BORDER AIR QUALITY STRATEGY

United States—Canada Emissions 

Cap and Trading Feasibility Study 

UNITED STATES—CANADA AIR QUALITY AGREEMENT
To Obtain Additional Information, Please Contact: 

In the United States In Canada 

Clean Air Markets Division Transboundary Air Issues Branch 

U.S. Environmental Protection Agency Environment Canada 

Mail Code 6204J 351 St. Joseph Boulevard 

1200 Pennsylvania Avenue, NW 11th Floor, Place Vincent Massey 

Washington, DC 20460 Gatineau, Quebec K1A 0H3 

Internet: Internet: 

www.epa.gov/airmarkets/usca http://www.ec.gc.ca/cleanairairpur/Canada-_United_StatesWS105E2511-1_En.htm 

American spelling is used throughout this report. 
United States–Canada Emissions Cap and

Trading Feasibility Study

Table of Contents


Executive Summary..........................................................................................................................ix


Introduction .....................................................................................................................................xiii


Section A: Air Quality Context .......................................................................................................1


A.1	 OVERVIEW.............................................................................................................................1


A.2	 SHARED AIR QUALITY PROBLEMS......................................................................................3


A.3	 PRECURSOR EMISSIONS: SOURCES AND GEOGRAPHICAL


DISTRIBUTION OF SO2 AND NOX.........................................................................................5


A.4	 SHARED SOURCE REGIONS .................................................................................................8


A.5	 SUMMARY ...........................................................................................................................11


A.6	 REFERENCES .......................................................................................................................13


Section B: Legal Background .......................................................................................................15


B.1 UNITED STATES ....................................................................................................................15


B.2 CANADA ................................................................................................................................23


B.3 SUMMARY .............................................................................................................................29


Section C: Applicability..................................................................................................................31


C.1	 OVERVIEW OF PRINCIPLES ................................................................................................31


C.2	 SO2 AND NOX SOURCES AND DISTRIBUTION OF FUEL TYPES ......................................33


C.3	 EMISSION REDUCTION OPTIONS FOR SO2 AND NOX......................................................38


C.4	 OPT-IN PROVISIONS ...........................................................................................................40


C.5	 SUMMARY ...........................................................................................................................41


C.6	 REFERENCES .......................................................................................................................42


Section D: Emissions Monitoring and Reporting ....................................................................45


D.1	 PRINCIPLES..........................................................................................................................45


D.2	 U.S. MONITORING AND REPORTING.................................................................................46


D.3	 ENVIRONMENT CANADA’S PROTOCOL FOR CONTINUOUS


EMISSION MONITORING SYSTEMS (REPORT EPS 1/PG/7) ............................................61


D.4	 ANALYSIS.............................................................................................................................62


D.5	 SUMMARY ...........................................................................................................................65


D.6	 REFERENCES .......................................................................................................................66


Section E: Allowances Use............................................................................................................67


E.1	 UNIT OF MEASUREMENT ...................................................................................................67


E.2	 ALLOWANCE SERIALIZATION............................................................................................67


E.3	 ALLOWANCE DISTRIBUTION .............................................................................................68


E.4	 ALLOCATION TIMING .........................................................................................................71


E.5	 BANKING .............................................................................................................................71


E.6	 BORROWING .......................................................................................................................71


E.7	 PROPERTY RIGHTS .............................................................................................................71


E.8	 TRANSPARENCY..................................................................................................................72


E.9	 SET-ASIDES .........................................................................................................................72


E.10 ALLOWANCE ACCOUNTING...............................................................................................73


iii 
Canada-United States Emissions Cap and Trading Feasibility Study 

E.11 TAX CONSEQUENCES.........................................................................................................73


E.12 THE U.S. EXPERIENCE WITH ALLOWANCE USE...............................................................73


E.13 SUMMARY ...........................................................................................................................77


Section F: Electronic Emissions Trading Registry: 


Data Systems for Tracking Allowances and Emissions .....................................79


F.1	 PRINCIPLES FOR DESIGNING AN ELECTRONIC REGISTRY..............................................79


F.2	 COMPONENTS OF THE REGISTRY.....................................................................................80


F.3	 CENTRALIZATION ...............................................................................................................81


F.4	 THE U.S. EXPERIENCE WITH DATA TRACKING SYSTEMS...............................................82


F.5	 THE CANADIAN EXPERIENCE WITH DATA TRACKING SYSTEMS...................................85


F.6	 SUMMARY ...........................................................................................................................85


Section G: Compliance and Enforcement .................................................................................87


G.1	 OVERVIEW OF COMPLIANCE .............................................................................................87


G.2	 ENFORCEMENT ..................................................................................................................88


G.3	 THE U.S. EXPERIENCE WITH COMPLIANCE AND ENFORCEMENT .................................89


G.4	 COMPLIANCE AND ENFORCEMENT IN CANADA .............................................................91


G.5	 SUMMARY ...........................................................................................................................91


Section H: Analytical Tool Development and Feasibility Analysis......................................93


H.1	 DEVELOPMENT AND DESCRIPTION OF JOINT ANALYTICAL TOOLS .............................93


H.2	 ILLUSTRATIVE MODELING SCENARIOS FOR CROSS-BORDER 


SO2 AND NOX EMISSIONS CAP AND TRADING ..............................................................100


H.3	 RESULTS FOR THE POWER SECTOR USING THE INTEGRATED PLANNING MODEL ......101


H.4	 RESULTS FROM AIR QUALITY MODELING......................................................................108


H.5	 SUMMARY OF FEASIBILITY ANALYSIS AND TOOL DEVELOPMENT ............................113


H.6	 REFERENCES .....................................................................................................................114


iv 
List of Tables


Table A-1 Average Concentration and Percent Concentration of PM2.5 

Mass from Selected State Contributions to Class 1 Areas 

(Acadia, Boundary Waters, Dolly Sods)..................................................................10


Table D-1 Essential Measurements Required by U.S. Emission Cap 


and Trading Programs.................................................................................................46


Table D-2 Part 75 Monitoring Options ......................................................................................48


Table D-3 CEMS Requirements for U.S. Emission Cap and Trade Programs ...................49


Table D-4 Low Mass Emission Units ..........................................................................................51


Table D-5 Part 75 Certification Tests.........................................................................................54


Table D-6 Ongoing QA Test Requirements for Year-Round Reporters..............................56


Table E-1 Overview of Allowance Use in U.S. SO2 and NOX Programs.............................74


Table F-1 Required Emission Data on a Quarterly Basis .....................................................83


Table H-1 Exisiting U.S. and Canadian Electricity Generating Capacity 


by Source .......................................................................................................................96


Table H-2 Figures Demonstrating Projected Changes in Environmental 


Endpoints from Air Quality Modeling of an Illustrative U.S.–Canada 

Cross-Border Emissions Cap and Trade Scenario ...............................................99


Table H-3 Illustrative Emission Caps for the United States and Canada........................101


v 
List of Figures


Figure A-1 Mean PM2.5 Concentrations (μg/m3) at Canadian 

Dichotomous Monitors and U.S. Federal Reference 

Monitors in the Border Region, 2000-2003.........................................................4


Figure A-2 Ozone Concentrations (ppb) in the U.S.-Canada Border Regions, 


2000-2002 (Average Annual Fourth-Highest Daily Maximum 

Eight-Hour Ozone) ......................................................................................................4


Figure A-3 Average Wet Sulfate Deposition, 1990-1994.......................................................5


Figure A-4 Annual Wet Sulfate Deposition, 2002....................................................................5


Figure A-5 Average Wet Nitrate Deposition, 1990-1994 .......................................................6


Figure A-6 Annual Wet Nitrate Deposition, 2002 ....................................................................6


Figure A-7 Canada (2000) – U.S. (2001) Geographical Distribution of SO2 Emissions ........7


Figure A-8 Canada (2000) – U.S. (2001) Geographical Distribution of NOX Emissions .......7


Figure A-9 U.S. and Canadian National Emissions by Sector for SO2 and NOX, 2002 ..........8


Figure A-10 Combined QTBA Plot Derived Using 2000 and 2001 PM2.5 

Measurements for the Warm Months (May-September) ...................................9


Figure A-11 Average Concentrations (μg/m3) of PM2.5 and Components by 


State and Province......................................................................................................9


Figure A-12 Satellite Imagery of the Quebec Forest Fire PM Episode in July 2002.......12


Figure B-1 CAIR: Affected Region and Emission Caps ........................................................22


Figure C-1 Fraction of Electric Generation by Fuel Type ................................................35


Figure C-2 Total Electricity Generation by Fuel Type, 2002...............................................36


Figure D-1 Overview of Continuous Emission Monitoring under Part 75 ......................47


Figure D-2 Monitoring System Certification Process ...........................................................53


Figure F-1 Sample Feedback Quarterly Report Receipt and Status Code Information......83


Figure F-2 Allowance Reconciliation........................................................................................84


Figure H-1 Electricity Generation in Canada and the United States, 2003 ....................95


Figure H-2 IPM Inputs of U.S. and Canadian Fossil Fuel-Fired Power 


Plants Showing Locations and Characteristics of the Plants 

Used in IPM................................................................................................................95


Figure H-3 Map of the AURAMS Modeling Domain Used in the Feasibility Study......100


Figure H-4 Map of the CMAQ Modeling Domain Used for CAIR.....................................100


Figure H-5 NOX East and West Model Regions for Illustrative Analysis........................102


Figure H-6 Annual SO2 Emissions in 2010 and 2020, Comparing the Base Case 


(with no caps in Canada) with the Trading Scenario (with caps in 

Canada and cross-border trading) .....................................................................102


Figure H-7 Annual NOX Emissions in 2010 and 2020, Comparing the Base Case 


(with no caps in Canada) with the Trading Scenario (with caps in 

Canada and cross-border trading) .....................................................................103


vi 
Figure H-8 Summer NOX Emissions in 2010 and 2020, Comparing the Base Case 

(with no caps in Canada) with the Trading Scenario (with caps in 

Canada and cross-border trading) .....................................................................103 

Figure H-9 Emissions of SO2 and NOX from the U.S. Power Sector – Base Case, 

Clear Skies U.S., and the Trading Scenario .....................................................104 

Figure H-10 Emissions of SO2 and NOX from the Canadian Power Sector – 

Base Case and the Trading Scenario.................................................................104 

Figure H-11 Annual Incremental Costs to the Base Case for the U.S. 

Power Sector of Illustrative Trading Scenario ................................................105 

Figure H-12 Annual Incremental Costs to the Canadian Power Sector of 

Illustrative Trading Scenario ..............................................................................106 

Figure H-13 U.S. Generation Mix – Base Case, Clear Skies U.S., and the 

Trading Scenario.....................................................................................................107 

Figure H-14 Canadian Generation Mix – Base Case and the Trading Scenario ..............107 

Figure H-15 Percent Change in Annual Fine Particles with Emission Reductions 

under Illustrative Trading Scenario Compared to Base Case in 2010 

(CMAQ)......................................................................................................................109 

Figure H-16 Percent Change in Annual Fine Particles with Emission Reductions 

under Illustrative Trading Scenario Compared to Base Case in 

2020 (CMAQ)...........................................................................................................109 

Figure H-17 Absolute Change in Annual Fine Particles (ug/m3) with 

Emission Reductions under Illustrative Trading Scenario 

Compared to the Base Case in 2020 (CMAQ) ....................................................110 

Figure H-18 Absolute Difference in PM2.5 Concentration (μg/m3), Comparing 

Illustrative Trading Scenario to the Base Case during the 

Winter Episode for 2020 (AURAMS)...................................................................110 

Figure H-19 Absolute Difference in PM2.5 Concentration (ug/m3), 

Comparing Illustrative Trading Scenario to the Base Case 

during the Summer Episode for 2020 (AURAMS)...........................................111 

Figure H-20 Absolute Difference between Illustrative Trading Scenario to the 

Base Case for Ground Level Ozone Daily Maximum (ppb) during 

the Summer Episode for 2020 (AURAMS) .......................................................111 

Figure H-21 Percent Change in Sulfur Deposition with Emission Reductions 

under Illustrative Trading Scenario Compared to Base Case in 

2020 (CMAQ)...........................................................................................................112 

Figure H-22 Percent Change in Nitrogen Deposition with Emission Reductions 

under Illustrative Trading Scenario Compared to Base Case in 

2020 (CMAQ)...........................................................................................................112 

Figure H-23 Absolute Change in Visibility (Deciviews) with Emission Reductions 

under Illustrative Trading Scenario Compared to Base Case in 

2020 (CMAQ).................................................................................................................113 

vii 

Executive Summary


The 1991 Canada-United States Air Quality 

Agreement established a flexible framework 

to address transboundary air pollution. In June 

2003, Canada and the United States undertook 

three two-year joint projects, one of which is 

the feasibility of developing a cross-border cap 

and trade program for sulfur dioxide (SO2) and 

nitrogen oxides (NOX) emissions, emissions that 

are key components of fine particles, smog, 

regional haze, and acid rain in the transboundary 

region. 

U.S. EPA and Environment Canada 

reviewed the key components of the U.S. cap 

and trade programs and developed Canada-U.S. 

economic and air quality modeling tools to be 

able to assess the potential economic and 

environmental impacts of NOX and SO2 crossborder trading. 

The focus of the cross-border feasibility study 

has been electricity generators that burn fossil 

fuels and emit NOX and SO2 in the United States 

and Canada. Currently, over 3800 electricity 

generating units (EGUs) in the United States 

participate in the national SO2 emissions cap 

and trade program (the Acid Rain Program), 

while over 2600 EGUs and large industrial boilers 

participate in the regional summer season 

NOX emissions cap and trade program. Since 

its implementation in 1995, the U.S. Acid Rain 

Program has successfully reduced SO2 emissions 

by 32 percent from 1990 levels, while electricity 

generation has increased by 30 percent over that 

same time period. Facilities have achieved their 

emission reduction requirements at substantially 

less cost, because the trading mechanism 

provides flexibility for sources to pursue the 

least-cost options. At the same time, mandatory 

emission caps have created the impetus for 

innovation in pollution abatement technologies 

and ensured the required reductions. Finally, 

the U.S. emission cap and trade programs, 

through their requirements for rigorous emission 

monitoring and reporting, as well as strong 

enforcement, have assured both high compliance 

and the integrity of the allowance markets. 

There are several key findings in this report. 

The United States and Canada share three 

principal transboundary air quality problems: 

fine particulate matter (PM2.5), ground-level 

or tropospheric ozone (O3), and acid 

deposition. SO2 and NOX are key precursors 

that can lead to the formation of PM2.5, 

ozone (or smog), and acid deposition in 

both countries. (See Ground-Level Ozone: 

Occurrence and Transport in Eastern North 

America and Transboundary PM Science 

Assessment at http://www.epa.gov/ 

airmarkets.usca/ index.html or 

http://www.ec.gc.ca/cleanair-airpur/ 

key_positions_on_issues_of_concernWS0A8790BD-1_En.htm and 

http://www.msc-smc.ec.gc.ca/saib/ 

smog/transboundary/index_e.html). 

A significant portion of the population in 

the eastern border region of both Canada and 

the United States is exposed to harmful levels 

of air pollutants, levels that often exceed both 

countries’ air quality standards designed to 

protect human health. Acidic deposition 

remains at levels that cause concern for 

sensitive ecosystems in both countries, and 

significant degradation of visibility in national 

parks persists. Further emission reductions 

would improve air quality and reduce acid 

deposition in both countries, and an 

emissions cap and trading program can 

maintain those improvements at costs lower 

than traditional regulatory approaches. 

The legal framework in Canada and 

the United States was assessed for 

differences and gaps that would need to be 

addressed in order for there to be a crossborder emissions cap and trading program. 

In both countries, federal and provincial/state 

governments have legal responsibilities for 

air quality management and would need to 

participate in the development of any crossborder trading programs. While legal 

authorities exist now in Canada that could 

ix 
Canada-United States Emissions Cap and Trading Feasibility Study 

provide the basis for developing cross-border 

trading, additional clarification is needed 

in the United States. In both countries, 

legislative and/or regulatory changes would 

be needed to ensure that the units of trade— 

the “allowances”—issued by each country 

would be equivalent so that they could 

be recognized, traded, tracked, and used for 

compliance in either country. In addition, 

while cap and trade programs in the United 

States exist now, in Canada regulations 

would be required to create the mandatory 

emission reduction caps as well as the basis 

for cross-border trading, such as monitoring 

and reporting. 

Over 4000 units currently participate in 

the established cap and trade programs in the 

U.S. There are 207 Canadian fossil fuel-fired 

electricity generating units, in total, in 

Canada that are 25 MWe or larger and, 

therefore, similar to the universe of sources 

covered by the U.S. cap and trade programs. 

Two critical factors in assessing which 

sectors are best able to take part in 

cap and trade programs are, first, the sector’s 

contribution to the emissions that must be 

reduced to address fine particles, acid rain, 

and ground-level ozone and, second, the 

ability to rigorously monitor the emissions 

from the sectors. Emissions monitoring 

equipment is available and being used by 

each of the sources in the U.S. cap and trade 

programs. Electricity generators that burn 

fossil fuels would be the best candidates for 

participating in possible future cross-border 

cap and trade programs. However, exploring 

the inclusion of key contributors (e.g., base 

metals smelters) from other sectors in 

Canada is recommended. 

In a cross-border cap and trade program 

that would “dovetail” with the existing U.S. 

SO2 and NOX cap and trade programs, the 

emission monitoring and reporting systems 

would need to be the same in both countries. 

Within an emissions cap and trading regime, 

the monitoring and reporting requirements 

provide the basis for guaranteeing the 

emission value of the allowances which can 

therefore be traded and used for compliance 

with full confidence. In the United States, 

emission monitoring and reporting 

requirements for the SO2 and NOX cap 

and trade programs are detailed in federal 

regulation (40 CFR Part 75) with which all 

affected sources must comply throughout the 

country. In Canada, provincial governments 

have traditionally addressed requirements 

for monitoring of emissions from electricity 

generator smokestacks, and the federal 

government has guidelines that some 

provinces have reflected in their requirements. 

For cross-border trading to be successful, 

certain trading rules should be the same in 

both countries. With respect to allowances, 

for instance, how allowances are identified 

by serial number, whether the allowances 

are measured in metric or imperial units, 

how allowances can be saved for future use 

or “banked,” whether governments define 

allowances as “property rights,” and the 

fungibility of allowances—the ability to freely 

exchange allowances—would need to be 

addressed and agreements reached. In the 

U.S. SO2 and NOX cap and trade programs, 

every allowance, regardless of its origin or 

destination, is deemed to have the same value, 

with the result that trades can occur without 

government approval and, therefore, can take 

place quickly—even online. Experience in the 

United States has shown that, with hundreds 

of sources participating, air quality concerns 

related to the distance and direction of 

trades have been adequately addressed 

with aggressive emission reduction caps 

and ongoing environmental assessments. 

In cross-border trading, other rules related 

to allowances could be handled differently 

in each jurisdiction. For example, in the 

U.S. NOX SIP call program, while the federal 

government establishes an emissions 

“budget” for each state and provides a 

“model rule” as guidance, each state can 

x 
Executive Summary


use its own method to distribute the 

state’s budget of allowances to the EGUs 

and industrial boilers. Each state also 

defines the number of allowances that 

could be “set aside” from the cap for new 

sources or to encourage certain kinds 

of renewable or energy efficiency 

development. Such flexibility provides the 

opportunity for each jurisdiction to meet 

the emission cap requirements while 

allocating the cap among affected sources 

in ways that support jurisdictional goals. 

In cross-border trading, the requirements 

for verifying the emissions and allowance 

information and its reporting and tracking in 

online electronic registries in each country 

would have to be equivalent to provide for 

“borderless” transactions. Online electronic 

emissions and allowance tracking systems 

compile the information that is used by 

governments to determine compliance 

by facilities. The tracking systems also 

provide for public transparency so that 

full information about allowances 

traded and facility emissions is both 

robust and available. 

In a cross-border cap and trade program, 

while Canadian and U.S. sources would 

continue to be subject to their own domestic 

laws, harmonized compliance and 

enforcement would be essential. Among the 

features that would require harmonization 

would be the tests for what is “in” or “out” of 

compliance with respect to caps, emissions 

monitoring, reporting, and verification. 

Where compliance with the caps is concerned, 

the same compliance schedules would be 

essential to prevent undesirable trading 

behavior in the cross-border market. Further, 

minimum penalties for noncompliance with 

the caps would need to be equivalent in both 

countries. In the U.S. cap and trade programs, 

automatic penalties for noncompliance with 

the cap are sufficiently severe that compliance 

has been almost 100 percent since the 

programs began operating in the mid-1990s. 

There are two key conclusions in this feasibility 

study. 

First, while the feasibility study demonstrates 

through air quality modeling that a crossborder NOX and SO2 emissions cap and trading 

program can reduce the total loading of 

pollutants into the environment over a 

broad geographic area, it is the levels and 

timing of the SO2 and NOX emission reduction 

requirements, or caps, in the electricity 

sector that determine the level and extent 

of the air quality and environmental benefits 

that would result. Trading does not alter the 

overall level of the emission reductions and 

consequent benefits. 

Second, the feasibility study used economic 

modeling to examine cost-effectiveness for 

the electricity sector of achieving emission 

reductions with a cross-border cap and 

trading program in place. The results mirror 

those seen in the United States, where the 

NOX and SO2 cap and trade programs have 

set emission reduction caps for electricity 

generators and provided the sources the 

opportunity to trade. Faced with mandatory 

requirements to reduce emissions of SO2 

and NOX, the sources in the U.S. cap and 

trade programs have found that achievement 

of their reductions is cheaper with a system 

that allows trading than without. 

Based on the analysis that Canada and the 

United States have done to date, a cross-border 

emissions cap and trade program could be feasible 

but the following critical program elements would 

be necessary: 

•	 In Canada, enforceable SO2 and NOX emission 

caps for the electricity sector—and other 

sectors, as appropriate—that are comparable in 

stringency to emission reduction requirements 

in the U.S. 

•	 A commitment by the United States and 

Canada, including provinces, to pursue 

implementation of cross-border SO2 

and NOX cap and trade. 

xi 
Canada-United States Emissions Cap and Trading Feasibility Study 

•	 In both countries, legislative and/or regulatory 

changes to give the allowances in each 

country equivalency so that they could be 

traded freely and used for compliance in 

either country. 

•	 Development in Canada of the regulations 

that would provide the basis for cross-border 

trading and in particular the emissions 

monitoring and reporting requirements 

for electricity generating units, as well as 

development of the electronic tracking 

systems for emissions and allowances. 

Recommendations for future work include: 

•	 Conduct more comprehensive modeling of 

caps based on various policy considerations. 

•	 Develop additional quality assurance of all 

data and, from Canada, improved historical 

emission inventories from the non-EGU 

sector for modeling assessments. 

•	 Perform integrated assessments of 

alternative cap and trade scenarios, such 

as cost/benefit, air quality, health, and 

ecosystem impact analyses. 

•	 Examine further the potential of including 

Canadian base metals smelters and boilers in 

industries such as cement kilns, petroleum 

refineries, chemical manufacturers, and pulp 

and paper mills in cap and trade programs. 

xii 
Introduction


I

n June 2003, the Administrator of the U.S. 

Environmental Protection Agency and the 

Canadian Minister of the Environment announced 

three joint projects to be implemented under a 

Canada-United States Border Air Quality Strategy 

(BAQS). Identification of the joint projects fulfilled 

a pledge made by the two countries in January 

2003 to build on the continued success of the 

1991 Canada-United States Air Quality Agreement 

(AQA). 

These projects were intended to explore 

opportunities for coordinated air quality 

management that could result in air quality 

improvements and the establishment of 

innovative strategies. One of the projects is 

this feasibility study, a binational project to jointly 

analyze the feasibility of cross-border trading of 

capped emissions of nitrogen oxides (NOX) and 

sulfur dioxide (SO2). This builds on the earlier 

commitment under the AQA to cooperate and 

exchange information with respect to marketbased mechanisms, including emissions trading. 

The goals of this project have been to 

examine key requirements and components of a 

SO2 and NOX emissions cap and trade program 

necessary to assess the feasbility of cross-border 

trading. By using illustrative scenarios, we 

can begin to understand the economic and 

environmental impacts of cross-border trading. 

Objectives of this feasability study are to: 

•	 Develop analytical tools and share 

data to help evaluate a cross-border 

emissions cap and trade approach for 

addressing transboundary air quality issues; 

•	 Analyze compliance regimes and 

identify any divergences in accountability 

frameworks (such as divergences and 

gaps in measuring, monitoring, tracking, and 

reporting air emissions in each country); and 

•	 Describe the legal and regulatory 

infrastructure pertaining to NOX and 

SO2 emissions cap and trading regimes 

in each country. 

For instance, an important gap that was 

recognized early in the study was the fact that, in 

Canada, emission caps for the electricity power 

sector—the key sector that participates in the 

U.S. cap and trade programs—only exist in 

parts of Ontario and Quebec, and only for NOX 

emissions. Further, no emission cap and trading 

programs exist. While this study looks closely 

at the requirements of an emissions cap and 

trading program, the study’s mandate did not 

include discussion of the cap level; hence the 

study does not attempt to address an appropriate 

level and timing of emission caps for Canada. 

The first part of the study (Sections A through 

G) addresses key issues regarding feasibility 

and describes similarities and differences 

between Canada and the U.S. The second part 

of the study (Section H) uses emission and air 

quality models to demonstrate the feasibility 

of analyzing illustrative emission management 

scenarios. The study does not consider the 

appropriate level or timing of emission caps, 

nor does it look at pollutants other than SO2 

and NOX. 

The study has been carried out by federal 

teams of experts from both Canada and the 

United States, and information on the study 

has been provided in both countries through 

information sessions and reports to the 

U.S.–Canada Air Quality Committee, as well 

as other interested groups. 

xiii 

This section examines regional air quality 

along the U.S.-Canada border and the role 

played by long-range transport. The section 

seeks to answer a primary question: What does 

the science indicate about the transboundary 

nature of particulate matter (PM), ozone, and 

their precursors that may provide additional 

insight into the feasibility of a cross-border SO2 

and NOX emissions cap and trading program? 

An emissions cap and trading program can 

reduce the total loading of pollutants into the 

atmosphere, particularly if these pollutants are 

emitted by many sources and transported over 

a large geographic region. Emission cap and 

trading programs in the United States have helped 

address ambient air quality problems by reducing 

background levels of pollution that contribute to 

adverse air quality. This section begins to assess 

the regional air quality problem along the U.S.­

Canada border, giving consideration to the 

contributing meteorological conditions and 

chemical mixing in the atmosphere, by looking 

at existing scientific evidence in the cross-border 

area. 

The following discussion broadly explains 

the air quality information relevant to the 

U.S.–Canada transboundary region. Section A.1 

provides an overview of the air quality problems 

shared by the United States and Canada. Section 

A.2 discusses the extent of the shared air quality 

problem, and Section A.3 addresses sources and 

geographic distribution of precursor emissions. 

Section A.4 describes shared source regions, and 

Section A.5 summarizes the section. 

A.1 OVERVIEW 

A.1.1 The Chemistry of the Atmosphere 

The United States and Canada share three 

principal air quality problems: PM, tropospheric 

ozone, and acid deposition. Emissions of the 

precursor gases SO2 and nitrogen oxide and 

nitrogen dioxide (collectively referred to as NOX) 

are the primary contributors to poor air quality 

Section A 

AIR QUALITY CONTEXT 

in eastern North America. Discussions regarding 

air quality in support of the feasibility of a crossborder emissions cap and trading program 

consider only the precursor gases SO2 and NOX, 

although it is recognized that volatile organic 

compounds (VOCs), ammonia (NH3), and other 

components of ground-level ozone (e.g., 

black and organic carbon), or smog, can also 

contribute to poor air quality in the cross-border 

region. 

When emitted into the atmosphere, the 

precursor gases SO2 and NOX can undergo 

chemical reactions to form secondary PM, 

ozone, regional haze, and acid rain. Groundlevel ozone is a gas that forms when NOX and 

VOCs react with other chemicals in the air in the 

presence of sunlight. NOX and VOCs are emitted 

by combustion sources; VOCs often originate 

from petrochemical operations (such as refueling 

stations), solvents, cleaners, and paints. 

SO2 and NOX, primarily from anthropogenic 

sources, are also key contributors to acid 

deposition and fine particle (PM2.5) formation. 

These gases remain in the atmosphere 

under appropriate meteorological conditions, 

influencing the air quality over a large receptor 

region. When SO2 and NOX are emitted into the 

atmosphere, they can form “aerosols,” consisting 

of liquid and solid particles. When the amount 

of humidity (i.e., water) in the air becomes 

sufficiently high, aerosols containing SO2 and 

NOX react with water to form acidic compounds, 

falling to the earth as acid deposition. (For a 

more thorough description of atmospheric 

chemistry and related meteorological theories, 

see the references included at the end of this 

section.) 

SO2 and NOX emissions are key targets of 

air quality management in the border region 

and have been successfully reduced through 

comprehensive emission reduction programs in 

both countries. In the United States, a number 

of programs have been in place over the past 

1 
Canada-United States Emissions Cap and Trading Feasibility Study 

35 years that have reduced both SO2 and NOX. 

In particular, a large-scale SO2 emissions cap 

and trading program for electricity generating 

sources has been in effect for 10 years under 

Title IV of the Clean Air Act to address acid rain. 

Canadian sources have also reduced emissions 

of these precursor gases over the past several 

decades, most recently through implementation 

of the Canada-wide Acid Rain Strategy for 

Post 2000. However, poor air quality continues 

to be documented in the shared border region 

between Canada and the United States, 

indicating that additional reductions are needed. 

A.1.2 Environmental and Human Health 

Effects of Air Pollution 

Significant harmful effects on human health and 

the environment result from elevated ambient 

levels of ozone and fine particles, including 

particle sulfate and particle nitrate. Reducing 

emissions of SO2 and NOX from power plants 

and other sources in turn reduces ambient levels 

of both PM2.5 and ozone, benefiting human 

health and the environment. 

Mounting epidemiological evidence published 

since 1990 suggests that all PM, especially PM2.5, 

is harmful to human health. A large published 

body of literature now provides a strong basis for 

quantification of human mortality and morbidity 

reductions associated with reduced ambient 

levels of PM2.5 as SO2 and NOX emissions are 

reduced (U.S. EPA, 2005). The benefits to 

human health from reductions of PM2.5 include 

reductions in adult and infant mortality; fewer 

new cases of chronic bronchitis; prevention 

of nonfatal heart attacks, as well as fewer 

hospitalizations and emergency room visits for 

respiratory and cardiovascular illnesses; and 

fewer days when adults and children limit their 

outdoor activities. 

The human health benefits of reducing 

ground-level ozone, independent of exposure 

to PM, include reductions of hospitalizations 

for respiratory conditions and fewer emergency 

room visits for asthma. Recent evidence suggests 

that short-term exposure to ozone may have a 

significant effect on daily mortality rates. 

Just as PM2.5 and ozone pollution adversely 

affect human health, PM2.5 and ozone pollution 

adversely affect visibility and ecosystem health. 

PM2.5 in the air absorbs and scatters light as it 

passes through the atmosphere, which creates 

a haze that reduces one’s visual range and the 

clarity of viewed objects. When visibility is 

reduced, the value of a vacation day at a 

national park is reduced. 

Air pollution in the form of sulfur and 

nitrogen deposition harms freshwater lakes 

and streams, coastal estuaries, and forests. 

Chronically and episodically acidified lakes and 

streams lose fish species, other aquatic life, and 

recreational and commercial fishing. Nitrogen 

deposition is a significant contributor to excess 

nitrogen in watersheds, causing eutrophication 

of estuaries. The environmental consequences 

of eutrophic estuaries include algal blooms 

and low levels of dissolved oxygen that stress 

or kill fish and shellfish, as well as reduce areas 

of submerged aquatic vegetation that provide 

important habitat for many species. In forests, 

acid deposition leaches nutrients from the 

leaves, needles, and soils, thus removing 

elements essential for tree growth. Also, 

acidification mobilizes aluminum in forest soils 

and thus interferes with nutrient uptake through 

the roots. Trees weakened by the burden of acid 

deposition are susceptible to disease, drought, 

and extreme temperatures. Ozone exposure 

also stresses trees, damages urban ornamental 

plants, and reduces the commercial yields of 

forests and agricultural crops. Canadian studies 

estimate that a 75 percent reduction in SO2 

emissions from Canadian and U.S. sources— 

beyond what is currently called for in the 

Canada-U.S. Air Quality Agreement—will be 

required to protect eastern Canadian and 

northeastern U.S. ecosystems from deposition 

damage (Environment Canada, 2004). In the 

United States, researchers have examined a 

range of 40 to 80 percent further reduction in 

emissions to more fully protect sensitive 

2 
Section A


ecosystems (Bulger et al., 2000; Driscoll et al., 

2001). 

Acid deposition affects the built environment 

as well, damaging buildings, bridges, and 

historical monuments by eroding the surfaces 

of paint, galvanized steel, limestone, and 

marble. PM2.5 deposition also causes soiling 

of buildings and monuments. Such material 

damage reduces the value and increases the 

costs for maintenance and repair of national 

infrastructure and significant historical sites. 

Progress implementing current commitments 

under the Canada-U.S. Air Quality Agreement 

continues. However, both countries recognize 

that additional efforts are necessary to address 

ongoing public health and environmental 

problems (Canada–United States Air Quality 

Agreement Progress Report, 2004). 

A.2 SHARED AIR QUALITY 

PROBLEMS 

A.2.1 Observations of Ambient PM2.5 

Concentrations 

Recent air quality monitoring data indicate 

that mean levels of PM2.5 are as high as 

18 micrograms per cubic meter (μg/m3) in the 

northeastern United States but consistently 

lower than 12 μg/m3 in the mid-continental 

states for the years 2000-2003 (see Figure A-1). 

The northeastern United States is a region of 

high ambient PM levels, with 98th-percentile 

values up to 65 μg/m3 (the U.S. ambient air 

quality standard) at a majority of sites. Canadian 

locations exhibit generally lower levels of PM2.5, 

although 98th-percentile concentrations greater 

than 30 μg/m3 (the Canada-wide Standard) 

occurred in several regions of the country for 

the years 2000-2002, particularly in the WindsorQuebec City corridor. 

Current ambient levels of PM2.5 in much of 

the border region exceed both Canadian and U.S. 

standards, affecting over 65 million people in the 

United States and 13 million Canadians. In the 

Georgia Basin—Puget Sound region, there are 

sites with elevated PM2.5 levels (with very few 

sites exceeding either standard for the time 

periods evaluated), but the problem is more 

confined (subregional), and the levels 

are generally lower than in the northeast. 

Urban concentrations of PM2.5 are higher than 

concentrations in rural sites in all regions of both 

Canada and the United States. 

A.2.2 Observations of Ambient Ozone 

Concentrations 

Regional PM2.5 and ground-level ozone share 

common precursors and similar influences of 

transport and meteorology in eastern North 

America, with the highest concentrations of 

both occurring in the summer months. 

Ambient ozone data have been examined at 

monitoring sites within 500 km of the CanadaU.S. border. Data meeting specific data 

completeness requirements were used to create 

the contour map presented in Figure A-2. This 

figure shows the annual fourth-highest daily 

maximum eight-hour ozone concentration 

averaged over the period 2000-2002 in Canada 

and the United States, the basis for determining 

compliance with the ozone standard (65 parts 

per billion (ppb) for Canada and 85 ppb for the 

United States). The highest values are found in 

the northeastern United States and southeastern 

Canada, while the lowest values are generally 

found in southern Manitoba and southern 

British Columbia near Vancouver. A large 

portion of the northeastern United States and 

southeastern Canada also exhibits levels in 

excess of domestic standards set for ozone in 

the respective countries. 

A.2.3 Observations of Sulfate and 

Nitrate Deposition 

Although there have been marked reductions 

in sulfate and, to a lesser extent, nitrate 

concentrations, acidic deposition remains 

at levels that cause concern for sensitive 

ecosystems in both countries. Wet deposition 

is comparatively easy to measure using 

precipitation gauges and is regularly used 

3 
Canada-United States Emissions Cap and Trading Feasibility Study 

Figure A-1 Mean PM2.5 Concentrations (μg/m3) at Canadian Dichotomous Monitors


and U.S. Federal Reference Monitors in the Border Region, 2000-2003 


Source: Canada–U.S. Transboundary PM Science Assessment, 2004. 

Figure A-2 Ozone Concentrations (ppb) in the U.S.-Canada Border Regions, 2000­


2002 (Average Annual Fourth-Highest Daily Maximum Eight-Hour Ozone) 


Source: Canada–United States Air Quality Agreement Progress Report, 2004. 

50-55 

55-60 

60-65 

65-70 

70-75 

75-80 

80-85 

85-90 

90-95 

<50 

<95

4 
Section A


Figure A-3 Average Wet Sulfate Figure A-4 Annual Wet Sulfate Deposition, 

Deposition, 1990-1994 2002 

Source: Canada-United States Air Quality Agreement 

Progress Report, 2004. 

Source: Canada-United States Air Quality Agreement 

Progress Report, 2004. 

as the reference measure for comparison with 

emissions. On the other hand, the dry portion 

of deposition is difficult to measure directly; 

therefore, inferential models are used in 

conjunction with filter pack measurements 

of pollutant concentrations to estimate dry 

deposition. The combination of wet and dry 

deposition of sulfate and nitrate contributes to 

the acidification of ecosystems. Estimated sulfate 

and nitrate wet deposition data for the years 

1990-1994 are illustrated in Figures A-3 and A-5, 

to be compared with sulfate and nitrate 

deposition data for 2002 in Figures A-4 and A-6. 

There has been a significant response to both the 

U.S. and Canadian Acid Rain Programs. A broad 

regional response to SO2 emission reductions, in 

particular, is seen along the U.S.-Canada border. 

Wet sulfate deposition is greatest in eastern 

North America, along an axis running from the 

Mississippi River to the lower Great Lakes. 

SO2 emissions are estimated to have declined 

by a third to a half from 1990 levels, largely over 

the eastern half of North America. NOX emissions 

have risen in Canada and have fallen slightly in 

the United States. Decreasing NH3 emissions, 

where sulfate concentrations are high, can 

reduce PM2.5 mass concentration, but may 

increase precipitation acidity. Trends in wet 

deposition of sulfate and nitrate correspond to 

changes in SO2 and NOX emissions (Environment 

Canada, 2004). 

A.3 PRECURSOR EMISSIONS: 

SOURCES AND GEOGRAPHICAL 

DISTRIBUTION OF SO2 AND NOX 

SO2 and NOX emissions are significant 

contributors to the shared air quality problems of 

the transboundary region in both Canada and the 

United States. The gaseous precursor emission 

distributions of NOX and SO2 largely follow 

population centers and result from intensive 

energy use, industrial activity, and transportation 

sources, also extending throughout the crossborder region in a wide area (see Figures A-7 

and A-8). High SO2 and NOX emissions are 

located in the industrial Midwest, northeastern 

United States, and southern Ontario. 

5 
Canada-United States Emissions Cap and Trading Feasibility Study 

Figure A-5 Average Wet Nitrate Figure A-6 Annual Wet Nitrate Deposition, 

Deposition, 1990-1994 2002 

Source: Canada-United States Air Quality Agreement 

Progress Report, 2004. 

Source: Canada-United States Air Quality Agreement 

Progress Report, 2004. 

A.3.1 Sulfur Dioxide 

Electricity generators contributed about 

70 percent of SO2 emissions in 2002 to the total 

national emissions in the United States, with 

some 95 percent of these emissions from coal 

combustion. In Canada, electricity generators 

contributed approximately 26 percent of SO2 

emissions to the total national emissions, 

with 86 percent of these emissions from coal 

combustion (Figure A-9). Non-ferrous mining 

and smelting are the main anthropogenic 

sources of SO2 emissions in Canada, accounting 

for roughly 33 percent. 

Overall, a 38 percent reduction in SO2 

emissions is projected in Canada and the United 

States from 1980 to 2010. In the United States, 

these reductions in SO2 emissions are mainly a 

result of controls on electric utilities under the 

the Acid Rain Program (1990 Clean Air Act 

Amendments (CAAA), Title IV) and the Clean Air 

Interstate Rule (CAIR) and desulfurization of 

diesel fuel under Section 214 of the 1990 CAAA. 

In Canada, these reductions are primarily from 

actions in the non-ferrous mining and smelting 

sector and electric utilities as part of the Canadawide Acid Rain Strategy. As demonstrated in 

recent reports and government findings, more 

reductions of SO2 and NOX emissions are needed 

on both sides of the border to lower background 

levels and transport of precursors and to more 

fully address the shared air quality problems 

(Canada–U.S. Air Quality Committee, 2004). 

A.3.2 Nitrogen Oxides 

The principal anthropogenic sources of NOX 

emissions in North America remain the 

combustion of fuels in nonroad and on-road 

mobile sources and electricity generators. 

Motor vehicles, residential and commercial 

furnaces, industrial and electric utility boilers 

and engines, and other equipment contribute to 

this category. The power sector in the United 

States contributes roughly 22 percent of the total 

national emissions of NOX; 87 percent of those 

NOX emissions result from coal. In Canada, the 

power sector contributes 11 percent of total 

national NOX emissions, of which 81 percent 

is from coal (Figure A-9). 

U.S. reductions in NOX emissions are 

attributed to the estimated controls associated 

6 
Section A


Figure A-7 Canada (2000) – U.S. (2001) Geographical Distribution of SO2 Emissions 

Source: Environment Canada and EPA. 

SO2 

tons/y 

250 000 

10 000 

500 

100 

50 

20 

10 

5 

2 

1 

Figure A-8 Canada (2000) – U.S. (2001) Geographical Distribution of NOX Emissions 

NOX 

tons/y 

96 500 

10 000 

5 000 

1 000 

400 

100 

50 

10 

5 

1 

Source: Environment Canada and EPA. 

7 
Canada-United States Emissions Cap and Trading Feasibility Study 

Figure A-9 U.S. and Canadian National Emissions by Sector for SO2 and NOX, 2002 

U.S. Emissions–2002 

Sulfur Dioxide 

Total: 15.8 million tons/year 

Solvents 

Other Nonroad 

Forest Fires On-road 

Industrial 

Non-Industrial 

Generating 

Unit 

Electric 

U.S. Emissions–2002


Nitrogen Oxides


Total: 21.2 million tons/year


Canadian Emissions–2002


Nitrogen Oxides


Total: 2.8 million tons/year


Forest Fires 

Other 

Solvents 

Electric 


On-road Generating 


Unit


Industrial Nonroad 

Non-Industrial 

Forest Fires 

Other 

Solvents 

Nonroad 

On-road 

Industrial 

Non-Industrial 

Electric 

Generating 

Unit 

Source: Canada–United States Air Quality Agreement Progess Report, 2004. 

with the Tier 2 Tailpipe Standard, Heavy-Duty 

Engine and Vehicle Standards, and the Highway 

Diesel Fuel rules, as well as to controls in 

electric utilities under the Acid Rain Program and 

the regional efforts to address ozone transport, 

beginning with the Ozone Transport Commission 

NOX Budget Program (1999) and the NOX State 

Implementation Plan (SIP) call NOX Budget 

Trading Program (2004) as well as the Clean 

Air Interstate Rule (2009). 

In Canada, substantial NOX emission 

reductions are expected to occur mainly as a 

result of the implementation of the Ozone Annex 

under the Canada-U.S. Air Quality Agreement, 

including the stationary source commitments for 

NOX emissions and the 10-year vehicle and fuels 

agenda, which implements Tier 2 Tailpipe 

Standards, among other initiatives. However, 

recent research findings indicate more action 

may be warranted to solve the shared air quality 

problems. 

A.4 SHARED SOURCE 

REGIONS 

Observational evidence, in combination with 

emissions information and air quality model 

applications, has been used by both Canada 

and the United States to determine the source 

8 
Section A


Figure A-10 Combined QTBA Plot 

Derived Using 2000 and 2001 PM2.5 

Measurements for the Warm Months 

(May-September) 

Source: Canada–United States Transboundary PM Science 

Assessment, 2004. 

regions that contribute to poor air quality in the 

transboundary region. These scientific results 

have led to the notion of a borderless approach to 

air quality analysis and, ultimately, management, 

with sources and source regions of smog, fine 

particles, and acid deposition transcending 

geographic boundaries. The following scientific 

studies have been selected as evidence of this 

borderless approach, but these studies are by 

no means exhaustive. Additional analyses can 

be found in material provided in the reference 

section. 

A type of source-receptor analysis known 

as Quantitative Transport Bias Analysis (QTBA) 

was applied to determine the geographic areas 

that contribute to above- and below-average 

fine particle mass (PM2.5) over eastern 

Figure A-11 Average Concentrations (μg/m3) of PM2.5 and Components by State 

and Province (IMPROVE sites shown as blue dots) 

Each trajectory endpoint is associated with concentrations corresponding to the IMPROVE sample for the 

trajectory start date (Kenski, 2004). EC = elemental carbon, OC = organic carbon, SO4 = sulfate, NO3 = nitrate 

Source: Canada–United States Transboundary PM Science Assessment, 2004. 

9 
Canada-United States Emissions Cap and Trading Feasibility Study 

Table A-1 Average Concentration and Percent Contribution of PM2.5 Mass from 

Selected States to Class 1 Areas (Acadia, Boundary Waters, Dolly Sods) 

Class 1 

Area Acadia Boundary Waters Dolly Sods 

State/ 

province 

Average PM2.5 Annual 

concentration percent 

(ug/m3) PM2.5 mass 

Average PM2.5 Annual 

concentration percent 

(ug/m3) PM2.5 mass 

Average PM2.5 Annual 

concentration percent 

(ug/m3) PM2.5 mass 

States 

Illinois 10.8 0.4 9.5 1.7 8.7 1.6 

Indiana 17.1 0.9 12.5 0.6 11.0 3.2 

Iowa 7.6 0.2 8.1 5.0 8.5 0.9 

Kentucky 11.8 0.5 14.0 8.6 

Maine 5.6 12.6 8.6 0.1 

Michigan 7.6 1.7 6.2 1.7 10.1 2.6 

Minnesota 7.1 0.6 5.7 35.2 8.6 1.0 

New Hampshire 8.6 2.0 

New Jersey 18.9 1.0 8.4 0.1 

New York 8.2 4.4 9.1 0.8 

North Carolina 13.9 0.3 10.0 0.1 12.0 3.1 

Ohio 10.6 1.2 12.8 0.2 11.5 8.8 

Pennsylvania 13.2 3.0 10.9 5.1 

Tennessee 9.9 0.2 13.4 4.9 

Vermont 8.3 1.8 

Virginia 14.2 0.9 11.8 7.6 

West Virginia 18.4 0.5 10.0 0.1 14.0 26.4 

Wisconsin 6.2 0.6 7.1 7.6 9.0 1.3 

Provinces 

Ontario 6.0 7.7 3.5 16.4 9.2 4.8 

Quebec 4.9 17.8 2.4 0.2 6.6 0.7 

Source: Canada–United States Transboundary PM Science Assessment, 2004. 

North America (Figure A-10) (Canada-U.S. 

Transboundary PM Science Assessment, 2004). 

Source regions are shown with the area of 

most significant contribution indicated by the 

gray coloring, and the area of least significance 

to above-average concentrations indicated by 

the blue coloring (as per the legend). Receptor 

sites used for the analysis are shown as yellow 

stars, while the black circles indicate locations 

of the greatest predicted contribution to the 

receptors. Values greater than 1.0 indicate a 

high likelihood of air masses passing over 

that area, bringing above-average warm-season 

PM2.5 to the receptor. Much of the populated area 

of northeastern Canada and the United States 

was implicated in the buildup of PM2.5 to aboveaverage concentrations. The significantly 

contributing area leading to above-average 

PM2.5 levels at the receptor sites covers much 

of the eastern United States, as well as southern 

Ontario. 

Speciated IMPROVE measurements for 17 

Class 1 sites (represented by dots in Figure A-11) 

in the eastern United States were examined in an 

analysis (Kenski, 2004) at the Lake Michigan Air 

Directors Consortium. Three-day back-trajectories 

for these sites were calculated with each endpoint 

(one per hour, 72 per trajectory) associated 

with concentrations corresponding to IMPROVE 

samples for the trajectory start date. These 

concentrations are averaged by state and 

province, as shown in Figure A-11. 

The data presented indicate which states are 

associated with high-concentration air masses 

arriving at Class 1 areas, but do not take into 

10 
Section A


account the frequency with which air masses 

traverse a particular area or state. States that 

are closer to Class 1 sites will tend to contribute 

more PM2.5 to those sites, because the air masses 

spend more time over those nearby states and 

emissions from nearby sources have less time 

to disperse and deposit than emissions from 

sources farther away. These areas of more 

frequent transport can be associated with PM2.5 

concentrations that are high, low, or moderate. 

By combining this frequency information with 

the concentration information, this study derives 

an average contribution to PM2.5 mass from each 

state/province to the Class 1 areas. 

Table A-1 gives the average concentration 

and percent PM2.5 mass contributed by selected 

states and provinces to a sample of the Class 1 

areas examined. These results can be thought 

of as indicators combining the upwind status 

of a state/province, the geographic size of the 

state/province, and the magnitude of source 

emissions within the state/province. A state 

or province that is close to, and frequently 

upwind of, multiple Class 1 areas will 

generally contribute more mass than states 

or provinces that are seldom upwind, unless the 

concentration difference is marked. For example, 

Minnesota contributes a large percentage 

of mass to Boundary Waters (35.2 percent), 

although the average concentration associated 

with air masses in Minnesota is less than 

6 μg/m3. Similarly, the Canadian provinces 

make significant contributions to the border-area 

Class 1 sites; Ontario provides about 16 percent 

of the annual PM2.5 mass at Boundary Waters, 

and Quebec provides about 18 percent to Acadia. 

Ohio and Pennsylvania are associated with highconcentration air masses at the three Class 1 

sites shown, but make significant (>5 percent) 

contributions to annual PM2.5 mass only at the 

nearby Dolly Sods wilderness site. 

In an analogous manner, the contribution 

of each state and province to the joint set of 17 

Class 1 areas was derived (not shown). The 

results indicate that some states associated with 

high-concentration air masses nevertheless 

contribute only a small amount of mass to the 

collective group of Class 1 sites; conversely, 

states (or provinces) with low average 

concentrations can be major mass contributors 

(Kenski, 2004). 

The Canada-U.S. Transboundary PM Science 

Assessment, completed and peer reviewed 

in 2004 under the Canada-U.S. Air Quality 

Agreement, found further evidence that 

emissions of SO2 and NOX from the northeastern 

United States and southern Canada have an 

impact on PM2.5 levels in many areas of the two 

countries, including as far east as Nova Scotia 

and New Brunswick. Source-receptor analyses 

indicate that there are several areas that 

contribute to elevated PM levels in eastern 

North America. These areas include, but 

are not restricted to, the following: 

•	 Southeast Ohio to the western part 

of Virginia, and western Kentucky to 

central Tennessee 

•	 Windsor-Quebec City corridor 

•	 U.S. Midwest and Boston-to-Washington, 

D.C., corridor 

•	 Ohio River Valley. 

Additional evidence for cross-border flows 

of air masses comes from observations of natural 

events such as forest fires and dust episodes. 

Satellite imagery and aerosol optical depth 

measurements give visual evidence of the 

movement of pollutants across boundaries 

(Figure A-12). This particular episode clearly 

demonstrates movement of air masses and the 

associated pollutants from Canada to a large 

geographic area within Canada and to the south 

into the United States. 

A.5 SUMMARY 

The United States and Canada share three 

principal air quality problems contributing to 

degradation of air quality, health, and visibility: 

fine particles (PM2.5), tropospheric ozone, and 

acid deposition. Transport of key precursor 

emissions such as SO2, NOX, VOCs, and NH3 

11 
Canada-United States Emissions Cap and Trading Feasibility Study 

Figure A-12 Satellite Imagery of the Quebec Forest Fire PM Episode in July 2002 

Source: Canada–United States Transboundary PM Science Assessment, 2004. 

can lead to the formation of acid deposition 

and ground-level ozone (smog). 

A significant portion of the population in 

the eastern border regions of both Canada and 

the United States is exposed to levels of air 

pollutants that exceed air quality standards 

designed to protect human health. As well, 

acidic deposition remains at levels that cause 

concern for sensitive ecosystems. While there 

have been significant reductions of the emissions 

of these key pollutants, poor air quality, visibility 

problems, regional haze, and acid deposition 

continue to be recorded in the shared border 

region between Canada and the United States. 

Observational evidence, in combination 

with emission information and air quality 

model applications, has been used by both 

Canada and the United States to determine the 

source regions that contribute to poor air quality 

in the transboundary region. These scientific 

results have led to the recognition of the 

value of a borderless approach to air quality 

management. 

Further emission reductions have been 

identified as necessary to improve air quality 

and visibility and reduce acid deposition and 

regional haze in the shared cross-border region. 

An emissions cap and trading program can 

reduce the total loading of a pollutant into 

the atmosphere. Emissions cap and trading is 

most effective when pollutants are emitted by 

many sources and transported over a large 

geographic region. The data presented here 

support the conclusion that such a case exists 

along the U.S.-Canada border region. 

12 
Section A


A.6 REFERENCES 

Bulger, A.J., Cosby, B.J., and Webb, J.R. (2000). 

Current, reconstructed past, and projected 

future status of brook trout (Salvelinus 

fontinalis) streams in Virginia. Canadian 

Journal of Fisheries and Aquatic Sciences, 

57: 1515-1523. 

Canada-United States Air Quality Committee 

(2002). “The Canada-United States Air 

Quality Agreement: 2002 Progress 

Report.” 

Canada-United States Air Quality Committee 

(2004). “The Canada-United States Air 

Quality Agreement: 2004 Progress 

Report.” 

Canada-U.S. Air Quality Committee 

Subcommittee on Scientific Cooperation 

(2004). “Canada-United States 

Transboundary PM Science Assessment.” 

Catalogue En56-203/2004E. 129 pp. 

Charola, A.E. (2001). Acid deposition on stone. 

U.S. National Committee of the 

International Council on Monuments and 

Sites (U.S./ICOMOS) Scientific Journal, 

III(1): 19-58. 

Driscoll, C.T., Lawrence, G.B., Bulger, A.J., Butler, 

T., Cronan, C.S., Eagar, C., Lambert, 

K.F., Likens, G.E., Stoddard, J.L., and 

Weathers, K.C. (2001). Acidic deposition in 

the northeastern United States: Sources 

and inputs, ecosystem effects, and 

management strategies. Bioscience, 

51(3): 180-198. 

Environment Canada (2004). “Canadian Acid 

Deposition Science Assessment.” 

Meteorological Service of Canada, 

Environment Canada. 

Finlayson-Pitts, B.J. and Pitts, J.N. (2000). 

“Chemistry of the Upper and Lower 

Atmosphere: Theory, Experiments and 

Applications.” Academic Press, San Diego, 

California. 

Kenski, D.M. (2004). Quantifying transboundary 

transport of PM2.5: A GIS analysis. In: 

“Proceedings of the 97th Air and Waste 

Management Association Annual 

Conference, Indianapolis, Indiana, 

June 2004.” 

McMurry, P.H., Shepherd, M.F., and Vickery, J.S. 

(2004). “Particulate Matter Science for 

Policy Makers: A NARSTO Assessment.” 

Cambridge University Press, Cambridge. 

Seinfeld, H.H. and Pandis, S.N. (1997). 

“Atmospheric Chemistry and Physics: 

From Air Pollution to Climate Change.” 

Wiley, New York. 

U.S. EPA (2005). “Regulatory Impact Analysis for 

the Final Clean Air Interstate Rule.” Office 

of Air and Radiation, U.S. Environmental 

Protection Agency, Washington, D.C., 

March, pp. 4-30 and 4-31. 

13 

I

n both Canada and the United States, different 

levels of government share jurisdiction 

over environmental affairs, and this is reflected 

in the environmental laws of each country. In 

Canada, both the federal and provincial levels 

of government play a role in the regulation 

of sulfur dioxide (SO2) and nitrogen oxide 

(NOX) emissions. In the United States, state 

governments are responsible for implementing 

much of the environmental legislation, but the 

federal government sets ambient air quality 

standards and overall emission limitations. 

This section analyzes the legal framework 

relevant to a cross-border emissions cap and 

trading program. Since there are no national 

emission cap and trading programs in Canada to 

date, this section describes the legal authority 

whereby Canada could establish such a regime. 

For the United States, this section also describes 

the existing U.S. emission cap and trading 

programs and discusses some of the technical 

requirements of a cross-border trading 

program. The U.S. currently does not have 

any emission cap and trade programs that 

involve international emissions trading, nor 

is it clear the extent to which authority exists 

under the Clean Air Act to establish such a 

program. Legislative and/or regulatory action 

would likely be required to authorize a crossborder emissions cap and trading program 

for SO2 and NOX. Section B.1 describes the 

regulation of SO2 and NOX in the United States, 

while Section B.2 describes regulation in 

Canada. 

B.1 UNITED STATES 

In the United States, the federal U.S. 

Environmental Protection Agency (EPA) 

develops and enforces regulations that 

implement environmental laws enacted by 

Congress. EPA is responsible for researching 

and setting national standards for a variety of 

environmental programs and in many instances 

Section B 

LEGAL BACKGROUND 

delegates to states and tribes the responsibility 

for issuing permits and for monitoring and 

enforcing compliance, while continuing to 

reserve the authority to enforce compliance itself 

where necessary. Where national standards are 

not met, EPA can issue sanctions and take steps 

to assist the states and tribes in reaching the 

desired levels of environmental quality. A state 

always has the option, unless barred by state 

law, to impose stricter standards than those 

required by the federal government in order to 

meet environmental goals. 

B.1.1 The Clean Air Act 

The Clean Air Act (CAA) gives EPA the authority 

to set permissible atmospheric concentrations 

for “criteria pollutants” for the entire country. 

To date, such limits have been set for particulate 

matter (PM), carbon monoxide (CO), nitrogen 

dioxide (NO2), sulphur dioxide (SO2), ozone 

(O3), and lead. EPA sets these limits, referred 

to as National Ambient Air Quality Standards 

(NAAQS), taking into account human health and 

the prevention of environmental and property 

damage. Individual states can set stricter 

pollution standards, but cannot have weaker 

standards. In addition, other environmental 

regulations cannot supersede the NAAQS. 

While there is flexibility in the method 

and timing of meeting emission reduction 

requirements of Title IV of the Clean Air 

Amendments of 1990 (CAAA), as described 

below, the NAAQS still limit the total permissible 

concentrations of the criteria pollutants in a 

given area. Titles I (NAAQS) and IV (Acid Rain 

Program) are complementary. 

Individual states have responsibility for 

achievement of the NAAQS. Each state must 

prepare a State Implementation Plan (SIP) that 

outlines planned measures to meet the air 

quality standards. For the purpose of assessing 

air quality, each state is divided into smaller air 

quality areas. Each area is designated as being 

15 
Canada-United States Emissions Cap and Trading Feasibility Study 

in attainment or nonattainment for each of the 

criteria pollutants. SIPs focus mainly on the 

measures and schedules designed to bring 

nonattainment areas into attainment. EPA 

reviews and approves each SIP and can take 

over the implementation of the NAAQS in a state 

if the SIP is not adequate. 

The CAA also identifies 189 hazardous air 

pollutants, which are chemicals known to present 

a threat of serious health or environmental 

hazards. EPA can add to this list as necessary and 

must issue regulations to reduce the emissions of 

these pollutants from different types of stationary 

sources. Sources are required to use the 

Maximum Achievable Control Technology (MACT) 

to reduce emissions of hazardous air pollutants. 

The CAA permitting system, outlined in 

Title V, is the primary mechanism for regulating 

many types of stationary sources. Source 

permits, usually issued by states, specify which 

pollutants are currently emitted by the source, 

the maximum amount that may be emitted, 

and the steps the owner or operator must take 

to monitor and reduce emissions. All of the 

information relevant to the CAA is contained 

in a single permit, and EPA can issue fines for 

violation of the terms of the permit. 

The CAA also includes provisions for 

controlling pollution that travels across areas 

and states. For example, states can form 

interstate commissions to develop regional 

strategies for controlling air pollution, and EPA 

can issue regulations designed to limit interstate 

transport of emissions. 

B.1.2 Title IV – Acid Rain 

Acid rain receives special attention in the CAAA 

because the long-range transport of acidic 

compounds places the problem beyond the 

control of any one state or region. The purpose 

of Title IV is to reduce environmental damage 

resulting from acid deposition by lowering 

emissions of SO2 and NOX from the combustion 

of fossil fuels, primarily by power plants. Title IV 

sets a national goal of reducing total annual 

SO2 emissions by 10 million tons 1 below 

1980 levels (primarily through a cap and trade 

program) and a goal of reducing annual NOX 

emissions by approximately 2 million tons. 

B.1.2.1 SO2 

SO2 emissions are reduced to the capped level 

through an emissions cap and trading program. 

Coverage 

Title IV mandates a two-phase approach to 

achieving SO2 emission reductions at fossil fuelfired electricity generating plants. Phase I began 

in 1995 and affected 263 units at 110 mostly 

coal-burning electric utility plants located in 21 

eastern and midwestern states.2 Under Phase II, 

which began in 2000, Title IV broadened 

coverage to virtually all existing fossil fuel-fired 

electricity generating units serving generators 

with a nameplate capacity greater than 25 

megawatts (MW), as well as virtually all new 

units, regardless of size. In addition to the large 

coal-fired units, Phase II requires that smaller, 

cleaner plants fired by coal, oil, and gas— 

encompassing over 3,000 units in all—hold 

allowances for their SO2 emissions. 

Allowances 

The overall cap for SO2 emissions is divided into 

allowances, each of which currently authorizes 

a unit to emit one ton of SO2 during or after a 

specified year. Existing affected utility units—but 

not new units—are allocated allowances based 

on the product of their historic fuel consumption 

and a specific emissions rate. At the end of each 

calendar year, the owners or operators of each 

unit must surrender one allowance for each ton 

of SO2 emitted from that unit during the year. 

Allowances may be bought, sold, or banked, but 

1 One ton = 2,000 pounds ~ 0.9072 tonne. ~

An additional 182 units joined Phase I of the program as substitution or compensating units, bringing the total of Phase I 

affected units to 445. 

16 

2 
Section B


once they are used for compliance, they cannot 

be used again. Anyone may acquire allowances 

and participate in the trading system. Regardless 

of the number of allowances a source holds, it 

may not emit at levels that would violate any 

other requirements of the CAA. 

Emissions Monitoring 

In addition to allowance-holding requirements, 

each unit must continuously measure and record 

its emissions of SO2, NOX, and carbon dioxide. 

This monitoring requirement ensures the credible 

accounting of emissions that is necessary to 

guarantee the integrity of the market-based 

allowance system and to verify the achievement of 

the emission reduction goals. Rigorous monitoring 

standards instill confidence in allowance 

transactions by certifying the underlying emission 

values of the commodity (i.e., allowances) being 

traded and ensure that the government can track 

progress toward the emission reduction targets. 

In most cases, a unit must have a continuous 

emission monitoring system (CEMS) installed to be 

in compliance with Title IV. EPA has issued detailed 

regulations for CEMS (40 CFR Part 75), including 

initial equipment certification procedures, periodic 

quality assurance and quality control procedures, 

record-keeping and reporting requirements, and 

procedures for filling in missing data periods. All 

CEMS must be in continuous operation and must 

be able to sample, analyze, and record data at 

least every 15 minutes. In some instances, Part 75 

allows oil- and gas-fired units to use less rigorous 

“excepted” monitoring methods (e.g., fuel flow 

metering and fuel sampling) in lieu of CEMS. 

Affected sources may also petition EPA to use 

alternate monitoring systems; to be approved, an 

alternative system must demonstrate accuracy 

and reliability comparable to a CEMS. 

If CEMS data, data from an excepted method, 

or data from an alternative monitoring system 

approved by EPA are not available for any affected 

unit during any period, the unit is considered to 

be operating in an uncontrolled manner for the 

period for which the data were not available. EPA 

has prescribed formulas, some of which are very 

conservative, to calculate emissions for periods of 

missing data, and the owner or operator is liable 

for excess emission fees and must still ensure that 

it holds sufficient allowances to offset the higher 

calculated emissions. There is also a fine for 

noncompliance with monitoring provisions. 

(See Section D for greater detail on monitoring 

and reporting.) 

Permits 

The owner or operator of each source is required 

to file a permit application and a compliance 

plan under Title V of the CAA. Acid rain permits 

require that the owner or operator hold for each 

affected unit a sufficient number of allowances 

to cover the unit’s SO2 emissions in each year, 

comply with the applicable NOX limit, and 

monitor and report emissions. Permits are 

subject to public comment before approval. 

Other than these basic requirements, the Title V 

permitting system does not prescribe any specific 

actions that must be undertaken by owners and 

operators. Sources have broad flexibility in how 

they meet the allowance-holding provisions of 

Title IV, e.g., by reducing emissions or by buying 

allowances, so long as they hold sufficient 

allowances at the end of the year to cover their 

annual emissions for that year. 

Opt-ins 

The Acid Rain Opt-in Program provides sources 

not required to participate in the Acid Rain 

Program with the opportunity to enter the 

program on a voluntary basis, comply with Part 

75 for emissions monitoring, and receive their 

own SO2 allowances. To date, however, only a 

small number of units have opted in to the 

program. 

B.1.2.2 NOX 

Title IV of the CAAA also set a goal of reducing 

NOX emissions by approximately 2 million 

tons. The NOX program provides some flexibility 

for sources to choose the method to achieve 

17 
Canada-United States Emissions Cap and Trading Feasibility Study 

emission reductions, but does not “cap” NOX 

emissions as the SO2 program does, nor does it 

utilize an allowance trading system. Instead, 

affected sources must meet a NOX emissions 

rate, expressed in pounds of NOX per million 

British thermal units (mmBtu) 3 of heat input. An 

affected source can meet the emissions rate for 

an individual boiler or by averaging its emission 

rates with those of one or more other boilers 

with the same owner or operator. 

Phase I of the NOX program began on 

January 1, 1996, and applied to two types of 

boilers that were already targeted for Phase I SO2 

reductions: larger dry-bottom wall-fired boilers 

and tangentially-fired boilers. Approximately 

170 boilers needed to comply with the NOX 

emissions rates during Phase I. Phase II of 

the NOX program, which began in 2000, set 

lower emission limits for remaining wall- and 

tangentially-fired boilers and established initial 

NOX emission limitations for boilers applying 

cell-burner technology, cyclone boilers, wetbottom boilers, and other types of coal-fired 

boilers. 

B.1.3 Ozone Transport Commission NOX 

Budget Program 

In 1994, a number of eastern states formed 

the Ozone Transport Commission (OTC) to 

develop a regional approach to reducing NOX 

emissions, 4 as prescribed under the Clean Air 

Act Amendments of 1990. Most of the states 

in the OTC were facing difficulties meeting 

the NAAQS for ozone through individual state 

measures because of regional transport. Under 

the OTC, these states agreed to develop and 

adopt a regulatory cap and trading program to 

reduce NOX emissions from electricity generators 

and large industrial boilers starting in 1999. 

EPA provided assistance to the states by helping 

them develop a “model rule,” which states could 

adopt and which identified elements of the 

trading system that needed to be consistent 

across states. These elements included source 

applicability (sector coverage), control period, 

allowance trading and banking requirements, 

emissions monitoring, record-keeping for 

emissions and allowances, and electronic 

reporting requirements. 

B.1.3.1 Common Elements 

Applicability 

The program affected all fossil fuel-fired boilers 

or indirect heat exchangers with a maximum 

rated heat input capacity of 250 mmBtu/hour 

or greater and all electricity generating facilities 

with a rated output of 15 MW or greater. States 

had the option of requiring additional sources— 

both below the threshold and in other sectors— 

to participate in the trading program if they could 

monitor emissions properly. 

NOX Budgets 

The OTC NOX regional budget was established 

in 1995 based on discussions among states, 

industry, EPA, and environmental groups. The 

group applied the overall emissions reduction 

target to 1990 baseline emissions from affected 

sources and then divided the resulting total cap 

among participating states. Each state was then 

responsible for allocating allowances to specific 

sources, but the emission caps, or state trading 

budgets, could not be changed. 

Control Period 

The control period in which units had to limit 

their emissions lasted from May through 

September, corresponding to the annual peak 

ozone season. Beginning in 1999, the sum of 

NOX emissions from affected sources during the 

May through September control period could not 

exceed the equivalent number of allowances 

allocated in the region, and each source had to 

hold an amount of allowances at least equal to 

One Btu ≈ 1.06 kilojoules. 

Maine, New Hampshire, Vermont, Massachusetts, Connecticut, Rhode Island, New York, New Jersey, Pennsylvania, 

Maryland, Delaware, northern Virginia, and the District of Columbia. 

18 

3 

4 
Section B


its NOX emissions. The affected sources were 

allowed to buy, sell, or trade allowances to meet 

their needs. In 2003, the OTC states adopted 

lower caps under the NOX SIP call, which 

superseded the OTC trading program (see 

Section B.1.4 below). Compliance is determined 

annually after the end of the control period by 

ensuring that each affected source has sufficient 

allowances to match its emissions. Sources can 

bank allowances forward to subsequent years, 

but cannot emit at levels that would violate other 

CAA or state requirements. 

Monitoring, Allowance Tracking, and Reporting 

As with SO2 under the Title IV Acid Rain 

Program, affected sources under the OTC were 

required to monitor emissions, primarily with 

CEMS. Low-emitting sources such as gas-fired 

power plants could use other estimation 

methods, provided they offered a similar level 

of accuracy. The OTC states requested that 

EPA develop the NOX allowance and emissions 

tracking systems (see Section F) on the 

basis of the existing federal SO2 systems. 

They also asked EPA to administer the annual 

reconciliation and compliance procedures. 

States retained the responsibility for allocations, 

auditing of source monitoring requirements, and 

enforcement of compliance. 

B.1.3.2 Areas of Flexibility 

Under the model rule, states were responsible 

for enacting state-level regulations to implement 

the OTC program, and they were charged with 

allocating allowances to affected sources in their 

jurisdiction. The OTC decided that discretion 

in allocation methodologies would not interfere 

with the operation of the trading system, 

and therefore states could choose different 

approaches to allocation. States were also 

responsible for determining baselines for sources 

that opt in to the program and had the option 

to set aside allowances for early reductions prior 

to the start of the program, for renewable and 

energy efficiency projects, and for new entrants. 

B.1.4 The NOX SIP Call 

In 1998, EPA announced that a large number 

of eastern states would be required to submit 

new NOX SIPs. 5 EPA concluded that, because 

of the long-range transport of ozone, these states 

would continue to interfere with other states’ 

ability to achieve attainment with ozone air 

quality standards without further reductions 

of regional emissions. The SIP call established 

state budgets for total NOX emissions during 

the ozone season from May 1 to September 30 

each year. Each state had the freedom to 

enact specific measures to meet the emission 

limitations for various sectors outlined in the SIP 

call, but EPA developed a model rule for states 

that preferred an emissions cap and trading 

approach for stationary sources to achieve 

required reductions. Under the model rule, 

EPA administers an ozone season NOX cap 

and trading program for states that choose to 

participate in the program. The similarity of this 

model rule to the OTC NOX Budget Program 

model rule allowed states participating in the 

OTC to transition smoothly into the NOX SIP 

call program, known as the NOX Budget Trading 

Program. 

B.1.4.1 The Model Rule – Common Elements 

The model rule set forth mandatory elements 

of the NOX Budget Trading Program. States 

could choose not to adopt the EPA-administered 

trading program as a whole, but if they decided 

to participate in that trading program, they had 

to adopt the entire model rule with only a few 

types of changes being allowed. The mandatory 

elements ensured consistency across states in 

development of a regional emissions cap and 

trade program. Such consistency is essential 

SIP call states included Alabama, Connecticut, the District of Columbia, Delaware, Illinois, Indiana, Kentucky, 

Massachusetts, Maryland, Michigan, North Carolina, New Jersey, New York, Ohio, Pennsylvania, Rhode Island, South 

Carolina, Tennessee, Virginia, West Virginia, Wisconsin, Georgia, and Missouri. Following litigation in 2000, Wisconsin 

was dropped from the program and Georgia and Missouri were given compliance dates of 2007. 

19 

5 
Canada-United States Emissions Cap and Trading Feasibility Study 

to guarantee a cost-effective emissions market, 

a transparent monitoring and compliance 

regime, and the value and validity of an 

allowance. With regard to a few elements, 

such as allowance distribution and set-asides, 

states had some discretion to modify the rule. 

Applicability 

To adopt the model rule, states had to include all 

fossil fuel-fired electricity generators with a rated 

capacity of greater than 25 MW and all industrial 

boilers and turbines with a rated thermal input 

of greater than 250 mmBtu/hour. The OTC 

states that transferred into the NOX SIP call (all 

except New Hampshire) could maintain their 

applicability threshold of electricity generators 

with equal to or greater than 15 MW capacity. 

Monitoring 

As with the SO2 trading program, all affected 

sources are required to monitor emissions 

using CEMS or an alternative methodology of 

equivalent rigor. EPA updated Part 75 of the 

Title IV regulations to include provisions for 

monitoring and certification, data review, 

quality assurance tests, and quarterly reporting 

with regard to NOX mass emissions from both 

electricity generating units and industrial sources 

under an emissions cap and trade program. EPA 

is responsible for establishing and maintaining 

the centralized emissions data tracking system. 

Timing of Allocation 

EPA allocates NOX allowances to sources 

on a schedule determined by each individual 

state. Generally, allocation occurs a number of 

years before the compliance period to facilitate 

market liquidity and provide owners and 

operators with the certainty needed for longterm emission reduction planning. The annual 

compliance period for the NOX SIP call is the 

five-month ozone season, from May through 

September. The allowance reconciliation process 

follows a two-month period in which sources 

can make additional allowance transfers. 

Banking 

An allowance is defined as an authorization to 

emit one ton of NOX during a particular season. 

Sources cannot use an allowance before its year 

of allocation or “vintage,” but unused allowances 

can be banked for use in future years. The 

“Progressive Flow Control” provision changes 

the status of banked allowances if the total 

bank exceeds 10 percent of the regional budget. 

Under these conditions, a source can use 

only a portion of its banked allowances for 

compliance without penalty. The remaining 

banked allowances must be surrendered on a 

two-to-one basis (two banked allowances to 

cover one ton of emissions). This feature is 

designed to discourage large-scale fluctuations 

in emissions—and in attainment status—in 

a particular ozone season that could raise 

concerns regarding seasonal air quality. 

Compliance 

As with the SO2 program, all sources must hold 

sufficient allowances to cover emissions, in this 

case during the summer ozone season. EPA 

performs the annual reconciliation process to 

assess compliance and implements an automatic 

offset of three allowances for each ton of excess 

emissions. States take the lead with additional 

enforcement actions, including fines, and the 

affected sources are still covered by all other 

relevant CAA provisions. 

B.1.4.2 State Flexibility 

Allocation Method 

States receive total NOX budgets on the basis of 

emission baselines from affected sources, but 

they have discretion to determine the allocation 

methodology. States can allocate to sources 

based on historical emissions, through periodic 

updating, or through any other combination of 

methodologies, provided they do not allocate 

more than the allotted state budget. The 

allocation methodologies are outlined in each 

state’s SIP adopting the NOX Budget Trading 

Program model rule. 

20 
Section B


Set-asides 

States may also set aside a portion of the NOX 

budget to provide incentives for early reductions, 

new renewable energy generation, and demandside energy efficiency measures. 

Additional Sources 

Provided they can meet the same stringent 

emission monitoring and reporting standards, 

states may elect to require participation in the 

trading program of electricity generators or 

industrial boiler units that fall below the size 

thresholds outlined in the model rule, as well as 

other types of sources. In addition, they may 

elect to adopt procedures under which individual 

sources not otherwise subject to the trading 

program opt in (voluntary entry), assuming they 

meet certain requirements, including the same 

stringent emissions monitoring and reporting. 

Additional Regulatory Measures 

The model rule does not preempt any existing 

state-level regulations on NOX emissions and air 

quality. For example, states must still meet the 

NAAQS for ozone. Furthermore, an affected 

source cannot emit at levels above permitted 

levels, regardless of how many allowances it 

holds. 

B.1.5 Proposed U.S. Multipollutant Legislation 

and Final Regulations 

B.1.5.1 Legislation: Proposed Clear Skies 6 

Though the experience with allowance trading 

has been successful, the United States is 

committed to further reductions in NOX and 

SO2 emissions necessary to attain the NAAQS 

and to reduce acid rain, reduce regional haze, 

and address other environmental concerns. 

The proposed Clear Skies Act (2003) would 

create a national multipollutant trading program 

for electricity generators, to be centrally 

managed by EPA, which would build upon the 

existing SO2 program, NOX SIP call, and existing 

CAA regulatory authority for mercury emissions. 

As with all proposed legislation in the United 

States, the proposed Clear Skies Act (2003) has 

to be passed by Congress in order to become 

law. An alternative regulatory approach under 

the existing CAA, the Clean Air Interstate 

Rule (CAIR), which requires reductions for 

NOX beginning in 2009 and SO2 in 2010, was 

finalized in March 2005; it is described in 

Section B.1.5.2. 

B.1.5.2 Regulation: The Clean Air 

Interstate Rule 

As part of its commitment to ensure further 

reductions in NOX and SO2, EPA promulgated a 

final regulation called the Clean Air Interstate 

Rule (CAIR). 7 CAIR is a regulatory alternative to 

enacting new legislation. Under this regulatory 

initiative, EPA is making use of its existing 

authority under the CAA to require further 

reductions in emissions if current regulations 

are insufficient to meet the NAAQS. As with the 

NOX SIP call, states have the flexibility to decide 

which sources to control to meet the state 

emissions budget, and EPA has developed an 

optional cap and trade program similar to the 

current Acid Rain Program. 

The geographic coverage of the rule is 

confined to states that have been shown to 

contribute significantly to ozone and particulate 

matter nonattainment areas in other states. 

Most states in the east are controlled for both 

SO2 and NOX annual emissions, and a slightly 

larger number of states are controlled for NOX 

emissions during the ozone season. Western 

states are not covered under CAIR. 

The caps and timing occur in two phases. 

For SO2, the Phase I cap of 3.6 million tons 

begins in 2010 and declines to 2.5 million tons 

by the beginning of Phase II in 2015. The NOX 

program begins a year earlier, in 2009, with the 

6 See http://www.epa.gov/clearskies/ for more information. 

7 See http://www.epa.gov/cleanairinterstaterule/ for more information. 

21 
Canada-United States Emissions Cap and Trading Feasibility Study 

Figure B-1 CAIR: Affected Region and Emission Caps 

Emission Caps* 

(million tons) 

Annual SO2 

(2010) 

2009/2010 

36 

2015 

25 

Annual NOX 

(2009) 

1.5 1.3 

Seasonal NOX 

(2009) 

.58 .18 

* For the affected region. 

States controlled for fine particles (annual SO2 and NOX) 

States controlled for ozone (ozone season NOX) 

States controlled for both fine particles (annual SO2 and NOX) and ozone (ozone season NOX) Source: EPA 

States not covered by CAIR 

Phase I cap set at 1.5 million tons and the Phase 

II cap set at 1.3 million tons in 2015 (Figure B-1). 

Overview of the Trading Programs 

CAIR includes three model rules that states may 

adopt in order to achieve required SO2 and NOX 

emission reductions, through an emissions cap 

and trading approach. The model rule for the 

SO2 trading program is designed to work with 

the existing Title IV program. Title IV allowances 

continue to be used in the new SO2 trading 

program. CAIR SO2 emission reductions in the 

trading program are achieved through retirement 

ratios of Title IV allowances, not through a 

budget for new allowances. Sources turn in Title 

IV allowances for 2010 or later at a ratio greater 

than one-to-one to ensure reductions beyond 

Title IV. Sources may use pre-2010 allowances at 

a one-to-one ratio. This approach preserves the 

viability of the Title IV program and maintains the 

confidence in the market for Title IV allowances. 

There are two model rules for NOX: one 

for an annual NOX trading program and one for 

an ozone season NOX trading program. Each 

program sets a budget for CAIR NOX allowances, 

which represents the number of allowances that 

a state receives and has discretion to allocate. 

The annual NOX trading program provides 

sources with additional allowances from a fixed 

compliance supplement pool, e.g., for early 

reductions. 

The ozone season NOX trading program 

allows sources to use banked allowances from 

the NOX SIP call. NOX SIP call sources that are 

not part of CAIR (e.g., industrial boilers) may 

be brought into the ozone season NOX trading 

program. 

Emissions Monitoring 

Sources are required to comply with 40 CFR Part 

75 emission monitoring provisions. 

Permits 

CAIR permits are required for sources required 

to have a Title V permit and opt-in sources. 

Permits are issued by the state or local 

permitting authority. 

Opt-ins 

States can choose to allow sources to opt in 

to the CAIR trading programs. Opt-ins are limited 

22 
Section B


to boilers, turbines, or other fossil fuel-fired 

combustion devices that vent all emissions 

through a stack and are able to meet Part 75 

emission monitoring and reporting requirements. 

There are two mechanisms that the states can 

use to allow an opt-in, and they may choose one 

or both. The first effectively requires—through 

reduced allowance allocations—a 30 percent 

reduction in emissions, and the second has 

special provisions and requirements for sources 

that repower with qualifying technologies. 

Banking 

The CAIR trading programs allow unrestricted 

banking of allowances. Additionally, banked 

allowances from the NOX SIP call can be used in 

the CAIR ozone season NOX trading program, 

and banked Title IV allowances can be used in 

the CAIR SO2 trading program. There is no flow 

control under CAIR. 

Compliance 

The compliance, or “true-up,” process in the 

CAIR trading programs is somewhat different 

for SO2 than for NOX. For both SO2 and NOX, 

each source must hold in its compliance account 

a tonnage equivalent of allowances at least 

equal to the tonnage of emissions during the 

control period (i.e., a calendar year for SO2 and 

a calendar year or an ozone season for NOX). 

However, in the CAIR SO2 trading program, 

Title IV allowances are used for compliance 

as follows: each pre-2010 vintage allowance 

authorizes one ton of SO2 emissions; each 2010­

2014 vintage allowance authorizes 0.50 ton of 

SO2 emissions; and each 2015 and later vintage 

allowance authorizes 0.35 ton of SO2 emissions. 

In the CAIR NOx trading programs, each NOX 

allowance authorizes one ton of NOX emissions, 

but CAIR ozone season NOX allowances may not 

be used in the CAIR annual NOX trading program 

and vice versa. Additionally, the amount of NOX 

allowances allocated (i.e., the cap) is reduced in 

2015 and beyond, in both the annual and ozone 

season NOX trading programs. 

Flexibility 

CAIR requires affected states to make reductions 

in SO2 and NOX and offers EPA-administered 

trading programs, set forth in model trading 

rules, as one way to achieve the required 

reductions. However, states can choose the 

method for achieving the reductions and do 

not have to use the EPA-administered trading 

programs. States that use these trading programs 

must adopt the relevant model trading rule, with 

only a few changes allowed. In particular, states 

have the flexibility to allocate NOX allowances 

as they choose in these trading programs. EPA 

offers a possible allocation methodology, but 

does not require its use. The CAIR SO2 trading 

program relies on acid rain allowances that are 

already allocated, so states do not have this 

flexibility for SO2. As explained in the opt-in 

section, states do not have to include the opt-in 

provisions in their trading rules. 

B.2 CANADA 

B.2.1 Introduction 

Environmental jurisdiction in Canada is shared 

between the federal and provincial governments. 

The “environment” is not granted as an express 

head of power in the Constitution Act, 1867 

and 1982. Rather, a division of powers set forth 

in sections 91 and 92 of the Constitution Act 

grants both federal and provincial governments 

authority over the environment under diverse 

powers, both legislative and proprietary. For 

instance, provinces have traditionally handled 

electricity generation. Because there is no 

national emissions cap and trading program in 

Canada to date, this section sets forth a view 

of how Canada could establish, legally, a crossborder emissions cap and trading regime with 

the United States. 

The Government of Canada is responsible for 

assuming Canada’s international commitments, 

such as the Canada-U.S. Air Quality Agreement. 

As described below, the Canadian Environmental 

Protection Act, 1999 (the Act or CEPA) 

enables the Minister of the Environment 

23 
Canada-United States Emissions Cap and Trading Feasibility Study 

to regulate toxic air emissions, including 

domestic emissions which may lead to air 

pollution in other countries. The Act empowers 

the federal government to establish a system 

of tradable units when controlling either 

domestic or international air pollution. It also 

allows the Minister of the Environment to enter 

into agreements with provincial governments 

regarding the execution and administration 

of some of these responsibilities. 

B.2.2 Canadian Environmental Protection 

Act, 1999 

B.2.2.1 Toxics Provisions 

CEPA, Part 5, provides the federal government 

with authority to regulate toxic substances. Both 

SO2 and NOX have been included in the Act’s 

List of Toxic Substances, found in Schedule 1 

(ss. 62-64). At present, Environment Canada 

places prohibitions on the production, emission, 

import, and export of many toxic substances, 

including SO2 and NOX, through regulations 

issued under the Act. 8 

Sections 93 and 330 of CEPA provide 

the legal authority for Environment Canada to 

make regulations with respect to the quantity 

or concentration of a toxic substance that may 

be released into the environment, the manner 

and conditions under which it may be released, 

the monitoring, reporting, and testing of such 

releases, and other similar elements. 

Section 326 of the Act, as shown below, 

allows the creation of a system of tradable units 

when regulating toxics: 

326. The Governor in Council may, in the exercise 

of a regulation-making power under section 93, 

118, 140, 167, 177 or 209, make regulations 

respecting systems relating to tradeable units, 

including regulations providing for, or imposing 

requirements respecting, 

(a) the substance, product containing a substance 

or quantity or concentration of the substance 

that is released or activity in relation to which 

the system is established; 

(b) the methods and procedures for conducting 

sampling, analyses, tests, measurements or 

monitoring under the system; 

(c) the description and nature of a tradeable unit, 

including allowances, credits or coupons; 

(d) the baselines to be used for comparison or 

control purposes in relation to the system and 

the maximum limits applicable to the system 

and the manner of determining those baselines 

and maximum limits; 

(e) the conditions related to the creation, 

distribution, exchange, sale, use, variation 

or cancellation of a tradeable unit; 

(f) the creation, operation and management 

of a public registry related to the system; 

(g) the conditions for the use of and 

participation in the system, including 

environmental or temporal limits; 

(h) reports and forms related to the system; and 

(i)	 the maintenance of books and records 

for the administration of any regulation 

made under this section. 

Among other elements, this system may 

determine the nature of the tradable unit, 

conditions required for its use, maximum limits 

applicable to the system, and the creation of a 

reporting scheme and public registry related 

thereto. When creating such an emissions trading 

regime based on the toxics provisions of the Act, 

the Minister of the Environment is required to 

consult with the provinces through the National 

Advisory Committee, established under section 6 

of CEPA. 

For example, persons having charge of listed substances, including nitrogen dioxide (NO2) and SO2, must develop 

emergency preparedness plans under the Environmental Emergency Regulations, SOR/2003-307; airborne release of 

asbestos fibers from a mine or mill is controlled under the Asbestos Mines and Mills Release Regulations, SOR/90-341; 

the production, import, and export of certain ozone-depleting substances are controlled under the Ozone-Depleting 

Substances Regulations, 1998, SOR/99-7; and the airborne release of maximum concentrations of lead particulate 

matter from smelters is regulated by the Secondary Lead Smelter Release Regulations, SOR/91-155. 

24 

8 
Section B


B.2.2.2 International Provisions 

Sections 166-167 of the Act give the federal 

Minister the authority to prevent international 

air pollution and to make regulations to that 

effect. Under these provisions, the Minister is 

first required to consult with the provincial 

government responsible for the source of the 

pollution to determine whether it can prevent 

the contamination under its laws and give the 

province the opportunity to do so. Only if the 

province is unable or unwilling can the federal 

government then act. 

In the event that the province cannot or 

does not control the air pollution, then the 

federal Minister can either request a pollution 

prevention plan from the offending source or 

develop regulations to prevent or control the 

problem. If the Minister proceeds by way of 

regulation, then section 326, as described above, 

provides that when regulating international air 

pollution under section 167, the Minister of the 

Environment may develop a system of tradable 

units. 

B.2.2.3 Equivalency and Administrative 

Agreements 

In the United States, the NOX SIP call program 

uses a model federal rule for states that prefer an 

emissions cap and trade approach for stationary 

sources to achieve required reductions. This 

model rule approach may provide a useful 

example for Canada to understand in the context 

of establishing a cross-border emissions cap and 

trading program where federal and provincial 

governments each have a significant part of the 

responsibility. 

The Department of the Environment Act 

provides that the Minister of the Environment 

may enter into agreements with a province or 

provincial agency to carry out programs for 

which the federal Minister is responsible. The 

preamble to CEPA expressly notes that all 

governments in Canada have authority that 

enables them to protect the environment and 

that environmental protection can be better 

served through cooperative resolution. 

CEPA (s. 10) allows the creation of 

equivalency agreements between the federal 

and provincial governments. Under these 

agreements, Canada suspends the application 

of a federal regulation when the Minister of 

the Environment is satisfied that a provincial 

law is equivalent, with respect to both provisions 

governing the subject matter at hand and 

provisions allowing for the investigation of 

offenses, as found in sections 17 to 20 of the 

federal Act. 9 CEPA expressly contemplates 

equivalency agreements for regulations under 

the toxics provisions of the Act (s. 93), as well 

as for regulations under the international air 

pollution provisions (s. 167). 

By way of example, an equivalency 

agreement was created between Canada and 

Alberta, 10 declaring that four federal toxics 

regulations do not apply in the province. 11 The 

agreement specifically sets forth that the Alberta 

Environmental Protection and Enhancement 

Act establishes testing and approval standards, 

citizens’ requests for investigations, penalties, 

and enforcement mechanisms that are 

equivalent to provisions under CEPA. Alberta 

also undertakes prospectively, when amending 

any of the implicated legislation, not to create 

provisions that are any less stringent than the 

relevant CEPA regulations. 

In order for Canada to proceed with an 

emissions cap and trading program under the 

9	 Section 17 of CEPA allows any individual resident in Canada and over 18 years of age to request the Minister of the 

Environment to investigate an alleged offense. Section 18 requires the Minister to investigate; section 19 requires the 

Minister to report on the investigation; and section 20 allows the Minister to transfer evidence of any suspected offense 

under the Act to the Attorney General. 

10	 An Agreement on the Equivalency of Federal and Alberta Regulations for the Control of Toxic Substances in Alberta, 

1994; Alberta Equivalency Order SOR/94-752. 

11	 Pulp and Paper Mill Effluent Chlorinated Dioxins and Furans Regulations, SOR/92-267; Pulp and Paper Mill Defoamer 

and Wood Chip Regulations, SOR/92-268; Secondary Lead Smelter Release Regulations, SOR/91-155; and Vinyl Chloride 

Release Regulations, 1992, SOR/92-631. 

25 
Canada-United States Emissions Cap and Trading Feasibility Study 

equivalency provisions of section 10, each 

province would be required to have legal 

provisions in force that are equivalent to a 

federal regulation made under CEPA as well 

as provisions allowing for the investigation of 

offenses, as found in sections 17 to 20 of the 

federal Act. 

The Act also provides for administrative 

agreements (s. 9) whereby Environment 

Canada may enter into accords with provincial 

governments with respect to the administration 

of the Act. Unlike the equivalency provisions of 

section 10, an administrative agreement under 

CEPA does not require that a province have 

legislation equivalent to the federal regulations 

in question, nor does the agreement suspend 

application of the federal law. Rather, it enables 

a provincial government to administer the 

federal program that is the subject of the 

agreement. 

These cooperative mechanisms are typically 

upheld by the courts as a way of minimizing 

either the inefficiencies or the controversy 

caused by overlapping environmental 

jurisdiction. 

B.2.3 Local Air Quality Requirements 

in Provinces 

While emissions cap and trading programs can 

reduce emissions from sources participating, 

they do not replace provincial (or municipal) 

industrial facility-specific requirements that 

provincial governments put in place to ensure 

local air quality. 

All Canadian provinces have ambient air 

quality criteria for SO2 and NO2. These criteria 

are used to monitor air quality and may be relied 

upon to set emission limits for new sources. 

Provincial permitting, however, is often based 

upon ambient air quality standards instead of on 

maximum emission limits from a given source. 

The term limits on operating permits also vary 

from province to province. Provincial emission 

permits typically include monitoring and 

reporting requirements as well as compliance 

and enforcement measures. 

B.2.3.1 Ontario 

Industrial facilities above a minimum threshold 

that discharge airborne contaminants are 

required to obtain a certificate of approval under 

the Ontario Environmental Protection Act. The 

approvals process specifies maximum emission 

concentrations. Regulation 346 sets point of 

impingement standards for air quality, designed 

to protect public health from local air quality 

effects. Approvals are issued for an indefinite 

duration, though significant modifications to 

a facility that result in additional emissions or 

a change in the nature of the emissions will 

require a new approval. Facilities are required 

to monitor and report annual and smog season 

total emissions in conformity with Regulation 

127/01. This latter regulation covers the 

quarterly reporting of SO2 and NOX. 

Ontario has an SO2 and NOX emissions 

reduction and trading program under Regulation 

397/01, in force since December 31, 2001, 

issued under the provincial Environmental 

Protection Act. The regulation allocates 

emission allowances to designated emitters 

and establishes a trading and credit regime. Until 

recently, only Ontario Power Generation was 

covered by this regulation at six coal- or oil-fired 

electricity generating facilities. In 2004, the 

program was expanded to cover all generators 

that have over a 25 MW capacity, that sell more 

than 20,000 megawatt hours (MWh) annually, 

or that emit more than a threshold amount of 

nitric oxide (NO) and SO2. The Ontario Ministry 

of the Environment will lower the number 

of allowances currently allotted to Ontario 

Power Generation and distribute new 

allowances to the incoming emitters. A detailed 

description of the program can be found at 

http://www.ene.gov.on.ca. 

26 
Section B


B.2.3.2 Quebec 

The Loi sur la qualité de l’environnement (LQE) 

governs activities within the province that have 

adverse environmental impacts. The LQE defines 

activities having such adverse impacts as those 

involving construction, modification, or increase 

in production that will adversely affect the 

environment by emitting waste or airborne 

contaminants. Prior to engaging in such activities, 

a proponent must obtain a certificate of approval. 

Some exemptions exist for facilities operating 

below specified thresholds. 

A regulation under the LQE, the Règlement sur 

la qualité de l’atmosphère (Atmospheric Quality 

Regulations, Q-2, r.20), provides maximum 

permissible ambient air concentrations for both 

SO2 and NO2, as well as maximum permissible 

stack emission levels of SO2 and NO2 for fossil 

fuel combustion facilities. In general, these 

standards are point of impingement and opacity 

standards. 

B.2.3.3 British Columbia 

The Ministry of Land, Water and Air Protection 

administers the new Environmental Management 

Act, which permits industrial activities 

discharging contaminants into the environment. 

Provincial air quality objectives and standards 

govern the levels of discharge that are deemed 

permissible. Air quality is monitored through a 

variety of opacity and stack emission tests, set 

forth in the British Columbia Field Sampling 

Manual. 

The oil and gas industry is covered by sectorspecific statutory emission limits and is governed 

by the Oil and Gas Waste Regulations. 12 

Within the Greater Vancouver region, the 

permitting process has been delegated to the 

Greater Vancouver Regional District. The 

municipal government has created bylaws to 

designate those activities subject to or exempt 

from the permitting process. 13 The Vancouver 

permitting process establishes limits on the 

quantity and frequency of air emissions, requires 

monitoring and reporting of six common 

contaminants (CO, O3, NO2, SO2, PM10, and 

PM2.5), 14 and sets fees, charged as part of the 

permitting process, as an incentive to reduce 

emissions. 

B.2.3.4 Alberta 

Emission controls, monitoring, and reporting 

requirements in Alberta are governed by 

the Approvals and Registrations Procedure 

Regulation under the Alberta Environmental 

Protection and Enhancement Act. Activities 

requiring approval are categorized into five 

different groups, designated in the Activities 

Designation Regulation. Activities producing 

air emissions are listed in Division 2 of the 

regulation. The approvals process, which covers 

major industrial point sources and the electric 

power generation sector, represents roughly 

80 percent of total provincial NOX emissions 

and 60 percent of total provincial SO2 

emissions. 15 In June 2001, Alberta created 

minimum emission standards for new coal-fired 

power plants. 16 

Alberta has provincial Ambient Air Quality 

Guidelines for both NO2 and SO2 and follows 

the Canada-wide Standards for ground-level 

ozone. Consistent with the federal monitoring 

guidelines, the province monitors ambient air 

quality, and the data are then collected by the 

Clean Air Strategic Alliance. The province has 

recently undertaken a significant feasibility study, 

12 The Greater Vancouver Regional District (GVRD) also has its own municipal permitting requirements for the Vancouver 

district. Although it follows the same emission standards as the province, the GVRD aims to limit the number of facilities 

operating within its boundaries, thereby lowering overall emissions for this populated area. 

13 Air Quality Management Bylaw, No. 937, 1999. 

14 The GVRD has adopted Environment Canada’s Monitoring Protocol, EPS 1/PG/7. 

15 Alberta Environment Emission Trading Project, Major Feasibility Study, Preliminary Analysis and Discussion Document, 

Appendix C, March 2003, prepared by Cheminfo Services Inc. for Alberta Environment, pp. 63-64. 

16 Alberta Emission Standards for New or Expanded Coal-Fired Plants. 

27 
Canada-United States Emissions Cap and Trading Feasibility Study 

exploring the potential for an air emissions 

trading program in Alberta. 

B.2.3.5 Saskatchewan 

The Saskatchewan Clean Air Act requires 

operators of industrial sources, incinerators, 

or fuel-burning equipment to hold a provincial 

permit, with the exception of the oil and gas 

industry, which is regulated by the Oil and Gas 

Conservation Act, and the mining industry, 

which is governed by the Environmental 

Management and Protection Act. The permitting 

process includes compliance with the provincial 

Clean Air Regulations, which establish ambient 

air quality standards. Air quality is measured 

through a variety of stack sampling, point 

of impingement samples, and modeling. 

Modifications made to an industrial source 

that change its emissions require an application 

for a new permit. 

B.2.3.6 Manitoba 

The Manitoba Environment Act and its 

regulations govern the permitting of facilities 

that produce air emissions. The approvals 

process is set forth in the Act and the Licensing 

Procedures Regulation, while the classes of 

industrial facilities that are subject to the Act 

are contained in the Classes of Development 

Regulation. As with many other provinces, the 

oil and gas sector is separately governed by the 

Minister of Industry, Trade and Mines under the 

Oil and Gas Act. 

Permissible air emissions are set by the 

provincial Ambient Air Quality Criteria and 

are measured through modeling and point of 

impingement analysis. A schedule lists maximum 

permissible time-based pollutant concentrations 

within the province. Each contaminant is 

classified as either an objective or a guideline, 

depending upon several factors, the objective 

classification being more stringent. Maximum 

concentrations of NO2 and SO2 are both listed 

as objectives. 

B.2.3.7 New Brunswick 

Provincial approval of operations that discharge 

contaminants is administered under the Clean 

Environment Act and the Clean Air Act and 

its regulations. Air quality objectives for SO2 

and NO2 are set under the Clean Air Act. 17 The 

type of approval required is determined by the 

volume of emissions released by a facility, with 

Class 1 sources having the greatest emissions. 

The electricity generation sector generally falls 

within Class 1. These approvals contain a formal, 

public participation component, including a 

provision allowing anyone affected by an 

approval to appeal the decision to the Minister 

of the Environment. Major modifications to an 

existing facility require a new permit. 

B.2.3.8 Nova Scotia 

The Nova Scotia Environment Act and its 

regulations set forth the requirements for 

approvals of facilities that produce air emissions. 

The approvals process is administered under 

the Approvals Procedures Regulations, and 

the classes of industrial facilities that require 

approval are listed in the Activities Designation 

Regulations. The Air Quality Regulations set 

maximum permissible concentrations for certain 

contaminants, including SO2 and NO2. Facilities 

are required to show how they will comply 

with emission limits, and monitoring and 

reporting of performance may be required here. 

Major modifications require an application for 

approval. 

B.2.3.9 Newfoundland and Labrador 

Under the Environmental Protection Act, 2002 

and its regulations, 18 industrial facilities that 

release regulated substances must obtain 

approval from the Minister of the Environment. 

17	 Note that the New Brunswick Clean Air Act has an Administrative Penalties Regulation, which specifies the offenses 

under the Act for which administrative penalties between $200 and $5,000 per day may be imposed. 

18	 Environmental Protection Activity Approval Regulations and Air Pollution Control Regulations. 

28 
Section B


The regulations contain maximum allowable 

concentrations of the listed substances. 

Emissions from stationary sources are measured 

by maximum allowable concentrations at a point 

of impingement. Modifications to the activity 

require a new approval. In issuing a permit 

under the Act, the Minister may require pollution 

prevention or rehabilitation plans or apply more 

stringent standards in environmentally 

sensitive areas. 

B.2.3.10 Prince Edward Island 

The provincial Environment Protection Act 

and its regulations govern the issuance of air 

quality permits for fuel-burning equipment and 

industrial sources of air emissions. Provincial 

Ambient Air Contaminant Ground Level 

Concentration Standards are used for permitting. 

Compliance with air quality standards is 

determined through modeling and point of 

impingement measurements. 

B.3 SUMMARY 

In the United States, as a result of experience 

in emissions cap and trading gained under 

Title IV, the OTC, and the NOX SIP call, several 

of the legal prerequisites for possible crossborder trading with Canada are already in place 

(e.g., strict monitoring and an infrastructure 

for collecting emissions data, implementing 

allowance allocations and trading, and 

determining compliance). However, it appears 

that additional U.S. legislative and/or regulatory 

action may be necessary to authorize crossborder SO2 and NOX emissions cap and trading 

programs. 

In Canada, the legal authorities exist that 

could provide the basis for developing crossborder trading. Federal and provincial 

governments have legal responsibilities in 

air quality management and would need to 

participate in the development of any crossborder emissions cap and trading program. 

As well, in Canada, regulations would be 

required to create mandatory emission reduction 

caps in the electricity sector in addition to 

regulations that create the basis for cross-border 

trading, including elements such as monitoring 

and reporting. 

One area that remains to be considered is 

the recognition of Canadian allowances under 

U.S. law and U.S. allowances under Canadian 

law. Currently, affected units in the United States 

cannot use external (i.e., non-U.S.) allowances 

to comply with Title IV and SIP obligations. 

Should Canada and the United States decide 

to pursue cross-border trading of SO2 and 

NOX allowances, Canadian and U.S. allowances 

will need to be given equal legal status in both 

countries so that either could be exchanged 

freely and used for compliance. Such recognition 

would be based on consistency across the 

two countries in key areas such as monitoring, 

compliance, and banking and may require 

changes in domestic legislation coupled with 

international legal instruments by which 

Canada and the United States formally recognize 

certain elements of the other nation’s program 

as equivalent to enable international trading of 

emission allowances. 

29 

Section C


APPLICABILITY 

An emissions cap and trading system is 

supported by a legal framework in which 

the coverage (the domain of regulated activities) 

is precisely defined. Usually, this includes a list 

of the types of sources (e.g., power generation, 

industrial boilers), de minimis thresholds 

(capacity, input, output, and/or emissions rate), 

and pollutants covered. 

This section addresses the issue of which 

sectors are well matched to a cross-border 

emissions cap and trading program. Section C.1 

provides an overview of the technical and 

administrative considerations for including or 

excluding sources. Section C.2 presents an 

overview of sulfur dioxide (SO2) and nitrogen 

oxide (NOX) sources in the United States and 

Canada. Section C.3 discusses emission 

reduction options available for different sources, 

and Section C.4 describes voluntary opt-in 

provisions. 

C.1 OVERVIEW OF 

PRINCIPLES 

Cap and trade can be an effective way to control 

emissions from some sectors. The United States 

has achieved very good results from its cap and 

trade programs for controlling SO2 emissions 

from electric power plants and NOX emissions 

from electric power plants and industrial boilers. 

However, for various practical reasons, not all 

sectors are as well suited to such a program. In 

addition, even within an otherwise appropriate 

sector, there may be certain types of sources that 

should be excluded for administrative or 

technical reasons. 

“Applicability,” as discussed in this section, 

refers to the technical and administrative 

considerations that need to be addressed to 

determine whether a particular kind of source 

participates in an emissions cap and trading 

program. 

Based on the U.S. experience in determining 

the applicability of the SO2 and NOX emissions 

cap and trade programs in the electric power 

and industrial sectors, the key technical 

considerations include the contribution to 

emissions and “potential for leakage,” 

measurement capabilities, availability of costeffective control options, and administrative 

burdens. These considerations are discussed in 

more detail below. 

C.1.1 Contribution to Emissions and Potential 

for Leakage 

Sources included in a cap and trading program 

should represent a significant portion of 

emissions in order to appropriately and 

adequately address public health and 

environmental risks associated with SO2 and 

NOX emissions. Further, it is important for the 

regulating authority to examine and, if necessary, 

address emission sources that cannot feasibly be 

included in the cap and trade program, but that 

could receive shifts in production from emission 

sources constrained by the cap. Such shifts of 

production from affected sources to unaffected 

sources, more commonly called “leakage,” could 

undermine the environmental benefits of the 

cap. 

C.1.2 Ability to Measure Emissions 

Sources that participate in a rigorous cap and 

trading program must have the ability (or 

capability) to monitor their emissions within a 

defined level of certainty and comprehensiveness. 

For example, emissions that are vented to the 

atmosphere through a stack can be measured 

with a continuous emission monitoring system 

(CEMS) to produce accurate, verifiable emissions 

data. 

C.1.3 Availability of Cost-Effective Control 

Options 

Sources included in the program should have 

a wide range of costs of compliance due to wide 

31 
Canada-United States Emissions Cap and Trading Feasibility Study 

economies of scale, variations in compliance 

options, and other factors to ensure their 

ability to achieve the reduction goal. Generally, 

variation in abatement costs promotes 

competition among control options, stimulates 

innovative technologies, helps lower compliance 

costs, and leads to a more robust trading market. 

C.1.4 Administrative Burdens 

C.1.4.1 Number and Size of Sources 

An important criterion in defining the 

applicability or “mandatory participation” in 

an emissions trading system (or the domain of 

regulated activities) is the minimum size of the 

plant or the unit. This de minimis threshold 

determines what small units would be exempted 

from mandatory participation. The threshold 

also has an implication for the total number of 

sources in the program. 

The determination of a de minimis threshold 

should take into account, on one hand, 

the emission monitoring costs and other 

administrative burdens associated with 

participation in the system and, on the other 

hand, the environmental and economic 

advantages of inclusion. The de minimis threshold 

should be low enough to minimize leakage. A 

preliminary and ongoing analysis should examine 

whether units excluded from the program thereby 

incur an economic advantage. For instance, the 

U.S. Acid Rain Program captured the vast majority 

of emissions using an applicability threshold of 

25 MW for existing units. Many units below this 

threshold were peaking units, or units used to 

meet requirements during the periods of greatest 

or peak load on the system. In other words, these 

smaller excluded units were not in competition 

with the larger included ones, and there was little 

risk of leakage or increased production shifting 

to smaller units from larger ones. In addition, 

smaller units generally were not significant 

emitters in this case. 

C.1.4.2 Simplicity 

It is important to avoid overly complex 

applicability criteria. Complex criteria make it 

more difficult and costly for sources and for the 

regulating authority to determine which sources 

the program covers. Complex criteria also 

increase the likelihood of loopholes that may 

allow significant sources in the same industrial 

sector to avoid inclusion in the program. To 

this end, the threshold(s) for determining 

source applicability should be based on source 

characteristics that generally remain constant, 

such as capacity or potential to emit, rather than 

characteristics that could vary from year to year, 

such as mass emissions or fuel use. Experience 

has shown that it is best to minimize changes in 

an individual source’s applicability status. This 

will ease administration of the program and 

provide greater certainty to sources for planning 

and implementation. 

However, if the characteristics of the source 

excluded from the program change so that the 

source is now essentially the same as other 

sources that are already in the program, it may 

be desirable to require that source to enter the 

program. This approach may prevent a source 

from avoiding the program by only temporarily 

adopting characteristics that would exclude it 

from the program. 

C.1.5 Geographic Scope 

An emissions cap and trading program should 

be applied at a scale and scope appropriate 

to achieve the environmental goal. The 

development of the U.S. Acid Rain Program as 

a nationwide program is a case in point. The 

evidence of long-range transport of SO2 and NOX 

emissions from the Midwest to the Northeast 

suggested that emission impacts could extend 

well beyond the area where they originated. 

Damage from acid deposition was also evident, 

particularly in the Northeast. In western regions, 

deposition levels were below what would cause 

widespread concern, with the exception of highelevation alpine lakes in certain areas. However, 

32 
Section C

rapid growth projections suggested that 

emissions would be rising in the future. 

Forecasts and trends, coupled with the 

knowledge that western ecosystems were 

considered sensitive to acid rain, pointed to 

the need to include the West in the Acid Rain 

Program. Furthermore, SO2 presented not 

only public health and environmental impact 

concerns, but also visibility concerns. Limiting 

the growth of acid rain precursors supported 

efforts by groups such as the Grand Canyon 

Visibility Commission to mitigate visibility 

impacts. Finally, the electric power sector 

operates on a continental, national, and regional 

grid. The ability to shift load (and emissions) 

to potentially excluded sources always needs to 

be considered in placing controls on this sector. 

All these reasons contributed to defining the 

geographic scope of the U.S. acid rain emissions 

cap and trading program. 

C.1.6 Equity 

As mentioned above, the regulating authority 

should give careful consideration to the 

economic competitiveness of businesses and the 

effect on markets of including or excluding 

certain industries from a trading system. Fairness 

relative to emission reduction potential is 

another consideration for the regulating 

authority in weighing the feasibility of an 

emissions cap and trading program. 1 

C.2 SO2 AND NOX SOURCES 

AND DISTRIBUTION OF FUEL 

TYPES 

As discussed previously, SO2 and NOX are 

pollutants that cause acid rain and numerous 

other human health and environmental impacts. 

Furthermore, both can be transported over long 

distances, expanding the potential area for 

impacts far beyond the source area where they 

were emitted. One of the major causes of SO2 

and NOX emissions is the combustion process 

(burning of fuels). 2 

C.2.1 National Overview of Sources 

C.2.1.1 United States 

In 2002, as stated in Section A on Air Quality, 

U.S. SO2 emissions totaled some 15.8 million 

tons. The primary source of these SO2 emissions 

(~70 percent) is fuel combustion from electric 

generating units (EGUs) due to burning of sulfurcontaining fuels, such as coal and oil. Figure A-9 

(in Section A) shows the contribution to 

emissions from various sources in the United 

States according to the most recent data from 

the U.S. National Emissions Inventory (NEI). Fuel 

combustion by industrial sources accounts for 

15 percent of total SO2 emissions. 3 

The two primary sources of the 21.2 million 

tons of NOX emissions in the United States in 

2002 are transportation (on-road combustion) 

and EGUs. As shown in Figure A-9, these 

two sources represent three-quarters of total 

NOX emissions in 2002. EGUs account for 

approximately 22 percent of these total NOX 

emissions. Industrial source fuel combustion 

accounts for some 14 percent of total NOX 

emissions. 

In the United States, metal smelting and 

other industrial processes release significant, 

but relatively smaller, quantities of SO2 and 

NOX. 4 Industrial processes include emissions 

that are produced from the industrial process 

itself and are not directly a result of energy 

consumed during the process. These nonenergy-related industrial activities include, for 

example, iron and steel production and cement 

manufacturing. According to the most recent 

1	 U.S. EPA, “Tools of the Trade,” http://www.epa.gov/airmarkets/international/tools.pdf. 

2	 Sulfur is released from the fuel source and combines with oxygen in the air to form SO2. Similarly, during the 

combustion process, nitrogen in the atmosphere combines with oxygen and water to form several NOX compounds. 

3	 The U.S. National Emissions Inventory with average annual emissions data for SO2 and NOX from 1970 to 2002 is 

available at http://www.epa.gov/ttn/chief/trends/index.html. 

4	 Ibid. 

33 
Canada-United States Emissions Cap and Trading Feasibility Study 

ambient air pollutant trends data from the 

NEI (2002), industrial processes as a whole 

contribute approximately 9 percent of SO2 

emissions, while specific processes such as 

metal processing account for approximately 

2 percent of total 2002 SO2 emissions. Similarly, 

industrial processes as a whole constitute 

5 percent of 2002 NOX emissions. 

C.2.1.2 Canada 

In 2002, as stated in Section A, Canadian SO2 

emissions totaled some 2.6 million tons. 5 Figure 

A-9 shows the contribution to emissions from 

various sources. In contrast to the United States, 

the primary single source of SO2 emissions 

(~30 percent) in Canada is non-ferrous mining 

and smelting. Fuel combustion from EGUs due 

to burning of sulfur-containing fuels, such as 

coal, is the second largest single source of SO2 

emissions (~25 percent). Other industrial sources 

account for 40 percent of total SO2 emissions. 

In Canada, the primary source of the 

2.8 million tons of NOX emissions is 

transportation (~60 percent). 6 As shown in 

Figure A-9, fossil fuel combustion from the 

electricity sector is one of the largest stationary 

sources of NOX (~11 percent). Various industrial 

sectors also contribute to significant NOX 

emissions. As a whole, these sectors account 

for approximately 25 percent of Canada’s total 

emissions. 

C.2.2 Electricity Generating Sector 

Fuel type plays a key role in the amount of SO2 

and NOX emissions generated during combustion 

to generate electricity. For example, emissions 

from uncontrolled coal-fired units are much 

greater than emissions from natural gas-fired 

units per unit of electricity produced. 

C.2.2.1 United States 

Coal-based fuel combustion from electric utilities 

is the largest single source of SO2 emissions in 

the United States. In 2002, electric utilities in the 

United States produced some 2,549 terrawatt 

hours (TWh) of electricity, with slightly more 

than 50 percent coming from coal. 7 Electric 

utilities accounted for 62 percent of electricity 

generation, while nonutility generators 

accounted for the remaining generation. Most 

power plants are located east of the Mississippi 

River in the United States. Figure C-1 shows the 

mix of fuels used to generate electricity in each 

state. According to the map, the fuel mix varies 

by region. In the Midwest, most generation is 

coal-based. In contrast, the mix of fuels used to 

generate electricity in Texas is approximately 

50 percent gas, 37 percent coal, and 10 percent 

nuclear (with the remaining 3 percent from other 

sources). The U.S. fuel mix is not projected to 

change significantly over the next 15 years. 8 

The mix of U.S. fossil fuel-fired EGUs at 

electric utilities consists primarily of steam 

units, turbines, and combined cycle units. 

Among Acid Rain Program units, 9 52 percent 

are steam units, while 30 percent are gas-fired 

turbine units. The remaining units consist of 

combined cycle units (16.3 percent) and oil-fired 

turbines (1.6 percent). More information 

on facility attributes is available on the U.S. 

Environmental Protection Agency’s (EPA) 

Clean Air Markets Division (CAMD) Web site 

at http://cfpub.epa.gov/gdm/. Units range 

in size from 25 MW to 1,300 MW. 

5 Preliminary data from Environment Canada.


6 Ibid.


7 Total electricity generation in the United States was 3,858 TWh from all energy sources. Energy Information Administration


(2002). “Electricity Quick Stats,” updated 01/31/2005, http://www.eia.doe.gov/neic/quickfacts/quickelectric.htm, 

accessed 1/31/05. 

8	 U.S. EPA (2004). “Technical Support Document: Analysis in Support of the Clean Air Interstate Rule Using the Integrated 

Planning Model,” http://www.epa.gov/air/cleanairinterstaterule/pdfs/tsd.pdf, May 28, 2004, accessed 12/16/04. 

9	 These percentages are based on data provided by the Emissions Monitoring Branch of the Clean Air Markets Division (CAMD). 

34 
Section C


Figure C-1 Fraction of Electric Generation by Fuel Type (2000) 

Year 2000 Generation (MWh) 

380,000,000 

190,000,000 

38,000,000 

Coal 

Oil 

Gas 

Nuclear 

Hydro 

Biomass 

Geothermal 

Wind 

Source: EPA, http://www.epa.gov/cleanenergy/egrid/samples.htm#egridmaps 

C.2.2.2 Canada 

In Canada, a large proportion of fuel combustion 

is for the generation of electricity. Electric 

utilities generate over 90 percent of the nation’s 

total electricity, while the remainder is generated 

at various industrial plants, primarily for on-site 

use. In 2002, 580 TWh of electricity was 

generated. 10 Figure C-2 illustrates the mix of fuel 

types used to generate electricity in each region. 

At the national level, electricity generation in 

Canada is dominated by hydroelectricity, which 

produces 60 percent of the nation’s electricity. 

While the combustion of fossil fuels for electricity 

generation accounts for only a quarter of 

Canada’s overall total, in certain regions fossil 

fuels play a prominent role. 

In Canada, approximately three-quarters of 

fossil fuel-fired electricity is generated from the 

combustion of coal. The five major coal-burning 

provinces are Alberta, Saskatchewan, Ontario, 

New Brunswick, and Nova Scotia. Additional 

generation comes from oil and orimulsion in the 

Atlantic and northern regions and from natural 

gas in the west. 

In Canada, the mix of fossil fuel-fired EGUs at 

electric utilities is composed of steam units, gas 

turbines, and internal combustion units. Steam 

units, at over 85 percent, 11 make up the largest 

percentage by capacity of these fossil fuel-fired 

units. Within the 12 major electric utilities 

across Canada, there are 35 steam plants with 

approximately 100 active boilers. These units 

range in size from 1.5 MW to 510 MW, with an 

average size of approximately 240 MW. Many of 

these units fire bituminous, subbituminous, or 

lignite coal. There are also some oil-, gas-, and 

orimulsion-fired units. 

Combustion turbines (as simple or combined 

cycle) make up 12 percent 12 of the capacity from 

electric utilities. There are approximately 100 

units ranging in size from 1 MW to 110 MW, 

with an average size of 40 MW. These units 

combust oil and natural gas. The choice of fuel 

is generally dependent upon the region. Over 

90 percent of the capacity of oil-fired combustion 

turbines is in Quebec and the Atlantic provinces. 

These units, located in the east, combust either 

light fuel oil or diesel. Typically, these units are 

10 Statistics Canada (2004). “Electric Power Generation, Transmission and Distribution, 2002,” Catalogue no. 57-202-XIB.


11 Statistics Canada (2001). “Electric Power Generating Stations, 2000,” Catalogue no. 57-206-XIB.


12 Ibid. 


35 
Canada-United States Emissions Cap and Trading Feasibility Study 

Figure C-2 Total Electricity Generation 

by Fuel Type, 2002 

Source: Statistics Canada (2004). “Electric Power Generating 

Stations, 2002,” Catalogue no. 57-206-XIB; Statistics Canada 

(2003). “Report on Energy Supply-Demand in Canada, 2002,” 

Catalogue no. 57-003-XIB. 

utilized for peaking or backup power and not 

for base load generation, generally operating 

fewer than 100 hours per year. As a result, their 

overall contribution to generation is extremely 

small. For example, in Atlantic Canada, these 

plants contribute to less than 1 percent of the 

region’s generation. 

The majority of natural gas-fired combustion 

turbines (over 95 percent by capacity) are located 

in Ontario, Saskatchewan, and Alberta. While 

some of these units may be used for base load 

generation, they also contribute only a small 

amount of the total generation. For these 

three provinces, electricity production from gasfired turbines is less than 10 percent of each 

province’s total generation. 

The remaining 3 percent 13 of capacity 

of fossil fuel-fired electric utilities comprises 

internal combustion units, which mainly 

combust oil, but natural gas and waste gas are 

also used. These will not be considered further 

in this discussion due to their minor impact 

on air emissions and the small size of the units 

(typically <1 kilowatt). 

C.2.3 Other Industrial Sectors 

As discussed in Section C.2.2.1, the U.S. SO2 

emissions cap and trading program targets 

the primary and largest contributing sector to 

emissions: the electric power sector. This 

maximizes coverage of emissions and also 

ensures efficiency, given the variation in 

abatement costs of different units. 

Because both U.S. emissions cap and trading 

programs focus on the electric power sector, 

that is a logical place to begin studying the 

feasibility of a cross-border U.S.-Canada 

emissions cap and trading program. However, 

industrial sectors that are important contributors 

of SO2 and NOX emissions may be suitable for 

inclusion in the kind of cap and trading program 

being contemplated by this study. 

The following discussion does not imply 

that industrial sectors ought or ought not to 

be included. Though they are large stationary 

sources that contribute to emissions, many 

other economic, environmental, and social 

considerations beyond the scope of this study 

would need to be explored. 

C.2.3.1 United States 

According to data collected by EPA, some 

340 industrial sources in the United States are 

affected under the NOX Budget Trading Program. 

These largely include industrial boilers (48 percent 

of industrial sources), but also petroleum 

refineries (16 percent), pulp and paper mills, 

cement kilns, and iron and steel mills. In 2004, 

these sources represented nearly 13 percent of 

all State Implementation Plan (SIP) sources and 

approximately 7 percent of the NOX emissions 

under the SIP call. 14 

13	 Ibid. 

14	 This number represents the most current numbers in the EPA-CAMD database as of June 2005 (updated from U.S. EPA 

(2003). “NOX Budget Trading Program: 2003 Progress and Compliance Report,” p. 10). Note: The Emissions Monitoring 

Branch of EPA’s CAMD defines industrial sources as industrial boilers not classified under the source category of Electric 

Utility, Small Power Producer and Cogeneration, or that meet State industrial source classification. 

36 
Section C

C.2.3.2 Canada 

Industrial Boilers 

It is estimated that there are 350,000 to 

600,000 nonutility boilers in Canada. 15 These are 

found in several different industries, including 

pulp and paper, chemical, oil refining, iron and 

steel, mining, and commercial and institutional 

sectors. Of these, approximately 200 to 400 

have maximum rated heat input capacities 

greater than 250 million British thermal units 

(mmBtu) 16 per hour (the minimum size for 

inclusion in the U.S. NOX Budget Trading 

Program). 17 These units are widely dispersed 

across the country in relation to the industrial 

sector in which they belong. For example, there 

are a large number of pulp and paper boilers 

in British Columbia. 

It is difficult to ascertain the SO2 and NOX 

emission contributions of industrial boilers 

within the given size range (>250 mmBtu/hour). 

Further information is required on this sector to 

determine its feasibility for inclusion in a crossborder emissions cap and trading program. 

Smelters 

As mentioned previously, Canadian smelters 

play a significant role in Canada’s SO2 emissions. 

These facilities are primary producers of cobalt, 

copper, lead, nickel, and zinc, along with a 

variety of co-product metals. There are 12 base 

metals metallurgical complexes located in British 

Columbia, Alberta, Manitoba, Ontario, Quebec, 

and New Brunswick. 

The smelters release approximately 30 

percent of the nation’s SO2 emissions. These 

emissions are regional and play a major role 

in Manitoba, Ontario, and Quebec. 

Industrial boilers exist at smelter facilities 

in Canada, but they play a minor role in the air 

emissions produced by the facilities as a whole. 

The industrial processes used in the extraction 

and refining of base metals are the dominant 

contributors to air emissions. These processes 

are specific to the type of metal produced. 

Fugitive emissions from smelters—that is, 

emissions not directly released through a stack— 

contribute to total emissions. This may lead to 

difficulties within an emissions trading system 

(e.g., continuous monitoring of emissions). More 

information is required on smelter emissions to 

determine the feasibility for inclusion in a crossborder emissions cap and trading program. 

Cement Manufacturing 

The cement manufacturing industry has also 

been considered for inclusion in an emissions 

trading system, since this sector is one of 

Canada’s top 10 industrial sectors for the 

emission of both NOX and SO2 and it is also a 

sector whose emissions can be monitored at the 

unit level with CEMS. (According to EPA, three 

cement kilns in New York successfully participate 

in the U.S. NOX Budget Trading Program under 

the NOX SIP call.) 

In Canada, the cement manufacturing sector 

comprises seven companies operating 16 plants 

with a total of 25 operational kilns. Emissions 

from this sector are regional and play a major 

role in British Columbia, Alberta, Ontario, and 

Quebec. 

While emissions are generated in all steps 

of the cement manufacturing process, the 

combustion of fuel in the kiln makes up 75 

percent of the total emissions from this sector. 

One factor influencing the amount of emissions 

is the fuel type. Several types of fuel are used in 

the cement industry: coal and petcoke account 

for approximately 60 percent of the total fuel 

15 Working Group #1 for the Multistakeholder Steering Committee for Initiative N306 (1996). “Background Document for 

the Development of a National Guideline for NOX Emissions from New or Modified Commercial/Industrial Boilers and 

Process Heaters,” p. A-1. 

16 One Btu ≈ 1.06 kilojoules. 

17 Based on estimates from 1) Jaques Whitford (2004). “Industrial Boilers Database for Boilers > 250 mmBtu/hr” and 

2) Working Group #1 for the Multistakeholder Steering Committee for Initiative N306 (1996). “Background Document for 

the Development of a National Guideline for NOX Emissions from New or Modified Commercial/Industrial Boilers and 

Process Heaters.” 

37 
Canada-United States Emissions Cap and Trading Feasibility Study 

consumed; other fuels include natural gas, 

petroleum products, and wastes. 

A kiln’s process type—wet or dry—also 

influences the amount of emissions. The addition 

of preheaters and precalciners represents more 

recent technologies that have increased process 

control and plant efficiency, thereby reducing 

fuel consumption. The dry process has become 

more prevalent than the traditional wet process; 

in Canada, only one wet plant (with two kilns) 

still operates. Of the 23 remaining units, 12 are 

conventional dry kilns, five are preheater kilns, 

and six are preheater-precalciner kilns. 

C.3 EMISSION REDUCTION 

OPTIONS FOR SO2 AND NOX 

Sources participating in an emissions cap and 

trading program can employ one or more of 

the following alternatives for meeting emission 

requirements: reducing on-site emissions, buying 

excess allowances from other sources that have 

allowances to sell, or using banked allowances 

from a previous year. This section describes the 

options that may be available to different types 

of sources for achieving on-site emission 

reductions. 

Typically, sources have two types of options 

available for controlling emissions: primary 

measures and postcombustion controls. Primary 

measures include: 

•	 Process optimization, where the emphasis 

is on increased energy efficiency and 

productivity. 

•	 Selection of different fuels or raw 

materials with lower emission generating 

characteristics. 

•	 Combustion controls, where the emphasis 

is on reducing emissions formation. 

Postcombustion options involve installation 

of emission control technologies that remove 

pollutants from the flue gas stream, such 

as scrubbers used for SO2 removal. Often, 

source facilities use a combination of both 

primary and postcombustion techniques. 

Many factors, including age, size, usage, 

and location of an existing plant, require 

consideration when selecting one of these 

options. 

C.3.1 Electric Generating Units 

One of the most common methods for electric 

utility steam plants to reduce SO2 and NOX 

emissions at the source is to install pollution 

control equipment. The use of low-NOX burners 

and/or the use of overfire air are common 

combustion modification technologies for 

NOX control on boilers firing a variety of fuels. 

On gas turbines, dry low-NOX combustors, 

water injection, or steam injection systems 

are used to reduce NOX. The most commonly 

used postcombustion technology options include 

wet or semidry flue gas desulfurization (FGD) 

systems for SO2 removal and selective catalytic 

reduction (SCR) or selective noncatalytic 

reduction (SNCR) for NOX removal. FGD 

generally reduces SO2 emissions by 90 to 

95 percent depending on the technology, while 

SCR and SNCR systems are typically capable of 

reducing NOX emissions by more than 90 percent 

and 30 to 60 percent, respectively, depending 

on unit and fuel characteristics. 18 

Other options that are available for reducing 

on-site emissions include: 

•	 Fuel blending. 

•	 Fuel switching—from high-sulfur to lowersulfur fuel; from coal or oil to natural gas. 

•	 Repowering—replacing a boiler in a steam 

plant with a gas turbine and heat recovery 

steam generator train, or more efficient IGCC. 

•	 Improving energy and operational efficiency, 

which will reduce emissions of both SO2 

and NOX. 

A retrospective look at compliance strategies 

by EGUs under the U.S. Acid Rain Program 

18 EPA-CAMD (2004). “IPM Documentation Report,” Section 5: Emission Control Technologies, Exhibit 5-1, v.2.1.9. 

Conversation with S. Khan, January 31, 2005. 

38 
Section C


shows that postcombustion controls such as 

scrubbing accounted for nearly 37 percent of 

emission reductions in 2001. Most of these 

reductions came from new scrubbers installed 

on 30 units, located primarily in the Midwest. 

The remaining 63 percent of reductions came 

from coal-fired units switching to lower-sulfur 

coals. 19 Fuel switching to low-sulfur coal 

became a cost-effective abatement option with 

the significant decline of rail transport costs in 

the late 1980s and early 1990s. This trend may 

not continue into the future. 

Under the NOX Budget Trading Program, 20 

sources also report pollution control information, 

including installation dates, in monitoring 

plans submitted to EPA. As of April 2005, there 

were 122 coal-fired units using SCR controls 

that report emissions. Fifty-three coal-fired units, 

of which nine are industrial units, reported 

installing SNCR. Most of these installations 

occurred outside of the Ozone Transport 

Commission (OTC) region in the northeastern 

United States. However, since October 2002, 

sources within the original OTC states have 

installed SCR controls on fifteen units with 

approximately 8171 MW capacity and SNCR 

on thirteen units with about 2295 MW capacity. 

These data indicate that the implementation of 

the NOX Budget Trading Program appears to 

have been an impetus for many units to reduce 

their NOX emissions through the use of add-on 

controls, especially in the states where 

significant reductions are needed to comply with 

the NOX Budget Trading Program. 21 

C.3.2 Industrial Boilers 

Many of the options available to steam plants 

in the electric utility sector for emission 

reductions are also available to industrial boilers. 

The applicability of these control options is 

conditional on several factors, including boiler 

size. Postcombustion control technologies, 

such as FGD, may be realistic options for larger 

electric utility boilers, but smaller industrial 

boilers may choose less costly alternatives. The 

likely options for on-site reduction of emissions 

from industrial boilers include the following 

(depending on size of boiler): 

•	 Low-NOX burners for NOX control. 

•	 Fuel switching, where possible, for SO2 

control. 

•	 Improved boiler performance through 

control optimization and good combustion 

practices, which will reduce emissions of 

both NOX and SO2. 

As mentioned above, under the NOX 

Budget Trading Program, nine industrial units 

have reported installing SNCR technology. 

Approximately 70 industrial units have reported 

using low-NOX burners. 22 Many industrial 

units reporting add-on control technologies 

(SCR) have combined these with other control 

technologies (combustion modifications and fuel 

switching) for maximum effect. 

An additional factor affecting the application 

of potential control options is integration 

within an industrial process. In some facilities, 

industrial boilers use fuel derived from their 

specific industrial processes at little or no cost. In 

these cases, it is unlikely that switching to, and 

therefore purchasing, a more environmentally 

benign fuel would occur. Industrial boilers in 

the pulp and paper industry, for example, often 

combust spent pulping liquor. 

C.3.3 Smelters 

One option available to the smelter industry for 

SO2 control is the installation of a wet scrubbing 

system. An acid plant may follow this system, 

19 Ellerman, A.D. (2003). “Lessons from Phase 2 Compliance with the U.S. Acid Rain Program,” MIT Center for Energy and 

Environmental Policy Research, Cambridge, p. 5, http://web.mit.edu/ceepr/www/2003-009.pdf. 

20 The NOX Budget Trading Program is a cap and trading program for large EGUs and large industrial boilers, turbines, and 

combined cycle units within NOX SIP call states. EPA provided these states with a model cap and trading rule (the NOX 

Budget Trading Program) to achieve the emission reductions set forth in the NOX SIP call in a highly cost-effective way. 

21 U.S. EPA (2004). “NOX Budget Trading Program: 2003 Progress and Compliance Report,” pp. 20-21. 

22 This is from preliminary data collected by the Emissions Monitoring Branch of the U.S. EPA’s CAMD as of October 2004. 

39 
Canada-United States Emissions Cap and Trading Feasibility Study 

where the SO2 recovered from the FGD is 

converted into sulfuric acid, a product with 

further commercial value. A second option is 

the modernization of the smelter process. This 

is specific to the type of metal being produced 

and may not be available to all facilities. NOX 

emissions from this sector are relatively minor. 

C.3.4 Cement Kilns 

Both primary measures and postcombustion 

control options may be used to reduce SO2 

and NOX emissions from cement kilns. Primary 

measures for SO2 control include the selection 

of low-sulfur fuels and raw materials with low 

pyrite content, as well as lime addition. Primary 

measures for NOX control include changes to 

temperature and excess air, mineral additions, 

the selection of raw material, and combustion 

modification via flame cooling, low-NOX burners, 

staged fuel/air combustion, and mid-kiln firing. 

Postcombustion methods include dry or wet 

scrubbing technologies for SO2 control and SCR 

or SNCR for NOX control. 

C.4 OPT-IN PROVISIONS 

In general, the applicability criteria for an 

emissions cap and trading program are designed 

to include those sectors of emission sources 

that are most appropriate, taking into account 

policy, control cost, monitoring, and other 

considerations. However, it is possible to 

include provisions that allow individual sources 

not covered by these applicability criteria to 

voluntarily “opt in” to the program. Theoretically, 

these sources may have cost-effective emission 

reduction opportunities that warrant the 

expense of meeting the monitoring and other 

requirements associated with the cap and 

trading program. If policymakers allow opt-ins, 

the regulator would have to define the program 

entry requirements for such sources (including 

monitoring requirements, such as having CEMS) 

and the method for allocating allowances for 

such sources. Monitoring requirements for an 

opt-in source must be the same as those for 

sources that are required to be in the program in 

order to ensure that the reductions achieved are 

real, verifiable, and comparably valued. 

While voluntary opt-in provisions may reduce 

costs to affected sources, such provisions raise 

some other issues. Sources may decide to opt in 

and take advantage of allowance allocations that 

are greater than what their emissions would 

have been if they were not participating in the 

cap and trading program. In some cases, they 

may opt in and then take measures to reduce 

emissions that would have occurred anyway, 

regardless of participation in the program. In 

addition, sources may opt in, reduce their 

utilization by shifting utilization to other sources 

not subject to the trading program, and have 

freed-up allowances to sell. Unless the regulating 

authority can make an allowance allocation at 

a level that is at or below “business as usual” 

and takes account of reduced utilization, extra 

allowances will be introduced into the system 

and will undermine the environmental 

effectiveness of the emissions cap and trading 

program. 23 

C.4.1 Acid Rain Program Opt-in Provision 

Recognizing that additional SO2 emission 

reduction opportunities existed in the 

industrial sector, Congress established the Opt-in 

Program under section 410 of the Clean Air Act 

Amendments of 1990. The Opt-in Program 

allowed sources not required to participate in the 

Acid Rain Program the opportunity to enter the 

program on a voluntary basis and receive their 

own SO2 allowances. Opt-in sources faced the 

same requirements as other sources in the 

program. It was expected that the participation 

of these additional sources would reduce the 

cost of achieving the roughly 10 million ton 

reduction in SO2 emissions mandated under the 

23 See U.S. EPA (2003), “Tools of the Trade,” http://www.epa.gov/airmarkets/international/tools.pdf, for continued 

discussion. 

40 
Section C


Clean Air Act by providing lower cost reduction 

opportunities. As participating opt-in sources 

reduced their SO2 emissions at relatively 

low cost, their reductions—in the form of 

allowances—would be available to electric 

utilities where emission reductions were more 

expensive. The program was further intended to 

offer combustion sources financial incentives to 

voluntarily reduce SO2 emissions. By reducing 

emissions below the allowance allocation, an 

opt-in source would have unused allowances, 

which it could then sell in the SO2 allowance 

market. 24 However, only 11 units from four 

sources actually chose to opt in to the Acid Rain 

Program. Furthermore, research on the Acid Rain 

Program (Ellerman et al., 2000) suggests that 

these sources were induced to voluntarily 

join the program under the opt-in provisions 

because of overly generous allowance allocation 

formulas. Opt-ins using these provisions 

achieved very few additional emission 

reductions. 

C.4.2 U.S. NOX Budget Trading Program 

Opt-in Provisions 

Most states within the NOX SIP call area have 

also adopted the opt-in provisions outlined in 

the NOX Budget Trading Program model rule 

(40 CFR Part 96). Similar to opt-in provisions 

under the Acid Rain Program, once a unit opts 

in to the program, the unit is subject to the 

same compliance, monitoring, and reporting 

requirements that apply to units required to 

participate in the trading program. However, 

only boilers, combustion turbines, or combinedcycle systems can opt in to the NOX Budget 

Trading Program. In order to opt in, units must 

submit an application to their state permitting 

authority for a NOX budget opt-in permit that 

includes a monitoring plan. This plan is reviewed 

and must be determined to be sufficient by the 

relevant state permitting authority and EPA. If the 

plan is sufficient, the source must monitor and 

report its emissions rate and heat input for a full 

control period (ozone season), in accordance 

with 40 CFR Part 75, in order to establish the 

baseline heat input and baseline NOX emission 

rate. Subsequently, after the application is 

approved, the relevant state permitting authority 

will issue the unit a permit and allocate the 

appropriate amount of allowances, calculated 

for a given control period as: 

•	 The lesser of the unit’s baseline heat input 

or actual heat input for the immediately 

prior ozone season multiplied by 

•	 The lesser of the unit’s baseline emissions 

rate or the most stringent state or federal 

emissions limitation applicable to the unit. 

The opt-in program under the SIP call will be 

evaluated as data are collected. 

C.4.3 CAIR Program Opt-in Provisions 

The opt-in provisions in the Clean Air Interstate 

Rule (CAIR) trading programs are similar to the 

opt-in provisions in the NOX Budget Trading 

Program. Opt-ins are limited to boilers, turbines, 

or other fossil fuel-fired combustion devices 

that vent all emissions through a stack and 

are able to meet Part 75 emission monitoring 

and reporting requirements. There are two 

mechanisms that the states can use to allow 

an opt-in, and they may choose one or both. 

The first effectively requires—through reduced 

allowance allocations—a 30 percent reduction in 

emissions, and the second has special provisions 

and requirements for sources that repower with 

qualifying technologies. 

C.5 SUMMARY 

While in the United States, the primary source 

of SO2 emissions, and a major contributor of 

NOX emissions, is fuel combustion from EGUs, 

in Canada other sectors in addition to EGUs are 

key contributors to SO2 (base metals smelting) 

and NOX emissions (industrial sources). 

In general, harmonization of applicability 

in terms of coverage of sources and sectors 

24 See http://www.epa.gov/airmarkets/arp/overview.html#optin for more information. 

41 
Canada-United States Emissions Cap and Trading Feasibility Study 

is desirable, rather than required. For example, 

EGUs should be included in any SO2 or 

NOX cross-border trading program because 

they are an important contributor to both SO2 

and NOX emissions in both countries. Currently, 

in both the U.S. Acid Rain Program and NOX 

Budget Trading Program, the EGUs are the main 

participants, while the NOX Budget Trading 

Program includes industrial sources such as 

large industrial boilers (e.g., petroleum refineries, 

pulp and paper mills, cement kilns, and iron 

and steel mills). The CAIR trading programs are 

generally limited to EGUs. However, industrial 

sources play a relatively larger role in SO2 and 

NOX emissions in Canada than in the United 

States. These sources, including base metals 

smelters, need to be examined further for 

potential inclusion in a Canada-U.S. cross-border 

emissions cap and trading program, as there 

are some concerns about the ability to measure 

emissions rigorously and in an equivalent 

manner to the electricity sector. To the extent 

that some aspects of applicability would not be 

harmonized, there should be further analyses of 

economic consequences and international trade 

issues before a decision is made as to allowable 

differences. 

Opt-in provisions could be considered, in 

the context of a cross-border emissions cap 

and trading program, to allow sources that fall 

outside of the applicability bounds the option to 

participate in the program. However, additional 

provisions for these units would need to be 

specified in the program to ensure the integrity 

of the emission caps and to minimize 

administrative burden. These provisions would 

need to address issues such as: requiring the 

same emissions monitoring as for units required 

to be in the program; avoiding the allocation 

of allowances for emissions that already have 

been reduced; and minimizing allocations for 

emissions that would be reduced without the 

unit opting in or that may be shifted (through 

utilization shifting) to units not subject to the 

trading program. These issues need to be 

addressed effectively but in a way that does not 

impose unreasonable administrative burden. 

C.6 REFERENCES 

Clean Air Markets Division, U.S. EPA. 

http://www.epa.gov/airmarkets. 

Ellerman, A.D., P. Joskow, R. Schmalensee, 

J. Montero and E. Bailey, Markets for 

Clean Air, The U.S. Acid Rain Program. 

Massachusetts: MIT Center for Energy 

and Environmental Policy Research, 

Cambridge University Press, 2000. 

Ellerman, A.D. (2003). “Lessons from Phase 2 

Compliance with the U.S. Acid Rain 

Program,” MIT Center for Energy and 

Environmental Policy Research, 

Cambridge, p. 5, http://web.mit.edu/ 

ceepr/www/2003-009.pdf. 

Energy Information Administration (2002). 

“Electricity Quick Stats,” updated 

03/31/04, http://www.eia.doe.gov/ 

neic/quickfacts/quickelectric.htm, 

accessed 5/21/04. 

Statistics Canada (2001). “Electric Power 

Generating Stations, 2000,” Catalogue no. 

57-206-XIB. 

Statistics Canada (2003). “Report on Energy 

Supply-Demand in Canada, 2002,” 

Catalogue no. 57-003-XIB. 

Statistics Canada (2004). “Electric Power 

Generating Stations, 2002,” Catalogue no. 

57-206-XIB. 

U.S. EPA (2003). “Acid Rain Program 2002 

Progress Report,” Fall 2003, Clean Air 

Markets Division, EPA 430-R-03-011, 

http://www.epa.gov/airmarkets/ 

cmprpt/arp02/2002report.pdf. 

U.S. EPA (2003). “Tools of the Trade: A Guide to 

Designing and Operating a Trade Program 

for Pollution Control,” June 2003, Clean 

Air Markets Division, EPA 430-B-03-002, 

http://www.epa.gov/airmarkets/ 

international/tools.pdf. 

U.S. EPA (2004). 1970-2002 average annual 

emissions, all criteria pollutants 

(Excel file), http://www.epa.gov/ 

ttn/chief/trends/index.htm, accessed 

12/16/04. 

42 
Section C

U.S. EPA (2004). “NOX Budget Trading Program: 

2003 Progress and Compliance Report.” 

U.S. EPA (2004). “Technical Support Document: 

Analysis in Support of the Clean Air 

Interstate Rule Using the Integrated 

Planning Model,” http://www.epa.gov/

air/interstateairquality/pdfs/tsd.pdf, 

May 28, 2004, accessed 12/16/04. 

Whitford, J. (2004). “Industrial Boilers Database 

for Boilers > 250 mmBtu/hr.” 

Working Group #1 for the Multistakeholder 

Steering Committee for Initiative N306 

(1996). “Background Document for the 

Development of a National Guideline for 

NOX Emissions from New or Modified 

Commercial/Industrial Boilers and 

Process Heaters.” 

43 

Section D 

EMISSIONS MONITORING AND REPORTING 

Emissions monitoring and reporting are the 

backbone of emission cap and trading 

programs. Experience has shown that welldefined, rigorous monitoring and reporting 

procedures that measure mass emissions as 

accurately, consistently, and objectively as 

possible are a necessary condition for creating 

a high level of confidence in the value of 

allowances. The more accurate and complete 

the method of emissions measurement, the 

less risk and uncertainty there are associated 

with the emission tonnage represented by an 

allowance, the more value they have as tradable 

commodities, the lower the transaction costs of 

trading, and hence the more efficient the market. 

This section discusses emissions monitoring 

and reporting in the United States and Canada 

and highlights the need for harmonization 

of the two regimes under a cap and trading 

program. Section D.1 illustrates the fundamental 

requirements of emissions monitoring and 

reporting under an emissions cap and trading 

program. Section D.2 discusses U.S. emissions 

monitoring and reporting under the sulfur 

dioxide (SO2) and nitrogen oxide (NOX) trading 

programs, focusing on 40 CFR Part 75 – 

Continuous Emission Monitoring. Section D.3 

discusses the Canadian emission monitoring and 

reporting specifications in Report EPS 1/PG/7. 

Finally, Section D.4 provides an analysis of 

the previous sections, highlighting the areas 

where the two monitoring regimes need to be 

consistent in order to implement a successful 

cross-border emissions cap and trading program. 

D.1 PRINCIPLES 

Emission monitoring requirements for an 

emissions cap and trading program must 

be rigorous for several reasons: 

•	 To ensure that emissions from all sources 

are consistently and accurately measured 

and reported. 

•	 To verify that a ton of emissions from 

one source is equal to a ton of emissions 

from any other source. 

•	 To address the need to collect and 

evaluate large amounts of data quickly. 

•	 To ensure that emission values are 

produced for every unit operating hour, i.e. 

to ensure that all emissions are counted. 

•	 To verify that emission reduction goals are 

achieved by ensuring that emissions do not 

exceed allowances. 

To ensure the success of an emissions cap 

and trading program, the program must meet 

several overarching goals in addition to rigor. 

These include accountability, transparency, 

predictability, consistency, and flexibility. 

D.1.1 Accountability 

An emissions cap and trading program 

must include a framework of oversight and 

enforcement that will hold participants 

accountable for all their emissions and ensure 

compliance with the program’s requirements. 

The basis of accountability is the accurate 

measurement and verification of emissions 

and the rigorous and consistent enforcement 

of penalties for fraud or noncompliance. The 

regulating authority can facilitate accountability 

through clear rules that are not unnecessarily 

complicated. 

D.1.2 Transparency 

Transparency refers to the full and open 

disclosure of relevant public and private 

decisions, such as establishing the rules 

and regulations for a trading program and 

determining whether an emissions source is in 

compliance. Transparency is important to a wellfunctioning cap and trading program, in terms of 

both its design and its operation. Transparency 

of the design process can promote public 

45 
Canada-United States Emissions Cap and Trading Feasibility Study 

Table D-1 Essential Measurements Required by U.S. Emission Cap and Trading Programs 

Program Affected sources 

Parameter 

measured 

(units) 

Accounting 

period 

Acid Rain 

Program 

Fossil fuel-fired electric generating units (EGUs) and other 

combustion sources that opt in to the SO2 emissions cap and 

trading program 

SO2 (tons) Annual 

NOX Budget 

Trading 

Program 

EGUs, large industrial boilers, other industrial sources 

(e.g., cement kilns, process heaters), and units that opt in to 

the NOX emissions cap and trading program 

NOX (tons) Ozone season 1 

acceptance and confidence in the emissions 

cap and trading program. 

Providing public access to source-level 

emissions and allowance data also promotes 

confidence in the program and provides an 

additional level of scrutiny to verify enforcement 

and encourage compliance. In some jurisdictions 

these data are classified as confidential, and 

legal changes may be required to make them 

publicly available. 

D.1.3 Predictability and Consistency 

Predictability and consistency in the design 

and application of program rules are important 

principles for an effective emissions cap and 

trading program. They help create the right 

circumstances to encourage innovation and 

lower costs. With a cap and trading program, 

emission sources have an incentive to find 

better and lower-cost opportunities to reduce 

emissions. This incentive depends upon longterm, predictable, and consistent rules that affect 

the economic value of emission reductions. 

D.1.4 Flexibility 

Although program rules must be predictable and 

consistent in their design and application, they 

must also have flexibility. The framework must 

include options to accomplish the overall data 

quality objective of the program. Such options 

allow the source to choose the monitoring 

approach that best fits its operation. This 

minimizes the effective cost of monitoring. New 

information is continually being made available, 

stressing the importance of flexibility in the 

program rules. 

D.2 U.S. MONITORING AND 

REPORTING 

In the United States, 40 CFR Part 75 – Continuous 

Emission Monitoring establishes requirements 

for continuous air emissions monitoring and 

reporting for large power plants and industrial 

sources in the Environmental Protection Agency 

(EPA) Acid Rain Program and the NOX Budget 

Trading Program. Under the Acid Rain Program, 

large industrial sources are included on a 

voluntary basis only, in contrast to their inclusion 

in the NOX Budget Trading Program. 

Table D-1 illustrates the essential monitoring 

measurements required by the Acid Rain 

Program and the NOX Budget Trading Program 

and gives the accounting period for each. Note 

that Acid Rain Program sources are also required 

to continuously monitor and report carbon 

dioxide (CO2) mass emissions under section 

821 of the Clean Air Act. However, measurement 

of CO2 mass emissions is not essential for 

an effective SO2 or NOX trading program. 

The Part 75 rule specifies the types of 

monitoring systems that may be used for 

the required measurements, as well as the 

operation and maintenance requirements, 

The ozone season extends from May 1 through September 30. 

46 

1 
Section D


Figure D-1 Overview of Continuous Emission Monitoring under Part 75 

Protocol Gas 

Field Audits 

Audit Program 

Electronic Audits 

CEMS 

Quality 

Assurance 

Tests 

Electronic 

Data 

Reports 

Emissions 

Tracking 

System 

Allowance 

Tracking 

System 

quality assurance/quality control (QA/QC) 

requirements, and record-keeping and reporting 

requirements. Continuous emission monitoring 

systems (CEMS) must be used unless an affected 

unit meets the requirements for an alternative 

to CEMS. 

Figure D-1 depicts the major links in the data 

quality chain for a CEMS. The process starts 

with ensuring that the gas standards used to 

calibrate and test the monitoring equipment 

are accurate. To this end, EPA has adopted a 

traceability protocol for the certification of 

gaseous calibration standards. 2 The source 

must then conduct the necessary QA tests, 

following all appropriate procedures, and report 

the results of those tests in a timely and 

accurate manner. These QA activities are 

conducted initially for monitoring system 

certification and then on an ongoing basis, 

to ensure that the monitoring systems continue 

to measure the emissions accurately. 

Once the continuous emission monitoring 

(CEM) data are quality-assured, the next step is 

to ensure that the data are accurately recorded 

by a data acquisition and handling system 

(DAHS) and appropriately reported in a 

standardized format in an electronic data 

report (EDR). The EDRs are submitted quarterly 

to EPA for review, and the emissions data are 

used for accounting purposes in the cap and 

“EPA Traceability Protocol for Assay and Certification of Gaseous Calibration Standards,” September 1997, 

EPA-600/R-97/121. 

47 

2 
Canada-United States Emissions Cap and Trading Feasibility Study 

Table D-2 Part 75 Monitoring Options 

If an affected unit is 

classified as a... 

Part 75 provides these monitoring options... 

Basic CEMS 

provisions 

(75.10-18) 

Appendix D 

method 3 

Appendix E 

method 4 

LME 

method 5 

(75.19) 

Coal-fired unit 

Non-peaking oil- or gas-fired unit 

Peaking oil- or gas-fired unit 

y 

y 

y 

y 

y y 

y 

y 

trading program. EPA provides the necessary 

data management systems and tools to: 

•	 Check the format of the emissions data and 

QA tests submitted in the EDRs. 

•	 Recalculate the emissions and QA test results 

from the raw data. 

•	 Track emissions and allowance transfers. 

The integrity of the overall trading program 

can break down anywhere along this chain of 

activities. Therefore, EPA relies on a combination 

of electronic and field audits to verify overall 

data integrity. 

D.2.1 Monitoring Options 

The Part 75 rule provides several monitoring 

options. The available options depend on how 

each unit is classified in terms of the type of fuel 

burned, the utilization of the unit, and the unit’s 

potential emissions. Part 75 has a set of basic 

continuous monitoring provisions that apply to 

all units. These basic provisions require CEMS for 

all monitored parameters. However, if a unit is 

classified as oil-fired or gas-fired, alternatives to 

CEMS are available for some or all monitored 

parameters. These alternatives are known as 

“excepted methods” and are found in Appendices 

D (for gas- and oil-fired units) and E (for gas- and 

oil-fired peaking units) of Part 75 and in section 

75.19 (for low mass emission (LME) units). This 

regulatory flexibility allows compliance to be 

achieved at a lower cost in many instances, 

without compromising the integrity of the trading 

programs. 

The Part 75 monitoring options are 

summarized in Table D-2 and are discussed in 

Sections D.2.1.1 through D.2.1.4 below. Sections 

D.2.1.5 and D.2.1.6 discuss monitoring methods 

for industrial sources and alternative monitoring 

systems, respectively. 

D.2.1.1 Continuous Emission Monitoring (CEM) 

A CEMS consists of all the equipment needed 

to measure and provide a permanent record of 

the emissions from an affected unit. Examples 

of CEMS components include: 

•	 Pollutant concentration monitors (e.g., 

SO2 or NOX monitors). 

•	 Diluent gas monitors, to measure 

percent oxygen (O2) or percent CO2. 

•	 Volumetric flow monitors. 

•	 Sample probes. 

•	 Sample (“umbilical”) lines. 

•	 Sample pumps. 

•	 Sample conditioning equipment (e.g., heaters, 

condensers, gas dilution equipment). 

•	 Data loggers or programmable logic 

controllers (PLCs). 

•	 DAHS that electronically record all 

measurements and calculate the emissions. 

3 For SO2 emissions and heat input only. 

4 For NOX emissions only. 

If the LME qualifying thresholds are met and this method is selected, it must be used for all parameters, i.e., for SO2, 

NOX, and heat input (as applicable). 

48 

5 
Section D

Table D-3 CEMS Requirements for U.S. Emission Cap and Trading Programs 

To measure this 

essential parameter... The following CEM systems are required... 

To provide data in 

these units of 

measure 6... 

SO2 tons • SO2 system 

• Stack gas flow rate system 

• Moisture system (in some cases) 

ppm 

scfh 

% H2O 

NOX tons • NOX system 

• Stack gas flow rate system 

• Moisture system (in some cases) 

or

• NOX-diluent system 7 

• Stack gas flow rate system 

• Moisture system (in some cases) 

ppm 

scfh 

% H2O 

lb./mmBtu 

scfh 

% H2O 

The specific components of a CEMS depend 

upon what parameter is being monitored and 

the required units of measure. For instance, a 

typical CEMS used to measure SO2 or NOX 

concentration might consist of a sample probe, 

umbilical line, sample pump, condenser, SO2 

(or NOX) analyzer, PLC, and DAHS. Table D-3 

summarizes the types of CEMS that are needed 

to measure the essential parameters (i.e., 

SO2 and NOX tons) in the U.S. cap and trading 

programs. 

D.2.1.2 Alternative SO2 and Heat Input 

Monitoring Methodology for Gas- and Oil-Fired 

Units (Appendix D) 

If an affected unit meets the definition of “gasfired” or “oil-fired” in 40 CFR 72.2, the source 

may use the alternative methodology in 

Appendix D of Part 75 instead of CEMS for 

certain parameters. Appendix D applies only to 

the measurement of the SO2 mass emissions 

rate and the unit heat input rate. 

Appendix D requires continuous monitoring 

of the fuel flow rate and periodic sampling of 

fuel characteristics, such as sulfur content, gross 

The alternative methodology in 

Appendix D of Part 75 applies exclusively 

to gas- and oil-fired units. The SO2 mass 

emissions and/or unit heat input are 

determined using fuel flow meters and 

the results of periodic fuel sampling and 

analysis. 

calorific value (GCV), and density. The measured 

fuel flow rates are used together with the results 

of the fuel sampling and analysis to determine 

the SO2 mass emissions rate and/or the unit 

heat input rate, depending on the requirements 

of the applicable program(s). 

D.2.1.3 Alternative NOX Monitoring 

Methodology for Oil- and Gas-Fired Peaking 

Units (Appendix E) 

If an affected unit in the Acid Rain Program 

or NOX Budget Trading Program meets the 

definition of a “peaking unit” in 40 CFR 72.2 and 

also qualifies as “oil-fired” or “gas-fired,” then the 

alternative methodology in Appendix E of Part 75 

may be used to monitor the NOX emissions rate, 

in lieu of CEMS. 

6	 The acronym “ppm” means parts per million; “scfh” means standard cubic feet per hour; lb. is pounds; and “mmBtu” is 

million British thermal units, where 1 Btu ≈ 1.06 kilojoules. 

7	 This system consists of an NOX monitor and a diluent gas (CO2 or O2) monitor. 

49 
Canada-United States Emissions Cap and Trading Feasibility Study 

The Appendix E methodology for oiland gas-fired peaking units pertains only to 

the monitoring of NOX emissions rate. To 

use this methodology, a correlation curve 

of NOX emissions rate vs. heat input rate is 

first derived from emissions testing; then, 

the hourly unit heat input rate is measured 

using the Appendix D methodology, and the 

hourly NOX emissions rate is determined 

from the correlation curve. 

If the Appendix E method is selected for a 

qualifying unit, the owner or operator must: 

•	 Use the Appendix D methodology to 

measure the hourly unit heat input rate. 

•	 Perform four-load emissions testing to 

develop a correlation curve of NOX emissions 

rate versus heat input rate. 

•	 Continuously monitor key parameters related 

to NOX formation (e.g., excess O2 for boilers, 

water-to-fuel ratio for turbines, etc.). 

Acceptable ranges and values for the 

parameters must be defined in a QA plan. 

•	 Redetermine the correlation curve once 

every five years or if any of the monitored 

parameters are outside the acceptable 

range of values for greater than 

16 consecutive unit operating hours. 

D.2.1.4 Alternative Monitoring Methodology 

for Low Mass Emission Units 

If an affected unit qualifies as an LME unit, 

Part 75 provides an alternative methodology that 

may be used instead of CEMS. The alternative 

monitoring methodology for LME units is found 

in 75.19. The LME methodology does not require 

actual continuous monitoring of emissions or 

unit heat input. Rather, hourly SO2, NOX, and CO2 

emissions are determined using fuel-specific 

default emission rates (“emission factors”) and 

estimates of hourly heat input. Once the LME 

methodology has been selected, it must be used 

for all program parameters, i.e., for SO2, NOX, 

CO2, and heat input, if the unit is in the Acid Rain 

Program, and for NOX and heat input if the unit 

is in the NOX Budget Trading Program. “Mixingand-matching” other Part 75 methodologies with 

LME is not permitted. 

The LME methodology in 40 CFR 

75.19 provides an alternative to CEMS for 

determining SO2, NOX, and CO2 emissions 

and unit heat input. To qualify to use the 

LME methodology, a unit must be gas- or 

oil-fired and its SO2 and/or NOX mass 

emissions must not exceed certain annual 

or ozone season limits. 

In the most basic form of the LME 

methodology, hourly emissions are estimated 

by multiplying the maximum rated unit heat 

input by a “generic” emissions factor provided 

in the rule. This results in a conservatively high 

estimate of the unit’s emissions. If the source 

wants to make a more realistic estimate of 

emissions, heat input can be determined by 

monitoring fuel flow and conducting fuel 

sampling for GCV in lieu of using the maximum 

rated heat input method. Owners and operators 

of LME units also have the option of performing 

NOX emissions rate testing to determine more 

representative fuel- and unit-specific default NOX 

emission rates. 

To use the LME methodology for a particular 

gas-fired or oil-fired unit, the owner or operator 

must demonstrate that the SO2 and/or NOX 

mass emissions from the unit do not exceed the 

annual threshold limits shown in Table D-4. 

For instance, a unit in the NOX Budget Trading 

Program must demonstrate that its ozone season 

NOX mass emissions do not exceed 50 tons. 

D.2.1.5 Monitoring Methods for 

Industrial Sources 

In the U.S. emissions cap and trading programs, 

EGUs are the predominantly affected units. In 

some cases, monitoring of industrial sources can 

be more complex than the monitoring of EGUs. 

Under the Ozone Transport Commission 

(OTC) NOX Budget Program, there were 43 

50 
Section D


Table D-4 Low Mass Emission Units 

A combustion unit may qualify as a low mass emissions, or LME, unit if it... 

• Meets the definition of a gas-fired or oil-fired unit in 72.2, and 

• If its SO2 and/or NOX mass emissions meet the following limits: 

For Acid Rain Program units: 

• < 25 tons of SO2 per year 

and 

• < 100 tons of NOX per year 

For NOX Budget Trading Program units: 

• < 50 tons of NOX per ozone season 

and 

• < 100 tons of NOX per year 8 

facilities and more than 120 units in the industrial 

source category. These units encompassed a wide 

variety of industries, including electric, gas, and 

sanitary services; petroleum refining; pulp and 

paper; chemical products; primary metals; and 

other miscellaneous source categories. The units 

were primarily industrial boilers and monitored 

according to Part 75. 

In the NOX Budget Trading Program, certain 

states have elected to regulate two additional 

categories of units, i.e., cement kilns and refinery 

process heaters. These facilities do not produce 

electrical or steam load, and for the kilns, 

the formation of CO2 during the calcination 

process prevents the heat input rate from being 

determined in the same manner as it is for 

boilers, i.e., by using flow rate and diluent gas 

monitors. To address the unique monitoring 

issues associated with these sources, EPA 

revised Part 75 in 2002 to include special 

provisions for non-load-based units. In addition, 

the cement industry was given an exemption 

from heat input monitoring by New York State. 9 

Smelters are an industrial source category 

that is not currently regulated under either of 

the U.S. emissions cap and trading programs. 

For the major smelter units that discharge to the 

atmosphere through stacks (e.g., dryers, roasters, 

etc.), Part 75 monitoring potentially could be 

applied. However, fugitive emissions from 

smelters are not easily captured or quantified. 

If smelters were to be considered for inclusion 

in a cap and trade program, further analysis of 

the sector, including appropriate monitoring 

approaches, would need to be conducted. 

D.2.1.6 Alternative Monitoring Systems 

and Petitions 

Subpart E of Part 75 provides a mechanism that 

allows the owner or operator of an affected unit 

to submit a petition to the Administrator for 

approval of an alternative monitoring system. To 

obtain approval, the petition must demonstrate 

that the alternative system has the same (or 

better) precision, reliability, accessibility, and 

timeliness as that provided by a certified Part 75 

CEMS. The performance of any proposed 

alternative system must be demonstrated by 

simultaneously testing it against a fully certified 

CEMS or an EPA reference test method. The 

petition must also include QA provisions and 

missing data substitution procedures that are 

consistent with those in Part 75. Partly due to the 

rigorous requirements of Subpart E and partly 

because the Appendix D, Appendix E, Appendix 

G (Determination of CO2 emissions), and LMEexcepted methods in Part 75 provide substantial 

flexibility in choosing a monitoring methodology, 

EPA has received and approved only a few 

Subpart E petitions to use alternative monitoring 

systems. 

Part 75 provides additional regulatory 

flexibility, whereby the affected unit may 

petition the EPA Administrator requesting relief 

(or minor variances) from certain provisions 

of Part 75. Each petition must explain why the 

8 This limit applies only if the source is required to (or elects to) report NOX mass emissions on a year-round basis. 

9 All of the affected cement kilns are in New York State. 

51 
Canada-United States Emissions Cap and Trading Feasibility Study 

proposed alternative is being suggested in lieu 

of the regulatory requirement and must contain 

enough information for the reviewing agency 

(or agencies) to evaluate the request. 

The option to petition is a critical part of the 

emissions monitoring program. The Part 75 

monitoring and reporting requirements are 

written in a way that ensures applicability to the 

broadest range of facilities; however, given that 

there are thousands of affected units using Part 

75, not every situation or circumstance can be 

accounted for in the regulation. The petition 

process serves as a vehicle through which 

individual units or facilities can use alternative 

means to accomplish the principal objective 

of Part 75, which is to ensure complete and 

accurate emissions accounting. The regulatory 

flexibility provided by the petition process 

reduces the cost of monitoring and reporting 

emissions for many sources and facilitates 

program implementation. 

A consistent petition process is critical 

in a cross-border trading program. Petitions 

are like case law. Therefore, decisions 

made by one country should not contradict 

or compromise previous decisions made by 

the other nation. 

D.2.2 Monitoring System Certification Process 

Before any data from Part 75 monitoring systems 

can be reported as quality-assured, the systems 

must pass a series of certification tests to 

demonstrate that they are capable of providing 

accurate emissions data. The overall monitoring 

system certification process consists of several 

steps, as shown in Figure D-2. The process 

begins by selecting the monitoring methodology 

to be used for each parameter and then 

submitting an initial monitoring plan. Next, the 

monitoring equipment is installed, notices of 

certification testing are provided, the tests are 

conducted, and a certification application is 

submitted to EPA and to the state agency for 

review. The steps in the certification process are 

discussed in greater detail in Sections D.2.2.1 

through D.2.2.5. Section D.2.2.6 describes 

recertification and diagnostic testing. 

D.2.2.1 Submit Initial Monitoring Plan 

The initial monitoring plan identifies the overall 

monitoring strategy for the affected unit. The 

plan must contain sufficient information about 

the monitoring systems to demonstrate that all 

of the regulated emissions from the unit will be 

measured and reported. The monitoring plan has 

both a hard copy and an electronic portion. 

At least 45 days before certification testing 

begins, the electronic portion of the initial 

monitoring plan must be submitted to EPA’s 

Clean Air Markets Division (CAMD) in the 

Agency’s standardized EDR format, and the hard 

copy portion must be submitted to the applicable 

EPA Regional Office and to the appropriate state 

or local agency. The electronic portion of the 

monitoring plan is then reviewed by CAMD, and 

feedback is sent to the facility, to the EPA Region, 

and to the state. Any deficiencies or issues 

identified in the review process are resolved 

between the facility and the reviewing agencies. 

The monitoring plan is to be a “living” 

document that reflects changes over time in 

the monitoring systems. As technology 

advances, new monitors may replace the 

monitors originally described in the monitoring 

plan, or the monitoring methodology may 

change. Also, facility operations may change 

and necessitate the use of additional monitors or 

alternative placement of existing monitors. The 

monitoring plan must be updated to reflect any 

and all such changes. For example, replacing a 

gas analyzer requires a monitoring plan update, 

because the source is required to report the make, 

model, and serial number of each analyzer. 

D.2.2.2 Submit Certification Test Notices 

Certification test notices must be sent to CAMD, 

to the EPA Regional Office, and to the appropriate 

state or local air agency at least 21 days prior 

to conducting the required certification testing. 

There is one exception to this: for the certification 

52 
Section D


Figure D-2 Monitoring System Certification Process 

Submit Initial 

Monitoring Plan 

Submit 

Certification 

Test Notices 

Conduct 

Certification 

Tests 

Submit 

Certification 

Application 

Submit Any 

Missing 

Information 

Receive Agency 

Approval or 

Disapproval 

45 days or more before beginning 

certification testing. 

Provide notice to EPA and the state 

at least 21 days before testing. 

Conduct the required tests and 

prepare a certification application 

for submission to EPA and the 

state. 

Within 45 days of completing 

testing. The electronic portion goes 

to CAMD and hard copy portion 

goes to the state and EPA Region. 

If the application is incomplete 

source will be notified and given 

reasonable time to submit the 

missing information. 

A notice of approval or disapproval 

will be issued within 120 days of 

receipt of the completed application. 

In the absence of such notice, the 

monitoring systems are considered 

to be certified by default. 

of Appendix D fuel flow meters, the notifications 

are not required. 

D.2.2.3 Conduct Certification Tests 

The types of certification tests required by Part 

75 are summarized in Table D-5. 

D.2.2.4 Submit Certification Application 

Within 45 days after completing the required 

certification testing, a certification application 

must be submitted. There are two parts to the 

application: electronic and hard copy. The 

electronic piece of the application consists of 

a complete, updated monitoring plan and the 

results of the certification tests, in EDR format. 

This piece is sent to CAMD. The hard copy piece 

of the application consists of an application 

form, the hard copy certification test report, and 

any changes made to the hard copy portion of 

the monitoring plan as a result of the testing. 

If the certification application is incomplete 

or is missing any information, the reviewing 

agencies will notify the source, and a reasonable 

amount of time will be given to submit the 

required information. 

D.2.2.5 Receive Agency Approval or 

Disapproval 

The permitting authority will issue a notice 

of approval or disapproval of the certification 

application within 120 days of receiving 

the complete application. If this notice is not 

53 
Canada-United States Emissions Cap and Trading Feasibility Study 

Table D-5 Part 75 Certification Tests 

This type of 

certification test... Is required for... And its purpose is... 

Seven-day calibration 

error test 

Gas and flow monitors To evaluate the accuracy and stability of 

a monitor’s calibration over an extended 

period of unit operation. 

Linearity check Gas monitors To determine whether the response of a 

gas analyzer is linear across its range. 

Relative accuracy test 

audit (RATA) 

Gas and flow 

monitoring systems 

(three-load test for flow) 

To compare emissions data recorded by a 

CEMS with data collected concurrently with 

an EPA reference test method. 

Bias test SO2, NOX, and flow 

monitoring systems 

To determine whether a monitoring system 

is biased low with respect to the reference 

method, based on the RATA results. If a low 

bias is found, a bias adjustment factor must 

be calculated and applied to the subsequent 

hourly emissions data. 

Cycle time test Gas monitoring systems To determine whether a CEMS is capable 

of completing at least one cycle of sampling, 

analyzing, and data recording every 

15 minutes. 

Flow meter accuracy 

test 

Appendix D fuel flow 

meters 

To demonstrate that a fuel flow meter can 

accurately measure the fuel flow rate. 

NOX emissions rate testing 

and heat input measurement 

at four unit loads 

Appendix E peaking 

units 

To construct a correlation curve of NOX 

emissions rate vs. heat input rate. 

NOX emissions rate testing 

at one or more unit loads 

LME units To determine fuel- and unit-specific NOX 

emission factors for reporting purposes. 

DAHS verification Units using CEMS or 

Appendix E and/or 

Appendix D monitoring 

methodologies 

To ensure that all emission calculations 

are being performed correctly and that 

the missing data routines are being applied 

properly. 

given within 120 days, then provided that all 

required tests were successfully completed, the 

monitoring systems are considered to be certified 

by default. 

D.2.2.6 Recertification and Diagnostic Testing 

Whenever a replacement, modification, or other 

change is made to a monitoring system 

that could significantly affect the ability of the 

system to accurately measure emissions, the 

system must be recertified. Also, if the flue gas 

handling system or unit operation is changed 

and there is a significant change in the unit’s 

flow or emissions concentration profile, the 

affected monitoring systems must be recertified. 

Examples of situations that require recertification 

of Part 75 monitoring systems include: 

•	 Replacement of an analyzer. 

•	 Replacement of an entire CEMS. 

•	 Change in location or orientation of 

a sampling probe. 

•	 Fuel flow meter replacement. 

The requirements for recertification are 

basically the same as those shown for initial 

certification in Figure D-2, except that an initial 

monitoring plan submittal is not required and 

the test notification requirements are slightly 

different. Note also that in some instances, EPA 

requires less than a full battery of tests for 

recertification. 

54 
Section D


Not all changes made to a certified 

monitoring system require recertification. In 

many cases, only diagnostic testing is required 

to ensure that the system continues to provide 

accurate data. For a more thorough discussion of 

recertification and diagnostic testing, see section 

75.20(b) and Question 13.21 in EPA’s “Part 75 

Emissions Monitoring Policy Manual.” 10 

D.2.3 Quality Assurance and Quality Control 

Procedures 

Following initial certification, all Part 75 

monitoring systems are required to undergo 

periodic QA testing to ensure that the monitoring 

systems continue to provide accurate data. 

For CEMS, the QA test requirements are found 

in either: 

•	 Appendix B of Part 75 and section 

75.21, for sources that report emissions 

data year-round. 

or 

•	 Section 75.74(c), for NOX Budget Trading 

Program sources that report emissions data 

only during the ozone season, from May 1 

through September 30. 

For Part 75 fuel flow meters, the ongoing 

QA test requirements are in section 2.1.6 

of Appendix D, and for Appendix E NOX 

monitoring systems, the QA requirements are 

found in sections 2.2 and 2.3 of Appendix E. 

D.2.3.1 QA Test Requirements for Year-Round 

Reporters 

Year-round reporting of emissions data is 

required for all Acid Rain Program units and for 

certain NOX Budget Trading Program units. 11 

The ongoing QA test requirements for yearround reporters are summarized in Table D-6. 

Table D-6 shows that for CEMS, the routine QA 

testing is required at three basic frequencies: 

daily, quarterly, and semi-annual/annual. 

Calibration error checks and flow monitor 

interference checks are required daily; gas 

monitor linearity checks, flow-to-load ratio tests, 

and (for differential pressure-type flow monitors) 

leak checks are required quarterly; and RATAs 

are required either semiannually or annually, 

depending on the results of the test. 

For Appendix D fuel flow meters, the basic 

test frequency for the required accuracy tests 

is annual, and for Appendix E systems, NOX 

emissions testing is required once every five 

years, to develop a new correlation curve. 

Note that there are some exceptions to the 

basic QA test requirements and frequencies 

shown in Table D-6. For instance, linearity 

checks are not required for SO2 or NOX monitors 

with span values of 30 ppm or less. For calendar 

quarters in which the unit operates for less than 

168 hours, limited exemptions from linearity 

checks and limited extensions of RATA deadlines 

are available. The limits of these exemptions and 

extensions are as follows: at least one linearity 

check is required per year, and a RATA is 

required at least once every eight calendar 

quarters, regardless of the number of unit 

operating hours. 

EPA recognizes that sometimes 

circumstances beyond the control of the source 

owner or operator (e.g., a forced unit outage) 

prevent a linearity check or RATA from being 

done in the calendar quarter in which it is due. 

To provide regulatory relief in these instances, 

Part 75 allows the test to be done in a “grace” 

period, immediately following the end of that 

quarter. For linearity checks, the grace period 

is 168 unit operating hours, and for RATAs, it is 

720 unit operating hours. 

D.2.3.2 QA Test Requirements for Ozone 

Season-Only Reporters 

If a unit is in the NOX Budget Trading Program 

but is not an Acid Rain Program unit, emissions 

10	 The Policy Manual is located at http://www.epa.gov/airmarkets/monitoring/polman/index.html. 

11	 Certain states allow NOX Budget Trading Program sources to choose between year-round and ozone season-only 

reporting. 

55 
Canada-United States Emissions Cap and Trading Feasibility Study 

Table D-6 Ongoing QA Test Requirements for Year-Round Reporters 

Perform this type of 

QA test... 

On these continuous 

monitoring systems... At this basic frequency... 

Calibration error test Gas and flow monitors Daily 

Interference check Flow monitors Daily 

Linearity check Gas monitors Quarterly 

Flow-to-load ratio or gross 

heat rate test 

Flow monitors Quarterly 

Leak check Differential pressure-type flow monitors Quarterly 

RATA and bias test Gas and flow monitors (bias test 

applies to SO2, NOX, and flow 

monitoring systems, only) 

Semiannual or annual 12 

Accuracy test Fuel flow meters Annual 

NOX emissions rate testing Appendix E systems Once every five years 

data may be reported on an ozone season-only 

basis rather than year-round, if this is allowed 

by the state regulation. If ozone season-only 

reporting is permitted and this option is selected, 

the QA procedures under section 75.74(c) 

in Subpart H of Part 75 must be met. These 

procedures require some pre-ozone season QA 

testing between October 1 and April 30 and 

other QA testing inside the ozone season (May 1 

to September 30). 

The QA test requirements for ozone seasononly reporting are considerably different 

from, and quite a bit more complex than, the 

requirements for year-round reporters. In view 

of this, sources that qualify to use the ozone 

season-only reporting option must carefully 

weigh the perceived benefits of this option (e.g., 

reduced reporting requirements, less required 

maintenance of CEMS during the off-season) 

against the potential invalidation of emissions 

data (and consequent loss of NOX allowances) 

that could result from a misunderstanding or 

misapplication of the rule requirements. 

D.2.3.3 QA/QC Program 

Part 75 requires all owners and operators of 

affected units to develop and implement a 

QA/QC program for the continuous monitoring 

systems. Each QA/QC program must include a 

written plan that describes in detail the step-bystep procedures and operations for a number 

of important activities, such as the routine 

maintenance procedures for the monitoring 

systems and the procedures used for required 

QA tests. Records must also be kept of all 

testing, adjustment, and repair of the monitoring 

systems (i.e., maintenance logs). This QA plan 

must be made available to the regulatory 

agencies upon request during field audits. 

D.2.3.4 Out-of-Control Periods and Missing 

Data Substitution 

In emissions cap and trading programs, it is 

essential to account for the emissions from 

a source during each hour of unit operation, 

because comparing the total mass emissions 

for the compliance period (i.e., year or ozone 

season) to the total number of allowances held 

determines compliance. Therefore, Part 75 

requires a complete data record for each affected 

unit. Emissions data must be reported for each 

unit operating hour. 

In real-life situations, however, qualityassured emissions data may not be available 

12 Depending on percent relative accuracy obtained in the previous test, the next RATA is required either semiannually 

or annually. 

56 
Section D


for some hours, because monitoring equipment 

occasionally malfunctions or needs to undergo 

routine maintenance, and sometimes a routine 

QA test is failed. For any unit operating hour in 

which a monitoring system is unable to provide 

quality-assured data, the system is considered to 

be “out of control.” Data recorded by an out-ofcontrol monitoring system are unsuitable for 

Part 75 reporting and may not be used in the 

emission calculations. For each hour of an outof-control period, emissions data must be 

provided in one of the following ways: 

•	 Using an approved Part 75 backup 

monitoring system that is not out of control. 

or 

•	 Using an EPA reference test method. 

or 

•	 Using an appropriate substitute data value. 

Many facilities do not have backup monitoring 

systems, and even if they do, there is no 

guarantee that the backup monitor will be 

“in control” during an outage of the primary 

monitor. In view of this, there needs to be 

a standard methodology for determining 

appropriate substitute data values during 

missing data periods. 

CEMS Missing Data Procedures 

In general, the Part 75 missing data procedures 

for CEMS are designed to provide conservatively 

high substitute data values, to ensure that 

emissions are not underestimated during 

monitor outages. Application of the missing 

data procedures begins at the date and hour 

of “provisional certification,” i.e., when the 

CEMS has passed all required certification tests 

and starts generating quality-assured data. 

Two distinct sets of missing data algorithms 

are described in Part 75: the “initial” 

and the “standard” missing data routines. 

The initial missing data algorithms in section 

75.31 are temporary “spin-up” procedures that 

are used for a specified period of time, after 

which the standard missing data algorithms in 

sections 75.33 through 75.37 begin to be applied. 

For both the initial and standard missing data 

procedures, all of the appropriate substitute data 

values are calculated and applied automatically 

by the DAHS. 

The initial missing data algorithms are 

simple, and the substitute data values derived 

from them are likely to be close to the actual 

source emissions. For example, the algorithm 

for SO2 is the arithmetic average of the SO2 

concentrations from the hour before and the 

hour after the missing data period. For NOX 

and flow rate, the substitute data value for each 

hour is an arithmetic average of the historical 

data at similar load levels. 

The standard missing data routines use a 

“tiered” approach, which takes into account both 

the percent monitor data availability 13 (PMA) and 

the length of the missing data period. When the 

PMA is high (≥ 95 percent) and the missing data 

period is relatively short (< 24 hours), the standard 

missing data algorithms are nearly identical to 

the initial missing data routines; consequently, 

the substitute data values are generally not 

punitive. However, as the PMA decreases and 

the length of the missing data period increases, 

the substitute data values become increasingly 

conservative (i.e., conservatively high), to ensure 

that emissions are not underreported. If the 

PMA drops below 80 percent, regardless of the 

length of the missing data period, the maximum 

potential concentration or emissions rate must 

be reported. 

The initial and standard missing data 

algorithms for NOX and stack gas flow rate 

are load-based, in order to provide more 

representative substitute data values. Note, 

however, that certain units in the NOX Budget 

Trading Program do not produce electrical or 

steam load (e.g., cement kilns). To accommodate 

these sources, EPA added a series of special 

13 In its simplest form, the PMA is the ratio of the number of quality-assured hours to the number of unit operating hours, 

in a specified look-back period. The PMA is calculated hourly by the DAHS. 

57 
Canada-United States Emissions Cap and Trading Feasibility Study 

missing data algorithms for NOX and flow 

rate to Part 75 in 2002. The algorithms are 

structurally similar to the standard missing data 

routines, except that they are not load-based. 

The rule allows the affected sources to define 

“operational bins” corresponding to different 

process operating conditions and to populate 

each bin with CEM data. The substitute data 

value for each missing data hour is then drawn 

from the appropriate operational bin. 

Missing Data Procedures for Appendices D 

and E 

Appendix D of Part 75 includes missing data 

procedures for fuel flow rate, fuel sulfur content, 

GCV, and density. The Appendix D missing data 

algorithms are considerably less complex than 

the CEMS missing data routines. The standard 

Appendix D missing data algorithms for fuel flow 

rate are the most sophisticated, in that they are 

fuel-specific and load-based. However, the 

substitute data value for each hour is simply 

an arithmetic average of the data in the 

corresponding load bin, based on a look back 

through 720 hours of quality-assured data. 

Appendix D also requires missing data 

substitution for fuel sulfur content, GCV, and 

density whenever the results of the required 

periodic sampling and analysis for any of these 

parameters are missing or invalid. The missing 

data approach is quite simple: the maximum 

potential value of the parameter is reported for 

each hour of the missing data period. 

Appendix E missing data substitution is 

relatively straightforward. When the QA/QC 

parameters are unavailable or outside the 

acceptable range of values, the substitute data 

value is simply the highest NOX emissions rate 

from the baseline correlation curve. When the 

measured heat input rate is above the highest 

value from the baseline testing, conservatively 

high NOX emission rates (and in some cases, the 

maximum potential NOX emissions rate (MER)) 

must be reported. For Appendix E units with 

add-on NOX emission controls, whenever 

the controls either are shut off or cannot be 

documented to be working properly, the fuelspecific MER must be reported. 

D.2.3.5 Conditional Data Validation 

When a significant change is made to a CEMS 

(e.g., replacement of an analyzer) and the system 

must be recertified, the CEMS must pass a series 

of recertification tests before it can be used to 

report quality-assured data. Recertification takes 

at least seven days (since a seven-day calibration 

error test is one of the required tests). However, 

while the recertification tests are in progress, the 

requirement to report emissions data for every 

unit operating hour remains in effect. Without 

regulatory relief, this could result in an extended 

period of missing data substitution, with a 

consequent loss of allowance credits. 

To alleviate this situation, section 75.20(b)(3) 

of Part 75 allows “conditional data validation” 

(CDV) to be used for recertification events. CDV 

provides sources with a means of minimizing the 

use of substitute data while a CEMS is being 

tested for recertification. To take advantage of 

this rule provision, as soon as the monitoring 

system is ready to be tested, a calibration error 

test should be performed. This is called the 

“probationary calibration.” If the probationary 

calibration is passed, data from the CEMS are 

assigned a “conditionally valid” status from that 

point on, pending the results of the recertification 

tests. 

If the required recertification tests are then 

performed and passed within a certain time 

frame, with no test failures, all of the 

conditionally valid data recorded by the CEMS 

from the date and hour of the probationary 

calibration to the date and hour of completion of 

the required tests may be reported as qualityassured. However, if one of the major 

recertification tests (e.g., a linearity check or 

RATA) is failed, then all of the conditionally 

valid data are invalidated and missing data 

substitution must be used until all of the required 

tests have been successfully completed. 

58 
Section D


Part 75 extends the use of CDV beyond 

recertification events. The procedures may also 

be used for initial certification, diagnostic testing, 

and routine QA testing. 

D.2.4 Electronic Reporting 

In U.S. SO2 and NOX emissions cap and trading 

programs, affected units are required to report 

electronic data of various kinds (e.g., emissions 

data, monitoring plan information, results of 

certification and QA tests, etc.) to EPA at certain 

times, as specified in Part 75. 

D.2.4.1 Initial Reporting 

The initial Part 75 electronic reporting 

requirements include the submittal of a 

monitoring plan and the results of the 

monitoring system certification tests. These 

requirements are discussed in Sections D.2.2.1 

and D.2.2.4 above. 

D.2.4.2 Quarterly Reporting 

For each affected unit, emissions data must be 

reported quarterly, beginning with either the 

date and hour at which all certification tests are 

completed (known as the date of “provisional 

certification”) or the date and hour of the 

certification deadline specified in the rule, 

whichever comes first. EPA uses the quarterly 

report data to assess compliance, by comparing 

each unit’s reported annual SO2 mass emissions 

and/or ozone season NOX mass emissions 

against the number of allowances held. 

The quarterly reporting of hourly emission 

data (as opposed, for example, to annual 

reporting) is critical to the success of cap 

and trade programs. Quarterly reporting eases 

the administrative burden associated with the 

data reconciliation and allowance accounting 

process, because it enables EPA and the affected 

sources to work together during the year or 

ozone season to correct any problems with the 

data, rather than waiting until the year or ozone 

season is over. By reducing the potential for 

erroneous emissions data, this process also 

increases the ability of sources to ensure that 

they have allowances, as of the allowanceholding deadline, at least equal to their total 

emissions and reduces the potential for 

violations. 

All quarterly reports must be submitted to 

EPA by direct computer-to-computer transfer, 

either by email or by using an EPA-provided 

software tool known as the Emissions Tracking 

System File Transfer Protocol, or ETS-FTP. The 

reports are due within 30 days after the end of 

each calendar quarter. During this 30-day 

submission period, the reports may be revised 

and resubmitted as many times as necessary. 

The data in each quarterly report must 

be in a standardized EDR format provided by 

EPA. 14 The DAHS must be capable of recording 

all of the necessary data and putting the data 

into this format. 

The quarterly EDR files must include the 

following essential information: 

•	 Facility information. 

•	 Hourly and cumulative emissions data. 

•	 Hourly unit operating information (e.g., 

load, heat input rate, operating time, etc.). 

•	 Monitoring plan information. 

•	 Results of required QA tests (e.g., daily 

calibrations, linearity checks, RATAs, etc.). 

•	 Certification statements from the designated 

representative or authorized account 

representative, attesting to the completeness 

and accuracy of the data. 

The data from each quarterly report submittal 

are recorded and stored in EPA’s ETS. The 

tracking system consists of the aforementioned 

submission software (i.e., ETS-FTP) and data 

checking routines, housed in an EPA mainframe 

computer. All sources must obtain an account 

and a password from EPA in order to submit 

14 The version 2.1 and 2.2 EDR formats and accompanying instructions are found on the CAMD Web site at 

http://www.epa.gov/airmarkets/reporting/edr21/index.html. 

59 
Canada-United States Emissions Cap and Trading Feasibility Study 

their EDR files. The success of the emissions cap 

and trading programs depends vitally on ETS. 

It instills confidence in allowance transactions 

by certifying the existence and quantity of the 

commodity (emissions) being traded in the form 

of allowances. 

Each quarter, EPA reviews and evaluates the 

EDR reports, using a four-step review process: 

•	 Data review. 

•	 Feedback to sources. EPA provides feedback 

to the sources, based on the results of the 

ETS and monitor data checking (MDC) 

software evaluations. The feedback reports 

indicate that either: 

—	 The data have been accepted and will 

be stored in the EPA mainframe for the 

purposes of annual reconciliation and 

dissemination. 

or 

—	 The EDR is unacceptable and contains 

“critical errors” that prevent the data from 

being used for allowance accounting and 

dissemination. 

•	 Data resubmission. EPA requires reports with 

critical errors to be resubmitted by a specified 

deadline (generally within 30 days). 

•	 Data dissemination. All data are reviewed, 

and preliminary and final emission data 

reports are prepared for public release and 

compliance determination. 

D.2.5 Audits and Inspections 

When emissions data are reported in a 

standardized electronic format such as the EDR, 

regulatory agencies can develop software 

tools with which to audit the data. The results 

of these electronic audits can serve as a basis 

for targeting problem sources, either for more 

comprehensive electronic audits or for field 

audits. In the Part 75 audit program, both 

electronic audits and field audits are routinely 

performed. 

D.2.5.1 Part 75 Electronic Audit Program 

EPA’s CAMD performs routine electronic audits 

on the Part 75 electronic quarterly reports, 

using the ETS and MDC software tools. EPA also 

occasionally performs special (ad hoc) electronic 

audits to look for other specific data reporting 

problems (e.g., incorrect application of the 

missing data routines). 

EPA has made the MDC software available 

to all via the Internet. 15 Also, ETS has a “test” 

region where quarterly reports can be sent to 

receive a preliminary feedback report. Thus, the 

regulated sources can prescreen their EDR data 

prior to official submittal. This greatly reduces 

the number of required resubmittals due to 

critical errors. 

D.2.5.2 Audit Targeting 

EPA has recently developed an electronic 

auditing software tool known as the Targeting 

Tool for Field Audits (TTFA). This tool is intended 

to be used primarily by state agencies to assist 

them in targeting sources for field audits. The 

TTFA tool is capable of identifying a variety of 

CEMS operation and maintenance problems, 

such as monitoring systems with an excessive 

number of failed calibration error tests or 

linearity checks, sources with long periods of 

monitor downtime, and monitoring systems 

with improperly set span and range values. 

D.2.5.3 Field Audits 

EPA relies primarily on state and local agencies 

to conduct field audits of Part 75-affected 

sources. In many instances, the field audits are 

integrated with routine source inspections. The 

audits encourage good monitoring practices by 

raising plant awareness of Part 75 requirements. 

Field audits generally include the following 

activities: 

15 The MDC software and information on how to use it can be found at http://www.epa.gov/airmarkets/monitoring/mdc/index.html. 

60 
Section D


•	 Preparation (e.g., monitoring plan review, 

examination of historical EDR data using 

MDC or the TTFA, etc.). 

•	 On-site inspection of the monitoring 

equipment and system peripherals. 

•	 Records review. 

•	 QA test observations. 

•	 Interviews with the appropriate plant 

personnel. 

EPA has developed a Field Audit Manual, 

which is available on the Internet. 16 The Field 

Audit Manual details recommended procedures 

for conducting field audits of Part 75 CEMS. 

The manual includes tools that can be used to 

prepare for an audit, techniques that can be used 

to conduct the on-site inspections and records 

review, proper methods for observing QA tests, 

and guidelines for preparing a final report. 

Checklists are also provided that can be used 

to ensure that all necessary data are obtained 

during the audit. EPA has designed the audit 

procedures in the manual so that personnel with 

varying levels of experience can use them. 

D.3 ENVIRONMENT 

CANADA’S PROTOCOL FOR 

CONTINUOUS EMISSION 

MONITORING SYSTEMS 

(REPORT EPS 1/PG/7) 

D.3.1 Description 

In September 1993, Environment Canada 

published “Protocols and Performance 

Specifications for Continuous Monitoring of 

Gaseous Emissions from Thermal Power 

Generation,” Report EPS 1/PG/7. This document 

was developed to provide guidance on 

Environment Canada’s expectations for the 

performance of CEMS for electric power 

generation units. In 2005, EPS 1/PG/7 has 

been revised with minor changes and additions 

to address specific issues raised by stakeholders. 

This revision does not change the overall context 

of the report. 

EPS 1/PG/7 provides specifications for the 

design, installation, and operation of automated 

CEMS used to measure gaseous releases of 

SO2 and NOX from fossil fuel-fired steam electric 

generating facilities. It presents procedures 

used to determine the various CEMS parameters 

during initial certification testing and subsequent 

long-term operation of the monitoring system. 

Additionally, guidelines are provided to assist 

in the development of a site-specific QA/QC 

plan, in conjunction with the appropriate 

regulatory agency. The resulting plan forms 

an integral part of the overall requirements for 

the operation of each CEMS. 

EPS 1/PG/7 is a technical document that 

may be used by regulatory agencies for setting 

requirements to achieve accurate measurement 

of NOX and SO2 emissions via CEMS. It does not 

set out the policy context for monitoring; nor 

does it specify where CEMS must be used or how 

they must be used to support operating permits, 

emission caps, or emission trading systems. This 

is left to the appropriate regulatory agency. 

D.3.2 Summary of Current Use in Canada 

D.3.2.1 Application within the Thermal Power 

Generation Sector 

The requirements specified in EPS 1/PG/7 are 

recommended guidelines from the federal 

government. It is left to regulatory agencies 

to implement them. 

EPS 1/PG/7 has been widely used by 

Canadian provinces in establishing their own 

CEM requirements. Two of Canada’s provinces, 

Ontario and Alberta, have adopted EPS 1/PG/7 

as a basis for their provincial CEM requirements. 

The Greater Vancouver Regional District, a 

region within British Columbia, has also adopted 

EPS 1/PG/7 by reference. 

Other jurisdictions do not have explicit 

requirements for CEMS. In these areas, the issue 

of monitoring is approached on a case-by-case 

basis, and any requirements are outlined in a 

16 The Field Audit Manual is found at http://www.epa.gov/airmarkets/monitoring/auditmanual/index.html. 

61 
Canada-United States Emissions Cap and Trading Feasibility Study 

source’s operating permit. Often, EPS 1/PG/7 

requirements, or sections thereof, are referenced 

within these approvals. 

D.3.2.2 Application within Other 

Industrial Sectors 

Although it was originally intended for the 

thermal power generation sector, EPS 1/PG/7, 

or sections thereof, has been applied to CEMS 

in industrial sectors. Examples include cement 

kilns, smelters, pulp and paper units, wood-fired 

boilers, municipal and biomedical incinerators, 

and cremators. Typically, EPS 1/PG/7 is 

referenced in the unit’s operating permit. 

D.4 ANALYSIS 

D.4.1 Differences between Canadian and U.S. 

Monitoring Requirements (EPS 1/PG/7 and 

40 CFR Part 75) 

Many of the differences 17 between EPS 1/PG/7 

and 40 CFR Part 75 are a result of the context 

in which the two monitoring tools have been 

developed. In Canada, EPS 1/PG/7 is a technical 

document that may be used by regulatory 

agencies for setting requirements to achieve 

accurate measurement of NOX and SO2 

emissions. It does not specify where CEMS must 

be used or how they must be used to support 

operating permits, emission caps, or emission 

trading systems. In the United States, 40 CFR 

Part 75 was developed specifically for an 

emissions cap and trading regime. From this 

wider scope, many additional requirements 

relating to accountability, transparency, and 

other aspects necessary for an effective trading 

regime are encompassed in the regulation. These 

requirements serve to maintain the credibility 

of a program where the emissions monitored 

acquire monetary value as tradable commodities. 

Other differences between the two systems 

are more technical in nature and are simply 

different methods for meeting similar objectives 

concerning performance specifications, test 

procedures, and QA procedures. Some of the key 

differences between EPS 1/PG/7 and 40 CFR Part 

75 are: 

•	 Data acquisition system requirements—These 

are less detailed in EPS 1/PG/7. 

•	 Bias—EPS 1/PG/7 has specific limits to bias. 

Bias adjustment factors are allowed for both 

high and low bias, if the bias is within the 

specific limits. 40 CFR Part 75 allows high 

bias, and adjustment factors are required for 

low bias. 

•	 EDRs—EPS 1/PG/7 does not require EDRs. 

This is specified in detail in 40 CFR Part 75 

and is necessary for compliance 

determination and QA programs that are 

based on the submitted EDRs. 

•	 Missing data—Requirements for missing 

data in 40 CFR Part 75 are more detailed 

than in EPS 1/PG/7. 

•	 Unit operating data—EPS 1/PG/7 does not 

have the requirements for submitting fuel 

usage, fuel GCV, etc., that are specified in 

40 CFR Part 75. 

•	 Flow monitors—EPS 1/PG/7 allows the 

use of heat rate calculations using heat input 

rate and F-factors or other engineering 

calculations for determining flow, while 40 

CFR Part 75 requires flow monitors, with 

some exceptions for gas- and oil-fired units. 

•	 Procedural differences—Numerous procedural 

differences exist between the two systems 

because of the extensive prescriptive 

requirements of 40 CFR Part 75. These 

include: 

—	 The quarterly submission of monitoring 

plans and QA performance test data. 

—	 The certification of the data by a 

corporate designated representative or 

authorized account representative. 

—	 The QA check of the submitted EDRs 

by EPA computers. 

17 Much of the information in Section D.4 was obtained from Jahnke (2001, 2004). 

62 
Section D


Within an emissions cap and trading regime, 

the monitoring and reporting requirements 

provide the basis for guaranteeing the value 

of the allowances to be traded. While accuracy 

is essential, of equal importance is consistency 

in the methods by which the emissions 

are monitored and reported. Hence, these 

requirements must be harmonized so that 

the allowances traded among facilities are 

considered fungible under a cross-border 

emissions cap and trading regime. 

With 40 CFR Part 75, EPA has already 

developed requirements to meet the needs of an 

emissions cap and trading program that are not 

currently present in Canada. Additionally, the 

United States has gained experience in trading of 

emissions and the associated monitoring needs 

under the Acid Rain Program, which began in 

1995. This is true at both the government level 

and within the electric power generating sector 

itself. 

Should Canada participate in a joint 

emissions trading program with the United 

States, Canada should be prepared to implement 

40 CFR Part 75. 

D.4.2 Impact of Implementing 40 CFR Part 75 

in Canada 

D.4.2.1 Consistency with EPS 1/PG/7 

Despite the differences between 40 CFR Part 75 

and EPS 1/PG/7, the directions of the two 

documents are consistent. EPS 1/PG/7 provides 

options for meeting its requirements and does 

not specify any particular type of CEMS. If a 

cross-border emissions cap and trading system 

were established, participants would be able to 

choose appropriate equipment to meet EPS 

1/PG/7 in such a way that it would contribute 

to meeting 40 CFR Part 75 requirements at a later 

date. 

D.4.2.2 Required Upgrades/Changes at 

Electricity Generating Units 

Currently, no Canadian CEMS is equivalent to 

a U.S. CEMS meeting 40 CFR Part 75. This is not 

to imply that a Canadian system is necessarily 

less accurate or precise. However, due to the 

differences in EPS 1/PG/7 and 40 CFR Part 75 

and the absence of a national emissions cap 

and trading regime in Canada, certain elements 

have not been included. The following 

describes some of the upgrades/changes that 

would be needed if 40 CFR Part 75 were to be 

implemented at Canadian facilities. 

One of the key changes to be made is to 

require the use of DAHS software to generate 

EDRs. One option is to purchase commercial 

Part 75 software. Canadian facilities, however, 

have a tradition of in-house programming for 

their CEMS and may develop software on their 

own. In a cross-border emissions cap and 

trading regime, the regulator will check all EDRs 

for proper formatting and internal consistencies, 

necessitating a clear understanding of the 40 

CFR Part 75 requirements if this second option 

is chosen. In the United States, only three 

of 2,100 affected sources developed their own 

software, and they have since replaced it with 

readily available commercial alternatives. 

Most Canadian systems will also need to 

change their missing data and bias routines 

and add plant operating inputs to a DAHS for a 

complete EDR. This will come as part of the 

package if commercial software is purchased, 

as described above. 

The use of flow monitors is mandatory in the 

U.S. program, with a few exceptions for gas- and 

oil-fired units. While some plants in Canada use 

flow monitors to compute mass emission rates, 

others use heat input/F-factor calculations and 

will need to install flow monitors. 

Additionally, RATA, calibration, and QA 

criteria are more extensive in 40 CFR Part 75 

than in EPS 1/PG/7. While no additional 

hardware would be required for Canadian units 

with flow monitors, further work would be 

necessary for meeting the more comprehensive 

performance specifications. A modification of the 

software may also be necessary for installing 

algorithms for calculations of the flow-to-load 

test. 

63 
Canada-United States Emissions Cap and Trading Feasibility Study 

In contrast to the United States, many 

Canadian EGUs have installed in situ CEMS 

(both path and point). These systems may not 

be designed to meet daily calibration checks or 

quarterly cylinder gas checks with protocol gases 

according to 40 CFR Part 75. Those with pathtype monitors would have difficulty modifying 

existing equipment to meet these requirements. 

Those with probe monitors employing a slotted 

tube could retrofit with a sintered tube, which 

could accept calibration gases. Sintered probe 

monitors are installed on some Canadian plants 

and have been installed in the United States to 

meet 40 CFR Part 75 requirements. 

For units that use CEMS to quantify SO2 or 

NOX mass emissions (e.g., coal-fired units), 

40 CFR Part 75 requires the use of stack flow 

monitors, which measure on a wet basis. 

However, if the SO2 or NOX monitor measures on 

a dry basis, corrections for stack gas moisture 

content must be applied when calculating the 

emissions. Therefore, the source must either 

continuously monitor the moisture content or 

use an approved default moisture value. While 

most gas monitoring systems in Canada measure 

on a wet basis, some use cool dry extractive 

technology, which would require moisture 

corrections to accurately calculate the SO2 or 

NOX mass emissions. 

Total NOX emissions, comprising both nitric 

oxide (NO) and nitrogen dioxide (NO2), are 

required in 40 CFR Part 75. Several units 

in Canada measure NO only. These facilities 

may be able to use a correction factor in the 

DAHS to account for discrepancies between 

total NOX and NO or between the CEMS and the 

chemiluminescence reference test method that is 

required by the U.S. system. If this is not sufficient, 

the existing systems can be modified with the 

addition of an NO2 channel. 

The procedural requirements of 40 CFR 

Part 75 have resulted in the development of a 

“monitoring culture” within the United States, 

which is characterized by greater management 

control and resource allocation than that found 

in Canada. By necessity, there is corporate 

management responsibility and interest in the 

CEM program and the availability of capital 

and operating funds to maintain the CEMS in 

compliance with 40 CFR Part 75. It is likely that 

this support for the CEM program would develop 

if Canada were to participate in a cross-border 

emissions cap and trading program. 

D.4.2.3 Perspectives on CEMS in Other 

Industrial Sectors in Canada 

While the electric utility sector and industrial 

boilers were initially identified as prime 

candidates for a joint U.S.-Canada emissions 

trading program, two other sectors—base metals 

smelting and cement kilns—have also been 

identified as potential players in Canada. The 

base metals smelting industry is the largest 

single contributor to SO2 emissions in Canada. 

The cement manufacturing industry is one of 

Canada’s top 10 industrial sectors for the 

emissions of both NOX and SO2, and it is also a 

sector whose emissions can be easily monitored 

at the unit level. The implementation of 40 CFR 

Part 75 in these sectors is briefly presented 

below. 

Cement Plants 

In Canada, most cement plants have installed 

CEMS. These systems are typically extractive 

systems that can accept calibration gases, 

although some do have in situ systems installed. 

Flow monitors may or may not be installed, 

depending upon the form of the provincial 

reporting requirements. If 40 CFR Part 75 

requirements were to be implemented in the 

cement sector, DAHS upgrades and possibly the 

addition of flow monitors would bring them into 

conformance with 40 CFR Part 75 requirements. 

Smelters 

In Canada, it is viewed that smelters, in 

general, have monitors installed for measuring 

SO2 emissions, either for process or for 

environmental monitoring. Flow monitors may 

or may not be installed, depending on permit 

64 
Section D


reporting requirements. Monitoring of SO2 

emissions from smelter stacks is relatively 

easy due to the high concentration of the SO2 

emissions. Emissions are typically on the 

order of thousands of parts per million, 

which are not difficult to measure using either 

extractive or in situ systems. Implementing 40 

CFR Part 75 at Canadian smelters would include 

the incorporation of flow monitors (if necessary) 

and the addition of software that would generate 

a 40 CFR Part 75 EDR. For higher concentrations, 

some difficulty might be experienced in obtaining 

protocol gases in the appropriate concentration 

range. In some cases, monitoring systems would 

have to be upgraded to meet the performance 

specifications of 40 CFR Part 75. 

Fugitive emissions from smelters, however, 

may play a role in overall emissions; this may 

lead to difficulties in monitoring within an 

emissions trading system. Further information 

is required on this issue. 

D.5 SUMMARY 

Within an emissions trading regime, the 

monitoring and reporting requirements provide 

the basis for guaranteeing the value of the 

allowances to be traded. While accuracy is 

critical, the method by which the emissions are 

monitored and reported is also important. These 

requirements must be harmonized between the 

United States and Canada so that the allowances 

traded among facilities are considered fungible 

under a cross-border emissions cap and trading 

regime. 

Current CEM requirements in the United 

States for the existing emissions cap and 

trading programs (Acid Rain Program and the 

NOX Budget Trading Program) are contained 

in 40 CFR Part 75 – Continuous Emission 

Monitoring. In Canada, the federal government 

has established guidelines, as distinguished 

from regulations as in the United States, for 

CEMS for thermal power plants in EPS 1/PG/7, 

“Protocols and Performance Specifications for 

Continuous Monitoring of Gaseous Emissions 

from Thermal Power Generation.” 

Many differences between EPS 1/PG/7 and 

40 CFR Part 75 are technical in nature, relating to 

the methods for determining accuracy. Other 

differences are a result of the context in which the 

two monitoring tools have been developed. EPS 

1/PG/7 lacks specific requirements for electronic 

data reporting and verification, whereas in 40 CFR 

Part 75, these have been developed and are 

widely utilized by U.S. government and industry. 

With 40 CFR Part 75, EPA has established 

requirements to meet the needs of an emissions 

trading program not currently present in Canada. 

Additionally, the United States has gained 

experience in monitoring and trading of 

emissions under the Acid Rain Program, which 

began in 1995. This is true at both government 

and state levels and within the electric power 

generating sector itself. In order to have 

equivalency of allowances traded among U.S. 

and Canadian facilities, there would need to be 

a high level of consistency between the systems 

in the two countries with respect to accuracy, 

accountability, transparency, predictability, and 

flexibility. 

Also, the number of units in the existing U.S. 

cap and trading programs that have already 

installed CEMS to meet the U.S. requirements 

significantly outnumber the potential units in 

Canada that would be included in a cross-border 

emissions cap and trading program. Therefore, 

if a cross-border emissions cap and trading 

system were established, then 40 CFR Part 75 

requirements would need to be implemented in 

Canada. 

The implementation of emission and 

monitoring requirements at Canadian facilities 

comparable to those in the United States is 

technically feasible. Any Canadian facility 

following EPS 1/PG/7 should not need to replace 

an entire CEMS, but need only upgrade or add 

on to its existing system, in order to be 40 CFR 

Part 75 compliant. This may involve additional 

hardware, software, and QA/QC procedures 

to conform to operation and maintenance 

requirements of the emission monitoring 

provisions. 

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Canada-United States Emissions Cap and Trading Feasibility Study 

D.6 REFERENCES 

Jahnke, J.A. (2001). “Continuous Emission 

Monitoring Issues for Cross-Border 

Emissions Trading – Final Report.” Ref: 

STA:ENVC:2904R, December 14, 2001. 

Report to Environment Canada. 

Jahnke, J.A. (2004). “Emission Trading Status of 

Continuous Emission Monitoring (CEM) 

Systems in Canada – Final Report.” Ref: 

STA:ENVC:5155, May 25, 2004. Report to 

Environment Canada. 

66 
Allowances are the tradable units of an 

emissions cap and trading program. Each 

allowance, issued by a governing agency, is an 

authorization to emit a specific quantity of a 

particular pollutant. In other words, an allowance 

is required for emitting a certain quantity of a 

regulated gas (e.g., nitrogen oxides (NOX), sulfur 

dioxide (SO2)) from regulated activities. By the 

end of each true-up, or reconciliation, period that 

follows the compliance period, participating 

sources must submit (or the government must 

deduct) the appropriate number of allowances to 

compensate for their emissions during the 

compliance period. 

Allowances are a commodity with an 

economic value. Because allowances are 

tradable, this value is revealed through the 

market. In turn, the allowance price provides 

useful information for regulated entities when 

developing their compliance strategies. Emitters 

are able to compare their abatement costs with 

the expected allowance price to assess the most 

cost-effective way to meet the compliance 

requirements. 

To simplify program design and operation, 

reduce transaction costs, and increase the 

economic effectiveness of a program, allowances 

should be fungible—that is, each allowance 

should be interchangeable with other allowances 

in the program. Simplicity is enhanced by 

avoiding the creation of different categories 

of allowances with different attributes. 

This section describes allowances and their 

use in a cross-border emissions cap and trading 

program context, including areas of jurisdictional 

flexibility such as allowance allocation 

methodologies. Allowance serialization, 

allowance distribution and timing, banking, and 

other aspects of allowance use are discussed. 

This section also presents anecdotal experience 

with allowances in the existing U.S. emissions 

cap and trading programs. 

Section E 

ALLOWANCES USE 

E.1 UNIT OF MEASUREMENT 

An allowance is defined by the amount of 

emissions it allows. In the U.S. Acid Rain 

Program, for instance, one allowance is currently 

equivalent to one ton of SO2. In a cross-border 

trading system, using a common unit of measure 

would offer a simpler solution than having two 

heterogeneous “goods” to trade that generate 

two prices: one for the U.S. allowances and one 

for the Canadian allowances. Using a different 

unit of measurement to define allowances 

would also make the compliance process more 

complex, necessitating the use of conversion 

factors to compare the number of allowances 

submitted for compliance with the actual level 

of emissions. 

E.2 ALLOWANCE 

SERIALIZATION 

Allowances may be serialized (i.e., assigned a 

single and unique number or code) to facilitate 

tracking from creation to compliance use. 

There are a number of benefits to identifying 

allowances by serial number. The use of serial 

numbers facilitates record-keeping so that 

allowance holders can track the different costs 

incurred in acquiring allowances. (This may 

be useful for tax purposes.) Tracking provides 

additional transparency and protection against 

accounting discrepancies. Finally, the inclusion 

of serial numbers in the allowance tracking 

system (ATS) provides the opportunity 

to analyze trading patterns and the movement 

of allowances over time. This may be useful for 

assessing the impacts of the trading program. 

At a minimum, allowances must be identified 

by vintage (i.e., the compliance period for 

which they are issued) to determine when the 

allowances are authorized for compliance use. 

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Canada-United States Emissions Cap and Trading Feasibility Study 

E.3 ALLOWANCE 

DISTRIBUTION 

The distribution of allowances can be one of 

the most politically contentious issues when 

designing an emissions cap and trading program. 

Distribution decisions have economic, equity, 

and political consequences. Because an 

emissions cap and trading program creates new 

assets with economic value, participants who 

receive the allowances at no cost through an 

allocation capture the economic gains from 

these assets. Under an auction, the auctioning 

agency (e.g., the government or jurisdiction) 

captures the value of the assets. 

The first decision in the allowance allocation 

process is which method will be used for 

distribution. Allowances can be distributed 

through an auction or directed allocation, or 

some combination of the two systems. To date, 

most U.S. emissions cap and trading programs 

have used directed allocations to distribute the 

majority of allowances. Some programs have a 

supplemental auction of allowances to ensure 

liquidity and to facilitate the entrance of new 

regulated entities into the system. Experience 

with the U.S. Acid Rain Program has shown that 

establishing an auction to ensure liquidity was 

not necessary, because the allowance markets 

are working well. 

The distribution of the allowances has, 

generally speaking, little impact on the costeffectiveness or environmental integrity of the 

emissions trading program. As a result, in a 

cross-border emissions cap and trading program, 

the method by which allowances are distributed 

does not need to be the same in Canada and the 

United States. As long as the cap is respected, 

the method of distributing allowances could be 

shared with state and provincial governments. 

However, since distribution has an impact 

on the burden sharing of the total cost of 

abatement, it is a key design element of the 

trading system. Distribution is particularly 

important because it impacts the perception 

of the system’s equity as a whole and thus its 

political acceptability. There is not a single 

definition of equity. Some may find a directed 

allocation inconsistent with the “polluter pays” 

principle. Others may find it inappropriate to 

require emitters to pay for any emissions plus 

abatement costs when the environmental goal 

is to reduce rather than eliminate emissions. 

Whatever distribution method is selected, 

some allowances from within the cap may be 

set aside. The set-aside allowances (see Section 

E.9) can be used to allocate allowances to new 

sources or to create incentives or compensation 

for certain types of behavior (e.g., early 

reductions, energy efficiency measures, or 

renewable energy generation). 

E.3.1 Auctions 

Auctions are one method for distributing 

allowances. Under this approach, participating 

sources are required to bid for the number of 

allowances they would like to purchase. 

Generally, the highest bidders receive the 

allowances at their specified price or at the 

clearing price. Allowance auctions provide 

numerous benefits including the internalization 

of the environmental cost of air emissions 

upfront by industry. Among the benefits are: 

1) auctions create a source of revenue that 

can be used to offset administrative expenses 

or be distributed to affected groups; 2) auctions 

enable the governing authority to collect 

“windfall” profits that might otherwise accrue to 

participating sources under a directed allocation 

approach; 3) auctions avoid some politically 

contentious issues regarding allocation 

methodologies (although auctions may involve 

other politically contentious issues, such as how 

to use auction proceeds); 4) the winning bids 

provide the market with a price signal that 

helps participating sources create a cost-saving, 

environmentally effective compliance strategy; 

and 5) auctions provide equal opportunities 

for new emission sources. 

Auctions may be used to distribute only a 

portion of allowances, with the remainder 

68 
Section E


distributed by a directed allocation method. 

Some analysts have proposed beginning with 

a directed allocation system and eventually 

transitioning to an auction-based system. This 

would increasingly internalize costs over time and 

may decrease political opposition from emission 

sources worried about the cost of allowances. 

E.3.2 Directed Allocations 

Despite the advantages of actions, the three 

major U.S. trading systems all rely on directed 

allocations. 

There are at least two important factors to 

consider when designing a directed allocation 

approach: baselines and benchmarks. The 

baseline is the year or years of historical (or 

predicted) data that are used to calculate the 

allowance allocation. An important distinction 

among baseline approaches is whether the 

baseline is permanent or changes over time. A 

“permanent baseline” results in a fixed allowance 

allocation in perpetuity, although it may provide 

for changes that are specified in advance, such 

as a fixed reduction each year. The alternative is 

an “updating baseline” in which the allocation 

changes over time based on the activities of the 

participating sources (e.g., increased production 

as a proportion of total production levels). A 

permanent baseline, therefore, establishes a 

fixed distribution of allowances, whereas an 

updating baseline allows for the redistribution 

of allowances. 

Permanent and updating baselines differ in 

the incentives they create. A permanent baseline 

generally has no impact on the decisions of 

the participating sources once the system is 

implemented. In theory, an updating baseline 

influences the decisions made by the operators 

of participating sources. Because an updating 

baseline periodically changes the allocation, some 

sources may have an incentive to do more of the 

activity that will earn them additional allowances. 

This effect, however, will be influenced by the 

demand for the product, cost of the activity, and 

value of allowances. 

Benchmarks, or metrics, are the type of 

data that are used to calculate the allowance 

allocation. Different benchmarks include 

historical fuel or heat input, output, or emissions. 

Each benchmark produces different “winners” 

and “losers.” 

A directed allocation could be based on any of 

the benchmark measures. The allocation could be 

based on different benchmarks for different levels 

if the allocation is a multistage process (e.g., the 

national authority allocates to state/provincial 

authorities, which then allocate to the sources). 

E.3.2.1 Inputs 

Fuel or heat input is one benchmark approach. 

To calculate the allocations, fuel usage or 

energy input data are multiplied by an emissions 

performance metric (e.g., emissions per unit of 

fuel input). When a single performance metric 

is used for all sources, an input benchmark 

rewards participating sources that are inherently 

cleaner (e.g., natural gas units), have installed 

emission reduction controls, or pursued early 

reductions, because those sources’ emission 

rates may be below the performance metric. This 

approach can work well if the emission sources 

have a variety of outputs or cross several 

industrial sectors (e.g., electric generating units, 

cement kilns, and pulp and paper facilities). 

E.3.2.2 Outputs 

Output is another benchmark approach. To 

calculate the allocations, production data are 

multiplied by an emissions performance metric 

(e.g., emissions per unit of electricity produced). 

When a single performance metric is used for 

all sources, an output benchmark rewards 

participating sources that are inherently cleaner, 

operate efficiently, install emission reduction 

controls, or pursue early reductions. This 

approach can work well if the sources and/or 

industries produce a homogeneous product (e.g., 

electricity). If the product is heterogeneous, the 

allocating authority must convert the products 

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Canada-United States Emissions Cap and Trading Feasibility Study 

to a uniform unit or apply different emission 

performance metrics for each product. 

E.3.2.3 Emissions 

Emissions are the final benchmark approach. 

Allocations are calculated based on a 

participating source’s relative share of total 

emissions. This approach rewards the highest 

emitting and least efficient sources. It also 

penalizes participating sources that pursue early 

emission reductions, install pollution controls, 

or operate efficiently, because their emissions 

are lower. When combined with an updating 

baseline approach, an emissions benchmark 

weakens incentives for emission reductions. 

E.3.2.4 Other Considerations 

Several other issues must be addressed if a 

directed allocation approach is used. These 

include the following: 

•	 Baseline Period: The baseline period for 

allocations could be historic, current, or even 

projected. The relative importance of the 

baseline period increases with the length of 

the allocation. Allocations using historical 

baseline periods are attractive to large 

sources that typically operate near capacity or 

had an important share of the benchmark, 

because they are guaranteed a relatively large 

proportion of the allocated allowances. 

•	 Updating Frequency: If an updating baseline 

approach is used, the length of the interval 

between allocations may affect the level 

of influence that updating has on future 

behavior. For example, if updating is done 

annually based on output, in theory, it could 

provide a strong incentive to increase output 

in order to receive additional allowances. 

If, however, the time period is longer (e.g., 

10 years), the effect will be considerably less. 

Permanent allocations, on the other hand, 

provide no such incentive, because changes 

in behavior will not affect future allocations. 

•	 Length of Allocation: Allowances may be 

allocated to emission sources in advance of 

the allowances’ vintage period (i.e., the period 

in which the allowances can be used for 

compliance). Having allowances allocated 

in advance can add liquidity to the market, 

because sources and other market participants 

can trade allowances on the spot market for 

use in future years. This also helps emission 

sources develop and implement compliance 

strategies in advance of the compliance period 

(e.g., a source that installs an emission control 

device can sell future excess allowances to 

generate revenue to help offset the cost of 

the control). 

•	 Preserving the Cap: After a baseline and 

benchmark are applied, the resulting total 

allocations should be compared with 

the intended cap. If too many or too few 

allowances were created while calculating 

allocations, a ratchet (i.e., a formula that 

adjusts each allocation proportionately) can 

be applied. The resulting total allocation will 

then match the number of allowances in the 

cap. This ensures that the cap is not inflated 

through the allocation process. 

•	 Incorporating New Sources: New entrants 

to the program must obtain allowances to 

participate in the program. In some allocation 

schemes with updating baselines, new 

emission sources may receive allowances. 

In the case of permanent allocations, new 

sources may need to obtain allowances from 

the market. Alternatively, a set-aside could be 

created for new entrants. The set-aside could 

hold a specific percentage of the overall cap 

to cover growth in new sources. 

Many analysts have noted that both 

economic theory and empirical experience 

suggest that there is not a competitive barrier 

to new entrants that do not receive directed 

allowance allocations in emissions cap and 

trading programs. They argue that emission 

sources receiving directed allowance allocations 

have the same marginal “opportunity cost” for 

every ton emitted as the marginal cost paid by 

the new entrant. In support of this argument, 

70 
Section E


there is no evidence of entry problems for new 

electric power plants under the U.S. SO2 Acid 

Rain Program, which requires new power plants 

to purchase all their needed allowances on the 

market. There has been significant entry by new 

units, even coal-fired units that do not receive a 

directed allowance allocation. 

E.4 ALLOCATION TIMING 

In order to provide affected sources with the 

certainty necessary to develop a compliance 

strategy, the rules for the allocation of 

allowances must be completed and known by 

the operators of the affected sources prior to the 

beginning of the compliance period, preferably 

several years in advance. 

E.5 BANKING 

Allowances are usually allocated for use in a 

specific compliance period. The vintage of the 

allowance identifies the period in which it is 

eligible to be used. If allowances are unused, 

they may expire (i.e., be invalidated) or be 

banked (i.e., carried forward) for compliance 

use in future periods. Banking avoids allowance 

price instability and increased use of allowances 

(and thus increased emissions) around the end 

of the compliance period. Providing participating 

sources the ability to bank allowances creates 

additional flexibility, encourages early 

reductions, may reduce compliance costs, and, 

therefore, may increase economic and political 

support for the program. 

The biggest environmental gains 

from banking come from early reductions. 

If a participating source reduces emissions 

more than is required in the early years of 

the program, the source can bank its surplus 

allowances for use in the future. This can, 

however, delay the achievement of an overall 

environmental goal if banked allowances 

are used. Because banking does not delay 

achievement of cumulative reductions, this 

tradeoff does not represent an environmental 

concern for problems such as acid deposition, 

where the environmental problem is caused 

by total accumulation of a pollutant in the 

atmosphere. If the relationship between 

emissions and environmental damage is linear, 

the environmental benefits of reducing emissions 

early to bank allowances should offset the 

environmental costs of using these banked 

allowances. In such a case, banking would be 

environmentally neutral at worst. 

Banking (or the use of banked allowances) 

could also be limited when the relationship 

between emissions and environmental damage 

is not linear. This is to avoid important 

environmental damage if emissions peak 

significantly over the normal level due to the 

use of too many banked allowances. For 

problems such as ground-level ozone, where 

there is concern over short-term episodes of 

high emissions, the benefits of banking must 

be weighed against the potential effects. 

However, the U.S. experience has shown that 

limits on banked allowance use often complicate 

or hinder the operation of emissions cap and 

trading programs and fail to provide apparent 

benefits. 

E.6 BORROWING 

Borrowing would be the use, during a current 

period, of allowances to be allocated in a 

future period. Because borrowing could easily 

jeopardize the credibility of the trading system, 

borrowing has never been allowed in U.S. 

systems. 

E.7 PROPERTY RIGHTS 

An important consideration in the design of 

emission trading programs is whether emission 

allowances are defined as property rights for 

allowance holders. If an allowance is defined as 

a property right, it could limit the government’s 

ability to adjust the cap or make necessary 

program changes at a later date. An emission 

allowance should remain analogous to any other 

type of authorization granted by government, 

such as a license to broadcast or to fish. In this 

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Canada-United States Emissions Cap and Trading Feasibility Study 

way, the regulator retains the ability to modify 

or revoke allowances and avoids claims by the 

regulated industry that allowances cannot be 

taken from it without compensation or that it 

has a right to future allocations. Existing cap and 

trade programs expressly prohibit any property 

rights in their emission allowances. For example, 

the U.S. SO2 allowance trading program (section 

403(f) of Title IV of the Clean Air Act) states: 

(f) Nature of Allowances. – An allowance 

allocated under this title is a limited 

authorization to emit sulfur dioxide in 

accordance with the provisions of this title. 

Such allowance does not constitute a property 

right. Nothing in this title or in any other 

provision of law shall be construed to limit 

the authority of the United States to terminate 

or limit such authorization. 

The government can limit or terminate 

authorizations to emit. In this way, the 

government retains the ability to amend, revoke, 

or reallocate emission allowances. The ability 

to reallocate allowances is essential if the 

government wishes to lower the cap on total 

emissions at a future date. However, in 

exercising the authority to limit or terminate 

authorizations to emit, it is important to take 

account of the potential effect on sources’ 

willingness to rely on the allowance trading 

system in making compliance and investment 

decisions. For example, when replacing existing 

authorizations by new authorizations, it may be 

desirable to provide some credit to sources 

holding existing authorizations. 

E.8 TRANSPARENCY 

By providing data and information in a 

transparent manner, cap and trade programs can 

build public confidence by revealing how well the 

program is enforced and ensuring accountability 

for each unit of emissions. Transparency can 

also increase the efficiency of the market and 

reduce transaction costs by enabling participants 

to identify potential buyers and sellers. True 

transparency, however, requires providing the 

information in a useful and informative format. 

Full transparency with public access to 

information, such as the number of allowances 

allocated to affected entities and the number 

of allowances in each account, is a key 

component to maintain the environmental 

integrity of the emissions cap and trading system. 

Full transparency could also reinforce incentives 

for good environmental behavior because of 

public awareness of the use of allowances. In the 

United States, price information is not provided by 

the U.S. Environmental Protection Agency (EPA) 

(except in auctions). Not only has provision of 

such information by EPA not been necessary, 

but given the wide variation in the circumstances 

of allowance transactions (e.g., transactions 

involving future delivery or transactions coupling 

allowances with other commodities such as fuel), 

such price data are likely to be confusing and of 

little use (see Section F.4.2 for further discussion 

on price). 

E.9 SET-ASIDES 

Another tool that can be used in allowance 

distribution is an allowance set-aside. Under 

a set-aside, a certain number of allowances 

within the cap are withheld for a specific purpose. 

The set-aside can be defined as a fixed number 

of allowances or as a percentage of the total 

allowance budget. 

The set-aside allowances can be distributed 

for a variety of purposes, including incentives 

for certain technologies, for energy efficiency or 

renewable energy programs, as a way to address 

equity issues, or as a reserve for new entrants to 

the program. 

It is important to also consider how surplus 

allowances from the set-aside will be managed if 

they are not distributed. Options include retiring 

the allowances, saving them for future use, 

and distributing them to sources through an 

allocation or auction. Retiring decreases the 

quantity of allowable emissions (i.e., the cap) 

and may therefore increase compliance costs 

for sources. Saving for the future may provide 

flexibility but reduces the number of available 

allowances in current years and can also lead to 

72 
Section E


increased compliance costs for current emission 

sources. Distributing through an allocation or 

auction is perhaps the most common and 

economically efficient approach. 

The set-aside allowances must come from 

within the cap so that new allowances do not 

inflate the cap and undermine the ability to 

achieve the environmental goal. If a set-aside is 

used, the basis for awarding allowances from the 

set-aside and the size of the set-aside allowance 

pool should be established in advance. 

As for the method of allowance distribution, 

how set-aside allowances are dealt with in 

Canada and the United States need not be the 

same, as long as the set-aside allowances 

respect the total cap (i.e., the set-aside 

allowances come from within the cap). 

E.10 ALLOWANCE 

ACCOUNTING 

Compliance with an emissions cap and trading 

program is determined by comparing total 

emissions and allowance holdings. It is therefore 

critical to ensure the highest level of accuracy in 

both emissions and allowance data. Tracking 

each allowance from creation to surrender is an 

essential step in ensuring accurate allowance 

information. 

Allowance accounting involves developing 

procedures and information management 

systems for the creation, transfer, compliance 

use, and surrender of allowances. The 

procedures must establish the roles and 

responsibilities of each party involved in the 

transaction (the buyer, seller, and administrative 

agency), the information that is collected to 

process the transaction, the time required to 

process the transaction, and the manner in 

which a transaction is confirmed. 

E.11 TAX CONSEQUENCES 

When market participants buy allowances, they 

incur costs. When they sell allowances, they 

earn revenues. If participants generate profits or 

losses on their allowance sales, those earnings 

might incur tax liabilities. In addition, the use 

of purchased allowances (i.e., allowances with 

an associated cost to acquire) for compliance 

purposes may have tax consequences, as the 

cost of the allowances may be considered an 

environmental compliance cost. 

E.12 THE U.S. EXPERIENCE 

WITH ALLOWANCE USE 

In the U.S. SO2 allowance trading program, 

allowances are defined in the Clean Air Act 

Amendments of 1990 as an authorization to 

emit one ton of SO2. The Act also specifies that 

allowances are not property rights; rather, they 

are treated as a revocable authorization to emit. 

Over time, if new scientific information emerges 

or societal preferences change, allowances can 

be revoked or discounted to achieve a lower cap 

level. In the U.S. NOX Budget Trading Program, 

banked allowances may be discounted to limit 

episodic ozone events that could occur if sources 

used too many banked allowances. Table E-1 

presents an overview of allowance use in the 

SO2 and NOX emissions cap and trading 

programs. 

E.12.1 Allowance Serialization 

Each allowance in the U.S. SO2 and NOX 

emissions cap and trading programs has a 

unique serial number. The number includes 

the vintage year (i.e., the first year that the 

allowance can be used for compliance purposes) 

and a unique eight-digit number. 

The use of serial numbers aids market 

participants by making it easier to track the cost 

basis of each allowance. This is helpful for tax 

purposes. Serial numbers aid EPA and the public 

by offering opportunities to analyze allowance 

use, trading patterns, and program effectiveness. 

E.12.2 Allowance Banking 

The U.S. SO2 emissions cap and trading program 

permits banking with no restrictions. This has 

had positive effects on environmental quality and 

has reduced compliance costs. Although banking 

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Canada-United States Emissions Cap and Trading Feasibility Study 

Table E-1 Overview of Allowance Use in U.S. SO2 and NOX Programs 

U.S. SO2 Acid Rain Program 

U.S. NOX Budget Trading 

Program 

Definition Authorization to emit. 

Not a property right. 

Authorization to emit. 

Not a property right. 

Serialization Yes ’ vintage + unique number. 

Allowances are stored in blocks. 

Yes ’ vintage + unique number. 

Allowances are stored in blocks. 

Banking Unlimited. Banked allowances are discounted 

if total bank exceeds 10 percent of 

initial allocation. 

Distribution – auction 2.8 percent of cap auctioned 

each year. 

None. 

Distribution – allocation Benchmark: Heat input multiplied by 

1.2 pounds (lbs.) of SO2 per million 

British thermal units (mmBtu). 1 

Baseline: Average of 1985–1987 

(permanent). 

Allocation approaches are 

determined by states. 

Tax consequences Profits (and losses) from allowance 

trades are subject to capital gains 

taxes. 

Purchased allowances used for 

compliance are considered an 

environmental compliance cost and 

have associated tax consequences. 

Profits (and losses) from allowance 

trades are subject to capital gains 

taxes. 

Purchased allowances used for 

compliance are considered an 

environmental compliance cost and 

have associated tax consequences. 

New sources Purchase from market. Determined by states. 

Set-asides Limited number for conservation and 

renewable energy projects before 

1995 (phasing out). 

Determined by states. 

Government oversight Market oversight is limited. Market oversight is limited. 

is unlimited in the SO2 program, regardless of 

the number of allowances a participating source 

holds, it is never entitled to exceed the sourcespecific limits set in the facility’s operating 

permit or other applicable provisions to protect 

public health. 

Under the U.S. NOX Budget Trading Program, 

participating sources can bank unused 

allowances. However, if the total number of 

banked allowances is greater than 10 percent of 

the cap, the banked allowances are discounted. 

This is called progressive flow control. The 

discount ratio is determined on a regional 

basis and applied to allowances when they are 

used for compliance. The ratio is calculated by 

multiplying the cap by 10 percent and dividing 

the result by the number of banked allowances. 

The ratio indicates the number of allowances 

that can be used at full value, while the 

remaining allowances are discounted by 

50 percent (i.e., two allowances are required 

for each ton of NOX emissions). For example, 

if the cap is 500,000 allowances and 75,000 

allowances are banked, progressive flow control 

would be triggered, since the bank is greater 

One Btu ≈ 1.06 kilojoules. 

74 

1 
Section E


than 10 percent of the cap. The ratio would 

be 0.67 ((500,000 × 10%) / 75,000). Under this 

example, 67 percent of a source’s banked 

allowances could be used at full value, while 

the remaining 33 percent would be discounted, 

so that two allowances are required for each 

ton of NOX emissions. 

E.12.3 Allowance Distribution 

EPA distributes the majority of allowances for 

the SO2 emissions cap and trading program 

directly to participating sources through a 

directed allocation. EPA also holds an annual 

allowance auction where 2.8 percent of the total 

allowances are sold to interested parties. For the 

NOX Budget Trading Program, allowances under 

the regional cap are distributed to the states, 

which then allocate their state budgets among 

their affected sources. A state may leave some 

allowances in reserve for special state set-aside 

programs, such as energy efficiency projects. 

E.12.3.1 Allocations 

The benchmark for the SO2 allowance 

allocations is heat input. Heat input was selected 

because the data were available and this 

benchmark does not penalize sources that took 

early action to reduce emissions. The baseline 

was heat input data from 1985 through 1987. 

The average of the three years is used, because 

a single year may not accurately reflect normal 

conditions at a particular source. For example, a 

unit may have been offline for maintenance or 

the weather may have been extreme, increasing 

demand for heat and/or electricity. 

Allocations were calculated by multiplying 

each participating source’s average heat input 

for 1985 through 1987 by a performance rate of 

1.2 lbs. SO2/mmBtu or, if it was already lower 

than 1.2 lbs. SO2/mmBtu, the source’s actual 

emission performance rate. 

There were also numerous special provisions 

to recognize special circumstances and to 

address equity concerns raised by some states. 

For example, in some cases, states that had 

already reduced the emissions of their electric 

utilities well below the national average were 

given extra allowances. Similarly, a state with 

high population growth in the 1980s was given 

bonus allowances for its electric utilities to 

compensate for this growth. In all cases, 

these redistributions were performed without 

increasing the size of the emissions cap. 

The Clean Air Act stated that if the allocation 

calculations resulted in an allocation greater 

than the available allowances under the cap, 

each source’s allocation would be reduced by 

the same percentage to maintain the cap. Hence, 

the increase in allowances allocated to certain 

participating sources was offset by a decrease 

in the number of allowances allocated to other 

sources. 

The SO2 allowance allocations are issued to 

sources in perpetuity. If a source is shut down 

or ceases operation, the owner(s) of the source 

may choose to transfer all future allocations to 

another source, but EPA does not revoke the 

allocation. This was done to discourage owners 

from operating older, inefficient units just to 

have the allowances. 

At the beginning of the program, EPA issued 

30 years of allowances to each participating 

source. At the beginning of each year, EPA issues 

allowances for a year 30 years in advance. For 

example, in 2005, EPA will issue allowances with 

a 2034 vintage. Issuing allowances far into the 

future provides affected sources and market 

participants with certainty about allowance 

availability, 2 but it can complicate future 

changes to the level of the emissions cap, since 

allowances have already been distributed well 

into the future. 

Certainty is not absolute, however, because the United States may discount distributed allowances in the future. 

75 

2 
Canada-United States Emissions Cap and Trading Feasibility Study 

E.12.3.2 SO2 Auction 

Each spring, EPA holds an allowance auction 

to sell 2.8 percent of total allowances for 

the year. These allowances are withheld, or set 

aside, from sources during the initial allocations, 

and approximately half are auctioned seven 

years prior to the vintage year of the allowance 

(the advance market) and half are auctioned 

during the vintage year of the allowance (the 

spot market). In other words, the 2005 auction 

included allowances with a vintage year of 2005 

and allowances with a vintage year of 2012. 

Allowances cannot be used prior to their vintage 

year. 

The auction is a sealed bid process. 

Interested parties submit a bid for a specific 

number of allowances and a particular price. The 

bids are ranked by bid price, and the top bid is 

fulfilled at the bid price. If allowances remain, 

the next bid is fulfilled at the bid price. The 

process continues until there are no allowances 

remaining or the bids are exhausted. The 

proceeds from the auction and any unsold 

allowances are distributed to the sources on a 

pro rata basis (i.e., proceeds are distributed to 

the sources from which the allowances were 

initially withheld). 

The Clean Air Act allows EPA to designate 

a third party to administer the auction. 

EPA does not hold an annual auction for 

the NOX Budget Trading Program. This trading 

program is a state program, and while some 

states have chosen to auction off some 

allowances to sources (Virginia, Kentucky), 

most maintain the directed allocation approach. 

E.12.4 Allowance Accounting 

EPA has established a computerized tracking 

system to manage all allowance transactions. 

The data system (see Section F) manages the 

creation, transfer, and compliance use of 

allowances. Each participating source has a 

compliance account in the system. In addition, 

any person can open a general account in 

ATS so that he or she can participate in the 

allowance trading program. 

When EPA allocates allowances, the blocks 

of allowances are transferred into the respective 

sources’ compliance accounts. The allowances 

reside in the account until the source officially 

transfers the allowances to another account, 

general or compliance, or submits the 

allowances for compliance purposes (i.e., 

retires the allowances). 

Only official transfers—transfers that are 

submitted to EPA—are entered into the tracking 

system. Transfers of allowances that will be used 

for compliance must be recorded in the tracking 

system, while other transfers (e.g., purchases, 

sales) are not required to be submitted to EPA. 

To submit a transfer, the designated 

representative (or, for general accounts, the 

authorized account representative) for the source 

transferring the allowances uses the Clean Air 

Markets Division Business System to do online 

transfers or submits a paper form. EPA added an 

online allowance transfer option in late 2001, 

allowing those who wish to transfer allowances 

to do so over the Internet, either by submitting 

a file containing the transfer information or by 

entering the data on the screen. This online 

capability lowers transaction costs even further 

and allows the market participants more control 

over their transactions. 

If a paper form is submitted, EPA records the 

transfer in the tracking system, usually within one 

or two business days (although the regulations 

allow five days), and sends a confirmation 

notice to both transferring and recipient account 

representatives. When using the EPA Business 

System, recordation is “real time,” with instant 

confirmation. In addition, each day EPA updates 

its Web site with that day’s transactions. 

The information that EPA collects for 

processing a transaction includes the 

transferring account ID, account representative, 

recipient account ID, and allowance serial 

numbers. EPA does not collect price information, 

76 
Section E


because prices do not provide information 

necessary to determine compliance with the 

program. In addition, the price paid may not be 

an accurate reflection of market prices. Price 

information without adequate explanation of the 

underlying transactions could lead to confusion 

about the market price of allowances. 

E.12.5 Allowance Market 

The allowance market for the U.S. SO2 emissions 

cap and trading program is very active and 

liquid—over 20 million allowances are traded 

each year since Phase II began. The financial 

community has played an important part in the 

development of the market and has helped 

sources develop hedging strategies (e.g., options 

and futures). This has helped sources better 

manage allowance price risk. 

There are numerous participants in the 

market, including brokers, traders, speculators, 

source representatives, and individuals. In fact, 

anyone can participate in the market. As an 

example, every year, school children in different 

parts of the United States raise money to 

purchase one or more allowances at the EPA 

auction that can be withheld from the pool of 

available allowances, thereby reducing the level 

of allowable pollution. This access to the market 

has not had any effect on prices or allowance 

availability, but it does provide a useful hands-on 

lesson about emissions trading. 

E.12.6 Tax Consequences 

Most allowances are provided to sources 

through a directed allocation. Since there is no 

cost associated with these allowances, there are 

no tax consequences when they are used for 

compliance. However, if a source uses purchased 

allowances for compliance, the cost of the 

allowances is considered a cost of environmental 

compliance and can be included on the firm’s 

operation costs for tax purposes. For this reason, 

many sources specify the allowances they want 

to retire for compliance. If a company sells 

allowances for a profit (or loss), the earnings 

from that sale are taxed as capital gains. 

The tax consequences of allowances were 

not determined in the Clean Air Act or by EPA. 

Rather, the U.S. Internal Revenue Service 

provided a ruling on these tax consequences. 

E.13 SUMMARY 

Allowances should be fungible—that is, each 

allowance should be interchangeable with 

other allowances. This simplifies program design 

and operation, reduces transaction costs, and 

increases the economic effectiveness of the 

emissions cap and trading program. Simplicity is 

enhanced by avoiding the creation of different 

categories of allowances with different attributes. 

Emissions and allowances should be 

measured in the same units (e.g., one ton 

of SO2) in order to simplify record-keeping, 

improve transparency, and create an efficient 

market for allowances between the two 

programs. Allowances should be equal to 

the same unit of emissions in both countries. 

To obtain a well-functioning emissions 

trading system, it is necessary to harmonize 

a number of design elements with regards to 

allowances in both countries: 

•	 Serialization of the allowances must 

follow the same rules and patterns, 

including the same approach to vintage. 

•	 Banking and borrowing rules must be 

the same. 

•	 Property rights must be compatible. 

•	 The degree of transparency must be high. 

•	 Rules to create and transfer allowances 

must be the same. 

In addition, the timing for the distribution 

of allowances (i.e., the number of years in 

advance that allowances are allocated) and 

other accounting processes must be the same. 

77 
Canada-United States Emissions Cap and Trading Feasibility Study 

Finally, other aspects of allowance treatment 

can be different. For example, the provisions for 

distributing the allowances and the approach to 

defining and managing set-asides (a number of 

allowances reserved to create specific incentives) 

can be different among jurisdictions participating 

in an emissions cap and trading program, as 

long as the provisions of the set-aside ensure 

the integrity of the cap (i.e., allowances set 

aside come from within the cap). In addition, 

the methods for distributing allowances and 

managing set-asides may need to be evaluated 

from the standpoint of equity and economic 

impacts on industry in the two different 

countries. 

78 
Section F 

ELECTRONIC EMISSIONS TRADING REGISTRY: 

Data Systems for Tracking Allowances and Emissions 

An essential element of emissions cap 

and trading programs is comprehensive, 

accurate, transparent, and timely information 

about emissions and tradable allowances. 

An electronic emissions trading registry can 

greatly enhance the collection, verification, 

management, and dissemination of data for 

an emissions cap and trading program. 

This section discusses principles for 

designing an electronic registry (Section F.1), the 

components of the registry (Section F.2), and 

centralization (Section F.3). It also presents U.S. 

and Canadian experiences with data tracking 

systems (Sections F.4 and F.5), as well as the 

levels of consistency and compatibility that are 

necessary for electronic registries in a crossborder emissions cap and trading program. 

F.1 PRINCIPLES FOR 

DESIGNING AN ELECTRONIC 

REGISTRY 

The advantages of using electronic registries 

go well beyond their ability to handle large 

amounts of data. Using a flexible, comprehensive 

system to collect and manage data can provide 

numerous benefits, including: 

•	 Increased data accuracy—Tools such as 

electronic reporting and automated data 

quality checks reduce errors and eliminate 

redundant data entry. 

•	 Reduced time and costs—Electronic reporting 

and automated data quality checks also 

reduce the time and costs required to 

complete, process, and review paper forms. 

In addition, the electronic storage of data 

can significantly reduce, or even eliminate, 

the costs associated with the collection, 

transport, storage, and distribution of 

paper forms. 

•	 Enhanced access—Electronic data storage 

makes it easier and faster to retrieve, 

analyze, and evaluate relevant data on 

demand. Improved access to data can also 

promote confidence in the trading program 

by permitting program participants and 

interested members of the public to retrieve 

data to ascertain compliance, evaluate a 

program’s effectiveness, and make informed 

decisions. 

•	 Improved consistency and comparability— 

Electronic reporting and electronic data 

storage encourage consistency by requiring 

all program participants to report the same 

information in a common reporting format. 

This consistency promotes comparability 

across time and among program participants. 

•	 An electronic registry should integrate several 

design principles, described below. 

F.1.1 Stress Data Quality 

Compliance with an emissions cap and trading 

program is determined by comparing total 

emissions and allowance holdings. It is therefore 

important to ensure the highest level of accuracy 

in both emissions and allowance data. The 

registry system should conduct automated data 

quality checks on every emissions submission. 

Errors and discrepancies can then be reported to 

the participating sources. 

F.1.2 Promote Transparency 

Registries play a critical role in building public 

acceptance. By providing data in a transparent 

manner, registries can build public confidence in 

a program by revealing how well the program is 

enforced and ensuring accountability for each 

unit of emissions. Data transparency can also 

increase the efficiency of the market and reduce 

transaction costs by enabling participants to 

identify potential buyers and sellers. True 

transparency, however, requires providing the 

information in a useful and informative format. 

79 
Canada-United States Emissions Cap and Trading Feasibility Study 

F.1.3 Design for the Future 

When designing registry systems, every effort 

should be made to create a flexible, adaptable 

design that can accommodate future program 

changes as well as new programs. For example, 

if an emissions cap and trading program focuses 

on a single pollutant or sector, the system 

should be designed so that it can accept 

additional pollutants and sectors in the future. 

Designing a flexible system initially requires 

more financial resources and effort, but will 

reduce administrative burden and reengineering 

costs in the long run. 

Most regulatory agencies already collect 

some data about the environmental performance 

of sources. The design of the registry should 

account for those existing and any planned 

systems to reduce data redundancy and 

administrative effort. 

F.1.4 Automate Recurring Procedures 

Many processes contain repetitive procedures. 

To the extent that these are automated, they will 

reduce the effort required to process data. 

F.1.5 Emphasize Security 

Registries must have a high degree of integrity 

to prevent fraudulent transactions and malicious 

attacks on the system. Integrity of data is critical 

for accurately determining compliance and 

because allowances in an emissions cap and 

trading program have economic value. In 

addition, the costs of compliance and 

noncompliance are based on emissions 

data and allowance holdings. 

F.2 COMPONENTS OF 

THE REGISTRY 

A fully functioning registry must have several 

components to collect and manage information 

about sources, market participants, emissions, 

allowances, and compliance. The primary 

components of the registry are the emissions 

tracking system (ETS) and allowance tracking 

system (ATS). 

The most convenient basis for handling data 

for an emissions trading program is an electronic 

registry. The U.S. Environmental Protection 

Agency (EPA) has developed software especially 

designed to manage information on emissions 

trading. The software includes the possibility of 

linking multiple trading zones. EPA has offered 

to share this software with other governments, 

free of charge. 

F.2.1 Key Functions of the ETS 

The ETS stores the actual emissions reported by 

the regulated entities. Emissions data stored in 

the ETS are used by the ATS to verify, during 

end-of-year reconciliation, that each regulated 

entity has covered its emissions with an 

equivalent number of allowances submitted 

for compliance. 

The ETS is based on a detailed regulation 

that specifies requirements such as the nature of 

the information to be recorded, the format of the 

information, and the frequency of the mandatory 

reporting. 

Sources use EPA-provided software to submit 

their electronic data reports (EDRs) directly to 

the ETS. ETS performs extensive checks on 

the EDRs for quality assurance (QA), stores the 

data on EPA’s mainframe computer, and provides 

the source with a feedback report that includes 

notification of any errors and an explanation of 

how best to resolve the errors. 

80 
Section F


F.2.2 Key Functions of the ATS 

F.2.2.1 Ownership Record 

The ATS is a compliance system. The key 

function of the ATS is to determine compliance 

by tracking the allowances in the system. 

Each participant 1 has an account in which a 

list of allowances that he or she owns is kept. 

When a block of allowances is transferred to 

another participant, the ATS moves them to 

the new owner’s account. If multiple registries 

are involved in a program (e.g., a block 

of allowances is traded between two sovereign 

states with independent registries), transfers may 

need to be verified against a “clearinghouse” 

to enhance the integrity of the system. 2 The 

clearinghouse could contain a summary of 

information necessary to verify that the trade 

is valid. 

F.2.2.2 Deduction of Allowances for 

Compliance 

The ATS is used to make allowances available 

for compliance. At the end of a grace period 

following the compliance period, the government 

deducts the number of allowances that 

corresponds to the participant’s emissions 

covered by the system (see Section G.1) by 

moving the allowances into a permanent EPA 

retirement account. Allowances may also be 

surrendered as a penalty for noncompliance or 

to enhance the environmental benefits of the 

program. Once deducted or surrendered, the 

allowances are no longer transferable, bankable, 

or usable. Allowances are never deleted from the 

data system, so any allowance ever issued may 

be tracked. This allows the system to remain 

auditable and transparent. 

F.2.2.3 Authorized Participants 

The ATS should include information on one 

or more authorized representatives for each 

allowance account. This information identifies 

those individuals who are authorized to conduct 

transactions or other activities on behalf of the 

account holder. It can also facilitate information 

flow between the registry operator and the 

account holder. 

In a well-functioning emissions cap and 

trading system, the conditions to open an 

allowance account should not be too restrictive 

to allow the participation of market facilitators 

such as brokers. Moreover, these conditions 

must be the same on both sides of the border. 

F.3 CENTRALIZATION 

When more than one legal or political 

jurisdiction is included in an emissions cap 

and trading program, questions relating to 

registry operation may arise. The jurisdictions 

may work together to operate a single, 

centralized registry in which all information 

is maintained. Alternatively, each jurisdiction 

may operate an independent registry to maintain 

information relevant to its program, but share 

information, when appropriate, with the other 

registry or registries. There are benefits and 

drawbacks to each approach. 

A centralized registry provides a single 

point of contact for submitting or querying 

data, regardless of jurisdiction. Program 

participants or the public can easily access 

information from any program with greater ease, 

thereby improving transparency. Centralization 

also reduces the need for communication 

between registry systems and thus reduces 

the security and data integrity risks associated 

with open communication. Also, perhaps most 

importantly, centralization reduces the 

resource requirements to develop and operate 

independent data systems for each jurisdiction. 

The primary drawback of centralization is legal 

jurisdiction. With a centralized approach, one 

jurisdiction, or a third party, must manage the 

1	 As specified in Section F.2.2.3, “Authorized Participants,” a participant could be a nonregulated entity. 

2	 We assume that a typical registry automatically keeps a record of each allowance transfer. In other words, a transaction 

log is integrated into a typical ATS. 

81 
Canada-United States Emissions Cap and Trading Feasibility Study 

data and determine compliance for sources in 

other jurisdictions. 

A decentralized approach overcomes legal 

jurisdiction issues, but requires greater resources 

for registry operation and maintenance. In 

addition, it requires coordination among 

jurisdictions to establish data requirements 

and communication protocols. 

A decentralized approach would also require 

a mechanism such as a “clearinghouse” to 

ensure that any transactions involving more 

than one registry are valid. Using a centralized 

approach, the verification function is internal; 

in a decentralized approach, it is important 

that an independent verification system is used 

to ensure that each transaction—including 

allocations, trades, transfers, and compliance 

deductions—is allowed within the appropriate 

emissions cap and trading program(s), and that 

the account holders and allowances involved 

are valid. 

A balanced option may be to link the two 

national registries. In this way, legal challenges 

associated with compliance enforcement due to 

an international registry would be avoided and 

the number of windows for reporting and links 

between registries would be kept low. 

F.4 THE U.S. EXPERIENCE 

WITH DATA TRACKING 

SYSTEMS 

EPA has operated registries for a decade and 

has learned many valuable lessons. The firstgeneration registries were expensive and 

sometimes burdensome. However, as 

technologies improved and experience 

increased, EPA reengineered the systems 

to provide better data collection, auditing, 

management, analysis, and dissemination 

capabilities. Today’s systems offer unprecedented 

automation and data access. 

As the volume of data has grown, EPA has 

increased the use of electronic data transfer. 

In 2004, 100 percent of emissions data and 

93 percent of allowance transfers, accounting 

for 94 percent of all allowances transferred, were 

submitted electronically. EPA has also introduced 

an online management system to encourage 

program participants to use the Internet to 

manage their participation in the emissions cap 

and trading program. EPA’s registry system is a 

key component in the transition to a paperless 

interaction between industry and regulator. In 

addition, EPA provides sources with reporting 

software that conducts data quality checks, 

to use before submitting data. By moving the 

QA checks to the data source, there is less 

opportunity for poor quality data to enter the 

registry. 

F.4.1 Emissions Tracking 

EPA’s registry includes an ETS to collect, audit, 

and manage emissions data from the more than 

3,000 affected units in the U.S. sulfur dioxide 

(SO2) and nitrogen oxide (NOX) emissions cap 

and trading programs (see Table F-1). Each of 

the units is required to submit hourly emissions 

data on a quarterly basis. To simplify and 

improve the process, EPA provides each source 

with software to process, format, pre-audit, 

and submit the data. As the submissions are 

received, they are processed and audited by 

the ETS. The ETS reviews the data for errors 

or omissions, conducting several hundred 

calculations on each submission. When the 

audit is complete, the ETS sends an electronic 

report to the source that details results of the 

audit and indicates whether the data were 

accepted or rejected (see Figure F-1). 

F.4.2 Allowance Tracking 

The ATS is the accounting system for the 

SO2 and NOX allowance trading programs in 

the United States. The ATS tracks account 

information, account holdings, and allowance 

transactions. Account holders can access their 

accounts to transfer allowances through an 

online system. The system allows users to 

register trades and select the specific allowances 

to transfer. In addition, account holders can 

82 
Section F


Table F-1 Required Emissions Data on a Quarterly Basis 

Facility Information 

Pollutant Gas Concentrations 

Diluent Gas Concentrations 

Moisture Data 

Volumetric Flow 

Daily Quality Assurance Data and Results 

Reference Method Backup QA Data 

Unit Operating and Cumulative Emission Data 

SO2 Mass Emission Data 

NOX Emission Data 

CO2 Mass Emission Data 

Qualifying Low Mass Emission Unit Data 

Monitoring Plan Information 

Certification Test Data and Results 

Figure F-1 Sample Feedback Quarterly Report Receipt and Status Code Information 

Report received for ORISPL: 000099 

Facility Name: Tamarasc Power 

Unit/Stack/Pipe ID: 6B 

Status Code for this report: 9 

Submission Year: 2003 

Submission Quarter: 4 

Date: 01/06/2004 

Time: 9:48 

Submitter User ID: TMA 

Submission Account: ETSP (ETSP=Official, ETSD=Test) 

Receipt ID: 115008 

STATUS CODE 9: Quarterly Report Contains Informational Errors 

Explanation: 

While the EPA has accepted your report, informational errors are present in the report. The following 

items accompany this letter: A Cumulative Data Summary Table of Emission Values, an Error Report 

containing detailed descriptions, and a File Summary that lists the number and type of records found 

in the quarterly data report. 

Required Action: 

Please investigate the informational errors described in the accompanying feedback and identify any 

suspect data periods or unusual operations (e.g., startup, shutdown, or operational problems) in the 

quarterly report. Review and, if possible, correct the identified errors to ensure there is no measurement 

or reporting problem. 

83 
Canada-United States Emissions Cap and Trading Feasibility Study 

Figure F-2 Allowance Reconciliation 

, 

, 

, 

, 

update information about their account 

(e.g., adding designated representatives and 

authorized agents; editing facility data). After 

an account holder registers an allowance 

transaction or updates his or her account, the 

system sends an email confirmation to the 

relevant parties. The use of these online tools 

has made participating in the SO2 and NOX 

allowance trading programs a paperless process. 

Submitting an allowance transfer requires 

information about the transferring account, 

authorized representative of the transferring 

account, receiving account, and specific 

allowances to be transferred. EPA does not 

collect information about price, because it is not 

relevant to enforcing the program or achieving 

the environmental goal. In addition, price data 

may not provide useful information, because 

some transactions have nonmonetary terms 

(e.g., fuel suppliers may bundle allowances with 

their fuel; a company with multiple sources may 

transfer allowances among their accounts), 

while others may involve more complicated 

financial or nonfinancial instruments (e.g., 

futures, options, swaps). Price information is 

readily available from most brokers, most of 

whom post price information on their Web sites. 

F.4.3 Reconciliation 

At the end of each year, after 

a short grace period, the 

emissions and allowance data 

are reconciled. Currently, for 

the SO2 program, the registry 

deducts one allowance for 

each ton of SO2 emissions 

(see Figure F-2). For the NOX 

program, if banked 

allowances are used, the 

registry discounts the 

allowances as necessary 

before deducting the 

appropriate number of 

allowances (see Section 

E.12.2 for a discussion of discounting banked 

NOX allowances). 

F.4.4 Public Reporting 

As discussed in Section F.1.2, providing public 

access to source-level emissions and allowance 

data promotes confidence in the program 

and provides an additional level of scrutiny to 

verify enforcement and encourage compliance. 

In the United States, emissions data are not 

considered confidential. The Clean Air Act 

explicitly states that emissions data are public 

information. 

Advances in technology and the Internet 

have made it possible to provide interested 

persons with timely and useful information 

about emissions, allowances, and program 

results. EPA’s registry provides data access tools 

through the Internet that allow people to 

develop customized queries for the data that 

are of most interest to them. In addition, 

mapping and other applications provide data in 

an easy-to-understand graphical format. 

84 
Section F


F.5 THE CANADIAN 

EXPERIENCE WITH DATA 

TRACKING SYSTEMS 

F.5.1 Canadian Ozone-Depleting 

Substances Trading 

Environment Canada operates systems similar 

to the ETS and ATS described above under the 

Canadian Environmental Protection Act, 1999 

(CEPA) for two ozone-depleting substances: 

hydrochlorofluorocarbons (HCFCs) and methyl 

bromide. The administrator of the system 

communicates by mail the exact number of 

allowances for the coming year to each recipient 

a few weeks prior to the beginning of the year. 

On an ongoing basis, transferors and transferees 

provide information on the transfers of 

allowances by faxing (or mailing) a form, 

available on a Web site, 3 to the administrator of 

the program. Each transfer has to be approved 

by the Minister or its administrator before being 

valid. Only the quantity of the transfer has to 

be divulged; the value of the transfer is not 

released. The administrator keeps up to date 

a database on each account using relational 

database software (i.e., MS Access). Although 

Ministerial approval of allowance transfers is 

required for specified substances under the 

Ozone-Depleting Substances Regulations, 1998, 

CEPA does not require Ministerial approval of 

allowance transfers within a system of tradable 

units (s. 326). 

Unlike the NOX and SO2 systems in the United 

States, the ozone-depleting substances trading 

system does not control emissions per se, but 

rather controls the apparent consumption (i.e., 

production plus import minus export) of ozonedepleting substances. Authorized importers and 

producers produce an annual report on apparent 

consumption and submit it to the authority for 

compliance assessment. 

F.5.2 Ontario Emissions Trading 

With its Ontario Emissions Trading Code, 

Ontario developed a registry that fulfills the basic 

functions of an ATS and an ETS, since it notifies 

the public of the distribution and retirement of 

nitric oxide (NO) and SO2 emission allowances 

and the creation and retirement of NO and 

SO2 Emission Reduction Credits. 4 The Ontario 

Registry’s Allowances Tracking System is not 

based on serialization of allowances (see Section 

E) to track their initial ownership; instead, each 

transfer has to specify the initial owner name. 

F.6 SUMMARY 

In assessing the qualities of well-functioning 

tracking systems for both emissions and 

allowances, this section identified a number of 

desirable elements. These elements could be 

brought together in electronic registries that 

would provide data accuracy, reduce time 

and costs, enhance data access, and improve 

consistency and comparability. 

Emissions and allowance tracking systems 

provide the link between the electronic data 

reporting requirements and the determination of 

compliance with the emissions cap and trading 

program. Being crucial elements of compliance 

determination, the type of data, the data 

requirements, and the accuracy and quality of 

the data in both Canada and the United States 

must be the same. This is because of the need 

for consistency and comparability, protection 

of allowance values, and to ensure equity. 

In order to gain public acceptance, trust, 

and understanding of the results of an 

emissions cap and trading program, full and 

open disclosure of relevant public and private 

decisions needs to be consistent in Canada and 

the United States. This transparency is a critical 

element of emissions cap and trading programs 

See http://www.ec.gc.ca/ozone. 

Ontario Ministry of the Environment, “Ontario Emissions Trading Code,” Toronto, Ontario, January 

(http://www.ene.gov.on.ca/envision/env_reg/er/documents/2003/XA03E0001.pdf). 

85 

3 

4 
Canada-United States Emissions Cap and Trading Feasibility Study 

and includes the establishment of rules and 

regulations and determining if an emissions 

source is in compliance. Accurate and timely 

information is important to a credible, wellfunctioning emissions cap and trading program. 

Tools are available that integrate all the 

data and functionality of a registry into a 

single, flexible software system. This system 

is adaptable to new programs and the 

inclusion of additional sectors and is capable 

of communicating with other registries and 

emissions reporting systems. Using these tools 

would allow Canada and the United States to 

have comparable and consistent national 

emissions and allowance tracking registries 

necessary for a cross-border emissions cap 

and trading program. 

86 
Section G 

COMPLIANCE AND ENFORCEMENT 

This section addresses the key questions of 

compliance and enforcement considerations 

for a cross-border emissions cap and trading 

program. Section G.1 presents an overview 

of compliance in relationship to a cap and 

trading program and describes compliance 

determination in more detail. Section G.2 

discusses enforcement. Sections G.3 and G.4 

present U.S. and Canadian experience with 

compliance and enforcement. 

G.1 OVERVIEW OF 

COMPLIANCE 

Determining compliance in an emissions cap 

and trading program is relatively simple and 

straightforward. The regulator simply compares 

a source’s total emissions to the permissible 

emissions, based on the allowances held in the 

source’s account. Some important decisions, 

however, must be made prior to implementing 

an emissions cap and trading program. 

These decisions involve measurement and 

quantification of emissions, allowance banking 

rules, emission reporting deadlines, and the 

deadline for holding allowances for compliance. 

At the end of each compliance period, the 

emission sources should be given enough time 

to verify and submit the emissions data. This 

verification period should not be so short as to 

cause the emission sources to submit data that 

have not been properly quality assured, but not 

so long as to unreasonably delay compliance 

assessment. It should also allow enough time 

for the regulating authority, once it receives 

the data, to finish conducting the compliance 

determination prior to the end of the subsequent 

compliance period, when the process will begin 

again. At the end of each compliance period and 

during the time when sources are assuring the 

quality of their emissions data, the rules should 

provide for a short grace period so that sources 

can make final allowance trades. This allows 

sources to ensure that their account contains 

allowances equal to or greater than their 

emissions. This can be accomplished 

by specifying in advance an allowance transfer 

deadline—the final date for sources to trade 

allowances for use in the compliance year. 

G.1.1 Compliance Determination 

The first step in compliance determination is 

to determine the total amount of emissions 

during the compliance period. A cap and trading 

program has several elements that are critical to 

that first step in compliance determination. One 

element is emissions monitoring, which must 

meet stringent technical requirements to ensure 

that emissions are properly measured for each 

regulated activity. Another element is emissions 

data reporting, which must conform to certain 

protocols to ensure that the information is 

forwarded to the authority in an accurate and 

timely way. In addition, there are verification 

systems to ensure quality of the emissions 

monitoring and reporting and to indicate any 

necessary corrections. The requirements for 

these elements are specified in the cap and 

trading program regulations and include, for 

example, operating, quality assurance and 

quality control, and documentation requirements 

(see Section D on monitoring and reporting). 

The regulator may audit and inspect a facility’s 

emissions monitoring and reporting to ensure 

compliance with the requirements. If the facility 

is not in compliance with these requirements, 

then substitute emissions data must be used for 

the period of noncompliance, in lieu of reported 

data, and the facility may be determined to be in 

violation of the program regulations. 

The second step is to compare the amount 

of regulated emissions with the amount 

of allowances held for compliance in the 

compliance period for each regulated entity. 

A cap and trading program has an allowance 

trading system to ensure that allowance 

allocations, transfers, and holdings are properly 

87 
Canada-United States Emissions Cap and Trading Feasibility Study 

tracked and that emissions and allowances are 

correctly compared. 

In a cross-border emissions cap and trading 

program, the definition of “compliance” must 

be the same in both countries with regard to 

allowance holding requirements, as well as with 

regard to emissions monitoring and reporting 

requirements. 

G.1.2 Regulated Entity 

A regulated entity could be equipment (e.g., 

a boiler), a production unit (e.g., a power plant), 

or a legal entity that owns or operates the 

production unit (e.g., a power generator firm). 

This must be determined and defined by the 

program’s applicability criteria. The number of 

regulated entities would be much larger if they 

are defined as equipment rather than plants, or 

as plants rather than firms. However, the identity 

of the legal entity that owns or operates a plant 

can change during a compliance period or before 

an allowance transfer deadline, and ownership 

structures can be very complex (e.g., with 

multiple owners and the use of partially or 

wholly owned subsidiaries or affiliates or limited 

liability corporations). Further, foreign owners 

may be involved. Consequently, making the 

owner or operator the regulated entity may make 

the determination of compliance difficult. 

G.1.3 Compliance Date 

There are two significant dates related to 

compliance determination: one is the deadline 

for reporting emissions; and one is the deadline 

for transferring and holding allowances to 

equal the reported emissions for the compliance 

period. For instance, the last date to report 

emissions data could be 30 days after the end of 

the year. Then, firms might have an additional 

30 days to make trades and hold allowances for 

compliance. 

G.1.4 True-Up Process 

The true-up process, also known as 

reconciliation, is the process through which 

reported emissions are compared with 

allowances held. During the true-up period, the 

accounts in the allowance tracking system are 

frozen, in that transfer of allowances that could 

be used for compliance is suspended until 

compliance is determined. 

G.2 ENFORCEMENT 

G.2.1 Penalties for Noncompliance 

A stringent, automatic penalty for 

noncompliance is an integral feature of a wellfunctioning emissions cap and trading program. 

This penalty should be applied automatically in 

cases where a source does not hold sufficient 

allowances by a designated date to cover mass 

emissions during the compliance period. In 

addition to the automatic penalty, discretionary 

civil or criminal penalties may be applied in 

cases of emissions in excess of allowances held. 

In cases where there is noncompliance with 

other requirements of the cap and trade program 

(e.g., emissions monitoring, reporting, and other 

requirements), discretionary civil or criminal 

penalties may also be applied. Discretionary 

penalties should be determined based on 

the nature and severity of the violation. The 

penalties should be great enough to provide the 

appropriate incentives for compliance and can 

take the form of allowance surrender, fines, or 

criminal penalties. 

G.2.1.1 Noncompliance with the Cap 

In cases where a source does not have sufficient 

allowances to cover its emissions, the automatic 

penalty should also be accompanied by an 

allowance recovery (or offset) of one-to-one to 

maintain the environmental integrity of the 

program. Under a one-to-one offset, one 

allowance from the next compliance period 

would be deducted for the source for every unit 

of excess emissions in the current compliance 

period. 

However, a one-to-one restoration rate 

without other accompanying punitive measures 

for noncompliance could imply that a source 

88 
Section G


could, in effect, use allowances from future 

compliance periods to attain an emissions 

reduction target. This could result in a scenario 

where the emissions cap is always exceeded. 

Hence, it is very important that penalties deter 

noncompliance. 

In addition to the one-to-one offset to 

maintain environmental integrity, the automatic 

penalty should include either further allowance 

deductions or a financial penalty for each 

unit of excess emissions. With an allowance 

deduction penalty (i.e., where a source would 

have to turn in an amount of allowances that is 

a multiple, greater than one-to-one, of its excess 

emissions), the aggregate cap of emissions in 

the next compliance period is reduced. The 

environmental benefits of the program would 

increase due to the allowances deducted as 

a penalty. 

If the automatic penalty is a financial penalty 

(in addition to the one-to-one offset), the penalty 

should be set significantly higher than the 

expected marginal abatement cost—the expected 

market price of allowances—to create an 

effective deterrent for noncompliance, but not 

too high so as to be unreasonable (e.g., in 

cases where excess emissions resulted from 

inadvertent error). (If higher penalties are 

warranted, in some circumstances the automatic 

penalty could be supplemented by discretionary 

penalties.) Further, since it may be difficult to 

project the future marginal abatement cost and 

that cost may change, it may be appropriate to 

set the level of the automatic financial penalty in 

accordance with some benchmark such as a 

recent auction or market index. 

G.2.1.2 Other Penalties 

The regulator should have the discretion to 

impose civil or criminal penalties on sources 

or individuals who violate requirements of the 

cap and trading program. Civil and criminal 

penalties provide direct incentives for the legally 

responsible individuals at the affected source 

to behave responsibly. Owners, operators, or 

designated representatives should be required to 

certify that each form submitted to the regulating 

authority for the source (e.g., allowance 

transfers, emission reports) is true, accurate, 

and complete. The certification should also 

acknowledge potential civil or criminal penalties 

under the law for acts and omissions within 

the scope of their responsibilities under 

the emissions cap and trading program. 

Discretionary civil or criminal penalties need 

not be the same in each country. 

G.3 THE U.S. EXPERIENCE 

WITH COMPLIANCE AND 

ENFORCEMENT 

G.3.1 Compliance 

Under the Acid Rain Program (Title IV of the 

Clean Air Act), affected units submit their 

continuously monitored emissions data 

quarterly to EPA. EPA then verifies the quality, 

completeness, and consistency of the reported 

data, the adherence to the Electronic Data 

Report (EDR) format, and the appropriate use 

of missing data procedures, if applicable. 

For circumstances in which a source measures 

emissions from several regulated units through a 

single stack—a “common stack”—the designated 

representative (DR) has the option of using the 

Common Stack Allowance Deduction Form to 

identify the percentage of allowances to be 

deducted from each unit to cover all of the stack’s 

emissions. If the DR does not specify particular 

unit accounts, then EPA will take an equal 

percentage of allowances from each unit emitting 

through the stack. However, EPA recently 

amended its regulation to provide for emissions 

and allowances to be compared on a plant level, 

rather than a unit level, starting in 2006. With 

compliance at the plant level, it will no longer be 

necessary to divide emissions among regulated 

units at a common stack. 

Once all the emissions data are checked 

and all valid and timely allowance transfers are 

implemented, allowances are deducted to cover 

emissions and are transferred into a permanent 

89 
Canada-United States Emissions Cap and Trading Feasibility Study 

EPA emissions retirement account. Any 

remaining allowances of the current compliance 

year vintage are valid for compliance deductions 

in any future year. After reconciliation is 

complete, EPA sends each DR a report entitled 

“Allowance Deductions for Compliance Year 

20YY” detailing the unit’s allowance deductions. 

The schedule for the U.S. Acid Rain Program 

compliance process is as follows: 

•	 April 30, July 30, October 30, and January 30 – 

Deadline to submit 1st, 2nd, 3rd, and 4th 

quarter emission reports, respectively. 

•	 December 31 – Compliance year ends. 

•	 January 30 – Deadline to submit 4th quarter 

emission reports. 

•	 March 1 (February 29 in a leap year) – 

Allowance Transfer Deadline (no allowance 

transfers permitted for compliance in the 

previous compliance year after this date). 

The schedule for the U.S. NOX Budget Trading 

Program compliance process is: 

•	 July 30 and October 30 – Deadline to 

submit 2nd and 3rd quarter ozone season 

emission reports. 

•	 September 30 – Compliance period (ozone 

season) ends. 

•	 November 30 – Allowance Transfer Deadline 

(no allowance transfers permitted for 

compliance in the previous compliance 

period after this date). 

G.3.2 Enforcement 

There are several layers of enforcement 

measures in the Acid Rain Program in the 

United States: 

•	 Under the offset provision, violating sources 

must offset excess SO2 emissions with 

allowances from the next year in an amount 

equivalent to the excess. A source may have 

allowances deducted either immediately or, if 

the unit shows immediate deduction would 

interfere with electric reliability, at a later 

date. If the unit plans to have allowances 

deducted at a later date, the company (that 

is, the designated representative) must 

submit to EPA an Excess Emissions Offset 

Plan, which must undergo public review 

and comment before approval. This offset 

plan states when the unit will provide the 

necessary allowances for compliance. 

(Since the commencement of the Acid Rain 

program, all offset allowances have been 

immediately deducted.) 

•	 The owners or operators must also pay an 

automatic penalty of $2,963 per excess ton of 

emissions in the year 2004. (The 1990 penalty 

of $2,000 is adjusted each year for inflation.) 

The excess emission penalties for the Acid 

Rain Program are automatic. In other words, 

while the determination of the amount of excess 

emissions is subject to legal challenge, there 

is no negotiation of or legal challenge to the 

penalty amount once the determination of the 

excess emissions amount is final. 

EPA also has discretion to seek civil or 

criminal penalties for excess emissions and other 

violations, including failure to install and certify 

monitors on time or to report emissions. EPA can 

seek financial penalties up to $25,000 per day for 

violations and, in the case of willful violations, 

seek criminal penalties. 

For the NOX Budget Trading Program, a 

regional, ozone season-only trading program, 

the automatic penalty is entirely in the form of 

allowance deductions. Violating sources must 

offset each excess ton of NOX emissions with 

one allowance and are penalized two additional 

allowances, for a total of three allowances from 

the next year, for each ton of excess emissions 

during the compliance period. There are 

discretionary civil and criminal penalties for 

violations of the NOX Budget Trading Program, 

as is the case with the violation of any 

requirements of the Acid Rain Program or 

any provision of the Clean Air Act. 

90 
Section G


G.4 COMPLIANCE AND 

ENFORCEMENT IN CANADA 

Although Canada does not have any existing 

national emissions cap and trading programs 

for NOX or SO2, the Canadian Environmental 

Protection Act, 1999 (CEPA) contains provisions 

outlined below that provide for the compliance 

and enforcement elements of such a regime. 

Section 326 of CEPA grants regulationmaking authority with respect to a system of 

tradable units, when used in conjunction with 

the regulation of toxic substances under sections 

93 or 167. Section 326 specifies that the system 

may contain elements such as: 

•	 The methods and procedures for conducting 

sampling, analyses, tests, measurements, 

or monitoring under the system. 

•	 The conditions related to the creation, 

distribution, exchange, sale, use, variation 

or cancellation of a tradable unit. 

•	 The conditions for participation in the system, 

including environmental and temporal limits. 

•	 Reports and forms related to the system. 

The authority to require monitoring and 

reporting is also found in sections 93 and 167, 

respecting toxic substances and international air 

pollution. By way of example, existing regulations 

under CEPA contain reporting requirements to 

the Minister of the Environment regarding the 

emission or manufacture of specified substances 

or regarding the proper functioning of pollution 

control equipment. 1 

These general provisions would allow 

harmonization of a Canadian and American 

trading program with respect to compliance 

elements such as reporting deadlines, length 

of compliance periods, true-up requirements, 

and allowance offsets. 

Provincial governments also have authority 

for compliance and enforcement in air quality 

management programs. Were cross-border 

trading to be implemented, dependent on the 

specific design of select elements, the provinces 

could play a key role in the compliance and 

enforcement provisions of the program. This 

could involve ensuring that facilities covered 

in the emissions cap and trade program are in 

compliance with the monitoring, reporting, and 

verification requirements. 

As well, Part 10 of CEPA provides the 

authority to the federal government for 

enforcement of noncompliance with the 

monitoring, reporting and verification 

requirements of a cross-border cap and trade 

program, which are similar to the civil and 

criminal penalties under the Clean Air Act. The 

Minister of the Environment may designate law 

enforcement officials of provincial governments 

to enforce provisions of CEPA. Such designation 

would take place pursuant to a federal-provincial 

administrative agreement. 

G.5 SUMMARY 

Compliance and enforcement are key aspects 

of cap and trading programs. This would also 

be the case for a Canada-U.S. cross-border 

emissions cap and trading program. 

Under a cross-border regime, Canadian 

regulatees will be subject to Canadian law 

and U.S. regulatees will be subject to U.S. law. 

Regardless, based on U.S. experience, what is 

considered to be in compliance or out of 

compliance needs to be the same in both 

countries. For compliance with the allowanceholding requirement, the penalties for 

noncompliance, be they allowances or financial 

penalties, need to be automatic and equivalent 

in both Canada and the United States. 

For example, see: Asbestos Mines and Mills Release Regulations, SOR/90-341; Chlor-Alkali Mercury Release 

Regulations, SOR/90-130; Ozone-Depleting Substances Regulations, 1998, SOR/99-7. 

91 

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Canada-United States Emissions Cap and Trading Feasibility Study 

The harmonization of compliance schedules 

as regards compliance dates and the true-up 

process is necessary. Different schedules and the 

absence of harmonization could make operation 

of the program problematic and could adversely 

affect the market and create undesirable trading 

behavior. 

Discretionary civil or criminal penalties 

need not be the same in Canada and the United 

States, but they would need to be stringent 

enough to ensure compliance. 

92 
Section H 

ANALYTICAL TOOL DEVELOPMENT AND 

I

n order to assess the impacts of cross-border 

emissions cap and trading between Canada 

and the United States, joint analytical tools 

were developed and expanded. The Integrated 

Planning Model (IPM) was used to prepare 

illustrative modeling scenarios with emission 

reductions of SO2 and NOX from the power 

sector in both countries. Further, since the air 

quality implications of lowering emissions and 

allowing trading are important to estimate, 

air quality modeling was also performed. Air 

quality models used emission data from the 

power sector to assess the broad air quality 

and environmental benefits that could result 

from emission reductions in both countries. 

Over the past two years, joint analytical 

tools were developed to evaluate the 

environmental and economic impacts of a 

potential cross-border emissions cap and trading 

program for NOX and SO2 in both countries. 

This section describes the development of 

analytical tools, the analysis of transboundary 

air quality, and the significant advances necessary 

to the consideration of cross-border trading, 

including shared emission inventories, integrated 

electricity and emissions modeling, and crossborder air quality modeling. 

H.1 DEVELOPMENT AND 

DESCRIPTION OF JOINT 

ANALYTICAL TOOLS 

The IPM and air quality modeling done for 

this feasibility study and, more specifically, the 

projections of potential impacts, demonstrate 

that we can analyze cap and trade and illustrate 

the type of effects that can be considered. The 

actual results are not meant for decision-making 

since scenarios selected were a test of the 

models, not actual options the U.S. and Canada 

would want to pursue. The results are 

illustrative. They do not represent a prediction 

of a future control regime or environmental 

FEASIBILITY ANALYSIS 

policy. The results of economic, emissions, and 

air quality modeling are highly dependent upon 

the design of policy scenarios the U.S. and 

Canada would want to analyze. The study 

demonstrates that the IPM model could be used 

productively to assist the U.S. and Canada to 

further examine emission caps and cross-border 

trading. The study’s illustrative results, below, 

show that additional valuable insight and 

information on Canada-U.S. air management 

activities, can result from IPM and air quality 

modeling. 

H.1.1 U.S.-Canada Power Sector Background 

and Power Sector Model: The Integrated 

Planning Model 

Historically, cap and trade programs in the United 

States have focused on the power sector, which 

is a significant source of emissions affecting air 

quality and a sector where reductions can be 

achieved in a cost-effective manner. Analysis 

done to support the emissions cap and trading 

feasibility study has concentrated on the power 

sector and various existing models that have 

been used in the development and design of cap 

and trade programs in the United States. This 

section provides background on and discusses 

important aspects of the power sector that relate 

to transboundary issues. In addition, this section 

provides some background on the development 

and enhancement of the modeling tools that 

were used to better understand potential impacts 

of both caps and cross-border emissions cap and 

trading in the United States and Canada. 

H.1.1.1 The Power Sector in the United States 

and Canada 

The U.S. and Canadian power sectors are 

significantly different in size, scope, and 

composition. In 2003, electric generating sources 

in the United States produced roughly 3,850 

billion kilowatt hours (kWh) to meet electricity 

93 
Canada-United States Emissions Cap and Trading Feasibility Study 

demand, while Canadian sources produced 

roughly 580 billion kWh. In the United States, 

over 70 percent of this electricity was produced 

through the combustion of fossil fuels, primarily 

coal and natural gas, while 26 percent of this 

generation was produced from fossil fuels in 

Canada (Figure H-1). 

Electricity generation in Canada comes 

predominantly from hydroelectric units (60 

percent); the remaining generation comes from 

fossil fuel units (26 percent), nuclear units (12 

percent), and other units such as wind turbines. 

While hydro is the main source of generation 

nationally, in certain regions, such as Alberta, 

Saskatchewan, Ontario, New Brunswick, and 

Nova Scotia, coal combustion plays a significant 

role. In the United States, about half of all 

generation is produced from coal-generating 

facilities, dispersed throughout the country, with 

most of the coal capacity located in the eastern 

portion of the country. Figure H-2 is a map of 

both countries showing the population of existing 

U.S. and Canadian fossil fuel-fired power plants 

larger than 25 megawatts that are inputs to IPM. 

Table H-1 displays existing U.S. and Canadian 

capacity by source type. 

The burning of fossil fuels results in air 

emissions of SO2 and NOX, important precursors 

to the formation of fine particles (PM2.5) and 

ozone, which contribute to serious negative 

environmental and health effects. The power 

sector is a major contributor of both these 

pollutants, and emissions of SO2 and NOX are 

essential to any discussions in the transboundary 

context. In 2003, the power sector in the 

United States accounted for 67 percent of total 

nationwide SO2 emissions and 22 percent of 

total nationwide NOX emissions. In 2002, in 

Canada, the power sector accounted for 

approximately 26 percent of total nationwide 

SO2 emissions and 11 percent of nationwide 

NOX emissions. (For more information, see 

Figure A-9 in Section A for pie graphs of SO2 

and NOX emissions.) 

The U.S. and Canadian power sectors are 

integrated, with electricity flowing back and 

forth, depending on seasonal demand. Canada 

is generally a net exporter of electricity to the 

United States, sending between 7 and 9 percent 

of the total power generated in Canada to the 

United States. Typically, Canadian sources sell 

power to the United States during peak demand 

periods, mostly from hydro. While electricity 

flows from Canada to the United States continue 

to exceed flows from the United States to 

Canada, the past several years have seen 

increasing flows from the United States to 

Canada. In 2003, the United States imported 

roughly 5 billion kWh, or about 0.1 percent of 

all U.S. electricity consumed. 

H.1.1.2 Power Sector Model 

In discussing the impacts of cap and trade, 

the primary focus in the United States has 

historically been the power sector. The U.S. EPA 

has extensive experience with analytical tools 

specific to the power sector that have helped 

inform and direct environmental policy for the 

past 15 years, beginning with the Acid Rain 

Program in 1990 and up through EPA’s most 

recent regulatory cap and trade initiative, the 

Clean Air Interstate Rule (CAIR), promulgated in 

March 2005. The IPM model has been used to 

examine air pollution control policies for SO2 

and NOX throughout the contiguous United 

States for the entire power system. As part of 

this feasibility study under the Border Air Quality 

Strategy, a module that reflects the Canadian 

power sector was developed and added to the 

existing IPM model of the U.S. power sector. 

In addition, the IPM model that reflects the 

U.S. power sector was improved and enhanced. 

In order to assess the impacts of emission 

reductions with and without cross-border 

emissions cap and trading between the two 

countries, the IPM model was run using 

illustrative modeling scenarios, where emission 

restrictions on SO2 and NOX were applied in 

both countries. In addition to the power sector 

modeling, air quality modeling was also 

performed. 

94 
Section H


Figure H-1 Electricity Generation in Canada and the United States, 2003


Source: U.S. Energy Information Administration and Statistics Canada. 

Figure H-2 IPM Inputs of U.S. and Canadian Fossil Fuel-Fired Power Plants Showing 

Locations and Characteristics of the Plants Used in IPM 

95 
Canada-United States Emissions Cap and Trading Feasibility Study 

Table H-1 Existing U.S. and Canadian Electricity Generating Capacity by Source 

Energy source 

United States (2002) Canada (2003) 

Number of 

generators 

Generator 

nameplate 

capacity (MW) 

Number of 

generators 

Generator 

nameplate 

capacity (MW) 

Coal 1,566 338,199 58 16,901 

Oil/gas 9,044 420,558 887 15,631 

Nuclear 104 104,933 15 11,155 

Hydro 4,157 96,343 1,493 70,374 

Other 1,542 19,553 474 2,931 

Total 16,413 979,586 2,927 116,991 

Source: U.S. Energy Information Administration and Statistics Canada. 

Development of the Canadian module of 

the IPM model grew out of recognition that 

emissions transport across the U.S.-Canada 

border and the growing interdependence and 

restructuring of the electricity markets in the two 

countries present Canadian and U.S. air quality 

policymakers with the challenge of coordinating 

approaches to limiting power plant emissions. 

Developing more sophisticated analytical tools 

to examine cross-border air quality issues was 

seen as an important step toward increasing 

understanding of emissions in the cross-border 

region and evaluating possible air quality 

policies. The Canadian IPM module was intended 

to meet the following goals: 

•	 Represent the Canadian power sector 

(excluding industrial boilers), in support 

of analyzing transboundary emission cap 

and trading issues, and be compatible 

with similar analytical tools used by EPA. 

•	 Provide analyses of the electric power 

sector in Canada in order to identify the 

distinctive geographic, technological, 

economic, financial, legal, operational, 

and environmental features that will need 

to be incorporated into a model of the 

Canadian electric power sector. 

•	 Design, program, test, implement, and 

document a model of the Canadian power 

sector that would be able to run both 

independently and in combination with 

the U.S. models to perform cross-border 

emissions policy analysis. 

•	 Provide outputs at the national, regional, 

and provincial levels and unit-level, point 

source emission values that can be used 

as inputs to atmospheric and health 

effects models. 

The IPM model was seen as offering a 

number of important advantages in meeting 

these goals. IPM is a well-established model 

of the electric power sector, designed to help 

government and industry analyze a wide 

range of issues related to this sector. The 

model represents economic activities in key 

components of energy markets: fuel markets, 

emission markets, and electricity markets. Since 

the model captures the linkages in electricity 

markets, it is well suited for developing 

integrated analyses of the impacts of alternative 

regulatory policies on the power sector. In 

the past, applications of IPM have included 

capacity planning, environmental policy analysis 

and compliance planning, wholesale price 

forecasting, and asset valuation. IPM’s 

representation of the electric power sector 

has achieved a high level of credibility growing 

out of an established record of use by a wide 

range of private and public sector clients and 

its extensive application in analyzing and 

developing emission policies in the United 

States. It is particularly well suited for modeling 

the operation of the North American electric 

power system due to its detail-rich depiction 

of the sector, its refined representation of the 

dispatch and capacity expansion behavior 

96 
Section H


of electricity generating units, and its bottomup representation of emissions, emission 

control technologies, and fuels. IPM 

also has a wide array of regulatory options 

for implementing emission reduction policies, 

ranging from traditional “command and 

control” policies to market-based cap and 

trade programs. 

The IPM model offers the capability to project 

results down to the generating unit level, and 

it produces outputs that can be used in other 

models (e.g., atmospheric, deposition, health 

effects, cost/benefit models). Since EPA is 

already using IPM for modeling the U.S. electric 

power sector, there would be immediate 

structural compatibility between the U.S. and 

Canadian models. It also would allow Canada 

to take advantage of prior U.S. modeling work 

and expertise, thereby fostering more informed, 

faster, and cost-effective model development. 

Its applications for EPA are fully documented, 

and it has had a long history of public and expert 

review. 

Canadian efforts focused on the Canadian 

IPM module, intended to provide a representation 

of the Canadian electric power sector comparable 

to the representation of the electric power sector 

in the implementation of the IPM model being 

used by EPA. The sector scope includes power 

sector generators that sell the majority of their 

output to the grid. The geographic scope includes 

all provinces. Although the IPM model is capable 

of modeling many pollutants in the electricity 

sector, including carbon dioxide, mercury, and 

particulate matter (PM), the pollutants of focus in 

the Canadian module are SO2 and NOX. 

For the Canadian IPM module, a database 

of existing generating units was developed, 

including existing hydro, nuclear, fossil fuel, 

biomass, and other non-fossil fuel EGUs. The 

database also included the specific characteristics 

of these existing generating units, such as 

generation capacities, unit types, fuel types used, 

unit availabilities, emission rates, and heat rates. 

The Canadian module required characterizations 

of Canada’s national and regional electricity 

demand, peak demand, and load duration 

curves by season as well as a characterization 

of transmission interconnection capacities, loss 

factors, and charges for the transmission grid 

connecting Canada’s regions as well as the shared 

Canada-U.S. transmission grid. 

Cost and performance characterizations 

were also developed for new generating units 

and environmental control technologies. Care 

was taken to maintain consistency with the U.S. 

IPM model assumptions by using the same basis 

for estimating cost and performance of generation 

and environmental control technologies. This 

was necessary to ensure that the results (e.g., 

trading opportunities, costs of compliance) 

would reflect real differences in the system 

characteristics (e.g., current control levels, 

emission rates, opportunities for reductions) 

and not the fact that the U.S. and Canadian 

models assumed that control technologies 

have fundamentally different costs. It was critical 

that the inputs to the two models reflected real 

differences between the two countries. 

Financial assumptions were developed 

based on both “expert” input from Canadian 

federal government departments and the EPA 

IPM model Base Case (v. 2.1.6). Fuel price 

structures and projections were developed for 

coal, natural gas, fuel oil, orimulsion, biomass, 

and nuclear fuel. Existing federal and provincial 

laws and regulations that affect NOX and SO2 

emissions from the electric power sector were 

also taken into account. 

The development of the Canadian module for 

the IPM model could not have been completed 

without the support, advice, experience, guidance 

and knowledge of the EPA. A detailed technical 

report documenting all of the assumptions and 

inputs in the Canadian module of the IPM model 

is available on Environment Canada’s Clean Air 

online Web site at http://www.ec.gc.ca/cleanairairpur/can-us_border_air_quality_strategy_ 

wsd6f2621E-1_en.htm. EPA IPM model 

documentation is also available on EPA’s Web site 

at http://www.epa.gov/airmarkets/epa-ipm/. 

97 
Canada-United States Emissions Cap and Trading Feasibility Study 

H.1.1.3 Post-Processing of IPM Model Power 

Sector Emission Projections for Air Quality 

Modeling 

In order to perform air quality modeling using 

IPM power sector emission projections, EPA 

uses a process to convert and enhance IPM 

output files to better reflect exact EGU conditions, 

in terms of emissions and unit characteristics. 

The IPM post-processing methodology involves 

taking IPM output files and transforming them 

into air quality model input files. It enhances 

the IPM outputs by adding additional parameters 

important for air quality modeling, such as 

estimates of additional emissions, stack 

parameters, unit information, disaggregating 

and siting units, and adding identifiers. 

Post-processing IPM model files into air 

quality model input files has occurred for almost 

a decade for the U.S. power sector. This process 

was expanded to include the Canadian power 

sector. Through collaboration between EPA and 

Environment Canada, the necessary location and 

configuration data for the Canadian EGUs were 

gathered and air quality model input files were 

developed. This represents significant progress 

in the development of air quality modeling 

related to the power sector in North America, 

as air quality models have not previously had 

such precise information regarding Canadian 

EGUs. Although there is still additional work to 

be done to improve the information that is now 

available, this marks an important development 

that was instrumental in analyzing cross-border 

cap and trading scenarios. 

H.1.2 Air Quality Models 

Air quality modeling was performed by Canada 

and the United States to evaluate the air quality 

impact of an illustrative cross-border cap and 

trade scenario. The two countries have a long 

history of experience in developing and applying 

air quality models to analyze air pollutant 

emission control scenarios. Both countries 

have performed joint air quality modeling in 

the past, notably as part of the National Acid 

Precipitation Assessment Program (NAPAP) 

studies, undertaken in the 1980s, and most 

recently in preparing the Canada–U.S. GroundLevel Ozone and Transboundary PM Science 

assessments. The work in this study builds on 

the joint modeling that was done as part of the 

most recent Canada–U.S. Transboundary PM 

Science Assessment released in February 2005 

and available online at http://www.ec.gc.ca/pdb/ 

can_us/canus_links_e.cfm. 

U.S. air quality modeling for PM2.5, visibility, 

and deposition was conducted using the 

Community Multiscale Air Quality Model 

(CMAQ). The CMAQ model is the result of 

scientific and technical collaboration by 

hundreds of researchers from around the 

world over the last 10 years, resulting in 

a state-of-the-art modeling system for 

investigating the impact of emissions upon 

air quality indicators of interest, such as PM2.5 

concentrations, acid deposition, and visibility. 

The CMAQ “base case” modeling scenario 

used in this study was based on the work 

performed and documented in detail for 

the Clean Air Interstate Rule (see the air 

quality modeling technical support document 

for details of the model configuration, base 

year emission inventory, and meteorology at 

http://www.epa.gov/cair/technical.html). 

The base year for this study is 2001 as in the 

EPA’s recent CAIR analysis, with updated 

estimates of Canadian emission sources 

provided as part of this feasibility study by 

Environment Canada. CMAQ was used to 

provide illustrative results as to air quality 

impacts of a cross-border emissions cap and 

trade scenario. As detailed in Table H-2, the 

annual average PM2.5 concentrations, visibility, 

and deposition estimates for each of the 

emission scenarios in two modeled years 

are provided. 

Canadian episodic modeling was performed 

using AURAMS (A Unified Regional Air Quality 

Modelling System). AURAMS simulations were 

performed for two episodes (one in summer, 

one in winter) to evaluate the relative impact 

98 
Section H


Table H-2 Figures Demonstrating Projected Changes in Environmental Endpoints from 

Air Quality Modeling of an Illustrative U.S.–Canada Cross-Border Emissions Cap and 

Trade Scenario 

Model Period Modeled Parameter Figure 

CMAQ Annual Average (PM2.5) 15-17 

AURAMS Winter Episode Average (PM2.5) 18 

AURAMS Summer Episode Average (PM2.5) 19 

AURAMS Summer Episode Peak (O3) 20 

CMAQ Annual Total S Deposition 21 

CMAQ Annual Total Oxidized N Deposition 22 

CMAQ Annual Visibility (Deciview) 23 

of each scenario modeled by IPM. The summer 

simulation spans the period from July 1 through 

July 19, 1995, and covers a regional ozone 

episode that is also associated with high levels 

of PM. The winter simulation covers the period 

from February 1 through February 16, 1998. 

The February 1998 simulation period was chosen 

because of the occurrence of a wintertime 

regional PM episode over a large portion of 

northeastern North America during the second 

week of the period. 

In both the U.S. CMAQ and Canadian 

AURAMS modeling, for each scenario modeled, 

the emissions from electric power plants 

predicted by IPM were used to replace power 

plant emissions, and all other emissions were 

held constant to the 2001 base year simulation 

values. This approach resulted in the observed 

changes in model output being isolated to the 

effects of the given cap and trade scenario. 

H.1.2.1 The AURAMS Air Quality Model 

AURAMS is a unified regional air quality 

modeling system developed by Environment 

Canada for research and policy applications. 

Designed as a “one-atmosphere” system, 

AURAMS allows the study of interactions 

between NOX, VOCs, ammonia, ozone, and 

primary and secondary PM through aqueous, 

gaseous, and heterogeneous reactions. AURAMS’ 

credentials have been documented in the peerreviewed literature (Bouchet et al., 2003; Makar 

et al., 2003, 2005; Gong et al., 2005), and the 

model has been used for both joint U.S.-Canada 

assessments (Transboundary PM Science 

Assessment) and joint U.S.-Canada experiments 

(McKeen et al., 2005). 

AURAMS version 1.1 was used for the 

feasibility study. Updates from the version used 

for the Canada-U.S. Transboundary PM Science 

Assessment included an extension of the 

modeling domain to cover the western part 

of the continent, optimization of the chemistry 

modules, and inclusion of a plume-rise 

calculation. Figure H-3 depicts the AURAMS 

modeling domain, encompassing all Canadian 

provinces and U.S. states between 30 and 60 

degrees north latitude with a horizontal resolution 

of approximately 42 km by 42 km. 

H.1.2.2 The CMAQ Air Quality Model 

The CMAQ modeling system is a comprehensive 

three-dimensional grid-based Eulerian air 

quality model designed to estimate particulate 

concentrations and deposition over large spatial 

scales (Dennis et al., 1996; Byun and Ching, 

1999; Byun and Schere, 2004). The CMAQ model 

is a publicly available, peer-reviewed, state-ofthe-science model consisting of a number of 

science attributes that are critical for simulating 

the oxidant precursors and nonlinear organic 

and inorganic chemical relationships associated 

with the formation of sulfate, nitrate, and organic 

aerosols. CMAQ also simulates the transport and 

removal of directly emitted particles that are 

99 
Canada-United States Emissions Cap and Trading Feasibility Study 

Figure H-3 Map of the AURAMS Figure H-4 Map of the CMAQ Modeling 

Modeling Domain Used in the Domain Used for CAIR 

Feasibility Study 

speciated as elemental carbon, crustal material, 

nitrate, sulfate, and organic aerosols. 

Version 4.3 of CMAQ (Byun and Schere, 2004) 

was used for this feasibility study. This version 

reflects updates to earlier versions in a number 

of areas to improve the underlying science and 

address comments from the peer review. This 

version of the model is the same as that applied 

for CAIR modeling and as specified in detail in 

the CAIR air quality modeling technical support 

document (TSD) (http://www.epa.gov/ 

cair/pdfs/finaltech02.pdf). In addition, the 

CMAQ meteorological, initial, and boundary 

conditions used here are the same as those used 

in the CAIR modeling, as specified in detail in the 

CAIR TSD. Finally, the CMAQ modeling domain 

was also the same as that used for CAIR analysis, 

encompassing the lower 48 states and portions 

of Canada and Mexico (as shown in Figure IV-1 

provided at the end of Section IV of the CAIR TSD 

and reproduced here as Figure H-4). The domain 

extends from 126 degrees to 66 degrees west 

longitude and from 24 degrees north latitude to 

52 degrees north latitude. The horizontal grid 

cells are approximately 36 km by 36 km. The 

modeling domain contains 14 vertical layers, 

with the top of the modeling domain at about 

16,200 meters, or 100 millibars (mb). 

H.2 ILLUSTRATIVE 

MODELING SCENARIOS 

FOR CROSS-BORDER SO2 

AND NOX EMISSIONS CAP 

AND TRADING 

Using the enhanced version of IPM, which is 

capable of modeling an integrated U.S.-Canada 

power system, various illustrative modeling 

scenarios were developed to assess the potential 

impacts of caps and cross-border trading. For 

the emission caps on the electricity sector in a 

cap and trade system, a decision was made 

to develop SO2 and NOX emission caps based 

upon the levels set in the U.S. Clear Skies 

proposal of 2003. This legislative proposal has 

been analyzed and modeled in the United States. 

It must be emphasized that these cap levels were 

used for illustration purposes only. 

The primary scenario used for analysis, the 

Trading Scenario, is one that applies Clear Skies 

(2003) cap levels for SO2 and NOX in both the 

United States and Canada and allows crossborder trading. The Canadian caps were 

developed by applying the percent reduction 

that roughly reflects what Clear Skies (2003) is 

designed to achieve in the United States. The 

U.S. and Canadian caps were then combined to 

obtain one joint SO2 cap and one joint NOX cap 

for both countries. Note that all fossil fuel-fired 

100 
1 

Section H

Table H-3 Illustrative Emission Caps for the United States and Canada 

Year 

Emission caps (million short tons) 1 

United States Canada 

Joint crossborder caps 

SO2 2010 

2018 

4.5 

3.0 

0.5 

0.3 

5.0 

3.3 

NOX East 2008 

2018 

1.6 

1.2 

0.05 

0.04 

1.6 

1.2 

NOX West 2008 0.5 0.09 0.6 

One tone is equal to 1.1 short tons. 

EGUs with a capacity greater than 25 MW and 

producing electricity for sale to the grid are 

covered by the SO2 and NOX caps in this 

scenario. 

A base case, or reference case, was also 

modeled. The Base Case includes all existing 

pollution reduction programs that were in place 

in 2004 and provides a comparison point to 

determine the incremental impacts of a given 

emission reduction scenario. The model’s base 

case incorporates, for the United States, Title IV 

of the Clean Air Act (the Acid Rain Program), 

the NOX SIP call, various New Source Review 

(NSR) settlements, and several state rules 

affecting emissions of SO2 and NOX. The Base 

Case does not include EPA’s recent regulation, 

CAIR. For Canada, the Base Case includes all 

current requirements for the power sector for 

SO2 and NOX emissions. In terms of emission 

caps in Canada’s base case, emission caps exist 

only in Ontario and Quebec, where there are 

annual NOX caps in place to be met by 2007. The 

Base Case is used to provide a reference point to 

compare environmental policies and assess their 

impacts and does not reflect any future predicted 

scenario. 

The caps for each country, along with the 

combined caps, are shown in Table H-3. For 

NOX, two separate caps were modeled to reflect 

Clear Skies (2003), where separate NOX zones 

were proposed (see Figure H-5), along with a 

national SO2 cap. 

Finally, a third scenario, “Clear Skies Act 

(CSA) in U.S. only,” applied the Base Case to 

Canada with no additional emission reductions 

and no cross-border trading along with Clear 

Skies caps and trading in the United States. This 

third scenario provided the basis for comparing 

results in the United States with and without 

cross-border trading. 

In addition to the main Trading Scenario, 

various sensitivity runs (see Section H.3.6 for 

more information) were also modeled to help 

answer some important questions regarding 

trading, such as the benefits and advantages 

of trading, as well as questions concerning the 

stringency and equivalency of the cap levels 

for each country. 

H.3 RESULTS FOR THE 

POWER SECTOR USING THE 

INTEGRATED PLANNING 

MODEL 

The Trading Scenario impacts each country’s 

respective power sector differently, since 

there are significant power sector differences 

in each country. Because total emissions are 

considerably lower in Canada than in the United 

States, the magnitude of reductions in Canada 

will be much less than the reductions one would 

anticipate in the United States. To provide a 

general sense of the potential impacts of caps 

and cross-border trading and how those impacts 

are unique to each country, IPM model results for 

both countries are presented. 

H.3.1 Emissions 

Figures H-6, H-7, and H-8 show, for the Base 

Case and Trading Scenario, the state- and 

101 
Canada-United States Emissions Cap and Trading Feasibility Study 

Figure H-5 NOX East and West Model Regions for Illustrative Analysis 

Figure H-6 Annual SO2 Emissions in 2010 and 2020, Comparing the Base Case 

(with no caps in Canada) with the Illustrative Trading Scenario (with caps in Canada 

and cross-border trading) 

102 
Section H


Figure H-7 Annual NOX Emissions in 2010 and 2020, Comparing the Base Case 

(with no caps in Canada) with the Illustrative Trading Scenario (with caps in Canada 

and cross-border trading) 

Figure H-8 Summer NOX Emissions in 2010 and 2020, Comparing the Base Case 

(with no caps in Canada) with the Illustrative Trading Scenario (with caps in Canada 

and cross-border trading) 

103 
Canada-United States Emissions Cap and Trading Feasibility Study 

Emissions of SO2 and NOX from the U.S. Power Sector – Base Case, Clear 

province-level 2010 and 2020 annual SO2, 

annual NOX, and summer NOX emissions, 

respectively. 

Modeling the Trading Scenario with caps 

and cross-border trading show broad reductions 

in SO2 and NOX emissions in both countries. 

Specifically, for the United States (as seen in Thousand Tons

Figure H-9 

Skies U.S., and the Illustrative Trading Scenario 

Figure H-10 

and the Illustrative Trading Scenario 

Base Case Cross-BorderTrading with Caps in Bot Countries 

Source: IPM 

Source: IPM 

12,000 

10,000 

8,000 SO2 

6,000 

4,000 

Base Case 

CSA in US Only* 

Trading (w/ Caps in Both Countries)* Cross-BorderTrading with Caps i Both Countries 

Base Case

CSA in US Only* 

Emissions (thousand tons)

NOx 

2,000 

0 

2010 2015 2020 

Note: Lines are on top of each other as the scenario results are virtually the same. 

Emissions of SO2 and NOX from the Canadian Power Sector – Base Case Emissions (thousand tons) 

Figure H-9), the projections from IPM are similar 

to the original Clear Skies (2003) analysis. 

In Canada (Figure H-10), with emission caps 

under the Trading Scenario, emissions of NOX 

and SO2 are projected to be roughly 30 percent 

lower in 2010, relative to the Base Case, and 40 

to 50 percent lower in 2020. 

104
Section H


Figure H-11 Annual Incremental Costs to the Base Case for the U.S. Power Sector of 

Illustrative Trading Scenario 

Source: IPM 

H.3.2 Allowance Prices 

Allowance prices for SO2 and both NOX zones 

are not greatly altered when Canadian sources 

are capped and included in a cross-border 

trading program (the Trading Scenario) from 

what they would be under the Clear Skies U.S. 

only case. In 2015, the NOX West allowance 

prices increase when Clear Skies (2003) is 

expanded to include Canada, the only notable 

difference. 

H.3.3 Costs 

For the United States, the total annualized 

incremental cost of Clear Skies (2003) does not 

change significantly whether there is crossborder trading with Canada or not (Figure H-11). 

The incremental cost represents the additional 

costs to the power sector of reducing emissions, 

as required in the cap and trade program. The 

difference in costs is roughly between $100 

million to $180 million (U.S. 1999) as a result of 

slight changes in the way in which the power 

sector chooses to meet the emission caps in the 

most cost-effective manner. 

As expected, in Canada, by requiring the 

power sector to achieve emission reductions 

through caps, the Trading Scenario with crossborder emission caps and trading will cost the 

electricity sector in Canada more than under 

the Base Case, where there are no emission 

reductions. Based on the modeling that was 

done, the total annualized incremental cost of 

capping the electricity sector in Canada under 

the illustrative cross-border emissions cap and 

trading scenario ranges from about $130 million 

U.S. in 2010 to roughly $460 million U.S. in 2020 

(see Figure H-12). 

H.3.4 Electricity Generation 

As projected in IPM, the United States will 

eventually be a net exporter of electricity to 

Canada in the future, which is consistent with 

general trends in electricity production over 

the last 10 to 20 years. The Trading Scenario 

with caps and cross-border trading, does not 

alter this forecast in any meaningful way, since 

the change in the amount of electricity sent 

to Canada from the United States represents 

less than one-tenth of a percent of total U.S. 

generation and less than seven-tenths of a 

percent of total Canadian generation. By 2020, 

Canada is projected to import net electricity of 

105 
Canada-United States Emissions Cap and Trading Feasibility Study 

Figure H-12 Annual Incremental Costs to the Canadian Power Sector of Illustrative 

Trading Scenario 

128 

227 

456 

Costs (millions US$) 

Source: IPM 

8.1 terrawatt hours (TWh) under the caps and 

cross-border trading scenario and 12 TWh under 

the base case scenario. Therefore, the same 

trend is observed in the Base Case as with caps 

and cross-border trading: less Canadian reliance 

on imported U.S. electricity in 2020 with the caps 

and cross-border trading scenario relative to the 

Base Case. 

H.3.5 Generation Mix 

The total generation mix in the United States is 

not changed in any significant way (Figure H-13). 

Similarly, the total generation mix in Canada is 

not altered significantly with caps and crossborder trading (Figure H-14). There are minimal 

shifts in the generation mix with caps and crossborder trading compared with the Base Case. 

Canadian natural gas-fired generation is 

projected to increase slightly, while coal-fired 

generation is projected to decline somewhat in 

the caps and cross-border trading scenario. 

H.3.6 Sensitivity Analyses using IPM 

To help inform the issue of caps and crossborder trading, sensitivity analyses were 

conducted using IPM to answer questions 

regarding the benefits of cap and trade to 

both countries and the levels of reductions or 

costs that are possible in Canada and if emission 

reductions were implemented by the power 

sector in Canada. The sensitivity runs also 

analyzed the impact of cross-border trading 

with a tighter SO2 cap in Canada, the difference 

in costs and emissions in Canada between 

emission caps on the Canadian power sector 

with and without cross-border trading, and the 

impacts of an alternative, less flexible control 

strategy. (It is important to note that the analysis 

only modeled trading in Canada when there was 

cross-border trading available). 

The sensitivity analyses show clearly that 

the level of the cap has a major impact on 

costs to the power sector, the distribution of the 

costs, the location of emission reductions, the 

extent of emission reductions, and the extent 

of the air quality and environmental benefits. 

Applying a tighter Canadian SO2 cap when 

allowing cross-border trading resulted in 

additional reductions and slightly higher costs 

in both countries. 

Further, the sensitivity analyses show that 

meeting the emission reduction limits in the 

Canadian power sector would be significantly 

less expensive if cross-border trading were 

available. The analyses demonstrate that 

because the cost to the power sector of 

achieving the emission reductions is lower with 

cross-border trading than without, if cost is the 

driver, the power sector could afford to reduce 

106 
Section H

Figure H-13 U.S. Generation Mix – Base Case, Clear Skies U.S., and the Illustrative 

Trading Scenario 

Base 

Case 

CSA 

in US 

only 

CrossBorder 

Trading 

with Caps 

in Both 

Base 

Case 

CSA 

in US 

only 

CrossBorder 

Trading 

with Caps 

in Both 

Base 

Case 

CSA 

in US 

only 

CrossBorder 

Trading 

with Caps 

in Both 

Generation (TWh)

2010 2015 2020 Other 

Renewables 

Hydro 

Nuclear 

Oil/Gas 

Coal 

Countries Countries Countries 

CSA = Clear Skies (2003)


Source: IPM


Figure H-14 Canadian Generation Mix – Base Case and the Illustrative Trading Scenario 

CrossBorder 

Trading 

with Caps 

in Both 

Countries 

Base 

Case 

Base 

Case 

Base 

Case 

CrossBorder 

Trading 

with Caps 

in Both 

Countries 

CrossBorder 

Trading 

with Caps 

in Both 

Countries 

Generation (TWh) 

Source: IPM 

significantly fewer emissions if cross-border 

trading were not available. The primary reason 

for these results is the flexibility that trading 

allows, since greater flexibility lets sources find 

the most cost-effective way to achieve emission 

reductions. In Canada, the same level of 

emission reductions without flexibility (i.e., 

with no cross-border trading) could result in 

costs of roughly $130-$230 million more, 

depending on the year. Additionally, the same 

level of costs without that same flexibility (i.e., 

with no cross-border trading) would likely 

107 
Canada-United States Emissions Cap and Trading Feasibility Study 

achieve fewer SO2 emission reductions (80,000 

to 125,000 tons less) and fewer NOX emission 

reductions (35,000 to 45,000 tons less), 

depending on the year in question. 

These results reaffirm what has been the U.S. 

experience with existing cap and trade programs. 

Cap and trade programs achieve the required 

emission reductions in a more cost-effective 

and efficient manner than less flexible control 

requirements. In addition, many factors in a cap 

and trade program will influence the costs of 

reducing emissions, the amount of emission 

reductions, and where those reductions occur. 

Additional work needs to be undertaken to 

further explore these issues in a cross-border 

emissions cap and trading context. 

H.4 RESULTS FROM AIR 

QUALITY MODELING 

Air quality modeling was carried out in the 

United States and Canada to determine the 

impacts of caps and cross-border trading on air 

quality, acidification, and visibility. In particular, 

the air quality modeling looked at the resulting 

concentrations in the air of fine particles (PM2.5) 

and ozone, as well as acidification (sulfur and 

nitrogen deposition) and visibility (in deciviews). 

Building on the scenarios developed for the 

joint IPM modeling, the air quality modeling 

starts from the same base case in which the 

United States incorporates Title IV of the Clean 

Air Act (the Acid Rain Program), the NOX SIP call, 

various NSR settlements, and several state rules 

affecting emissions of SO2 and NOX. The Base 

Case does not include EPA’s recent regulation, 

CAIR, promulgated in March 2005. Canada has 

current requirements but no power sector caps 

for SO2 and NOX in place (except in Ontario and 

Quebec, where there are annual NOX caps to be 

met by 2007). The Base Case is used to provide 

a reference point to compare environmental 

policies and assess their impacts and does 

not reflect a future predicted scenario. The 

air quality modeling compares this Base Case 

to the Trading Scenario that applies the U.S. 

Clear Skies (2003) cap levels for SO2 and NOX 

in Canada, establishing the cap levels in Canada 

using percent reductions that roughly reflect the 

levels that Clear Skies (2003) is designed to 

achieve in the United States and allowing crossborder trading between the two countries. 

H.4.1 Annual PM2.5 

Figures H-15 and H-16 show annual percent 

PM2.5 reductions across the domain from 

modeling using the CMAQ model for the years 

2010 and 2020. The figures indicate significant 

regional reductions in annual PM2.5 over a 

broad geographic area covering the eastern 

United States and Canada. Reductions of 10 to 

20 percent occur over significant areas of eastern 

North America in 2010 and are maintained and 

expanded through 2020 under the modeled 

cross-border cap and trade scenario. Most 

significant improvement is observed in the midAppalachian area of the United States, with 

smaller, but noticeable, improvements extending 

well into Ontario and across New England and 

eastern Canada. With caps and cross-border 

trading, broad regional reductions in fine 

particles are achieved over the significant crossborder receptor area in eastern North America 

in this illustrative scenario. 

In Figure H-17, with caps and cross-border 

trading, the model projects an absolute 

improvement in the average concentration 

of fine PM2.5 of 1 to 3 micrograms per cubic 

meter (μg/m3) for broad areas of eastern 

North America in 2020. 

H.4.2 Absolute Change in Fine Particles with 

Emission Reductions and Trading during a 

Winter Episode 

Using AURAMS to model a winter episode when, 

generally speaking, the PM2.5 composition is less 

influenced by SO2 emission reductions, shows the 

main decrease in PM2.5 concentrations occurring 

over most of Iowa and neighboring states, with 

smaller decreases observed in select parts of 

Canada (Figure H-18). At the same time a small 

area of increased PM2.5 concentration can be 

108
Section H


Figure H-15 Percent Change in Annual Fine Particles with Emission Reductions under 

Illustrative Trading Scenario Compared to Base Case in 2010 (CMAQ) 

Figure H-16 Percent Change in Annual Fine Particles with Emission Reductions under 

Illustrative Trading Scenario Compared to Base Case in 2020 (CMAQ) 

observed over Kentucky. This small increase in 

PM mass is due to a change in the sulfate-tonitrate ratio where, under winter conditions, 

nitrate formation compensates for lower ambient 

sulfate levels compared to the annual simulations. 

The decrease in concentration is more limited in 

spacial extent and intensity, implying that more of 

the PM decrease in concentration occurs during 

other seasons. 

H.4.3 Absolute Change in Fine Particles with 

Emission Reductions and Trading during a 

Summer Episode 

As seen in Figure H-19, the PM concentration 

change from the AURAMS model during a 10-day 

summer episode shows large-scale reductions 

over most of the eastern part of the continent on 

the order of 1 to 5 μg/m3, with significant areas 

showing even greater reductions, particularly 

in the United States. This represents reductions 

on the order of 15 to 25 percent in some areas. 

109 
Canada-United States Emissions Cap and Trading Feasibility Study 

Figure H-17 Absolute Change in Annual Fine Particles (ug/m3) with Emission Reductions 

under Illustrative Trading Scenario Compared to the Base Case in 2020 (CMAQ) 

Figure H-18 Absolute Difference in PM2.5 Concentration (μg/m3), Comparing 

Illustrative Trading Scenario to the Base Case during the Winter Episode for 2020 

(AURAMS) 

Decreases in PM concentration are also observed 

in the eastern Canadian provinces, particularly 

Ontario and Quebec, but also, to a lesser extent, 

in the Maritimes, Saskatchewan, and Alberta. 

These findings from the AURAMS model, relative 

to location and extent of PM2.5 reductions, are 

compatible with the findings from the CMAQ 

model done on an annual basis. 

H.4.4 Absolute Change in Ozone with 

Emission Reductions and Trading during a 

Summer Episode 

Results from AURAMS for the 10-day summer 

episode in Figure H-20 show large-scale 

reductions (blue areas) in ozone concentrations 

over a broad geographic area from caps and 

cross-border trading on the order of 1 to 5 parts 

per billion (ppb). 

110 
Section H


Figure H-19 Absolute Difference in PM2.5 Concentration (ug/m3), Comparing 

Illustrative Trading Scenario to the Base Case during the Summer Episode for 

2020 (AURAMS) 

Figure H-20 Absolute Difference between Illustrative Trading Scenario to the Base 

Case for Ground Level Ozone Daily Maximum (ppb) during the Summer Episode for 

2020 (AURAMS) 

For Canada, Figure H-20 presents a general 

decrease in ozone concentrations in the border 

regions and the Maritimes. In localized areas, 

including southern British Columbia’s Lower 

Fraser Valley, air quality is below the standard 

for ozone but public interest is high. The 

modeling shows that caps with cross-border 

trading would result in reductions in ozone on 

the order of 1 to 5 ppb in these populated areas. 

In other parts of Canada, and a few locations in 

the U.S., the AURAMS simulation for this one 

10-day episode in the summer shows slight 

localized increases in ozone in urban areas and 

some rural locations downwind of major plants. 

An analysis of the ozone precursors has shown 

that these slight increases of just over 1 ppb are 

due to less NOX being available to destroy ozone, 

as a result of the reductions in NOX emissions 

under the caps with cross-border trading 

scenario. (See Seinfeld and Pandis, 1998). 

111 
Canada-United States Emissions Cap and Trading Feasibility Study 

Figure H-21 Percent Change in Sulfur Deposition with Emission Reductions under 

Illustrative Trading Scenario Compared to Base Case in 2020 (CMAQ) 

Figure H-22 Percent Change in Nitrogen Deposition with Emission Reductions under 

Illustrative Trading Scenario Compared to Base Case in 2020 (CMAQ) 

H.4.5 Acidification: Sulfur Deposition 

CMAQ modeling demonstrates in Figure H-21 

that sulfur deposition will decrease across the 

eastern United States and Canada with an 

emission cap and cross-border trading scenario 

compared to the Base Case. Similar to the PM2.5 

concentrations presented above, total annual 

sulfur deposition is reduced across the sensitive 

receptors of eastern North America, notably in 

the receptor areas of upstate New York and 

eastern Canada. The whole domain experiences 

a reduction in 2010 (not shown) that expands 

and deepens in 2020 (Figure H-21). The 

largest reductions, from 30 to 65 percent, are 

projected to occur in the 2020 simulation in 

the midwestern states, the Appalachian area, 

and parts of New England in the United States, 

as well as in Ontario, Quebec, and the Maritime 

provinces. The emissions cap and cross-border 

trading approach produces significant broad 

112
Section H


Figure H-23 Absolute Change in Visibility (Deciviews) with Emission Reductions 

under Illustrative Trading Scenario Compared to Base Case in 2020 (CMAQ) 

regional reductions in sulfur deposition over 

the cross-border receptor area in eastern North 

America. 

H.4.6 Acidification: Nitrogen Deposition 

Modeling projections show in Figure H-22 that 

nitrogen deposition reductions will be seen 

across nearly all of the U.S. and cross-border 

Canadian region. In the United States, the 

Midwest, Southeast, and parts of the West 

see at least 10 percent reductions, while in 

Canada, southern Ontario and Quebec see 10 

to 25 percent reductions under this illustrative 

scenario. The largest percent reductions, of up 

to 50 percent, are scattered in the U.S. Rocky 

Mountain West. The emissions cap and crossborder trading approach modeled here produces 

significant broad regional reductions in nitrogen 

deposition over the cross-border receptor area 

in eastern North America and the Colorado 

front range. As seen in the sulfur deposition 

results presented above, the reductions in the air 

quality indicator start in 2010, are domain wide, 

and are deepened and expanded geographically 

in the 2020 simulation (Figure H-22). Reductions 

in both sulfur and nitrogen deposition 

will contribute to reduced acid rain and 

improvements in acid-sensitive ecosystems. 

H.4.7 Visibility 

Visibility degradation is a significant concern 

in the United States, where the Regional Haze 

rule is driving long-term emission reductions, 

and in Canada, where Continuous Improvement/ 

Keeping Clean Areas Clean provisions of the 

Canada-wide Standards are the basis for 

preventing air quality deterioration. In 2010 and 

2020, visibility modeled improves noticeably (on 

the order of one deciview, which is a standard 

measure of visibility change, discernible to the 

typical eye), compared with the Base Case, if an 

emissions cap and cross-border trading scenario 

is considered (Figure H-23). Visibility improves 

as the concentration of airborne fine particles 

declines. Most significant improvement is 

observed in the mid-Appalachian area of 

the United States, with smaller improvements 

extending well into Ontario and across 

New England and eastern Canada. The 

emissions cap and cross-border trading 

approach produces significant broad regional 

improvements in visibility over the cross-border 

receptor area in eastern North America. 

113 
Canada-United States Emissions Cap and Trading Feasibility Study 

H.5 SUMMARY OF FEASIBILITY 

ANALYSIS AND TOOL 

DEVELOPMENT 

The work undertaken for this feasibility study 

represents a number of important steps toward 

the understanding of cross-border air quality 

issues and the continued development of 

tools that will facilitate future discussions 

and analysis. The progress made in enhancing 

power sector and air quality modeling marks 

a significant milestone. The enhancements 

made to the IPM model are important for both 

countries as Canada and the U.S. pursue 

methods to reduce emissions from power 

plants to improve air quality, both separately 

and jointly. 

The results of our preliminary analysis 

indicate that cross-border emissions cap 

and trading could provide opportunities for 

reducing emissions that have benefits in 

terms of air quality. The cap and trade 

framework can also provide cost savings 

because of the flexibility it provides to sources. 

The IPM model results have generally shown this 

to be true, and the modeling done in support 

of this study has reinforced these findings. The 

initial findings show that the U.S. and Canada 

can analyze in detail cap and trade scenarios to 

estimate significant impacts such as incremental 

cost, generation mix, allowance costs, and shifts 

of power generation between countries. 

The air quality modeling results appear to 

be reasonable and consistent with observations 

made in the past; models were run successfully, 

producing technically sound results. The 

air quality modeling shows that broad emission 

reductions over a wide geographic region in both 

countries would provide improvements in air 

quality, including visibility and acid deposition, 

as well as health benefits. This work sets the 

stage for future modeling of the North American 

grid, operating in concert with an emissions 

cap and trading scenario that produces regional 

reductions for the air quality endpoints of 

interest. 

The United States and Canada share 

common regional air quality problems. The 

successful development, enhancement, and 

use of tools that can analyze and model 

key aspects of different emission scenarios 

are apparent. Furthermore, the air quality 

modeling demonstrates significant air quality 

improvements and cost-effective reductions from 

applying an emissions cap and trading approach 

to SO2 and NOX emissions. The results presented 

here are a first step toward helping all interested 

parties better understand the implications 

of cross-border emissions cap and trading. 

H.6 REFERENCES 

Bouchet, V.S., Moran, M.D., Crevier, L.-P., 

Dastoor, A.P., Gong, S., Gong, W., 

Makar, P.A., Menard, S., Pabla, B., 

and Zhang, L. (2003). Wintertime and 

summertime evaluation of the regional 

PM air quality model AURAMS. In: 

“Proceedings of the 26th NATO/CCMS 

ITM on Air Pollution Modelling and Its 

Application, May 26-29, Istanbul, Turkey” 

[cited in Borrego, C. and Incecik, S., Eds. 

(2003). “Air Pollution Modelling and Its 

Application XVI.” Kluwer/Plenum 

Publishers, New York, pp. 97-104]. 

Byun, D.W. and Ching, J.K.S., Eds. (1999). 

“Science Algorithms of EPA Models-3 

Community Multiscale Air Quality (CMAQ) 

Modeling System.” EPA/600/R-99/030, 

Office of Research and Development, 

U.S. Environmental Protection Agency. 

Byun, D.W. and Schere, K.L. (2004). Review of 

the governing equations, computational 

algorithms, and other components of 

the Models-3 Community Multiscale Air 

Quality (CMAQ) modeling system. Applied 

Mechanics Reviews, 2005, in press. 

Dennis, R.L., Byun, D.W., Novak, J.H., Galluppi, 

K.J., Coats, C.J., and Vouk, M.A. (1996). 

The next generation of integrated air 

quality modeling: EPA’s Models-3. 

Atmospheric Environment, 30: 1925-1938. 

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Section H


Gong, W., Dastoor, A.P., Bouchet, V.S., Gong, S., 

Makar, P.A., Moran, M.D., Pabla, B., 

Ménard, S., Crevier, L.-P., Cousineau, S., 

and Venkatesh, S. (2005). Cloud 

processing of gases and aerosols in a 

regional air quality model (AURAMS). 

Atmospheric Research (accepted for 

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Makar, P.A., Bouchet, V.S., Crevier, L.-P., 

Dastoor, A.P., Gong, S., Gong, W., 

Menard, S., Moran, M.D., Pabla, B., 

Venkatesh, S., and Zhang, L. (2003). 

AURAMS runs during the Pacific2001 

time period—a model/measurement 

comparison. In: “Proceedings of the 26th 

NATO/CCMS ITM on Air Pollution 

Modelling and Its Application, May 26-29, 

Istanbul, Turkey” [cited in Borrego, C. and 

Incecik, S., Eds. (2003). “Air Pollution 

Modelling and Its Application XVI.” 

Kluwer/Plenum Publishers, New York, 

pp. 97-104]. 

Makar, P.A., Bouchet, V.S., Gong, W., 

Moran, M.D., Gong, S., Dastoor, A.P., 

Hayden, K., Boudries, H., Brook, J., 

Strawbridge, K., Anlauf, K., and Li, S.-M. 

(2004). AURAMS/Pacific2001 

measurement intensive comparison. 

In: “Proceedings of the 27th NATO/CCMS 

ITM on Air Pollution Modelling and 

Its Application, Banff, Alberta, 

October 25-29.” 

McKeen, S., Wilczak, J., Grell, G., Djalalova, I., 

Peckham, S., Hsie, E.-Y., Gong, W., 

Bouchet, V., Ménard, S., Moffet, R., 

McHenry, J., McQueen, J., Tang, Y., 

Carmichael, G.R., Pagowski, M., Chan, A., 

and Dye, T. (2005). Assessment of an 

ensemble of seven real-time ozone 

forecasts over Eastern North America 

during the summer of 2004. Journal 

of Geophysical Research (submitted). 

Seinfeld, J.H. and Pandis, S.N. (1998). 

“Atmospheric Chemistry and Physics.” 

John Wiley and Sons, Inc., pp. 254-264. 

115 

NOTES

NOTES


United States Environmental Protection Agency


Office of Air and Radiation (6204)


1200 Pennsylvania Avenue, NW


Washington, DC 20460


EPA430-R-05-005


July 2005


www.epa.gov/airmarkets/usca


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