Canadian Energy Perspectives

Developments in Energy and Power Law

Canadian Energy Perspectives

Alberta’s Renewable Electricity Support Agreement: McCarthy Tétrault Submission to the AESO on the Draft Term Sheet

Posted in Energy – Renewable, Alternative and Clean, Power, Procurement
Kimberly J. HowardSeán O'Neill

Almost a year after the provincial government released its Climate Leadership Plan, it tabled the Renewable Electricity Act (Act) and released details on its Renewable Electricity Program (REP).

Consistent with the Alberta Electric System Operator’s (AESO) earlier indications and as discussed in previous posts, renewable electricity will include wind, solar, hydro, geothermal, and sustainable biomass projects.  The REP is available to large scale renewable electricity generation (5 MW or greater total nominal capacity).  Under the Act, the AESO will administer “a fair and competitive process” for REP proposals to incentivize renewable generation in the Alberta in order to meet the Province’s “30 by ‘30” target.  Following the competitive process, successful bidders will enter into a Renewable Electricity Support Agreement (RESA) with the AESO.

The RESA will be a twenty-year, index-adjusted fixed price contract, also known as a contract for differences (CFD).  The fixed (or “strike”) price of a RESA will be the price that the AESO accepts from a successful bidder and is expected to be the lowest price at which such bidder can build and operate its renewable energy project while obtaining an acceptable rate of return.

On November 10, 2016, the AESO released a draft Term Sheet for the purposes of stakeholder comments on the proposed commercial terms of the RESA.  The deadline for stakeholder comments on the Term Sheet was December 9, 2016.

Our team prepared and submitted comments to the AESO on the Term Sheet.  A copy of our submission can be found here.

The New Current: Alberta Announces Overhaul of Electricity Market

Posted in Electricity, Energy – Renewable, Alternative and Clean, Power
Kimberly J. HowardGeorge VeghBeverly Ma

On November 23, 2016, the Government of Alberta announced the restructuring of Alberta’s electricity market, from a fully deregulated regime to a hybrid system that incorporates capacity payment mechanisms.

Alberta is one of the few jurisdictions in the world with an “energy-only” market.  This means that Alberta generators only recover the wholesale price of electricity.  Investors are only able to recover invested capital if they can leverage high-priced hours, and in this way, the energy-only system contains the risk of supply instability and may not promote investment in generation facilities and, in particular, renewable energy sources.

Alberta’s Capacity Market

Over the next 14 years, the Alberta Government estimates that it will need up to $25 billion of new investment in electricity generation to support, in part, the growing electricity needs of the province and to implement the province’s plan to phase-out coal-fired generation and meet its target of 30% renewable electricity capacity by 2030.  In order to achieve this, the province intends to support 5,000 MW of additional renewable capacity.

Accordingly, current and potential energy investors as well as the Alberta Electric System Operator (AESO) recommended that Alberta transition to a capacity power market regime, which is expected to promote stability in the price and supply of electricity and investment in energy.  This recommendation can be found in the AESO’s report entitled, Alberta Wholesale Electricity Market Transition Recommendation.

Under the proposed market scheme, Alberta will incorporate mechanisms to compensate power producers for their generation capacity.  Alberta’s electricity market will therefore be comprised of two separate markets: (i) a market for energy; and, (ii) a market for capacity, in which generators will agree to have availability to supply electricity when required.  Each of these markets produce separate revenue streams: (i) energy payments, which are paid to the generator for electricity that is purchased; and (ii) capacity payments, which are paid to the generator for making generation capacity available on demand.

Timeline for the Capacity Market

  • Alberta’s capacity market will be developed in consultation with stakeholders, and will be implemented by 2021.
  • AESO has estimated that the design of the market will take 2 years to complete, with an additional year to finalize legal contracts and to set up a procurement process.
  • The first capacity contracts are expected to be formed at least three years after the design process starts.
  • Accordingly, the earliest date that capacity procured through the initial auction would be in service will likely be in 2024.

Issues and Developments to Monitor

The possible implications of the power market overhaul on Alberta’s energy landscape will need to be considered in light of other commitments recently announced by the Alberta Government, such as its renewable energy initiatives.  At present, some issues to consider include:

  • Price Stability: Although there are many direct benefits to consumers from capacity markets, such as the reduction of price spikes, consumers risk incurring increased costs. The Government of Alberta recently announced its commitment to protecting consumers from volatile prices by implementing a price cap of 6.8 cents per kilowatt hour from June 2017 to June 2021.  However, as the cap on electricity prices and the implementation of power capacity payments will likely not overlap, the implications of the capacity power market on consumer prices remains uncertain.
  • Overlap and Interplay with Other Initiatives: How the capacity market will interact with the principles of the energy-only market and specifically the principles legislated within the Fair, Efficient and Open Competition Regulation (FEOC) will be critical to watch. Specifically, whether and how the FEOC principles will be applied to the various relationships between generators participating in the Alberta market, including the successful bidders from both the Renewable Electricity Program, and the auction for capacity contracts, and how such incentives will be addressed with incumbent generators who already invested, built and operate natural gas and renewable generation facilities in Alberta.
  • Supply Reliability: The capacity market provides incentives for electricity generators to supply the power pool, as well as with the means to invest in renewable energy sources. It remains to be seen whether the market overhaul will remedy possible gaps in Alberta’s power supply, especially during the period of coal phase-out, and whether it will reinforce Alberta’s Climate Leadership Plan.

We will be watching these developments closely.

Compliance with Flexibility: Ontario Releases Regulatory Proposal for Offset Credits under Cap-and-Trade Program

Posted in Climate Change, Emissions Regulation, Emissions Trading
Selina Lee-Andersen


As Ontario puts the finishing touches on its cap-and-trade program, which will commence on January 1, 2017, the Ministry of Environment and Climate Change (MOECC) has released its Compliance Offset Credits Regulatory Proposal (the Regulatory Proposal) for a 45-day public comment period that will end on December 30, 2016.  Under the cap-and-trade program, capped facilities will be required to either reduce their greenhouse gas (GHG) emissions or meet their compliance obligations through other regulatory tools, including the use of offset credits. As a compliance mechanism, offset credits provide emitters with greater flexibility and potentially lower cost options to meet their compliance obligations.

MOECC has proposed certain amendments to the Cap and Trade Program Regulation (the Regulation) to create the regulatory framework for the offsets component of the cap-and-trade program. Facilities and sectors which are not subject to the Regulation, and which are able to reduce GHG in accordance with the proposed requirements and associated protocols, will be eligible to seek to have offset credits created and issued. Offset credits, which are aimed at increasing the compliance options for capped facilities, may be used to meet up to 8% of a capped facility’s compliance obligation.

The draft Regulatory Proposal provides an overview of the criteria, process and administrative requirements for the registration of offset initiatives and the creation and issuance of offset credits that can be used to meet a compliance obligation. In particular, the Regulatory Proposal outlines a number of program elements, including:

  • Offset Participants – The Regulatory Proposal identifies two types of participants : (i) Offset Initiative Operators (persons who undertake action to remove GHG or reduce/avoid emissions outside of capped sectors); and (ii) Offset Initiative Sponsors (persons who register an initiative, submits annual reports and application for offset credits). An Offset Initiative Operator will have the legal authority to implement the offset project and apply for offset credits; an Offset Initiative Sponsor can be either the Offset Initiative Operator or an individual designated by the Offset Initiative Operator to act on their behalf (the Offset Initiative Sponsor must be a resident or an entity with a presence in Ontario, and will be required to register with the Compliance Instrument Tracking System Service (CITSS)).
  • Offsets Initiative Registry – MOECC will establish an Offsets Registry as an online website which will be the public registry of compliance offset credit initiatives that are eligible to apply for Ontario offset credits. Offset Initiative Sponsors will submit offset initiative descriptions through the Offset Registry as well as all forms, data reports and verification reports in accordance with the Regulation. A prerequisite for registering an offset initiative on the Offsets Registry is the establishment of an account for the Offset Initiative Sponsor with CITSS.
  • Offset Project Start Dates – GHG emission reduction initiatives are eligible to create offset credits for use in Ontario’s cap-and-trade program for offset initiatives that began on or after January 1, 2007.
  • Offset Crediting Periods – Crediting periods will be identified in the relevant protocols with the following limitations: (i) a non-sequestration offset credit initiative will have a continuous crediting period of no more than 10 years (i.e. offset credits cannot be created after 10 consecutive years unless a new crediting period is approved); and (ii) a sequestration offset credit initiative will have a continuous crediting period of no more than 30 years.
  • Offset Credit Creation Criteria – Offset credits must meet essential regulatory criteria with clear ownership to be real, additional, permanent, quantified, independently verified, enforceable and unique.
  • Reporting Requirements – No later than 18 months after the offset initiative begins, the Offset Initiative Sponsor must submit an Initiative Data Report of the first 12 months of reductions, avoidances or removals in a project report to the Offset Registrar, and annually thereafter for the duration of the offset initiative in order for the initiative to be eligible for offset credits. The Initiative Data Report will be in a format specified by MOECC.
  • Verification Requirements – Each Initiative Data Report submitted to MOECC to request the issuance of offsets must be accompanied by a Verification Report prepared by a verification organization accredited under ISO 14065 by a member of the International Accreditation Forum in either Canada or the United States and according to an ISO 17011 program, with respect to the sector of activity for the offset initiative. Details concerning verifier qualifications/criteria are as defined in Reg. 143/16 (Quantification, Reporting and Verification of Greenhouse Gas Emissions).
  • Buffer Account – The Buffer Account is a holding account for Ontario offset credits issued to sequestration offset credit initiatives where a percentage risk of reversal has been established in an Ontario Offset Protocol. The Regulation and protocol will set out the portion of the offsets that will be required to be placed in the Buffer Account. The intent of the Buffer Account is to provide a pool of offsets to serve as an insurance mechanism against unintentional reversals for all sequestration offset initiatives under an Ontario Offset Protocol and to provide an insurance pool to the overall offsets program. The requisite number of offsets will be placed in the Buffer Account at no cost to MOECC and will be administered by the Ministry. The Buffer Account will also include 3% of all non-sequestration offset credits as insurance for any offset credits found to be created in error or fraudulently and that are not replaced by the Offset Initiative Sponsor as required.
  • Offset Credit Issuance – Offset credit creation and issuance involves MOECC reviewing offset initiative documentation presented as evidence supporting the emissions reduction, avoidance or removal assertion being made by the Offset Initiative Sponsor, and accepting that documentation when it is satisfied all regulatory requirements of the Ontario offset program have been met. The documentation must consist of the annual Initiative Data Report accompanied by the annual Verification Report.
  • Project Reversals – Ontario offset protocols and the Regulation will have mechanisms in place to address permanence, including provisions to address unintentional and intentional reversals, error, and fraud. MOECC will remove offset credits from an Offset Initiative Sponsor’s CITSS account in the event of an intentional reversal. The Regulation will also set out a requirement for the Offset Initiative Sponsor to replace offset credits for any offset credit issued for an offset initiative in the following cases: (i) an intentional reversal; (ii) where offset credits that were issued were not eligible for offset credits because of omissions, inaccuracies or false information in the information and documents provided by the applicant; (iii) where it is found that offset credits were applied for under another program for the same reductions, avoidances or removals as those covered by the application for offset credits under the Regulation; (iv) where the offset initiative was not carried out in accordance with the provisions of the Ontario offset protocol and/or the Regulation.

Protocols are a critical component of any offsets program. The Regulatory Proposal notes that Ontario is working with Québec to develop thirteen protocols that, in most cases, proponents across the country will be able to follow to create offset credits eligible for use in Ontario’s cap-and-trade program. These protocols will be adapted from the best existing protocols for each offset initiative type. The first three will be based on Québec’s existing protocols, with the remaining ten being mostly agriculture and forestry-related. The establishment of the Offset Registry will include the creation of Offset Application Forms, Offsets Program Guidance, and the Verification System (draft of verification statement template and forms). Other implementation details will be developed as the Regulatory Proposal is refined and ultimately finalized.

The Regulatory Proposal has been posted for a 45-day public review and comment period starting November 15, 2016. Stakeholders have until December 30, 2016 to submit comments to the individual listed on the Environmental Registry web site or comments may be submitted on-line (Reference: EBR Registry number 012-907).


Hydro-Québec Distribution Issues New RFP for a Forest Biomass Cogeneration Plant in Obedjiwan Community

Posted in Biomass, Hydro-Québec, RFP
Mathieu LeBlancLouis-Nicolas BoulangerKarina Gagnon

On November 16, 2016, Hydro-Québec Distribution (“HQD”) issued a new request for proposals (A/P 2016-01) (“RFP”) to develop, build and operate a forest biomass cogeneration plant which would be integrated to the Obedjiwan off-grid system located in Haute-Mauricie, near the Gouin Reservoir, in the province of Québec.

The issuance of the RFP reflects HQD’s intention to “progressively convert off-grid systems to more reliable, cleaner, less expensive energy sources” in accordance with its Strategic Plan 2016-2020. Continue Reading

Paving the Route to 2050: Canada Releases Mid-Century Strategy for a Clean Growth Economy

Posted in Climate Change, Climate Policy, Electricity, Emissions Regulation, Energy – Renewable, Alternative and Clean
Selina Lee-Andersen

The Paris Climate Change Agreement came into force on November 4, 2016 and as global efforts get underway to implement the agreement, the Canadian federal government continues to craft its strategy to shift Canada to a low-emissions economy. At the recent United Nations climate change conference (COP 22) in Marrakech, Morocco that was held from November 7 – 18, 2016, the Minister of Environment and Climate Change announced Canada’s Mid-Century Long-Term Low-Greenhouse Gas Development Strategy (the Long-Term GHG Strategy) at COP 22, making Canada one‎ of the first countries to do so.

Under the Long-Term GHG Strategy, Canada considers an emissions abatement pathway consistent with net emissions falling by 80% in 2050 from 2005 levels. This is consistent with the Paris Agreement’s goal to hold the increase in the global average temperature to well below 2°C above pre-industrial levels, while pursuing efforts to limit the temperature increase to 1.5°C above pre-industrial levels.

Canada’s Long-Term GHG Strategy makes it clear that it is not a blueprint for action. Rather, the strategy is meant to inform the conversation about how Canada can achieve a low-carbon economy. That said, Canada’s mid-century objectives will ultimately be realized though short-term concrete action, which includes an evaluation of various scenarios to achieve deep emission reductions. To facilitate discussion, the Long-Term GHG Strategy outlines potential GHG abatement opportunities, emerging key technologies, and identifies areas where emissions reductions will be more challenging and require policy focus in the context of a low carbon economy by 2050. In particular, the strategy focuses on a number of key areas including the expansion of Canada’s electricity sector, energy consumption in end use applications (including electrification of transportation), non-carbon dioxide emissions, forests, agriculture, waste and clean technology. However, the strategy does not cover emissions from the oil and gas sector.

The federal government acknowledges that in order to achieve the 2050 target, a fundamental restructuring of multiple sectors of the economy will be required. In particular, cost effective abatement opportunities will need to be realized from virtually every greenhouse gas emissions source and activity. The Long-Term GHG Strategy notes that a failure to act now will likely lead to increased costs in the future as the required pace of decarbonisation increases, raising the probability of misallocation of investment and infrastructure, as well as stranded assets. Also, there is an opportunity for Canada to participate in the emerging global markets for clean energy and related goods and services.

The Long-Term GHG Strategy identifies key objectives and potential building blocks for Canada’s transition to a low emissions economy, including the following elements that could frame the foundation for a long-term climate change mitigation strategy:

  • Electrification – The electrification of end-use applications that are currently using fossil fuels is fundamental, e.g. using electricity to power certain cars, trucks, building appliances and heating systems, and energy requirements for some industries.
  • Decarbonisation of the electricity generating sector – Electricity generation in Canada is already more than 80% non-emitting, with a trend towards non-emitting generation expected to continue, including through increased government action.
  • Electricity demand and exports – The significant increase in electricity demand resulting from electrification policies (e.g. doubling or more by 2050) and electricity exports should be satisfied through low-carbon sources.
  • Electricity cooperation – Canada and North America’s electricity future will be shaped by interprovincial and intercontinental cooperation. Enhanced interjurisdictional electricity transmission interties could allow areas with hydropower, or other forms of non-emitting generation, to sell electricity to other provinces or US states that rely on fossil fuels.
  • Energy efficiency and demand side management – The International Energy Agency (IEA) estimates that 38% of the required global emissions reductions associated with a 2°C pathway could be met through energy efficiency improvements. Efficiency gains are also key enablers of electrification technologies and consumer savings.
  • Low-carbon fuels – Some sectors such as heavy industries, marine transportation, some heavy freight transportation, and aviation could move to lower or low-carbon fuels such as second generation biofuels or hydrogen. Alternatively, new and emerging technologies in synthetic hydrocarbons or energy storage would be needed.
  • Abatement of non-carbon dioxide greenhouse gases – Methane and hydrofluorocarbons are a priority given their high global warming potentials. Reductions of these pollutants can often help slow the rate of near-term warming and contribute to achievement of the global temperature goal.
  • Carbon sequestration – Forests and lands will continue to play an important role in sequestering substantial amounts of carbon dioxide from the atmosphere. This sequestration can be augmented through policies and measures that better manage Canadian forests and forest products.
  • Innovation – A sustainable energy transition is possible with currently deployed or near-commercial technologies, but the long-term transition will be eased with the near-term accelerated deployment of clean energy options, or the development of more innovative technologies. The private sector has an important role to play in this respect including spurring investment and innovation towards low GHG alternatives. Carbon pricing will be an important element to achieving this objective.
  • Collaboration – Working together with provinces and territories, Indigenous peoples, municipalities, business and other stakeholders will be essential to Canada’s long-term success in enabling clean growth, reducing emissions and seizing the opportunities of the low-carbon global economy.

By aligning Canada’s policy objectives with the Paris Agreement’s temperature goals, the federal government is looking to integrate climate change objectives into its long term planning processes. In the short to medium-term, the Long-Term GHG Strategy will help inform the pan-Canadian framework on clean growth and climate change currently under development.


Calgary Herald Interviews Seán O’Neill

Posted in Coal, Energy – Renewable, Alternative and Clean
Kimberly J. Howard

We are delighted that McCarthy Tétrault partner Seán O’Neill has been quoted in a recent article by Reid Southwick and Chris Varcoe of the Calgary Herald. In the interview, Seán discusses the potential impact of Alberta’s NDP government enacting retroactive legislation to change or invalidate the change of law provisions in Alberta coal-fired generation power purchase arrangements.  Continue Reading

Change is in the Wind: Alberta Government Tables the Renewable Electricity Act

Posted in Biomass, Energy – Renewable, Alternative and Clean, Solar, Wind
Kimberly MacnabKimberly J. HowardSeán O'Neill

Almost a year after the provincial government released its Climate Leadership Plan, it tabled the Renewable Electricity Act (Act) and released details on its Renewable Electricity Program (REP).

Consistent with the Alberta Electric System Operator’s (AESO) earlier indications and as discussed in previous posts, renewable electricity will include wind, solar, hydro, geothermal, and sustainable biomass projects.  The REP is available to large scale renewable electricity generation (5 MW or greater total nominal capacity).  Under the Act, the AESO will administer “a fair and competitive process” for REP proposals to incentivize renewable generation in the Alberta in order to meet the Province’s “30 by ‘30” target.  Following the competitive process, successful bidders will enter into a Renewable Electricity Support Agreement (RESA) with the AESO.

The RESA will be a twenty-year, index-adjusted fixed price contract, also known as a contract for differences (CFD).  The fixed (or “strike”) price of a RESA will be the price that the AESO accepts from a successful bidder and is expected to be the lowest price at which such bidder can build and operate its renewable energy project while obtaining an acceptable rate of return.  Continue Reading

Renewable Generation Incentives in Alberta Contracts for Differences: the Way Forward?

Posted in Climate Change, Climate Policy, Electricity, Energy – Renewable, Alternative and Clean
Kimberly J. HowardKimberly MacnabSeán O'NeillMichael Weizman

Last November, the Alberta government released its Climate Leadership Plan, setting out the phase-out of coal-fired electricity generation by 2030, to be replaced with two thirds renewable energy generation and one third natural gas generation.  Then, the Alberta Electric Systems Operator (AESO) was subsequently directed to develop an incentives program for renewable generation.

Today at the CanWEA Conference held in Calgary, Minister Shannon Phillips delivered a speech announcing details about Alberta’s Renewable Electricity Program. The Alberta Government has issued a press release following the announcement this morning.  Some of the highlights include:

  • Incentives for renewable generation will take the form of an indexed renewable energy certificate (REC) structured akin to a contract for difference (CFD);
  • The AESO will commence consultation on the commercial terms of the REC/CFD as early as next week;
  • The AESO will be implementing a competitive process and the first call will commence in Q1 of 2017 for up to 400MW of renewable generation. The projects are expected to be in service by 2019; and
  • The Renewable Electricity Act will be tabled today in Alberta’s Legislative Assembly. This Act is expected to contain details regarding the competitive procurement process and will enshrine into law Alberta’s target that 30% of electricity used in Alberta will come from renewable sources by 2030.

Our team has prepared a legal update which provides an overview of CFDs and a description of some of their more important commercial provisions to illuminate some of the key issues that government and potential stakeholders should consider in connection with the implementation of the REP in Alberta.

Alberta Power Market Update

Posted in Carbon Tax, Climate Change, Emissions Regulation, Energy – Renewable, Alternative and Clean
Kimberly J. HowardKimberly MacnabSeán O'Neill

Last year’s election ushered in Alberta’s first regime change since 1971, resulting in a wave of policy changes involving renewable generation development, the phase-out of coal-fired generation, and emissions and carbon tax policy.  This update captures certain key aspects to these changes and takes stock of things to come.

Alberta’s provincial government released its Climate Leadership Plan (Climate Plan) in November of 2015, as discussed in a previous post.  This post focuses on the following key Climate Plan policy announcements affecting the power industry:

  • incentives for renewable generation,
  • phase-out of coal fired generation emissions by 2030,
  • implementing an economy-wide carbon price, and
  • implementing an energy efficiency program.

Renewable Electricity Program

The Alberta Electric System Operator (AESO) was mandated by the government to spearhead initiatives for development and implementation of the province’s Renewable Electricity Program (REP).  The AESO undertook stakeholder consultation and developed draft recommendations for the REP in the form of a report delivered to the government on May 31, 2016.  To date, the report is not public and it is unclear whether the report will be released in its entirety, but aspects of its contents appear to have been included in a recent press release.

In September, the province announced a firm target that 30% of electricity used in Alberta will come from renewable sources such as wind, hydro and solar by 2030.  As discussed in a recent post, the province intends to support 5,000 MW of additional renewable capacity in order to achieve this target.

REP Timelines

Currently, the expected timeline for the REP remains as follows:

       Q1-Q2 2016

Phase 1 of stakeholder engagement process closed on March 24, 2016.

May 2016

Provincial government requested AESO’s draft recommendations on program design.

Q2-Q3 2016

Program development.

Q4 2016

First competition for new REP projects.

Q2 2019

Expected in-service date of first REP projects.


REP Eligibility

For developers, project eligibility for the REP will be critical.  The AESO has indicated that projects must:

Issues and Developments to Monitor

In its early release of details respecting the REP, the AESO noted that “[i]t is anticipated that the existing transmission system will be leveraged”.  While use of existing infrastructure is a logical path forward, certain renewable projects face significant congestion on inadequate lines.  For instance, substantial wind power development opportunities in highly desirable locations are shackled by insufficient transmission capacity in the southern Alberta region and face delays in planned reinforcements for the area.  It will be interesting to see how the province plans to accommodate 5,000 MW of additional renewable capacity given the locational constraints for generation sources such as wind and solar and the significant controversy characterizing transmission system reinforcement efforts in southern Alberta.[1]

The province has stated that the REP will be based on recommendations provided to government by the AESO, and that the government and AESO are now working on detailed program design.  As always, the devil is in the details, and such release of details is anticipated in Q4 of 2016.

Alberta Coal Phase Out

Many market participants in Alberta are aware of the controversy currently surrounding Alberta’s Power Purchase Agreements (“PPAs”), originally a mechanism to transition the Alberta electricity market from a cost-of-service model to a deregulated model.  The PPAs allow their holders to buy output from the facility owners and bid it into the power pool.  PPAs have recently declined in profitability for their holders as a result of increased costs attributed to Alberta’s regulation of greenhouse gas (GHG) emissions and lower revenues resulting from falling power pool prices.

Coal Facilitator

In March of 2016, Alberta named Terry Boston to act as the province’s independent coal phase-out facilitator.  The full scope of work for the coal-facilitation can be found here.  Generally, Boston was tasked with presenting options to government that will strive to maintain the reliability of Alberta’s electricity grid, maintain stability of prices for consumers, and avoid unnecessarily stranding capital while meeting the government’s objective to phase out coal generation by 2030.

One key aspect of Boston’s work is to engage with the three owners of coal-fired generation facilities that are currently expected to operate beyond 2030.  Boston is supported by the Alberta Energy’s Coal Secretariat and the Alberta Electric System Operator.  Alberta’s Economic Development Minister had initial hopes that a deal with the owners would be in place by September when Boston’s contract expires.

Regulation of Emissions

Changes to the Specified Gas Emitters Regulation (SGER) in 2015 significantly increased the cost of emissions for large industrial emitters, being those which emit 100,000 tonnes or more of GHG.  As noted in a previous post, such facilities are subject to the following costs of compliance under SGER:

Site-specific emissions intensity reduction targets:

·        12% in 2015

·        15% in 2016

·        20% in 2017

Emissions payments for each tonne over the facilities’ reduction targets:

·        $15 in 2015

·        $20 in 2016

·        $30 in 2017

Further, the government adopted the Climate Leadership Panel’s recommendation to introduce a Carbon Competitiveness Regulation basing emissions intensity credits on a comparison with the most efficient natural gas generator. This means that coal-fired generation, which falls near the bottom of the pack in terms of emissions intensity, now receives far fewer credits.

As a study co-authored by Andrew Leach (chair of the Climate Leadership Panel) notes, this change in emissions credits increases the cost to the PPA holders by approximately $15 per MWh over and above the new government’s June 2015 changes to the SGER.

The “Change in Law”

The Climate Leadership Implementation Act ((Climate Act), as discussed in an earlier post) will come into force on January 1, 2017.  Before the Climate Act officially became law, PPA holders, namely ENMAX, TransCanada and Capital Power, gave notice of their intention to terminate their PPAs under their respective contractual “Change in Law” provisions.  Such provisions, dubbed the “Enron Clause” by the provincial government, allow the PPA holder to terminate the PPA without penalty if a “Change in Law” renders the PPA “unprofitable or more unprofitable”.[2]

The province has disputed the effectiveness of the Change of Law provisions essentially on a procedural basis.  The province contends that in 2000, during the process of finalizing the PPAs but before their “auction”, a request was made on behalf of Enron to add the phrasing “or more unprofitable” to the Change in Law provision.  The reason that the addition of this language is so important is that it broadly increased the discretion of the PPA holders to terminate their respective PPAs.  The form of PPAs that had been approved by previously held public hearings were granted such amended phrasing by the Energy Utilities Board of Alberta without public notice or hearing.

The provincial government has commenced a lawsuit seeking, among other things, a declaration from the courts as to the validity of the Enron Clause.  The government argues that the last-minute amendment to the PPA was void from the outset as it was done without proper consultation or review, and thus there was no authority to amend the PPAs in the first place.  While frequently portrayed in the media as the province suing itself, the legal skirmish is more nuanced.  The government is banking, using the guise of protecting Alberta ratepayers, that it can erase a critical piece of a commercial agreement entered into and accepted by the parties nearly 20 years ago.  Seen another way, the government’s strategy appears to be that if the words “or more unprofitable” are found by the court to not be valid, the PPA holders will not have met the condition necessary to allow the Balancing Pool to accept the termination of the PPAs and will, therefore, need to keep performing their contractual obligations.

With emissions regulations driving up the costs of producing coal-generated electricity, and power prices much lower than expected, PPA profitability has been impacted.  To illustrate, the Leach-Tombe paper states:[3]

In 2014, Enmax’s Battle River 5 PPA generated just over 2.5 million MWh of electricity. Assuming spot-market sales, with prices down over $18 per MWh in 2016 from what was previously expected, revenue would be roughly $45 million lower in 2016 alone. Add to this the revenue losses expected between now and 2020 and the Battle River 5 PPA alone may lose roughly $100 million.

If the Balancing Pool accepts the termination of a PPA, the Balancing Pool can either terminate the PPA (which requires payment of a termination amount to the PPA holder) or it may assume the role of “buyer” under the PPA and manage the bidding of the generation assets into the power pool.  Under the Balancing Pool’s governing legislation, any surplus or deficiency is allocated to consumers through either a customer allocation payment or a surcharge.  With the significant impact of low power prices on the profitability of the PPAs, the province’s argument hangs on the phrase “or more unprofitable” and whether the PPA holders may have the benefit of this contractual “out”.  It remains to be seen whether the court will be persuaded that the amendment process was so flawed that the result should be to void this term of the PPAs.

Impact of the Case on Albertans and Developments to Monitor

The Government of Alberta estimates that terminating all of the PPAs will cost ratepayers up to $2 billion between now and 2020.  In comparison, the study by Andrew Leach and Trevor Tombe, referenced above, estimates the cost of terminating the PPAs is closer to $600 million (the drop in value being approximately $900 million, and taking into account that one of the PPAs was already owned by the Balancing Pool).  The $900 million amounts to about $2.25/month on the typical consumer’s electricity bill.

The province’s originating application was filed on July 25, 2016, and the action has been assigned a case management judge.  We will continue to monitor its progress through the courts.

Climate Leadership Implementation Act: Carbon Levy and Energy Efficiency Alberta

Alberta’s Bill 20 was tabled in the legislature in May of this year, containing both the Climate Act and the Energy Efficiency Alberta Act.  The former establishes a carbon levy for the province and the latter establishes a Crown corporation called Energy Efficiency Alberta, tasked with raising awareness and delivering programs related to energy conservation.

Carbon Levy

A detailed overview of the carbon levy and its estimated impacts on Albertans can be found in in a previous post.  Broadly, carbon levies will be implemented on various enumerated transactions across the fuel value chain.  There are some exemptions to the levy, but these are limited in number and scope.

Proceeds from the levy are estimated at around $9.6 billion over the next five years.  The government has indicated that the proceeds will be reinvested in the provincial economy and it has earmarked approximately $6.2 billion on diversifying the energy economy.  The remaining $3.4 billion will be used to provide provincial support (i.e. rebates) for households, businesses and communities adjusting to the carbon price.

Energy Efficiency Alberta: Advisory Panel

Given that the province’s April 2016 budget allocated $645 million to this new Crown corporation, it is well worth keeping track of Energy Efficiency Alberta’s progress.  In June of 2016, the province established the Energy Efficiency Advisory Panel and tasked it with conducting public, indigenous and technical engagement activities from June to September, 2016 and providing a report to the government in the fall of 2016.

The report will contain the panel’s recommendations on “the types of energy savings programs that Energy Efficiency Alberta can start to deliver in the short and medium-term, as well as help set out a long-term vision”.  Energy Efficiency Alberta’s programs are scheduled to launch in early 2017.

Recent Developments: Climate Change Technology Task Force

On September 19, 2016, Alberta announced that it had appointed a Climate Technology Task Force (Task Force) to “provide recommendations on targeting investments in climate technology to help transition to a lower-carbon economy”.

The Task Force comprises a chair and four members with experience in research, development and deployment of climate change-related technology, and plans to bring together a cross-section of academic, business, government and not-for-profit representatives in a series of sessions this October.  Albertans may also provide their views via email.

The Task Force will provide a written report to the government at the end of November 2016 containing recommendations for a provincial Climate Change Innovation and Technology Framework.

[1] Colette Derworiz, “Proposed power line threatens iconic views in southern Alberta”, Calgary Herald (5 March 2015), online; John Stoesser, “Phase two of Enel’s Castle Rock Ridge wind farm on hold again”, Pincher Creek Echo (29 November 2014), online; “Jocelyn Doll, “LLG’s request for review of needs identification document denied”, Pincher Creek Echo (12 April 2016), online.

[2]  “Originating Application for Declaratory Relief and Originating Application for Judicial Review,” Court File 1603 13041, filed July 25, 2016, at para 31 [emphasis added].

[3] Andrew Leach and Trevor Tombe, “Power Play: The Termination of Alberta’s PPAs”, The School of Public Policy, Vol 8, Issue 11 (August 2016) at 9.

Taking the Bull by the Horns: Federal Government Introduces Pan-Canadian Carbon Price and Ratifies Paris Agreement; Paris Agreement to Come into Force in November 2016

Posted in Carbon Tax, Climate Change, Climate Policy, Emissions Regulation, Emissions Trading
Selina Lee-Andersen

The week of October 3, 2016 was an eventful one for Canadian climate change policy as the federal government introduced a pan-Canadian carbon price and ratified the Paris Agreement. Following the federal election in October 2015, indications were that all provinces and territories would be expected to price carbon. This was confirmed on October 3, 2016 when Prime Minister Justin Trudeau announced that the federal government will set a minimum price on carbon starting at $10 per tonne of carbon dioxide equivalent (CO2e) in 2018, which will increase by $10 per year until it reaches $50 per tonne of CO2e by 2022. This approach will be reviewed in 2022 to confirm the path forward, including continued increases in stringency.

Under the federal plan, each province and territory will be required to implement carbon pricing in its jurisdiction within two years, whether in the form of a carbon tax or a cap-and-trade system. If the carbon price in a jurisdiction does not meet the federal minimum price, the federal government will step in and impose a carbon price that makes up the difference and return the revenue to the province or territory. In addition, provincial and territorial goals for reducing emissions must be at least as stringent as federal targets. Canada has pledged to reduce its greenhouse gas (GHG) emissions by 30% from 2005 levels (approximately 523 Mt) by 2030. Currently, Canada’s four biggest provinces representing more than 80% of Canada’s population (Ontario, Quebec, Alberta and British Columbia) either have carbon pricing in place or will introduce it in 2017. For more information on climate change policies in each province and territory, please refer to our Climate Change Essentials Guide.  Prime Minister Trudeau has indicated he will convene a first ministers’ meeting on December 8 with the aim of concluding a pan-Canadian climate plan, which will likely include more detail on carbon pricing and other measures.

Canada’s Approach to Carbon Pricing

While the details are still pending, Canada’s pan-Canadian approach to carbon pricing is premised on the following principles, which are drawn from principles proposed by the Working Group on Carbon Pricing Mechanisms that was established during the First Ministers’ Meeting in March 2016:

  • Carbon pricing should be a central component of the Pan-Canadian Framework on Clean Growth and Climate Change.
  • The approach should be flexible and recognize carbon pricing policies already implemented or in development by provinces and territories.
  • Carbon pricing should be applied to a broad set of emission sources across the economy.
  • Carbon pricing policies should be introduced in a timely manner to minimize investment into assets that could become stranded and maximize cumulative emission reductions.
  • Carbon price increases should occur in a predictable and gradual way to limit economic impacts.
  • Reporting on carbon pricing policies should be consistent, regular, transparent and verifiable.
  • Carbon pricing policies should minimize competitiveness impacts and carbon leakage, particularly for trade-exposed sectors.
  • Carbon pricing policies should include revenue recycling to avoid a disproportionate burden on vulnerable groups and Indigenous peoples.

The federal government’s goal is to ensure that carbon pricing applies to a broad set of emission sources throughout Canada with increasing stringency over time to reduce GHG emissions at lowest cost to business and consumers and to support innovation and clean growth.

The federal government’s carbon pricing benchmark includes the following elements:

  • Provinces and territories will have flexibility in deciding how they implement carbon pricing: they can put a direct price on carbon pollution or they can adopt a cap-and-trade system.
  • Pricing will be based on GHG emissions and applied to a common and broad set of sources to ensure effectiveness and minimize interprovincial competitiveness impacts. At a minimum, carbon pricing should apply to substantively the same sources as British Columbia’s carbon tax.
  • The price on carbon should start at a minimum of $10 per tonne of CO2e in 2018 and rise by $10 a year to reach $50 per tonne of CO2e in 2022.
  • Provinces with cap-and-trade need: (i) a 2030 emissions reduction target equal to or greater than Canada’s 30% reduction target; (ii) declining annual caps to at least 2022 that correspond, at a minimum, to the projected emissions reductions resulting from the carbon price that year in price-based systems.
  • The federal government will provide a pricing system for provinces and territories that do not adopt one of the two systems by 2018.
  • Revenues from carbon pricing will remain with provinces and territories of origin.
  • Provinces and territories will use the revenues from this system as they see fit, whether it is to give it back to consumers, to support their workers and their families, to help vulnerable groups and communities in the North, or to support businesses that innovate and create good jobs for the future.
  • The federal government will work with the territories to address their specific challenges.
  • The overall approach will be reviewed in 2022 to ensure that it is effective and to confirm future price increases. The review will account for progress and for the actions of other countries in response to carbon pricing, as well as recognition of permits or credits imported from other countries.
  • Legislated increases in stringency, based on modeling, to contribute to Canada’s national target and provide market certainty.
  • Jurisdictions should provide regular, transparent and verifiable reports on the outcomes and impacts of carbon pricing policies.

Canada ratifies Paris Agreement; Paris Agreement to come into force on November 4, 2016

Following the federal government’s announcement, parliament ratified the Paris Agreement by a vote of 207 to 81 on October 5, 2016. The Paris Agreement, which was opened for signature on April 22, 2016, sets a goal of holding the increase in global average temperature to well below 2°C above pre-industrial levels, while countries pursue efforts to limit the temperature increase to 1.5°C above pre-industrial levels. With Canada’s ratification and ratification earlier in the week by the European Union and India, the implementation threshold for the Paris Agreement was reached on October 5, 2016. This means that the Paris Agreement will enter into force on November 4, 2016, which is thirty days after the date on which at least 55 parties to the United Nations Framework Convention on Climate Change accounting in total for at least an estimated 55% of the total global GHG emissions have deposited their instruments of ratification, acceptance, approval or accession with the United Nations depositary.

Overview of Carbon Pricing Mechanisms

Canada’s move to put a price carbon follows a global trend where carbon pricing is being increasingly seen as the key mechanism by which meaningful GHG emission reductions can be achieved. A price on carbon looks to capture what are referred to as the external costs of carbon emissions, i.e. costs that the public pays for indirectly, such as damage to property as a result of flooding. By placing a monetary value on carbon, the rationale is that governments, businesses and individuals will have an incentive to change their behaviour to less carbon intensive alternatives. Market instruments are perceived as providing more cost efficient and flexible compliance mechanisms to drive emission reductions, so governments are now looking to the market for solutions. There are two main types of carbon pricing mechanisms available to policymakers:

  • An Emissions Trading System (ETS) is a market-based approach designed to provide economic incentives for reducing emissions. While emissions trading systems tend to be complex, the economic concept behind it is straightforward – since climate change is a shared global burden and the environmental impacts of reducing emissions is the same wherever the reductions take place, it makes economic sense to reduce emissions where the cost is lowest. Under an ETS, an annual limit or cap is set on the amount of GHG emissions that can be emitted by certain industries. Regulated entities are then required to hold a number of emissions allowances equivalent to their emissions. Regulated entities that reduce their GHG emissions below their target will require fewer allowances and can sell any surplus allowances to generate revenue. Regulated entities that are unable to reduce their emissions can purchase allowances to comply with their target. By creating demand and supply for emissions allowances, an ETS establishes a market price for GHG emissions. In order to achieve absolute reductions in GHG emissions, the limit or cap is gradually lowered over time.
  • A carbon tax puts a price on each tonne of GHG emissions generated from the combustion of fossil fuels. The idea is that over time, the carbon price will elicit a market response from all sectors of the economy, thus resulting in reduced emissions. The design and implementation of carbon taxes varies widely and will depend on the jurisdiction’s energy mix, composition of its economy, existing tax burdens, existence of complementary environmental policies, and political considerations. In terms of scope, some jurisdictions have focused on a narrow category of energy users and large emitters, while others such as British Columbia (BC) have adopted a broader scope where the carbon tax covers GHG emissions from the combustion of all fossil fuels.

The key differences between the mechanisms are that with an ETS, the quantity of emission reductions is known, but the price is uncertain.  With a carbon tax, the price is known, however the quantity of emissions reductions is uncertain. Both carbon pricing mechanisms can generate revenue that can be used to lower other taxes or invest in “green” initiatives. Both mechanisms also have related monitoring, reporting, verification and compliance obligations, and both need special provisions to minimize the effects on certain energy intensive, trade exposed industries.

Industry Leads the Way

In recent years, companies have been working hard to reduce their carbon footprints by setting emission reduction targets and taking action to address climate change impacts in both their own operations and their supply chain. Given the range of climate policies across jurisdictions, companies are often faced with having to consider multiple carbon compliance costs in their business decisions. As a result, there have been increasing calls from the private sector on governments to establish clear pricing and regulatory certainty to support climate-related investments and climate risk assessment efforts. In the meantime, companies have been assessing risk and developing business plans based on a real or internal carbon price that is incorporated into their planning and investment decisions. This means that companies worldwide are already advanced in their use of carbon pricing and in planning for climate change risks, costs and opportunities. According to the CDP, internal carbon pricing has become standard operating practice in business planning and the prices used range from US $6 to 89 per tonne of CO2e. On April 22, 2016, the United Nations Global Compact (UNGC) called for a minimum internal carbon price level of US$100 per tonne of CO2e by 2020, which UNGC  believes is the minimum price needed to shift market signals in line with the 1.5 – 2°C pathway set out in the Paris Agreement.

As countries and businesses look for innovative approaches to reduce their carbon footprint, carbon pricing will become an increasingly prominent policy and business planning tool for governments and industry alike.

Large Renewable Procurement II – Ontario Suspends LRP II

Posted in Energy – Renewable, Alternative and Clean, Independent Producers, Ontario Independent Electricity System Operator, Power
Kerri LuiZachary MasoudBrianne Paulin

On September 27, 2016, the Minister of Energy of Ontario issued a policy direction to suspend the Large Renewable Procurement II (“LRP II”) process. In response to this direction, the IESO cancelled the first phase of the LRP II (the Request for Qualifications (“RFQ”)) and will not commence the second phase of the process (the Request for Proposals (“RFP”)).

Launch of LRP II Process

The LRP II was announced on April 5, 2016 with procurement targets of 600 MW of wind, 250 MW of solar, 50 MW of waterpower, 30 MW of bioenergy and 50 MW for technical upgrades and optimization of existing facilities. Submissions for the LRP II RFQ were due on September 8, 2016. The IESO received 59 RFQ submissions and successful applicants were to be notified in November 2016. The second phase of the process, the LRP II RFP, was expected to begin in early 2017, with contracts offered by May 2018.

Suspension of the LRP II

Suspending the LRP II is part of the Ontario government’s plan to reduce electricity costs for consumers. As renewable energy prices are expected to decline, the Ministry of Energy has advised that suspending the LRP II would allow the government to procure renewable energy at a lower cost in the future. It further noted that suspending the LRP II process “would save up to $3.8 billion in electricity system costs relative to Ontario’s 2013 Long-Term Energy Plan (“LTEP”) forecast” and up to $2.45 per month on the average residential electricity bill of a typical consumer.

The Ministry of Energy based its decision to suspend the LRP II process on the Ontario Planning Outlook (“OPO”) published by the IESO. The OPO indicated that Ontario had abundant electricity resources to support the development of projects planned in the LTEP. The findings in the OPO considered a range of demand forecasts for electricity in Ontario from 2016 to 2035.

Next Steps – Ontario’s Long-Term Energy Plan 2017

In the fall, consultations will begin with various stakeholder groups regarding the development of a new LTEP to be released in 2017. In regards to the LRP II RFQ, the IESO noted on its website that additional details will be available shortly for RFQ Applicants regarding the cancellation of the first phase.

For more information, please visit:


30 by 30: Alberta Announces Hard Targets in Alberta Renewables

Posted in Electricity, Energy – Renewable, Alternative and Clean, Power, Utilities
Kimberly J. HowardKimberly Macnab

On September 14, 2016, the Alberta Government announced its firm target that 30% of electricity used in Alberta will come from renewable sources such as wind, hydro and solar by 2030.  In order to achieve this, the province intends to support 5,000 MW of additional renewable capacity.

The province’s 30 by 30 announcement also provides useful details regarding eligibility for the Renewable Electricity Program (or REP).  Projects must:

  • be based in Alberta,
  • be new or expanded,
  • be five megawatts or greater in size, and
  • meet the Natural Resources Canada definition of renewable sources.

Interestingly, the announcement also notes that work is underway to improve the rules surrounding smaller-scale electricity generation, in order to make it easier for individuals and communities to generate their own renewable energy.

The announcement builds on the previous announcement that the Alberta Electric System Operator (AESO) was chosen under the province’s Climate Leadership Plan to develop and implement the REP to add additional renewable generation capacity into Alberta’s electricity system.  The AESO delivered its recommendations to the Alberta government on May 31, 2016.

As discussed in a previous post, the AESO released the results of its stakeholder engagement process on May 5, 2016.  The AESO’s stakeholder engagement update also included a summary of expected development timelines for different sources of renewable generation.  Estimated timelines are based on key activities and timelines associated with the development, regulatory approval and construction of anticipated renewable projects:

  • Wind: 4 to 6 years
  • Solar: 1.5 to 3 years
  • Biomass: 2 to 3 years
  • Geothermal: 3 to 7 years
  • Large Hydro: 10 to 14 years

Further details on how the program will operate will be released later this year.  We are monitoring the development of the REP closely and will provide updates as information is released.

Large Renewable Procurement II – Final LRP II RFQ Materials Posted

Posted in Energy – Renewable, Alternative and Clean, Independent Producers, Ontario Independent Electricity System Operator, Power
Kerri LuiZachary MasoudBrianne Paulin

On July 29, 2016, the IESO posted the final materials for the Large Renewal Project II (“LRP II”) Request for Qualifications (“RFQ”). Draft materials were posted on June 27, 2016 and the IESO solicited feedback from potential applicants and industry groups. As a result of this consultation, minor changes were included in the final materials for the LRP II RFQ.

As previously noted in detail in our post on July 15, 2016, the two major changes to the LRP II RFQ process are the introduction of the simplified process for LRP I Qualified Applicants (“QAs”) and a procurement target of 50 MW from technological upgrades and optimization of existing renewable facilities. Changes included in the final materials provide greater clarity regarding the application process under the simplified process for LRP I QAs, and the required submission materials for applicants submitting projects for technological upgrades and optimization of existing renewable facilities.

Simplified Process

To be eligible for the simplified process, an applicant must declare that (i) each LRP I Control Group Member is still a Control Group Member of the applicant and (ii) each LRP I designated team member is still a Designated Team Member.

The IESO has provided additional information for this requirement: if an LRP I QA or its Control Group Member(s) underwent an approved change of Control as part of the LRP I Process, it will qualify as an LRP I QA and can submit its RFQ under the simplified process. The applicant must submit the letter issued by the IESO or its predecessor approving the change of Control.

50 MW of Procurement from Existing Renewable Energy Facilities

The IESO has also introduced a new separate form that must be filled out by applicants who will submit technological and optimization projects, namely the Prescribed Form – Technical Upgrades and Optimization Questionnaire. In several of its online webinars, the IESO mentioned that the purpose of this form is to collect information that will assist the IESO in formulating the Request for Proposals (“RFP”) process and project requirements for technological and optimization projects.

The IESO confirmed that the applicant must evidence the Designated Team Member Development Experience for proposed technological upgrades and optimization of existing renewable generation facilities. The IESO received several comments on this issue, where applicants noted that existing generation facilities were operational and they therefore should not be required to re-evidence their development experience. Though the IESO kept this requirement in the final materials, it has included an exception where applicants submitting technological and optimization projects do not need to demonstrate development experience for the entity level.

Applicants are not eligible for the simplified process and will have to proceed through the standard process. The final materials also include a disclaimer, where the IESO reserves the right to make a determination (even if an applicant is deemed a QA), that it is not feasible to procure any additional generation resulting from technological upgrades to and optimization of existing renewable generation facilities.

Comment Period and Next Steps

The LRP II RFQ submission period began on July 29, 2016 and will end on September 8, 2016 at 3:00 p.m. (Eastern Prevailing Time). Successful applicants, who will be deemed QAs, will be notified in November 2016.

Target 2050: BC Releases Updated Climate Change Action Plan

Posted in Climate Change, Climate Policy, Emissions Regulation
British Columbia
Selina Lee-Andersen

The BC government released its long awaited Climate Leadership Plan (the Plan) on August 19, 2016. The Plan, which updates the province’s 2008 Climate Action Plan, contains 21 new actions to reduce emissions across the following sectors: (i) natural gas, (ii) transportation, (iii) forestry and agriculture, (iv) communities and built environment, and (v) public sector. The Plan follows the release of the Climate Leadership Team’s report in November 2015. The CLT, which was appointed by the BC government in May 2015 to provide advice for the development of the Plan, made 32 recommendations including, among others, the establishment of a mid-term 2030 greenhouse gas (GHG) emissions reduction target and a reduction in the provincial sales tax from 7% to 6%, which would be offset by an increase in the carbon tax by $10 per year commencing in July 2018.  While the Plan reflects some recommendations made by the CLT and feedback received through public consultation and stakeholder engagement sessions, the Plan bypasses BC’s 2020 target of achieving a reduction in GHG emissions of 33% below 2007 levels and instead charts a path for BC to reach its 2050 target of 80% below 2007 levels. In addition, the BC government has decided to keep the province’s revenue neutral carbon tax at $30 per tonne until the details for a pan-Canadian climate change policy, including the federal government’s approach to carbon pricing, are more clear.

Highlights of the Plan include the following:

Natural Gas

This action area is expected to reduce annual emissions by up to 5 million tonnes by 2050:

  • launching a strategy to reduce upstream methane emissions, including targets for reducing fugitive and vented emissions from extraction and processing infrastructure (built before January 1, 2015) by 45% by 2025;
  • developing regulations to enable carbon capture and storage; and
  • investing in infrastructure to develop upstream electrification of several projects including the Peace Region Electricity Supply Project and North Montney Power Supply Project.


This action area is expected to reduce annual emissions by up to 3 million tonnes by 2050:

  • increasing the requirements for BC’s Low Carbon Fuel Standard, which currently requires a reduction in the carbon intensity of transportation fuels by 10% by 2020 (relative to 2010) – the LCFS will be increased to 15% by 2030;
  • amending regulations to encourage emission reductions in transportation by allowing utilities to double the total pool of incentives available to convert commercial fleets to natural gas, when the new incentives go towards vehicles using 100% natural gas; and
  • expanding support for zero emission vehicle charging stations in buildings through the Clean Energy Vehicle program;

Forestry & Agriculture

This action area is expected to reduce annual emissions by up to 12 million tonnes by 2050:

  • rehabilitating under-productive forests, recovering more wood fibre, and avoiding emissions from burning slash through the new Forest Carbon Initiative (which will seek to increase the rate of replanting and fiber recovery by 20,000 hectares per year).

Industry & Utilities

This action area is expected to reduce annual emissions by up to 2 million tonnes by 2050:

  • developing new energy efficiency standards for gas-fired boilers; and
  • facilitating projects that will help fuel marine vessels and commercial vehicles with natural gas.

Communities & Built Environment

This action area is expected to reduce annual emissions by up to 2 million tonnes by 2050:

  • working together with local governments to refresh the Climate Action Charter;
  • amending regulations to promote more energy efficient buildings; and
  • creating a waste-to-resource strategy to reduce waste sent to landfill and establishing a food waste prevention target of 30% and increasing organics diverted from landfills to 90%.

Public Sector

This action area is expected to reduce annual emissions by up to 1 million tonnes by 2050:

  • promoting the use of low carbon and renewable materials in public sector buildings; and
  • mandating the creation of 10-year emission reduction and adaptation plans for provincial public sector operations.

The BC government has indicated that the Plan is a living document that will be further updated as needed in order to reflect any policy initiatives within the context of the development of a pan-Canadian climate framework. At the First Ministers’ meeting in March 2016,  Prime Minister Trudeau and the Premiers launched a process to develop a national climate change plan which includes the establishment of working groups to study: (i) clean technology, innovation and jobs, (ii) carbon pricing mechanisms, (iii) mitigation opportunities, and (iv) adaptation and climate resilience. The working groups are expected to report back by October 2016, following which a national climate change plan will be negotiated.

Large Renewable Procurement II – IESO Webinar re: Upgrades of Existing Facilities

Posted in Energy – Renewable, Alternative and Clean, Independent Producers, Ontario Independent Electricity System Operator, Power
Kerri LuiBrianne Paulin

On July 21, 2016, the IESO hosted a discussion on the portion of the Large Renewable Procurement II (“LRP II”) process pertaining to technological upgrades and optimization of existing renewable facilities. This discussion provided potential applicants with an opportunity to provide comments and feedback to the IESO as to the types of technologies that should be included in the LRP II process, procurement considerations for such technologies and contractual considerations.

Prescribed Form – Technical Upgrades and Optimization

The Prescribed Form for Technical Upgrades and Optimization is required for applicants submitting an RFQ for a technological upgrade and optimization project. The form requires the applicant to provide extensive information regarding the proposed project, the technology used and potential pricing.

Several concerns were raised about this Prescribed Form, including questions as to why this Prescribed Form is only required for technological upgrade and optimization projects. Some participants noted that the requested information was extensive and suggested that the deadline for submission should be extended. Others noted that the information requested would be more suitable for the LRP II RFP phase.

The IESO indicated that this Prescribed Form will only be used for data collection and will not be used to assess an applicant during the LRP II RFP phase. The IESO has significant data (including data regarding appropriate pricing) for certain types of renewable projects, such as wind and solar, but lacks information for technological upgrade and optimization projects. The IESO indicated that it will use the collected data to help determine the appropriate requirements for the LRP II RFP phase.

Consultation Process and Community Engagement

Some participants inquired about the consultation process between the IESO and the Ministry of the Environment and Climate Change (“MOECC”) and, in particular, noted that specific software upgrades could require additional environmental permitting and community engagement. The IESO indicated that community engagement is an important part of the process and that it would be unreasonable to not require any community engagement for a project change, even if such change is limited to a software upgrade. The IESO also mentioned that they are currently engaged in ongoing consultations with the MOECC and that the IESO’s ultimate selection of the technologies that are eligible for this portion of the LRP II procurement will impact such consultations.

Existing PPAs and Transmission Constrained Areas

Certain participants inquired about their existing power purchase agreements (“PPAs”) with the IESO. The IESO noted that each PPA is different and contains nuances that will need to be considered. The IESO did indicate that it would consider (i) suggestions regarding appropriate PPA terms and (ii) concerns raised by an applicant who does not believe that its proposed technological upgrade and optimization can be made under the project’s current PPA.

The IESO also addressed questions regarding the submission of projects from transmission constrained areas and advised that the standard LRP II capacity evaluation would apply, since this procurement is part of the LRP II process.

LRP II RFQ Materials and Process

As previously noted, the LRP II RFQ materials will be posted online on July 29, 2016. The LRP II RFQ process will launch on August 1, 2016. Question and comment periods will be held between August 1 and August 19, 2016. The deadline for Qualification Submissions is September 1, 2016. These dates are subject to change and will be finalized once the final LRP II RFQ documents are available. For additional information, please refer to the following link:

Large Renewable Procurement II – IESO Webinar and Process Updates

Posted in Energy – Renewable, Alternative and Clean, Independent Producers, Ontario Independent Electricity System Operator, Power, Procurement, Purchase Agreements
Kerri LuiBrianne Paulin

As previously noted, the IESO is currently developing the Large Renewable Procurement II (“LRP II”) process. Consistent with LRP I, the LRP II process will involve two phases: a Request for Qualifications (“LRP II RFQ”) and a Request for Proposals.

On July 13, 2016, the IESO hosted a webinar to provide an overview of the LRP II RFQ process and the changes it has introduced following the feedback received on the LRP I RFQ process. The IESO indicated that the LRP II RFQ process is substantively similar to the LRP I RFQ process. Two key topics emerged from the webinar: the introduction of a simplified process for Qualified Applicants (“QAs”) and the addition of a procurement target of 50 MW from technological upgrades and optimization of existing renewable facilities.

Simplified Process

The IESO has introduced a simplified process for applicants that were deemed QAs during the LRP I RFQ process. To be eligible for the simplified process, the qualification submission of an applicant must, for each renewable fuel, be the same or less than the aggregate number of MWs and large renewable projects that the applicant qualified for under the LRP I RFQ (less the MWs and number of projects awarded during the LRP process).

Under the simplified process, the applicant must re-evidence its financial capability and must submit the IESO letter from the LRP I RFQ process (which confirmed its status as a QA). The applicant must declare that it continues to meet the LRP I RFQ development experience requirements, but does not have to submit new and current evidence to support such declaration. The applicant must also declare that (i) each LRP I Control Group Member is still a Control Group Member of the applicant and (ii) each LRP I designated team member is still a Designated Team Member. If any changes were made to a Control Group Member (i.e. in connection with a reorganization) or to any designated team members, the applicant will not be eligible for the simplified process.

50 MW of Procurement from Existing Renewable Energy Facilities

As this procurement target was not included in the LRP I process, the IESO is currently determining the types of technology that should be included in the LRP II process. The IESO has circulated questionnaires to the relevant industry groups in order to gain a better understanding of the available technologies and how such technologies could increase the capacity and annual output of an existing project. The IESO is also seeking feedback from appropriate stakeholder and industry groups as to which technologies should be considered for LRP II, the type of contracts that should be awarded, and any other information that may be relevant to this type of procurement process.

Applicants submitting proposals for such projects will not qualify for the simplified process and will have proceed through the standard process. Such applicants will also be required to submit their project’s existing power purchase agreement and provide information about each proposed upgrade and optimization (and the corresponding change to output).

Next steps and timeline

The final LRP II RFQ documents will be posted on the IESO website on July 29, 2016 and the LRP II RFQ process will be launched on August 1, 2016. Question and comment periods will be held between August 1 and August 19, 2016. The deadline for Qualification Submissions is September 1, 2016. These dates are subject to change and will be finalized once the final LRP II RFQ documents are available.

The IESO accepted feedback on the LRP II RFQ materials until July 14, 2016 and will post the results on its website on July 29, 2016. However, the IESO indicated during the webinar that it intends to continue to accept feedback after July 14, 2016 (which may be submitted via email to, provided that it has enough time to review the feedback before July 29, 2016.

The IESO will hold a session on July 21, 2016 from 9:30 AM to 12:30 pm, which will focus on the technical aspects of the LRP II. A discussion on the LRP II technological upgrades and optimization will follow from 1:30 PM to 2:30 PM.

For additional information on the upcoming session and the LRP II process, please refer to the following link:

North American Leaders’ Summit Yields Tri-Lateral Climate, Clean Energy, and Environment Partnership Action Plan

Posted in Climate Change, Electricity, Energy – Renewable, Alternative and Clean
Selina Lee-Andersen

During the North American Leaders Summit held in Ottawa on June 29, 2016, Prime Minister Justin Trudeau, United States (US) President Barack Obama, and Mexican President Enrique Peña Nieto announced the North American Climate, Clean Energy, and Environment Partnership, which reflects the leaders’ shared vision for a clean energy economy. The Partnership is supported by an action plan (the Action Plan) that details the activities to be pursued by the three countries in order to achieve a “competitive, low-carbon and sustainable North American economy”.

As reported in our earlier blog, energy ministers from Canada, Mexico and the United States signed a Memorandum of Understanding (MOU) on Climate Change and Energy Collaboration on February 12, 2016 during the North American Energy Ministers Meeting in Winnipeg. The June 29 announcement builds on the MOU with a range of initiatives to support the North American leaders’ stated goals, including a target to achieve 50% clean power generation by 2025 through clean energy development and deployment, clean energy innovation and energy efficiency. This target will be achieved by:

  • scaling-up clean energy through domestic initiatives, including Mexico’s Energy Transition Law and new Clean Energy Certificates, the US Clean Power Plan, and Canada’s actions to further scale-up renewables, including hydro;
  • collaborating on cross-border transmission projects, including for renewable energy;
  • conducting a joint study on the opportunities and impacts of adding more renewables to the power grid on a North America-wide basis; and
  • aligning efficiency standards across all three countries, including a commitment to promote industrial and commercial efficiency through the voluntary ISO 50001 energy performance standard and to align a total of ten energy efficiency standards or test procedures for equipment by end of 2019.

On the climate change front, the leaders committed to implementing the Paris Agreement, which includes a goal to limit temperature rise this century to well below 2oC, while pursuing efforts to limit the temperature increase to 1.5oC. As the three countries work to implement their respective Nationally Determined Contributions, the parties will cooperate on climate mitigation and adaptation measures. In addition, the leaders committed to:

  • adopting a comprehensive Montreal Protocol hydrofluorocarbons (HFCs) phase-down amendment in 2016, and to reduce domestic use of HFCs;
  • phasing out fossil fuel subsidies by 2025 and urging the G20 to make commitments to reduce methane emissions in the oil and gas sector and to improve the environmental performance of heavy-duty vehicles; and
  • aligning approaches to account for the social cost of carbon and other greenhouse gas (GHG) emissions when assessing the benefits of emissions-reducing policy measures.

Further, Canada, the US and Mexico set out commitments to address short-lived climate pollutants such as methane, black carbon, and hydrofluorocarbons, which are significantly more potent than carbon dioxide. In particular, Mexico announced that it will join Canada and the US in committing to reduce their methane emissions from the oil and gas sector by 40% – 45% by 2025. To that end, the three countries will look to develop and implement federal regulations to reduce emissions from existing and new sources in the oil and gas sector as soon as possible.  The leaders also committed to developing and implementing national methane reduction strategies for key sectors such as oil and gas, agriculture, and waste management, including food waste, as well as taking action to reduce black carbon (soot) emissions in North America and promote alternatives to hydrofluorocarbons.

The Action Plan also includes a number of initiatives on transportation and biodiversity conservation, including:

  • accelerating deployment of clean vehicles in government fleets and working with industry to encourage the adoption of clean vehicles by consumers;
  • convening industry leaders and other stakeholders by spring 2017 as part of a shared vision for a competitive and clean North American automotive sector;
  • implementing aligned light-duty vehicle (LDV) and heavy-duty vehicle (HDV) fuel efficiency and/or GHG standards out to 2025 and 2027, respectively;
  • implementing aligned ultra low-sulphur diesel fuel and HDV exhaust air pollutant emission standards by 2018;
  • aligning LDV exhaust and evaporative air pollutant emission standards with full US Tier 2 standards by 2018 and fully phase in Tier 3 standards by 2025, while also implementing ultra low-sulphur gasoline standards;
  • supporting the adoption by all countries in 2016 of the market-based measure proposed through the International Civil Aviation Organization to allow for carbon-neutral growth from international civil aviation from 2020 onwards and joining the first phase of the measure adopted;
  • reducing GHG emissions from maritime shipping and continued work through the International Maritime Organization (IMO) to support implementation of a North American Emission Control Area that includes Mexico;
  • collaborating with Indigenous communities and leaders to incorporate traditional knowledge in decision-making, including in natural resource management, where appropriate;
  • renewing regional, bilateral, and trilateral activities in support of migratory bird and habitat conservation; and
  • implementing programs to conserve and improve biological corridors for whales and other species and their habitats, including their food chains and ecosystem quality.

The Action Plan represents a renewed push to strengthen continental ties among the three countries, and establishes climate change as a key policy driver for reducing GHG emissions from the oil and gas sector, boosting the development of clean power and building new cross-border transmission lines. The Action Plan also shares common objectives with provincial climate change and clean energy initiatives, including Alberta’s Climate Leadership Plan and Ontario’s Climate Change Action Plan. The newly announced initiatives under the Action Plan will no doubt feed into the development of a pan-Canadian framework for clean growth and climate change. In March 2016, four working groups were established at the First Ministers’ meeting to address four priority areas: (i) clean technology, innovation, and jobs; (ii) carbon pricing mechanisms; (iii) specific mitigation opportunities; and (iv) adaptation and climate resilience. With the working groups due to report back to the Ministers with recommendations in October 2016 and the implementation of commitments under the Action Plan, the fall agenda is shaping up to be a busy one for both provincial and federal decision-makers.

Large Renewable Procurement II

Posted in Energy – Renewable, Alternative and Clean, Independent Producers, Ontario Independent Electricity System Operator, Power, Procurement, Purchase Agreements
James Klein

On June 27, 2016 the IESO posted the draft Request for Qualifications (LRP II RFQ) and associated Prescribed Forms on the LRP Engagement page for review and comment.  According to the IESO, the LRP II RFQ builds on the LRP I RFQ and on the feedback received on the LRP I process, and the policy direction from the Minister of Energy.

 Comments and feedback on the draft LRP II RFQ and the associated Prescribed Forms are due by July 14, 2016 and can be provided via email to using the feedback form available on the LRP Engagement page.  In addition, a webinar will be offered on July 12, 2016, to provide an overview of the draft LRP II RFQ.

 Please visit the LRP Engagement page for more information and the latest updates.


Ripple Effect Continues: AER Issues Bulletin 2016-16 in Wake of Redwater

Posted in Energy – Conventional
Craig SpurnKimberly J. HowardKimberly Macnab

On Monday, June 20, 2016, the Alberta Energy Regulator (AER) issued Bulletin 2016-16 (Bulletin) detailing its interim regulatory response to the Alberta Court of Queen’s Bench decision in Re Redwater Energy Corporation (Redwater).

As detailed in a previous post, the Redwater decision allows a trustee to disclaim certain assets (and their associated abandonment and reclamation obligations) under the provisions of the federal Bankruptcy and Insolvency Act (BIA).  In doing so, such a trustee will not be liable as a licensee under the provincial oil and gas regulatory regime in relation to the renounced assets.  Further, the trustee is not required to assume any liabilities, and will not be bound by any abandonment orders issued by the AER relating to renounced assets, in seeking approval of the sales process to sell assets remaining under its possession and control.

With respect to the AER’s Licensee Liability Rating Program (LLR Program), the result of Redwater is that the AER cannot consider the disclaimed assets in calculating a company’s Licensee Liability Rating (LLR) for the purpose of approving or refusing a transfer of licences to a purchaser who is subject to a BIA bankruptcy or receivership.  Generally, these impacts all resonate from the court’s finding that the provisions of the provincial legislation governing the actions of licensees of oil and gas assets do not apply to receivers and trustees in bankruptcy of insolvent companies insofar as they conflict with the BIA, as the federal legislation is paramount.

Bulletin 2016-16

The Bulletin confirms that the AER and Orphan Well Association (OWA) have appealed Redwater, and announces three interim regulatory measures to be effective immediately.  According to the AER, the following measures are temporary, pending the earlier of the Redwater litigation or the implementation of appropriate regulatory measures:

1.           Licence Eligibility Approvals

The AER will consider and process all applications for licence eligibility under Directive 067: Applying for Approval to Hold EUB Licences as nonroutine and may exercise its discretion to refuse an application or impose terms and conditions on a licence eligibility approval if appropriate in the circumstances.

2.           Material Changes in Licence Eligibility

For holders of existing, but previously unused, licence eligibility approvals, prior to approval of any application (including licence transfer applications), the AER may require evidence that there have been no material changes since approving the licence eligibility.  This may include evidence that the holder continues to maintain adequate insurance, and the directors, officers and/or shareholders are substantially the same as when licence eligibility was originally granted.

3.           Post-Transfer LLR of 2.0 or Higher

As a condition of transfer of existing licences, approvals, and permits, the AER will require all transferees to demonstrate they will have a LLR of 2.0 or higher immediately following the transfer.

Earlier this year, the AER had issued Bulletin 2016-10 to “remind” licensees and their directors and officers “of their statutory responsibilities when ceasing operations because of insolvency or for any other reason.”  Bulletin 2016-10 specifically noted licensees’ responsibility to obtain AER approval to transfer licences, approvals, or permits to an eligible party with an LLR of at least 1.0 post-transfer, which was increased to a LLR of 2.0 in the new Bulletin.

AER’s Justification for the Bulletin

The Bulletin could have significant and far-reaching impacts to the oil and gas industry and Alberta’s economy, including preventing new licensee entrants, reducing competition for leases, properties and assets, and creating a chilling effect on investment interest.  Notwithstanding these impacts, it is our understanding that the AER felt it was necessary to quickly formulate an interim response to Redwater and as such issued the Bulletin without extensive consultation.

In justifying its regulatory measures, the AER stated the following within the Bulletin:

  • The changes are interim measures to minimize risks to Albertans and the AER intends to work with industry and other stakeholders and the Government of Alberta to develop broader and more permanent regulatory measures in accordance with government policy in response to Redwater.
  • While the AER recognizes that these measures will inconvenience some stakeholders, they are necessary to ensure the continued protection of Albertans and confidence in both the regulatory system and AER licensees; and
  • The post-acquisition minimum LLR of 2.0 was justified on the following basis: (i) it only applies to licensees wishing to acquire AER-licensed assets; (ii) it is required because the AER has observed licensees maintaining a LLR at the minimum level (i.e. 1.0) and purchasing assets, only to find themselves in financial difficulty shortly after the acquisition; and (iii) licensees have a number of ways to achieve a LLR of 2.0 or higher, including posting security, addressing existing abandonment obligations, or transferring additional assets.

What’s Next?

While ensuring that abandonment and reclamation obligations are borne by industry is within the public interest, unilateral strategies and policy changes will only compound the crippling effects on the Canadian oil and gas industry caused by current economic conditions and global oversupply and competition.  The AER appears to have recognized this in the Bulletin by committing to work with industry, stakeholders and the Government of Alberta in developing broader, more permanent regulatory measures in accordance with government policy.

The magnitude of the abandonment and reclamation liabilities in Alberta must be viewed in context in order to fully understand the size and scope of the issue.  The liabilities are magnified through the lens of the AER’s LLR Program, which looks primarily at the licensee/operator of the assets rather than all of the working interest participants.  In contrast, although the licensee/operator is the only party subject to the AER’s LLR Program, the OGCA and operating procedures provide that abandonment and reclamation obligations are shared by all working interest participants.  The vast majority of working interest participants in the province are solvent, viable companies with the financial capacity to fund their abandonment and reclamation obligations.

When viewed in light of the number of parties to whom responsibility can be cast, the magnitude of the risks is not nearly as large as originally perceived.  Changes to the LLR Program for the purposes of casting a wider net would provide a more accurate assessment of the actual risks and liabilities for Albertans.

However, the Canadian oil and gas industry is currently under significant financial hardship, as evidenced by tens of thousands of job terminations, termination of billions in capital spending, 10% rig utilization, and 25% office vacancy rates.  Among other challenges, low commodity prices, lack of access to international markets, competing international resource developments, and new carbon emissions regimes all contribute to a very tough economic environment.  Nonetheless, the oil and gas industry remains a substantial part of the Canadian economy, and it is the backbone of the provincial economy.

In this current period of restricted cash flow, piling additional obligations and financial hardship solely on licensees/operators for abandonment and reclamation liabilities risks the long-term viability of the industry in Western Canada.  While industry must help the AER and provincial government solve the problem of abandonment and reclamation liabilities, an important point that seems to be missing from the debate is that the best way of funding those liabilities is ensuring the continuation of a healthy and robust industry.  Measures to increase the burden on industry for the purpose of addressing abandonment and reclamation liabilities today and in the future must be weighed carefully against ensuring a return to a more robust provincial economy, which benefits all Albertans.

Further, increasing the LLR for transfers to 2.0 while existing licensees must only meet an LLR of 1.0 raises a number of questions, including related to fairness.  While requiring transferees to meet a LLR of 2.0 or greater, the Bulletin does not impose a similar obligation on transferors – presumably there is an equal risk that a transferor’s LLR can dip to 1.0?  Further, we speculate whether, in order to meet the required threshold, the higher LLR for transferees could lead to the disclaimer of more borderline economic, but currently inactive, wells.  What happens if a transferee’s LLR dips below 2.0 post-acquisition – would it be required to take steps to maintain a LLR of 2.0 or greater, or is 1.0 sufficient (as it is for other licensees)?

Clearly the AER and industry ought to be working together to find a long-term and viable solution to the funding and retirement of abandonment and reclamation liabilities.  In fact, we understand that discussions of this nature have begun among the AER, the Explorers and Producers Association of Canada (EPAC), the Canadian Association of Petroleum Producers (CAPP) and potentially others.

The Quebec Government introduces the Petroleum Resources Act

Posted in Québec
Pierre BoivinPierre RenaudDominique Amyot-BilodeauMartin Thiboutot

On June 7, 2016, the Quebec Minister of Energy and Natural Resources, Mr. Pierre Arcand (the “Minister“) introduced Bill No. 106 at the National Assembly (An Act to implement the 2030 Energy Policy and to amend various legislative provisions) (the “Bill“). Among other things, this Bill would enact the new Petroleum Resources Act in replacement of the existing provisions of the Mining Act (CQLR c M-13.1) that currently regulate hydrocarbons mining activities in the province.

This Bill had been expected for several months and would significantly modify the legal framework applicable to the development and production of hydrocarbons in Quebec. It purports to govern the development of petroleum resources in the province of Quebec while ensuring the safety of persons and property, environmental protection, and optimal recovery of the resource. The bill also aims at ensuring that mining work involving hydrocarbons is performed in compliance with the greenhouse gas emission reduction targets set by the Quebec Government. Continue Reading

The Quebec Government introduces its Bill to Modernize the Environmental Authorization Scheme

Posted in Québec
Dominique Amyot-BilodeauCindy Vaillancourt

On June 7, 2016, the Quebec Minister of Sustainable Development, Environment and the Fight against Climate Change, Mr. David Heurtel (the “Minister“), introduced Bill 102[1] at the Quebec National Assembly, which aims at modernizing the environmental authorization scheme established by the Environment Quality Act. If adopted in its current form, this bill could have important repercussions on the environmental assessment procedure and on the authorization scheme of industrial projects carried out in Québec. Continue Reading

Quebec Government Introduces Legislation Implementing its 2030 Energy Policy

Posted in Plan Nord, Québec, Régie de l’énergie, Regulation
Daniel BénayMathieu LeBlancMason Gordon

On June 7, 2016, the Quebec Government introduced before the National Assembly Bill 106, An Act to implement the 2030 Energy Policy and to amend various legislative provisions. The 2030 Energy Policy has the principal goal of making Quebec, by 2030, a North American leader in renewable energy and energy efficiency. Continue Reading

What Every Stakeholder Needs to Know About Lobbyist Registration

Posted in Energy – Conventional, Energy – Renewable, Alternative and Clean, Federal
AlbertaBritish ColumbiaOntarioQuébec
Mathieu LeBlanc

The following article published in our firm’s newsletter could be of interest to many readers active in the energy industry across Canada. It discusses the applicable rules for lobbyist registration in Ontario, Ontario municipalities, Québec, British Columbia, Alberta and at the federal level. Continue Reading

When the Levy Breaks: Alberta Government Tables the Climate Leadership Implementation Act

Posted in Carbon Tax, Climate Change, Climate Policy, Energy – Renewable, Alternative and Clean
Kimberly J. HowardSelina Lee-AndersenKimberly Macnab

On May 24, 2016, Alberta’s provincial government tabled Bill 20 for first reading in the legislature.  Otherwise known as the Climate Leadership Implementation Act (Climate Act), Bill 20 furthers the implementation of the provincial government’s Climate Leadership Plan released in November 2015.

Bill 20 provides for a carbon levy on consumers of fuel, and creates an agency called Energy Efficiency Alberta, as part of the provincial government’s ongoing commitment to climate change policies and initiatives.   Notably absent from Bill 20 are any details on initiatives or incentives for transitioning to renewable energy sources.

More information on this development may be found on McCarthy Tétrault’s Canadian ERA Perspectives blog.