6.1	Stationary Sources

6.1.1

Utility Emissions Overview

Power generation across North America has been linked to the creation of acid rain, smog, possible climate change and other environmental effects, through the release of sulphur dioxide (SO ₂ ), nitrogen oxides (NO _X ), carbon dioxide (CO ₂ ) and various particulates. One of the main sources of NO _X and SO ₂ , in both Canada and the US, as seen in Figure 3, is the utility sector. Regulations have substantially decreased overall emission from utilities; however, further reductions will be necessary if negative environmental impacts are to be ameliorated.

6.1.1.1

US 'Grandfathered' Power Plants

Power plants operating at the time the US Clean Air Act was amended in 1970 and again in 1977 were 'grandfathered,' that is, in consideration of their anticipated limited useful operating life, utility companies were not required to retrofit those existing plants with new air pollution control equipment, unless the utilities undertook major modifications of those facilities.

On November 3, 1999, the Justice Department, on behalf of the US EPA, filed seven lawsuits against electric utility companies in the west and South. The USEPA suit claimed that the utilities had modified particular plants and therefore should have installed pollution control equipment at these utilities. The USEPA alleged that 17 power plants have been illegally releasing significant amounts of air pollutants for several years, contributing to significant and severe environmental damage. The USEPA also issued an administrative order against the Tennessee Valley Authority (TVA), a federal agency, charging the agency with similar violations at seven plants.

The electric utility companies - American Electric Power, Cinergy, FirstEnergy, Illinois Power, Southern Indiana Gas and Electric Company, Southern Company, Tampa Electric Company and TVA - were charged with violations of the Clean Air Act by modifying their plants without installing of proper pollution control equipment, increasing air pollution both in local and distant regions.

In addition to the lawsuits and administrative orders, the USEPA also issued notices of violation to the utilities, and named an additional eight plants where similar violations have occurred. The 32 plants targeted are located in Alabama, Florida, Georgia, Illinois, Indiana, Kentucky, Mississippi, Ohio, Tennessee, and West Virginia. The USEPA aims to reduce the amount of SO ₂ , NO _X and PM that electric utility plants release to the atmosphere through installation of current air pollution technology.

In early March, 12 more plants were added to the suit, five American Electric Power (AEP) plants in Ohio, West Virginia and Virginia, two Cinergy plants in Indiana, and five Southern Company affiliates in Georgia, Mississippi, Florida and Alabama. A settlement with Tampa Electric Co. of Florida was also announced, under which that facility would reduce emissions by burning natural gas rather than coal at some facilities, while installing new pollution control equipment and operating existing equipment more efficiently at other units. The utility also agreed to pay a $3.5 million fine. A similar settlement is being considered by the Tennessee Valley Authority (TVA).

The United States government continues to seek significant civil penalties from the other violators. The Clean Air Act authorizes civil penalties of up to $25,000 for each day of violation at each plant prior to January 30, 1997 and $27,500 for each day thereafter.

On September 14, 1999, New York State announced its intention to sue 17 power plants, mainly in the west, to force reduction in the amount of emissions released into the atmosphere by these facilities. Eleven of the 17 plants named in the suit are owned by American Electric Power of Columbus, Ohio. This legal action is the first instance in which a state has gone directly against individual companies owning utilities that send emissions across state boundaries.

New York alleges that these plants failed to upgrade pollution control equipment, as is required under the Federal Clean Air Act, when making other large investments in the plants. The state alleges that significant improvements had been made to equipment at the plants that increased their life span and output of both electricity and pollution; however, no permits were sought and no new pollution controls were added.

In an approach similar to that of the USEPA, the plants charged with contributing to polluting downwind states include some of the largest single sources of air pollution in the country.

On February 8, 2000, New Hampshire indicated it would also file a lawsuit against several western coal-fired utilities, claiming a failure to upgrade in violation of the Federal Clean Air Act. New Hampshire officials contend emissions from the plants, including mercury and sulphur dioxide, are carried by wind to that state and deposited in fragile ecological areas.

In the fall of 1999, officials of the City of Toronto filed to intervene as a respondent in the case, siding with environmental groups and other downwind states. Ontario's Ministry of the Environment estimates that half of the sulphur dioxide and NO _X pollution in the province originates in the United States. A significant portion of this pollution comes from coal-fired power plants in the mid-west United States.

The Emissions & Generation Resource Integrated Database (E-GRID) is a comprehensive source of information on the environmental characteristics of all electric power generated in the United States. It integrates 12 different databases from 3 federal agencies: EIA (Electrical Industry Association), the USEPA and the Federal Energy Regulatory Commission (FERC). It covers approximately 4800 plants and 2100 generating companies. E-GRID provides data on pollutant emissions and resource mix for individual power generating plants and also from non-utilities, such as cogenerators. It allows for direct comparison of attributes between plants, companies, states and regions in the country.

From various studies performed by environmental groups, it was established that power generating plants are responsible for:

• 26 per cent of all emissions of nitrous oxides (NO _X )
• 64 per cent of all emissions of sulphur dioxides (SO ₂ )
• 40 per cent of man-made emissions of carbon dioxide (CO ₂ )

Many consumers of electricity may wish to be informed about how their power is generated and related environmental impacts. This information could become very important as consumers become free to choose their electricity suppliers. Approximately 20 states have determined that consumers have the right to know about emissions and the generating method associated with the electricity they use.

What E-Grid Provides

• For every power plant and generating company, information is available on:
• emissions of three major pollutants - NO _X , SO ₂ and CO ₂ in lbs/MMBTU and lbs/MWh
• generation resource mix
• identification and locational information
• It can assist States in the development of mechanisms for electricity labeling and verification of green power marketing claims.
• It can assist States that are adopting approaches to regulating emissions based on product output (emissions per kWh).
• It could allow environmental regulators to identify regional differences in emission rates that could affect air quality in a competitive electricity market.

E-GRID97 can be downloaded from the Website http://www.epa.gov/acidrain/egrid/egrid.html . Downloading all E-GRID97 files could take up to a few hours depending on Internet connection. The USEPA plans to make E-GRID97 available on CD-ROM in early 2000.

Background

• NO _X and associated ozone can travel hundreds of miles across State and International boundaries to affect the health of the public and the environment. Thus, cities or areas where clean air objectives are being met may be contributing to a downwind city's ozone problem.

• The US Clean Air Act requires that a State Implementation Plan contain provisions to prevent a State's facilities or sources from contributing significantly to air pollution 'downwind,' specifically in those areas that fail to meet the national air quality standards.
• In June of 1997, the Ozone Transport Assessment Group (OTAG) States (largely those east of the Mississippi River) voted to reduce NO _X emissions from utilities and other major sources. Reductions ranged from those currently required by the Clean Air Act, up to an 85 per cent reduction in emissions rate from the year 1990 electric utility levels (or to a level of 0.15 lb/mmBTU in the input fuel) in a number of states in the OTAG region.
• On November 7, 1997, building on the OTAG recommendations, the USEPA proposed to require 22 states and the District of Columbia to submit State Implementation Plans that address the regional transport of ground-level ozone. The USEPA proposed to require NO _X emission reductions by September 2002 to eliminate the significant contribution of emissions from upwind states, and set statewide NO _X emissions budgets reflecting those reductions.

In the fall of 1998, the USEPA announced three actions meant to address the regional transport of ground-level ozone, focused on NO _X emissions from all sources. They included:

The rule requires emission reduction measures to be in place by May 1, 2003, and would have a significant impact on both utilities and large non-utility point sources (such as coal-fired industrial generators and combustors).

The final rule includes a model NO _X emissions trading program that would allow States to achieve over 90 per cent of the required reductions in a highly cost-effective way. The goal is reduction in total summertime emissions of nitrous oxides by about 28 per cent (1.2 million tons) beginning in the year 2003 in the affected 22 States and the District of Columbia.

For the 1998 SIP Rule, the USEPA considered what levels of NO _X reductions could be obtained by applying proven pollution control technologies to various source sectors in a reasonably cost-effective and feasible manner. For utilities, the USEPA chose emissions reductions that are equivalent to an emission limit of 0.15 lb/mm BTU of input fuel heat value.

For electrical generating units (EGUs) larger than 25 MWe, the control level was determined by applying a uniform NO _X emissions rate region-wide with the assumption that the air quality benefits could be achieved at a cost-effectiveness less than $2000 per ton of fuel (primarily coal).

As a result of the rule, for the purpose of calculating the state NO _X budgets, the emissions decreases shown in Table 8 from uncontrolled levels would be required of the large (greater than 250 mm BTU or 1 ton/day) non-EGU (electrical generating units) sources:

Delay of NO _X SIP Call Schedule and its Resolution

In May 1999, the US Court of Appeals for the District of Columbia remanded the EPA's 8-hour ozone standard, and postponed the September 1999 deadline for states to submit their modified NO _X State Implementation Plan (SIP) to the USEPA.

The court's decision to postpone the deadline for the states to submit their NO _X implementation plans was limited and did not address the technical basis of the USEPA's NO _X SIP call rule.

On March 3, 2000 the US Court of Appeals for the District of Columbia ruled on a suit brought by the states of Michigan and West Virginia against the US EPA challenging the basis for that agency's call for State Implementation Plans (SIPs). Canada and Ontario, along with the New England states, were interveners on the side of the USEPA in this suit.

By a 2 to 1 majority, the Court rejected the following claims by the two states i) that the USEPA could not call for a revised SIP without convening a transport commission; ii) that the USEPA failed to make a sufficiently state-specific determination of ozone contribution; iii) that the Agency unlawfully overrode past precedent regarding "significant" contribution; and iv) that the USEPA's consideration of cost as a factor in determining reductions was a violation of the statute; v) that the USEPA scheme of uniform controls was arbitrary and capricious; and vi) that the Agency was exercising powers not delegated to it by the Congress. A request for exclusion from compliance with the SIP call by the state of South Carolina was also rejected by the court.

The court did, however, rule that the record did not support inclusion of Wisconsin in the SIP call nor did it support creating NO _X budgets based on the entire NO _X emissions of the states of Missouri and Georgia. Development of SIPs may now proceed, assuming the states do not elevate their suit to a higher court.

The USEPA has proposed federal requirements to reduce NO _X emissions, even if a state does not submit the required plan provisions in response to the NO _X SIP call mentioned above. The proposal outlines reduction requirements for both utilities and large non-utility point sources, including large industrial boilers and turbines, large internal combustion engines, and cement manufacturing. The proposed requirements use the same cut-off levels, categories, and control levels as were used to develop the final NO _X SIP call budgets and have the same implementation date of May 1, 2003.

USEPA has also proposed action on petitions filed by eight Northeastern states seeking to reduce ozone transport across state boundaries through reductions in NO _X emissions in upwind states. Each petition requests that EPA make a finding that NO _X emissions from certain stationary sources, particularly coal-fired utilities, significantly contribute to ozone non-attainment in the petitioning state. The utilities and some states have challenged the USEPA's action on the Section 126 petitions because they are based on the new 8-hour ozone standard currently in abeyance as a result of a US federal court decision. In response, the USEPA has modified its justifications, basing them solely on a 1-hour standard.

The polluting states identified in the petition include all of the 22 states and the District of Columbia that are subject to the NO _X SIP call, plus a few other states. The USEPA has found that seven of the eight Section 126 petitions have technical merit and that sources in 19 States and the District of Columbia significantly contribute to non-attainment in, or interfere with, the ability of states to maintain clean air in one or more of the petitioning states.

Strategic Attack on Air Pollution (Ontario Program)

The Ontario government recently proposed (January 24, 2000) air pollution reductions to the electric utilities sector, through the implementation of a Strategic Attack On Air Pollution , a clean air plan which applies only to oil and coal burning electricity generating facilities. Net emissions of smog-causing NO (not NO ₂ ) are to be reduced by 5 per cent and sulphur dioxides by 10 per cent below current caps, beginning in 2001, through the implementation of three major initiatives: revised emission caps, emission performance standards, and emission credit trading. Also, the Province will adopt any future regulations imposed on the electric utilities sector in the US, provided that such standards are more stringent than the present Ontario standards.

Emission Caps: Initial regulations would cap total annual emissions of NO _X and SO ₂ from all coal and oil-fired electric generating stations in Ontario greater than 25 MW in capacity through:

• an annual cap for NO (rather than NO ₂ ) of 36 kilotonnes per year for the year 2001 ( current cap 38 kt/year );
• an annual cap for SO ₂ of 157.5 kilotonnes per year for the year 2001 (current cap 175 kt/year)

The government has also made a commitment to reduce total NO emissions by 45 per cent below the 1990 levels by the year 2015 as part of the "Anti-Smog" Program.

Emissions Performance Standards: The emission performance standards (EPSs), will apply to coal and oil-fired electrical generating plants with a capacity greater than 25 MW. The EPSs will also apply to any electricity generated in other provinces or the United States and sold for use in Ontario. The EPSs would require that electricity produced or sold in Ontario must generate NO _X or SO ₂ at rates less than or equal to the rate specified in Table 9 below.

Emissions associated with power imported into Ontario from the US would not be included in the NO and SO ₂ cap calculation; however, American utilities selling into Ontario will have to meet the same emissions standards that govern in-province producers.

Emissions Trading

As part of their Strategic Attack, the Ontario Ministry proposed a "Cap, Credit and Trade" emissions trading program. The proposal is meant to maintain environmental protection while providing flexibility for industry to adapt to the new standards. Capped emitters of NO _X and/or SO ₂ would be allowed to purchase Emission Reduction Credits (ERCs) from non-capped sources to meet their regulated limits. Any emitter of NO _X and/or SO ₂ , not subject to a cap, that reduces emissions of NO _X and/or SO ₂ below its current legal limit would be permitted to create emissions reduction credits saleable to capped emitters. The new pollution credit trading system is designed to leverage environmental benefits on local air quality, by giving greater value to pollution credits purchased within a given airshed.

The new Strategic Plan states that some emission reduction credits used by the purchaser in Ontario must not have been created outside of the Ontario airshed. The ERCs will be subject to some restrictions including:

• NO _X : directionally NNW to SSE, distance 1,500 km; and,
• SO ₂ : directionally NE to W to SE, distance 3,000 km.

The Ontario plan notes that discounting the value of the credits from distant sources shall be used beyond 300 km to reflect the relative impact on the airshed. This responds, to some extent, to the Commission concern with regard to consideration of the impact of direction, distance, and seasonality in the execution of trades.

Environmental officials from the USEPA are considering Ontario's approach, since neither the NO _X SIP call nor the Acid Rain Program employ it. Utility sources in the US are currently reviewing the plan to determine if it is effective and feasible.

Broader Air Strategy : The new action plan commits the province to reducing by 75 per cent the number of times the province's one-hour air quality criterion for ozone is exceeded. To reach this goal, provincial emissions of NO _X 's and VOC's are to be reduced by 45 per cent of 1990 levels by the year 2015.

In addition to reductions in NOx and VOCs, a strategy to reduce levels of particulate matter in air is also in development under the Anti-Smog Action Plan. Scientists state that the strategy indicates that up to a 75 per cent reduction in SO ₂ emissions from both parts of Canada and parts of the US is needed to fully protect aquatic ecosystems in Ontario and eastward. The electricity sector accounts for only a portion of NO _X and SO ₂ emissions in the province, therefore, in order to ensure Ontario's progress towards the targets of Anti-Smog Action Plan and the Canada Wide Acid Rain Strategy for Post 2000, other sectors will need to reduce air emissions.

Emissions Reporting

Other provisions announced by the Province include a requirement for annual reporting by all electric power plants of emissions of their pollutants including mercury, SO _X 's, NO _X 's and carbon dioxide, starting in May of 2000. The government has set a target of reducing total sulphur dioxide emissions in the province by 50 per cent, by 2015, as part of a national plan to reduce acid rain emissions.

Comments From Environment Canada on Ontario's New Strategic Attack on Air Pollution

Environment Canada offered comments and suggestions that may strengthen or clarify key areas of focus.

Recommendation

With respect to the Ontario Strategic Attack on Air Pollution, the Commission should seek the following enhancements:

1. the inclusion of gas fired units within any nitrogen oxides cap for Ontario electrical generation facilities;

2. rather than the current cap of 36 kt/year on NO emissions, a commitment to a lower cap of 21.6 kilotonnes/year from all combustion electrical generation facilities consistent with application of the USEPA NO ₂ performance benchmark for such facilities of 0.15 lb of NO ₂ /mmBTU (0.65 kg/MWh);

3. an acceleration of the province-wide, multi-sectoral programs for SO ₂ , NO _X , and VOCs to an attainment year of not later than 2010, with ongoing and careful review to determine if reduction actions are adequate to meet air quality objectives; and,

4. assurances that the use of emissions trading not allow total SO ₂ and NO _X emissions to exceed the province-wide targets established by Ontario.

Within these four regions, a total of 312 coal-fired electric utility stations were operating in 1995. Over the past few years, nuclear stations in these regions have experienced operational difficulties which have resulted in a greater reliance on the use of coal stations. Besides the excess generation capacity currently available at many operating stations, there are an additional 201 non-operational coal-fired stations in these regions. This includes 11 stations reported to be under construction, and 154 listed as being retired. Together, these two categories of non-operating stations represent 12.5 per cent of the total capacity of all operating coal-fired stations in the regions under investigation.

Table 10 presents data for SO ₂ , NO _X and CO ₂ emissions for the year 1995 for the largest 100 coal-fired stations contained within the four regions studied (Institute for Environmental Studies, Pollution Probe, 1998). It is particularly significant to note from this table that the Ohio Valley/US Great Lakes region generated a great majority of the emissions for each of the three pollutants studied. This could be due to the fact that, out of the 100 largest coal stations in the designated area, 90 (or 90 per cent) were located in the Ohio/Great Lakes region. Also, when comparing the various ages of these facilities, over 80 per cent of the stations were built before 1970, and therefore likely contain very limited pollution control technologies. It is 'grandfathered' plants such as these that the USEPA is pursuing in court for their failure to adapt or upgrade their pollution control equipment.

The much greater reliance on coal-fired stations to supply electricity in this Ohio Valley/US Great Lakes region also resulted in it having the highest per capita generation of all emissions, with the exception of SO ₂ . A higher per capita SO ₂ level was found in the Eastern Canada region, caused by the use of coal with a high sulphur content at a number of stations there.

Due to the long-range transport of many of these air pollutants, any increase in the use of coal in the US Ohio Valley/Great Lakes States region without additional emission control would affect all areas to the east and northeast, including Ontario, Quebec, the US Northeast and Atlantic Canada.

On December 21, 1999, the US Environmental Protection Agency signed the final Tier 2 mobile source emission regulations. The new standards set more stringent exhaust emission levels for light duty vehicles and establish a new maximum sulphur level in gasoline.

The new standards will apply for new passenger cars and light-duty trucks. The program, for the first time, will apply the same set of standards to all passenger cars, light trucks and medium- duty passenger vehicles, regardless of vehicle or engine size. Light trucks include "light light-duty trucks" (LLDT's), rated at less than 6000 lbs (2700 kg) gross vehicle weight and "heavy light-duty trucks" (HLDT's), rated at more than 6000 lbs gross weight. "Medium-duty passenger vehicles" (MDPV's) form a new class of vehicles covered by the new standards. It includes sport utility vehicles (SUVs) and passenger vans rated between 8500 and 10000 lbs (3600 and 4500 kg) gross vehicle weight.

For the Tier 2 standards, the same requirements will apply to all vehicles regardless of fuel (gasoline or diesel). The Tier 2 standards will reduce new vehicle NO _X emissions to an average of 0.07 g/mi, compared to the Tier 1 standards of 0.4 g/mi for gasoline cars and 1.0 g/mi for diesel cars. The projected reductions in NOX from mobile sources are compared to overall estimated future emissions in Table 11.

Overview of Tier 2 Regulations for Vehicle Emissions

• for new passenger cars and LDT's, standards will phase in beginning in 2004, with implementation by 2007
• for heavy LDT's and MDPV's, the Tier 2 standards will be phased in beginning in 2008, with full compliance by 2009
• during the phase in period between 2004-2007, all passenger cars and light LDT's not certified to the primary Tier 2 standards will have to meet an interim average standard of 0.30 g/mi NO _X
• during the period between 2004-2008, heavy LDT's and MDPV's not certified to the final Tier 2 standards will phase in to an interim program with an overall average standard of 0.20 g/mi NO _X , with those not covered by the phase-in meeting a per-vehicle cap of 0.60 g/mi NO _X for HLDT's and 0.09 g/mi NO _X for MDPV's.

Under the Tier 2 standards, the USEPA has also set stringent requirements for particulate matter emissions. It allows manufacturers to have a choice of certifying their vehicles to any of 10 'certification bins,' which will vary from 0 (zero emissions), through 0.01, to a maximum of 0.02 grams/mile. Three temporary bins, scheduled to expire at the end of the 2006 model year, allow for certification up to a 0.08 g/mi standard, which is identical to the current Tier 1 PM limit for diesels. Manufacturers will be allowed to distribute their vehicles among 'bins' as long as their fleet averages .07 grams/mile of NO _X or less. Primary particulate matter will be lowered markedly from the current 0.1 gram/mile standard largely prevalent under Tier 1, particularly given the fuel neutrality (equivalent treatment for both diesel and gasoline) of the new regulation. Secondary particulate formation (not measured as PM at the tailpipe) will also be lowered as a result of the reductions in SO ₂ and NO _X associated with the lower allowed sulphur level in gasoline and the more stringent NO _X requirements respectively.

Along with limiting vehicle emissions, the Tier 2 standards also set a maximum sulphur limit for gasoline.

Overview of Tier 2 Regulations for Sulphur in Gasoline

• The standards require that most refiners and importers meet an average gasoline sulphur standard of 120 ppm and a maximum of 300 ppm, beginning in the year 2004.
• By the year 2006, the standard will be reduced to 30 ppm average and a maximum of 80 ppm.
• Temporary, less stringent standards will apply to a few smaller refiners through the year 2007.

The lower sulphur levels will enable use of automotive emission control technology necessary to meet the more stringent standards over the useful life of vehicles. Also, as soon as the low sulphur gasoline is available, gasoline vehicles already on the road should achieve reduced emissions from less degradation of their catalytic converters.

The new regulation has not addressed the issue of sulphur levels in diesel fuel. Concern has been expressed that unless ultra low sulphur diesel fuels are required, the new Tier 2 particulate standard cannot be attained by diesel vehicles. The USEPA has concluded that it would address this issue separately, with a notice of proposed rulemaking (NPRM) expected in early spring of this year.

One area of concern about the new standards are the costs to the public. According to the USEPA's estimates, complying with the Tier 2 standards will:

• cause a cost increase of less than $100 per passenger car;
• cause an average cost increase of less than $200 for light trucks;
• cause an average cost increase of $350 for medium-duty passenger vehicles; and,
• cause an average cost increase of less than 2 cents per gallon of gasoline.

Along with reductions in NO _X , some SO ₂ reductions will occur; however, they are less when compared to NO _X . It is estimated the SO ₂ emissions will be reduced by 1.3 per cent by the year 2007, as a result of the Tier 2 program.

In Canada, with imminent declaration of the Canadian Environmental Protection Act, the authority for regulation of motor vehicle emissions will be moved under that Act from its current location in the Canada Motor Vehicle Safety Act, administered by Transport Canada.

Almost from the inception of auto emissions controls, given the active trade in vehicles and parts between the US and Canada, the federal government has recognized the benefits of compatible auto regulations extending through both countries, resulting in comparable regulations to date. Over the next few years, it is the established intention of the government to introduce Canadian regulations compatible with the new USEPA Tier 2 requirements in time for incorporation of necessary technology in production of 2004 model year vehicles.

On October 23, 1998, the Environmental Minister announced the government will introduce regulations to significantly lower the allowable level of sulphur in gasoline sold in Canada. The new regulation was published in Canada Gazette, Part II, June 1999. The regulations would reduce the sulphur content in gasoline to an average level of 30 ppm with a maximum of 80 ppm, which is a 90 per cent reduction from current average levels. To reduce the impact on industry, the requirement will be phased in as follows:

• gasoline produced or imported into Canada must meet an average of 150 ppm in the phase in period of July 1, 2002 to December 31, 2004; and,
• gasoline produced or imported into Canada must meet an annual average of 30 ppm starting on January 1, 2005.

Refiners have indicated that they require three years or more to plan, design and build the equipment to remove sulphur from gasoline. Therefore, -2002 is the earliest time at which low sulphur gasoline could be made widely available in Canada.

Sulphur levels in gasoline now average 360 ppm in Canada, among the highest in the world. The proposed regulations would bring Canadian gasoline sulphur levels in line with those in California, Japan and the European Union.

By decreasing the level of sulphur in gasoline, and thus allowing emission control systems on automobiles to function optimally, the emission of air pollutants, health impacts and premature deaths will all be reduced. A federal-provincial work group estimated that, over 20 years, low sulphur gasoline would prevent 2,100 premature deaths, 93,000 incidences of bronchitis in children, and over 5,000,000 other health related effects such as asthma.

It is expected that the introduction of low sulphur gasoline would result in a one cent per liter increase at the pumps, or about $20 a year per car on average.

Diesel exhaust (DE) is a complex mixture of gases and particles with hundreds of chemical constituents, including many organic compounds, found both in gaseous form and on particles. The gaseous fraction is composed of nitrogen, oxygen, carbon dioxide, and water vapor, as well as smaller amounts of other substances such as carbon monoxide, sulfur oxides, nitrogen oxides, volatile organics, alkenes, aromatic hydrocarbons, and aldehydes, such as formaldehyde and 1,3-butadiene, and polycyclic aromatic hydrocarbons.

The particulate emission fraction is composed of very small (typically 0.2 µm in diameter) particles that are highly respirable. It can be divided into two categories: primary and secondary particulate. Primary particulate is formed during the fuel combustion process in the engine, and is released as exhaust from the tailpipe. It includes soot, the soluble organic fraction which contains polycyclic aromatic hydrocarbons (PAHs), and sulphate. Secondary particulate is formed when the sulphur dioxide (SO ₂ ) emissions from diesel exhaust are converted to sulphate particulate in the atmosphere.

Diesel particulate matter (DPM) emissions have increased almost steadily since the introduction of diesel engines to the trucking industry first occurred in the 1930's. Although diesel fuel use has increased from one per cent of total fuel use in 1949 to 18 per cent in 1995 (U.S. Federal Highway Administration, 1995), DPM emission per individual vehicle have been reduced by roughly a factor of six by advances in control technologies and changes in diesel fuel chemical composition. Estimates of the contribution of diesel fueled vehicles to the total fine particulate burden in the United States and Canada are given in Figures 4 and 5, respectively.

Table 12 displays California's estimated daily PM ₁₀ emissions from on-road mobile sources. Heavy-duty diesel vehicles emit approximately 57 per cent of the total PM ₁₀ emissions each day in California.

In its previous reports, the Board has noted some of the negative environmental impacts associated with several of the primary constituents emitted from operating diesel engines. For example, diesel vehicles, through their release of nitrogen oxides, make a substantial contribution to the formation of ozone and acid rain. More recent concerns focus on diesel particulate matter (DPM) because of its potential carcinogenic effect in humans. In 1996 the USEPA in its Proposed Guideline for Carcinogen Risk Assessment, declared that diesel engine exhaust is "highly likely" to be carcinogenic via the inhalation route of exposure. In 1998, in their third draft report since 1994 focusing on DPM, the California Air Resources Board (CARB) identified diesel particulate matter as a "toxic air contaminant."

Epidemiological studies suggest that incidents of lung cancer increase, on average, about 33-47 per cent above background levels in occupational exposures to diesel exhaust. There are some uncertainties about the magnitude of the increase because with lung cancer, the question of confounding by cigarette smoke is present (EPA Diesel-Health Report, 1999).

The USEPA feels that, despite the finding that diesel emissions are best characterized as "highly likely" to be a lung cancer hazard, the available data are currently unsuitable to make a confident quantitative statement about the magnitude of the lung cancer risk attributable to those emissions at ambient exposure levels.

Some of the uncertainties involved include: methodologic limitations inherent in epidemiologic studies, as well as lack of historical exposure data for occupational exposed cohorts; uncertainties regarding the extent of bioavailability of organic compounds present on diesel particles and their impact on the carcinogenic process; and other uncertainties regarding the mode of action of DE on lung cancer in humans.

The California Air Resources Board (CARB) has established that diesel particulate matter increases respiratory disease, lung damage, cancer, premature death, reduced visibility, and surface soiling.

The CARB has established unit risk estimates for cancer from diesel exhaust particulates represented in Figure 6:

The primary health concerns surrounding human exposure to diesel exhaust include nonmalignant respiratory effects and lung carcinogenicity; however, an emerging area of concern is exacerbation or initiation of allergenic hypersensitivity.

Diesel engine emissions are considered an irritant to the human respiratory system given sufficient episodic exposure. A variety of inflammation-related symptoms may result which include, but are not limited to, headache, eye discomfort, asthma-like reactions, and nausea, depending on individual susceptibility to diesel emission constituents. A recommended human chronic exposure level to diesel exhaust without appreciable hazard from adverse noncancer respiratory effects is 5 µg/m ³ (Inhalation Reference Concentration, RfC).

As mentioned, the Tier 2 standards apply for new passenger cars and light-duty trucks. The same standards will apply to all vehicles regardless of fuel used (gasoline and diesel-fueled vehicles will be certified to the same NO _X emission standard). However, the regulation has not yet addressed the issue of sulphur levels in diesel fuel.

The new standard is expected to require exhaust gas after-treatment technologies, including diesel particulate traps. Ultra low sulfur diesel (ULSD) fuel will also play a key "technology enabler" role in making the standard feasible. ULSD fuels improve the emission reduction effectiveness and durability of diesel oxidation catalysts and particulate filters and are expected to enable future advances in emission controls.

Emission Reductions Using Low Sulphur Diesel

Currently, in the US, the regulated level of sulphur in diesel fuel used in highway vehicles is set at 500 ppm, and averages between 300 and 400 ppm.

Recent test results on the use of particulate filters and diesel fuel with 30 ppm sulphur levels in test diesel engines indicated particulate traps achieve approximately 73 per cent efficiency (or 0.02 grams per brake horsepower-hour (g/bhp-hr)) in PM reduction. It allows for an emission level of 0.02 g/bhp-hr, which is a level being considered by the USEPA for the year 2007 regulations. The USEPA sees a potential for 70-90 per cent reduction in PM emissions by utilizing lower sulphur fuels, relative to today's standards. That is approximately a 0.01 g/bhp-hr PM standard, down from the 0.1 g/bhp-hr PM standard.

Implementation of a diesel fuel sulfur standard between 5 - 40 ppm is under consideration by the USEPA, while the California ARB has suggested a 30 ppm level. The engine manufacturers have indicated that, to be confident of meeting the year 2007 standards, a sulphur content of five ppm (5 ppm) in diesel fuel would be necessary. The final fuel sulfur specification, which may be introduced in the next few months, would likely come into effect as of the year 2007 and would depend on aftertreatment technology needs for NO _X and particulate matter control, refinery production technology feasibility, costs, the ability to maintain fuel quality in the distribution system, and testing tolerances.

A Notice of Proposed Rule Making (NPRM) on the new federal HD standards is expected to be published in early 2000. Both the USEPA and CARB indicated they would also regulate substantial reductions in PM emissions from non-road diesel engines.

Reducing PM _2.5 Emissions from Older Vehicles

Understanding the prevalence of diesel engine penetration into the motor vehicle market is an important aspect of estimating the potential health effects of diesel exhaust emissions. According to data from the US Census of Transportation (1995), in 1992, out of the 1,966,200 Heavy Heavy-Duty (HHD) trucks in use, 87.8 per cent were diesel powered; out of the 732,000 Light Heavy-Duty (LHD) trucks in use, 35.8 per cent were diesel; and out of the 1,259,000 Medium Duty (MD) trucks in use, 25.9 per cent were diesel. For all three vehicle classes in 1992 there were a large number of vehicles more than 10 years old: 54 per cent MD, 60 per cent LHD, and 43 per cent for HHD. Figure 7 displays the model distribution of in use trucks in 1992. For Heavy Heavy-Duty trucks, there were roughly 100,000 vehicles in each model year from 1983 to 1993 (USEPA Health Report).

The USEPA certifies emission control technologies under its urban bus retrofit/rebuild program. Before the program began in 1993, there was no affordable emission control technologies available to reduce PM emissions to 0.1 grams per brake horsepower-hour. In 1997, the USEPA certified the first technologies that could cost-effectively meet that low emission limit when applied to older diesel engine systems.

In early February of this year, the USEPA announced that it has certified emission control technology for urban bus operators to use, in order to reduce PM and NOx emissions from diesel buses built in the model year 1993 or earlier.

Recognition and application of this technology means that urban bus operators can reduce PM emissions on their buses with four-stroke engines to 0.1 grams per brake horsepower-hour, down from the original certification standard of 0.6 gram PM that most pre-1993 engines were to attain when they were new. Many rebuilt two-stroke diesel engines already must meet the 0.1 gram PM standard because of earlier USEPA certified technology.

In Canada, particulate matter emissions were first regulated in the year 1988, when heavy-duty diesel emissions standards from the United States (0.1 g/bhp-hr PM standard) were adopted. The federal 'Diesel Fuel Regulations,' of January 1, 1998 also limit the sulphur concentration in diesel fuel used in on-road light-duty vehicles, light-duty trucks and heavy-duty vehicles to 500 ppm.

Designing a specific diesel engine for Canada to meet a distinct set of Canadian emission requirements would be inefficient from a manufacturing point of view, while at the same time increasing costs to the consumer. These considerations strongly argue for the continuation of harmonizing Canadian diesel vehicle emission standards with those in the United States.

Recommendation

The Commission should recommend that the governments of the United States and Canada move to adopt standards limiting the sulphur content of diesel fuel, so as to enable the introduction of advanced, reliable and durable high level control systems for NO _X and particulate matter on diesel engines. These sulphur standards will likely lead to a diesel fuel with an estimated 5 ppm sulphur content. The infrastructure to produce and deliver this fuel must be place in the year 2006 to support emission standards applicable to the 2007 model year vehicles.

In December of 1999, Environmental Ministers from Europe and North America met in Sweden to sign a new Protocol to the UN/ECE Convention on Long Range Transboundary Air Pollution, 'The Protocol to Abate Acidification, Eutrophication and Ground-Level Ozone' aims to reduce emissions of sulphur oxides, VOC's, NO _X 's and ammonia from energy generation, and industrial sources as well as motor vehicles.

The Protocol sets reduction targets for all four major pollutants. By the year 2010, Europe's sulphur dioxide emissions should be reduced by 63 per cent, its NO _X emissions by 41 per cent, VOC emissions by 40 per cent and ammonia levels by 17 per cent compared to their 1990 levels. As participants in the UN/ECE, Canadian and US reductions in sulphur oxides, nitrogen oxide and VOC emissions will be incorporated when the protocol is ratified.

The protocol also sets limit values for specific emission sources and requires use of best available techniques including control of agricultural ammonia emissions.

Once all the targets are met, the area in Europe with excessive levels of acidification should shrink from 93 million hectares in 1990 to 15 million hectares in 2010. Those with excessive levels of eutrophication should fall from 165 million hectares in the year 1990 to 108 million hectares in the year 2010. Also, the number of excessive ozone days should be cut in half. Table 13 compares emissions, targets and target timeframes for North America and some selected European countries, illustrating that this issue is a global concern.