The federal government unveiled Turning the Corner: An Action Plan to Reduce Greenhouse Gases and Air Pollution on April 26, 2007. The legislative details of this action plan are contained in the government's Regulatory Framework for Air Emissions (the Regulatory Framework), which outlines the actions that the federal government intends to take to regulate greenhouse gas (GHG) emissions and air pollution. The bulk of the plan deals with regulating industrial emissions; however it also proposes actions for transportation sources, consumer and commercial products and indoor air quality. The following sets out our thoughts based on the preliminary policy document released by the government and it should be recognized that there is uncertainty in the application of the words and there is relative certainty that there will be changes as the regulations unfold.
The Regulatory Framework states that "[t]he federal government will set stringent national standards and will work to reach equivalency agreements with those provinces that set provincial emissions standards that are at least as stringent as the federal standards", thus raising the possibility of a single regulator for some or all of Canada. However, reaching equivalency agreements will present considerable challenges as a result of different baselines, the use of intensity targets versus absolute caps, and varying compliance mechanisms. This may be compounded by differing scopes and definitions of the regulated entities, including thresholds for coverage, units of production, regulated and non-regulated activities and other fundamentals, as well as potentially diverse approaches to quantification, reporting, verification and enforcement. Given the federal government's emphasis on co-benefits for Canadian air quality in its approach to GHGs, there is also the question of whether the government will assess rules for GHGs and air pollutants separately or in an integrated fashion (for example, a provincial regime that allows greater use of out of jurisdiction credits might imply fewer co-benefits for Canadian air quality).
Nonetheless, the Regulatory Framework indicates a willingness to work with the provinces and territories as the regulations are developed. If regulations can be developed and completed at both levels contemporaneously, the federal regulations may never take effect in some or all Canadian jurisdictions. However, the use of equivalency agreements has historically been rare and a variety of factors seem to make a change in this regard increasingly unlikely. For example, provisions in the government's Clean Air Act amending the Canadian Environmental Protection Act, 1999 to facilitate the greater use of these agreements appear to have less chance of becoming law in this Parliament, provincial laws and policies appear to be increasingly unlikely to permit equivalency agreements and the possibility of one or more constitutional challenges has been mentioned by some who are close to provincial politicians.
The government intends to regulate industrial GHG emissions by establishing mandatory emissions reduction requirements on a sector basis. The sectors are: electricity from combustion; oil and gas (including upstream and downstream production, as well as oil sands and pipelines); forest products; smelting and refining; iron and steel; iron ore pelletizing and potash mining; cement and lime; and chemicals, including fertilizers.
The regulation is to cover all GHGs in the Kyoto Protocol, which are carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs) and sulphur hexafluoride (SF6). For regulatory reporting purposes, GHGs are to be expressed in terms of tonnes of carbon dioxide equivalent (CO2e). GHG emissions are denominated this way because different GHGs have different global warming potentials (GWPs). For example, one tonne of N2O (a fertilizer related chemical) has a GWP of 310, while SF6 has a GWP of 23,000 and methane (the primary constituent of natural gas and landfill gas and a by-product of decomposition of biomass) has a GWP of 21. The CO2e denomination enables the proper evaluation of reductions of emissions of different GHGs in relation to each other.
The Regulatory Framework proposes to require mandatory GHG emissions reductions through the use of emission intensity targets. Emission intensity ties emissions reduction targets to production, meaning that facilities would be required to reduce GHG emissions per unit of production relative to a baseline. According to the Regulatory Framework, the intensity targets are ambitious enough to produce absolute reductions in GHGs from present levels as early as 2010 and no later than 2012, even if the economy grows as expected. An absolute target would be set for 2020 of 20% below 2006 levels. Draft GHG regulations are expected "starting" in the spring of 2008.
For "existing facilities" (i.e. facilities operating as of 2003 or earlier), the baseline is the facility's GHG emission intensity in 2006. For "new facilities" (i.e. facilities whose first year of operation is 2004 or later), the baseline will be the facility's GHG emission intensity of its third year of operations, but the intensity reduction requirements will be "based on cleaner fuel standards", which may require an adjustment of the baseline. The adoption of these baselines are controversial as they permit growth in emission intensities for a number of years after Canada agreed to the Kyoto Protocol and a year after Canada ratified the Kyoto Protocol (but earlier baselines would need to cope with the absence of comprehensive, reliable emissions and production data).
For existing facilities, the regulations will come into force in 2010. The required reduction in GHG emission intensity will be 18% from the 2006 baseline by 2010 and 2% more from the 2006 baseline for each year of operation thereafter until at least 2020. This means that a 26% intensity improvement will be required by the start of 2015.
For new facilities, the first year of enforceable requirement would be the later of either 2010 or its fourth year of operations. For the first three years of operations, no reductions would be expected. In the fourth year, the initial target will be based on intensity in the third year of operations, but as mentioned above, that target will also be subject to the application of a "cleaner fuel standard" which may impose an adjustment to the baseline (presumably this involves the notional substitution in baseline calculations of readily available and competitive low GHG-emitting fuels such as natural gas for high GHGemitting such as coal and oil). After the initial target is set, a continuous improvement requirement of 2% will be imposed for each year.
Two examples may assist although they are based upon an interpretation of the Regulatory Framework and cannot be relied upon to be precisely correct. For a facility that begins operations in 2005, no improvements will be required during 2005, 2006 or 2007. It will be expected to make improvements as of 2008 ("accrue a target"), based on its emissions intensity in 2007 and the application of a "cleaner fuel standard". Its target will become enforceable in 2010 and will reflect the expectations for improvement accruing since 2008. Continuous improvement of 2% would apply as of 2009. For a facility that commences operations in 2008, no improvements will be expected over 2008, 2009 or 2010, but it will be expected to make improvements as of 2011, based on its 2010 intensity and the application of a "cleaner fuel standard", and the targets will also be enforceable as of 2011, with continuous improvement required in 2012 and each year thereafter.
The phrase "cleaner fuel standard" is not explained. It may suggest that the standard will discourage the use of higher carbon content fuels: as indicated above, new oil sands facilities considering the use of petroleum coke rather than natural gas to separate bitumen from its surrounding materials is an obvious example. However, the Regulatory Framework chose to use a general phrase for this standard, rather than naming a cleaner fuel such as natural gas. The Regulatory Framework also states that a "flexible approach" to implementation will be taken where the equipment used in a plant facilitates carbon capture and storage ("CCS"), or another technology with significant and imminent potential for emissions reductions is used. This may suggest that the "cleaner fuel standard" will accommodate heavier fuel use when combined with CCS or any comparable technologies.
While historically, reporting requirements have not applied to facilities that emit under 100,000 tonnes of CO2e per year, there is no indication in the Regulatory Framework that such facilities will be excluded from regulation.
"Fixed process emissions" are excluded from the emission intensity reduction targets. These are emissions "that are tied to production and for which there is no alternative technology that will reduce them". Thus, the only way to reduce them is to reduce production. For example, in order to produce cement and lime, limestone is heated and CO2 in the limestone is released. This type of CO2 emission would be a "fixed process emission", whereas the combustion of fuel used in the cement production process would not. In addition, if modern technology can eliminate an emission, it is not a fixed process emission and therefore would not be excluded from the emission reduction targets.
Fixed process emissions will be excluded until it is shown that technologies or processes have been developed that could reduce or capture and store these emissions. One implication is that sector-specific emission intensity targets will be less than 18% in the aggregate, depending upon the proportion of fixed process emissions in each sector.
The federal government's plan does not give any guidance on the appropriate units of production to be used in determining emission intensity. The example used in the Regulatory Framework is a "widget facility", with the intensity calculation being the GHG emissions per widget produced. Comparisons between various products produced at different facilities and between time periods at the same facility will be challenging.
The government will issue a notice under Section 71 of the Canadian Environmental Protection Act, 1999 to require reporting of GHG emissions from 2006 by the industry sectors to be regulated.
A reporting notice under Section 46(1) was also issued last year for GHGs from facilities emitting over 100kts of CO2e in 2006 (similar notices have been issued since 2004). A key point of difference between Sections 46 and 71 is that the latter does not include any authority for the government to require the retention of records used in reporting (under the former provision that requirement is for up to three years). While the government's proposed Clean Air Act would have corrected this, its status is uncertain at best. The use of Section 46(1) as part of the implementation of the Regulatory Framework could be subject to question as Section 46 is aimed at gathering information for study purposes and not to allow the imposition of a regulatory program.
Although not mentioned in the Regulatory Framework, in order to be able to measure emission intensity, the notice will also require the reporting of production, which means that issues relating to the confidentiality of production information seem inevitable. Note, however, that the Ontario system that regulates nitrogen oxides (NOx) and sulphur dioxide (SO2) requires this type of reporting, as will Alberta's Specified Gas Emitters Regulation under the Climate Change and Emissions Management Act.
The Regulatory Framework sets out a number of different ways for firms to meet their obligations under the proposed regulatory regime, as described in more detail below:
The Regulatory Framework states that "ideally, firms will reduce their own emissions through abatement actions". Examples of in-facility reductions given are energy efficiency measures, improved energy management systems and other emission reducing technologies. While CCS is cited as one such example, it is not clear that CCS is an "in-facility" reduction.
The Regulatory Framework proposes a "baseline and credit" emissions trading system, where the "baseline" is a facility's emission intensity target. A facility can receive tradable credits equal to the amount by which its actual emission intensity is below the emission intensity target, multiplied by the facility's production. Credits will be issued ex post (after the year is completed and all calculations are filed), which is not conducive to emissions trading.
A firm can bank credits it receives or sell them to other parties through an emissions trading market. The emissions trading market is to be established by the private sector. There is no support in the Regulatory Framework for designating any specific exchange or other body as the location for the market, although such entities can participate to the extent they wish. Given the regulatory nature of the GHG emissions reduction system proposed by the Regulatory Framework, the ability of the federal government to avoid managing or at least supervising the operation of a registry remains open to question.
Domestic offset credits would be granted for emission reductions outside the domain of regulated activities. Examples of offset project activities include capturing methane from landfill gas (GWP of 21) and converting it to CO2 (GWP of 1) perhaps by using the methane to generate electricity, undertaking energy efficiency projects, or undertaking projects that store carbon in agricultural land or forests. Offset reductions must be verified "at a reasonable cost", quantified accurately, and be incremental to what would have happened without the offset program. Offset credits can be traded to a regulated facility to use for compliance, and it is intended that the offset system will commence prior to 2010 so that credits are available when intensity reductions are first required. The private sector is to play "a major role" in verifying offset credits and creating a trading system.
CERs from the CDM and Credits from Other International Linkages
CERs are generated through the Kyoto Protocol's CDM, which recognizes emission reductions created by a project undertaken in a developing country, such as India, by a developed country, such as Canada. The government intends to allow limited use of certain types of CERs for compliance purposes, but does not give any hint of what the appropriate characteristics of eligible CERs would be. Ten percent of each firm's total target will be able to be met by eligible CERs; whether this means 10% of the target or 10% of the reductions required by the intensity reduction provisions is left unclear and the use of the term "firm" rather than "facility" might be helpful in permitting more CER use, as one firm could have several facilities, some of which could use CERs to free up offsets or other credits for use at another of its facilities. The government apparently currently has no appetite for including Emission Reduction Units from the Kyoto Protocol's Joint Implementation mechanism.
The government also intends to actively pursue links with American state and regional-level systems such as the Regional Greenhouse Gas Initiative ("RGGI"), the Western Regional Climate Action Initiative ("WRCAI") led by California, any national U.S. system which may emerge, and potentially with Mexico, as well as other international systems in the future.
The concept of a clean technology fund has appeared previously, for example in the Liberal's 2005 Project Green plan, among other places. Using this compliance option, firms would be able to meet part of their regulatory obligations by contributing to a technology fund. The fund as contemplated by the current government would have two components: the first focused on technology deployment and infrastructure (for example, CCS infrastructure such as a pipeline in Alberta to transport CO2), and the second aimed at longer-term research and development. The Regulatory Framework states that the fund would be primarily aimed at the first component, deployment and infrastructure, which will mean funding investments that are likely to yield GHG emission reductions in the near term.
The fund is to be administered by an independent not-for-profit entity with a federal government mandate. The process for determining project funding, and the legislative authority, governance and administration of the fund is yet to be determined. However, the design of the fund is to respect two basic principles: no inter-regional transfer of wealth; and no government control. Other funds that meet all necessary requirements, particularly consistent provincial funds, could qualify as part of the regulatory framework.
Regulated firms can contribute $15/ tonne to the fund during 2010-2012 to meet their compliance obligations, with the price rising to $20/tonne in 2013 and increasing thereafter at the rate of growth of nominal gross domestic product (which number has not been adjusted for inflation) (but with the future pricing regime subject to review and potential adjustment every 5 years). Contributions to the deployment and infrastructure component of the Fund would be limited to 70% of the total regulatory obligation in 2010, decreasing by 5% for each year for the first few years to 50% in 2014, then to 40% in 2015, 10% in 2016, 10% in 2017, and falling to 0% in 2018 and later years. Thus, while initially representing a large part of the system, particularly in combination with contributions to the R&D component, this option will be progressively phased out, beginning a more rapid decline in 2014, and representing only a minor component by 2016.
In addition and separately, credit will be available for investment in the second component of the Fund, limited to 5 megatonnes per year from 2010 to 2017 (or between $75 million and approximately $125 million in 2017) that would finance R&D for transformative technologies that could achieve emission reductions in the medium to longer term. As the size of the regulatory system grows with continuous improvement requirements each year, contributions to the R&D component will likely represent a progressively smaller proportion of the overall cost of the system.
The government states that it will also explore credits for investment in "transformative technology that would incrementally reduce future emissions", and may also impose a mandatory requirement for investments in specific infrastructure projects, although there is no indication what those projects might be.
Lastly, there will be a one time grant of credits for firms covered by the proposed regulation that took verified action to reduce GHG emissions during the period 1992-2006. The aggregate of early action credits for all firms will be limited to 15 megatonnes (Mts), significantly fewer than most experts expect to be claimed. No more than 5 Mts can be used in any one year by all regulatees. Firms would be able to apply for credits by showing proof of changes in processes or facility improvements that resulted in incremental GHG reductions between 1992 and 2006; however eligibility criteria have yet to be developed. Evidence of GHG reductions would be audited.
Once applications are received, firms would receive up to one credit per tonne of reductions, but if the aggregate eligible requests exceed 15 megatonnes, the government will distribute the 15 megatonnes of credits to firms pro rata based on their contribution to the total reductions achieved. No baseline protection against the adverse effect of early action is mentioned.
The Regulatory Framework contemplates limiting the amounts of air pollutants that can be emitted in Canada from a given sector in a year, in particular, nitrogen oxixdes (NOx), sulphur oxides (SOx), volatile organic compounds (VOCs) and particulate matter (PM). Certain other sector specific air pollutants will also be regulated on a Canada-wide basis, for example benzene from natural gas production and processing, and mercury from electricity generation and base metal smelting.
Regulated air pollutants are to be subject to Canada-wide fixed emission caps. The fixed caps on air pollutants will remain the same regardless of production levels, and can therefore be contrasted with the proposed intensity targets that will be applied to GHG emissions. A table in the Regulatory Framework indicates that national caps, to be effective at a point between 2012 and 2015, would be amounts representing approximate reductions from 2006 levels of 40% for NOx emissions, 55% for SOx emissions, 45% for VOC emissions, and 20% for PM emissions. Sectoral caps were proposed more recently at the federal government's technical briefings on the Regulatory Framework.1
The government states that it will validate the benchmarked air pollutant targets over the next several months. Benchmarks were comparisons to standards across Canada, North America and globally. These are proposed to be validated through consultation with industry, provinces and territories, labour and environmental and health groups.
Whether a sectoral limit is set will depend on whether a specific pollutant is emitted in significant quantities by facilities in the sector. The determination of how sectoral caps will be allocated among facilities will be made during the process of developing the regulations, the targets for which are to come into effect "as early as possible" between 2012 and 2015.
The federal government anticipates working closely with the U.S. with respect to air pollutants and has announced its intention to have national standards that are no less stringent in Canada than comparable U.S. regulations.
For NOx and SOx, compliance options for facilities subject to air pollutant emission limits are to include a cap-and-trade system. Under such a system, a sectoral cap will be allocated among facilities in the form of credits, and, at the end of a compliance period, the facilities will have to surrender credits equal to their emissions. Facilities will be able to acquire credits from other facilities that reduce their emissions of the relevant substance below the regulatory limit imposed on them. The government also states that it will "expedite discussions with the U.S. on a cross-border SOx and NOx emissions trading system". In addition, the government will assess the feasibility of using offsets in the system. The trading in surplus emissions would not be permitted from outside an area where the quality of the air does not meet national air quality objectives. The Regulatory Framework states that these ambient air quality objectives would be set for particulate matter and ozone.
It is anticipated that the targets, the compliance mechanisms and the timetable for the entry into force of air pollutant regulations will be finalized by the fall of 2007 after the federal government has validated benchmarked air pollutant targets. Draft sector specific regulations will be developed for air pollutants and incorporated into draft regulations for GHGs "a few months" after the latter are published.
As mentioned above, Canada Gazette Pt. I publication for the draft GHG regulations will occur starting in spring 2008. While it is possible that provisions such as quantification and reporting could come into effect as early as 2009 or 2010, the targets for air pollutants will be effective "as early as possible" between 2012 and 2015.
Five-year reviews of industrial regulations for GHGs and air pollutants are planned, the first to take place in 2012. The purpose of the review would be "to determine the potential for further emissions reductions consistent with the goal of continuous improvement".
New energy efficiency standards for 18 currently unregulated products and more stringent requirements for 10 currently regulated products are to be implemented in order to reduce air emissions from products used by households and businesses. The government also plans to phase out inefficient incandescent lighting for common applications by 2012. These standards are to be "prepublished" in December, 2007.
In 2007 the government will also address VOC emissions by bringing forward three new regulations (in addition to existing regulation) to limit VOC content in certain paints, coatings and auto refinish coatings and selected consumer products. A strategic plan is also being developed to guide action in other consumer and commercial products sectors for the 2007-2010 period.
In the Regulatory Framework the government states its intention to take regulatory action to address the emissions caused by motor vehicles, as well as rail, marine and aviation transportation.
One aspect of this is the government's intention to implement mandatory fuel efficiency standards for motor vehicles, commencing with the 2011 model year. A voluntary agreement with the auto industry will be kept in place until 2010 to achieve certain GHG emission reductions. The Regulatory Framework states that "[t]he government will build on this 2005 agreement" in establishing its standards. The government also states its intention to work in collaboration with the U.S. government pursuing the concept of a "Clean Auto Pact", "towards establishing an environmentally ambitious North American regulatory standard for cars and light-duty trucks". Presumably any standard adopted in Canada must therefore be established in a North American context and surpass the targets of the 2005 voluntary agreement. Final regulations will be published in the Canada Gazette Pt. II by the end of 2008.
For the rail sector, the Regulatory Framework states the government's intent to enter into a voluntary Memorandum of Understanding to improve GHG emission performance through 2010, after which compulsory standards are to take effect under the Railway Safety Act in 2011. The government took a first step in May 2007 by entering into a Memorandum of Understanding that, among other things, commits Canada's major railway companies to buy only new locomotives that meet U.S. Environmental Protection Agency (EPA) emissions standards, and upgrade, upon remanufacturing, all high-horsepower locomotives to EPA emissions standards.
For the marine sector, the Regulatory Framework will apply international standards for air pollutants developed by the International Maritime Organization domestically through the Canada Shipping Act. It is unclear whether maritime standards for GHGs are contemplated.
For the aviation sector, the Regulatory Framework will consider international standards and recommended practices developed by the International Civil Aviation Organization, for both GHGs and air pollutants, in the development of domestic regulations under the Aeronautics Act. The commitment to regulate GHGs and pollutants is less clear in the case of aviation.
The Regulatory Framework also states that a series of regulations will be implemented to reduce air pollutant emissions from on- and off -road vehicles, consistent with the standards of the EPA.
The Regulatory Framework provides a policy framework which will leave a lasting impression on Canada and its economy. For GHGs, the Regulatory Framework, despite its controversial features (intensity targets, scope of use of technology fund instead of emissions reductions, limited international connection to trading markets, confirmation of Canada's abandonment of Kyoto Protocol targets and timeline) confirms the place of GHG reductions as a central element of Canada's environmental and economic policy for the foreseeable future. The Regulatory Framework establishes a floor below which Canada is unlikely to go in the GHG reduction area for many years. The mixing of GHG and air pollutant targets and policies in a single document makes the implementation of the Regulatory Framework much more complex and fraught with difficult constitutional and administrative issues. However, multi-pollutant analyses and legislation has been considered for some time in the US and given the close ties between Canada and the US, this approach may be both necessary and desirable. Time will tell. Time will also tell as to the acceptability of the federal government inserting itself into air pollutant matters which have traditionally been seen as air-shed driven and, thus, relatively local and amenable to provincial control (even where regional provincial co-operation and co-operation between provinces and nearby states seem to be necessary).
The Regulatory Framework is striking in its sheer scope, announcing the regulation of most major industrial sectors, cars, light trucks, trains, ships, planes, personal watercraft, outboard engines, snowmobiles, motorcycles, all-terrain vehicles, paints, coatings, light bulbs, appliances, commercial boilers and a wide variety of other consumer and commercial products, not to mention sources of indoor air pollution. The possibility of a constitutional overreach in some of these areas cannot be disregarded.
The Regulatory Framework represents the first time in Canada that the federal government has proposed regulating air pollutants from across industry, as well as the first time the federal government will regulate fuel economy from motor vehicles. In both cases, national laws were established decades earlier in the United States. This will also be the first time that indoor air pollutants are to be regulated by the federal government. Given the proposals to establish short, mid and long-term targets for GHGs, and the commitment of the government to establish new national air quality objectives, as well as five year reviews beginning in 2012 that will explore further emission reductions, federal regulation of GHGs and air pollutants will be part of the environmental and economic calculations of Canadian business, at least for the next several years and perhaps for the much longer term.
Currently, the Climate Change and Emissions Management Act (the "Act") (http://www. qp.gov.ab.ca/documents/Acts/C16P7. cfm?frm_isbn=9780779723386), provides a statutory framework for managing climate change and greenhouse gas ("GHG") emissions in Alberta. The Act provides that, "[t]he specified gas emission target for Alberta is a reduction by December 31, 2020 of specified gas emissions relative to Gross Domestic Product to an amount that is equal to or less than 50% of 1990 levels." For the purpose of meeting this specified gas emission reduction target, Alberta has enacted a regulation, the "Specified Gas Emitters Regulation" ("SGER") (http://www3.gov.ab.ca/env/air/pubs/ Specified_Gas_Emitters_Regulation. pdf), effective July 1st, 2007.
In response to the ratification of the Kyoto Protocol by the federal government, the Alberta government passed the Act as part of its plan to manage climate change and GHG emissions.
In addition to the establishment of an ultimate goal for specified gas emission reduction, the Act establishes the statutory framework for regulating specified gas emissions in Alberta. The Act imposes duties to report and reduce emissions on every person who releases or permits the release of a specified gas into the environment at or in excess of levels or in circumstances established by the regulations.
Under the Act, Alberta's cabinet is authorized to regulate emission offsets, credits and sink rights for the purpose of reducing specified gas emissions. Under the Act, to achieve the specified gas emission reduction target, cabinet can create a market for emission offsets and create and maintain a public registry. With the approval of the cabinet, the Minister may enter into sectoral agreements with representatives of different sectors of the Alberta economy with respect to emission reduction targets and how the targets are to be achieved. The Act gives the Minister various enforcement powers, including the right of entry and inspection, the power of seizure without order or search warrant and the power to impose administrative penalties, subject to the limits imposed by the Act.
The SGER is the principal accompanying regulation to the Act. The SGER applies to a facility that has direct emissions totalling 100,000 tonnes or more in 2003 or any subsequent year. "Direct emissions" means the release of specified gasses from sources actually located at a facility, expressed in tonnes on a CO2e basis. Direct emissions include industrial process emissions. Therefore, while industrial process emissions are excluded from the emissions intensity limits, it must be noted that they are included in the threshold calculation that determines whether an emissions intensity limit will apply.
Under the SGER, a facility is required to apply for an emissions intensity baseline, to meet its emissions intensity limit, and to file an annual compliance report. Generally, once a facility is made subject to the SGER, it will remain subject to the SGER, even if its emissions fall below the threshold of 100,000 tonnes of CO2e in the future. However, the SGER does allow Alberta Environment2 to exempt a facility from the obligations of meeting its emissions intensity limit and filing a compliance report if the facility was operated under unusual conditions or was shut down for a prolonged period and the conditions or shutdown caused a material reduction in the specified gas emissions for the applicable period.
The SGER covers all greenhouse gasses ("GHGs") in the Kyoto Protocol, which are carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs) and sulphur hexafluoride (SF6). For regulatory reporting purposes, GHGs are to be expressed in terms of tonnes of carbon dioxide equivalent (CO2e). GHG emissions are denominated this way because different GHGs have different global warming potentials. For example, one tonne of N2O in the atmosphere has the same warming effect as 310 tonnes of CO2, and one tonne of SF6 has the same warming effect as 23,900 tonnes of CO2.
The SGER requires mandatory emission reductions through the use of emissions intensity targets. The emissions intensity approach ties targets to production, meaning that facilities would be required to reduce GHG emissions per unit of production relative to a baseline.
(i) Baseline: new facilities v. established facilities
Under the SGER, a facility is a plant, structure or thing where an activity listed in section 2 of the Schedule of Activities to the Environmental Protection and Enhancement Act (the "EPEA") occurs; or a site or two or more contiguous or adjacent sites that are operated and function in an integrated fashion where an activity listed in any of sections 3 to 11 of the Schedule of Activities to the EPEA occurs. A facility includes all the buildings, equipment, structures, machinery and vehicles that are an integral part of the activity.
The person responsible for the facility is required to apply for the establishment of a baseline emissions intensity (the "BEI"). Where the release of the specified gas occurs at a facility that is the subject of an approval or registration under the EPEA, the "person responsible" means the holder of the approval or registration; where the release of the specified gas occurs at a facility that is not the subject of an EPEA approval or registration, but is the subject of an approval or other authorization issued by the Alberta Energy and Utilities Board, the "person responsible" means the holder of that approval or authorization; and, in all other circumstances, the "person responsible" means the owner of the facility. The SGER establishes different baselines for a new facility and an established facility. A new facility is a facility that completed its first year of commercial operation on December 31 of 2000 or a subsequent year and has completed less than 8 years of commercial operation. An established facility is a facility that completed its first year of commercial operation before January 1, 2000, or has completed 8 years of commercial operation. Alberta Environment may designate an established facility as a new facility if it considers it appropriate to do so.
The BEI for a new facility is the ratio of total annual emissions to production for the 3rd year of commercial operation of the facility. "Total annual emissions" (the "TAE") means total direct emissions in a year, not including industrial process emissions. For a facility that is an established facility on January 1st, 2007, the BEI is determined by the following formula:
In the formula, "P" means the production for the year indicated. In other words, an established facility's total annual emissions and production for the years of 2003, 2004 and 2005 determine the facility's BEI.
Alternatively, Alberta Environment may specify in writing a method to calculate a BEI for a new or established facility if it determines that the method above is not appropriate. In particular, Alberta Environment can establish a new BEI or direct the person responsible to apply for a new BEI if it is of the opinion that the BEI applied for is not accurate; or that the facility has undergone an expansion or significantly changed, or that it is appropriate for any other reason to revise the BEI.
(ii) GHG Emissions Reduction Requirement for a New Facility
For the first three years of its commercial operations, a new facility is under no regulatory obligation to reduce its emissions intensity. Its fourth year of commercial operation is the first year when an enforceable requirement of emissions reduction is imposed.
If the period commencing on July 1, 2007 and ending on December 31, 2007 (the "Period") is the last 6 months of the new facility's 4th year of commercial operation, the required reduction in emissions intensity for the Period will be 2% from the BEI.3 In other words, the net emissions intensity ("NEI") for the Period shall not exceed 98% of the BEI. The NEI for the Period will be determined by the following formula:
If the new facility has been in commercial operation for more than 4 years, a continuous improvement of 2% will be imposed for each year until the facility becomes an established facility. For example, if the Period is the last 6 months of the new facility's 8th year of commercial operation, the required reduction in emissions intensity will be 10% from the BEI.
For a new facility, commencing with the year 2008, the annual required reduction shall be 2% from the BEI if the facility is in its fourth year of commercial operation. In other words, the new facility's annual net emission intensity shall not exceed 98% of its BEI. The annual NEI limit shall be determined by the following formula:
The required reduction in emissions intensity will be 2% more from its BEI for each subsequent year of operation until the facility becomes an established facility. For example, a new facility in its 8th year of commercial operation has a NEI limit of 90% of its BEI.
(iii) GHG Emissions Reduction Requirement for an Established Facility
For an established facility whose direct emissions exceed 100,000 tonnes in a year of commercial operation in any of the years of 2003, 2004, 2005 or 2006, the required reduction in GHG emissions intensity for the second half year of 2007 will be 12% from the BEI, which means that the net emissions intensity for an established facility shall not exceed 88% of the BEI. The 2007 net emissions intensity will determined by the Formula NEI 2007.
Starting from the year 2008, an established facility's annual required reduction in emissions intensity is 12% from the BEI. In other words, the established facility's annual net emissions intensity shall not exceed 88% of its BEI, as determined by Formula NEI, above.
The person responsible for a facility on December 31st of a year is required to submit to Alberta Environment a compliance report with respect to the facility by March 31st of the following year.
The SGER provides that the compliance report must contain the information and data required in a form prescribed by Alberta Environment and must confirm that the NEI limit for the facility has been met or provide an acknowledgement that the NEI has not been met with an explanation and proposal to remedy the non-compliance. Under the SGER, Alberta Environment may evaluate a facility's calculation of its NEI. Thus, it is reasonable to infer that the person responsible may be required to provide Alberta Environment with confidential information, including the production of the facility, for the purpose of such evaluation. The SGER requires a compliance report to be certified by a person and in a manner required by the form and to be verified by a third party auditor.
Note that a Specified Gas Reporting Regulation (the "Reporting Regulation") is in effect under the Act which incorporates by reference an Alberta Environment publication, the Specified Gas Reporting Standard, which is subject to change from time to time. In addition, Alberta, along with Canada's other provinces and territories, has agreed to join The Climate Registry, a North American entity which will develop a common approach to entity level GHG measurement, reporting and verification. Maintaining Records Under the SGER, a person responsible who submits an application for the establishment of the BEI or a compliance report is required to retain a copy of the application or report (the "Filing Documents") and the records, information and data on which the application or report was based for at least 7 years following the submission of the application or report.
The public may request access to the Filing Documents. However, under the SGER, Alberta Environment may refuse a request to inspect the Filing Documents if the requesting person fails to make such request to the appropriate personal responsible first.
A person responsible may request that certain commercial, financial, scientific or technical information in the Filing Documents be kept confidential for a period of up to 5 years after the date of submission on the basis that the disclosure of such information would reveal proprietary business, competitive or trade secret information about a specific facility, technology or corporate initiative. Alberta Environment must determine whether the request is well founded, having regard to the factors set out in the SGER, and then inform the person responsible of its decision on the request within 150 days after receiving the request.
In addition to in-facility emission reductions, the SGER sets out a number of ways for regulated facilities to meet their regulatory obligations. Specifically, a regulated facility can meet its emissions reduction obligation by applying "emission offsets" from reductions from non-regulated actions; by contributions of money to the Climate Change and Emissions Management Fund (the "Fund") and through acquiring emission performance credits from other regulated facilities that have surpassed their targets. The SGER states that emission offsets, fund credits and emission performance credits are not property rights but are revocable licences.
(iv) Emission Offsets
The SGER allows a regulated facility to apply an emission offset towards its regulatory target from specified gas emission reductions that occur on or after January 1, 2002, and that result from a non-regulated action taken on or after January 1, 2002, within Alberta.
A non-regulated action is an action that is not required by law at the time the action is initiated. For example, capturing methane from landfill gas and using it to generate electricity, undertaking energy efficiency projects, undertaking projects that increase the storage of carbon on agriculture land, and geological carbon sequestration, represent such actions.
The SGER also requires that, to constitute emission offsets, the specified gas emissions reduction must be real and demonstrable, as well as measurable and quantifiable.
(v) The Climate Change and Management Fund and Fund Credits
The Act establishes the Climate Change and Management Fund (the "Fund"). A person responsible may meet obligations under the SGER by contributing money to the Fund and obtaining fund credits. According to the Act, the Fund will be administered by the Minister responsible for the Act. The Minister will make payments to projects that are related to reducing emissions of specified gases or improving Alberta's ability to adapt to climate change.
A regulated facility may obtain a fund credit for each $15 contribution to the Fund. The SGER contains no provision regarding an increase of the credit price in the near future. The SGER also does not contain any provision with respect to a limit on the extent to which a person responsible may meet its obligation by using fund credits.
Under the SGER, a fund credit obtained on or before March 31 in a year may only be used in meeting the annual reduction obligation for the previous year and a fund credit obtained after March 31 may only be used to meet the obligation for that year except that a fund credit obtained on or before March 31, 2008 may only be used in meeting a regulatory obligation for the period between July 1, 2007 and December 31, 2007.
(vi) Emission Performance Credits
If a regulated facility's actual emission intensity for a period is less than the NEI limit for that period, the reduction that is not used in meeting the NEI limit constitutes an emission performance credit or credits (the "EPC").
The SGER does not impose a limit on the amount of the EPC that a regulated facility can trade. A regulated facility's tradable EPCs is equal to the amount by which its actual emissions intensity is below the NEI limit multiplied by the facility's production. The EPC created at a regulated facility may also be used by the facility in meeting its regulatory obligation for a subsequent year (i.e. "banked").
Under the SGER, an investigator's right of entry and inspection under the Act extends to inspecting, investigating or auditing of a person responsible and a facility in respect of their obligations under the SGER.
In addition to the actions authorized by the Act, under the SGER, Alberta Environment is authorized to order the person responsible to take measures to minimize or remedy the effects of the facility's non-compliance with its NEI limit. Specifically, Alberta Environment may issue an order when the facility fails to meet its NEI limit as shown in the compliance report; when the calculation of NEI was incorrect or was based on incorrect information and the NEI limit for the facility was exceeded; or when the value for the emission offsets that was used to calculate the annual NEI of the facility becomes invalid by reason of some or all of the tonnes of specified gases that the emission offsets represented as not being released into the environment being subsequently released and the NEI limit for the facility was exceeded. By order, Alberta Environment may require the person responsible to obtain emission offsets or EPC, to make contributions to the Fund or any other measures that it considers advisable.
Under the SGER, a failure to comply with the NEI limit, to file a valid compliance report, to retain necessary records or to apply for the BEI constitutes an offence. It is also an offence to perform the function of a third party auditor without having the qualifications set out in the SGER, or to retain such a person, or to fail to follow an order of Alberta Environment under the SGER. The person that fails to meet its regulatory obligations will be exposed to fines. Certain provisions of the SGER, the Reporting Regulation and the Act, but not the SGER's emissions intensity targets, will be enforced under the Administrative Penalty Regulation made under the Act. It is a defence if the person can establish that it has taken all reasonable steps to prevent the offence from being committed.
To avoid unexpected obligations under the SGER, a person acquiring an interest in, or responsibility for, a potential "facility" or facilities ("the assets") needs to determine whether any of the assets include a "facility" that has "direct emissions" totalling 100,000 tonnes or more of CO2e in 2003 or any subsequent year, and whether the person will fall within the definition of a "person responsible" as a result of acquiring the relevant interest or responsibility. The person will also wish to determine whether the assets are capable of creating emission offsets or emission performance credits that are governed by the SGER.
The person responsible for a facility on December 31st of a year is required to submit to Alberta Environment a compliance report with respect to the facility by March 31 of the following year.
Most importantly, the requirement to comply with the net emissions intensity limits, whether a target is applicable for July 1st, 2007 to December 31st, 2007, or the year 2008, or a subsequent year (a "Compliance Period"), is imposed on the person responsible on December 31st of the Compliance Period, even if that person was not the person responsible when most or all of the emissions occurred. Note also that for 2008 and subsequent years, the Minister may, by order, establish net emissions intensity limits in addition to, or in substitution for, those otherwise applicable under the SGER. Whether such an order has been made should be addressed.
Notwithstanding the above, the SGER states that Alberta Environment may issue an order to "the person responsible" for the facility to take certain measures to remedy a breach of the net emissions intensity limit, without any requirement that the "person responsible" made subject to the order be the "person responsible" for the facility when the intensity target was exceeded, or that the person be the "person responsible" for the facility as of December 31st. As a result, the potential exists that any person who becomes a person responsible on any date in respect of such a facility may incur liability for events occurring in any past Compliance Period.
As noted above, a "facility" that becomes subject to the SGER by crossing the 100,000 tonnes of "direct emissions" threshold in 2003 or any later year, a threshold which includes "industrial process emissions", will not cease to be subject to a net emissions intensity limit by virtue of falling below that threshold in a later Compliance Period.
Finally, for offences arising from a breach of the provisions described above, other than a breach of an emissions intensity limit, or failing to file a compliance report, the relevant date may not be specified as a particular calendar date in the relevant provision: each of these provisions should be considered carefully on its own to determine whether there is potential liability.
Alberta is the first jurisdiction in Canada to introduce legislation to reduce GHG emissions from large emitters. It sets out a highly complex regime which will inform efforts by other Canadian jurisdictions to develop their own laws on GHG emissions. With increased stringency of emissions intensity targets and possibly adjustments to the technology fund option and the application of a cleaner fuel standard for "new" facilities, Alberta Environment may well remain the sole regulator for both air pollutants and GHGs in the Province, a situation that is desirable for all concerned.
Under the Canadian Environmental Protection Act, 1999 ("CEPA, 1999"), the federal Environment Minister may enter into an agreement with a "government", including a province, agreeing that provisions are in force in the province that are, among other matters, "equivalent" to a federal regulation made under certain sections of CEPA, 1999. On the basis of this agreement (an "equivalency agreement"), and the recommendation of the federal Environment Minister, the federal cabinet may make an order providing that the federal regulation is of no effect in the province concerned. Under the proposed federal Regulatory Framework for GHGs and air pollutants released on April 26th, 2007 (http:// www.ecoaction.gc.ca/news-nouvelles/ pdf/20070426-1-eng.pdf ), the federal Government states that it "will work to reach equivalency agreements with those provinces that set provincial emissions standards that are at least as stringent as the federal standards".
Historically, equivalency agreements have been used rarely. Differences between the federal Regulatory Framework and SGER may complicate reaching an equivalency agreement with Alberta, although such an agreement would make it possible for the Province to continue to have a single regulator for both GHGs and air pollutants. The federal Regulatory Framework uses a baseline of 2006 for existing facilities, rather than a three year 2003 to 2005 average, as Alberta does for facilities that are "established" as of the date January 1st, 2007.
The federal Regulatory Framework also defines "existing" facilities more broadly than Alberta (and thus the federal Regulatory Framework defines "new" facilities more narrowly), as facilities that commenced operations in 2003 or earlier. By contrast, the Alberta Regulation considers established facilities as those that completed their first year of commercial operation before January 1st 2000. Thus, "new facility" is a much broader category for Alberta.
Like the federal Regulatory Framework, the Alberta Regulation requires no target for "new" facilities for the first three years of operations and this is reflected in the baseline, which is the third year of operations for both. However, the federal Regulatory Framework may also impose an adjustment to this baseline for "cleaner fuel standards", an unexplained phrase which appears to be an effort to discourage new facilities from opting for higher carbon content fuels (absent carbon capture and storage, perhaps).
Note that although federal GHG reporting notices have set a threshold of 100,000 tonnes, there is no indication in the federal Regulatory Framework that this threshold will apply to the proposed federal regulations, unlike the Alberta Regulation.
The federal Regulatory Framework shares the emissions intensity approach of the SGER, with regulations entering into force in 2010, whereas Alberta's regulations entered into force on July 1st, 2007. However, the federal Regulatory Framework sets a target for existing facilities of 18% below 2006 levels in the year 2010, whereas the SGER requires an established facility to reduce its emissions to 12% below the average of its emissions from 2003 to 2005. The federal Regulatory Framework also requires 2% annual improvement to the emissions intensity of existing facilities, resulting in a required emissions intensity improvement of 26% by the start of 2015, whereas Alberta does not require such annual improvement. The federal regulatory requirements will therefore be significantly more stringent when they come into force in 2010, and more so every passing year. In order for an equivalency agreement to be reached, it is likely that the Alberta intensity targets would have to equal or exceed those set by the federal government.
In addition, the technology fund option is fundamentally different for each jurisdiction. While contributions to a technology fund are permitted to represent a substantial majority of compliance with the federal regime initially, the Regulatory Framework phases out contributions to the fund each year, proceeding rapidly after 2014, and eliminating the fund entirely by 2018. The SGER, however, places no limits on contributions to a technology fund, and there are no indications that such a limit will exist in future.
In the case of an emission offset or credit given for surpassing a regulatory target, emission reductions must already have occurred, and are subject to monitoring and verification procedures. By contrast, a contribution of money to a fund established by a government will not necessarily ensure that any emission reductions ever occur, or that reductions will occur in a quantity that corresponds to the number of compliance units given for a certain price. As a result, the greater the role played by a technology fund, the higher the risk that reductions notionally made by the regulatory system will not reflect actual reductions in the same compliance year.
In addition, the majority of contributions to a technology fund in the federal Regulatory Framework are to be directed to investments in technology deployment and infrastructure with a high likelihood of yielding emission reductions in the near-term, whereas the SGER and the Act do not include this requirement. As a result, monies may be spent on long-term projects to develop technology that will not be successful in reducing emissions, either because the technology does not succeed from a technical viewpoint, or because it is not widely deployed, or monies may be spent on projects that reduce emissions only in the long-term. In the case of Alberta, monies may also be directed at adaptation to climate change.
The federal technology fund option will also set a higher price for each unit after 2012, rising to $20 in 2013 and increasing each year thereafter by the rate of nominal GDP increase, whereas Alberta's contribution rate is fixed at $15/tonne. This suggests that there will be more pressure to achieve "real" reductions in the federal system, particularly after 2012, or to purchase verified reductions from other federal regulatees in the form of performance related credits, offsets in respect of non-regulated activities, or credits issued under the Kyoto Protocol's Clean Development Mechanism, up to allowed limits.
While it is acknowledged that for both regimes the technology fund has not been well defined, the design of the technology fund compliance option and the size of the role it plays under the SGER (potentially representing the entirety of compliance under the system), in contrast to the federal Regulatory Framework would, at a minimum, make it less certain that the SGER will achieve an equivalent level of protection for the environment. It remains to be seen whether the federal government and Alberta will harmonize their approaches to a technology fund. In the first several years, however, both schemes may operate for the most part in a manner similar to a carbon tax. In other words, regulatees will, for the most part, comply by making payments to an entity established by the government, at a fixed price determined by the government per tonne of carbon.
One additional point of difference is the requirement to retain records under the Alberta Regulation for up to 7 years. The federal government has announced it will use section 71 of CEPA, 1999 to collect information for the purposes of its GHG and air pollutant regulations, which does not include any authority to require the retention of records (although a notice was issued under section 46(1) of CEPA earlier in 2006 for GHGs, which is a general information gathering provision in the statute under which the retention of records can be required, and were in this case, for up to three years).
Alberta's Specified Gas Emitters Regulation (the "Regulation": http://www3.gov.ab.ca/env/ air/pubs/Specified_Gas_Emitters_ Regulation.pdf ), which took effect July 1st, 2007, applies to certain emissions of greenhouse gas (GHGs) in Alberta and is made under the Province's Climate Change and Emissions Management Act, as recently amended (see http://www. qp.gov.ab.ca/documents/Acts/C16P7. cfm?frm_isbn=9780779723386). The Regulation sets out the first legally enforceable limits on greenhouse gases (GHGs) in Canada. The Regulation includes emissions intensity targets, compliance mechanisms, reporting and verification rules and enforcement measures. Each target is set as a reduction below an emissions intensity baseline, and the Alberta regulation sets out a fairly complicated approach to establishing those baselines. The Regulation entered into force on July 1st, 2007, meaning that there will be a one half compliance year in 2007 and that a baseline is needed almost right away.
Under the Regulation, the baseline is not pre-determined. Rather, an emissions intensity baseline must be applied for by the "person responsible" for a regulated facility to Alberta Environment. The term "person responsible" means, at a facility that is the subject of an approval or registration under the Environmental Protection and Enhancement Act ("EPEA"), the holder of the approval or registration, at a facility that does not fall in this first group but is the subject of an approval or other authorization issued by the Alberta Energy and Utilities Board, the holder of that approval or authorization, or at any other facility, the owner.
A "facility" means "a plant, structure or thing where an activity listed in section 2 of the Schedule of Activities to [EPEA] occurs" and "a site or 2 or more contiguous or adjacent sites that are operated and function in an integrated fashion where an activity listed in any of sections 3 to 11 of the Schedule of Activities to the [EPEA] occurs", "including all the buildings, equipment, structures, machinery and vehicles that are an integral part of the activity".
The answer to this question will vary depending upon whether the facility falls in one of three categories: (1) a facility that is subject to an emissions intensity target for the latter half of 2007 beginning on July 1st, (2) a new facility which will have a target after 2007, and (3), a facility that exceeds 100,000 tonnes of "direct emissions" in a year which is 2007 or later and is not one of its first three years of operations.
All of these categories have a threshold of "direct emissions" in the relevant year over 100,000 tonnes ("direct emissions" are defined as "the release of specified gases from sources actually located at a facility", which excludes off site emissions). Note that "industrial process emissions" are included in this threshold calculation, although they are not included for the purposes of emissions intensity targets.
Facilities in category (1) must apply for the establishment of a baseline by December 31, 2007. Facilities in this category include facilities that were an "established facility" on January 1, 2007, and that had direct emissions totalling 100 000 tonnes or more in any year of commercial operation from 2003 to 2006, inclusive. An "established facility" means a facility that completed its first year of commercial operation before January 1, 2000, or has completed 8 years of commercial operation (but note that Alberta Environment can designate any "established" facility as a "new" facility, if Alberta Environment considers it appropriate to do so). Other facilities in this category are those "new" facilities in their fourth to eighth year of commercial operation (specifically, those where the period between July 1st, 2007 and December 31st, 2007 is the last 6 months of the 4th to eighth year of commercial operation, with the same condition as to "direct emissions" for the years 2003 to 2006, inclusive). A "new facility" is a facility that completed its first year of commercial operation on December 31 of 2000 or a subsequent year, and that has completed less than 8 years of commercial operations. All facilities in this category are required to meet or exceed a target in the latter half of 2007.
Facilities in category (2) are those "new" facilities that will face a target after 2007. "New" facilities in this category must also have 100 000 tonnes or more of direct emissions in any of their first 3 years of commercial operation, but they avoid falling into category (1) as a result of the fact that none of those years in which the 100 000 tonnes threshold is crossed fall within the years 2003 to 2006, inclusive. In this instance, the application for the baseline must be made on the later of June 1st, 2008 or June 1st of the 4th year of commercial operation. This reflects the fact that targets are not applicable to "new" facilities for their first three years.
Facilities in category (3) are those facilities that exceed the 100 000 tonne threshold in a year of commercial operation which is 2007 or later and is not one of its first three years of operations. For these facilities, the application for the emissions intensity baseline must be made on June 1st of the year following the year when this threshold is crossed. Note that no issue arises if the threshold is crossed prior to 2003, as this is outside the scope of the Regulation. Guidance should be sought from Alberta Environment on the relevant forms to be completed.
For "established" facilities facing a target in the latter half of 2007, the baseline is the average emissions intensity over the years 2003, 2004, and 2005. For "new" facilities facing a target in their fourth to eighth year of operation, the baseline is their emissions in their third year of commercial operation. Note, however, that in both cases, Alberta Environment can specify an alternative method of arriving at a baseline, if the default method is considered by Alberta Environment to be inappropriate, and can do so at any time once a baseline is established under certain conditions.
In arriving at its baseline determination, Alberta Environment has a number of powers, including the power to require verification of data by a third party or to request any additional information or to require the application to be resubmitted. Alberta Environment can adopt the requested baseline, or vary or replace it. Alberta Environment has the power to define the units of production in a different manner than requested (the Regulation does not define the substantive content of the term "production"). Alberta Environment may consider any factors Alberta Environment considers relevant, including technologies in use at comparable facilities, and the best available technology economically achievable for the facility.
Note that there is also a requirement to maintain the records, information and data used in the application for 7 years from the time it is submitted, and to obtain verification by a third party auditor, generally a professional engineer or chartered accountant, with the required technical background as set out in the Regulation. There is also a general requirement to maintain any records, information and data relating to the emissions intensity of the facility for 7 years from the time the record etc. is created.
Fixed process emissions are emissions that are the result of a physical or chemical reaction and that cannot be reduced using known technology without actually stopping production. The Regulation terms these "industrial process emissions", which are defined as "direct emissions from an industrial process involving chemical or physical reactions other than combustion, and where the primary purposes of the industrial process is not energy production". "[I]ndustrial process emissions" are excluded from calculations of both "total annual emissions" and "total half year emissions" and thus are excluded for the purposes of calculating intensity limits. Note, however, that "industrial process emissions" are included in the calculation of the 100,000 tonne threshold to determine whether the Regulation will apply.
Written requests for confidentiality of specified information in the baseline application may be granted, effective for up to 5 years, on the basis that the information is "commercial, financial, scientific or technical information that would reveal proprietary business, competitive or trade secret information about a specific facility, technology or corporate initiative". Alberta Environment has 150 days after receiving the request to notify the person responsible of the decision.
Under Alberta's Specified Gas Emitters Regulation (the Regulation: http://www3. gov.ab.ca/env/air/pubs/Specified_ Gas_Emitters_Regulation.pdf ), now in force, greenhouse gas (GHG) reductions/removals must have certain characteristics to constitute emission offsets. To start, the GHGs must be "specified gases" which are currently the traditional GHGs covered by the Kyoto Protocol. Specifically, the reduction in specified GHG emissions must:
Alberta has released the Offset Credit Project Guidance Document (the Guidance: http://www3.gov.ab.ca/env/ climate/docs/Guidance_Document_ Alberta_Offsets.pdf ). The Guidance states that a key principle is "Maximum Scope", suggesting that a wide range of projects from a wide range of sectors will be given full consideration. A wide range of pre-approved offset quantification protocols have now been finalized, in areas such as efficiency, enhanced oil recovery, waste heat recovery, sequestration in agricultural soils, biogas, biomass and landfill gas capture (see http://www.carbonoffsetsolutions. ca/offsetprotocols/finalAB.html).
As can be seen from the above, offsets will only be conferred for reductions that occur in the Province of Alberta.
An offset under the Regulation is distinct from a credit earned by a regulated person for reducing GHG emissions to below the required emissions intensity targets: an offset must relate to activities that are not covered by the emissions intensity requirements of the Regulation. The Guidance provides that "reductions or removals must be incremental to provincial regulations" (i.e. that they must go beyond what is already required by provincial regulations).
The Guidance also states that "the intent of the regulation was to ensure that the projects generating emission reductions are additional to what otherwise would have occurred in Alberta, prior to the January 2002 release [of ] Alberta's first climate change plan – 'Taking Action'…" (http://environment.gov.ab.ca/info/ library/6123.pdf ). In particular, it adds that "[the design of offset projects] must ensure project-based emission offsets result in further reductions and removals in greenhouse gas emissions, than would be the case if offset credits were not available". Although the commonly used term "additionality" is not used, an additionality requirement or something close to it is implied, including in the discussion of establishing a baseline. As the Guidance and SGER are not as clear or elaborate as they could be in addressing the issue, however, the issue should be handled with some care.
Offsets can include reductions/removals on or after January 1, 2002. There is therefore some recognition for early action.
To be real, the Guidance states that "an offset project must have specific and identifiable actions that reduce or remove GHGs" and do not "result in emissions moving to another part of the facility or operation". It could be queried why the project is not also required to show that emissions are not being shifted outside the facility or operation. The project is required to also show that it "causes a net reduction of all greenhouse gases involved in the project".
To be "demonstrable" and "quantifiable" the Guidance provides that "GHG reductions/removals must be calculated or measured according to scientifically acceptable methods". As noted above, a number of pre-approved quantification protocols are now available.
The Regulation makes it a condition for using an offset for compliance purposes that any Ministerial guidelines be complied with. In that respect, the Guidance establishes a number of additional requirements, including:
The use of a third party verifier for validation and registration of the Offset Project Plan before the project commences is optional, unlike the verification that follows implementation and operation of the project and which supports the making of a GHG reduction/removal assertion (GHG assertion). A registry for Alberta projects will be established for voluntary use. In addition, the Guidance states that an Offset Project Plan, including a description of the baseline and project conditions, as well as quantification, monitoring and quality assurance/ control procedure sub-plans, is "essential" to allow the mandatory verification phase to be completed. A Data Management System for recording project information is also mandatory.
Projects under the Alberta offset system will have a credit duration period of 8 years, with potentially an additional 5 years. Issuance of offsets will follow submission of a Project Report, containing the records outlined in the Verification Guide cited above, and a completed Verification Report. This documentation, along with a GHG assertion, will be submitted to Alberta Environment, not by the project developer, but by the regulated emitter that is purchasing the offsets, together with other required compliance information.
In a speech given on June 20th of this year to The Shared Air Summit, the Premier announced that GHG emission targets for Ontario are:
According to the Premier, fifty per cent of the short-term target of 2014 is to be achieved through closing Ontario's remaining coal-fired plants and "existing policies like the Greenbelt". Approximately 15 per cent of the target would be met through transit investments and "working on initiatives with the federal government and other partners, such as strong, national fuel-efficiency and auto emissions standards". An additional 15 per cent is said to be accounted for by "new policies", both announced and unannounced, the examples provided being "home audits and working with municipalities". The remainder will come from "research and innovation".
During the visit of Governor Schwarzenegger to Canada, the Premier signed a memorandum of understanding between Ontario and California, committing Ontario to adopt California's low carbon fuel standard (LCFS). This standard has not yet been published in detail. Rather, an Executive Order (EO) establishes a statewide goal to reduce the "carbon intensity" of California's transportation fuels by at least 10 percent by 2020. Under the EO, the LCFS, to be developed through a collaborative process between various California agencies and the University of California, will apply to "all refiners, blenders, producers or importers" of transportation fuels, and "shall be measured on a full fuels cycle basis". The latter has raised concerns that the LCFS could discourage shipments of products from the heavier oil found in Western Canada, particularly in the oil sands, which has much higher GHG emissions associated with its product.
Unlike British Columbia, Ontario did not agree to adopt California's auto emissions standards for GHGs during the Governor's visit. Rather, Ontario has announced $650 million in spending for the auto industry to invest in the development of lower emission technologies.
The targets set out above for Ontario, while short of the targets in the Kyoto Protocol applicable to Canada as a whole, are significantly deeper than those announced by the federal government. For the latter, short term intensity targets are predicted to stabilize and then reduce emissions in absolute terms from 2006 levels between 2010 and 2012. The federal government has committed to a midterm target for Canada of 20% below 2006 levels by 2020, which translates to 3% above 1990 levels, and a long-term target of 60 to 70% below 2006 levels by 2050. Ontario's targets use the 1990 Kyoto baseline.
However, unlike the federal announcement, Ontario has not stated at present that it would regulate emissions from industry, with the exception of the Premier's announcement that a regulation will be made requiring the closure of the remaining coal plants by 2014. Concerns have been raised, however, that with rapidly growing demand, insufficient plans may be in place for new base load electricity generation (which will include the use of renewable energy and may include nuclear energy) to permit the orderly closure of the remaining coal plants by 2014.
On September 5, 2007, Ontario announced that it was establishing a working group of experts to develop protocols for carbon offsets and that pilot carbon offset projects for farms and forests are expected to be "up and running" in 2008. Offsets could form part of a regulatory regime for GHGs in Ontario and/or could serve other purposes. All Canadian provinces and territories have agreed to join The Climate Registry, which will provide common entity-level measurement, reporting and verification system for most of North America. Ontario is also current an observer to the Western Climate Initiative (WCI).
In B.C.'s Throne Speech of February 13th, 2007, the Province announced its intention to reduce its GHG emissions to 33% below "current" (2007) levels by 2020, as well as to set interim targets for 2012 and 2016. According to the Province, the 2020 target would also be equivalent to a reduction of the Province's emissions to 10% below 1990 levels.
According to the Throne Speech, B.C. would:
On September the 28th, 2007 Premier Campbell announced that the Province would enact the Province's 2020 target into legislation, as well as targets for 2012, 2016 and 2050. Targets for key emitting sectors will be introduced for 2012 and 2016, to be announced by July 31, 2008, and enacted as regulations by the end of 2008. Sectoral consultations on GHG reductions are to be held with forestry, mining, energy, waste, landfills and agriculture. Legislation will also be introduced in the spring of 2008 to require "hard caps" on GHG emissions as part of a "cap and trade system" to be developed by August 2008 through the Western Climate Initiative (WCI). B.C.'s Finance Minister also stated at the end of October that the Province was examining the option of a carbon tax. Quebec is the only North American jurisdiction with such a tax at present.
On April 24th of this year, B.C. announced that it would join the Western Regional Climate Action Initiative (WRCAI), now the WCI. The WRCAI was formed in February 2006 by California, Arizona, New Mexico, Oregon and Washington State. Utah joined in May 2007 and Manitoba joined in June 2007, while Quebec, Ontario and Saskatchewan are now observers.
Under the WRCAI, B.C., Manitoba and the six U.S. states agreed to set an overall regional GHG reduction goal by August 2007. The WRCAI members also agreed to complete the design of a "regional market-based multi-sector mechanism" by August 2008 to meet the WRCAI's regional GHG goal. Now the WCI, its members have agreed on a goal of 15% below 2005 levels by 2020 as a minimum level to which all members must adhere.
In addition, the WCI's members have agreed to participate in a multi-state/ provincial GHG registry, which will serve, according to the MoU, "to enable tracking, management, and crediting for entities that reduce GHG emissions, consistent with state GHG reporting mechanisms and requirements". In May, B.C. became a member of The Climate Registry, along with the other 6 WRCAI members who are among approximately 37 participating states, and the Provinces of Manitoba and Quebec, as well as two American Indian tribal governments and the Mexican state of Sonora. In August 2007, the remaining Canadian provinces and three territories agreed that they would join The Climate Registry. The Registry will provide a common entity-level GHG measurement, reporting and verification system to support the WCI and other initiatives, and will begin accepting data in January 2008.
In the Premier's September 28th announcement, Premier Campbell also stated that a BC Carbon Trust will be established in early 2008 to invest in project-based GHG reductions (i.e. offsets). For every tonne of GHG emissions resulting from official government travel, the Province will invest $25 in a new BC Carbon Trust. Investment in the BC Carbon Trust will "also be open to individuals, companies and other levels of government", which may suggest that those included in future sector-specific GHG regulations will be able to invest in the Trust for compliance purposes. It is not clear if offsets associated with the BC Carbon Trust will be tradable or if other types of offsets will be permitted. Examples of potentially eligible projects provided are energy efficiency, renewable energy and afforestation projects.
During the visit of Governor Schwarzenegger to Canada, the Premier signed a memorandum of understanding between B.C. and California, committing B.C. to adopt California's low carbon fuel standard (LCFS). This standard has not yet been published in detail. Rather, an Executive Order (EO) establishes a statewide goal to reduce the "carbon intensity" of California's transportation fuels by at least 10 percent by 2020. Under the EO, the LCFS, to be developed through a collaborative process between various California agencies and the University of California, will apply to "all refiners, blenders, producers or importers" of transportation fuels, and "shall be measured on a full fuels cycle basis". The latter has raised concerns that the LCFS could discourage shipments of heavier oil from Western Canada, while encouraging imports. B.C. has also said it will legislate this standard. Ontario has also committed to adopting the LCFS.
Unlike Ontario, Premier Campbell also committed B.C. to adopt California's GHG tailpipe regulations during Governor Schwarzenegger's visit to Canada. California's current regulations establish fleet average emission standards for weight-based categories of vehicles over the 2009 to 2016 model years, are applicable to both vehicles produced and delivered for sale in the State, and are expressed on a grams per mile of CO2 equivalent basis. In B.C., standards consistent with those of California would apply to all new vehicles sold in the Province over that period. B.C.'s Premier announced on September 28th, 2007 that these standards will be enacted into law in spring 2008.
If these standards are not adopted by neighbouring provinces or the federal government, purchases by B.C. residents of non-compliant vehicles outside the province could weaken this policy approach. It should be noted that California's GHG tailpipe standards are currently being challenged in U.S. federal court. The first decision in one of these cases was made in September 2007 by a federal district court in Vermont, ruling in favour of regulations for GHG emissions from motor vehicles enacted by Vermont based on those in California.
In addition, the State's regulations require a waiver of federal preemption to be issued by the U.S. Environmental Protection Agency's Administrator under the U.S. Clean Air Act. California has stated that it will litigate the matter itself, if the waiver, requested on April 26th of this year, is not granted within six months and a day of that request.
On October 29, 2007, B.C. announced that it was joining a number of European Union countries, Northeastern U.S. states that are members of the Regional Greenhouse Gas Initiative (RGGI) and its fellow WCI jurisdictions, including Manitoba, to form an International Carbon Action Partnership. In total, more than 15 governments are signatories. The Partnership is open to jurisdictions that have established caps and will "share best practices on strategies such as the development of compatible global carbon trading systems" as well as exchange ideas and new technologies. According to Premier Campbell, the Partnership "ultimately will lay the foundation for compatible market-based systems to trade carbon offsets and credits worldwide".
Since May 2007, the Province has also signed bilateral climate change agreements with California, Oregon, Washington State and Manitoba.
The targets set out above for B.C., while outside the Kyoto Protocol timeframe, are significantly deeper than those announced by the federal government. For the latter, short term intensity targets are predicted to stabilize and then reduce emissions in absolute terms from 2006 levels between 2010 and 2012. The federal government has stated a mid-term target for Canada of 20% below 2006 levels by 2020, which translates to 3% above 1990 levels, and a long-term target of 60 to 70% below 2006 levels by 2050. B.C. will use 2007 as its baseline.
B.C.'s ambitious GHG targets may be challenging to reconcile with its growing role as a producer of oil and gas, and its growing and sought after role as a principal point of arrival and departure for Pacific markets, including for both its own fossil fuel production and that of neighbouring Alberta. Nonetheless, the elements of a detailed plan are now beginning to emerge.
Quebec announced North America's first carbon tax in June, 2007. The tax applies to all hydrocarbons used in the province based on carbon content. The tax will be 0.5 cents per litre for propane, 0.8 cents per litre for gasoline, 0.9 cents per litre for diesel, 0.96 cents per litre for light heating oil, 1.3 cents a litre for coke used in steel making and $8 a tonne for coal. Three companies, Petro- Canada, Ultramar and Shell, operate refineries in Quebec, and the province has approximately 1,500 gasoline retailers. The tax will come into force on October 1st, 2007, and is expected to largely be passed on to consumers. The tax is also expected to raise $200 million a year to finance Quebec' 2006 climate change plan: Québec and Climate Change: A Challenge for the Future (the Plan) (http://www.menv.gouv.qc.ca/ changements/plan_action/2006-2012_ en.pdf ) and finance public transit.
Quebec's climate change plan commits Quebec to meet the targets set out for Canada in the Kyoto Protocol, i.e. 6% below 1990 levels on average between 2008 and 2012 (although the plan states "by 2012"). It outlines measures such as increased hydro and wind power generation, requiring speed limiting devices on trucks, implementation of a regulation that would require the "management" of methane emissions from landfills, and new standards applicable to cars sold in Quebec that will aim to achieve "results…similar" to regulations in California for GHG emissions. Quebec states that it will negotiate voluntary agreements with industrial sectors to control GHG emissions, rather than use regulations, and expresses interest in having Quebec entities participate in emissions trading systems. It is not stated clearly in the Plan whether the agreements would be entered into voluntarily but form binding commitments (i.e. "regulatory covenants").
Quebec currently has observer status in the Northeastern States' Regional Greenhouse Gas Initiative (RGGI) and is an observer in the Western Climate Initiative (WCI). All Canadian provinces and territories have agreed to join The Climate Registry, which will provide common entity-level measurement, reporting and verification system for most of North America. Quebec became the third Canadian province to officially join at the end of October.
(http://www.gnb.ca/0009/0369/0015 /0002-e.pdf) (the "New Brunswick Plan") sets a target of reducing the Province's GHG emissions to 1990 levels by 2012, and to 10% below 1990 levels by 2020 consistent with a target set by the New England Governors and Eastern Canadian Premiers ("NEG/ECP") in its Climate Change Action Plan 2001 (the "NEG/ECP target"). The New Brunswick Plan includes a variety of primarily nonregulatory actions in the following areas: Renewable Energy and Energy Efficiency; Transportation; Waste Reduction and Diversion; Industrial Sources; Government Leading by Example; Adaptation; and Partnerships and Communication. Specific initiatives include implementing standards for appliances and equipment set at Energy Star levels, wherever possible, requiring speed limiting devices on trucks, requiring 5% ethanol in gasoline and 5% biodiesel in diesel fuels and heating oil sold in the Province, and encouraging landfill methane capture projects. New Brunswick currently has observer status in the RGGI. All Canadian provinces and territories have agreed to join The Climate Registry, which will provide common entity-level measurement, reporting and verification system for most of North America.
Nova Scotia has established a target in legislation, the Environmental Goals and Sustainable Prosperity Act, which entered into force June 7, 2007, which includes principles, objectives and goals related to climate change, as well as provisions authorizing the Province to enact regulations, enter into sectoral and intergovernmental agreements, and establish programs and other measures related to climate change. The Act provides for a target of at least ten per cent below 1990 levels by 2020 consistent with the NEG/ECP target for 2020.
Newfoundland and Labrador's Climate Change Action Plan 2005 does not include any targets, however, an August 2007 Council of the Federation publication (an interprovincial and territorial body) states that Newfoundland and Labrador is committed to the NEG/ECP target. Newfoundland and Labrador is now Canada's leading producer of off shore oil and gas.
Prince Edward Island appears to be the only province that has not released a climate change plan (it had a climate change "business plan" but its last effective year was 2003 and it does not appear that anything replaced it). GHG However, a provincial Special Legislative Committee on Climate Change has produced A Climate Change Strategy for Prince Edward Island which has been subject to consultations but has not yet been adopted by the government. PEI has a number of relevant initiatives underway including a wind-hydrogen production facility.
Manitoba's environmental plan, Green and Growing (http://www.gov.mb.ca/ greenandgrowing/green.pdf ) (the Plan) stated that the Province would meet and exceed targets as set out for Canada in the Kyoto Protocol. The Plan describes initiatives such as increasing hydroelectric production and transmission, a new Provincial energy saving target, increasing wind power production, expanded financing for geothermal or ground source heat pumps for home owners, an already legislated 10% ethanol mandate contingent on local production, and methane and biogas capture. Manitoba set more specific targets in its 2002 plan Kyoto and Beyond (http://www.gov.mb.ca/ est/climatechange/pdfs/final-mccapsep- 16-02.pdf ), where the Province stated its intention to surpass Canada's Kyoto Protocol target by 2010. In a publication released in August 2007, Manitoba's target is now indicated as "below 1990 levels by 2012", still a more ambitious target than most. Manitoba is collaborating with the Canadian Standards Association and Canadian Climate Exchange to establish a "recognized carbon credit registry in Manitoba" that could fill a much needed niche to enable regulatory and voluntary GHG systems in North America to link to one another. Manitoba has also joined the International Carbon Action Partnership described above.
Saskatchewan's 2007 Energy and Climate Change Plan sets the following targets (the Plan: http://www.saskatchewan. ca/adx/aspx/adxGetMedia.aspx?DocI D=406,340,48,Documents&MediaID =493&Filename=The+Saskatchewan+ Energy+and+Climate+Change+Plan .pdf ):
The Plan sets out "five wedges" to achieve its targets: (1) conservation and efficiency, (2) carbon capture and storage for the oil and gas and electricity sectors, (3) increased use of renewable electricity and fuels and hydrogen, (4) the reduction of methane and other emissions in the oil and gas sector and nitrous oxide emissions from agriculture, and (5) the creation of more forest and soil-based carbon sinks. Specific initiatives cited would "[e]nsure" all of SaskPower's new and replacement generation electricity units "are either emissions-free or fully offset by emission credits", develop E-85 corridors across Saskatchewan and Canada, and increase the percentage of biofuels in gasoline and diesel. The Province proposes to create a provincial offsets system and technology fund to prevent capital from leaving the Province as a result of federal GHG regulations. The Plan does not propose that Saskatchewan regulate major emitters itself.
Saskatchewan is home to one of the world's few large scale carbon storage projects (http://www.ieagreen.org.uk/glossies /weyburn.pdf). The site at Weyburn combines the storage of carbon captured in North Dakota with enhanced oil recovery at a veteran oil field in the Province (EOR). SaskPower has been considering whether to proceed with a globally significant $2-billion clean coal plant that would capture and store over 90 per cent of GHG emissions, control a wide range of pollutants and facilitate EOR (http://www.saskpower.com/cleancoal/ index.html). It was decided not to proceed this year, although the decision will be reviewed again next year. All provinces and territories have agreed to join The Climate Registry. Saskatchewan is also an observer in the Western Climate Initiative (WCI).
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1 See http://www.ec.gc.ca/4F2292E9-3EFF-48D3-A7E4-CEFA05D70C21/techbrief_e.pdf at pages 15ff .
2 The SGER refers to "the director", but "Alberta Environment" is used here throughout the document for convenience.
3 Under the SGER, "year" means a calendar year unless otherwise specified.
4 In the formula, "NEI" means net emissions intensity for the facility; "THYE" means total half year emissions from the facility; "EO" is allowable emission offsets applied by the person responsible; "FC" is allowable fund credits applied by the person responsible; "EPC" is allowable emission performance credits applied by the person responsible; and "P" means production for the period from July 1, 2007 to December 31, 2007.
5 In the formula, "TAE" means total annual emissions from the facility." All other terminologies have the same meaning as they have in Formula NEI 2007, defined in the note above.
3 Under the SGER, "year" means a calendar year unless otherwise specified.
4 In the formula, "NEI" means net emissions intensity for the facility; "THYE" means total half year emissions from the facility; "EO" is allowable emission offsets applied by the person responsible; "FC" is allowable fund credits applied by the person responsible; "EPC" is allowable emission performance credits applied by the person responsible; and "P" means production for the period from July 1, 2007 to December 31, 2007.
5 In the formula, "TAE" means total annual emissions from the facility." All other terminologies have the same meaning as they have in Formula NEI 2007, defined in the note above.