Canada is a signatory to the Paris Agreement, negotiated at the United Nations Conference of the Parties (“COP 21”) in December of 2015. As part of its commitment, Canada confirmed that it will reduce its greenhouse gas (“GHG”) emissions by 30 per cent below 2005 levels by 2030.  On October 3, 2016, as part of the debate on a motion to support ratification of the Paris Agreement, the Prime Minister announced that Canada would implement a minimum price on carbon of $10/tonne throughout the country beginning in 2018. The price would increase by $10/tonne per annum to $50/tonne by 2022.

Although the Paris Agreement is a federal commitment, Canada will be relying on each of the provinces to enact appropriate climate change policies to achieve compliance. Indeed, during his carbon pricing announcement, the Prime Minister confirmed that Canada’s carbon pricing policy would only apply in those provinces and territories that did not otherwise put a direct price on carbon or establish cap-and-trade system stringent enough to meet the federal target.

Because of the importance of provincial GHG regimes and policies, this article describes the various regimes applicable in each of the ‘Big-Five’ provinces of British Columbia, Alberta, Saskatchewan, Ontario and Quebec, which collectively account for over 90 per cent of Canada’s GHG emissions.¹ This article also briefly describes the impact that the implementation of the various GHG regimes are having on each of the Big Five’s energy supplies and the costs of electricity associated with the transition to renewable energy production.

BRITISH COLUMBIA

In 2008, the British Columbia (“B.C.”) government took up the climate change challenge by setting specific GHG reduction targets and implementing the framework of a regime to achieve these goals. The government legislated that GHG emissions must be: at least 33 per cent less than 2007 levels by 2020; and 80 per cent less than 2007 levels by 2050.²

To help achieve these goals, the government created a number of legislative and policy measures including a carbon tax and the first stages of a cap and trade framework.  Since 2012, the carbon tax has been set at $30 per tonne of carbon dioxide equivalent emissions (“CO_2e”).³ This results in a tax that differs depending on the type of fuel and the anticipated carbon emissions (e.g., $5.70 per cubic metre of natural gas or $62.31 per tonne of high heat value coal).⁴ The tax is applied to most carbon-based fuels including gasoline, diesel, natural gas, heating fuel, propane, and coal, as well as certain combustibles including peat and tires when used to produce heat or energy. The B.C. government also introduced the first stages of a cap and trade framework, which included the requirement to report GHG emissions, although it did not implement any cap on emissions or legislate the trading of emission credits.⁵

Since January of 2016, there have been three significant developments in the GHG regulatory regime in B.C. First, the Greenhouse Gas Industrial Reporting and Control Act (“GHG Act”)⁶  came into force, which marked a significant shift in the province’s approach to GHG emissions. Second, the B.C. government released the Climate Leadership Plan (“2016 BC Plan”),⁷ which sets out the government’s current vision and action plan for attaining the legislated reduction targets. Third, the federal government approved the Pacific NorthWest LNG project (“PNW”) located near Prince Rupert B.C. The federal government’s approval included, for the first time, a maximum cap on annual project-specific GHG emissions.

GHG Act

On January 1, 2016, the GHG Act and its associated regulations came into force, which signaled a shift away from the previously proposed cap and trade system and aligned B.C. with the emissions intensity⁸ approach taken by Alberta.

The GHG Act creates intensity-based GHG emission performance standards for prescribed industrial facilities and sectors. Performance standards are currently in place for liquefied natural gas (“LNG”) facilities. The emissions intensity benchmark for LNG facilities is 0.16 tonnes of CO_2e per tonne of LNG produced. The benchmark for coal-based electricity generation operations, while not yet in force, will be zero tonnes of CO_2e, which effectively prohibits these operations in B.C.

Under the new GHG reporting framework, industrial operations must continue to report and, where applicable, verify GHG emissions as they have since 2010. Specifically, industrial operations located in B.C. and emitting 10,000 tonnes of CO_2e or more per year must report their GHG emissions. Industrial operations emitting 25,000 tonnes or more of CO_2e per year must have their emissions reports verified by an accredited third party.

The GHG Act also broadens available alternative compliance mechanisms. If an entity cannot meet the prescribed emissions target for its facility or sector, it may apply compliance units to avoid penalties. Compliance units include offsets funded units or earned credits, which can be used or traded. Offset units, are issued by the provincial government and will be based on accepted and verified offset projects. Funded units are essentially payment of a prescribed amount per tonne of GHG into a prescribed account. Earned credits can be earned if emissions in a reporting period are less than the emissions target.

2016 BC Plan

In 2008, the provincial government published its Climate Action Plan⁹ (“2008 BC Plan”). In May 2015, the B.C. government appointed a Climate Leadership Team Panel (“Panel”) to update the 2008 BC Plan and provide recommendations to achieve the legislated GHG emissions reductions targets, while also taking into account economic growth, B.C.’s Liquefied Natural Gas Strategy, and B.C.’s Jobs Plan. The Panel’s final report was issued in November 2015 and contained 32 recommendations.¹⁰  Recommendations of note included:

• Increasing the rate of the existing carbon tax by $10/year per tonne, commencing in July 2018. Note: There were no recommendations for when the increases should end or how high the tax rate should ultimately go.
• Lowering the provincial sales tax from 7 to 6 per cent, to provide relief for consumers for increased costs arising from the program, in particular, the rising rates of the carbon tax.
• Expanding the scope of the carbon tax to apply to all GHG emission sources, including non-combustion sources (e.g. fugitive emissions from pipelines and process emissions from industrial plants).
• Implementing targeted measures to protect emissions-intensive, trade-exposed sectors.
• Establishing sector-specific GHG reduction goals for the transportation, industrial and built environment sectors.

In August 2016, the B.C. government released the 2016 BC Plan.¹¹ The 2016 BC Plan updates the 2008 BC Plan and responds, in part, to the Panel’s recommendations for climate action in B.C. The 2016 BC Plan attempts to balance the actions required to reduce GHG emissions to reach 2050 targets with the government’s policies aimed at protecting the economy.

What the 2016 BC Plan Includes

The 2016 BC Plan outlines more than 20 climate action areas that will be developed by the Province. Specifically, the 2016 BC Plan identifies action items to reduce GHG emissions under six categories: natural gas; transportation; forestry and agriculture; industry and utilities; communities and the built environment; and the public sector. Some of the action items relevant to the energy industry include:

Natural Gas Action Items

• Launching a strategy, including a new Clean Infrastructure Royalty Credit Program, to reduce upstream methane emissions by 45 per cent through the reduction of fugitive and vented emissions
• Developing regulations to enable carbon capture and storage (“CCS”) to proceed in B.C.
• Investing in infrastructure to power natural gas projects in Northeast B.C. with clean electricity

Transportation Action Items

• Increasing the Low Carbon Fuel Standard from 10 per cent by 2020 to 15 per cent by 2030 to reduce the carbon intensity of transportation fuels
• Increasing the pool of incentives available to encourage commercial fleets to switch to natural gas
• Expanding the regulatory framework to support the installation of charging stations for zero emission vehicles
• Expanding the Clean Energy Vehicle Program to encourage the use of zero emissions vehicles through new vehicle incentives and infrastructure, education, and economic development initiatives

Industry and Utilities Action Items

• Ensuring that 100 per cent of the electricity supply acquired by BC Hydro for the integrated grid be from renewable or clean sources, except where there are concerns regarding reliability or costs
• Regulatory amendments to allow utilities to provide additional incentives to help fuel marine, mining, and remote industrial power generation sectors
• Regulatory amendments to set energy efficiency requirements for new and replacement gas-fired boilers, as well as to enable further incentives to encourage the adoption of technologies that reduce emissions from gas-fired equipment

Communities and the Built Environment Action Items

• Regulatory amendments to increase efficiency requirements for gas fireplaces, air source heat pumps, and natural gas space and water heating equipment
• Implementing a number of policies to encourage the development of Net-Zero Energy buildings, including accelerating and enhancing increased energy efficiency requirements in the B.C. Building Code

With these initiatives, the government believes that it can meet its legislated target of reducing emissions by 80 per cent below 2007 levels by 2050. Of course, until the government passes laws to implement the various action items, the 2016 BC Plan will be only that — a plan, and will have no legal effect.

What the 2016 BC Plan Excludes

While the 2016 BC Plan includes a number of the Panel’s recommendations, it did not address some of the Panel’s more significant and controversial recommendations. As such, what is most noteworthy is not what is in the 2016 BC Plan, but what is omitted. Panel recommendations that were not addressed in the 2016 BC Plan include:

1. Increase in Carbon Tax – The carbon tax rate has been at $30/tonne since 2012. The Panel recommended an increase in the carbon tax rate by $10/year commencing in 2018 and expanding the scope of the tax to include all emissions (i.e. including fugitive and process emissions from natural gas, coal mining, and cement and metal production). The government responded to the Panel’s recommendation by stating that now is not the time to consider increasing the carbon tax when other provinces and the federal government are implementing carbon pricing policies and “catching up” to B.C.’s lead.
2. Interim GHG Emission Targets – The Panel recommended that the government set an interim 2030 GHG target. The Panel also recommended sectoral emission reduction targets. These recommendations were not addressed in the 2016 BC Plan.
3. Environmental Assessment – The Panel recommended amending the provincial Environmental Assessment Act¹² to include the social cost of carbon in the environmental assessment process. This was also not included in the 2016 BC Plan.

The government has promised to update the 2016 BC Plan over the next year in response to work underway between the federal government and the provinces in regard to a national approach to climate action. The 2016 BC Plan is therefore only a “first step” and recommendations from the Panel’s report may ultimately find their way into an updated plan.

PNW

On September 27, 2016, the federal government approved the PNW subject to over 190 legally binding conditions. At full production, PNW will receive approximately 9.1 x 10⁷ cubic metres per day of pipeline grade natural gas and produce up to 20.5 million tonnes per annum of LNG for over 30 years.¹³

The federal government’s approval of PNW includes a maximum cap on annual project GHG emissions. Specifically:

• At the commissioning of Train 2, PNW must have an annual average emissions intensity of less than or equal to 0.22 tonnes of CO_2e per tonne of LNG produced and shall emit no more than a total of 3.2 million tonnes of CO_2e per calendar year.
• At the commissioning of Train 3, PNW must have an annual average emissions intensity of less than or equal to 0.21 tonnes of CO_2e per tonne of LNG produced and shall emit no more than a total of 4.3 million tonnes of CO_2e per calendar year.

PNW must also implement mitigation measures during all phases of the project to reduce and control air emissions and GHG emissions.

Industry Implications

These recent GHG-related developments have a number of implications for B.C. industry, particularly the energy industry.

First, commentators have noted that the carbon tax has been effective at reducing GHG emissions in B.C. However, the tax has also had a significant adverse impact on industries that are energy-intensive and trade-exposed, such as the cement industry.¹⁴

Second, there has been a greater emphasis on clean, renewable energy throughout the province. However, given that 98 per cent of B.C.’s power generation portfolio currently comes from clean or renewable resources, including hydro,¹⁵ this has not resulted in a significant change in renewable energy development or in energy prices. The B.C. government has also been careful to ensure that this shift towards renewable energy does not discourage the development of LNG projects in the province. For example, the government amended its initial objective of generating at least 93 per cent of electricity from clean or renewable resources to exclude electricity necessary to service demand from LNG facilities that will liquefy natural gas for export by ship.¹⁶

Third, in the future, proponents of large industrial facilities, including LNG facilities, should anticipate caps on their GHG emissions as the provincial and federal governments attempt to meet their respective GHG emission reduction goals. This will likely ensure the continued emphasis on, and use of, renewables in B.C. for years to come.

ALBERTA

Alberta’s GHG regulatory regime has been in place since July of 2007, which makes it the oldest GHG regulatory regime in North America. The regime is set out in the Climate Change and Emissions Management Act¹⁷ and regulations thereunder, the most notable being the Specified Gas Emitters Regulation (“SGER”).¹⁸ It is an emissions intensity regime and is predicated upon a facility becoming more carbon efficient over time. Pursuant to the SGER, any facility that emits greater than 100,000 tonnes of CO_2e/annum (“large emitter”) is required to reduce its emissions intensity as compared to its baseline intensity¹⁹ by 15 per cent. The emissions intensity reduction as compared to a facility’s baseline will increase to 20 per cent on January 1, 2017.

Regulatory Compliance

A large emitter can comply with the emissions intensity reduction requirements under the SGER in the following four ways:

1. Meeting the emissions intensity reduction requirements by increasing its efficiency of production as compared to its baseline through operational and process changes;
2. Purchasing emissions performance credits (“performance credits”);
3. Purchasing emissions offset credits (“offsets”) from facilities that are not large emitters; or
4. Contributing to the climate change and emissions management fund (“Fund”).

Performance credits arise in circumstances where a large emitter exceeds its required emissions intensity reduction requirements through operational efficiencies. The excess reductions or performance credits can then be sold to other large emitters that cannot otherwise meet their respective compliance obligations.

Offsets are generated by Alberta facilities that are not large emitters and not otherwise required to reduce emissions by operation of law. The offsets must be real, demonstrable and quantifiable as described in an accepted offset protocol, and can include CCS. Offsets arise when an activity or process is undertaken that generates less CO_2e than the average or accepted norm for that activity or process. A simple example is electricity generated from a wind-turbine. Alberta has a calculated average of CO_2e emissions per unit of electricity. Wind-turbines generate electricity in a manner that emits less CO_2e than the average. The difference, or delta, can be sold as offsets. Indeed the ability to sell both the electricity generated from a wind-project as well as the offsets generated from the same project may be the only reason that certain wind-projects are financially viable. Alberta currently has 34 approved offset protocols covering activities and processes as disparate as aerobic composting to electrical production to bio fuels to energy efficiency in commercial buildings.

The Fund monies are segregated from other government monies and used for projects that reduce GHG emissions and adapt to climate change. Between July of 2007 and 2015 the costs of contributing to the Fund was set at $15/tonne of CO_2e. In January of 2016 the Fund costs increased to $20/tonne and are set to increase to $30/tonne in January of 2017. Since July of 2007, approximately $740 million has been contributed to the Fund by large emitters. Because a large emitter can contribute to the Fund as a means of meeting all of its compliance requirements, the price of the Fund essentially dictates the maximum value a large emitter will pay for a performance credit or an offset. The recent increase in the Fund price from $15 to $20 in 2016 and the further increase to $30 set for 2017 has positively and significantly impacted the value of renewable energy offsets, which in turn have had a positive impact on the financial viability of renewable energy projects.

Criticisms of the existing SGER regime have included the following:

• The regime is too Alberta-centric, particularly with respect to the requirement that offsets must be Alberta-based.
• The Fund price is too low, although with the recent increase to $20/tonne and the future increase to $30/tonne, presumably this criticism will wane.
• The lack of any restriction on Fund contributions. In other words there is no requirement for a facility to undertake any efficiency upgrades. Rather a facility can continue to meet its efficiency obligations solely by contributing to the Fund.
• No absolute cap on emissions.
• The regime is too restricted in scope and does not target all contributors, particularly consumers.

Climate Leadership Plan

In the fall of 2015 Alberta released its Climate Leadership Plan (“AB Plan”). Once fully implemented, it will significantly change numerous aspects of Alberta’s existing climate change regime. Highlights include:

• Early phase-out of coal-fired power plants, which are amongst the most significant GHG emitters
• Replacement of the emissions intensity regime with product-based emissions performance standards
• Expansion of the program of only targeting large emitters, to a wide array of small and large emitters as well as consumers through the implementation of a broad-based carbon levy
• Capping oil sands emissions at 100 megatonnes
• Targeting methane emissions in the oil and gas sector
• Renewed focus on energy-efficient initiatives

Alberta currently obtains approximately 51 per cent of its electrical generation from coal-fired power plants. Pursuant to the AB Plan, GHG emissions from these plants will be completely phased out by 2030, with approximately 2/3 of the electrical generation to be replaced by renewable energy. This is a significant change. Not only will it dramatically change the electricity supply mode within Alberta, it will necessitate significant electrical transmission changes as the Province struggles with the siting of renewable energy projects in areas that may or may not be close to existing transmission infrastructure.

Another component of the AB Plan involves the replacement of the current emissions intensity program with product-based emissions performance standards. Under an emissions performance standard, facilities will be compared to a product-specific emissions standard, rather than an historic facility-specific standard. Facilities that cannot meet the emissions performance standard will be subject to a carbon levy. As of January 1, 2017, the levy will be $20/tonne of CO_2e. That amount will increase to $30/tonne as of January 1, 2018. The anticipated effect on businesses is that it will drive best-in-class performance. As for consumers, the $30/tonne levy is expected to translate into additional fuel costs of approximately $1.5/gigajoule of natural gas, 6.7 cents/litre of gasoline, 8.0 cents/litre of diesel and 4.6 cents/litre of propane. In an approach similar to that of B.C., the Alberta government has elected not to increase the carbon levy above $30/tonne until the economy becomes stronger and the actions of other jurisdictions, including the federal government, are better known.

A further key component of the AB Plan is its broad application. The existing regime only applies to large emitters, which account for approximately 45 per cent of provincial GHG emissions. Once fully implemented, the Plan is expected to cover approximately 78-90 per cent of provincial GHG emissions, including large emitters, small emitters and consumers.

In what appears to be a direct response to criticisms that Alberta hasn’t done enough to restrict GHG emissions in the oil sands sector, the AB Plan contemplates an absolute annual emissions cap of 100 megatonnes of GHG from oil sands production. Currently, oil sands emissions account for approximately 70 megatonnes of GHGs per annum. By transitioning to performance-based standards, coupled with the implementation of a legislated emissions cap, it is expected to create the conditions for continued oil sands growth in a manner that rewards innovation and enables oil sands producers to remain globally competitive. As stated by Alberta’s Premier Notley when she outlined the AB Plan:

The simple fact is this: Alberta can’t let its emissions grow without limit. But we can grow our economy by applying technology to reduce our carbon output per barrel. And that is what this limit will provide.

The AB Plan will also include provisions for recognition of new upgrading and co-generation in the oil sands sector. Alberta’s existing regime has been criticized for not directly addressing the benefits of co-generation (coupling energy production with heat production).

The AB Plan specifically targets methane emissions, particularly in the oil and gas sector. Under the AB Plan, methane emissions from oil and gas operations are anticipated to decrease by 45 per cent. The reduction will occur through the application of emissions design standards on all new facilities coupled with the development of a joint methane reduction initiative, which will include industry, environmental groups and indigenous communities.

The final aspect of the AB Plan involves a renewed focus on energy efficiency. Details of the program are anticipated to be released in 2017.

Notwithstanding the AB Plan’s multi-faceted approach to GHG regulation, it is interesting to note that it does not encompass any interprovincial or international cap-and-trade measures. This means that Alberta will remain isolated from any of the cap-and-trade regimes that other provinces, such as Ontario and Quebec, have signed onto. The AB Plan represents a made-in-Alberta approach in response to an Alberta problem. Whether or not remaining isolated from other jurisdictions will be beneficial to Alberta in the long term is unclear.

Transitioning to a Renewable Electricity Program

In March of 2016, as a result of the AB Plan, the Alberta government tasked the Alberta Electric System Operator (“AESO”), the independent system operator for Alberta’s electricity system, with developing and implementing a renewable electricity program (“REP”) that would increase the province’s renewable energy generation capacity as a percentage of total generation capacity from 11 per cent to 30 per cent by 2030.

The AESO provided its recommendations regarding the REP to the province at the end of May, 2016. Although the recommendations regarding the REP are not yet public, the AESO has provided some indications as to what those recommendations entail. More particularly, it is expected that:

1. The REP will involve a fuel neutral competitive auction process with the first auction competitions for renewable energy projects to be held in late 2016 with anticipated project in-service dates of 2019. The fuel-neutral concept is predicated upon the concept that no particular renewable electricity method is preferred over another;
2. The REP will fit within Alberta’s existing deregulated competitive electricity market. In that regard it is unlikely that Alberta will adopt a feed-in tariff (“FIT”) program that has been implemented in other jurisdictions, notably Ontario; and
3. AESO’s recommendations will generally follow those set out in the Alberta Climate Leadership Panel report (“Report”),²⁰ which was released just prior to the Plan, and upon which the Plan is based. One of the critical aspects of the Report is the proposed purchase of a project’s renewable energy certificates (“RECs”) by the government.  In essence, as a means of supporting renewable energy projects, the government will purchase a project’s RECs pursuant to long-term contracts.

Despite the specifics of the REP remaining unclear, beginning in late 2016 it appears that renewable energy producers will have an additional choice of markets for their environmental attributes. They will still be able to sell them as offsets. As an alternative, if successful at the 2016 auction competition (or any subsequent auctions), they will be able to sell them under long-term purchase contracts to the government of Alberta (“Government-Purchased RECs”). In order to limit the government’s exposure to high costs of support, the Report recommends a ceiling price for the Government-Purchased RECs of, at most, $35 per megawatt hour (“MWh”) which is roughly equivalent to $90/tonne CO_2e premium over natural gas generation under Alberta’s current system.

While the REP will obviously lead to increased renewable energy generation, its effect on electricity prices remains unclear. The average electricity pool price in Alberta decreased by 33 per cent from 2014 to 2015. The effect on electricity prices of transitioning from a jurisdiction where over 50 per cent of its electrical generation comes from baseload coal production to one that is much more highly dependent on renewable energy production, with no guaranteed electrical energy production levels, is unknown. Further, the costs of resolving the infrastructure challenges and the financial implication surrounding the lack of guaranteed energy supply that are associated with renewable energy production are also unknown.

SASKATCHEWAN

With just over 3 per cent of Canada’s population, emissions from Saskatchewan account for over 10 per cent of Canada’s total, making it the largest provincial emitter on a per capita basis.²¹

Despite the significant impact of Saskatchewan emissions on a national level, the province currently neither regulates emissions nor imposes any legislated emissions reductions targets. While the Saskatchewan Premier has admitted that the province needs to do better in terms of its record on climate change, he has consistently taken the position that climate change policies must be designed with the economy in mind.²²

With a view to limiting the impacts on its emissions-intensive economy, Saskatchewan’s climate change policies have primarily focused on technological developments, specifically CCS and support for the development of renewable energy sources.

Emissions management legislation: On hold since 2010

By 2010, Saskatchewan had made significant progress towards the development of a provincial climate change strategy, and had even passed legislation regulating GHG emissions. Pursuant to the Management and Reduction of Greenhouse Gases and Adaptation to Climate Change Act (“Sask CC Act”),²³ “regulated emitters” would be required to reduce their annual GHG emissions by a prescribed amount relative to a baseline in order to collectively meet the provincial emissions reduction target. At the time the legislation was passed, Saskatchewan had adopted a GHG emissions reduction target of 20 per cent below 2006 levels by 2020.²⁴

“Regulated emitters,” were facilities that emit 50,000 tonnes or more of CO_2e annually. Failure to comply with reductions would result in the requirement to make a carbon compliance payment (anticipated at the time to be set at $15 per tonne of CO_2e). The Sask CC Act also contemplated the development of alternative compliance mechanisms for regulated emitters including certified investments in a technology fund, recognition for early action, credits for emission intensive or trade-exposed industries, and the ability to purchase carbon offsets.

The Sask CC Act was passed and received royal assent in 2010. However, it has yet to be proclaimed, and there is no indication that the Government of Saskatchewan intends to bring this legislation into force in the near future. With the exception of a legislated minimum 7.5 per cent ethanol content in gasoline (prescribed by the Ethanol Fuel Act)²⁵ and regulatory requirements for the reduction of flaring and venting associated gas during upstream oil and gas operations (pursuant to Directive S-10: The Saskatchewan Upstream Petroleum Industry Associated Gas Conservation Standards),²⁶ Saskatchewan’s action on climate change has largely been limited to policy rather than legislative action.

CCS

Approximately 46 per cent of Saskatchewan’s electricity comes from coal-fired generation.²⁷ Unlike provinces such as Alberta and Ontario, Saskatchewan does not have plans to phase out its use of coal. It has, instead, focused on the development of CCS technology, and the use of that technology to retrofit coal-fired generation facilities in the province.

On October 2, 2014, the Boundary Dam Integrated CCS Project (“ICCS Project”), located at the Boundary Dam Power Station near Evanston, Saskatchewan, became operational. The ICCS Project was initiated in 2008 in response to proposed federal regulations that required coal-fired generation units that are new, or that have reached the end of their useful life, to emit no more than 420 tonnes of CO_2e per gigawatt hour.²⁸ The $1.47 billion²⁹ government-industry partnership between the Government of Canada, Government of Saskatchewan, SaskPower, and private industry involved the retrofitting of Unit #3 at the coal-fired Boundary Dam Power Station with a system for capturing CO₂, SO₂ and nitrous oxides. The captured CO₂ is sold to Cenovus Energy, who uses it for enhanced oil recovery operations. The ICCS Project is acknowledged as the world’s first full-scale coal CCS project, and represents a significant achievement for Saskatchewan.

SaskPower, Saskatchewan’s provincially-owned utility that operates the ICCS Project, has reported that the project produces 110-megawatts (“MW”) of power while eliminating SO₂ emissions, reducing CO₂ emissions by 90 per cent, and capturing up to 1 million tonnes of CO₂ annually. However, the ICCS Project has been the subject of significant criticism. Downtime required for maintenance has limited operations of the project to 40 per cent of its capacity, which has in turn prevented SaskPower from producing its contracted volume of CO₂ for sale to Cenovus Energy, which purchases the CO₂ at a cost of $25 per tonne. In addition to lost sales, SaskPower has been required to pay approximately $12 million in penalties to Cenovus Energy. This has contributed, at least in part, to SaskPower requests for multiple consumer electricity rate increases since 2014.³⁰ In order to mitigate additional losses, SaskPower renegotiated its CO₂ supply contract with Cenovus Energy in June 2016.³¹

Notwithstanding these challenges, the provincial government remains optimistic about CCS technology. SaskPower opened a CCS test facility at the Shand Power Station in June 2015, which provided CCS technology developers with an opportunity to test their processes at a commercial power plant. In order to avoid having to close Units 4 and 5 of the Boundary Dam Power Station pursuant to federal regulations, the Saskatchewan government is considering whether to retrofit those aging units with CCS, and expects to make a decision in this regard before the end of 2017. Further, in June 2016, the Premiers of Saskatchewan and Quebec signed a memorandum of understanding pursuant to which their respective provincial governments agreed to accelerate the development and deployment of CCS technologies, exchange updates and information on CCS projects and technologies, and work together to explore further collaborations in relation to CCS.

SaskPower has stated that, with learning-by-doing from the ICCS Project, it could likely achieve $200 million in cost savings on a similar plant. However, it has been estimated that the ICCS Project will generate a loss of approximately $1 billion over its lifespan, which could cost Saskatchewan ratepayers up to $750 million over 30 years.³² Alternatively, if investments are not made to significantly reduce emissions, it will be necessary to retire the majority of coal-fired generation in the province pursuant to federal regulatory requirements.³³ Units 4 and 5 of the Boundary Dam Power Station, which account for 278-MW of generation, will reach the end of their 50-year useful life at the end of 2019, and an additional 886-MW of coal-fired generation must be retired by 2029 if investments in CCS are not made.³⁴

SaskPower’s 50 per cent Renewable Energy Target

In November of 2015, SaskPower announced its commitment to achieving 50 per cent renewable energy capacity by 2030. This will involve doubling Saskatchewan’s renewable energy capacity in 15 years.

Approximately 25 per cent of Saskatchewan’s generation capacity currently comes from renewable sources: 20 per cent from hydro and 5 per cent from wind. The Minister responsible for SaskPower has stated that doubling renewable energy capacity will involve “a major expansion of wind power augmented by other renewables such as solar, biomass, geothermal and hydro, to go along with the world leading Boundary Dam 3 carbon capture project and more natural gas generation.”³⁵

To the extent that the above statement represents the Saskatchewan government’s definition of “renewable,” it is notable that it differs from the Natural Resources Canada definition, which has been adopted by Alberta for the purposes of its REP. The Natural Resources Canada definition of “renewable” does not include natural gas or nuclear energy, includes only limited forms of biomass, and does not reference CCS.

In order to achieve its 50 per cent renewable target, SaskPower is generally reviewing the potential for new hydro projects, hydro power imports from other provinces, biomass, and geothermal power projects in the province. SaskPower specifically plans to develop at least 60-MW of ground-mount solar photovoltaic generation. The 60-MW is expected to consist of two 10-MW projects procured from the private sector,³⁶ two 10-MW projects developed by a SaskPower-First Nations Power Authority partnership, with community driven projects accounting for the final 20-MW. The provincially-owned utility is relying most heavily on an increase in wind power capacity to achieve its 50 per cent renewable target. Specifically, SaskPower has stated that it intends to achieve 30 per cent wind power capacity by 2030 (“Wind Capacity Target”).

The addition of new wind power capacity is already underway in the province. Three private sector projects are currently in development, representing 207-MW of new generation capacity. SaskPower has also committed to adding three 100-MW projects to the provincial grid by 2024. A competitive procurement process for the first of these 100-MW projects is anticipated to begin before the end of 2016.³⁷ The development of these projects will bring Saskatchewan’s total wind power capacity to approximately 730-MW, or 15 per cent of the province’s total generation capacity. Plans regarding how to further increase this total to achieve the 30 per cent target have yet to be finalized.

Interestingly, in comparison to the fuel-neutral approach taken by Alberta’s REP, the Saskatchewan renewables procurement program has followed the path of the Ontario Large Renewables Program by specifying a particular quantity of both solar and wind generation capacity that it intends to introduce to the grid.

On September 13, 2016, Saskatchewan had a significant setback in meeting its Wind Capacity Target when the approval of the largest of the three wind power projects currently in development was refused by the Minister of Environment.³⁸ The Chaplin Wind Energy Project is a 177-MW wind power project proposed by Windlectric Inc., a subsidiary of Algonquin Power. It was the first wind power project to undergo a provincial environmental assessment and was proximate to two internationally recognized important bird areas.³⁹ While Windlectric Inc. had proposed a number of mitigation measures to address bird mortality risks and potential impacts to migratory bird corridors (i.e. avoiding linear arrangement of turbines, feathering blades, and increasing cut-in speeds), the Environment Minister noted that these mitigations for individual components of the project could not satisfactorily address the fact that the project had been sited within a migratory bird corridor and in proximity to bird congregation areas.

The Government of Saskatchewan publically announced its refusal to approve the Chaplin Wind Energy Project on September 19, 2016, the same date on which it released guidelines for the siting of future wind energy projects in the province.⁴⁰ The Wildlife Siting Guidelines for Saskatchewan Wind Energy Projects prescribe a 5-kilometre buffer zone around environmentally sensitive areas such as national and provincial parks, ecological reserves, important bird areas and key Saskatchewan rivers. Project proponents will be required to undertake an environmental and wildlife impact assessment even if a proposed project is located outside these buffer zones.⁴¹

Windlectric Inc. is currently in the process of reviewing alternative locations for its project. The company has a 25-year power purchase agreement with SaskPower for the project’s energy output, and plans to amend that agreement as required.⁴²

At this time, it remains unclear whether Saskatchewan will reach its goal of achieving its Wind Capacity Target. While SaskPower has published procurement plans to achieve 15 per cent wind power capacity, commitments have not yet been made regarding financial support or other programs to facilitate the development of an additional required 730-MW of wind power.  Similarly, the extent to which Saskatchewan’s 50 per cent renewable energy target and likely continued investment in CCS will impact consumer electricity rates remains an open question. While the United States Energy Information Administration estimates that the total levelized cost of wind power will be less than coal by the year 2020 due to the high cost of pollution control mechanisms such as CCS,⁴³ the actual cost of wind power and its resultant impact on electricity prices in Saskatchewan remains unknown.

ONTARIO

In Ontario, there has been a gradual evolution of climate change policies. The most recent of these policies, a Five-Year Climate Change Action Plan (“ON Action Plan”) was introduced in June 2016. The interrelationship between those policies and Ontario’s energy supply systems, including Ontario’s replacement of all coal-fired electricity generation, has resulted in a significant increase in renewable electricity production in the province, coupled with significant increases in the cost of electricity.

The Greening of Ontario’s Electricity Supply Mix

It could be said that Ontario’s efforts to combat climate change began in 2005 with the closure of the coal-fired Lakeview Generating Station in order to reduce GHG emissions, and the making in 2007 of a government regulation requiring the cessation of coal-fired generation in Ontario by December 31, 2014.⁴⁴ Ontario accomplished that goal when it closed its last remaining coal-fired generator in April 2014 and became the first jurisdiction in North America to fully eliminate coal as a source of electricity generation.⁴⁵ Ontario believes that its actions in that regard represent the single largest GHG reduction action in North America.⁴⁶

Another significant step occurred with the passage of the Green Energy and Green Economy Act, 2009⁴⁷  (the “Green Energy Act”). That legislation facilitated the replacement of coal-fired generation in the province with renewable electricity generation by introducing a FIT program, and a procedure whereby renewable energy projects would only need one primary environmental approval, known as the Renewable Energy Approval, in place of various other provincial permit and municipal by-law requirements.

Ontario’s FIT program was a government process for procuring electricity from renewable sources, with standard program rules, standard contracts and standard pricing for different classes of generation facilities. The FIT program incentivized the development of renewable generation by offering stable prices under long-term contracts (generally 20 years) for energy generated in Ontario from renewable sources. Renewable sources were defined to include bioenergy (biomass, biogas and landfill gas), wind, solar photovoltaic, and waterpower.

Ontario cancelled the large FIT (generating capacity over 500 kilowatts (“kW”)) part of the program⁴⁸ in June 2013⁴⁹, and replaced it with the Large Renewable Procurement (“LRP”) program in 2014. The LRP program was a competitive process for procuring renewable electricity projects larger than 500 kilowatts, and was designed to proceed in multiple phases. Phase one concluded in April 2016 with the execution of approximately 454-MW of renewable power contracts. Ontario announced that it was proceeding with phase two of LRP (“LRP II”) in the summer of 2016. However, on September 27, 2016 the Minister of Energy issued an unexpected Directive suspending all further procurement of renewable generation under LRP and putting an end to the LRP II request for qualifications process.⁵⁰

Ontario announced that it suspended the LRP because further procurement of electricity capacity is not needed at this time. Ontario is currently forecast to have a robust supply of electricity for the next decade. The suspension of the LRP is expected to avoid additional spending of $3.8-billion in electricity system costs (reflecting approximately $2.45 per month for a typical residential electricity consumer, relative to previous forecasts).

Ontario’s efforts to develop renewable generation capacity have dramatically changed its electricity supply mix over the last decade. Ontario currently has about 18,000 MW of wind, solar, bioenergy and hydroelectricity energy contracted or in development. Renewable energy now comprises 40 per cent of Ontario’s installed capacity and generates approximately one-third of the electricity produced in the province. When combined with nuclear resources, which account for one-third of Ontario’s installed capacity and produce nearly 60 per cent of its electricity, these non-fossil sources now generate approximately 90 per cent of the electricity in Ontario.⁵¹

The changes to Ontario’s electricity supply system, including the move to renewable energy, have resulted in substantial increases in the cost of electricity in Ontario over the last decade, and public complaints regarding consumer electricity rates have similarly increased in response. When the Ontario government lost a by-election on September 1, 2016, the Premier linked the loss to public frustration over the rising cost of electricity.⁵²  It is therefore not surprising that when the government suspended the LRP, it made a point of emphasizing the cost savings associated with the decision.⁵³

After achieving a substantial reduction in GHG emissions from the generation of electricity, Ontario turned its attention to other ways in which it could reduce GHG emissions. On May 18, 2016 the Climate Change Mitigation and Low-carbon Economy Act, 2016⁵⁴  (“Ont CC Act”) was enacted. Since the passage of that legislation, Ontario has launched or expanded a series of initiatives to facilitate meeting its targeted reductions in GHG emissions, including:

• Implementation of a cap and trade regime;
• The ON Action Plan and implementation of related initiatives; and
• The proposed expansion of the Industrial Conservation Initiative (“ICI”) intended to reduce peak electricity demand and electricity costs for business.

The Ont CC Act and Regulations

The stated purposes of the Ont CC Act are to create a regulatory scheme:

• to reduce GHG emissions in order to respond to climate change, to protect the environment and to assist Ontarians to transition to a low-carbon economy; and
• to enable Ontario to collaborate and coordinate its actions with similar actions in other jurisdictions in order to ensure the efficacy of its regulatory scheme in the context of a broader international effort to respond to climate change.

The Ont CC Act establishes the following targets for the reduction of GHG emissions as compared to 1990 levels: 15 per cent by the end of 2020; 37 per cent by the end of 2030; and 80 per cent by the end of 2050.⁵⁵

The legislation also requires the Ontario Government to prepare a climate change action plan, setting out actions that will enable Ontario to achieve the targets.⁵⁶

Ontario implemented two new regulations: The Cap and Trade Program Regulation⁵⁷ (“Cap and Trade Regulation”), which took effect on July 1, 2016, and The Quantification, Reporting and Verification of Greenhouse Gas Emissions Regulation⁵⁸ (“Emissions Regulation”), which will take effect on January 1, 2017. The Emissions Regulation provide the methodology by which participants in the Cap and Trade Program will quantify and verify their emissions.

Ontario’s Cap-and-Trade Regime

The finalization of the Cap and Trade Regulation is a significant step in a process that began in April 2015, when Ontario signed an agreement with Quebec to create a joint cap and trade system to reduce GHG emissions.

Under the Cap and Trade Regulation, a facility can only emit as much carbon as it has allowances for. One allowance is equal to one tonne of CO_2e. The first compliance period will be from January 1, 2017, (when the cap and trade system begins) until December 31, 2020. The total number of allowances for all facilities (i.e. the cap) is provided in the Cap and Trade Regulation for the years 2017 – 2020 and will steadily decline each year.

A certain number of allowances will be reserved each year for free distribution to participants. Eligible participants must apply for free allowances in respect of the activities engaged in at each facility and the number allocated will be determined according to the published Methodology for the Distribution of Ontario Emission Allowances Free of Charge.⁵⁹ Allowances that are not freely distributed will be auctioned. The first auction is scheduled for March 2017. If the amount of CO_2e emitted by a facility exceeds its free allowances, it must purchase additional allowances at the auction. Similarly, facilities that emit less than their permitted allowance may sell their unused free allowances at the auction.

All of the proceeds from Ontario’s cap and trade system will be allocated to a provincial fund called the Greenhouse Gas Reduction Account and used to fund many of the initiatives under the ON Action Plan.

The cap and trade system will impose certain compliance obligations on Ontario’s natural gas distributors, including facility-related obligations for facilities the distributors own or operate, and customer-related obligations for natural gas-fired generators, and certain other residential, commercial and industrial customers. The natural gas utilities will need to develop compliance plans for fulfilling their cap and trade obligations, and they will inevitably incur additional compliance costs.

The Ontario Premier has stated that she expects residential natural gas bills to go up about $5 a month (or $60/year) as a result of the cap-and-trade system. The Premier’s prediction is somewhat lower than Union Gas’ prediction that natural gas price for homeowners will likely rise by about $70 to $80 in 2017, and that amount is likely to rise in the future.

In the electricity context, the carbon price will only be added to the price of electricity generated in Ontario to the extent that the electricity is generated from a carbon producing source. That means that the carbon price will only be added to the portion of Ontario’s supply mix which comes from natural gas-fired generation – approximately 10 per cent in 2015. The carbon price will also be applied to electricity imports to the extent that those imports were generated by fossil fuels. However, the effect on the price of imported electricity may be mitigated if electricity imports to Ontario from low GHG emitting jurisdictions such as Quebec (which produces primarily hydroelectricity) increase and imports from higher emitting jurisdictions (such as Michigan which uses coal for much of its generation) decrease.⁶⁰

It is difficult to predict how the cap-and-trade system will ultimately impact the cost of electricity in Ontario as there are many different factors in play. However, in its September 2016 Planning Outlook report, the Ontario Independent Electricity System Operator (“IESO”) suggested that the increasing cost of using fossil fuels, like natural gas (and gasoline in cars), relative to the cost of using electricity, along with Ontario’s other climate change actions, may lead to increased demand for electricity and greater electrification of the overall energy system (such as transportation).⁶¹

The ON Action Plan and Related Initiatives

The ON Action Plan builds on Ontario’s Climate Change Strategy previously released in November 2015,⁶² which set the long-term vision for meeting GHG emissions reduction targets. The ON Action Plan acknowledges that there is a need to maintain a competitive economy while achieving environmental results. This will be the biggest challenge facing Ontario as it attempts to “up the ante” in its climate change fight.

The ON Action Plan outlines other key actions Ontario is proposing to combat climate change. The goal is to use the proceeds from the cap and trade system to fund green projects and implement elements of the ON Action Plan.

According to the ON Action Plan, Ontario’s environmental and clean technology sector is made up of approximately 3,000 firms employing 65,000 people and is estimated to be worth $8 billion in annual revenue and $1 billion in export earnings. There is no doubt that this sector will grow considerably if the ON Action Plan is implemented.

The ON Action Plan outlines Ontario’s intention to take numerous actions to introduce new fiscal measures to benefit individual consumers and businesses and at the same time move towards lower emission technologies, including:

• Create a cleaner transportation system

More than 33 per cent of Ontario’s GHG emissions are caused by the transportation sector. The ON Action Plan establishes an electric and hydrogen passenger vehicles sales target of 5 per cent in 2020 (in 2015, 5 per cent of the number of cars sold was 14,000 cars). Ontario intends to work with the federal government to eliminate the Harmonized Sales Tax on zero emission vehicles and to increase access to the infrastructure for charging electric vehicles. In July 2016, Ontario announced that it will be building nearly 500 electric vehicle charging stations (“Charging Stations”), to be in service by March 2017. The proposed network of Charging Stations will allow electric vehicles to travel from the City of Windsor in the south of the province to the City of North Bay and to all the major urban centers in the province.

• Encourage installation/retrofit of clean energy systems

Ontario will seek to help homeowners reduce their carbon footprints by supporting additional choice. Ontario intends to invest $100 million from the Ontario Green Investment Fund to help homeowners purchase and install low-carbon energy technologies such as geothermal or air-source heat pumps, solar thermal and solar energy generation. Fiscal incentives will also be introduced to encourage net zero carbon homes and reduce the reliance on the use of natural gas for heating. The province has announced that it is working in partnership with Enbridge Gas Distribution and Union Gas to develop a program to help about 37,000 homeowners conduct audits to identify energy-saving opportunities and then complete retrofits, such as replacing furnaces and water heaters, and upgrading insulation.

• Keep electricity rates affordable

In response to increasing public complaints over the sharp increases in the cost of electricity over the last decade, the ON Action Plan states that Ontario intends to keep electricity rates affordable through the use of proceeds from the cap and trade system to offset the cost of GHG reduction initiatives that are currently funded by residential and industrial consumers through their electricity bills.

In its September 2016 throne speech,⁶³ the Ontario government announced measures to provide homeowners and other eligible consumers with a rebate of the 8 per cent provincial sales tax on the cost of electricity, and a plan to expand the number of businesses eligible to benefit from the ICI (discussed below).

• Establish a “green bank” to promote the use of Energy Efficient Technologies

Ontario is proposing to establish a “green bank” to promote the use of energy efficient technologies. Once established, the green bank is intended to accomplish three goals:

help households understand and determine what government grants and other incentives are available for each prospective project, and help people calculate payback periods and returns on investments;

provide households with assistance to secure flexible low-interest financing to help pay for GHG-reducing energy improvements in their homes – with special provisions to support low and modest income households; and

support large commercial and industrial projects, or projects that require scale to be financed privately, by working with commercial banks to help aggregate projects to reduce risk.

• Manage the fiscal impact of the cap and-trade regime

Ontario intends to help business and industry manage the impacts of cap-and-trade by supporting significant emission reductions by providing funds to offset the cost of low-carbon technologies, support research and development and provide allowances to industry to help them transition to lower carbon technology while they reduce GHG pollution. These actions to facilitate the transition to a carbon priced economy are laudable but Ontario must be careful to not dilute the effectiveness of the cap-and-trade program by the provision of too many free allowances or offset credits.

Expansion of Ontario’s ICI

During its September 2016 throne speech, Ontario announced that it will be expanding its ICI to enable more businesses to access the program.⁶⁴  The ICI provides a strong incentive for large electricity consumers to shift their electricity consumption to off-peak hours, and Ontario hopes that the expansion of the program will promote its climate change goals by deferring the need to build peaking generation.

The ICI allows customers to significantly lower their year-round electricity costs by reducing consumption from the provincial grid during times of peak demand. If an ICI participant reduces the amount of power it consumes from the provincial grid during the five hours in a year when the overall demand for electricity in Ontario is the highest (known as “coincident peaks”) it will benefit from a reduction in its electricity costs throughout the following year.⁶⁵

While the ICI has been in place since 2011, only certain large industrial customers qualified for the program. Going forward, the ICI will be expanded to include all types of businesses and qualifying average hourly electricity demand will be lowered. More than 300 businesses already use the ICI and Ontario expects that over 1,000 new businesses will be eligible for ICI after the program is expanded.⁶⁶

The Future

In September 2016, Ontario confirmed that it intends to continue implementation of the initiatives highlighted in the ON Action Plan and in the government’s September 2016 throne speech.⁶⁷

Since 2010, Ontario has periodically released its Long-Term Energy Plan (“LTEP”).  The last LTEP was released in 2013, and another is due to be released in 2017. Ontario will be working to align the 2017 LTEP with the ON Action Plan. The LTEP will be guided by a number of strategic themes including GHG reductions, innovation, grid modernization, conservation and energy efficiency, renewable energy, distributed energy and continued focus on energy affordability for homes and businesses.

The Ontario government will also be working with the IESO to provide, later in 2016, a mid-term review of Ontario’s six-year Conservation First Framework, and an update on moving towards meeting Ontario’s GHG reduction targets for 2020, 2030 and 2050.

QUEBEC

The 2013-2020 Climate Change Action Plan (“CCAP 2020”),⁶⁸ adopted by the previous provincial government, is one of Quebec’s main tools to address climate change. CCAP 2020 sets a GHG emissions reduction target of 20 per cent below 1990 levels by 2020. When adopted in 2013, CCAP 2020 encouraged a shift toward a greener economy by establishing a list of thirty priorities to be pursued by the Quebec Government. In order to achieve the GHG emissions reduction target, one of the main mechanisms set forth in CCAP 2020 was to establish a cap and trade system (“Quebec Cap and Trade”).

Quebec Cap and Trade

The Quebec Cap and Trade is a flexible, market-based mechanism that allows regulated emitters and other participants to trade GHG emission allowances (“Carbon Credits”) in order to respect a cap set by the government. It formally started operating on January 1, 2013 and, one year later, was linked with California, creating the largest cap and trade regime in North America.⁶⁹ The ninth Quebec-California carbon market auction will be held on November 15, 2016.

The Regulation respecting a cap-and-trade system for greenhouse gas emission allowances⁷⁰ (“Cap and Trade Regulation”) enacted under the Environment Quality Act⁷¹ sets out the legal framework governing the operation of the Quebec Cap and Trade. The Cap and Trade Regulation applies to an emitter that emits a quantity equal to or exceeding 25,000 megatonnes (“Mt”) CO_2e per annum in a sector of activity listed under the Cap and Trade Regulation (which includes electrical, electricity, mining and fossil fuel distribution sectors).⁷²

There are several ways to obtain Carbon Credits under the Quebec Cap and Trade. First, some are freely allocated, auctioned off or sold by the Quebec Government.⁷³ Second, early reduction credits were allocated for reductions in GHG emissions made from January 1, 2008 to December 31, 2011, as an incentive to reduce emissions prior to the establishment of the Quebec Cap and Trade.⁷⁴ Finally, emitters and participants can also obtain offset credits by taking part in emission reduction projects in accordance with the Cap and Trade Regulation. Offset credits can also be traded through the system and used for compliance purposes.⁷⁵

At the end of each compliance period (2013-2014, 2015-2017 and 2018-2020), each regulated emitter must have enough Carbon Credits to cover their emissions, either through one of the previously discussed mechanisms or by purchasing credits from another regulated emitter or participant.⁷⁶ These transactions must be carried out via the Compliance Instrument Tracking System Service. An annual reduction of the cap and of the freely distributed Carbon Credits ensures a constant reduction of GHG emissions from the regulated entities.⁷⁷ The majority of the revenues raised by the government through the Quebec Cap and Trade are earmarked for the Green Fund, established under an Act Respecting the Ministère du Développement Durable, de l’Environnement et des Parcs⁷⁸, which is dedicated to financing measures or programs intended to promote sustainable development and address climate change. The Green Fund is expected to accumulate approximately $3.3 billion by 2020 with 70 per cent derived from the Quebec Cap and Trade.⁷⁹

Quebec’s Emission Reduction Targets

The Government of Quebec has articulated three ambitious and progressive GHG emission reduction targets to be reached by the middle of this century. In addition to the 20 per cent reduction below 1990 levels by 2020, the province has also set targets for 2030 and for 2050.

At the end of November 2015, in anticipation of COP 21, the Government of Quebec confirmed that it would aim to reduce emissions by 37.5 per cent below 1990 levels by 2030. This is the most ambitious target set to date in Canada.⁸⁰

Finally, as a signatory to the Subnational Global Climate Leadership MOU, an agreement that brings together subnational jurisdictions in order to further reduce GHG emissions, Quebec has committed to either reduce its GHG emissions by 80 per cent to 95 per cent, or limit GHG emissions to 2 MtCO_2e per capita per year, by 2050.⁸¹

Recent Developments

Two of the more important recent regulatory developments in Quebec in the energy and climate change sectors include the Transportation Electrification Action Plan 2015-2020⁸² (“QC Action Plan”) and the 2030 Energy Policy⁸³ (“Energy Policy”). In addition, related draft legislation has been recently tabled in the Quebec National Assembly, including Bills 102, 104, and 106.

Bill 102

On June 7, 2016, of Bill 102 – An Act to amend the Environment Quality Act to modernize the environmental authorization scheme and to amend other legislative provisions, in particular to reform the governance of the Green Fund⁸⁴ (“Bill 102”) was presented. Bill 102 seeks to amend the Environment Quality Act⁸⁵ in order to modernize the permitting process. The proposed changes would, inter alia, provide for a new ministerial authorization scheme which would allow the Minister to take into account the GHG emissions attributable to a project and assess any climate change impact mitigation and adaptation measures proposed when deciding whether or not to grant an authorization.

QC Action Plan

The QC Action Plan, which was presented by the Quebec Government on October 9, 2015, aims to create a structure and define the steps to be taken in order to establish Quebec as an “electric transportation leader and sustainable mobility trailblazer” by 2020.⁸⁶ In that regard, the QC Action Plan follows three policy directions: (1) to encourage electric transportation; (2) to build an industrial base (including research and development of the manufacturing sector); and (3) to create the right environment (an appropriate legal and regulatory framework). The electrification of transportation is also presented by the Government of Quebec as an opportunity to develop the mining sector.

In order to help achieve a 20 per cent reduction of GHG emissions below 1990 levels by 2020, as set out in the CCAP 2020, the QC Action Plan comprises 35 different measures financed by a $420 million investment provided by the Government of Quebec, mostly coming from the Green Fund discussed above. More specifically, the following targets have been set for 2020:

1. 100,000 plug-in electric and hybrid vehicles will be registered in Quebec (in the Energy Policy the Government also announced an even more ambitious target of reaching 300,000 electric and hybrid vehicles registered in Quebec by 2026 and 1,000,000 by 2030, which would represent approximately 20 per cent of all light-duty vehicles);
2. Reduce the annual GHG emissions produced by transportation by 150,000 tonnes;
3. Reduce by 66 million the number of litres of fuel consumed annually in Quebec; and
4. 5,000 jobs in the electric vehicle industry will be created and $500 million of investments will be generated.

The Government of Quebec recently moved forward with its first regulatory initiative following the release of the QC Action Plan. On June 2, 2016, the Minister of Sustainable Development, the Environment and the Fight Against Climate Change (“MDDELCC” for the French name of this Ministry, le ministère du Développement durable, de l’Environnement et de la Lutte contre les changements climatiques) introduced Bill 104 – An Act to increase the number of zero-emission motor vehicles in Québec in order to reduce greenhouse gas and other pollutant emissions (“Bill 104”).⁸⁷

Bill 104

Bill 104 aims to increase the number of zero-emission motor vehicles in Quebec. More precisely, it “establishes a system of credits and charges applicable to the sale or lease in Quebec, by motor vehicle manufacturers, of new motor vehicles”. The scope of Bill 104 is limited to motor vehicle manufacturers that, on average, for three consecutive model years, sell or lease more than 4,500 new motor vehicles in Quebec.

Credits accumulate by selling or leasing new motor vehicles that respect certain conditions (such as being completely or partially electrically propelled, using a battery or a cell that is rechargeable from a source that is not on board the vehicle). A manufacturer can also obtain credits by acquiring them from another motor vehicle manufacturer. Under Bill 104, motor vehicle manufacturers that do not accumulate enough credits, as determined and calculated by regulation, will have to pay a charge to the MDDELCC, which amount will be credited to the Green Fund.

Special consultations on Bill 104 were held in August of 2016 before the Committee on Transportation and the Environment and the Bill was adopted in principle on September 22, 2016. Due to the generality and the regulatory discretion contained in Bill 104, the consequences of the Bill will only be fully understood once the regulations come into effect.

The Energy Policy

On April 7, 2016, the Government of Quebec announced the Energy Policy which, by 2030, seeks to make Quebec a North American leader in the fields of renewable energy and energy efficiency by building a strong low-carbon economy. More precisely, the Energy Policy sets forth the following five targets to be achieved by 2030:

1. Enhance energy efficiency by 15 per cent;
2. Reduce the amount of petroleum products consumed by per cent;
3. Eliminate the use of thermal coal;
4. Increase overall renewable energy output by per cent; and
5. Increase bioenergy production by 50 per cent.

In addition to these ambitious targets, the Energy Policy has also introduced other significant developments. The Government of Quebec will establish a new agency devoted to energy conservation and to energy transition and has indicated that it will be broadening the powers of the Régie de l’énergie (the “Energy Board”). Also, a review of the environmental evaluation process applicable to energy projects will be conducted with the view of increasing coherence and coordination between the different authorities that play a role in the environmental, social and economic factors of a given project. In addition, the Energy Policy aims to develop a new approach to hydrocarbon exploration and exploitation in Quebec. Finally, Quebec Government intends to adopt legislation in order to completely eliminate thermal coal as an energy source by 2030.

Bill 106

The Energy Policy will be implemented through the publication of three action plans (2016-2020, 2021-2025 and 2026-2030) and will require several amendments to the existing regulatory framework. In this regard, on June 7, 2016, Bill 106 – An Act to implement the 2030 Energy Policy and to amend various legislative provisions (“Bill 106”) was introduced by Pierre Arcand, Minister of Energy and Natural Resources.⁸⁸

Bill 106 aims to implement the measures announced in the Energy Policy which will bring about significant changes to the energy regulatory landscape in Quebec.

First, Bill 106 introduces the Act respecting Transition énergétique Québec which, once adopted, will establish a new government agency entitled Transition énergétique Québec (“TEQ”), which will be responsible for creating all programs and taking the necessary measures to meet the energy targets set forth by the government. TEQ will notably be responsible for preparing an energy transition, innovation and efficiency master plan every five years and will be required to consult with relevant stakeholders, as specified under the Act. The master plan is to be submitted to the Government of Quebec and to the Energy Board for adoption, if it is considered to be consistent with the government’s objectives. The Green Fund and annual contribution from energy distributors will jointly finance TEQ.

Second, Bill 106 sets out amendments to the Act respecting the Régie de l’énergie.⁸⁹  In addition to its new role with respect to the approval of TEQ’s master plan, Bill 106 also contains provisions concerning the distribution of renewable natural gas and the inclusion of excess transmission capacity in a natural gas distributor’s supply plan.

Third, Bill 106 introduces amendments to the Hydro-Québec Act⁹⁰  that, once adopted, will provide Hydro-Québec with the power to grant financial assistance to public transit authorities and public bodies for the fixed equipment necessary for the electrification of shared transportation services.

Finally, Bill 106 proposes the enactment of the Petroleum Resources Act, which aims to govern the development of petroleum resources in Quebec. Currently, this sector is governed by the Mining Act^.91 In its current form, Bill 106 creates a license and authorization system for the exploration, production and storage of petroleum resources and enhances the role of the Energy Board. New exploration licenses would be allocated by auctions. It also includes provisions addressing closure and site restoration plans. Petroleum royalties, in addition to other sums, would be paid to the Energy Transition Fund, also created by Bill 106.

Special consultations were held in August of 2016 before of the Committee on Agriculture, Fisheries, Energy and Natural Resources. The Report of the Committee was presented before the Quebec National Assembly on September 20, 2016. Bill 106 has not yet been put to a vote and, taking into account the significance of the reform, may be subject to amendments before adopted.

Energy Implications

Contrary to other Canadian provinces, the policy and regulatory shift discussed throughout this section will not have a significant impact on the balance of energy sources in Quebec. Indeed, the abundance of hydroelectric power in the province allows Quebec to generate more than 99 per cent of its electricity through renewables.⁹² That stated, the policies and regulatory changes described above will have other impacts.

Although the heightened regulatory activity is not expected to significantly impact the type of energy sources in Quebec, carbon policies will likely translate into additional costs for consumers and businesses. As estimated by the government and the oil industry, the price of one litre of gasoline has increased somewhere between 2 to 3.5 cents as a result of the implementation of the Quebec Cap and Trade.⁹³ In 2015, the average natural gas consumer (2,300 m³/year) saw an increase of $41/year for his/her gas consumption and the average business (14,600 m³/year) saw an increase of $258/year.⁹⁴

As suggested by the Ontario IESO, regulatory pressure on the cost of carbon could lead to a greater electrification of the energy grid and drive up demand for electricity.⁹⁵ As discussed in the Energy Policy, Hydro-Québec, the most important Quebec power utility, is expected to take advantage of such a favorable context and attempt to further extend its reach outside of the province. In order to achieve its intention to double its revenues over the next fifteen years, Hydro-Québec has indicated that it will be seeking to increase its electricity exports to other markets and use its valuable know-how to increase its presence abroad.⁹⁶

In light of the foregoing, it is clear that Quebec is at a crucial stage in the development of its legal framework relating to climate change and energy development. By establishing ambitious targets related to the reduction of GHG emissions and the number of registered electric vehicles, Quebec has set the bar high for the upcoming years. The Bills recently tabled before the Quebec National Assembly and discussed in this article can be characterized as setting the stage for an era of energy transition. The practical impacts of this shift to a greener Quebec are still unpredictable, however we can expect a greater pressure on consumers of carbon intensive products and an enhancement of the role played by Hydro-Quebec in other provinces and in the United States.

CONCLUSION

As described in this article and summarized below, the GHG regimes and policies adopted by the Big-Five provinces are quite varied, as are their impacts on electricity production and prices:

B.C. has traditionally generated the majority of its electrical power from hydroelectric projects. As a means of reducing its GHG emissions, in 2012 it adopted a broad-based carbon tax, which is set at $30/tonne. As a supplement to its carbon tax, B.C. will also be implementing emissions-intensity performance standards for prescribed industries. To date B.C.’s GHG emissions reduction policies have had minimal impact on electricity prices, presumably because those policies have had limited impact on its production of hydroelectric power.

Alberta has traditionally relied on coal for the majority of its power production.  It also has extensive oil and gas operations which traditionally have high GHG emissions, particularly in the oil sands regions. Alberta has had an emissions intensity regime in place for large emitters for almost a decade. Beginning in 2017, it is expanding its carbon regime to encompass other businesses and consumers through the implementation of a carbon levy. By 2018, the levy will be set at $30/tonne and thereby mirror B.C.’s carbon tax. It is also phasing out all coal-fired power production and making a concerted effort to replace a significant portion of that power generation with renewable energy production. Finally, it is placing an absolute cap on oil sands emissions. As for the potential impact on electricity prices, it is still too early to tell, although there is a potential for prices to rise due to the additional costs associated with constructing additional necessary transmission infrastructure and transitioning into a higher reliance on renewable energy.

Saskatchewan is similar to Alberta in that it relies on coal for the majority of its power production. It also has extensive oil and gas and mining operations and is the highest provincial emitter of GHG emissions on a per capita basis. To date Saskatchewan appears to be a bit of an outlier when it comes to GHG emissions reduction policies. Instead of implementing extensive GHG reduction measures or moving towards the phasing out of coal-fired power plants, the government of Saskatchewan has concentrated on supporting CCS initiatives. Although SaskPower, Saskatchewan’s provincially-owned utility company, has committed to achieving 50 per cent renewable energy capacity (of which 30 per cent is to be from wind power) by 2030, it is unclear how it will reach that target.  Because of Saskatchewan’s limited approach to date, it is difficult to determine the impact, if any, its GHG emissions policies have had or will have on electricity costs.

Unlike its provincial counterparts, Ontario relies on nuclear energy for the majority of its electrical power production. It has adopted a cap-and-trade regime as its preferred means of reducing GHG emissions. Ontario’s first compliance period is set to begin as of January 2017. As a supplement to its cap-and-trade policy, Ontario eliminated all power production from coal-fired power plants as of 2014. Since then it has been the most active province in promoting renewable energy projects, having implemented a variety of incentive programs over the years. More recently it has introduced policies in support of the reduction of GHG emissions in the transportation industry. In that regard, it announced it will be building nearly 500 Charging Stations along its highways, which are expected to be in service by March of 2017.  Of all the Big-Five provinces, Ontario’s GHG emissions reduction policies have had the most significant impact on electricity prices.  The impact has been so dramatic that the government blamed the loss of a by-election held in September of 2016 on public frustration over the rising cost of electricity. It is unlikely that there will be any significant reduction in electricity prices and it will be interesting to see if the province is able to constrain additional increases in the future.

Quebec is similar to B.C. in that it generates the majority of its electricity from hydro-power. Quebec is also a cap-and-trade jurisdiction, with the first compliance period having occurred in 2013-2014.  Indeed, in 2014 Quebec linked itself with California, creating the largest cap-and-trade regime in North America. More recently, in 2015, Ontario confirmed it was aligning itself with Quebec’s cap-and-trade regime. Finally, in a manner similar to Ontario, Quebec has introduced policies and draft legislation that strongly support the reduction of GHG emissions in the transportation industry, including sales targets for electric and hybrid vehicles. With respect to the impact of its GHG emissions reduction policies on electricity costs, there appears to have been minimal effect. Presumably this is because, like B.C., those policies have had limited impact on its production of hydroelectric power.

The wide-ranging GHG emissions reduction policies that the Big Five provinces have employed are an excellent example of how one-size-does-not-fit-all when it comes to this vexing issue.  The disparate policies will certainly test the federal government’s resolve when it determines if they are otherwise stringent enough to meet the federal targets and thereby sufficient to avoid the imposition of the federal carbon pricing regime in 2018.

*All of the authors are members of the Blake, Cassels and Graydon LLP Environmental Law or Regulatory Law groups and include lawyers from Blakes’ Vancouver, Calgary, Toronto and Montreal offices.

1. According to: Environment and Climate Change Canada, National Inventory Report 1990-2014: Greenhouse Gas Sources and Sinks in Canada, Canada’s submission to the UNFCCC (Gatineau: 11 April 2016), in 2014 provincial emissions were approximately as follows: Alberta – 37 per cent; Ontario – 23 per cent; Quebec – 11 per cent; Saskatchewan – 10 per cent; and British Columbia – 9 per cent.
2. Greenhouse Gas Reduction Targets Act, SBC 2007, c 42.
3. Carbon Tax Act, SBC 2008, c 40.
4. Ministry of Finance, Tax Rates on Fuels: Motor Fuel Tax Act and Carbon Tax Act, Tax Bulletin MFT-CT 005 (Revised August 2016).
5. Greenhouse Gas Industrial Reporting and Control Act, SBC 2014, c 29.
6. Ibid.
7. British Columbia, British Columbia’s Climate Leadership Plan (Victoria: August 2016), online: <http://climate.gov.bc.ca>.
8. Emissions intensity refers to the quantity of CO_2e released by a facility per unit of production.  As a facility becomes more carbon efficient it can produce the same unit of production with less CO_2e released.
9. British Columbia, Climate Action Plan (Victoria: 2008), online: <http://www.gov.bc.ca/premier/attachments/climate_action_plan.pdf>.
10. British Columbia, Climate Leadership Team: Recommendations to Government (Victoria: 31 October 2015), online: <http://engage.gov.bc.ca/climateleadership/files/2015/11/CLT-recommendations-to-government_Final.pdf>
11. 2016 BC Plan, supra note 7.
12. Environmental Assessment Act, SBC 2002, c 43.
13. Canadian Environmental Assessment Agency, Environmental Assessment Decision Statement (Ottawa: CEAA, 27 September 2016) at 1, online: CEAA <http://www.ceaa.gc.ca/050/documents-eng.cfm?evaluation=80032>.
14. Cement Association of Canada, Press Release, “Cement Industry Welcomes B.C. Government Action on Carbon Tax” (27 February 2015), online: CAC <http://www.cement.ca/en/News-Releases/Cement-Industry-Welcomes-B-C-Government-Action-on-Carbon-Tax.html>.
15. 2016 BC Plan, supra note 7 at 28.
16. British Columbia’s Energy Objectives Regulation, BC Reg 234/2012.
17. Climate Change and Emissions Management Act, SA 2003, c C-16.7.
18. Specified Gas Emitters Regulation, Alta Reg 139/2007.
19. Baseline intensity refers to the quantity of CO_2e released per unit of production during the first few years of a facility’s start-up, or if it the facility has been established for quite some time, during the 2003-2005 time-frame.
20. See Government of Alberta, Climate Leadership Report to Minister (Edmonton: 20 November 2015), online: <http://www.alberta.ca/documents/climate/climate-leadership-report-to-minister.pdf>.
21. Paul Boothe & Félix-A. Boudreault, By the numbers: Canada’s GHG Emissions (London: Lawrence National Centre for Policy and Management: Ivey Business School at Western University, 2016).
22. Aaron Wherry, “Amid a climate-change parade, Brad Wall casts himself as Harper Lite”, Maclean’s (23 November 2015): “…we need to do better in terms of our record on climate change, our province needs to do better, and I can talk a little bit about that, but we can’t forget the economy”.
23. Bill 126, An Act respecting the Management and Reduction of Greenhouse Gases and Adaptation to ClimateChange, 3rd Sess, 26th Leg, Saskatchewan, 2010 (assented to 20 May 2010).
24. Government of Saskatchewan, News Release, “Saskatchewan takes real action to reduce greenhouse gas emissions” (11 May 2009).
25. The Ethanol Fuel Act, SS 2002, c E-11.1.
26. Government of Saskatchewan, Directive S-10: The Saskatchewan Upstream Petroleum Industry Associated Gas Conservation Directive, (Regina: November 2015).
27. SaskPower, “Our Supply Mix”, online: < http://www.saskpower.com/wp-content/uploads/power_sources_Apr2016.jpg>.
28. Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations, SOR/2012-167, s 3.
29. SaskPower, News Release, “CCS performance data exceeding expectations at world-first Boundary Dam Power Station Unit #3” (11 February 2015).
30. In May 2016, SaskPower applied for two rate increases: A 5 per cent increase to take effect July 1, 2016 and a further 5 per cent increase to take effect January 1, 2017. Rate increases were also approved in 2014 and 2015. Various critics have pointed to the significant costs associated with the Boundary Dam Integrated CCS Project as the cause of higher rates: Will Chabun, “SaskPower seeks 10.25-per-cent rate hike over next eight months”, Regina Leader-Post (20 May 2016); Stefani Langenegger, “Sask. carbon capture plant doubles the price of power”, CBC News (17 June 2016).
31. DC Fraser, “SaskPower renegotiated contract to avoid $91.8M penalty”, Regina Leader-Post (13 June 2016).
32. Office of the Parliamentary Budget Officer, Canada’s Greenhouse Gas Emissions: Developments, Prospects and Reductions (Ottawa: PBO, 21 April 2016) at 41.
33. Supra note 28.
34. SaskPower, Rate Application (2016 and 2017) at 10, online: SRR <http://www.saskratereview.ca/docs/saskpower2016/2016-and-2017-rate-application.pdf>.
35. SaskPower, News Release, “SaskPower to develop wind, solar and geothermal power to meet up to 50% renewable target” (23 November 2015).
36. For the first 10-MW project, the Request for Qualification process is anticipated to commence before the end of September 2016 with the Request for Proposals process taking place by the end of December 2016.
37. Requests for Qualification will be issued in November 2016, followed by Requests for Proposals in Q1 2017.
38. Chaplin Wind-Energy Project (13 September 2016), EAB 2013-013, online: < http://publications.gov.sk.ca/documents/66/94179Chaplin%20Wind%20Energy%20Project%20MD%20&%20RfD%20(PubCentre).pdf>.
39. Specifically, Chaplin Lake, which is part of a system designated as a Western Hemisphere Shorebird Reserve Network, is located 4.5 km south of the nearest proposed wind turbine and Paysen, Williams and Kettlehut lakes, which are designated as Important Bird Areas, are  located approximately 6 km north of the nearest proposed wind turbine.
40. Government of Saskatchewan, News Release, “New siting guidelines strengthen environmental protection and clarity for future wind power projects” (19 September 2016).
41. Saskatchewan, Ministry of Environment, Wildlife Siting Guidelines for Saskatchewan Wind Energy Projects, 2016-FWB 01 (Regina: September 2016).
42. Stefani Langenegger, “Wind project near Chaplin, Sask., denied” CBC News (19 September 2016).
43. Supra note 32 at 55.
44. Ontario, Ministry of Energy, The End of  Coal (Toronto: 16 December 2015).
45. Ontario, Ministry of Energy, New Release, “Creating Cleaner Air in Ontario” (Toronto: 15 April 2014).
46. Supra note 44.
47. Green Energy and Green Economy Act, 2009, SO 2009, c 12.
48. The small FIT program (generating capacity greater than 10 kW, and 250 kW or less if connected to a less than 15 kV line, and 500 kW or less if connected to a 15 kV or greater line), and the microFIT program (generating capacity 10 kW or less) continue to exist.
49. Ontario, Ministry of Energy, Renewable Energy Program (Toronto: 12 June 2013).
50. Ontario, Ministry of Energy, Large Renewable Procurement (LRP) II and Energy from Waste Standard Offer Program (EFWSOP), (Toronto: 27 September 2016).
51. IESO, Ontario Planning Outlook (Toronto: September 2016) at 2.
52. Robert Benzie, “Wynne Signals Hydro Relief is Coming for Consumers”, Toronto Star (7 September 2016).
53. Ministry of Energy, News Release, “Ontario Suspends Large Renewable Energy Procurement” (27 September 2016).
54. Climate Change Mitigation and Low-carbon Economy Act, 2016, SO 2016, c 7.
55. Climate Change Act, ibid, s 6(1).
56. Climate Change Act, ibid, s 7(1).
57. The Cap and Trade Program, O Reg 144/16.
58. Quantification, Reporting and Verification of Greenhouse Gas Emission, O Reg 143/16.
59. Ontario, Ministry of the Environment and Climate Change, Methodology for the Distribution of Ontario Emission Allowances Free of Charge (Toronto: MOECC,16 May 2016).
60.  Supra note 51 at 18.
61. Ibid at 7-8.
62. Government of Ontario, Climate Change Strategy (Toronto: 25 August 2016).
63. Ontario, Office of the Premier, “Speech from the Throne” (12 September 2016).
64. Ibid.
65. IESO, “Changes to Class A Eligibility”, online: IESO <http://www.ieso.ca/Pages/Participate/Settlements/Changes%20to%20Class%20A%20Eligibility.aspx>.
66. Ontario, Office of the Premier, News Release, “Introducing Measures to Reduce Electricity Costs” (15 September 2016).
67. Government of Ontario, “September 2016 Mandate letter, Environment and Climate Change”, (Toronto: 23 September 2016); Government of Ontario, “September 2016 Mandate letter, Energy”( 23 September 2016).
68. Government of Quebec, Quebec in Action: Greener by 2020, 2013-2020 Climate Change Action Plan, (Quebec : Government of Quebec, 2012).
69. Government of Quebec, A brief look at the Quebec cap-and-trade system for emission allowances, online: MDDELCC <http://www.mddelcc.gouv.qc.ca/changements/carbone/documents-spede/in-brief.pdf>. Note also that a Joint Declaration between the Ministry of the Environment and Natural Resources of the United Mexican States, the Government of Ontario, and the Government of Quebec was signed on August 31, 2016 under the terms of which the parties agreed to deepen their collaboration by conducting cooperation activities on carbon markets with the objective of reducing greenhouse gas emissions and jointly promoting the expansion of carbon market instruments for greenhouse gas emissions reduction in North America.
70. Regulation respecting a cap-and-trade system for greenhouse gas emission allowances, CQLR, c Q-2, r 46.1 [Cap and Trade Regulation].
71. Environment Quality Act, CQLR, c Q-2.
72. Cap and Trade Regulation, supra note 70 at s 2. Note that there is also mandatory reporting under the Regulation respecting mandatory reporting of certain emissions of contaminants into the atmosphere, CQLR, c Q-2, r 15 by every person or municipality operating an establishment that, during a calendar year, emits into the atmosphere greenhouse gases in a quantity equal to or greater than 10,000 metric tons CO₂ equivalent.
73. Cap and Trade Regulation, ibid at ss 39, 45, 56.
74. Ibid at s 65.
75. Ibid at ss 37, 70.1 ff.
76. Government of Quebec, supra note 69.
77. Ibid.
78. An Act Respecting the Ministère du Développement Durable, de l’Environnement et des Parcs, CQLR, c M-30.001, s 15.1 and ff.
79. Government of Quebec, Fonds vert– Secteur d’activité : Changements climatique, online : MDDELCC <http://www.mddelcc.gouv.qc.ca/ministere/fonds-vert/secteurs/Changements-climatiques.htm#provenance>.
80. Radio-Canada, « Réduction des GES : Quebec vise 37,5 % d’ici 2030 », Radio-Canada (27 November  2015),  online : <http://ici.radio-canada.ca/nouvelles/environnement/2015/11/27/003-quebec-ges-gaz-effets-de-serre-2030-objectif-reduction-environnement.shtml>.
81. Global Climate Leadership, Memorandum of Understanding (MOU), online: <http://under2mou.org/wp-content/uploads/2015/04/Under-2-MOU-English.pdf>.
82. Government of Quebec, Propelling Quebec forward with electricity, online: < http://www.transportselectriques.gouv.qc.ca/en/>.
83. Government of Quebec, Energy in Quebec, a source of Growth –The 2030 Energy Policy, 2016 [The 2030 Energy Policy].
84. Bill 102,  An Act to amend the Environment Quality Act to modernize the environmental authorization scheme and to amend other legislative provisions, in particular to reform the governance of the Green Fund, 1st Sess, 41th Leg, Quebec, 2016.
85. Supra note 71.
86. Supra note 82.
87. Bill 104, An Act to increase the number of zero-emission motor vehicles in Quebec in order to reduce greenhouse gas and other pollutant emissions, 1st Sess, 41th Leg, Quebec, 2016.
88. Bill 106, An Act to implement the 2030 Energy Policy and to amend various legislative provisions, 1st Sess, 41th Leg, Quebec, 2016.
89. Act respecting the Régie de l’énergie, CQLR, c R-6.01.
90. Hydro-Québec Act, CQLR, c H-5.
91. Mining Act, CQLR, c M-13.1.
92. The 2030 Energy Policy, supra note 83, at 16.
93. Ministry of  the Environment and Climate Change of Ontario, Backgrounder –How Cap and Trade Works (Toronto: 13 April 2015), online: <https://news.ontario.ca/ene/en/2015/04/how-cap-and-trade-works.html>.
94. Gazifere, Introduction des droits d’émission de carbone sur la facture au 1er janvier 2015, online : <http://www.gazifere.com/wp-content/uploads/2014/12/Info-Marche-du-carbone-dec-2014R.pdf>.
95. Supra note 61 at 7-8.
96. The 2030 Energy Policy, supra note 83, at 22.