Chapter 4. Climate change mitigation in electricity generation and transport
Canada’s greenhouse gas emissions are among the highest in the OECD on a per capita basis. Emissions are almost 20% above the 1990 level, and have fallen back only slightly since 2000. Meeting the 2030 emissions reduction target will require a major shift in policy. Recognising this, Canada developed the first-ever overarching plan to meet the target in a co-ordinated approach among federal, provincial and territorial levels. This chapter discusses Canada’s climate policy and some of the challenges involved in its climate targets. It focuses particularly on electricity generation and transport.
1. Introduction
The 2004 Environmental Performance Review (EPR) encouraged Canada to “aggressively implement the [2002] Climate Change Plan for Canada”, using a broad array of instruments. The plan had set out principles and steps for meeting Canada’s greenhouse gas (GHG) emission reduction target under the Kyoto Protocol, from which Canada withdrew in 2011. Even though the plan has never been implemented, a number of climate policies have been introduced, most notably at the provincial and territorial level. Notwithstanding, a decade after the last EPR, Canada’s GHG emissions had fallen back only slightly compared with the 2000 level, and were almost 20% above the 1990 level. While emissions in electricity generation had been cut, they grew substantially in domestic transport and in the oil and gas extraction industry.
The 2016 Pan-Canadian Framework on Clean Growth and Climate Change (PCF) represents the first time since 2002 that concrete steps to develop a nationwide strategy have succeeded. The PCF aims to reduce emissions by 30% from 2005 levels by 2030, in line with the target Canada set in its nationally determined contribution (NDC) under the Paris Agreement. Achieving the target will be challenging, even if it leaves emissions not much below the ambition embodied in the Kyoto Protocol (Figure 4.1). The PCF envisages a wide range of actions to reduce economy-wide emissions – many of which are yet to be implemented. Canada’s mid-century climate strategy recognises that much more will be needed after 2030 to bring Canada’s emissions on a path consistent with the global objective of keeping warming below 2°C.
This chapter discusses Canada’s climate policy and some of the challenges involved in its GHG mitigation targets. It focuses particularly on electricity generation and transport. Canada has huge potential for zero-carbon electricity generation, but also huge reserves of cheap fossil fuels, with the balance varying widely across the provinces and territories. The challenge is to find cost-efficient policies that exploit national advantages, while considering the regional variation. Emissions from transport continue to rise, alongside higher incomes and increased demand for travel and freight transport. Low- or zero-carbon transport technologies are increasingly available, but still suffer from a combination of high cost and/or lack of appropriate infrastructure. A good balance between use of carbon pricing, vehicle emission standards, fuel standards, and other kinds of regulations or voluntary agreements, paying attention to the needs of different transport sectors, needs to be found.
2. State and trends in GHG emissions
In 2014, Canada was the fourth largest emitter of GHG emissions in the OECD in absolute terms, excluding land use, land-use change and forestry (LULUCF). It accounted for about 5% of total OECD emissions, compared with its 2.8% share of population, or 3.2% of gross domestic product (GDP) (OECD, 2017a). Emissions in 2015 reached 722 million tonnes of carbon dioxide equivalent (CO2eq), 18% above 1990 levels and 2.2% below 2005 levels (ECCC, 2017). In 2008-12, the first period of the Kyoto Protocol, emissions were 20% above the 1990 level, rather than 6% below as foreseen in the protocol. Emissions stayed relatively stable in the first half of the 2000s, with a dip during the 2008/09 financial crisis; unlike in most other OECD member countries, they increased thereafter (Figure 4.1).
Although emissions have begun to decrease slightly since 2013, meeting the 2030 mitigation objectives will be difficult given Canada’s current and foreseeable emissions profile. Under business as usual conditions (with policies in place as of November 2016), GHG emissions are projected to peak in 2026. They will likely decline thereafter, though not enough to meet the 2030 targets (Figure 4.1). New climate policies foreseen under the PCF would, if fully implemented, put Canada on the right path according to government projections. The government may use international mechanisms to achieve the 2030 target, but domestic emissions are expected to provide more than three-quarters of the reduction. Canada’s Mid-Century Long-Term Low-Greenhouse Gas Development Strategy, issued in 2016 as a discussion document, examines a pathway that would bring emissions in 2050 to 80% below the 2005 level. This implies a cut between 2030 and 2050 nearly twice that planned between now and 2030. Much more will therefore need to be done after 2030. Indeed, the 2030 target itself could be tightened for consistency with the internationally agreed objective to keep global warming within 2°C.
Emissions have decreased in all provinces and territories since 2000, except in Alberta and Saskatchewan (Figure 4.2). Alberta accounted for 38% of Canadian emissions in 2015, reflecting the province’s large energy-intensive extractive industry, notably the oil sands. Ontario, the most populated province, was the second largest emitter of GHGs, accounting for 23% of Canadian emissions in 2015. It saw the most significant decrease in emissions, largely due to the phase-out of coal in electricity generation. The sparsely populated northern territories accounted for only 0.3% of national emissions.
The energy sector is responsible for the lion’s share of national GHG emissions. The oil and gas industry accounted for about one-quarter of total emissions; adding in fuel combustion by power plants, industry and transport brings the energy sector to above 80%. The most dramatic increases occurred in the oil and gas sector and in transport, with increases of nearly 80% over 1990-2015, or 20% over 2000-15 (Figure 4.3). By contrast, emissions from electricity generation decreased significantly (by 38%) over 2000-15, mostly driven by the phase-out of coal in Ontario. Emissions from industry (other than oil and gas) have also decreased (by 20% since 2000); emissions from agriculture and buildings have stayed relatively stable. Canada has one of the world’s least carbon-intensive power sectors, due to a high share of hydro and nuclear power (Section 4). However, fossil fuels continue to dominate Canada’s total primary energy supply (see Chapter 1). As a consequence, energy-related GHG emissions have continued to increase along with energy use in the economy.
CO2 accounted for 79% of Canada’s total GHG emissions in 2015, mostly from combustion of fossil fuels. Methane is estimated to have accounted for 14%, mostly due to fugitive emissions from oil and gas industries. Measurement of methane is challenging and statistics are poor. A recent report suggests that fugitive emissions from parts of the Alberta oil and gas industry could be underestimated by as much as 60% (Environmental Defence Canada, 2017). If this latter figure is accurate, total national GHG emissions are being underestimated by nearly 4%. N2O emissions from agricultural soil management and transportation accounted for 5% of total GHG emissions, and F-gases from industrial processes accounted for some 2% (ECCC, 2017).
Canada’s LULUCF sector acts as a net carbon sink (i.e. it absorbs more CO2 than it emits through land and land-use change activities such as deforestation) (ECCC, 2017). In 2015, the sector’s net emissions reached -34 million tonnes of CO2eq, meaning it reduced total Canadian emissions by nearly 5%. However, there is high variability in emissions and removals from Canada’s LULUCF sector. This is due to large variations in emissions from forest land as a result of natural disturbances. In some years, for example, wildfires release significant emissions in managed forests. The extensive Mountain Pine Beetle infestation in Western Canada is also responsible for considerable emissions from tree loss. Canada’s 2017 GHG inventory for the first time excludes the impact of natural disturbances on LULUCF net emissions. This improved approach has led to significant recalculations for anthropogenic emissions and removals estimates in the LULUCF category (ECCC, 2017).
Despite improvement, Canada’s emissions intensities remain among the highest in the OECD. In 2014, GHG emissions per capita were 20.5 tonnes of CO2eq – significantly above the OECD average of 12.4 tCO2eq. GHG emissions per unit of GDP (USD, 2010 PPPs) were 0.49 kg of CO2eq – also above the OECD average of 0.34 kgCO2eq (OECD, 2017a). High emission intensity partly results from Canada’s geography and industrial structure. Its northern location and long distances between major population and industrial centres result in high demand for transport and heating. At the same time, key energy extraction industries themselves emit large quantities of GHGs both as combustion products and fugitive emissions. Emission intensities are particularly high in Alberta and Saskatchewan, the centre of Canada’s production of oil and gas, as well as coal. Canada is among the world’s largest producers and exporters of oil and natural gas.
3. The evolution of climate change policy
3.1. Division of powers and institutional framework
Provinces have wide-ranging responsibilities, including in the area of environmental policy, energy policy and the management of natural resources within their boundaries (see Chapter 2). Indeed, most key policy tools for GHG mitigation are the responsibility of provinces and territories. The federal government has the jurisdiction to regulate GHG emissions under the 1999 Canadian Environmental Protection Act (CEPA). Indirectly, it also regulates emissions through the 1992 Energy Efficiency Act. This legislation provides authority to regulate minimum energy efficiency standards for energy-consuming products and product labelling.
Several institutions are involved in developing and implementing climate change policies at the federal level. Environment and Climate Change Canada (ECCC), the lead ministry for domestic and international climate change policy, has the main responsibility for regulation of GHG emissions. Natural Resources Canada (NRCan) is the primary body responsible for federal energy efficiency and renewable energy policy. NRCan and ECCC are also responsible for alternative fuels policy and vehicle emissions regulations. Transport Canada governs emissions and efficiency regulations for other transport modes – rail, air and marine. Indigenous and Northern Affairs Canada (INAC) works with Indigenous and northern communities to build resilience to climate change and address energy-related issues, including supporting the deployment of proven forms of renewable energy that reduce GHG emissions. The institutional framework for climate policy varies at the provincial level (IEA, 2016).
Canada’s federal structure and assignment of competences makes it imperative for the federal, provincial and territorial governments to work closely together to translate international commitments into domestic climate action. Negotiation, rather than imposition, is the typical approach for the federal government, with the risk it will be unable to meet its international commitments. The federal, provincial and territorial governments collaborate on climate action mainly through the Canadian Council of Ministers of the Environment (CCME). A Climate Change Committee was established in June 2015 to facilitate ongoing federal/provincial/territorial engagement on climate change.
3.2. National targets and objectives
Canada was a signatory to the Kyoto Protocol of the UN Framework Convention on Climate Change (UNFCCC), having formally ratified the protocol in 2002. Under the protocol, Canada committed to cut GHG emissions by 6% from 1990 levels during the first commitment period of 2008-12. In 2006, the government formally recognised it would not meet the Kyoto target; Canada withdrew from the protocol in 2011. It did not take on a commitment under the second commitment period. It decided to withdraw based on its assessment of the costs of meeting the protocol, its limited coverage of global emissions and, in particular, the absence of the United States from the protocol (EC, 2012).
In 2007, before Canada’s withdrawal from the Kyoto Protocol, the federal government announced new targets: an emissions reduction of 20% below 2006 levels by 2020, and 60‐70% below 2006 levels by 2050. The federal government’s implementation plan, Turning the Corner, focused on a reduction of emissions intensity. It intended to reduce industrial emissions per unit of output by 6% per year up to 2010 and by 2% per year thereafter. It also proposed regulating industrial emitters through a tradable credit system. However, many of its key provisions were opposed in Parliament, and no attempt was ever made to enforce the reductions in emissions intensity. Given the level of integration in the North American economy and developments within its southern neighbour, the federal government instead chose to pursue harmonisation of emissions reduction policies and regulations with those of the United States (IEA, 2016).
Two years later, at the 2009 Copenhagen meeting of the parties to the UNFCCC, Canada pledged to reduce GHG emissions by 17% below 2005 levels by 2020, stating this target is “to be aligned with the final economy wide emission reduction target of the United States in enacted legislation” (UNFCCC, 2017). Under the Paris Agreement, which Canada ratified in October 2016, Canada committed to reduce emissions by 30% from 2005 levels by 2030 (GoC, 2016a). The target includes LULUCF (which is a net sink in Canada, see Section 2) and allows for use of international mechanisms to achieve the target. The NDC notes that some sector-based policies have been aligned with those in the United States; it may be implicit this is expected to continue. However, the NDC does not repeat the wording of the 2020 objective to the effect that it may depend on US policy.
3.3. Towards a national response to climate change: The pan-Canadian framework
Until recently, climate change policy was driven mainly by provincial initiatives, without an overall pan-Canadian strategy or framework. Federal climate policy has largely focused around sector-specific intensity-based standards (Section 3.4). The PCF was foreshadowed in early 2016 by the Vancouver Declaration by the First Ministers of the federation, provinces and territories and formalised in late 2016 to help the country achieve its NDC commitment. It was developed in a collaborative manner and in consultation with Indigenous organisations. Both this move and the Alberta Climate Leadership Plan, which preceded it by a few months, represented a significant shift in political will back towards concerted action on climate change; Ontario, Quebec and British Columbia had introduced similar plans earlier. The PCF has four main pillars: pricing carbon pollution; complementary mitigation action across sectors; adaptation and climate resilience; and clean technology, innovation and jobs.
Carbon pricing as a foundation of the PCF
Carbon pricing is to be expanded across Canada using a benchmark approach: by 2018, provinces and territories will have to have their own carbon pricing system in place that must meet minimum requirements set by the federal government. Such a system can take the form of either a carbon tax, a cap-and-trade system or a hybrid approach (e.g. a carbon levy combined with an output-based pricing system, such as in Alberta, see Chapter 3). For any jurisdiction that lacks a system aligned with the benchmark, a federal carbon pricing backstop system will apply. Four provinces already have a carbon pricing mechanism in place (Table 4.1). The direct revenue remains in, or will be returned to, the jurisdiction in which it originates. Most provinces and territories have agreed on the principle (at the time of writing, Saskatchewan and Manitoba had not signed up). The precise mechanism and regulations have yet to be designed, even though it is intended to be in place by 2018. The minimum price under the federal benchmark will be CAD 10 per tonne in 2018, rising by CAD 10 per year to CAD 50 per tonne by 2022. For cap-and-trade systems, the benchmark requires: i) a 2030 emissions reduction target equal to or greater than Canada’s 30% reduction target; and ii) a decline of annual caps to at least 2022 that corresponds with projected emission reductions from the carbon price in price-based systems. Quebec’s cap-and-trade system already has minimum and maximum prices that are to rise through time. The minimum (currently under CAD 14) is less than that planned under the PCF; the maximum is currently CAD 50 to CAD 64, rising, under current legislation, by 5% per year in realterms.
Other key components of the PCF
There are several other important mitigation plans under the PCF. As already foreseen by most provinces, coal-generated electricity will be phased out by 2030. Further, Canada will work towards net-zero energy-ready building codes by 2030, developing a clean fuel standard based on life-cycle emissions (this may replace the more arbitrary biofuel content mandates in place for some fuels), reduce methane emissions in the oil and gas industry by 40-45% and increase carbon storage in forests and agricultural lands. The government of Canada has announced a CAD 2 billion (0.1% of GDP) Low Carbon Economy Fund to directly support initiatives in the PCF. As part of a major infrastructure investment programme (see Chapter 3), the government has also announced investments of around CAD 70 billion (about 4% of GDP) over ten years in public transit infrastructure, green infrastructure, trade and transportation infrastructure and clean technology. Much of the “green” part of this investment will be directed towards supporting mitigation and adaptation initiatives under the PCF. About CAD 9 billion will be channelled through provinces and territories, and CAD 5 billion through the Canada Infrastructure Bank.
Emission projections under the PCF
Baseline ECCC projections foresee, on current policies, a level of emissions in 2030 roughly unchanged from 2015, at 742 million tonnes of CO2eq; to meet targets, emissions should actually be 523 Mt, 30% below the 2005 level and 15% below the 1990 level. The PCF does not specify in detail which measures will achieve how much. However, it does anticipate that out of the total planned reduction of 219 Mt, 89 Mt will come from measures announced in 2016. These include regulations on hydroflurocarbons (HFCs), heavy duty vehicles and methane, as well as the British Columbia and Alberta Climate Leadership Plans, Saskatchewan’s renewables target and credits from abroad in the cap-and-trade programmes. Another 86 Mt would come from new measures in the PCF, such as the final coal phase-out, building regulations and retrofitting, the new clean fuel standard and industry-specific measures. This leaves 44 Mt to be found from further measures (Table 4.2). About a quarter of the reduction is expected to be met by purchasing credits from abroad.1
Because the expected impacts of many specific measures are not quantified, it is hard to verify whether the numbers “add up”. At this stage, lack of certainty is not a weakness of the approach; it is simply realistic. Cross-sectoral interactive effects can also make it difficult to attribute particular reductions to particular measures. Projections and estimates are essential to assessing whether policy is on track. However, if not used carefully, they can lend a spurious precision to analysis. In line with the approach taken in the Paris Agreement, Canada will need both to make objective (even though uncertain) estimates of the likely impact of its different policies, and plan periodic and preferably independent assessments of policies’ outcomes to adjust policy over time. Canada has provisions for performance-based analysis of policies, but they do not always go far enough in considering the ultimate aims of policies (Box 4.1).
Natural Resources Canada provides easy public access to an impressive range of audit and evaluation reports on its own activities and programmes. These include an evaluation of the Renewable Energy Deployment sub-programme (NRCan, 2015). The report demonstrates that information is in principle available to assess costs and benefits and reports that procedures are in place to save programme costs. However, many of the evaluated incentives do not refer to concrete results from the programme. Instead, they refer to the dollar value of likely investment under the programme. They also note surveyed opinions that without the programme “current [renewable energy] capacity would have taken longer to attain”. A cost-benefit approach would require, in addition, information on the quantity of GHG emissions saved (assuming the programme’s basic aim is GHG mitigation), as well as on the costs of the programme to both government and the private sector. Its definition of costs seems restricted to budgetary costs. For example, a “1:10 leveraging of federal funding” (i.e. private investment in renewables of approximately ten times the programme’s fiscal cost) is reported as positive. On its own, however, the ratio would be irrelevant in a society-wide cost-benefit analysis.
In fact, many of Canada’s programmes for support for renewables are indeed likely to be relatively cost effective to the extent that the utility solicits bids for capacity from private sector suppliers. Provided the bidding process is open and competitive, this reverse-bidding procedure at least ensures that targets for renewables are reached cost efficiently. According to OECD (2015a), reverse bidding is indeed the most common method in Canada; the feed-in tariff approach may be used for smaller installations.
The impact of external demand for hydrocarbons
GHG emissions will depend on one key factor outside Canada’s control: world demand and prices for hydrocarbons. Canada’s current projections foresee an increase in its production and exports. If serious steps are taken internationally to implement the Paris Agreement and limit the rise in atmospheric CO2 concentration to 450 parts per million (ppm), International Energy Agency projections suggest that Canada’s production of oil and gas in 2030 could be as much as one-third less than its “current policy” projections. This would be equivalent to 6% less than 2015 production for oil and 17% lower for gas (Figure 4.4). The US government has recently announced it will allow the construction of the Keystone XL and Dakota Access pipelines for delivering Canadian oil into the United States. Other pipelines within Canadian territory, which allow access to the Pacific Ocean for exports, are also planned. It is unclear whether all this planned construction implies higher production or possibly excess pipeline capacity (Gunton, 2017). As Hughes (2016) suggests, even using only existing pipeline capacity to the full would likely result in GHG emissions from Alberta’s oil and gas sector exceeding the recently announced annual ceiling of 100 Mt – unless new technology can radically reduce the emissions intensity of extraction, refining and transport.
3.4. Climate change policy prior to 2016
Most of the important steps in climate change policy, in terms of their impact on the recent evolution of emissions, were taken by provinces and territories. Canada’s Second Biennial Update Report to the UNFCCC provides an exhaustive list of measures undertaken across the country. The list shows the country has introduced up to ten or more such measures each year (GoC, 2016b). About half of these measures were reported with an indication of their expected quantitative impact on emissions in 2020. These data are used in Figure 4.5 to indicate the evolution of climate change policy since 2004.
The share of estimated emission reductions due to policy action in different sectors is very different from the sectors’ shares in emissions (Figure 4.3 versus Figure 4.6). For example, most estimated emission reductions occurred due to measures related to electricity generation, although the sector accounted for a rather small share of total emissions. Agriculture and industries that are particularly emissions-intensive or trade-exposed2 account for about 20% of total emissions, yet no significant measures, or at least none with quantifiable effects, have been taken. This discrepancy between apparent reduction effort and initial shares may suggest the inefficiencies of a piecemeal approach. This does not follow automatically, however; an efficient set of policies would focus on sectors with low abatement costs, and these will not always be those with the highest emissions.
Federal climate policy
As mentioned earlier, climate policy at the federal level has largely focused around sector-specific intensity-based standards. In 2011, the federal government introduced average emissions standards for light road vehicles. These were essentially equivalent to the US Corporate Average Fuel Economy (CAFE) standards, though expressed in GHG emissions per distance travelled rather than fuel consumption. It also established GHG emission regulation for coal-fired electricity production, whose effect would be to eventually force their closure, as discussed later in this chapter. The federal ecoENERGY programmes were launched in 2007 and implemented in subsequent years, covering a wide range of initiatives. These included, for example, support for investment in renewable electricity, retrofitting of houses, development of building codes and funding for research and development (R&D). The ENERGY STAR (labelling) initiative promoted energy-efficient products, including for buildings, cars and appliances. As well, the ecoENERGY for Aboriginal and Northern Communities Program (EANCP) aimed to reduce northern communities’ dependence on diesel-generated electricity.
Examples of provincial and sectoral measures
Most provinces and territories have reduction targets for 2020 and 2050, and measures to achieve them. The focus and design of climate policies vary according to individual priorities and circumstances (IEA, 2016). One of the arguably most important mitigation measures to date was Ontario’s decision to phase out traditional coal-fired electricity generation by 2014 (i.e. coal-fired plants operating without carbon capture and storage). Alberta also announced the phase-out of coal-fired electricity generation by 2030; and a Canada-wide phase-out by 2030 was included in the PCF. Several provinces adopted measures to promote renewable energy and enhance energy efficiency. Some of these measures are discussed in Section 4; mitigation measures in the transport sector are discussed in Section 5.
Many provinces have implemented measures that aim to reduce CO2 emissions across multiple sectors. British Columbia has a carbon tax and Quebec has a cap-and-trade system linked to California’s trading scheme; Ontario launched its programme in 2017 and intends to join the system in 2018. For its part, Alberta has a hybrid system that combines an economy-wide levy with a trading scheme for large emitters. Both Ontario and Quebec have announced reduction targets for 2030 of 37% compared with 1990. This is tighter than the federal target, albeit about a quarter of the reduction is currently expected to come from purchasing external credits in the cap-and-trade system.
Emissions-intensive industry
A small number of measures have addressed emissions-intensive industries, but not in any comprehensive way. Two measures involved financial incentives for specific industries. From 2009-12, Quebec had incentives for pulp and paper, albeit for “environmentally beneficial” capital projects, not just GHG-oriented ones. As of 2016, British Columbia has had subsidies for cement producers to beat emissions-intensity benchmarks. Saskatchewan’s 2010 Management and Reduction of Greenhouse Gases Act set a target for large industrial emitters to reduce their 2020 emissions to 20% below the 2006 level, with the option of paying into a technology fund in lieu of compliance. However, implementing regulations have not yet been published, and the act is yet to be proclaimed in force.
Alberta, the most significant emitter, introduced its Specified Gas Emitters Regulation in 2007. This gave large individual emitters (that produce more than 100 tonnes of GHG emissions annually) targets for intensity reduction. The targets covered about half of Alberta’s total emissions. Later, under its 2015 Climate Change Leadership Plan, Alberta supplemented this approach with a carbon levy on emissions that exceed facility-specific benchmarks.3 Under Alberta’s Carbon Competitiveness Regulation, expected to be introduced in 2018, this levy will be modified to be payable on all emissions. At the same time, sector-specific, output-based allocations of emissions rights will be issued (see Box 3.4 in Chapter 3 for details). The new system is expected to raise the carbon levy to CAD 30 by 2018. This will take carbon pricing coverage to 78-90% of the province’s emissions.
The oil and gas sector
Alberta announced a plan to cap GHG emissions from oil sands at 100 million tonnes, though this is somewhat above current emissions. It is not clear how the province will impose this cap. Apart from Alberta’s GHG cap, provincial measures were mainly focused on methane emissions. Methane accounts for about one-quarter of the sector’s total GHG emissions, but has a stronger warming potential than CO2. All provinces hosting the industry have had regulations to limit venting and flaring in place for some time and emissions from this source have reportedly declined by around 15% since 2005. Alberta has also announced a target of 45% reduction in methane gas emissions from its oil and gas operations by 2025 – this was originally a joint initiative with the US industry. British Columbia plans for the same 45% reduction in methane emissions (in its case, from natural gas); and the target was integrated into the PCF in 2016. The federal government announced intentions to regulate emissions from the oil and gas sector as far back as 2006, but no regulation has been implemented since. Canada, the United States and Mexico jointly committed to reduce methane emissions from the oil and gas sector by 40-45% by 2025. Canada published draft regulations that aim to achieve this reduction target. As proposed, the federal regulations would come into force between 2020 and 2023 (see also Chapter 3).
Three-quarters of the sector’s total GHG emissions are CO2 emitted from fuel combustion used to extract or transport hydrocarbons. CO2 emissions in the sector have not been targeted directly. A large share of these emissions are covered under provincial carbon pricing mechanisms (including British Columbia’s carbon tax and Alberta’s Specified Gas Emitters Regulation). However, their impact towards meeting the climate targets has been limited to date (IEA, 2016). From around 2003-11, Canada-wide GHG emissions from the oil and gas extraction and refining industries reached a plateau about 50% above the 1990 level. They resumed growth thereafter, rising nearly 20% over 2011-14.
Measurement of fugitive emissions is difficult and direct measurement or spot checks are rare.4 According to Environmental Defence Canada (2017), lax monitoring and reporting have led to a large underestimate of the number of devices from which methane may leak. Further, device-specific rates of leakage, often because of poor maintenance, have been significantly underestimated. Environmental Defence Canada (2017) argues that much of the leakage could be eliminated with standard technologies such as those listed in the UN Environmental Protection Agency’s Natural Gas STAR Program (EPA, 2017). In many cases, it argues, the captured methane has commercial value; this means the mitigation cost is very low, or negative. Given the under-reporting, the low cost of many mitigation measures, and the fact that some US states already have significantly tighter regulation, Canada should not further postpone regulation on emissions from methane.
The buildings sector
Most provinces improved building regulations; GoC (2016c) shows measures for all provinces and territories other than Alberta and Saskatchewan. Improvements were mostly of two kinds. On the one hand, they required improved overall energy efficiency in new buildings or in new social housing. On the other, they required energy efficiency in specific facilities, such as requiring new homes to provide for solar water heating (British Columbia, some municipalities). Some programmes involve financial assistance to private homeowners. Quebec, for example, provides financial assistance to retrofit existing dwellings with more efficient heating systems or subsidises insurance for new homes that satisfy energy efficiency standards (specified in its Novoclimat programme). Other provinces, including New Brunswick and Prince Edward Island, as well as Yukon and the Northwest Territories, have similar programmes. Nova Scotia and Quebec have programmes primarily focused on improved insulation and heating efficiency in low-income households.
Waste disposal and management
Most provinces and territories also have measures regarding waste disposal and management which target, either directly or indirectly, methane emissions. British Columbia, Manitoba and Ontario have regulations requiring the capture of methane emissions at landfills that are above thresholds for either landfill capacity or annual methane emissions. Quebec has a comprehensive scheme to improve re-use and recycling rates, charging a “royalty” on material placed in landfills. The municipality of Edmonton, capital of Alberta, recently replaced its main landfill site with a comprehensive waste management process that aims for maximum recycling. It includes a composting facility for sewage and other suitable waste, as well as a gasification plant that produces commercial methanol (soon to be upgraded to produce ethanol). Interestingly, neighbouring municipalities do not use spare capacity in this plant: even with marketable output such as metals recovery, compost and methanol, waste processing charges are too high compared with the landfill alternative.
Agriculture
In agriculture, mitigation measures have mostly been via programmes funded under the federal/provincial/territorial agricultural policy frameworks that have been in place since 2002, such as the current “Growing Forward 2” (2013-18) framework. This supports research or helps finance practices that should reduce emissions, mainly of methane and nitrogen. These practices include improved manure storage, biodigesters, energy-use efficiency, cover crops, precision nutrient application, equipment for reduced tillage seeding and enhanced irrigation efficiency. Agricultural mitigation measures have also been funded through provincially-led emission reduction protocols for carbon offsets, such as in Alberta.
4. Mitigation in electricity generation5
Canada has one of the world’s least carbon-intensive power sectors, due to a high share of hydro and nuclear power in the electricity generation mix (Figure 4.7). Hydropower accounts for 60% of total electricity generation. In absolute terms, only the People’s Republic of China produced more hydro electricity than Canada in 2014 and 2015 (IEA, 2016). Over 2000-15, the share of electricity generated using coal and oil products decreased from 22% to 10%. This decline was partly due to a deliberate policy of reducing coal-fired capacity, notably in Ontario. Electricity generated from natural gas, nuclear and renewables (excluding hydro) have all increased over the same period. The most remarkable increase occurred in the wind sector, which boomed starting in the late 2000s. This boom increased the share of renewables (excluding hydro) in Canada’s power generation sector from 1% to 6% over 2000-15 (Figure 4.7). Overall electricity output increased over this period by 4%, a slower rate of increase than either GDP or population growth.
The electricity generation mix varies a lot across Canada. In Quebec, Manitoba, Yukon, Newfoundland and Labrador hydropower accounts for almost 100% of electricity generation (Figure 4.8). British Columbia also relies primarily on hydro resources (86%). Following its phase-out of coal, Ontario’s supply has been dominated by nuclear energy, which provides around 60% of total electricity generation, as well as hydro (24%) and natural gas (10%). Alberta, Nova Scotia and Saskatchewan generate more than half of their electricity from coal, although natural gas has an increasing role in Alberta and Saskatchewan. In small remote communities in the north, where grid electricity is not available because of lack of grid connections, communities use local diesel generators.
Source: FAO GEONETWORK (2014), Global Administrative Unit Layers (GAUL), www.fao.org/geonetwork/srv/en/metadata.show?id=12691; NEB (2016), Canada’s Energy Future 2016; Statistics Canada (2017), CANSIM Table 127-0007.
The Canadian electricity system is strongly integrated with the US interconnected systems. In 2016, Canada exported 74 Tera-watt hours (TWh), over 11% of domestic production, to the United States and imported 9 TWh. Trade in electricity with the United States is important in most provinces with most exports coming from Ontario and Quebec. The provinces of Saskatchewan and Alberta are net importers. There are far fewer east-west interconnections between the electricity transmission networks within Canada and, consequently, provinces and territories trade much less among themselves. This is largely a result of the large east-west distances between population centres in Canada (IEA, 2016).
Regulation of electricity markets varies widely across Canada. Most provinces and territories regulate wholesale electricity prices by a quasi-judicial board or commission. Exceptionally, Alberta has a competitive wholesale market. Ontario has a hybrid model of a partially open and partially regulated wholesale market and has announced a complementary capacity market. Ownership structures vary across the country although public (provincial or municipal) ownership predominates in most places – only Alberta, Nova Scotia and Prince Edward Island feature private ownership of their utility sector (IEA, 2016). The ownership structure may have been one reason why electricity generation has been at the centre of much emissions reduction in the past. Planning a coal phase-out in a sector dominated by public-owned vertically integrated companies, for example, may be easier to organise than under more competitive conditions. At the same time, however, Canada has plentiful renewable power resources, which offer good alternatives to fossil-based power generation.
4.1. GHG emissions
The shift in power generation from coal and oil products has led to a remarkable reduction in GHG emissions. Between 2000 and 2015, emissions from electricity production were reduced by 38% (48 Mt CO2eq), far more than any other sector. The sector’s share in total Canadian emissions declined from 17% to 7% in the same period (Figure 4.9). About two-thirds of these emissions come from coal-fired generation, followed by natural gas at 22% and refined petroleum at 6%. The absolute amounts of GHG emissions from diesel generators in the north are small compared with the rest of the country. Hence, Alberta, along with Saskatchewan, Nova Scotia and New Brunswick, account for most of Canada’s GHG emissions from electricity generation.
4.2. Current targets and policies
In the past, policy objectives have varied widely among the provinces and territories, partly in line with their relative endowments of fossil fuels and hydro resources. More recently, especially after the Vancouver Declaration on Clean Growth and Climate Change, they have started to converge. Proposed amendments to existing coal regulations will put Canada on a path towards 90% non-emitting generation by 2030, up from 80% in 2015. Electrification is expected to spread through the economy. In Canada’s long-term strategy, electricity demand is expected to at least double by 2050, and low-carbon sources are expected to meet most of the demand.
Phasing out coal
In 2012, the federal government published regulations limiting GHG emissions from regulated coal-fired generating plants to 420 tonnes of CO2eq per GWh of net electricity generated, close to what can be achieved by Canadian natural gas combined cycle units. These regulations apply only to new plants (commissioned on or after 1 July 2017) and plants at the end of their design life (originally defined by the legislation as 50 years); emissions from existing plants not in those categories are not restricted, so as to reduce the cost of stranded assets. The government of Canada, as part of the PCF, is accelerating this phase-out of “traditional” coal-fired generation (the government expects plants operating with carbon capture and storage to be able to satisfy the emission limit) by applying the regulation to all plants in 2030, regardless of whether they have reached their design life.
Equivalency agreements are possible where provincial regulation provides for similar emission reductions. For example, Nova Scotia has implemented a mandatory declining cap on GHG emissions from Nova Scotia Power Inc. It started at an average of 9.6 Mt over 2010-11 to 7.5 Mt by 2020 and to 4.5 Mt in 2030. In June 2014, the Nova Scotia government and the Canadian federal government finalised an equivalency agreement on existing coal-fired electricity regulations. This allowed the federal government to suspend the application of coal-fired electricity regulations in Nova Scotia. A similar agreement may be reached with Saskatchewan.
Alberta reportedly produces more coal pollution than all other Canadian provinces combined (Alberta Government, 2017). It plans to replace all coal generation by 2030 – one‐third by renewables and two-thirds by gas. This plan includes an Advisory Panel on Coal Communities to look for ways to ease the transition for workers and local economies affected by the rundown of mining and coal generation. It also provides for a coal phase-out facilitator to work with coal-fired electricity generators, the Alberta Electric System Operator and the government of Alberta to develop options for a phase-out by 2030 (Alberta Government, 2016).
Ontario’s coal phase-out was partly facilitated by the ownership structure. This allowed all costs to be internalised in the publicly-owned electricity utility; Ontario’s hydro capacity and its vicinity to Quebec’s large hydro reserves should also help to contain costs. Even so, there have been recent complaints that the phase-out, and the parallel introduction of subsidies for renewables, induced an increase in prices. But there were other reasons for higher prices, including deferred grid infrastructure investment and nuclear refurbishment. In any case, international comparisons show the increase was very small compared with the large gap between electricity prices across Canada and those in the rest of the OECD outside North America (Figure 4.10). Alberta’s fully market-oriented structure suggests that CO2 pricing could be used rather than the case-by-case negotiations with coal-fired generator operators (to compensate for potentially stranded assets associated with a phase-out of coal-fired generation by 2030) that appear to be being used. As part of the accelerated coal phase-out, the federal government has proposed a flexible approach that would address concerns surrounding stranded assets through two key policies: i) allowing the conversion of coal boilers to run on natural gas; and ii) establishing agreements equivalency with provinces.
The accelerated coal phase-out risks creating a new set of stranded assets in the form of new gas-fired plants. These are low-carbon by comparison with coal, but not compared with hydro and other renewable energy sources. They may not even be low-carbon compared with carbon capture and storage. The new gas-fired plants may therefore be obsolescent (because of the need to move to zero-carbon emissions) well before their design life is reached. This could mean both higher costs than intended and possibly higher GHG emissions, at least for a period. However, eliminating coal has other environmental benefits: coal combustion emits significant amounts of local air pollutants such as NOx, SOx and PM, which in turn cause smog and acid rain.
Carbon capture and storage
While some provinces are focusing on phasing out coal-fired power generation directly, Saskatchewan, a coal-rich province with few local alternative energy sources, invested in one of the world’s first commercial-scale carbon captures on a coal-fired generating station. The Boundary Dam project retrofitted an existing coal-fired electricity generator near the US border. The facility has been operational since the end of 2014. The project’s investment cost was about CAD 1.5 billion, about 6% of Saskatchewan’s annual total fixed investment. The federal government provided a grant for about one-fifth of the total cost with SaskPower, a provincially-owned power utility, providing the rest. SaskPower (which aims to have 50% renewable electricity by 2030), is the vertically integrated principal provider of electricity generation, transmission and distribution services in the province. This probably makes this kind of investment less vulnerable to commercial risk than it would be in a more competitive regime.
Carbon capture and storage (CCS) is potentially a useful technology, if it is a viable low-cost option for meeting short-term targets and allowing more time for development of low-cost zero-carbon technologies. Until recently, there have been almost no full-scale examples of the technology in use, making it difficult to estimate the cost of using this technology compared with existing renewables, for example. However, Canada is now host to two large-scale carbon capture, utilisation and storage facilities in two of the contexts where it might have most potential. One is the Boundary Dam facility in Saskatchewan in the power generation sector. The other is the Quest project in Alberta; this involves capturing CO2 emitted during the conversion of bitumen extracted from oil sands into higher grade oils and injecting the extracted CO2 into deep saline aquifers. Although both projects have been operating for over a year, publicly-available data do not, at the time of writing, permit calculation of parameters such as the GHG emission intensity of net electricity generated, or cost of operation, that could be compared with ex ante estimates (Box 4.2). Reliable data on the performance of Quest and the Boundary Dam project could be very useful, both in Canada and elsewhere. SaskPower and BHP Billiton of Australia have partnered to create the International CCS Knowledge Centre to advance carbon capture globally.
The Boundary Dam project retrofitted an existing coal-fired electricity generator with carbon capture. The captured CO2 is not stored, but rather sold to a commercial company for enhanced oil recovery. The design called for 90% of emissions to be captured. On these conditions, ex ante estimates suggested the break-even price of carbon for the project was CAD 57 per tonne (PBO, 2016). Under the current contract, the captured gas is sold at around CAD 25 per tonne. A CO2 price over CAD 32 (to be reached by 2020, according to the Pan Canadian Framework) would in theory make it viable. The main use for CO2 in Canada could be for enhanced oil recovery in older conventional oil fields. Canada is also supporting innovation associated with the transformation of captured CO2 into revenue- generating carbon-based products.
Without CCS, at a CO2 price of over CAD 32, cost considerations alone would imply replacing coal generation with gas; hydro would be cheaper and wind might well be as well (PBO, 2016). If CCS became widespread, it might be difficult to market all the captured gas. Therefore, the cost of transport to storage locations and storage itself would have to be added to the break-even carbon price. PBO (2016) quotes an estimate of CAD 2 per 250 km for a large capacity pipeline.
SaskPower has suggested that experience acquired with the first installation would bring down capital costs and reduce the breakeven point to CAD 47 for a second installation; costs could be even lower on a newly-built generating facility rather than a retrofit (Saskpower estimates that such savings could be between 35% and 40%). SaskPower publishes data on CO2 captured, but not its share of CO2 generated, of coal consumption or of other related costs.
Support for renewables
A wide array of policies give different kinds of support to renewables from the provinces and territories (Table 4.3). Key direct incentives have been provided for electricity generation, some of which have been scaled back, notably feed-in tariffs (FITs). Ontario, for example, introduced a FIT scheme in 2009. Revisions in 2012 included lowering the subsidy for wind and solar energy. The FIT applied to solar photovoltaic generation, for example, fell by around 50% over 2012-17. However, it rose for various kinds of biogas about 50%, while FITs for small waterpower nearly doubled. Support still varies widely among the different technologies, though the range has narrowed.6
4.3. Expanding electricity generation
More renewables are needed
Continued increases in demand for electricity can be expected. Even without the PCF, the National Energy Board (NEB) already projects an increase in electricity generation of 10% or more between 2015 and 2030, with gas supplying most of this increase. Achieving the PCF targets will imply increasing electrification of the economy as industry and households are encouraged to switch to low-carbon technologies. Much of this will have to be emission-free, either from hydropower or other renewables. In the NEB’s projections to 2040, made before the PCF was in place, the share of non-hydro renewables in capacity was projected to rise from about 10% to 16% (although its share in actual generation would be only 8%). Although hydro generation would increase by nearly 20%, its share in total generation would fall slightly. In this reference scenario, recent sharp increases in non-hydro renewables (notably in wind power) do not continue for long. This is because provinces, which have been active in promoting renewables, have phased out some of the stronger incentives.
Additional generation capacity required to meet future demand needs to be developed in ways that minimise environmental costs while ensuring reliable energy supplies across the country at reasonable cost. The cheapest solution in most cases and in most places, with current technology, might be to expand hydropower. For example, in 2013, Ontario paid nearly four times less to produce electricity with hydro than using gas. Hydro was also 60% cheaper than wind and 30% cheaper than nuclear. However, this does not take account of the full costs, both current and capital. Some of the physical capital required needs renewing and the current prices charged for hydro and nuclear energy are reported to be insufficient to finance renewal (PBO, 2016).
The US Energy Information Administration (EIA) has calculated estimates of the levelised cost of electricity generation for new installations in 2020 under various technologies. These estimates show hydro electricity as somewhat more costly than natural gas and coal (with pollution control technology, but no carbon price). But it also shows wind power to be competitive with natural gas (PBO, 2016). With the carbon price planned under the PCF, both hydro electricity and wind would thus be strongly competitive.
If the EIA calculations are correct, and broadly apply in Canada as well as the United States, it would seem there should be a lot of investment in either wind power or hydropower to help decarbonise the economy. This builds a strong case for phasing out direct support policies for renewables, and relying on pricing GHG emissions and other externalities of non‐renewable energy. This, in turn, would result in more cost-effective solutions, releasing resources (including administrative resources in both public administration and in energy suppliers) that could be used towards environmental goals where use of market mechanisms is more problematic. Provinces that nevertheless want additional programmes to encourage the use of renewables in electricity generation should avoid committing to any future level of subsidy in advance. Rather, potential suppliers can be invited to bid for subsidies for a certain amount of capacity and/or delivered electricity; California introduced such a mechanism in 2010.
The regulation of electricity prices and the publicly-owned nature of suppliers in many jurisdictions may make carbon pricing less effective as a GHG mitigation strategy than it otherwise might be. Regulators will have to decide how much of the carbon price is borne by consumers and how much by producers. Provided public ownership does not insulate electricity suppliers from the need to make satisfactory financial returns, they will have internal incentives to find least-cost solutions from competing technologies to the need to cut GHG emissions. Competition between alternative suppliers to wholesale markets, however, will not be part of that mechanism.
Improved inter-connections between the different Canadian electricity markets could increase competition, which would in turn accelerate the transition to low-carbon electricity. It could also potentially reduce overall electricity costs and increase resilience. But there is no formal co-operation between the provinces on transmission and resource planning. In fact, inter-provincial power trade would also face a number of practical difficulties. All provinces have one transmission system operator and there are no harmonised rules for inter-provincial electricity trade across Canada (IEA, 2016).
Wind and solar power require investment in storage or backup facilities to cope with the inherent variability of these sources. Canada’s extensive hydro-electricity generation capacity, with large reservoirs, puts it in a good position to manage variability of wind and solar power.7 Manitoba Hydro already exports hydro electricity to Minnesota and North Dakota in the United States to balance wind variability in these states. However, good sites for new hydro generation and wind will not always be found close to where the energy is needed. This will require substantial investment in long-distance high capacity transmission lines, including in better grid connection to allow for trade across provinces. Provinces such as Alberta and Saskatchewan, which have been self-sufficient in energy, may find themselves net importers of hydro. Wind and solar will require complementary investment in smart networks, switching, new storage technologies and in-demand management.
In addition, contract structures need to be re-thought to ensure that suppliers have the right incentives. A large share of capacity with low marginal cost, but high capital costs and intermittent availability, changes the economics of supply. The Alberta Electricity System Operator has reviewed the Alberta electricity market that sets out how to address these issues (Box 4.3).
Over the next 14 years, Alberta will close 18 coal-fired power stations. It will require up to an estimated CAD 25 billion of new investment in electricity generation to support the transition towards cleaner sources of energy and meet the electricity needs of a growing province. In response, the Alberta Electricity System Operator has reviewed the province’s electricity market to determine what market structure would best support this transition while maintaining reliability at reasonable cost.
Alberta has an energy-only electricity market where generators make bids to dispatch electricity into a “pool”. Lowest-cost generators are dispatched first; the more expensive ones are brought in as needed to handle higher demand. Generators are paid based on the price of the last generator dispatched. In such a market, investors rely on the volatility of the market to send price signals for new investment. Low prices can indicate an abundance of generation capacity, while high prices can indicate a tighter supply of generation. Investors create an outlook of future electricity prices under a range of conditions. These forecasts are critical inputs for determining whether to invest in new generation.
The review sought to understand how adding greater intermittent renewable generation (such as wind) would affect pool prices for electricity, as well as revenues available to support investment needed to ensure a reliable supply of electricity (i.e. new “firm generation”). Because operating costs of intermittent generation are low (i.e. wind and sun are free), this reduces the pool price for electricity. This, in turn, reduces revenue for competing generators, making them more reliant on higher prices at times when intermittent generation is producing less or not at all. The review found considerable uncertainty about whether sufficient investment in firm generation will occur in the future due to both reduced revenues available in the market and reduced interest in investing in energy-only markets where revenue is uncertain.
To address this, the Alberta Electricity System Operator has recommended transitioning from an energy-only market to a capacity market, a recommendation endorsed by the provincial government. A capacity market has two separate markets. In the first, generators compete to sell their electricity; in the second, generators compete for payments to keep generation capacity available to produce electricity when required. A capacity market solves the price impact problem created by intermittent renewable generation by giving value to the important attribute of supply certainty. This value, in the form of a capacity contract, helps offset the effect of increased levels of intermittent generation, depressing energy prices and reducing available revenue.
Encouraging energy saving
Smart networks can help short-term demand management. Notably, intermittent wind power can be partially matched to interruptible supply contracts (some electricity users are willing to pay less in return for having their supply interrupted at times of peak demand or drops in supply). An intelligent network can forecast drops in wind power, notify and switch out those customers. This may not save overall energy consumption, but it can reduce the overall capacity required.
Other forms of demand management are already used in Canada. For example, New Brunswick (2005, 2014) introduced regulations to promote energy efficiency, including specific targets for some sectors. Yukon (2009) issued targets for energy efficiency and GHG intensity in government buildings and operations; this included an objective of working towards becoming carbon neutral by 2020. Price is one key measure that – arguably – is not used. Especially in jurisdictions where generation and supply are publicly owned, the level of prices may be too low to generate the revenue needed for future investment. Increasing prices would be unpopular, but would both help to finance the necessary investment and limit the growth in demand. Conversely, maintaining too-low prices results in too much consumption and over-investment in capacity (because a public sector provider is obliged to install capacity to meet the inflated demand). This diverts resources from other uses and likely leads to additional public debt as well. Canada’s low energy prices are a key competitive advantage. However, they should be based on genuine resource availability, not under-pricing of externalities, implicit subsidies or skimping on infrastructure maintenance and investment. The PCF’s overarching strategy of establishing an economy-wide price for CO2 emissions is, in part, a recognition of this.
Policies such as labelling schemes, or encouragement for energy audits, can be useful in increasing sensitivity to prices and reductions in demand. An internal evaluation report of Natural Resources Canada’s Energy Efficiency Programs (covering 2009-14) appears very encouraging for current policy, notably labelling and information schemes (NRCan, 2015).8 There is increasing attention paid to ways in which it can be stimulated such as by appealing to people’s concern for what the neighbours think (Box 4.4). Information schemes, such as ENERGY STAR labelling, are not costly to run. Their continuance, aligned as far as possible with labelling in the United States, is a useful part of the PCF.9 Most of these schemes are part of Natural Resources Canada’s ecoENERGY Efficiency programme. This is a wide-ranging scheme, which also encourages and/or subsidises energy-saving investments (a number of which have been discontinued), especially in housing; it has evolved over the last decade.
Two Ontario power companies have recently implemented a billing scheme imitating a successful programme in the United States. In this initiative, home energy bills sent to customers compared their energy consumption with that of their immediate neighbours.
In the US trial, based on controlled randomisation, people did not react very much to information about their consumption relative to that of the overall population. However, they were quite sensitive to that of people in their neighbourhood (Allcott, 2011). Households who saw that in one period they had consumed well above average showed a distinct tendency to reduce their consumption in following periods. The overall effect was not large – a reduction of about 2% in consumption – but this was estimated to be equivalent to the short-run impact of an 11% rise in price. The study also found that households with comparatively low consumption tended to increase subsequent consumption. This effect was much reduced, however, by the addition of simple "smiley"-like signs to reinforce the idea that low consumption was a desirable achievement.
Another study looked at how time-of-use (TOU) pricing for electricity could be improved as an effective means to allocate electricity. Martin and River (2015) evaluates a large-scale field trial in which households facing TOU pricing were given an in-home display, providing real-time feedback on electricity consumption. Receipt of the device results in a 3% reduction in average electricity consumption. The reduction in demand is roughly constant throughout the day, concentrated in the fall and winter. It is sustained for at least five months following receipt of the device, with households becoming more (less) price sensitive in warmer (colder) months.
Further analysis of these and other such schemes, including whether the effects continue in the longer term, could help understand how best to combine pricing signals and “nudging” policies. Examples from many countries and in many different policy domains can be found in OECD (2017b). OECD (2017c) discusses the issues specific to environmental policies.
5. Mitigation in the transport sector
Canada’s vast landscape, which entails long distances between the main economic centres, combined with historically low fuel prices, means that transport is an important sector of the economy. Canada generates more road and rail freight transport (measured by tonne-kilometres) both per unit GDP and per capita than almost any other country in the OECD. Dispersed settlement patterns and low density urban structure make passenger transport a necessity rather than a luxury. Roads are by far the dominant mode for passenger transport. By contrast, a relatively small share of freight is transported via roads (Figure 4.11). As nearly all transport uses hydrocarbon fuels, GHG-intensity is high as well. Transport-related CO2 emissions, on a per capita basis, are the third highest in the OECD, after Luxembourg and the United States (IEA, 2017).
5.1. GHG emissions
Transport contributed 24%10 of Canada’s GHG emissions in 2015, similar to oil and gas extraction and more than twice as much as electricity generation (ECCC, 2017). Only Switzerland, Sweden, Slovenia, Austria and France, all countries with relatively low-emission electricity like Canada, have a higher share of emissions from transport.11 Since 2000, emissions from transport rose by 21 Mt CO2eq (or 14%), an increase nearly as large as that of the oil and gas industry. This increase was mostly driven by on-road freight transport (which increased by more than 40% over 2000-15). Emissions from on-road passenger transport, rail, domestic aviation and marine transport also increased between 2005 and 2015, albeit at a much slower rate (Figure 4.12). Government projections are that GHG emissions from the on‐road passenger transport sector are likely to decrease up to 2030 as a result of existing regulations and despite increases in distances travelled. Freight transport emissions, by contrast, are expected to continue increasing, exceeding passenger transport emissions in 2030 (ECCC, 2016).
Road transport accounts for almost three-quarters of the transport sector’s emissions. In Canada as a whole, about 60% of road emissions are from private passenger transport and 40% from light and heavy duty trucks and buses. However, this varies by province; in Alberta, for example, more than half of emissions are from freight. GHG emissions from road transport (including both passenger and freight) are about 17 times higher than those from railway traffic, domestic aviation, or lake and river transport – despite a relatively large role of rail for freight transport in Canada (Figures 4.11and 4.12). Heavy trucks alone emit six times as much as all railway traffic. The main potential for reducing emissions from transport is thus likely to be in reducing the GHG intensity of road transport and/or shifting substantial amounts of traffic away from road. A modal shift is likely to require substantial infrastructure investment. In 2013, public investment on transport infrastructure was nearly CAD 30 billion, about 10% of Canada’s total fixed investment; 80% was on roads (Transport Canada, 2016a).
GHG emissions from the rail sector have been rising much less than the raw increase in traffic: emissions increased by 8.5% over 2000-13 compared to an increase of 29% in tonne-kilometres transported (Transport Canada, 2011, 2016b). As for road traffic, no such reduction in GHG intensity has been seen for freight and not much for passengers. GHG emissions from road freight transportation increased by 37% between 2000-13, and passenger traffic by 5%. Over the same period, road freight traffic volume increased by 37%, and passengers-kilometres by 17%. As short journeys declined, compositional changes may explain part of the improvement in emissions from rail freight. However, it seems there has been a stronger underlying improvement in rail than in road.
A modal shift?
As GHG emissions per tonne-kilometre from rail are much lower than from road, a rising carbon price will induce some modal shifting. This could be accentuated if railways were electrified (diesel locomotives supply almost all motive power). However, Transport Canada focuses on a steady reduction in the emission intensity of diesel-powered rail transport. Because road transport is much more flexible than rail, the extent to which prices can induce a shift may not be very large. There is a substantial implicit subsidy to road compared with rail because the public sector provides most road infrastructure whereas rail users typically pay infrastructure costs as well. But rail is exempted from most fuel taxes (which, for road fuels, were originally conceived as a way to finance road infrastructure). Therefore, it is not clear whether roads are more subsidised than rail. Nevertheless, many arguments favour increasing the direct charge to road users to pay for infrastructure use. But although road-charging is gradually spreading in different parts of the world, it is rare in Canada; a recent attempt to introduce road pricing – the introduction of a toll on two urban highways by the Toronto municipality – was vetoed by the Ontario government.
Modal shifts can be difficult to achieve. In most cases, flexibility and low transhipment costs for final delivery are important considerations. Thus reducing the high energy intensity, and therefore the high emissions intensity, of transport in Canada will rely a lot on cutting emissions from road transport. This can happen through improved efficiency and restraining the demand for travel. Canadians are used to low fuel prices, low-density housing settlements and, in many places, little provision of public transport. All of these factors contribute to high energy use in private transport. Nevertheless, it is encouraging that distance travelled in private automobiles seems to have stabilised since 2000 despite continued growth in GDP. But the possible contribution of a modal shift should not be overlooked.
Investment in rail infrastructure that could increase its share of traffic should be subject to cost-benefit analysis using an implicit price for carbon that should be quite high, given the long-lasting nature of such investment and its road-based alternatives. A cost-benefit analysis of a possible high-speed rail link in the Quebec City–Windsor corridor showed the project was economically infeasible, with an imputed cost for CO2 emissions of CAD 40 per tonne (Transport Canada, 2016c). Over the lifetime of the project, the minimum price will be at least CAD 50 and possibly much higher. Therefore, a higher imputed cost of CO2 emissions would be logical and might deliver a different verdict on the electrically-powered option. It is encouraging that such projects undergo this kind of cost-benefit analysis, provided the environmental costs and benefits are fully taken into account.
5.2. Policies to reduce emissions in road transport
Reducing GHG emissions in road transport can be done in two broad ways: reducing distance travelled per vehicle and reducing emissions per distance travelled. In turn, these can be split into two methods: reducing distance travelled by cutting transport demand or by shifting to mass transit; and reducing emission per distance travelled by reducing emissions per vehicle or (again) by switching to mass transit. Though a modal shift may help, most GHG reduction in transport needs to come from reduced emission intensity within the different modes.
In some cases, the impact of policies on total GHG emissions is not obvious, as intermediate objectives are affected in opposite directions. For example, subsidies for public transport, or for fuel- efficient vehicles, do induce a switch towards lower emissions for any given distance travelled. However, they also reduce the costs of transport and so potentially increase overall travel, other things being equal. It is unlikely, but possible, that overall emissions could thereby increase, especially if public transport provision is inefficient or not very low emission. If policies are not co-ordinated, increases in overall traffic can potentially worsen environmental or other external costs of transport, even if GHG emissions fall.
Federal road transport policies
Fuel taxation is one of the most obvious measures to improve fuel economy. Taxes are levied at both the federal and provincial levels. Federal fuel taxes are among the lowest in the OECD, though higher than in the United States; provincial taxes are typically higher (see Chapter 3). In most jurisdictions, the tax on diesel fuel used in railway locomotives and other railway equipment is only one-third the level of the combined standard rate, as most provinces and territories levy much lower rates than on fuel for road use. Aviation fuel, too, is taxed at a much lower rate than road fuel, although the rate has almost doubled over 2014-17. The inclusion of transport fuel in Quebec’s cap-and-trade system increases its effective rate.
The most important transport-specific mitigation measures in place are regulations on light-duty and heavy-duty vehicles. There are separate regulations for off-road and on-road vehicles. For light-duty vehicles, Canada’s regulations are the same as in the United States and Mexico. They set GHG/fuel economy target values12 based on vehicle footprint, calculated as wheelbase multiplied by average track width. The overall standard for a specific manufacturer is determined by averaging the targets for the footprints of all vehicles produced by the manufacturer. They were introduced in Canada in 2010 to cover model years from 2011 onwards. However, even before this date, US standards strongly influenced developments in Canada because of the integrated automobile market in North America. In 2016, the average light-duty vehicle sold should have had GHG emissions intensity of 135 g/km7. By 2025, average emissions per kilometre for light vehicles are intended to be 98 g/km; this will be 50% less than in 2008 (compared with a reduction of 23% for heavy-duty on-road vehicles). For heavy-duty vehicles in Canada and the United States, smaller vehicles are subject to a fleet average footprint based standard, while larger heavy-duty vehicles and engines are subject to conventional standards (not footprint based).
The regulations are quite complicated. For light-duty vehicles, there are different formulas used to calculate the GHG emission target value for a vehicle. For each car or light truck, the target value is then determined by the vehicles’ footprint on the road. The standards also include features to give incentives for innovation. For example, zero emission light duty vehicles (electric and fuel cell) and very low emission vehicles (plug-in hybrids, natural-gas fuelled) have a higher weight in the average. For example, an electric light duty vehicle sold in 2017 counts for 2.5 vehicles. However, recognising the risks of excessive costs, this advantage will be phased out over time (the multiplier is to be reduced to 1.5 by 2022). Additional allowances are available for “innovative technologies”. Smaller heavy-duty vehicles follow a similar methodology to establish target values based on the vehicle’s footprint and weight class.13
In private road transport, vehicle emission standards appear to have been effective in improving fuel economy and reducing emissions for each type of vehicle. However, these effects have been partly undermined by purchasers shifting towards increased use of light trucks (pickups, minivans and sport utility vehicles) within the “light-duty vehicle” class at the expense of cars (Table 4.4). This switch towards light trucks in itself is not the main reason for the increasing emissions from road traffic. On its own, it would have increased GHG emissions by about 10% between 1990 and 2014. The combined effects of improved fuel efficiency within each class of vehicle, and better emissions control, would have more than offset the increased emissions. The chief culprit is the increased number of vehicles (itself only partly offset by a fall in the distance travelled per vehicle) (Figure 4.13). These adverse trends were more moderate in the period after 2005, allowing a small fall in overall light vehicle emissions.
The GHG emission regulations are reinforced by fuel economy information programmes, notably the EnerGuide Label for Vehicles and the Fuel Consumption Guide. EnerGuide labels are similar to electrical appliance labelling. They give information on average fuel consumption and typical expenditure on fuel, showing how the vehicle compares with the range available on the market. The Fuel Consumption Guide is an online service for checking the average fuel consumption of any make and model of automobile.
For heavy goods vehicles, the objectives in emission reductions are apparently less ambitious than for light vehicles. This is perhaps because truck fleet operators already have strong commercial incentives to keep fuel consumption down. Nevertheless, some evidence suggests that gains in fuel efficiency forced by the US CAFE standards for light vehicles are transferable at least to the lighter end of the freight vehicle fleets; thus, they could perhaps be more ambitious (Lutsey, 2015). There are, however, training programmes for commercial truck drivers that can show driving styles that are more fuel efficient. Canada adopted the US SmartWay Program in 2012, which is a public private partnership to help businesses reduce fuel use while transporting goods in the cleanest, most efficient way possible. In 2017, the programme was expanded to Mexico to ensure a continental approach to greening freight by sharing best practices and benchmarking the energy used in the movement of goods across North America.
In addition to vehicle-focused policies, Canada has also had, since 2010, an “alternative fuels” programme. Under this programme, at least 5% of gasoline and 2% of diesel or heating oil should be from renewable fuels. This largely means ethanol, much of which is imported. Biofuel usage has increased over the past decade, thanks to the federal alternative fuels regulation. Production subsidies through the ecoENERGY for Biofuels programme for biofuel producers have also helped increase usage (IEA, 2016).
The government plans to modify these regulations into a “clean fuel standard”, which would take more care to look at the “life-cycle” of GHG emissions. Current requirements could be satisfied in principle by using ethanol whose production and transport to Canada may have emitted more GHGs than the fossil fuel it replaces.
Some provinces run programmes to encourage electric vehicle (EV) purchases. Quebec, for example, intends to have 100 000 electric vehicles and plug-in hybrids on its roads by 2020. It subsidises the purchase of EVs with up to CAD 8 000 (roughly 20% of average purchasing prices). It also subsidises the purchase and installation of charging stations, both at home and at work. The subsidy is financed through the Green Fund, whose revenue derives mainly from the carbon market. Ontario and British Columbia have similar programmes, with subsidies of up to CAD 14 000 and CAD 5 000, respectively, for the purchase of EVs. Some provinces use additional incentives, such as allowing EVs to use high-occupancy vehicle or toll lanes (Plug’n Drive, 2017).
Most provinces have programmes seeking to improve public transportation. These include Alberta’s GreenTRiP programme and Ontario’s The Big Move: Transforming Transportation in the Greater Toronto and Hamilton Area. The Ontario programme aims at a long-term sustainable transportation plan for one of Canada’s largest urban areas, increasing the use of transit and cycling in the region.
Land use, urban planning and smart cities
Urban transport policy is challenging in Canada, given the low population density in most cities (Figure 4.14). Little attention has been given to fuel use or climate change issues in planning urban development in Canada, yet interest in better planning is growing. “Transit Oriented Developments” emphasise high density planning in close proximity to transit stations, transit priority measures within the community and rapid transit routes to employment centres. According to the Victoria Transport Policy Institute, residents in these developments tend to own 15% to 30% fewer vehicles, drive 20% to 40% fewer annual kilometres and rely more on walking, cycling and public transit than they would in automobile-dependent communities (CUTA, 2016; VTPI, 2017).
An apparently mundane, but in fact quite significant aspect of urban planning, is parking policy. It can have an important influence on both use and ownership of automobiles, especially when integrated with policy on public transport. A number of Canadian cities are trying different approaches to make parking policy more consistent with urban policy goals (Box 4.5).
In many Canadian cities, as with most cities in North America, parking policy has been structured largely around promoting increases in parking supply to meet projected demand. To that end, new developments are often required to include a minimum number of parking spaces per dwelling unit or office space, for example. However, such minimum parking requirements subsidise car use at the expense of other transportation modes, reducing urban density, increasing construction costs and promoting increased driving. Moreover, street parking is often unpriced, even in very dense neighbourhoods with limited available parking. The resulting scarcity of free spaces can lead to extensive “cruising” for parking spaces. This has been shown to cause a significant percentage of the traffic in many congested urban neighbourhoods (Shoup, 1999; Litman, 2016).
A number of Canadian cities are reforming parking policy to make it more consistent with municipal goals beyond parking supply. For instance, the Borough of Saint-Laurent in the city of Montreal put new parking regulations into effect in 2010. Among other goals, they aimed to reduce heat islands and other environmental impacts caused by parking areas. The new regulations favoured public transit, as well as walking and biking, and promoted urban density (Borough of Saint-Laurent, 2011). They significantly reduced the number of spaces required for specific uses. For the first time, the borough capped the number of allowed spaces per property at 150% of the maximum. Perhaps most importantly, the new regulations adapted parking requirements to individual neighbourhood conditions. Specifically, they reduced the number of required spaces by 40% in the densely-populated Vieux-Saint-Laurent neighbourhood, and by 20% in areas close to existing commuter train stations and projected metro stations.
More recently, Montreal has adopted a city-wide parking policy that includes many elements of Saint-Laurent’s regulation, and that seeks to free up land devoted to parking for other uses. This policy also promotes approaches that allow for “pooling” of parking required in a neighbourhood, rather than requiring each development to have its own dedicated parking spots. It encourages the deployment of technology to maximise access to existing parking as an alternative to increasing supply. For instance, electronic signage can indicate where parking spaces are available. Moreover, the policy calls for reforming the price of street parking to better reflect variations in demand by block and by hour of day. This would allow the city to better manage demand and encourage rotation of vehicles in shopping areas (Montreal, 2016).
A few Canadian cities have taken further steps, actually eliminating minimum parking requirements for developments in specified areas. For instance, Halifax in Nova Scotia, St. Catharines and Oakville in Ontario, and High River in Alberta removed all parking minimums in their downtowns. Calgary, Alberta removed parking minimums for non-residential developments in the Beltline neighbourhood, adjacent to downtown (Jaffe, 2015).
In an interesting step, Canada has introduced a programme similar to the US Smart Cities competition. Cities across Canada would be invited to develop Smart Cities Plans together with local government, citizens, businesses and civil society. Participants will create ambitious plans to improve the quality of life for urban residents through better city planning and implementation of clean, digitally connected technology, including greener buildings, smart roads and energy systems, and advanced digital connectivity for homes and businesses.14
Appropriate public transport investment is an important part of good planning and smart cities. The central government, along with provinces and territories, plans to increase their activity in this area. Public transport per se may not have much impact on GHG emissions if, for example, subsidies allow it to run with too-low occupancy. Public transport may be attractive for some uses, but without competing with private cars in key cases. Canada’s tax treatment of company cars (see Chapter 3) is an example of good practice. Many – indeed, most – countries undermine provision of public transport by subsidising commuting in company cars at the same time.
Car sharing and pooling can also reduce GHG emissions and congestion, and in low density areas may be more cost effective than public transport. Regulations can inadvertently inhibit such arrangements. In 2009, for example, Ontario had to amend its public transport regulations after a bus company successfully sued a car-sharing application company.
5.3. Rail, air and maritime transport
In non-road transport – rail, water and air – Canada has eschewed a strong regulatory approach in favour of working for self-regulation by the industries themselves. Often this takes place in co-operation with the United States, which is the origin or destination of many journeys, especially rail freight. Compared with private road transport, the key actors in these sectors are profit-oriented, commercial, sometime state-owned, companies rather than private individuals. In the larger transport industries (e.g. the airline industry and the two largest rail carriers), Transport Canada estimates that the share of fuel in total variable costs was between 21-26% between 2010 and 2013, similar to the share of labour costs. Saving 10% on fuel costs may increase profits by a similar percentage.15 Such high visibility of the impact of fuel price on income gives a strong incentive to improve fuel efficiency, independent of government action.
Because road transport has been the main driver of both the level and growth of transport emissions, this section has concentrated more on road than other modes. For climate change policy to be as efficient as possible, different modes must have equivalent incentives to mitigate their GHG emissions (and other externalities). This is a difficult task. For example, there is a huge difference between emissions per tonne-kilometre of freight by road compared with rail. This suggests that policies to switch freight from road to rail could generate big savings. However, the detailed economics of rail freight compared with road are lost in the aggregate averages; to make that a definite objective might be excessively costly.
As emphasised above, and in the Pan-Canadian framework itself, carbon pricing can be a key co-ordinating element where market-based competition can operate. This implies ensuring that all transport sectors face the same tax on implied GHG fuel emissions. However, for competition to work properly, other costs should also be properly reflected in prices. As mentioned earlier, road transport escapes all direct charging for road infrastructure, while rail transport pays for it, which looks like a subsidy to road. However, rail operators pay lower provincial/territorial fuel taxes than road, which looks like an implicit subsidy as well. Unless and until road charging becomes feasible, such differential treatment could actually balance out. Calculating taxation levels under the assumption that both modes paid the same tax on GHG and other externalities would add transparency. Taxation levels should broadly offset the different treatment of infrastructure and give similar incentives to reduce GHG emissions.
Where market mechanisms cannot easily operate, carbon pricing can help. For example, it could be part of the mechanism for evaluating potential infrastructure investments that compete for financial support from the recently established Low Carbon Economy Fund.
Rail transport
Since 1995, the Railway Association of Canada and Transport Canada have been working together to reduce the emission of GHGs and local air pollutants from locomotives through a series of voluntary agreements. The most recent agreement, signed in 2013, sets targets to reduce the intensity of GHG emissions compared to a 2010 baseline. It encourages member railways to conform to the US Environmental Protection Agency’s locomotive emission standards until Canadian regulations to control criteria air contaminants emissions are introduced.16 Under the joint Canada-US Regulatory Cooperation Council, Transport Canada and the US Environmental Protection Agency have agreed to co-ordinate their regulatory agendas, to jointly develop new requirements, and share research and compliance data and information to enhance understanding of new technologies to reduce GHG emissions in the rail industry.
Since 1990, energy efficiency in rail has improved substantially. In freight operations, fuel consumption per revenue tonne-kilometre fell by 47% between 1990 and 2014 – more than private road transport. Over the same period, the real price of rail fuel rose by around 50%. Recent data show this continuing: GHG intensity fell 12% between 2010 and 2014, ahead of the voluntary target for 2015. This is happening at the same time as rail switches to ultra-low sulphur diesel fuel. This move drastically reduces its SOx emissions; the sulphur content of rail fuel fell about 98% between 2006 and 2014 (RAC, 2017).
Marine transport
The marine transport sector industry contributes about 2% of total transport emissions (Figure 4.12). Tax treatment varies as marine fuel is subject to the federal diesel excise tax, but exempted by most provinces from their excise product-specific taxes on fuels. It is, however, subject to British Columbia’s carbon tax. In 2012, Transport Canada and the industry environmental certification programme Green Marine signed a Memorandum of Co-operation, which is the main voluntary agreement in the maritime transport sector.
Green Marine runs an audited self-evaluation programme in which ship operators, port authorities and port installation operators agree to rank their performance on a number of environmental dimensions such as GHG emissions. Other dimensions include, for example, emissions of other air pollutants, treatment of dirty oil, garbage management and energy efficiency. Companies evaluate themselves according to guidelines issued by the association. The self-evaluation has to be audited within two years by an expert chosen and paid by the company under evaluation, but approved by Green Marine. Audited evaluations are published annually, and compared with the achievements of other participants in similar categories, which is an incentive to achieve good performance.
Air transport
The airline industry’s voluntary agreement between the federal government and aviation stakeholders dates to the publication of Canada’s Action Plan to Reduce Greenhouse Gas Emissions from Aviation in 2012. This initiative responded to the request of the International Civil Aviation Organization for Member States to submit action plans detailing specific measures to address GHG emissions. The action plan includes an aspirational target to reduce GHG emissions per revenue tonne kilometre by 2% annually from 2005 to 2020. It also targets a reduction of 1.5% per year from 2008 to 2020. The average annual reduction from 2005 to 2015 was below the target (about 1.2% per year). It has been about 1.4% per year since 2008 (GoC, 2016d).
In addition to the obvious commercial incentive for individual operators to reduce fuels costs, the measures being pursued include more efficient air operations, including air traffic management. In the future, the parties expect improvements from measures including aviation environmental research and development, alternative fuels, airport ground operations and infrastructure use.
Recommendations on general climate change policy
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Develop an institutional mechanism for monitoring and evaluating the implementation of climate change policy under the PCF and their contribution to meeting GHG emission targets; consider introducing mechanisms for adjusting policies over time in order to meet policy goals. One possibility is to give responsibility to the Office of the Auditor General of Canada, in collaboration with provincial audit offices.
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Implement carbon pricing in all jurisdictions; ensure that exemptions or other measures to smooth the transition for businesses are temporary and limited to emissions-intensive trade-exposed industries with limited effective abatement options; work towards increasing the share of emissions covered by a carbon price and plan for progressive tightening; identify and address interactions of carbon pricing and complementary regulations, both at the federal and provincial/territorial level.
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Promote co-ordination of sub-national climate policies and schemes and encourage linking between sub-national pricing systems, even if only at the sector level; consider the introduction of an inter-jurisdiction offset scheme to help meet nation-wide targets more efficiently. Such work could provide a foundation for a possible future transition to a full national cap-and-trade or carbon taxation system.
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Ensure that energy policy is aligned with climate change policy and other environmental goals, including with respect to future energy supplies (especially the role of renewables), grid interconnections across Canada, and demand management through pricing and energy efficiency standards; swiftly implement available energy efficiency measures and phase out fossil fuel subsidies; tighten the target and implement regulation to reduce methane emissions from energy production without further postponement, possibly aligning regulation to the tightest of regulations already in place in some US states, and improve monitoring and enforcement.
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Encourage use of the implied GHG price time path as a shadow price in policy and project evaluations, throughout government and public agencies.
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Design public education and information campaigns to enhance transparency and gain acceptance of policies and promote public support; monitor the impact of climate policy on vulnerable groups of society, ensuring that general policies for income support and welfare are well adapted to the possible impacts of climate change policies on income and employment, and that they cover all sections of the population including Indigenous peoples.
Recommendations on electricity generation
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Prioritise the elimination of fossil fuels while tapping into Canada’s vast renewable energy potential; review and adjust specific support schemes for renewable energy to the trends in technology cost and carbon pricing. Where incentives beyond carbon pricing are needed, use market-based mechanisms such as reverse auctions for capacity to look for low-cost solutions.
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Ensure electricity pricing reflects full economic and environmental costs; complement pricing with information programmes like Energy Star, experimenting with other “nudging” measures to help consumers make effective use of information.
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Encourage the sharing of best practice of leading carbon capture projects across Canada based on assessments of cost and performance, including the facility at Boundary Dam in the power segment; follow through on inter-jurisdictional consultation to expand grid inter-connections to make better use of the potential for hydro storage to complement the increased variability of growing generating capacity for renewable energy.
Recommendations on transport
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Continue to drive the decarbonisation of transport by ensuring that environmental externalities from fossil fuel use are adequately priced, either through carbon pricing schemes or direct fuel taxation; encourage the increased use of renewable fuels, electrification of transport, use of natural gas, and mode switching, including by additional vehicle and fuel taxation measures, as well as regulation.
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Continue to promote the provision of information on vehicle fuel economy and GHG emissions, including by making the EnerGuide labelling system obligatory; ensure the labelling is based on independently verified information, and laboratory testing benchmarks are monitored to ensure they are representative of performance under real-life driving conditions.
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Promote road charging, congestion charging, parking policy and other measures that both reduce the use of private transport and associated GHG emissions, and other environmental externalities; build on the Smart Cities programme to highlight and disseminate good or innovative practices; design land use and spatial planning policies to enable future low-carbon cities.
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Continue to enable the deployment of charging and refuelling infrastructure for low- or zero-emission vehicles, including by sharing information and lessons learned from pioneering municipalities, provinces and federal programmes to accelerate learning; and encourage standardisation and technology-neutral facilities to the extent possible.
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Benchmark and reduce energy use in the freight sector; encourage modal shifts in the freight sector, such as increasing the use of rail or water transport in place of long-distance heavy trucks; and encourage the development of associated infrastructure, but with appropriate cost-benefit analysis as a condition attached to public financing.
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Notes
← 1. If the price were, say, CAD 80 per tonne of CO2, such purchases would cost around 0.2% of Canada’s 2015 GDP.
← 2. Mining, Smelting and Refining (Non Ferrous Metals), Pulp and Paper, Iron and Steel, Cement, Lime & Gypsum, Chemicals & Fertilisers.
← 3. The Specified Gas Emitters Regulation required facility-specific reductions in emissions intensity by 12% in 2015, compared with a 2003-05 baseline, declining by 8% over the following two years (except for industrial process emissions in non-energy sectors). This regulation includes a system of offsets whereby verified emission reductions elsewhere can count towards compliance, as well as crediting for capture and storage. The price for excess emissions was initially set at CAD 15. In 2015, it was announced it would rise to CAD 20 in 2016 and CAD 30 in 2017.
← 4. Most inventory data come from assumptions on emission rates based on benchmarks for different technologies employed.
← 5. Descriptive material in this section relies to a considerable extent on IEA (2016), with supplementary material from the Canadian authorities.
← 6. Taking the Ontario example again, the 2017 subsidy per kWh varies from CAD 0.125 (onshore wind) to CAD 0.311 (small rooftop photovoltaic). In 2012, the subsidy ranged from CAD 0.103 (landfill gas) to CAD 0.311 (small rooftop photovoltaic). This compares with an average recommended retail price of CAD 0.08 in 2012 and CAD 0.95 in May 2017 (Ontario Energy Board, 2017).
← 7. Quebec authorities estimated that its hydro generation capacity could be doubled – i.e. more than enough to replace all of Canada’s current coal and gas-generated electricity – without excessive loss of natural habitats.
← 8. It should be noted, however, that the evaluation report is almost entirely based on interviews with clients or suppliers of the programmes, along with evidence from secondary literature. It is not supplemented with any statistical analysis to assess the impact of the programmes against a counterfactual. This is very difficult to do, but it can perhaps be made easier if measures – at least some of them – are designed with such an evaluation in mind. Neither does the evaluation assess the relative cost-effectiveness of the different sub-programmes (see also Box 4.1). This is also a difficult task, but would be valuable and important information.
← 9. For a summary of the economic literature on the extent to which US consumers make “mistakes” in ignoring price information, see Allcott (2016). He notes, for example, that regulations on phasing out incandescent light bulbs address a real ignorance of the economic benefits of switching. On the other hand, consumer responsiveness to fuel economy in cars is very high. Allcott (2013) shows that, on average, consumers correctly estimate or perhaps slightly underestimate the financial benefits of higher fuel economy vehicles. This suggests that CAFE type standards become less important if externalities are adequately included in diesel and gasoline prices.
← 10. Including transport services internal to other industries. Excluding such services, the share is 23%. Mostfreight transport data in this chapter cover only freight transported by commercial carriers, thus excluding own-use of transport in some industries.
← 11. Data limitations prevent a consistent accounting of emissions from transport that would derive overall emissions from volumes of different kinds of transport, the energy efficiency of each kind of transport and the emissions from each kind of energy. For Canada, some data are not measured directly, but rather by proxies for some of these underlying variables. For example, fuel use by passenger cars is calculated from assumptions about typical distance travelled and fuel economy derived from US surveys. Comparisons between Canada and other countries in this section are therefore subject to possible errors due to using indicators from data sources that might not be fully consistent.
← 12. Specifying the regulation in terms of GHG emissions eliminates any need for separate standards according to fuel type.
← 13. Medium and large heavy-duty vehicles have their target values determined based on vehicle characteristics such as weight, roof height and primary function (tractors or vocational vehicles). Performance for these medium and large heavy-duty vehicles is assessed through the use of a simulation model based on vehicle characteristics. Medium and large heavy-duty engines have output-based performance standards that are assessed through engine dynamometer testing.
← 14. In the United States, the city of Columbus, Ohio, won the competition with a “comprehensive, integrated plan addressing challenges in residential, commercial, freight, and downtown districts using a number of new technologies, including connected infrastructure, electric vehicle charging infrastructure, an integrated data platform, autonomousvehicles, and more. Columbus plans to work closely with residents, community and business leaders, and technical experts to implement their plan.” See www.transportation.gov/smartcity/winner.
← 15. For instance, when the average price of diesel for rail use fell 30% in 2015, the railway company Canadian Pacific saw a drop in fuel costs equivalent to one-quarter of its net income for 2014 (Transport Canada, 2016b; Canadian Pacific, 2017). Air Canada’s fuel costs in 2015 and 2016 were similar to the wage bill, in each case around one-fifth of total operating expenses (Air Canada, 2017).
← 16. These include SOx, NOx, volatile organic compounds, carbon monoxide, ammonia, ground level ozone and particulate matter.