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BORDER AIR QUALITY STRATEGY
United States—Canada Emissions
Cap and Trading Feasibility Study
UNITED STATES-CANADA AIR QUALITY AGREEMENT
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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 II111 Floor, Place Vincent Massey
Washington, DC 20460 Gatineau, Quebec K1A OH3
Internet: Internet:
www.epa.gov/airmarkets/usca http://www.ec.gc.ca/cleanair-
airpur/Canada-_United_States-
WS105E2511-l_En.htm
American spelling is used throughout this report.
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UNITED STATES-CANADA EMISSIONS CAP AND
TRADING FEASIBILITY STUDY
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TABLE OF CONTENTS
Executive Summary ix
Introduction xiii
Section A: Air Quality Context 1
A.I 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.I UNITED STATES 15
B.2 CANADA 23
B.3 SUMMARY 29
Section C: Applicability 31
C.I 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.I PRINCIPLES 45
D.2 U.S. MONITORING AND REPORTING 46
D.3 ENVIRONMENT CANADA'S PROTOCOL FOR CONTINUOUS
EMISSION MONITORING SYSTEMS (REPORT EPS l/PG/7) 61
D.4 ANALYSIS 62
D.5 SUMMARY 65
D.6 REFERENCES 66
Section E: Allowances Use 67
E.I 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
in
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Canada-United States Emissions Cap and Trading Fe
E.ll TAX CONSEQUENCES 73
E.12 THE U.S. EXPERIENCE WITH ALLOWANCE USE 73
E.I3 SUMMARY 77
Section F: Electronic Emissions Trading Registry:
Data Systems for Tracking Allowances and Emissions 79
F.I 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
F6 SUMMARY 85
Section G: Compliance and Enforcement 87
G.I 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.I 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
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LIST OF TABLES
Table A-1 Average Concentration and Percent Concentration of PM2.s
Mass from Selected State Contributions to Class 1 Areas
(Acadia, Boundary Waters, Dolly Sods) 1O
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 1O1
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LIST OF FIGURES
Figure A-1 Mean PM2.s Concentrations (ug/m3) at Canadian
Dichotomous Monitors and U.S. Federal Reference
Monitors in the Border Region, 2OOO-2OO3 4
Figure A-2 Ozone Concentrations (ppb) in the U.S.-Canada Border Regions,
2OOO-2OO2 (Average Annual Fourth-Highest Daily Maximum
Eight-Hour Ozone) 4
Figure A-3 Average Wet Sulfate Deposition, 199O-1994 5
Figure A-4 Annual Wet Sulfate Deposition, 2OO2 5
Figure A-5 Average Wet Nitrate Deposition, 199O-1994 6
Figure A-6 Annual Wet Nitrate Deposition, 2OO2 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 2OOO and 2OO1 PM2.s
Measurements for the Warm Months (May-September) 9
Figure A-11 Average Concentrations (ug/m3) of PM2.s and Components by
State and Province 9
Figure A-12 Satellite Imagery of the Quebec Forest Fire PM Episode in July 2OO2 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, 2OO2 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, 2OO3 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 1OO
Figure H-4 Map of the CMAQ Modeling Domain Used for CAIR 1OO
Figure H-5 NOX East and West Model Regions for Illustrative Analysis 102
Figure H-6 Annual SO2 Emissions in 2O1O and 2O2O, Comparing the Base Case
(with no caps in Canada) with the Trading Scenario (with caps in
Canada and cross-border trading) 1O2
Figure H-7 Annual NOX Emissions in 2O1O and 2O2O, Comparing the Base Case
(with no caps in Canada) with the Trading Scenario (with caps in
Canada and cross-border trading) 1O3
VI
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Figure H-8 Summer NOX Emissions in 2O1O and 2O2O, Comparing the Base Case
(with no caps in Canada) with the Trading Scenario (with caps in
Canada and cross-border trading) 1O3
Figure H-9 Emissions of SO2 and NOX from the U.S. Power Sector - Base Case,
Clear Skies U.S., and the Trading Scenario 1O4
Figure H-10 Emissions of SOi and NOx from the Canadian Power Sector -
Base Case and the Trading Scenario 1O4
Figure H-11 Annual Incremental Costs to the Base Case for the U.S.
Power Sector of Illustrative Trading Scenario 1O5
Figure H-12 Annual Incremental Costs to the Canadian Power Sector of
Illustrative Trading Scenario 1O6
Figure H-13 U.S. Generation Mix - Base Case, Clear Skies U.S., and the
Trading Scenario 1O7
Figure H-14 Canadian Generation Mix - Base Case and the Trading Scenario 1O7
Figure H-15 Percent Change in Annual Fine Particles with Emission Reductions
under Illustrative Trading Scenario Compared to Base Case in 2O1O
(CMAQ) 1O9
Figure H-16 Percent Change in Annual Fine Particles with Emission Reductions
under Illustrative Trading Scenario Compared to Base Case in
2O2O (CMAQ) 1O9
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) 11O
Figure H-18 Absolute Difference in PMi.s Concentration (ug/m3), Comparing
Illustrative Trading Scenario to the Base Case during the
Winter Episode for 2O2O (AURAMS) 11O
Figure H-19 Absolute Difference in PMi.s Concentration (ug/m3),
Comparing Illustrative Trading Scenario to the Base Case
during the Summer Episode for 2O2O (AURAMS) Ill
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 2O2O (AURAMS) 111
Figure H-21 Percent Change in Sulfur Deposition with Emission Reductions
under Illustrative Trading Scenario Compared to Base Case in
2O2O (CMAQ) 112
Figure H-22 Percent Change in Nitrogen Deposition with Emission Reductions
under Illustrative Trading Scenario Compared to Base Case in
2O2O (CMAQ) 112
Figure H-23 Absolute Change in Visibility (Deciviews) with Emission Reductions
under Illustrative Trading Scenario Compared to Base Case in
2O2O (CMAQ) 113
VII
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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 cross-
border 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.s), ground-level
or tropospheric ozone (Oa), and acid
deposition. SO2 and NOx are key precursors
that can lead to the formation of PM2.s,
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_concern-
WSOA8790BD-l_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 cross-
border 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 cross-
border trading programs. While legal
authorities exist now in Canada that could
IX
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Canada-United States Emissions Cap and Trading Fe
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
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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 cross-
border 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
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Canada-United States Emissions Cap and Trading Fe
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
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INTRODUCTION
In 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 (SCh). This builds on the earlier
commitment under the AQA to cooperate and
exchange information with respect to market-
based 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
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SECTION A
AIR QUALITY CONTEXT
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.I
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.I 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
in eastern North America. Discussions regarding
air quality in support of the feasibility of a cross-
border 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. Ground-
level 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.s) 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
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Canada-United States Emissions Cap and Trading Fe
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.s,
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 PIVh.s 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.s and ozone pollution
adversely affect visibility and ecosystem health.
PM2.s 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
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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.s 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 PIVh.s
Concentrations
Recent air quality monitoring data indicate
that mean levels of PM2.s are as high as
18 micrograms per cubic meter (pg/m3) in the
northeastern United States but consistently
lower than 12 pg/m3 in the mid-continental
states for the years 2000-2003 (see Figure A-l).
The northeastern United States is a region of
high ambient PM levels, with 98th-percentile
values up to 65 pg/m3 (the U.S. ambient air
quality standard) at a majority of sites. Canadian
locations exhibit generally lower levels of PM2.s,
although 98th-percentile concentrations greater
than 30 pg/m3 (the Canada-wide Standard)
occurred in several regions of the country for
the years 2000-2002, particularly in the Windsor-
Quebec City corridor.
Current ambient levels of PM2.s 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.s 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 PM2.6 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.s 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 Canada-
U.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
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Canada-United States Emissions Cap and Trading Feasibility Study
Figure A-1 Mean PM2.s Concentrations (ug/m3) at Canadian Dichotomous Monitors
and U.S. Federal Reference Monitors in the Border Region, 2OOO-2OO3
'x-
Canada Dlchot
and US FRM
PH;s Monitors
!OM - !M3 mean uj'm3
^K
I
Source: Canada-U.S. Transboundary PM Science Assessment, 2004.
Figure A-2 Ozone Concentrations (ppb) in the U.S.-Canada Border Regions, 2OOO-
2OO2 (Average Annual Fourth-Highest Daily Maximum Eight-Hour Ozone)
Source: Canada-United States Air Quality Agreement Progress Report, 2004.
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SECTION A
Figure A-3 Average Wet Sulfate
Deposition, 199O-1994
Figure A-4 Annual Wet Sulfate Deposition,
2OO2
"'
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 NHa emissions,
Source: Canada-United States Air Quality Agreement
Progress Report, 2004.
where sulfate concentrations are high, can
reduce PM2.s 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 cross-
border 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.
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Canada-United States Emissions Cap and Trading Feasibility Study
Figure A-5 Average Wet Nitrate
Deposition, 199O-1994
Figure A-6 Annual Wet Nitrate Deposition,
2OO2
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 Canada-
Source: Canada-United States Air Quality Agreement
Progress Report, 2004.
wide 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
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SECTION A
Figure A-7 Canada (2OOO) - U.S. (2OO1) Geographical Distribution of SO2 Emissions
Source: Environment Canada and EPA.
Figure A-8 Canada (2OOO) - U.S. (2OO1) Geographical Distribution of NOX Emissions
Source: Environment Canada and EPA.
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Canada-United States Emissions Cap and Trading Feasibility Study
Figure A-9 U.S. and Canadian National Emissions by Sector for SO2 and NOX, 2OO2
U.S. Emissions-2002
Sulfur Dioxide
Total: 15.8 million tons/year
Nonroad^
On-road -
Sioxlde
TotsJ: 2.6 ??*jn tons/year
Non-Industrial
• • .• I :
U.S. Emissions-2002
Nitrogen Oxides
Total: 21.2 million tons/year
Canadian Emissions-2002
Nitrogen Oxides
Total: 2.8 million tons/year
Nonroad
Industrial
Nonroad
Non-Industrial
On-road
Source: Canada-United States Air Quality Agreement Progess Report, 2004.
Non-Industrial
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
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SECTION A
Figure A-10 Combined QTBA Plot
Derived Using 2OOO and 2OO1 PM2.s
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.s) over eastern
Figure A-11 Average Concentrations (ug/m3) of PMi.s 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, SCU = sulfate, NOa = nitrate
Source: Canada-United States Transboundary PM Science Assessment, 2004.
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Canada-United States Emissions Cap and Trading Fe
Table A-1 Average Concentration and Percent Contribution of PM2.s Mass from
Selected States to Class 1 Areas (Acadia, Boundary Waters, Dolly Sods)
Class 1
Area
State/
province
States
Illinois
Indiana
Iowa
Kentucky
Maine
Michigan
Minnesota
New Hampshire
New Jersey
New York
North Carolina
Ohio
Pennsylvania
Tennessee
Vermont
Virginia
West Virginia
Wisconsin
Provinces
Ontario
Quebec
Acadia
Average PIVh.s Annual
concentration percent
(ug/m3) PM2.5 mass
10.8 0.4
17.1 0.9
7.6 0.2
11.8 0.5
5.6 12.6
7.6 1.7
7.1 0.6
8.6 2.0
18.9 1.0
8.2 4.4
13.9 0.3
10.6 1.2
13.2 3.0
9.9 0.2
8.3 1.8
14.2 0.9
18.4 0.5
6.2 0.6
6.0 7.7
4.9 17.8
Boundary Waters
Average PIVh.s Annual
concentration percent
(ug/m3) PM2.5 mass
9.5 1.7
12.5 0.6
8.1 5.0
6.2 1.7
5.7 35.2
10.0 0.1
12.8 0.2
10.0 0.1
7.1 7.6
3.5 16.4
2.4 0.2
Dolly Sods
Average PIVh.s Annual
concentration percent
(ug/m3) PM2.5 mass
8.7 1.6
11.0 3.2
8.5 0.9
14.0 8.6
8.6 0.1
10.1 2.6
8.6 1.0
8.4 0.1
9.1 0.8
12.0 3.1
11.5 8.8
10.9 5.1
13.4 4.9
11.8 7.6
14.0 26.4
9.0 1.3
9.2 4.8
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.s to above-
average 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
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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 Plvh.s 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.s
concentrations that are high, low, or moderate.
By combining this frequency information with
the concentration information, this study derives
an average contribution to PIVh.s mass from each
state/province to the Class 1 areas.
Table A-l gives the average concentration
and percent PIVh.s 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 pg/m3. Similarly, the Canadian provinces
make significant contributions to the border-area
Class 1 sites; Ontario provides about 16 percent
of the annual PM2.s mass at Boundary Waters,
and Quebec provides about 18 percent to Acadia.
Ohio and Pennsylvania are associated with high-
concentration air masses at the three Class 1
sites shown, but make significant (>5 percent)
contributions to annual PM2.s 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.s 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 (PIVh.s), tropospheric ozone, and
acid deposition. Transport of key precursor
emissions such as SO2, NOX, VOCs, and NH3
11
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Canada-United States Emissions Cap and Trading Feasibility Study
Figure A-12 Satellite Imagery of the Quebec Forest Fire PM Episode in July 2OO2
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
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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(l): 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.s: A CIS analysis. In:
"Proceedings of the 97th Air and Waste
Management Association Annual
Conference, Indianapolis, Indiana,
June 2004."
McMurry, PH., Shepherd, M.F., and VickeryJ.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
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SECTION B
LEGAL BACKGROUND
In 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 cross-
border 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.I 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
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 (NCh), sulphur dioxide (SCh), ozone
(Oa), 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
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Canada-United States Emissions Cap and Trading Fe
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.I.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.I.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 fuel-
fired 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.
2 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.
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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.I.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
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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, wet-
bottom 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
3 One Btu =1.06 kilojoules.
4 Maine, New Hampshire, Vermont, Massachusetts, Connecticut, Rhode Island, New York, New Jersey, Pennsylvania,
Maryland, Delaware, northern Virginia, and the District of Columbia.
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
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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.I.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.I.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.I.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.I.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.
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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 long-
term 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.I.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.
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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 demand-
side 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.I.S.I Legislation: Proposed Clear Skies6
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.
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Canada-United States Emissions Cap and Trading Feasibility Study
Figure B-1 CAIR: Affected Region and Emission Caps
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)
States not covered by CAIR
Emission Caps*
(million tons)
Source: EPA
2015
25
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
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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 cross-
border 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
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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 tiadeable 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.
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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. n 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
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.
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.
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
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Canada-United States Emissions Cap and Trading Fe
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
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SECTION B
B.2.3.2 Quebec
The Loi sur la qualite de 1'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 Reglement sur
la qualite de 1'atmosphere (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 sector-
specific 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, PMio, and
PM2.s),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.1S 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,
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.
Air Quality Management Bylaw, No. 937, 1999.
The GVRD has adopted Environment Canada's Monitoring Protocol, EPS l/PG/7.
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.
Alberta Emission Standards for New or Expanded Coal-Fired Plants.
27
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Canada-United States Emissions Cap and Trading Fe
exploring the potential for an air emissions
trading program in Alberta.
concentrations of NO2 and SO2 are both listed
as objectives.
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
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
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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.2.3.1O 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 cross-
border 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 cross-
border SO2 and NOX emissions cap and trading
programs.
In Canada, the legal authorities exist that
could provide the basis for developing cross-
border trading. Federal and provincial
governments have legal responsibilities in
air quality management and would need to
participate in the development of any cross-
border 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.
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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.I
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.I 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 cost-
effective 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.I.3 Availability of Cost-Effective Control
Options
Sources included in the program should have
a wide range of costs of compliance due to wide
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Canada-United States Emissions Cap and Trading Fe
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 high-
elevation alpine lakes in certain areas. However,
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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.I.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. SC>2 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 sulfur-
containing 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 non-
energy-related industrial activities include, for
example, iron and steel production and cement
manufacturing. According to the most recent
U.S. EPA, "Tools of the Trade," http://www.epa.gov/airmarkets/international/tools.pdf.
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.
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.
Ibid.
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Canada-United States Emissions Cap and Trading Fe
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
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SECTION C
Figure C-1 Fraction of Electric Generation by Fuel Type (2OOO)
Year 2000 Generation (MWh)
380,000,000
190,000,000
38,000,000
_| Coal
n on
Q Gas
• Nuclear
• Hydro
B Biomass
• Geothermal
U Wind
Source: EPA, http://www.epa.gov/cleanenergy/egrid/samples.htmttegridmaps
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, n 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 percent12 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
1° 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
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Canada-United States Emissions Cap and Trading Feasibility Study
Figure C-2 Total Electricity Generation
by Fuel Type, 20O2
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 gas-
fired turbines is less than 10 percent of each
province's total generation.
The remaining 3 percent13 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
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
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SECTION C
C.2.3.2 Canada
Industrial Boilers
It is estimated that there are 350,000 to
600,000 nonutility boilers in Canada. 1S 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 cross-
border 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
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-l.
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."
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 cross-
border 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
37
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Canada-United States Emissions Cap and Trading Feas
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 overflre 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 lower-
sulfur 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
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
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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. I' 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,
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.
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.
U.S. EPA (2004). "NOx Budget Trading Program: 2003 Progress and Compliance Report," pp. 20-21.
This is from preliminary data collected by the Emissions Monitoring Branch of the U.S. EPA's CAMD as of October 2004.
39
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Canada-United States Emissions Cap and Trading Fe
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
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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 combined-
cycle 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.htmlitoptin for more information.
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Canada-United States Emissions Cap and Trading Fe
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.
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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/in terstateairquality/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."
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SECTION D
EMISSIONS MONITORING AND REPORTING
Emissions monitoring and reporting are the
backbone of emission cap and trading
programs. Experience has shown that well-
defined, 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 l/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.I 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.I.I 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.I.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 well-
functioning cap and trading program, in terms of
both its design and its operation. Transparency
of the design process can promote public
45
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Canada-United States Emissions Cap and Trading Fe
Table D-1 Essential Measurements Required by U.S. Emission Cap and Trading Programs
Program
Acid Rain
Program
NOx Budget
Trading
Program
Affected sources
Fossil fuel-fired electric generating units (ECUs) and other
combustion sources that opt in to the SCh emissions cap and
trading program
ECUs, 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
Parameter
measured
(units)
SO2 (tons)
NOx (tons)
Accounting
period
Annual
Ozone season '
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 long-
term, predictable, and consistent rules that affect
the economic value of emission reductions.
D.I.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 (CCh) 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
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SECTION D
Figure D-1 Overview of Continuous Emission Monitoring under Part 75
Protocol Gas
Quality
Assurance
Tests
CEMS
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.
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Canada-United States Emissions Cap and Trading Fe
Table D-2 Part 75 Monitoring Options
If an affected unit is
classified as a...
Coal-fired unit
Non-peaking oil- or gas-fired unit
Peaking oil- or gas-fired unit
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)
/
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 (02) 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.
5 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).
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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
SC>2 system
Stack gas flow rate system
Moisture system (in some cases)
ppm
scfh
% H2O
NOx tons
1 NOx system
1 Stack gas flow rate system
1 Moisture system (in some cases)
or
1 NOx-diluent system 7
1 Stack gas flow rate system
1 Moisture system (in some cases)
ppm
scfh
% H2O
Ib./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 "gas-
fired" 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 SC>2 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; Ib. 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.
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Canada-United States Emissions Cap and Trading Fe
The Appendix E methodology for oil-
and 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 02 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. "Mixing-
and-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
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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 S<>2 and/or NOx mass emissions meet the following limits:
For Acid Rain Program units:
• < 25 tons of SO2 per year
and
• < 1 00 tons of NOx per year
For NOx Budget Trading Program units:
• < 50 tons of NOx per ozone season
and
• < 100 tons of NOx per year8
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 LME-
excepted 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.
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Canada-United States Emissions Cap and Trading Fe
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
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SECTION D
Figure D-2 Monitoring System Certification Process
Submit
Certification
Test Notices
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
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Canada-United States Emissions Cap and Trading Fe
Table D-5 Part 75 Certification Tests
This type of
certification test...
Seven-day calibration
error test
Linearity check
Relative accuracy test
audit (RATA)
Bias test
Cycle time test
Flow meter accuracy
test
NOx emissions rate testing
and heat input measurement
at four unit loads
NOx emissions rate testing
at one or more unit loads
DAHS verification
Is required for...
Gas and flow monitors
Gas monitors
Gas and flow
monitoring systems
(three-load test for flow)
SO2, NOX, and flow
monitoring systems
Gas monitoring systems
Appendix D fuel flow
meters
Appendix E peaking
units
LME units
Units using CEMS or
Appendix E and/or
Appendix D monitoring
methodologies
And its purpose is...
To evaluate the accuracy and stability of
a monitor's calibration over an extended
period of unit operation.
To determine whether the response of a
gas analyzer is linear across its range.
To compare emissions data recorded by a
CEMS with data collected concurrently with
an EPA reference test method.
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.
To determine whether a CEMS is capable
of completing at least one cycle of sampling,
analyzing, and data recording every
15 minutes.
To demonstrate that a fuel flow meter can
accurately measure the fuel flow rate.
To construct a correlation curve of NOx
emissions rate vs. heat input rate.
To determine fuel- and unit-specific NOx
emission factors for reporting purposes.
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 recertiflcation
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 recertiflcation 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
recertiflcation.
54
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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./ 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 year-
round 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.
1' Certain states allow NOX Budget Trading Program sources to choose between year-round and ozone season-only
reporting.
55
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Canada-United States Emissions Cap and Trading Fe
Table D-6 Ongoing QA Test Requirements for Year-Round Reporters
Perform this type of
QA test...
Calibration error test
Interference check
Linearity check
Flow-to-load ratio or gross
heat rate test
Leak check
RATA and bias test
Accuracy test
NOx emissions rate testing
On these continuous
monitoring systems...
Gas and flow monitors
Flow monitors
Gas monitors
Flow monitors
Differential pressure-type flow monitors
Gas and flow monitors (bias test
applies to SC>2, NOx, and flow
monitoring systems, only)
Fuel flow meters
Appendix E systems
At this basic frequency...
Daily
Daily
Quarterly
Quarterly
Quarterly
Semiannual or annual 12
Annual
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 season-
only 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-by-
step 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, quality-
assured 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.
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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-of-
control monitoring system are unsuitable for
Part 75 reporting and may not be used in the
emission calculations. For each hour of an out-
of-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 availability13 (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
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.
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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 fuel-
specific 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 quality-
assured. 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.
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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 allowance-
holding 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
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.
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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.1S 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.
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• 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 l/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 l/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.
16 The Field Audit Manual is found at http://www.epa.gov/airmarkets/monitoring/auditmanual/index.html.
EPS l/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 l/PG/7 is a technical document that
may be used by regulatory agencies for setting
requirements to achieve accurate measurement
of NOx and SC>2 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 l/PG/7 are
recommended guidelines from the federal
government. It is left to regulatory agencies
to implement them.
EPS l/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 l/PG/7
as a basis for their provincial CEM requirements.
The Greater Vancouver Regional District, a
region within British Columbia, has also adopted
EPS l/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
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source's operating permit. Often, EPS l/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 l/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 l/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 l/PG/7 and
40 CFR Part 75)
Many of the differences 17 between EPS l/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 l/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 l/PG/7 and 40 CFR Part
75 are:
• Data acquisition system requirements—These
are less detailed in EPS l/PG/7.
• Bias—EPS l/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 l/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 l/PG/7.
• Unit operating data—EPS l/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 l/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.
Much of the information in Section D.4 was obtained from Jahnke (2001, 2004).
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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 l/PG/7
Despite the differences between 40 CFR Part 75
and EPS l/PG/7, the directions of the two
documents are consistent. EPS l/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 l/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 l/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.
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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 path-
type 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 (NCh), 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
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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 l/PG/7,
"Protocols and Performance Specifications for
Continuous Monitoring of Gaseous Emissions
from Thermal Power Generation."
Many differences between EPS l/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
l/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 l/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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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.
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ALLOWANCES USE
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.
E.I 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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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 cost-
effectiveness 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
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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).
£.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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to a uniform unit or apply different emission
performance metrics for each product.
£.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.
£.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,
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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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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
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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.1O 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-l
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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Table E-1 Overview of Allowance Use in U.S. SO2 and NOX Programs
Definition
Serialization
Banking
Distribution - auction
Distribution - allocation
Tax consequences
New sources
Set-asides
Government oversight
U.S. SOa Acid Rain Program
Authorization to emit.
Not a property right.
Yes -> vintage + unique number.
Allowances are stored in blocks.
Unlimited.
2.8 percent of cap auctioned
each year.
Benchmark: Heat input multiplied by
1 .2 pounds (Ibs.) of SC>2 per million
British thermal units (mmBtu). '
Baseline: Average of 1985-1987
(permanent).
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.
Purchase from market.
Limited number for conservation and
renewable energy projects before
1995 (phasing out).
Market oversight is limited.
U.S. NOX Budget Trading
Program
Authorization to emit.
Not a property right.
Yes -> vintage + unique number.
Allowances are stored in blocks.
Banked allowances are discounted
if total bank exceeds 1 0 percent of
initial allocation.
None.
Allocation approaches are
determined by states.
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.
Determined by states.
Determined by states.
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 source-
specific 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
i One Btu =1.06 kilojoules.
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
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than 10 percent of the cap. The ratio would
be 0.67 ((500,000 x 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 Ibs. SO2/mmBtu or, if it was already lower
than 1.2 Ibs. 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.
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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,
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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.
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.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
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.
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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.
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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.I), 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 cross-
border emissions cap and trading program.
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.I 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,
F.I.I 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.
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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.I.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.
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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 participantl 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.I) 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
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.
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
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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 first-
generation 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-l). 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-l).
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
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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
SC>2 Mass Emission Data
NOx Emission Data
CC>2 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.
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Figure F-2 Allowance Reconciliation
Allowances
Beginning of year
15,812
Net Allowance
(Bought and Sold)
-3,201
Total Allowance
Available for Compliance
12,611
Deductions for
Emissions
-11,867
Allowances Remaining
(Source in Compliance]
744
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.
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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 ozone-
depleting 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
3 See http://www.ec.gc.ca/ozone.
4 Ontario Ministry of the Environment, "Ontario Emissions Trading Code," Toronto, Ontario, January
(http://www.ene.gov.on.ca/envision/env_reg/er/documents/2003/XA03EOOO 1 .pdf).
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Canada-United States Emissions Cap and Trading Fe
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, well-
functioning 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.
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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.I 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.I 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.I.I 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
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Canada-United States Emissions Cap and Trading Fe
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.I.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.I.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.I.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 well-
functioning 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
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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
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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.
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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 regulation-
making 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 allowance-
holding requirement, the penalties for
noncompliance, be they allowances or financial
penalties, need to be automatic and equivalent
in both Canada and the United States.
1 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.
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Canada-United States Emissions Cap and Trading Feasibil
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.
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SECTION H
ANALYTICAL TOOL DEVELOPMENT AND
FEASIBILITY ANALYSIS
In 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 cross-
border air quality modeling.
H.I 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
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.I.I 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.I. 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
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Canada-United States Emissions Cap and Trading Fe
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-l).
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-l 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.s) 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.I. 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
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SECTION H
Figure H-1 Electricity Generation in Canada and the United States, 2OO3
4.000
3.SOO
3.000
2500
S 2,000
1.500
1.000
wo
0
UK Canada
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
Canadian and United Slates
Fossil-Fueled Power Plants
Aaim RicKiarq ur«» undw 25
mftjpMwtti fi«WH*i untft vi propci
ttut BTJHTW M M« curt vCf «e«tit«fl if*
pUrt tui unA *» Mwwt K
iSt
-
COX
1 dO tftf to KB MW
N«(urtlGM
tDOMWtoKOMW
SMMWtolMOMrt
"IdOOMW
00
• IMMWicSOdMW
• SOOMWUilMOMW
Source: EPA
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Canada-United States Emissions Cap and Trading Fe
Table H-1 Existing U.S. and Canadian Electricity Generating Capacity by Source
Energy source
Coal
Oil/gas
Nuclear
Hydro
Other
Total
United States (2002)
Number of
generators
1,566
9,044
104
4,157
1,542
16,413
Generator
nameplate
capacity (MW)
338,199
420,558
104,933
96,343
19,553
979,586
Canada (2003)
Number of
generators
58
887
15
1,493
474
2,927
Generator
nameplate
capacity (MW)
16,901
15,631
11,155
70,374
2,931
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
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SECTION H
of electricity generating units, and its bottom-
up 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/cleanair-
airpur/can-us_border_air_quality_strategy_
wsd6f2621E-l_en.htm. EPA IPM model
documentation is also available on EPA's Web site
at http: //www. epa. go v/airmarkets/epa-ipm/.
97
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Canada-United States Emissions Cap and Trading Fe
H.I. 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 ECU 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.I.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. Ground-
Level 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.s, 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.s
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.s 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
CMAQ
AURAMS
AURAMS
AURAMS
CMAQ
CMAQ
CMAQ
Period Modeled
Annual
Winter Episode
Summer Episode
Summer Episode
Annual
Annual
Annual
Parameter
Average (PM2.s)
Average (PM2.s)
Average (PM2.s)
Peak (O3)
Total S Deposition
Total Oxidized N Deposition
Visibility (Deciview)
Figure
15-17
18
19
20
21
22
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.I. 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 peer-
reviewed 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 etal, 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.I.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-of-
the-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
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Canada-United States Emissions Cap and Trading Feasibility Study
Figure H-3 Map of the AURAMS
Modeling Domain Used in the
Feasibility Study
Figure H-4 Map of the CMAQ Modeling
Domain Used for CAIR
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/fmaltech02.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 cross-
border 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
-------
SECTION H
Table H-3 Illustrative Emission Caps for the United States and Canada
S02
NOx East
NOx West
Year
2010
2018
2008
2018
2008
Emission caps (million short tons) 1
United States
4.5
3.0
1.6
1.2
0.5
Canada
0.5
0.3
0.05
0.04
0.09
Joint cross-
border caps
5.0
3.3
1.6
1.2
0.6
1 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
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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 2O1O and 2O2O, Comparing the Base Case
(with no caps in Canada) with the Illustrative Trading Scenario (with caps in Canada
and cross-border trading)
•
;,:-
II.
n »
II,
•
_ --
_ ~
rm ft mM.~~.
Annual SO;
Emissions (thousand
short tons)
OQO
_] 2010 Tradog Scanafio
^12020 Base Case
12020 Traang Scenario
Source: EPA
1O2
-------
SECTION H
Figure H-7 Annual NOX Emissions in 2O1O and 2O2O, Comparing the Base Case
(with no caps in Canada) with the Illustrative Trading Scenario (with caps in Canada
and cross-border trading)
fi M. .
« it
Mi
'. \ ;«fr£J
it •*
Animal NO,
Emissions (thousand
-:i'"i i tonal
«* IA «. tr
rt ,-Kl
IL
• 29SO Tn»i>ii Samtie
f JOJO Traong Bcauna
Soure*- EPA
Figure H-8 Summer NOX Emissions in 2O1O and 2O2O, Comparing the Base Case
(with no caps in Canada) with the Illustrative Trading Scenario (with caps in Canada
and cross-border trading)
Ill te.
»•- fL
It
tL
_ ft 11 rt^r
u
14V
rft
Summer NO*
rv * Emissions (thousand
lit IB f|y «* short tons)
r* r* <*
Aim i
•Tij:
IL .
j MID Tisane SMMno
2«D20 BJM Caw?
Soure«: GPA
1O3
-------
Canada-United States Emissions Cap and Trading Feasibility Study
Figure H-9 Emissions of SO2 and NOX from the U.S. Power Sector - Base Case, Clear
Skies U.S., and the Illustrative Trading Scenario
12,000 -
10,000 -
f 8,000 -
o
T3
(0 o
!» H
| 1 6,000 -
t 1
§ 5
(0 1—
4 000
E '
UJ
2,000
0 -
f
SO -.
o<_>2 -•
"- o
— • — Base Case
— • — CSA in US Only*
Cross- BorderTradinq with Caps i
— "~ Both Countries
A
> • —
NOx J
2010 2015 2020
Note: Lines are on top of each other as the scenario results are virtually the same.
Source: IPM
Figure H-10 Emissions of SO2 and NOX from the Canadian Power Sector - Base Case
and the Illustrative Trading Scenario
Emissions of SQa and NO, from the Canadian Power Sector
Emissio
700
600
$00
400
300
200
100
2010
HUB
2020
Source: IPM
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
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.
1O4
-------
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 cross-
border 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 cross-
border 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
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Canada-United States Emissions Cap and Trading Feasibility Study
Figure H-12 Annual Incremental Costs to the Canadian Power Sector of Illustrative
Trading Scenario
2010
2015
2020
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 cross-
border trading (Figure H-14). There are minimal
shifts in the generation mix with caps and cross-
border 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 cross-
border 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
6.000.000
5,000.000
4.000.000
3.000.000
.23
11
IP
a 2.000,000
1.000.000
CSA = Clear Skies (2003)
Source: IPM
Figure H-14 Canadian Generation Mix - Base Case and the Illustrative Trading Scenario
0>
§
O
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
1O7
-------
Canada-United States Emissions Cap and Trading Feas
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 (PIVh.s)
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 SC>2 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 cross-
border trading between the two countries.
H.4.1 Annual PM2.s
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 PIVh.s 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 mid-
Appalachian 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 cross-
border 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 (pg/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.s 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 PM2.6 concentration can be
1O8
-------
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 2O2O (CMAQ)
observed over Kentucky. This small increase in
PM mass is due to a change in the sulfate-to-
nitrate 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 pg/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.
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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 PMi.s Concentration (ug/m3), Comparing
Illustrative Trading Scenario to the Base Case during the Winter Episode for 2O2O
(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 PIVh.s 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).
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SECTION H
Figure H-19 Absolute Difference in PM2.s Concentration (ug/m3), Comparing
Illustrative Trading Scenario to the Base Case during the Summer Episode for
2O2O (AURAMS)
ug'm5
20
15
10
£
1
0
-1
-5
•10
-15
•20
I
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
2O2O (AURAMS)
03
ppb
20
15
10
5
1
0
-1
-5
.10
-15
-20
I
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).
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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 PIVh.s
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
1 12
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SECTION H
Figure H-23 Absolute Change in Visibility (Deciviews) with Emission Reductions
under Illustrative Trading Scenario Compared to Base Case in 2O2O (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 cross-
border 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.
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Canada-United States Emissions Cap and Trading Feai
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.
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