions, air pollutants, investment costs and possible cost savings, which are used to identify the direct effects stemming from greenhouse gas, energy or air pollutant reduction measures. The resulting cost savings and investments from Energy 2020 are then used as inputs in TIM.

TIM is used to examine consumption, investment, production, and trade decisions in the whole economy. It captures the interaction, from a national perspective, among industries, as well as the implications for changes in producer prices, relative final prices, and income. It also factors in government fiscal balances, monetary flows, and interest and exchange rates. More specifically, TIM incorporates gross domestic product, gross output and employment for 133 industries at a provincial and territorial level. It also has an international component to account for exports and imports, covering about 100 commodities. The model projects the direct impacts on the economy’s final demand, output, employment, price formation, and sectoral income that result from various policy choices. These, in turn, permit an estimation of the effect of clean air and climate change policy and related impacts on the national economy.

E3MC develops air pollutant emissions projections using an approach based on market economics to analyze trends in energy use. For each fuel and consuming sector, the model balances energy supply and demand, accounting for economic competition among the various energy sources. The model generates an annual emissions projection and can then assess policy options by examining the changes in key parameters relevant to the BAU within the modelling framework.

Key Assumptions and Data Sources in E3MC

The projections incorporate updated data from Statistics Canada, the Department’s National Inventory Report (1990-2013: Greenhouse Gas Sources and Sinks in Canada), the National Energy Board, and the U.S. Energy Information Administration.

Economic projections to the year 2019 are calibrated to private sector projections used by Finance Canada from their most recent available Survey of Private Sector Economic Forecasters report. Beyond 2019, long-term key economic assumptions are based on Finance Canada’s Update of Economic and Fiscal Projections-2014. Forecasts of major energy supply projects from the National Energy Board’s Canada’s Energy Future 2016 projections are incorporated for key variables and assumptions in the model (i.e. oil and gas production and price).

2. Data Processing and Transformation

The output from E3MC requires significant transformation to the format required by AURAMS. In general, data transformations involve detailed manipulations (aggregation and disaggregation) to align data in inconsistent categories in National Pollutant Release Inventory (NPRI), Air Pollutant Emission Inventory (APEI), E3MC and AURAMS. Data transformations also involve allocating emissions spatially and temporally as required by AURAMS. For example, emissions for mobile and agricultural sources are allocated spatially and to sub-annual time windows, while emissions from industrial sources are allocated as ground level or stack level (over 50 meters).

The effort required for these transformations depends on pollutants, sources targeted and sectors. Assumptions are needed to transform data when, for example:

VOCs required speciation profiles — which must be developed, based on VOC chemistries. VOC speciation requires significant interpretation of NPRI data.

3. A Unified Regional Air-Quality Modelling System

AURAMS is a 3-D multi-pollutant off-line air quality model used to predict changes in air pollutant concentrations, and has been extensively peer reviewed. (see footnote 30) In order to predict changes in air quality, AURAMS combines information on predicted emission changes with information on meteorological fields (e.g. wind speed, temperature, humidity). The emission inventories, used as input by AURAMS, for the BAU and regulatory scenarios are calculated by the E3MC model. The meteorological data used for all modelled scenarios is generated by ECCC’s Meteorological Services weather forecast model.

4. Environmental Valuation Modelling

Using the resulting ambient air quality impacts from AURAMS, the environmental benefits are estimated using AQVM2. The environmental benefits estimated by AQVM2 include:

Overall, particulate matter and ozone negatively impact vegetation, soils, water, wildlife, materials, as well as overall ecosystem health. As chronic exposure to ozone may result in crop yield losses, physiological degradation of vegetation, reduced timber growth, and premature livestock mortalities and illnesses, reducing these pollutants can reduce associated economic costs for the agri-food and forestry industries. In addition, the degraded visibility associated with particulate suspension and smog may negatively affect residential welfare, tourism and the enjoyment of outdoor recreational activities. Particulate deposition is also associated with soiling and structural damages, which may lead to higher cleaning and maintenance costs for residential dwellings, commercial buildings and industrial facilities.

5. Health Valuation Modelling

Health Canada uses AQBAT to estimate how human health will be impacted by the estimated changes in ambient air quality associated with the Regulations and emission reductions.

Change in ambient air pollutant levels are linked with increased risks of various adverse health outcomes by AQBAT. These links are derived from studies in the scientific literature. The air pollutants assessed by AQBAT which contribute to increased health risks are ground level ozone, PM2.5, SO2, NOx, and carbon monoxide. Exposure to these pollutants increases the risks for a number of medical problems and adverse health outcomes including:

For each health impact in the model, AQBAT quantifies how a change in air pollutant concentration will affect Canadians’ risk of experiencing that health impact. Changes in risk levels are then summed up across individuals and across different regions with varying changes in air quality, to estimate the population health impacts (in terms of counts) by province and by health condition.

In addition to estimating these health impacts, AQBAT also converts health impacts into economic terms. Each of the health endpoints or risks in the model has an associated economic value drawn from the economic literature. Changes in risks for different health endpoints are converted to economic values, and summed up across different health endpoints and different regions to estimate the total economic value by province. This approach is based on accepted approaches in economic welfare theory, and is consistent with TBS Guide on the quantification of health benefits.