Home  About Blakes  Offices  People  Practices  Publications  Media  Join Blakes  Seminars   French  Chinese font [+] [-]
   
Recent Legal Bulletins in Energy - Electricity


Richard Corley & David Feldman

Ontario's Minister of Energy and Infrastructure, Brad Duguid, announced on May 10, 2010 the launch of the Community Energy Partnerships Program (CEPP). The CEPP will generally cover up to 90% of eligible development costs to a maximum of C$200,000 for community-owned renewable energy projects between 10 kilowatts and 10 megawatts. Charities, not-for-profits and co-ops will be eligible for the fund, as well as projects developed by individual Ontario residents.

The CEPP will likely increase the number of community-owned renewable energy project proponents applying to Ontario's Feed-in Tariff (FIT) Program. The FIT Program is North America's first comprehensive guaranteed pricing structure for renewable electricity production and is a centrepiece of Ontario's bid for an international leadership position in clean energy. It offers stable prices under long-term contracts for energy generated in Ontario from renewable sources, such as bioenergy (biomass, biogas, and landfill gas), onshore and offshore wind, solar photovoltaic (PV) (ground-mounted or rooftop), and waterpower (naturally flowing water).

On April 8, 2010, the Minister announced that FIT contracts had been offered for 184 large-scale projects representing 2,421 megawatts of renewable energy generation throughout Ontario. (See our April 2010 Blakes Bulletin on CleanTech/Energy: Ontario Announces 184 Feed-in Tariff Contracts for 2,421 MW of Renewable Energy for more information about these large-scale projects). Included in these FIT contracts were 20 for large-scale community-owned renewable energy projects located in several communities throughout Ontario, including Elmira, Clarington, Singhampton, Wainfleet, and Webbwood. These community projects represent a combined generating capacity of over 264 megawatts, which is enough electricity to power more than 70,000 homes.

The Minister announced the launch of the CEPP at the Community Power Finance Forum held at the MaRS Centre in Toronto, at which Blakes was one of the lead sponsors. The Forum presented community power project developers, funders, and policy makers with finance, funding and project management information relevant to community-owned renewable power projects under the FIT Program.

Feed-in Tariff Program
The FIT Program was launched by the Ontario government in September 2009 under the Green Energy and Green Economy Act, 2009, which was passed into law on May 14, 2009. The Ontario Power Authority (OPA) is responsible for implementing the FIT Program. More information on programs under the Green Energy Act can be found in our September 2009 Blakes Bulletin on Energy/CleanTech: Ontario Launches Programs to Implement its Green Energy Act.

In addition to the 184 large-scale projects announced on April 8, 2010, Capacity Allocation Exempt FIT contracts were announced by the OPA on March 10, 2010 for 510 mid-sized projects representing 112.2 megawatts of renewable energy generation. Capacity Allocation Exempt projects are defined as: (1) projects with no more than 250 kilowatts of rated generating capacity where the facility is connected to a less than 15 kV line; and (2) projects of 500 kilowatts or less of rated generating capacity where the facility is connected to a 15 kV or greater line. Capacity Allocation Exempt projects can be developed without significant impact on the transmission or distribution systems, through a streamlined and expedited connection process.

The FIT Program also has a separate stream called "microFIT" for renewable energy generation projects of 10 kilowatts or less. This subset of the FIT Program is designed for homeowners and small businesses interested in generating and selling power typically from existing premises. The first 700 microFIT conditional offers were issued on December 16, 2009. As of March 8, 2010, more than 180 microFIT projects were connected to the grid and will be receiving payments for the electricity that they generate. As of April 6, 2010, the OPA had sent approximately 3,000 conditional microFIT offers, after receiving approximately 8,500 microFIT applications representing 76.5 megawatts of capacity, including 8,424 applications for solar photovoltaic projects representing 76.0 megawatts of capacity. The OPA is accepting microFIT applications on an ongoing basis and eventually anticipates a 30-day turnaround for conditional offers.

By encouraging the development of renewable energy in Ontario, the FIT Program will help Ontario honour its commitment to phase out coal-fired electricity generation by 2014, boost economic activity and the development of renewable energy technologies, and create new green industries and jobs. The FIT Program is expected to create 20,000 jobs and attract approximately C$9-billion in private sector investment. The OPA continues to accept and process FIT applications. Applicants to the FIT Program must register online and submit a FIT application to the OPA.

Community Price Adder
The "Community Price Adder" is an incremental amount that forms part of the FIT contract price payable by the OPA to the owners of Community Participation Projects. The Community Price Adder is the Maximum Community Price Adder multiplied by the Community Participation Level multiplied by two, up to the Maximum Community Price Adder. Therefore, Projects that have a Community Participation Level of at least 50% are eligible for the Maximum Community Price Adder. Similarly, a Project with a 10% Community Participation Level is only eligible for 20% of the Maximum Community Price Adder. The Maximum Community Price Adder is 1¢/kWh for wind and ground-mounted solar PV, 0.6¢/kWh for water, and 0.4¢/kWh for biogas, biomass, and landfill gas.

A Project is a "Community Participation Project" if the Applicant or Supplier is a Community Investment Member, or if the Project has at least a 10% Community Participation Level. A Community Investment Member can be: (i) one or more individuals Resident in Ontario; (ii) a Registered Charity with its head office in Ontario; (iii) a Not-For-Profit Organization with its head office in Ontario; or (iv) a "co-operative corporation", as defined in the Ontario Co-operative Corporations Act, all of whose members are Resident in Ontario. The Community Participation Level refers to the percentage of the Economic Interest of the Applicant or the Supplier that is held by Community Investment Members. (All initially capitalized terms not otherwise defined in this bulletin have the meanings set forth in the FIT Standard Definitions.)

Aboriginal Price Adder
Similar to the Community Price Adder for Community Participation Projects, the FIT Program includes an Aboriginal Price Adder for Aboriginal Participation Projects. The Aboriginal Price Adder is the Maximum Aboriginal Price Adder multiplied by the Aboriginal Participation Level multiplied by two, up to the Maximum Aboriginal Price Adder. The Maximum Aboriginal Price Adder is 1.5¢/kWh for wind and ground-mounted solar PV, 0.9¢/kWh for water, and 0.6¢/kWh for biogas, biomass, and landfill gas.

A Project is an "Aboriginal Participation Project" if an Aboriginal Community holds at least a 10% Economic Interest in the Applicant or Supplier. "Aboriginal Community" means, for the purposes of the FIT Program: (i) a First Nation that is a "Band" as defined in the Canadian Indian Act; (ii) the Métis Nation of Ontario or any of its active Chartered Community Councils; (iii) an organization that represents the collective interests of a community that is composed of Métis or other aboriginal individuals; or (iv) a corporation that is wholly owned by one or more Aboriginal Communities as described in (i), (ii) or (iii).

Community Energy Partnerships Program
The CEPP offers grants to certain community-owned renewable energy projects. The maximum grant is: C$10,000 for solar and wind projects between 10 and 50kW; C$75,000 for solar and wind projects between 50 and 1000kW and biogas, biomass, and landfill gas projects between 10 and 500kW; and C$200,000 for solar and wind projects between 1 and 10MW, biogas, biomass, and landfill gas projects between 500kW and 10MW, and waterpower projects between 10kW and 10MW.

According to the announcement, the CEPP is to cover up to 90% of the actual costs of each eligible activity (as set out on the CEPP website), up to the maximum amount set out above. Applicants will be required to contribute a minimum of 10% of all costs of project activities funded by the CEPP. Renewable energy projects may be eligible for CEPP funding if they are between 10kW and 10MG, are located in Ontario, are economically viable and the subject of a future FIT contract, are not funded by any other OPA funded program, and are developed by a "Community". A "Community" within the CEPP Rules is essentially the same as a Community Investment Member who has a 100% Community Participation Level within the FIT Rules.

The CEPP Fund will be co-managed by the Community Power Fund and Deloitte. The mission of the Community Power Fund is to provide financial resources to help support renewable energy projects owned, developed and governed by Ontario communities. The Community Power Fund has successfully managed and operated a multimillion dollar community power grant program since 2007. As a result of this work, the Community Power Fund had gained a better understanding of the financing needs of community power projects and the experience required to co-manage the CEPP Fund.

Future Rounds of FIT Contracts
Applicants to the FIT Program for non-Capacity Allocation Exempt projects who were not offered a FIT contract but who are otherwise eligible to receive such an offer must now wait for future decisions of the OPA to award FIT contracts. The OPA uses an Economic Connection Test (ECT) to identify transmission or distribution system expansion projects that will support renewable generation and meet economic requirements. The OPA is conducting regular presentations to provide updates on the ECT and to further elaborate on the ECT process. The most recent ECT presentation was conducted by the OPA on May 19, 2010. The OPA will conduct ECTs every six months, with the first ECT beginning in early August 2010. The upcoming ECT will take into account all eligible FIT applications that have been received by June 4, 2010. Additional FIT contracts will be offered to eligible applicants based on the results of the ECTs, once work begins on the associated expansion projects.

The ECT does not apply to the mid-sized Capacity Allocation Exempt projects. Under the FIT Program, Capacity Allocation Exempt projects proceed directly to a FIT contract after the application is complete and checked. Furthermore, Capacity Allocation Exempt Projects are not required to submit application security, nor are they subject to the transmission and distribution availability tests, the FIT production line, or the FIT reserve.

If you are considering investing in or developing renewable energy projects, or if you would like us to submit an anonymous inquiry to the OPA regarding the Economic Connection Test, the Community or Aboriginal Price Adders, the CEPP, or any other aspect of the FIT Program or microFIT Program, please contact Richard Corley by email at richard.corley@blakes.com or by telephone at 416-863-2183 or David Feldman by email at david.feldman@blakes.com or by telephone at 416‑863-4021 or any member of the Blakes CleanTech Group.




Paul Cassidy & Selina Lee-Andersen

On April 28, 2010, the British Columbia (BC) government introduced Bill 17, the Clean Energy Act (the Act), into the legislature for its first reading. The Act provides a foundation to assist the province in achieving its goals of electricity self-sufficiency, job creation and reduced greenhouse gas (GHG) emissions. The Act builds on the work of the Green Energy Advisory Task Force, which was appointed in November 2009 to provide recommendations for a comprehensive clean energy development strategy in BC.

The proposed Act is designed to address three priority areas:

  • ensuring electricity self-sufficiency at low rates;

  • harnessing BC's clean power potential to create jobs in all regions of the province; and

  • strengthening environmental stewardship and reducing GHG emissions.

The BC government's 2007 Energy Plan commits the province to electricity self-sufficiency by 2016. The Act facilitates this goal by providing a new regulatory framework for long-term electricity planning, commitments to renewable electricity generation, streamlined approval processes, and measures to promote electricity efficiency and conservation. It also strengthens protection for ratepayers with new measures to promote competitive rates and ensure the benefits from the province's "heritage generation assets" continue to flow to British Columbians.

Perhaps most significantly, the Act provides for the following:

  • Inclusion of the export of electricity as an objective, thus enabling renewable power producers to work with BC Hydro to actively seek opportunities to sell clean, reliable electricity to other provinces and the U.S. New calls for clean power will be issued when export opportunities are secured.

  • Exemption of certain energy projects from sections 45 to 47 and 71 of the Utilities Commission Act (UCA), including projects awarded energy supply contracts under the Clean Power Call.

  • Consolidation of BC Hydro and the BC Transmission Corporation (BCTC). BCTC was originally created in 2003 in response to calls for increased independence of transmission and the development of regional transmission organizations. However, regional transmission organizations did not develop, and the movement towards greater independence for transmission did not advance further. As a result, the government views this as an opportunity to save costs and increase policy alignment through the consolidation of BC Hydro and BCTC.

  • Modernization of the role of the British Columbia Utilities Commission (BCUC) and alignment of BCUC activities with the provincial government's energy policy objectives. As noted above, certain energy projects will be exempt from BCUC approval requirements under the UCA; however, BCUC will continue to regulate BC Hydro's domestic supply and rates. BCUC will also continue to regulate the safety and reliability of the BC Hydro system, handle ratepayer complaints, and regulate operating, management and administrative costs.

Overview of the Clean Energy Act
The proposed Act is comprised of 10 parts and 77 sections. A first reading of the Act is currently underway, so the legislation may be revised before the final Act is passed. Below is an overview of the key provisions of the Act (to view a copy of the first reading of the Act online, click here.

BC's Energy Objectives
Part 1 of the Act sets out 16 specific energy objectives for the province, including expediting clean energy investments, protecting BC ratepayers, ensuring competitive rates, encouraging conservation, strengthening environmental protection, and aggressively promoting regional job creation and First Nations' involvement in clean electricity development opportunities.

Prohibited Projects
Under Part 2 of the Act, sections 10 and 11 prohibit the development of certain energy projects as set out in Schedule 2. Section 12 of the Act prohibits BC Hydro from acquiring electricity from a proposed facility that is located, in whole or in part, in provincial parks, protected areas and conservancies.

Integrated Resource Plan
Section 3 of the Act requires BC Hydro to submit a long-term Integrated Resource Plan (Plan) that allows for public input and long-term stability for industry. The first Plan will consider BC's electricity needs over the next 30 years and must be submitted within 18 months of the Act coming into force and will be subject to acceptance by the government. Once accepted, BCUC will be required to consider the Plan in its future decisions.

Exemption of Certain Projects from BCUC Review
Section 7 of the Act provides for the exemption of certain strategic projects from approval by BCUC (which projects would otherwise have required BCUC approval under the UCA): (i) Northwest Transmission Line; (ii) Mica units 5 and 6; (iii) Revelstoke unit 6; (iv) Site C; (v) Bioenergy Phase 2 Call for Power; (vi) BC Hydro's Integrated Power Offer; (vii) Clean Power Call (issued on June 11, 2008); (viii) Standing Offer Program; (ix) Feed-in Tariff; and (x) BC Hydro's Smart Metering and Smart Grid Programs. Future projects, specifically those for the purpose of supplying export markets, will also be exempt from BCUC review under section 4(1)(b) of the Act. Notwithstanding the exempt projects listed in the Act, BCUC will continue to regulate BC Hydro and provide oversight for future BC Hydro projects and programs.

Standing Offer Program and Feed-in Tariff
Part 4 of the Act contains provisions to create greater flexibility around the Standing Offer Program. In particular, the Act enables repricing to reflect the results of recent clean power calls and includes an option to increase the maximum project size above 10 MW. With respect to feed-in tariffs, the Act enables the implementation of a feed-in tariff program to support the development of emerging technologies in renewable power production. The parameters of the feed-in tariff program will be established through regulation.

Energy Efficiency and Greenhouse Gas Reductions
To promote electricity efficiency and conservation, Part 5 of the Act provides for the installation of smart meters by 2012 and enables initiatives and programs to encourage the reduction of GHGs.

Consolidation of BC Hydro and BC Transmission Corporation
Part 7 provides for the integration of BC Hydro and BCTC into a single entity with one board of directors and executive. Furthermore, the Act provides for the transfer of all BCTC assets, liabilities and employees to BC Hydro.

First Nations Clean Energy Business Fund
Part 6 of the Act establishes the First Nations Clean Energy Business Fund, which aims to support revenue-sharing and facilitate further First Nations participation in renewable power production.

As noted above, the Act includes the export of electricity as an objective. Currently, BC Hydro does not contract for long-term export power sales. However, under the proposed Act, BC Hydro will be able to aggregate clean and renewable energy and offer customers outside BC the opportunity to secure long-term agreements for clean power at competitive prices. In order to meet these contractual commitments, BC Hydro will issue new clean power calls. Under the new regulatory framework, BC ratepayers will not subsidize export power sales because the Act explicitly requires BCUC to ensure that any expenditure for exports is not included in domestic rates.

Green Energy Advisory Task Force Report
On the same day the Act was introduced, the report of the Green Energy Advisory Task Force was also released and contains a number of recommendations for implementing BC's clean energy strategy.

The Green Energy Advisory Task Force was established in November 2009 to provide input on BC's clean energy strategy. The task force was composed of four advisory groups, each focused on the following areas:

  • procurement and regulatory reform;

  • carbon pricing, trading and export market development;

  • community engagement and First Nations partnerships; and

  • resource development.

Each group prepared a report based on their individual mandates. To view the final report of the Green Energy Advisory Task Force online, click here.

The Act builds on a number of recommendations from the task force, including:

  • confirming BC's commitment to the Heritage Contract (as provided for under the BC Hydro Public Power Legacy and Heritage Contract Act) to ensure BC ratepayers continue to receive the benefits of BC's low-cost electricity assets;

  • moving forward critical infrastructure projects such as Site C and the Mica and Revelstoke upgrades;

  • increasing BC's clean energy supply to meet domestic and future export demand;

  • aligning the implementation of policy between BC Hydro and BCUC and reviewing the need for a separate transmission corporation;

  • encouraging initiatives to reduce GHG emissions and improve energy efficiency; and

  • creating a First Nations Clean Energy Business Fund to support revenue-sharing opportunities and to increase First Nations participation in clean energy resource development.

Paving the Way to BC's Clean Energy Future
By streamlining regulations around renewable power projects, the BC government is seeking to encourage renewable energy investments in the province. The Act also creates a new model to secure long-term export power agreements, which signals the provincial government's intent to actively seek out opportunities in export markets. With a clear export policy objective in place and exemptions from BCUC approvals for certain projects, including those projects in the Clean Power Call, the government appears to be paving the way for independent power producers to play a greater role in BC's clean energy future.

For further information, please contact:

Paul Cassidy 604-631-3390
Selina Lee-Andersen 604-631-3303

or any member of our CleanTech or Environmental Groups.




Ontario's Minister of Energy and Infrastructure, Brad Duguid, announced on April 8, 2010, that Feed-in Tariff (FIT) Contracts have been offered for 184 large-scale projects representing 2,421 MW of renewable energy generation throughout Ontario. This is enough energy to power 600,000 homes. The approved large-scale projects include 76 ground-mounted solar projects representing 651 MW, 47 onshore wind projects representing 1,229 MW, 46 waterpower projects representing 192 MW, and one offshore wind project representing 300 MW.

Feed-in Tariff Program
The FIT Program is North America's first comprehensive guaranteed pricing structure for renewable electricity production and is a centre-piece of Ontario's bid for an international leadership position in clean energy. It offers stable prices under long-term contracts for energy generated in Ontario from renewable sources, such as bioenergy (biomass, biogas and landfill gas), onshore and offshore wind, solar photovoltaic (PV) (ground-mounted or roof-top) and waterpower (naturally flowing water).

The FIT Program was launched by the Ontario government in September 2009 under the Green Energy and Green Economy Act, 2009, which was passed into law on May 14, 2009. The Ontario Power Authority (OPA) is responsible for implementing the FIT Program. More information on programs under the Green Energy Act can be found in the Blakes Bulletin titled "Ontario Launches Programs to Implement its Green Energy Act" available on the Blakes website.

The Minister's announcement on April 8 follows a previous announcement on March 10, 2010, that Capacity Allocation Exempt FIT Contracts were awarded by the OPA for 510 mid-sized projects representing 112.2 MW of renewable energy generation. Of these 510 projects, there were 476 roof-top solar PV projects representing 101.8 MW. Capacity Allocation Exempt projects are defined as (1) projects with no more than 250 kW of rated generating capacity where the facility is connected to a less than 15 kV line, and (2) projects of 500 kW or less of rated generating capacity where the facility is connected to a 15 kV or greater line. Capacity Allocation Exempt projects can be developed without significant impact on the transmission or distribution systems, through a streamlined and expedited connection process.

The FIT Program also has a separate stream called "microFIT" for renewable energy generation projects of 10 kW or less. This subset of the FIT Program is designed for homeowners and small businesses interested in generating and selling power typically from existing premises. The first 700 microFIT conditional offers were issued on December 16, 2009. As of March 8, 2010, more than 180 microFIT projects were connected to the grid and will be receiving payment for the electricity they generate. As of April 6, 2010, the OPA had sent approximately 3,000 conditional microFIT offers, after receiving approximately 8,500 microFIT applications representing 76.5 MW of capacity, including 8,424 applications for solar photovoltaic projects representing 76.0 MW of capacity. The OPA is accepting microFIT applications on an ongoing basis and eventually anticipates a 30-day turnaround for conditional offers.

By encouraging the development of renewable energy in Ontario, the FIT Program will help Ontario honour its commitment to phase out coal-fired electricity generation by 2014, boost economic activity and the development of renewable energy technologies, and create new green industries and jobs. The FIT Program is expected to create 20,000 jobs and attract approximately C$9-billion in private-sector investment. The OPA continues to accept and process FIT applications. Applicants to the FIT Program must register online and submit a FIT application to the OPA.

Future Rounds of FIT Contracts
Applicants to the FIT Program for non-Capacity Allocation Exempt projects who were not offered a FIT Contract but who are otherwise eligible to receive such an offer must now wait for future rounds of decisions to award FIT Contracts. The OPA uses an Economic Connection Test (ECT) to identify transmission or distribution system expansion projects that support renewable generation and meet economic requirements. The OPA will conduct ECTs every six months, with the first ECT beginning in August or September 2010. Additional FIT Contracts will be offered to eligible applicants based on the results of the ECTs, once work begins on the expansion projects. The OPA is conducting regular presentations and consultations regarding the ECT. The first such ECT presentation was conducted by the OPA on March 23, 2010.

In contrast to the large-scale FIT projects, the ECT does not apply to the mid-sized Capacity Allocation Exempt projects. Under the FIT Program, Capacity Allocation Exempt projects proceed directly to a FIT Contract after the application is complete. Furthermore, Capacity Allocation Exempt Projects are not required to submit application security, nor are they subject to the transmission and distribution availability tests, the FIT production line or the FIT reserve.

Domestic Content Requirements
The FIT Program also contains Domestic Content Requirements, under which wind and solar projects are required to include a minimum percentage of goods and services from Ontario. The Domestic Content Requirements are based upon actual activities on the project, as opposed to restrictions on ownership or equity interests or benefits. For example, the Domestic Content Requirement for wind projects over 10 kW is 25% if the milestone date for commercial operation is before January 1, 2012, and 50% if the milestone date is on or after January 1, 2010. For solar projects over 10 kW, the Domestic Content Requirement is 50% if the milestone date for commercial operation is before January 1, 2011, and 60% if the milestone date is on or after January 1, 2011. The OPA determines domestic content based on pre-determined qualifying percentages associated with designated activities (as specified in Exhibit D to the FIT Contract), which are indicative of overall project value. The OPA is carrying out regular consultations to provide clarifications and certainty regarding the Domestic Content Requirements.

* * * * *

If you are considering investing in or developing renewable energy projects, or if you would like to submit an anonymous inquiry to the OPA regarding the Economic Connection Test, the Domestic Content Requirements, or any other aspect of the FIT Program or microFIT Program, please contact:

Richard Corley 416-863-2183
Ted Betts 416-863-4198
David Feldman 416-863-4021

or any member of the Blakes CleanTech or Energy Groups.




Caroline Findlay & Janice Walton

In its recent decision in West Moberly First Nations v. British Columbia (Chief Inspector of Mines) and First Coal Corporation, the B.C. Supreme Court (the Court) examined the meaning of the treaty right to hunt for caribou in the context of a proposed coal exploration program in the Treaty 8 area of northeastern B.C. The Court ordered a stay of provincial exploration permits for 90 days and ordered the Crown, in consultation with the West Moberly First Nations (West Moberly), to proceed expeditiously to put in place a reasonable, active plan for the protection and augmentation of a local caribou herd. The Court's basis for this remedy can be summed up in the following passage from its reasons:

“I conclude that a balancing of treaty rights of Native peoples within the rights of the public generally, including the development of resources for the benefit of the community as a whole, is not achieved if caribou herds in the affected territories are extirpated.”

This decision adds to the evolving case law on the Crown's duty to consult and accommodate aboriginal and treaty rights, and illustrates what is “reasonable” accommodation. This case also squarely demonstrates how aboriginal law is influencing the shape of current environmental law, particularly the protection of species at risk.

Basis of West Moberly First Nations Challenge
In its judicial review application, West Moberly applied for a declaration of invalidity in respect of three exploration-related permits issued by the provincial government to First Coal Corporation (First Coal). These permits authorized First Coal to obtain bulk samples of coal, to conduct an advanced exploration program, and to clear trees to facilitate this exploration. West Moberly claimed that, in issuing these permits, the Crown failed to consult adequately and meaningfully concerning their Treaty 8 right to hunt caribou, and had failed to reasonably accommodate their hunting rights.

This litigation appears to have been preceded by the West Moberly asking the Province of British Columbia (the Province) to implement a rehabilitation plan for the Burnt Pine Herd of caribou, which is resident in the area of First Coal's mineral tenure, and which the West Moberly claim has been reduced to a population of 11. The Burnt Pine Herd form part of the Southern Mountain population of Woodland Caribou, which is a species listed as “threatened” under the federal Species at Risk Act (SARA).

All parties agreed that the Crown was required to consult West Moberly on the basis of its treaty right to hunt, but the parties diverged on the nature and scope of that right. Similarly, the parties advanced opposing submissions as to whether the Crown had adequately consulted and accommodated West Moberly's concerns, including whether a rehabilitation or recovery plan for the Burnt Pine Herd was necessary.

a) Nature of Treaty Right to Hunt
An important aspect of the Court's decision is how it defined the nature of the treaty right to hunt. In turn, this characterization of the right, together with the nature of the impact on it from the proposed exploration, is at the heart of the Court's conclusion that the Crown did not carry out consultation meaningfully and did not implement reasonable accommodation. Treaty No. 8, dated September 22, 1899, states, in part:

“... Her Majesty the Queen hereby agrees with the said Indians that they shall have right to pursue their usual vocations of hunting, trapping, and fishing throughout the tract surrendered as heretofore described, subject to such regulations as may from time to time be made by the Government of the country acting under the authority of Her Majesty, and saving and excepting such tracts as may be required or taken up from time to time for settlement, mining, lumbering, trading, or other purposes.”

In interpreting this right, the Crown argued that the treaty right was a broad “right to hunt for meat” (not just caribou) across the First Nation's entire traditional territory, and was subject to the Crown's right to “take up” land for mining, as set out in the Treaty. Given the scope of this right and the expected impact, the Crown argued that its efforts to consult and accommodate were met, essentially because certain mitigation steps were developed by First Coal to avoid impact to the caribou herd and, more importantly, there were other caribou herds that could be hunted by the West Moberly. As such, the Crown contended that West Moberly's opportunity to hunt caribou in its traditional territory “will not be significantly reduced” by First Coal's activities.

The Court found that the West Moberly have a treaty-protected right to hunt caribou in the area impacted by First Coal's exploration activities. That area was part of West Moberly's traditional seasonal round, to which hunters travelled at certain times of the year. Given the Crown's concession that no recovery plan was in place for the caribou herd in that area, the Court held that the Crown had failed to reasonably accommodate West Moberly's concerns.

b) Accommodation Means Recovery of the Species
The West Moberly were concerned that the few remaining members of the Burnt Pine Herd not be impacted by First Coal's activities. Inherent in this concern was the historic decimation of the herd caused by past activity, including impacts related to the construction of the WAC Bennett and Peace Cannon Dams in the 1960s and 1970s. First Coal had submitted a Caribou Mitigation and Monitoring Plan (the Mitigation Plan) in response to concerns expressed by West Moberly in the consultation period prior to the permits being issued. Two government scientists commented on the Mitigation Plan, suggesting that while providing measures for avoiding and minimizing impacts to the herd, the Mitigation Plan was inconsistent with the goal of maintaining or increasing caribou numbers and distribution.

The Court found that the Crown's failure to establish a plan for the protection and rehabilitation of the Burnt Pine Herd was a failure to reasonably accommodate the West Moberly hunting rights. While First Coal's Mitigation Plan was a step in the right direction of protecting caribou habitat, the Court was concerned with the lack of a rehabilitation program for the herd.

In ordering the government to develop a caribou rehabilitation plan, the Court did not explicitly limit its remedy to the context of First Coal's permit applications. Such a general remedy, it could be argued, broadened the scope of accommodation beyond that of responding to First Coal's infringement of the First Nation's rights. In ordering the Crown to develop a plan to not just protect but also augment the Burnt Pine Herd, it could be argued that the Court ordered the government to find a way to redress past infringement of West Moberly's hunting rights.

c) Cumulative Impacts
The Crown recognized the cumulative impacts of First Coal's project on West Moberly's traditional territory, but when asked by West Moberly to address this in the permit process, the Crown answered that this issue is “beyond the scope of this project to fully assess”. The Court commented that such a statement by a Crown decision-maker – that it does not have the authority to assess the “taking up” of a treaty right – fails to uphold the Crown's honour. This leaves for another day the intriguing question of whether cumulative impacts assessment is now part and parcel of the Crown's duty to consult/accommodate.

d) Species at Risk Issues
The Court did not analyze the requirements of species at risk laws, why the recovery planning for the Southern Mountain population of the woodland caribou has not been completed, or determine the relevance, if any, of the statutory recovery planning process to the question of whether the Crown had properly accommodated West Moberly's hunting rights. Because of this, it is difficult to predict how significant the decision may be to future recovery planning.

SARA requires the federal government to carry out recovery planning for species listed as “endangered” or “threatened” under the Act. It also contains specific requirements for this recovery planning to be carried out in cooperation with affected First Nations. British Columbia does not have similar legislative requirements, but has signed on to the federal/provincial Accord for the Protection of Species at Risk. This Accord, while non-binding, indicates a commitment on the part of the Province to participate in species recovery actions.

Several recovery teams, consisting of representatives of federal and provincial governments, members of the scientific community and First Nations, have been working for a number of years to develop the recovery strategies for the various subpopulations of caribou listed under SARA. However, largely because of uncertainties in the science or understanding of all the causes of the woodland caribou's decline, the work has taken longer to complete than is required under SARA. Despite the lack of completion of formal recovery strategies under SARA, some plans for caribou recovery have been completed and are being implemented. One example is the Mountain Caribou Recovery Implementation Plan, which specifically impacts part of the Southern Mountain population. It does not, however, include the Burnt Pine herd.

West Moberly claimed that neither the federal nor provincial governments had lived up to their legal obligations under SARA and the Accord with respect to recovery planning for the Burnt Pine Herd. One troubling aspect of this argument is that recovery planning under SARA occurs at a population level. As such, even if the recovery strategy for the Southern Mountain population of the woodland caribou had been completed, it would not necessarily plan for or result in augmentation of this specific herd.

The Court's remedy of an order to plan recovery and augmentation of the Burnt Pine Herd may prove problematic, as it does not require co-ordination with the national development of recovery strategy for the Southern Mountain population of the woodland caribou under SARA, or the current plan being implemented by British Columbia for a portion of this particular population. It also fails to recognise the requirement under SARA for consultation with locally affected First Nations. Effectively, the Court has now imposed recovery planning requirements for one herd that may ultimately not be compatible with the recovery planning that is required under SARA for the species as a whole.

This decision also raises serious questions to whether the completion of recovery planning under SARA and provincial regimes will provide certainty to resource users as to how governments will regulate activities that potentially impact species at risk which are in traditional territories of the First Nations. Further, it raises serious questions as to whether the extensive First Nations' consultative processes written into SARA are sufficient to address the consultation duties of the Crown. At the very least, the decision raises the prospect that broad federal population-level recovery plans may not insulate provincial permit-holders from allegations that the permitted activity would impose unreasonable impacts on asserted aboriginal and treaty rights.

For further information, please contact any of the following members of our Environmental Law Group:

MONTRÉAL Katia Opalka 514-982-5047
OTTAWA Gord Cameron 613-788-2222
TORONTO Michelle Chaisson 416-863-4006
Robert Fishlock 416-863-2904
Ben Jetten 416-863-2938
Jonathan Kahn 416-863-3868
CALGARY Dufferin Harper 403-260-9710
Ken Mills 403-260-9648
Dalton McGrath 403-260-9654
David Tupper 403-260-9722
Abram Averbach 403-260-9632
VANCOUVER Paul Cassidy 604-631-3390
Caroline Findlay 604-631-3333
Selina Lee-Andersen 604-631-3303
Angela Stolz 604-631-4184
James Sullivan 604-631-3358
Janice Walton 604-631-3354



While the lead-up to and the media coverage of the federal budget introduced on March 4, 2010 (the Budget) was heavily skewed towards deficit control, there was no shortage of significant tax proposals in the Budget, including the following:

  • effective immediately, unless an employer elects to forgo its deduction, employee stock option holders will be disqualified from capital gains rate taxation if their options are cashed out instead of being exercised, and the deferral rules for public company stock options introduced in the 2000 budget will be repealed;

  • effective immediately, foreign investors will no longer be subject to potential tax and compliance requirements on sales of Canadian shares that do not constitute a real property interest;

  • the proposed "foreign investment entity" regime, first announced in 1999 but never enacted, will be abandoned, and the related proposed "non-resident trust" rules will be relaxed; and

  • new rules will be enacted to curb loss transfer transactions achieved on conversion of income trusts and foreign tax credit planning schemes.

The Minister of Finance also announced a public consultation on proposals to require reporting of certain types of "aggressive" transactions, similar in some respects to measures previously proposed in Quebec.

Despite the fact that the government faces a significant budgetary deficit, no changes were made to the planned phased reductions in corporate tax rates nor were any changes proposed to personal tax rates.

In the remainder of this bulletin, we discuss these and other business tax measures contained in the Budget.

Employee Stock Option Rules
No deduction for cash-out

Generally, the Income Tax Act (the Tax Act) provides that the grant of an employee stock option is a non-event. At the time of exercise, the employee is taxed on the in-the-money value of the option. This deemed benefit is treated as employment income. Provided certain conditions are met, the option benefit is eligible for a 50% deduction – effectively resulting in the option benefit being taxed at capital gains rates.

Capital gains rate taxation is generally available upon crystallization of the option benefit, whether by actual exercise of the option into underlying shares, or by the "cash-out" of the option pursuant to the exercise by the holder of a right to be paid the in-the-money value in cash. A well-known opportunity existed for an employer to claim a deduction on the cash-out of its employees' options. It is understood that the availability of such a deduction in the context of a change of control of the employer is the subject of ongoing litigation. However, even the Canada Revenue Agency (CRA) has acknowledged that the deduction was available where options are cashed out in the ordinary course.

The Budget ends this opportunity by generally denying option holders the right to capital gains rate taxation where their options are cashed out unless the employer elects to forgo a deduction in respect of the cash-out payment. Thus, either the employer can claim a deduction or the employee can be entitled to capital gains rate taxation on the payment, but not both.

In many public M&A transactions completed through plans of arrangement, it has been customary for the options to be cashed out by the target. While this may still be a viable approach, there will now be a need to determine, as a business matter, whether the employer will agree to forgo a deduction so that option holders will choose to cash out options rather than exercise options in advance of the transaction.

End of deferral
In 2000, the stock option rules were amended to permit an employee to defer the employment income inclusion on the exercise of up to C$100,000 of qualifying public company options until the year of sale of the underlying shares. This measure was intended to allow employees to exercise options without having to then sell their shares on the market in order to fund the resulting tax liability. Effective immediately, this deferral rule is being repealed.

No doubt this change was intended to address the all-too-common circumstance of employees who elected to defer the taxation of employment benefits on the exercise of options and continued to hold securities that ultimately dropped in value. The stock option employment benefit and corresponding tax is crystallized on the date of option exercise and any subsequent loss on the securities is, typically, a capital loss to the employee and cannot offset any portion of the stock option employment benefit. Some employees found themselves in a situation where the ultimate proceeds of disposition of the acquired securities were insufficient to pay the tax on the stock option employment benefit.

The Budget proposes to offer relief to those who have elected to defer the inclusion of public company employee stock option benefits and find themselves in that situation. Qualifying employees can elect to pay a special tax equal to the full proceeds of disposition of such securities (2/3 of such proceeds for Quebec residents) instead of the tax otherwise payable in connection with the corresponding stock option employment benefit. This special election is proposed to apply to all such securities sold before 2015, including sales in past years where a public company option deferral election has been made.

Withholdings
The Budget also purports to "clarify" the rules surrounding an employer's obligation to withhold and remit amounts in connection with the exercise of options to acquire securities that are not shares of a Canadian-controlled private corporation by amending the withholding rules to require employers to make withholdings from employees' remuneration on the hypothetical basis that the corresponding employment benefit (reduced where capital gains rates apply) has been paid as a cash bonus to the employee. The proposals provide no guidance as to where employers could source any such hypothetical cash to the extent that an employee's regular salary is insufficient to fund such withholding obligations, but provide that the Minister of National Revenue will not be entitled to consider the fact that the benefit arose from the acquisition of securities as a basis to discretionarily reduce withholdings. This could lead to particularly harsh results in circumstances where there is no public market for the securities (unless they are shares of a Canadian-controlled private corporation) that are subject to the employee options. Stock option agreements may need to be amended to provide funding arrangements for such withholding.

These newly "clarified" withholding proposals are to take effect beginning in 2011.

Non-resident Taxation
Taxable Canadian Property

One of the major impediments to attracting cross-border venture capital and private equity investment in Canada has been the taxation of gains on such investments and the invasive compliance burden imposed by the section 116 filing and withholding regime under the Tax Act. The section 116 process has become increasingly time-consuming, with the result that sellers frequently have 25% of their proceeds tied up in escrow for months, even when no tax is owing. While some changes to section 116 were announced in 2008, it is widely believed that those changes were defective, as they did not absolve a non-withholding purchaser of liability if the non-resident seller was ultimately found to be taxable on any gain from the sale.

The source of the problem is the very broad definition of "taxable Canadian property" (TCP) in the Tax Act. Unlike most OECD countries, Canada's domestic rules generally taxed non-residents on gains from sales of any non-listed shares. However, most Canadian tax treaties then exempted such gains from tax provided the shares were not a real property interest. It was frequently the case that selling shareholders would be entitled to treaty relief, but the process of proving that entitlement required disclosure of significant information regarding the identity and treaty status of the seller. This would lead to time-consuming and burdensome withholding and compliance obligations in situations where there was almost always no tax actually payable. Typically, private equity funds investing in Canada, particularly those having non-treaty country participants, would establish "blocker" entities in third countries to address the Canadian taxation of gains and to simplify the compliance burden.

The Budget introduces a welcome and long advocated change to this regime by dramatically narrowing the TCP definition. As a result, the time-consuming and invasive section 116 procedure will now apply only in a very narrow range of cases. Essentially, TCP will now consist only of:

  • Canadian real property (including resource property);
  • property used in a Canadian business;
  • designated insurance property of insurers; and
  • shares (or interests in trusts or partnerships) that are real property interests.
  • Options to acquire such types of property will also be TCP.

A share or other investment will generally be a real property interest at a point in time only where, at that point in time, or at any time in the preceding 60 months, more than 50% of its fair market value was derived from Canadian real property. The five-year lookback is significant, and will require some diligence to verify in many M&A contexts.

This change should dramatically simplify many venture capital and private equity investments into Canada, by eliminating the need for "blocker" entities in many situations. There will, of course, be a need for buyers to satisfy themselves that the shares they are buying did not derive more than 50% of their value from real property in the preceding 60 months. Unfortunately, the Budget does not suggest that there will be a due diligence defence for a buyer who wrongly concludes that shares are not a real property interest. It is hoped that the legislation will provide some protection for buyers who reasonably rely on representations made to them by sellers regarding the status of shares as non-real property interests.

The Budget also proposes to amend a number of provisions in the Tax Act that deem shares received as consideration for the disposition of TCP to themselves be TCP from applying indefinitely to applying for a 60-month period following which the amended rules previously described would apply.

These rules apply to the determination of whether a property is TCP after March 4, 2010.

Refunds of Withheld Amounts
The Budget proposes a measure to counteract an anomaly affecting non-residents in respect of whom withholdings under Regulation 105 or under section 116 have been enforced as against the payor. Such assessments can occur outside the time within which the non-resident is entitled to file a tax return to claim a refund of such amounts. The Budget proposes to permit the Minister of National Revenue to refund an overpayment of tax withheld under Regulation 105 or section 116 if the application for such refund is made after March 4, 2010 and within two years after the date of the assessment.

Foreign Investment Entity and Non-Resident Trust Rules
There are three regimes in Canada which are designed to prevent the use of investments in foreign corporations or funds to avoid or defer Canadian tax. In general terms:

  • The "foreign accrual property income" (FAPI) regime applies to require current taxation in Canada of passive income earned in a controlled foreign affiliate.

  • The non-resident trust (NRT) rules apply to interests in non-resident trusts that have a direct or indirect Canadian beneficiary where the trust has directly or indirectly acquired property from a Canadian person that was related or was the uncle, aunt, nephew or niece of the Canadian beneficiary; where the non-resident trust is non-discretionary, the NRT rules apply a modified FAPI regime to certain beneficiaries of the trust and where the non-resident trust is discretionary, the trust itself is deemed resident in Canada and subject to Canadian tax on FAPI-type income.

  • The offshore investment fund (OIF) rules apply a deemed income accrual regime to investments in non-controlled entities (corporations, partnerships, funds or trusts other than non-resident trusts) that derive their value primarily from portfolio investments where it may reasonably be considered that one of the main reasons for making the investment is to defer or avoid current tax in Canada.

In 1999, the Minister of Finance announced proposed changes to tighten up the NRT provisions and replace the OIF regime with the foreign investment entity (FIE) rules. These proposed changes have been postponed and revised several times in response to criticisms that they were too complex, too broad, and impossible to administer. In the 2009 federal budget, the Minister of Finance announced that the Department of Finance would be reconsidering the proposed changes in response to the continuing criticisms.

Foreign Investment Entities
The Budget proposes to abandon the proposed changes to the FIE rules and to revert to the existing rules. This is a welcome announcement. The only change is to increase the prescribed rate of interest at which income on the FIE investment is deemed to accrue to the Canadian investor for Canadian tax purposes.

This measure is proposed to be effective for taxation years that end after March 4, 2010. Special measures apply to taxpayers who voluntarily filed their returns under the old proposed FIE rules.

Non-Resident Trusts
In the Budget, the Minister of Finance proposed to proceed with the basic format of the existing proposed NRT rules, but with some significant changes.

A major criticism of the proposed NRT rules is that they applied to legitimate investments in foreign commercial trusts. In order to address this concern, it is proposed that the exemption for commercial trusts would be simplified and expanded. The Budget also proposes a specific exemption for all tax exempt entities – including pension funds, Crown corporations and registered charities.

There are also proposed changes to the method of taxation of non-resident trusts and their beneficiaries that are caught by the rules. Under the previously proposed NRT rules, the non-resident trust is subject to Canadian tax on all of its income, regardless of who contributed the property from which the income was derived or the source of the income, with each Canadian resident contributor and Canadian resident beneficiary of the trust jointly and severally liable (with the non-resident trust) for the Canadian tax liability of the trust. Under the revised proposals, income from property acquired by the trust from Canadian resident contributors (and substituted property) (the Resident Portion) will be attributed back to the Canadian contributors. Income not arising from the Resident Portion, other than Canadian-source income in respect of which non-residents are normally subject to Canadian tax, will be excluded from the trust's income. It is expected that the non-resident trust will ordinarily pay Canadian tax only on income derived from contributions from certain former Canadian resident contributors. In addition, as under the current proposals, there could be Canadian non-resident withholding tax on distributions from the non-resident trust to its non-resident beneficiaries, but this is intended to be only where the distributions are out of the Resident Portion.

It appears that, if a non-resident trust is not caught by the revised NRT rules – i.e., in the case of exempt commercial trusts – the interest may be caught by the existing rules which apply a modified FAPI regime where the fair market value of the Canadian beneficiary's interest is equal to or exceeds 10% of the value of all interests in a non-resident trust. It is proposed that the modified FAPI rule will be broadened to apply to any resident beneficiary who, together with any non-arm's-length person, holds 10% or more of any class of interests in a non-resident trust.

The measures regarding non-resident trusts are generally proposed to apply for the 2007 and subsequent taxation years, except that attribution to Canadian resident contributors will apply only to taxation years ending after March 4, 2010. An election will be available to allow a trust to be deemed resident in Canada for the 2001 and following taxation years.

Non-Resident Reporting
In order to ensure that the CRA has the information to identify Canadian taxpayers that have invested in NRTs and FIEs, the Budget proposes to expand the foreign property reporting requirements in the Tax Act. It is also proposed to extend the reassessment period for interests in NRTs and FIEs by a further three years.

These proposed changes to the NRT and FIE proposals are a vast improvement over the old proposals. Our experience with the old proposals has told us, however, that the devil is in the details. The Budget proposals are given for public consultation with a view to developing revised legislation which will also be released for comment. Public comments are requested before May 4, 2010. The Budget announced that a panel consisting of respected tax practitioners will be formed to work with the Department of Finance in reviewing any issues identified in the comments received and in making recommendations on the design of the draft legislation.

"Aggressive" Tax Planning
The Budget contains four initiatives purporting to target "aggressive" tax arrangements.

SIFT Conversions and Loss Trading
The Budget delivered the anticipated reaction to January media reports concerning the number of income trusts that were considering utilizing corporations with large tax losses in their conversion plans: the proposal of a rule similar to an existing rule – which deems an acquisition of control to occur on certain reverse take-overs of a corporation by another corporation – to deem control of a corporation to be acquired where its shares are exchanged for units of a SIFT trust or SIFT partnership. A companion rule is also proposed to prevent the acquisition of control of a corporation that is a subsidiary controlled by a SIFT trust solely because of the distribution of its shares to a SIFT wind-up corporation on a SIFT trust wind-up event.

The new rules apply to transactions undertaken after 4 p.m. EST March 4, 2010, other than transactions that the parties are obliged to complete pursuant to the terms of a written agreement entered into before that time. Where such agreements permit a party to abort the transaction due to a change in the Tax Act, the new rules will also apply to the transaction.

Foreign Tax Credit Generators
The government has, for some time, indicated its concerns with Canadian corporations that have entered into transactions that have come to be known as "foreign tax credit generators". These transactions make use of the rules that allow a Canadian taxpayer to obtain a credit against Canadian tax for foreign taxes paid by the taxpayer. Although there are a number of variations, the structures have generally involved the Canadian taxpayer becoming a partner in a foreign partnership with a non-resident and claiming credits against Canadian tax for foreign taxes paid in respect of the partnership's activities. Another alternative involves a jointly owned foreign affiliate of the taxpayer that earns "foreign accrual property income" and obtains relief against the Canadian taxation thereof through the "foreign accrual tax" and "underlying foreign tax" mechanisms. The government believes that these transactions are structured to provide a Canadian taxpayer with credit for foreign taxes paid far in excess of the Canadian taxpayer's entitlement to profits or gains from the relevant structure. The CRA is in the process of challenging certain corporations which have entered into these types of transactions including through the application of the general anti-avoidance rule (GAAR).

The Budget proposes new rules affecting the foreign tax credit provisions applicable to Canadian taxpayers and the foreign accrual tax and underlying foreign tax mechanisms relevant to foreign affiliates of Canadian taxpayers. The purpose of these proposed changes is to limit the availability of relief for foreign taxes to the taxpayer's direct or indirect economic interest in the foreign vehicle, the activities of which have given rise to the foreign taxes paid. The proposal is to be effective for foreign taxes incurred in respect of taxation years ending after March 4, 2010, although the Budget papers indicate that the government will be accepting comments on the finalization of the legislation and encourages stakeholders to submit any such comments before May 4, 2010.

Tax Avoidance Transaction Reporting
The Budget announced a "public consultation" process on its proposal to implement a reporting regime to identify "avoidance transactions" which bear a high risk of constituting tax abuse, similar to the recently proposed "aggressive tax planning regime" in Quebec.

The proposals would require a taxpayer to report any tax avoidance transaction where two of the following three characteristics are present: (1) the promoter/tax advisor is entitled to fees that are attributable to the amount of the tax benefit, contingent upon obtaining the tax benefit or attributable to the number of taxpayers who participate in the transaction; (2) the promoter/tax advisor requires "confidential protection" about the transaction; and (3) the taxpayer (or a person who entered into the transaction for the benefit of the taxpayer) obtains "contractual protection" in respect of the transaction (other than a fee arrangement described in (1)).

According to the Budget papers, those characteristics (referred to as "hallmarks") are not themselves considered to be evidence of abuse, but their presence indicates a higher risk of abuse. For those taxpayers who fail to report such transactions, the Budget proposes to deny the tax benefit resulting from the transaction, which benefit could still be claimed if the taxpayer was prepared to pay penalties and supply any information required by the CRA. Such a taxpayer is still subject to regular audit and challenge by the CRA.

The proposals, although presented as "for consultation" are, as modified to take account of the consultations, proposed to apply to transactions entered into after 2010 as well as transactions that are part of a series of transactions completed after 2010.

While consultations are planned, it is suggested that the introduction of such a regime raises difficult questions regarding matters such as solicitor-client privilege.

Specified Leasing Property Rules
In recent years, some leasing companies and other financial institutions have carried out complex leveraged leasing transactions using certain types of property that are exempt from the "specified leasing property" rules. This has enabled the lessors to claim tax depreciation on the leased assets to shelter other income, including non-leasing income. An example of this is the transaction which was unsuccessfully attacked by CRA in the Canada Trustco case, which is one of the leading cases on the GAAR. One of the features of these structures is that they involve a lease of the exempt property to a non-resident or tax exempt lessee.

In order to curtail these types of arrangements, the Budget proposes to extend the application of the specified leasing property rules to otherwise exempt property that is subject to a lease to a government or other tax-exempt entity, or to a non-resident, unless the total value of the property that is subject to the lease is less than C$1-million. The Budget proposes to institute an anti-avoidance provision to prevent the artificial division of property into leases to defeat the C$1-million threshold. These proposals apply to leases entered into after 4 p.m. EST March 4, 2010.

While this measure will curtail the use of the sophisticated tax planning structures that were successful in Canada Trustco, they could conceivably affect the taxation of regular leasing transactions involving exempt property. The Canada Trustco case involved the lease of trailers with a total value of C$120-million, but it is unclear whether any individual trailer was valued at more than C$1-million. If the effect of the proposed change is to catch a single "lease" of multiple items of equipment which have a total value of over C$1-million but an individual value of under C$1-million, it would appear that regular lease financing of exempt property to government institutions could be caught in some cases.

Mineral Exploration
The temporary mineral exploration tax credit, the availability of which was extended in the 2009 budget, will be extended again. Thus, a 15% tax credit will be available for qualifying expenditures renounced under flow-through share agreements entered into on or before March 31, 2011.

Consolidated Tax Returns
The Budget also indicated that the government will explore whether new rules for taxation of corporate groups, such as the introduction of a formal system of loss transfers or consolidated reporting, could improve the functioning of the tax system. While this would be a welcome and overdue change, as Canada is one of very few developed countries with no tax consolidation or group relief regime, such proposals have been considered in the past and have not been pursued in some measure due to provincial income tax issues.

Previously Announced Measures
The Budget confirms the government's intention to proceed with a number of previously announced tax measures, as modified to take into account consultations and deliberations since their announcement, including:

  • technical amendments to the foreign affiliate rules released in draft form on December 14, 2009 and the remaining measures released in draft in 2004 relating to foreign affiliates;

  • improvements to the application of the GST/HST to the financial services sector released on September 23, 2009; and

  • technical legislative proposals addressing recent court decisions on the GST/HST and financial services, announced on December 14, 2009.

The proposed GST/HST amendments exclude certain "credit management" services (e.g., evaluating or authorizing credit) and "preparatory" services (e.g., market research, document preparation, promotional services) from the definition of a financial service. The scope of these exclusions is unclear, but could fundamentally impact the financial services sector. All suppliers of financial services will need to review the GST/HST treatment of their services in light of these draft amendments.

Notably absent from the list are previously-announced changes to the rules regarding deductibility of interest and the promised introduction of a tax-deferred rollover for share exchanges involving a foreign corporation and Canadian corporation.

For further information, please contact any member of our Tax Group listed below:

Members from Blakes Tax Group include:


Toronto

Bryan Bailey

416-863-2297

bryan.bailey@blakes.com

 

Ryder Gilliland

416-863-5849

ryder.gilliland@blakes.com

 

Janice McCart

416-863-2669

janice.mccart@blakes.com

 

Kathleen Penny

416-863-3898

kathleen.penny@blakes.com

 

Ron Richler

416-863-3854

ron.richler@blakes.com

 

Paul Stepak

416-863-2457

paul.stepak@blakes.com

 

Paul Tamaki

416-863-2697

paul.tamaki@blakes.com

 

Jeffrey Trossman

416-863-4290

jeffrey.trossman@blakes.com

 

Chris Van Loan

416-863-2687

chris.vanloan@blakes.com

 

Sabrina Wong

416-863-2645

sabrina.wong@blakes.com

Montréal

Jean Gagnon

514-982-5025

jean.gagnon@blakes.com

 

John Leopardi

514-982-5030

john.leopardi@blakes.com

 

Calgary

Edward Rowe

403-260-9798

edward.rowe@blakes.com

 

Wanda Rumball

403-260-9794

wanda.rumball@blakes.com

 

Wally Shaw

403-260-9766

wally.shaw@blakes.com

Vancouver

Robert Kopstein

604-631-3317

robert.kopstein@blakes.com

 

Bill Maclagan

604-631-3336

wsm@blakes.com

 

Janette Pantry

604-631-4163

janette.pantry@blakes.com

 

Bruce Sinclair

604-631-3382

bruce.sinclair@blakes.com

 

Kevin Zimka

604-631-3363

kevin.zimka@blakes.com




Caroline Findlay & Angela Stolz

INTRODUCTION
In a unanimous decision released on January 21, 2010, the Supreme Court of Canada clarified the discretion of a federal responsible authority (RA) to make decisions with respect to the scoping of projects for purposes of the federal environmental assessment (EA) process. In MiningWatch Canada v. Canada (Fisheries and Oceans), the court overturned a Federal Court of Appeal decision that granted RAs discretion to scope a project to determine the type of EA process or "track" that will apply. The track determines the level of the intensity of the EA review.

For over four years, the case has been in litigation, resulting in some confusion around the authority of an RA to decide if proposed projects can be "scoped" as either subject to a screening or a comprehensive study as the EA process that applies. The Supreme Court has definitively stated that the facts about a project as proposed by a project proponent determine whether a project is caught by the comprehensive study rules – there is no discretion under the law. In this case, the project's ore production resulted in a mandatory conclusion under the legislation that it be subject to a comprehensive study. However, the court's remedy was simply to declare this; not to order a comprehensive study at this time.

BACKGROUND
Red Chris Development Company and BCMetals Corporation (Red Chris) submitted a project description to the BC Environmental Assessment Office (BCEAO) in October 2003 for a copper and a gold mine. The BCEAO determined that the Red Chris project required a provincial EA certificate. The project received approval from the BCEAO in August 2005, after extensive review and comment by a working group, which included provincial and federal agencies, and local First Nations, as well as public consultation. The Supreme Court comments that this process "proceeded smoothly" and at no time did MiningWatch Canada (MiningWatch) object to the provincial EA process or certificate.

In 2004, Red Chris also triggered the federal EA process through applications to Fisheries and Oceans Canada (DFO) related to dams for the proposed tailings impoundment area and for a stream crossing. DFO then posted a Notice of Commencement of an Environmental Assessment, announcing that a comprehensive study would ensue. The Notice of Commencement described the project as proposed by the proponent, and stated that the scope of the project would be added once it became available.

The decision to proceed with the EA by way of a comprehensive study was based on the proposed project production as described by the proponent: ore production capacity of up to 50,000 tonnes per day. This exceeded the allowable 600 tonnes per day provided for under the Canadian Environmental Assessment Act's (CEAA) Comprehensive Study List Regulations (the CSL). The CSL outlines the triggers for when a project is subject to a comprehensive study.

DFO then re-scoped the project more narrowly on the basis that it should only consider those aspects of the project that were within its jurisdiction and responsibility flowing from the CEAA. As a result, DFO determined that the project was not within the CSL as originally contemplated and put the project through the screening process.

The trial court held that, based on the fact that the mine's proposed ore production capacity exceeded the threshold set out in the CSL, DFO had a legal responsibility to put the project through a comprehensive study and resulting public consultation. It was not within an RA's discretion to scope a project more narrowly in order to avoid the CSL. The Federal Court of Appeal reversed this decision and held that it is entirely appropriate for an RA to only consider the aspects of the project that are relevant to its jurisdiction and conclude that a project "as scoped" does not fall within the CSL. (See our July 2008 Blakes Bulletin on Environmental Law: Federal Court of Appeal Reaffirms Government Discretion in Scoping of Federal Environmental Assessments>.)

SUPREME COURT'S ANALYSIS
The Supreme Court of Canada held that the CEAA and its regulations require that the EA process or "track" be determined according to the project as proposed and that it is generally not open to the RA to change the level of assessment. The court found this interpretation to be consistent with Parliament's intent as found within the respective roles of the RA and the Minister in conducting EAs under the CEAA. Tracking and scoping are two distinct steps under the EA process. Once a project has been tracked in accordance with its description as proposed, it is then open to the RA to scope the project for purposes of the EA process. However, the minimum scope is how the project was proposed by the proponent.

The Supreme Court looked at the four corners of CEAA only. Its analysis did not consider the provincial/federal constitutional division of jurisdiction over the environment and, as such, the court has left open for another day the constitutional aspects of carrying out EAs in Canada.

Interestingly, while agreeing with the trial decision with respect to an RA's scoping discretion, the court disagreed with its remedy: requiring Red Chris to complete a comprehensive study. There had not been any challenge to the decision to grant a permit for the project, only the process through which this was decided. Thus, although the court found the method of permitting to be out of compliance with the CEAA, Red Chris may proceed with the project nonetheless. This conclusion is influenced by a number of factors. First, the court noted that the RA had re-scoped the project only after the Federal Court decision in Prairie Acid Rain Coalition v. Canada (Minister of Fisheries and Oceans) and found it difficult to fault the RAs for following a Federal Court decision based on the very matter with which they were dealing. Second, MiningWatch clearly stated that this case was purely a test case to determine the federal government's obligations under the CEAA and it had no proprietary or pecuniary interest in the outcome. Third, little would be gained by requiring Red Chris to proceed through the EA process over again. It had already gone through an extensive public consultation process and had, in fact, not done anything wrong to warrant the additional time and expense.

IMPLICATIONS
This decision will likely not have a significant impact on the scoping of future proposed projects. By requiring projects to be tracked in accordance with how they are proposed, proponents will have certainty around the regulatory process and, most importantly, provincial-federal harmonization will continue. The court stressed that minimizing duplication through governmental co-ordination was valuable for managing the federal EA requirements. While this decision may appear to be a hollow victory, at its heart it is about requiring governments to adhere to the powers that are set forth within legislation.

The CEAA is currently undergoing a seven-year review period as mandated within that statute. The resulting policy changes that may be on the horizon from this review are likely to have a more profound impact on the nature of the federal EA process and its scope and content than this decision.




Selina Lee-Andersen

Event: The United Nations Climate Change Conference in Copenhagen, Denmark (Copenhagen Conference), comprising the 15th Conference of the Parties (COP 15) to the United Nations Framework Convention on Climate Change (UNFCCC) and fifth Conference of the Parties serving as the Meeting of the Parties to the Kyoto Protocol (COP/MOP 5), in conjunction with sessions of the UNFCCC and Kyoto Protocol ad hoc working groups.

Mission: To conclude a fair, ambitious and binding international agreement on climate change, including agreement on: (i) mid-term emission reductions by developed countries; (ii) clarity on mitigation actions by developed countries; (iii) short- and long-term finance; and (iv) government structures.

Parties: 115 Heads of State and Government and their delegations representing 194 countries, along with intergovernmental organizations, 21,000 non-governmental organizations and 5,000 media.

Outcome: The Copenhagen Accord, a non-binding political agreement which acknowledges that "climate change is one of the greatest challenges of our time" and emphasizes the parties' "strong political will to urgently combat climate change".

This article provides an overview of the Copenhagen Accord based on our attendance at the Copenhagen Conference and considers some of the implications of the Accord for Canadian businesses, particularly in the context of ever-evolving Canadian and U.S. climate change policies.

Some Like it Hot
From December 7 to 19, 2009, the eyes of the world were on Copenhagen, Denmark, where 194 countries had gathered to hammer out the details of an international climate change agreement for the post-2012 period. The Copenhagen Conference marked the culmination of a two-year-long negotiating process to enhance international co-operation on climate change under the Bali Road Map, which was launched by COP 13 in December 2007. For more details on the Bali framework, please see our February 2008 Blakes Bulletin on Environmental Law: Drivers Needed: Mapping the Road to Global Climate Change Consensus. If nothing else, the Copenhagen Conference illustrates the difficulty, if not impossibility, of reaching a global consensus on how to tackle the climate change challenge.

The product of two tense weeks of negotiations was the Copenhagen Accord, a non-binding political agreement which sets a 2 degrees Celsius target (i.e., that the increase in global temperature should be limited to 2 degrees Celsius). The Copenhagen Accord does not contain any specific emissions reduction targets nor any framework for a carbon market. While the Accord includes provisions for short- and long-term financing, there is no indication of where the money for a promised US$30-billion fund will come from or where it will be directed. Furthermore, the Copenhagen Accord omits any mention of plans to continue climate talks in 2010. Many parties were disappointed with the weak outcome of the Copenhagen Conference, but the Copenhagen Accord could represent an important first step towards more meaningful international action on climate change if countries are willing to implement it.

Some of the implications of the Copenhagen Conference for Canadian businesses are:

  • continued uncertainty surrounding the timing and scope of federal climate change regulations

  • a continuing patchwork of regulatory initiatives at the provincial and regional levels, resulting in the need for companies to comply with competing regulatory requirements

  • a potential shift towards a new mode of climate negotiations among the world's major developed and developing countries

  • no global carbon market in the foreseeable future given the lack of emission reduction targets, but domestic and regional carbon markets will continue to develop

  • potential costs to Canadian manufacturers and exporters as a consequence of proposed "border adjustment" provisions in U.S. climate legislation

  • enhanced opportunities for Canadian companies to attract investment dollars and export clean technologies around the world.

Copenhagen Accord
The Copenhagen Accord was brokered directly by President Obama and a handful of key developing countries including China, India, Brazil and South Africa. The terms of the Copenhagen Accord were negotiated on the final day of the conference, topping off two weeks of high rhetoric and bitter procedural fights. It then took another day of tense negotiations to arrive at a procedural compromise that would allow the formalization of the Accord over the objections of several governments which complained about an "untransparent" and "undemocratic" negotiation process. Though far from perfect, the Copenhagen Accord is seen by many parties as a crucial step forward in international climate talks. The Copenhagen Accord is unique because, for the first time, all major economies including China and other key developing countries, have committed to reducing their greenhouse gas (GHG) emissions. However, it falls short of charting a path towards a treaty with binding commitments.

At the end of COP 15, the parties adopted parallel decisions under the UNFCCC and the Kyoto Protocol that "take note" of the Accord and open the way for governments to individually sign on. In separate decisions, parties extended the mandate of the ad hoc working groups under both the UNFCCC and the Kyoto Protocol to continue negotiations toward a more comprehensive agreement in Mexico City at the next COP. This unprecedented outcome leaves uncertainty about the formal standing of the Copenhagen Accord under the United Nations climate process and about the nature of any future agreement. The aim of a "legally binding instrument", which appeared to be part of the deal when President Obama first announced it, was later taken out.

Key elements of the Copenhagen Accord include:

  • a goal of limiting global temperature increase to 2 degrees Celsius

  • a process for countries to enter their specific mitigation pledges by January 31, 2010

  • action and co-operation on adaptation, with urgent attention given to the least developed countries, small island developing states and Africa

  • broad terms for the reporting and verification of developing country actions

  • an explicit acknowledgment to act on deforestation and forest degradation

  • establishment of four new bodies: (i) a mechanism to support reducing emissions from deforestation and forest degradation in developing countries (REDD); (ii) a high level panel to study the implementation of financing provisions; (iii) the Copenhagen Green Climate Fund to support the mitigation and adaptation efforts of developing countries as well as capacity building and technology transfer; and (iv) a technology mechanism to accelerate technology development and transfer

  • a commitment by developed countries to provide $30-billion in "new and additional" funding in the period 2010-2012 to help developing countries reduce emissions, preserve forests, and adapt to climate change

  • a commitment by developed countries to mobilize $100-billion a year in public and private finance by 2020 to address the needs of developing countries.

By 2015, the Copenhagen Accord calls for an assessment of the implementation of the Accord, including strengthening of the long-term target.

The way in which the Copenhagen Accord was forged provides a preview of how future international efforts to reduce emissions will be co-ordinated – that is, by a much smaller group of nations responsible for the majority of emissions. One forum that may provide the basis for future international climate negotiations is the Major Economies Forum on Energy and Climate (MEF), which was launched in March 2009. The purpose of the MEF is to facilitate a dialogue among major developed and developing economies with the objective of generating the political leadership necessary to increase clean energy supplies while cutting GHG emissions. The 17 major economies participating in the MEF, which produce the majority of the world's GHG emissions, include: Australia, Brazil, Canada, China, the European Union, France, Germany, India, Indonesia, Italy, Japan, Korea, Mexico, Russia, South Africa, the United Kingdom, and the United States.

Rise of Sub-National Initiatives
It became apparent at the Copenhagen Conference that governments lacked the political will to commit to concrete targets and actions. Climate change talks have essentially been deadlocked for the past two years as countries grapple with complex issues relating to economic development, trade, technology transfer, climate finance, responsibility for historical emissions, and responsibility for mitigating future emissions. It is hard to imagine any issue other than climate change which embodies the challenge of reconciling so many diverse national interests, not only between the developed and developing nations, but among the developed and developing nations themselves. As a result, "sub-national" governments including provinces, states and municipalities are becoming frustrated with this process and are forging ahead with their own strategies to reduce GHG emissions. For the foreseeable future, in the absence of an international climate change agreement, it looks like the onus will fall on provinces, states and municipalities to take meaningful emission reduction actions.

In North America, we have already seen a number of sub-national initiatives fill the leadership void left by federal governments on the climate change issue. Prominent among these are the Western Climate Initiative (WCI) and the Regional Greenhouse Gas Initiative. The WCI is a collaboration of four provinces (B.C., Ontario, Manitoba and Quebec) and seven U.S. states working together to reduce GHG emissions at a regional level. One of the main champions of sub-national action, and the main driver behind the WCI, is California's Governor, Arnold Schwarzenegger. Governor Schwarzenegger was in attendance at the Copenhagen Conference and once again pushed the sub-national agenda: "…as much as 80 percent of the necessary greenhouse-gas reductions will happen at the sub-national level." "So why" he asked, "should we focus all our faith and hope in international action?" Then, at the Climate Summit for Mayors in Copenhagen held on December 15, Governor Schwarzenegger called on the United Nations to convene a climate summit for cities, states, provinces and regions. He made the point that cities, states and provinces have, in many cases, already taken a leadership role in implementing policy innovations to curb GHG emissions and to spur the development of clean energy alternatives and transportation infrastructure. Sub-national governments have a distinct advantage over their sovereign counterparts – the advantage of governing a smaller population and geographic area.

R20 – A New Proposal from California
Building on the concept of sub-national initiatives, Governor Schwarzenegger offered a new proposal while in Copenhagen. This proposal draws on the G(X) model of international co-operation (as in the G-20 group of nations) and suggests that sub-national governments come together to advance climate policy in their own "R20", or "Club of 20 Regions". According to the Governor's office, officials from Quebec, Nigeria, France and Algeria have already signed on to the idea of "a new regional coalition to fast-track the results of the Copenhagen Climate Change Conference and push their respective national governments into more rapid actions and stronger commitments to fight climate change." Founding members of the group include Quebec's Premier, Jean Charest, who said the arrangement would facilitate the transfer of green technologies to developing countries.

According to a concept document released on December 14, R20 aspires to "demonstrate the feasibility" of the arrangement by 2012. The Governor's announcement provided no indication of whether other members of the WCI had signed on to R20 (the "20" is symbolic so far). If implemented, this initiative could present opportunities for members to exchange expertise and facilitate the transfer of green technologies to developing countries.

C40 – An Initiative by Cities
At the municipal level, "C40" was established in 2005 and represents a group of the world's largest cities committed to tackling climate change. C40 is currently chaired by Toronto's Mayor, David Miller. C40 recognizes that cities have a central role to play in dealing with climate change, particularly as cities bear a disproportionate responsibility for causing it. According to C40, approximately 50% of the world's population currently live in cities (set to reach 60% by 2030). However, cities and urban areas consume a disproportionate amount of the world's energy – approximately 75% – and produce up to 75% of the world’s GHG emissions. C40's member cities are committed to taking action on a number of fronts, including the creation of procurement policies and alliances to accelerate the uptake of climate-friendly technologies and to influence the marketplace.

Provinces on the World Stage
In Copenhagen, deep divisions between the federal government and the provinces on the climate change issue were pushed to the fore. A number of provinces and Canadian cities made their presence known at Copenhagen, seemingly to show the world that Canada is a climate leader despite a weak climate policy from Ottawa. Among those in attendance at Copenhagen were Quebec Premier Jean Charest, British Columbia Premier Gordon Campbell, Manitoba Premier Greg Selinger, Nova Scotia Premier Darrell Dexter, Ontario Environment Minister John Gerretsen, Mayor David Miller of Toronto, Mayor Gregor Robertson of Vancouver and Mayor Dave Bronconnier of Calgary. Quebec Premier Jean Charest summed up the view from some of the provinces: "There is something of a tale of two Canadas here. You have provinces leading with bold action, whether it's in Quebec or it's Manitoba or Ontario or British Columbia – leading on renewables, leading on passing carbon taxes, putting comprehensive climate legislation in place. And we have a federal government that is not taking the right role for Canada in these international negotiations. … We'd love to see that national position change." This followed earlier comments from Ontario and Quebec officials that they want to ensure that Ontario and Quebec do not carry the burden of national GHG reductions while other provinces, such as Alberta, do not see any significant GHG emission reductions for years. Quebec and Ontario's criticism of the federal government for its emission reduction targets – 20% below 2006 levels by 2020 – has led to a continuing spat between the federal government and Quebec and Ontario's provincial governments.

As a result of weak federal action on climate change, likely to go on for several years, the provinces and cities will continue to implement their own emission reduction strategies. It will be up to the federal government to bring the provinces together if it is to have any chance of meeting the country's emission reduction targets – no easy task. This means that for the foreseeable future, Canadian businesses will continue to face a patchwork of regulations and competing regulatory requirements.

Copenhagen: The Role of Business
Business leaders from around the world were present at Copenhagen. The main COP gathering for industry took place at the Business Day event, which was convened on December 11, 2009. Organized by the World Business Council for Sustainable Development (WBCSD), the International Chamber of Commerce and the Confederation of Danish Industry, the Business Day event was a recognition of the importance of business in generating solutions to the climate change challenge. A growing number of companies are acknowledging the importance of risk mitigation, corporate social responsibility, and the profitability and cost savings associated with innovative climate solutions. As a result, the business community is becoming increasingly involved with issues relating to clean technology, carbon markets, energy efficiency, demand-side management, and voluntary emission reduction commitments. At the end of the Business Day event, the WBCSD announced the launch of the Value Chain Initiative, which aims to optimize carbon reductions throughout the supply chains of consumer goods companies. The Value Chain Initiative, led by the Coca-Cola Company and Unilever, underscores the importance of influencing behavioural change in suppliers and consumers. As an increasing number of blue chip companies embrace carbon reduction initiatives, there is no doubt that these efforts will impact companies at all levels of the supply chain.

On December 12-13, 2009, the Bright Green Expo was also held in Copenhagen. The Bright Green Expo featured more than 180 of the world's leading companies and their cutting-edge, market-ready climate solutions. The exhibition focused on business-driven innovation and technology as the only feasible way to meet global climate challenges. Author Thomas Friedman has written that the next great global industry is going to be energy technology based on clean power and energy efficiency. The entire premise of the exhibition was that leaders in the energy technology industry will reap economic benefits, attract the most innovative companies and gain global respect.

From a business perspective, it was evident in Copenhagen that despite the political inertia, the business community is engaged on the climate change issue and continues to push forward with clean technology solutions in the spirit that innovation is good for the bottom line. There is no doubt that governments will need to play a key role in providing incentives to drive innovation and facilitate market access for companies at competitive prices. From a Canadian perspective, there continues to be significant international interest in Canadian companies and investment opportunities. As a result, there is great potential for Canadian companies to attract investment dollars and export their expertise and clean technology solutions to markets around the world.

Carbon Markets – A "Bottom-up" Approach
The Copenhagen talks did not produce any framework for a global carbon market. As a result, the outcome of the Copenhagen Conference was disappointing from the perspective of the carbon markets. The Copenhagen Accord only provides for a list of national pledges of GHG emission reductions and fails to set any concrete emission reduction targets. Further, there was no indication of whether the price for carbon will be regulated by governments (for example, by imposing a price cap) or determined by the carbon market itself. The uncertainty surrounding carbon pricing will make it difficult for companies to work out the costs of doing business in an increasingly carbon-constrained economy. Also, this will make it difficult for carbon market participants to estimate their earning opportunities. However, countries have chosen cap-and-trade as one of the tools to combat climate change and, in the longer term, the prospects for the global carbon market should improve. With countries developing their own domestic and regional markets, it looks like the global carbon market will take a "bottom-up" approach. This means that countries will link their carbon trading systems to one another to create the global market for carbon credits. There continues to be significant carbon market activity with the EU's Emissions Trading System and as the carbon markets of other countries come online, such as Japan, South Korea and Australia, the demand for carbon credits will only increase. Assuming that North America gets its climate act together, the long-term potential for the global carbon market looks very positive indeed.

U.S. Presence in Copenhagen
Despite the failure of the U.S. to pass climate change legislation prior to the Copenhagen Conference, the American delegation was fully engaged in climate talks at Copenhagen. On the first day of the conference, the U.S. made a major announcement that the U.S. Environmental Protection Agency (EPA) had issued a final ruling that GHGs pose a danger to human health and the environment, thus paving the way for regulating emissions from vehicles, power plants, factories and other major industrial emitters. The ruling provides the Obama administration with a significant administrative tool to combat GHGs even though Congress remains stalled on climate legislation.

At Copenhagen, the U.S. negotiating position was focused on the need for any international climate change treaty to include major emitters, in particular the emerging economies of China, India and Brazil. In addition, the U.S. insisted on having the targets and actions of these countries monitored and verified by an international body. Another concern of the U.S., as well as Canada and the European Union, related to the competitive advantage that emerging economies could have in the absence of legally binding targets. This competitive advantage is referred to as "carbon leakage". The Intergovernmental Panel on Climate Change defines carbon leakage as the increase in GHG emissions from countries without emission reduction commitments, occurring as a result of reductions in emissions-constrained nations. To illustrate, carbon leakage could occur if the emissions policy of one country raises local costs, leaving another country that has a more relaxed policy with a trading advantage. In this scenario, if demand for these goods remains the same, production may move offshore to the cheaper country with lower standards, and global emissions will not be reduced.

These concerns were underscored in a letter sent by a group of 10 Senate Democrats to President Obama on December 3, 2009 in the lead-up to the Copenhagen Conference. These Senators, who come from industrial states or regions heavily dependent on coal-fired power generation, are considered swing votes on climate legislation. In the letter, the Senators indicated they will only support climate legislation based on an international agreement that includes stringent verification and enforcement mechanisms, and border adjustment measures, together with emission allowances or rebates to trade- and energy-intensive sectors of the economy. In a session held at the Copenhagen Conference on December 15, a panel of House and Senate representatives (including staff of Senators Jeanne Shaheen (New Hampshire), Richard Lugar (Indiana) and Sherrod Brown (Ohio)) indicated that carbon leakage, competitiveness and environmental integrity will be key to any action taken by the Senate. Furthermore, any treaty or bill must protect U.S. jobs in order to have U.S. support.

The December 3rd letter calls for "border adjustments on imports from nations that have not yet adopted sufficient emission control measures." The Waxman-Markey bill (discussed in further detail below) already contains "rebate" and "border adjustment" provisions designed to keep U.S. companies competitive. These provisions, and any similar provisions inserted into Senate legislation, will likely cause controversy as they may come into conflict with global trade rules. Although these measures are aimed at countries without "sufficient emission control measures", Canadian companies could be inadvertently caught by them. Apart from trade levies that could be imposed on carbon-intensive exports, Canadian manufacturers will also likely face increased costs arising from the complex task of calculating the emissions embedded in internationally traded goods. As companies look for ways to remain competitive, Canadian industries will increasingly need to consider the carbon footprint of their products and services, particularly if they do business in the U.S.

Outsourcing of Canada's Climate Policy?
Despite the broad commitments under the Copenhagen Accord, Canadian businesses face a lengthy wait before the federal government introduces its revamped climate change plan. It was not long ago that Prime Minister Stephen Harper touted a "made in Canada" approach to climate change. However, the federal government has continued to delay the release of GHG emission reduction regulations based on the broad framework document it released in March 2008 entitled Turning the Corner: Taking Action to Fight Climate Change. This plan established the structure of GHG targets and compliance mechanisms for the period 2010 to 2020. After the election of President Barack Obama in late 2008, federal climate change policy underwent a major policy shift to embrace the concept of a common North American approach to GHG management. Regulations were expected to be in place by 2010, which was pushed to 2012 when the federal government committed to releasing its climate change plan before the Copenhagen Conference. However, any such regulations or new climate change plans have yet to be released.

Following the Copenhagen conference, during which the federal government was considered by its critics to be, at best, a passive participant, Prime Minister Harper indicated that Canada would have to watch from the sidelines while the U.S. pushes its climate change legislation through Congress: "What will be most critical for Canada in terms of filling out the details of our regulatory framework will be the regulatory framework of the United States. If the Americans don't act, it will severely limit our ability to act. But if the Americans do act, it is essential that we act in concert with them." The risk, of course, of following the U.S. lead in establishing a regulatory regime for managing GHG emissions is that U.S.-designed legislation will not likely be sufficient to protect the interests of Canadian industries, particularly since U.S. legislation is heavily influenced by lobbyist groups and tends to skew in favour of certain industries. For example, the Waxman-Markey bill was heavily influenced by coal interests and the Senate legislation will likely reflect the interests of an even greater number of lobbyist groups. As a result, while U.S. legislation may be a good fit for American businesses, it won't necessarily be a good fit for Canadian ones. Also, if Canada adopts trade measures similar to the ones proposed in U.S. legislation, Canadian industries could face potentially more severe repercussions than their American counterparts given that our economy is heavily dependent on trade for its prosperity.

Further delays in implementing federal climate change legislation may make it increasingly difficult – and more costly – for Canada to meet its 20% below 2006 levels by 2020 target. Without knowing the types of emission limits they face, many companies are adopting a wait-and-see attitude, which means that emission cuts may ultimately be deeper and more expensive to make within a shrinking timeframe. In addition, companies will need to manage the competing regulatory requirements of provincial and federal systems.

Spotlight on the U.S.
Following the election of President Obama, there was great optimism about the prospects for an international climate change treaty with the return of the U.S. to the negotiating table. During the first year of the Obama administration, energy and climate change issues remained top priorities despite the economic crisis. In June 2009, the American Clean Energy and Security Act of 2009 (ACES), also known as the Waxman-Markey Bill, was passed by the U.S. House of Representatives. The ACES sets out a framework for the establishment of an economy-wide cap-and-trade system and measures to help address climate change and build a clean energy economy. For more information on the ACES, please see our April 2009 Blakes Bulletin on Energy/Environmental Law/CleanTech: A Bold Step Forward: What the Draft U.S. Clean Energy and Security Act of 2009 Means for Canadian Industry. The vote on the ACES in the U.S. House of Representatives is the first step in a two-stage process. In order for the ACES to become law, it must next pass the U.S. Senate where similar legislation is now stalled in Senate committees. If the Senate passes a bill, the differences between the ACES and Senate bill would need to be reconciled, with the final bill passed by both houses, before it can be sent to President Obama and signed into law.

The timing of the climate change debate within the broader Congressional agenda remains unclear because of the nature of shifting political priorities in the U.S. There is a small window of opportunity for the Senate to pass climate legislation this spring if the political will exists. It is anticipated that Senators John Kerry, Graham Lindsey and Joe Lieberman will release a new climate bill into the Senate in early 2010. In December 2009, Senators Kerry, Lindsey and Lieberman outlined a sparse framework of their compromise climate bill in an attempt to jumpstart the Senate's stalled legislation on energy and climate change. There is still a chance that the U.S. will pass climate change legislation in 2010, however climate change legislation faces a tough fight in the Senate. This is because political and regional differences are more pronounced in the Senate and less populated agricultural states carry more weight in the Senate than in the House. Furthermore, any changes made to climate legislation by the Senate will likely be zero-sum in nature. The failure of Congress to pass climate legislation would provide greater incentive for states to adopt their own climate regulations and for the Obama administration to use the EPA's powers to impose emission regulations such as a low-carbon fuel standard.

Already in the first month of 2010, 11 governors of the northeast mid-Atlantic states signed a memorandum of understanding (MOU) to develop a comprehensive, regional low carbon fuel standard to reduce GHG emissions from transportation fuels. The governors have made it clear that they would prefer federal regulations rather than a patchwork of state-based regulations, but the MOU signals their intent to move forward if Washington does not. The potential for an even more complex and costly patchwork of climate regulations is of particular concern for Canadian-based oil sands producers, who are already grappling with the challenge of cutting their per-barrel emissions.

Next Stop: Mexico City
The Copenhagen Accord is a first step in the next stage of international climate negotiations. For many participants, the climate negotiation process that nations have relied on for almost two decades since the establishment of the UNFCCC in 1992 broke down in Copenhagen because it was virtually impossible to bring about a consensus among groups with so many disparate interests. The "top-down" style of targets and timetables under the Kyoto Protocol may have met its end in Copenhagen. What may emerge in its place is a "bottom-up" approach that will consist of voluntary pledges to reduce emissions at a domestic level. There is significant work that needs to be done on the road to COP 16, which will be held from November 29 to December 10, 2010 in Mexico City.

The impacts of the Copenhagen Accord have yet to be felt as countries wrestle with the timing and scope of climate change regulations. However, the push for clean, green technologies continues and companies are innovating despite the policy uncertainty and fragmented approach to regulating GHG emissions. This is because many businesses believe that clean technology will play a key role in the shift towards a low-carbon economy and that such innovations will lead to "climate prosperity".

For further information, please contact:

Selina Lee-Andersen 604-631-3303

or any member of our Environmental Law, CleanTech or Energy groups.




Caroline Findlay

The first part of 2009 witnessed the province's failed effort to experiment with legislation to address the long unresolved matter of aboriginal land rights in B.C. By the fall of 2009, the province had returned to the principles set out in its 2005 New Relationship document to re-calibrate the path forward on aboriginal relations. In the last days of December 2009, the province announced four different legally binding agreements, or "reconciliation protocols", with various First Nations groups, primarily located on the West Coast. These agreements indicate what the future will bring on this ever-changing landscape in B.C. And, often, what B.C. leads with, other provinces will follow with.

Notably, all of these agreements build on existing agreements between the province and First Nations. They also share two common themes: (i) they are focussed on mechanisms to collaborate on land and resource use decision-making (with varying degrees of specificity); and (ii) they set out broad yet tailor-made goals for resource-revenue sharing and infrastructure building, including specific measures around forest tenures, carbon offsets, and alternative energy considerations. The province explains that with these protocols, it is aiming to avoid disputes and litigation with First Nations and to allow statutory decision-makers to act with certainty around consultation. The writer understands that these protocols are intended to deal primarily with land use decisions outside of the provincial environmental assessment process.

What is the impact of these agreements on the current role of third parties in dealing with First Nations consultation/accommodation? A review of these agreements indicates that the province intends to continue to delegate certain procedural aspects of consultation to third parties and that third parties are expected to continue to have a role in providing economic benefits from resource projects to First Nations.

Haida Protocol (Signed december 11, 2009)
The province emphasizes that this "one-of-a-kind" protocol was negotiated as a result of the litigation history and strong claim to aboriginal title of the Queen Charlotte Islands, or Haida Gwaii, that the Haida Nation (the Haida) hold. Without ever mentioning the word "treaty", the protocol states that it is part of the incremental process the parties have agreed on for the negotiation of a "Reconciliation Agreement" (defined to be a more comprehensive agreement). Most importantly, each of the province and the Haida House of Assembly are committed to passing legislation to assist with the implementation of the protocol. The province has targeted the spring of 2010 for this legislation. To implement the protocol over five years, the province will fund the Haida Nation with a payment of C$600,000 per year, and a C$200,000 payment upon signing.

Building on a 2007 Strategic Land Use Agreement between the Haida and the province, which established land use zones for both economic activity and ecosystem protection, the protocol creates a Joint Management Council to make shared resource use decisions. The Joint Council consists of five members, two appointed by each of the province and the Haida, with a jointly appointed Chair holding a tie vote. The protocol does not provide detail as to what the Council will manage other than to focus on strategic-level matters (highlighted further below). As such, this protocol is enabling only based on a framework set out in the attached Schedule B, which will be developed with additional frameworks and implementation plans. Progress is to be measured by July 2010. By consensus decision-making, the Council is responsible for joint decision-making relating to specified strategic-level matters, such as:

(i) Implementation and amendment of the Haida Gwaii Strategic Land Use Agreement;

(ii) Establishment, implementation and amendment of Land Use Objectives for forest practices and determination and approval of the Allowable Annual Cut for Haida Gwaii; and

(iii) Developing policies and standards for the identification and conservation of heritage sites.

Other matters that the protocol deals with are:

  • Carbon Offset Sharing and Resource-Revenue Sharing. Schedule C of the protocol outlines a framework for the parties to agree to share carbon offsets, initially focussed on forest offsets. The essence of this approach is that there will be a further agreement, an "Offset Sharing Agreement", to be negotiated by September 30, 2010, that will establish the basis for qualifying and sharing carbon offsets. The parties also agree to pursue additional revenue sharing opportunities related to new major natural resource development projects.

  • Forest Tenures and Other Economic Opportunities. In Schedule D of the protocol, the province reaffirms its 2005 commitment to provide a forest tenure of 120,000 cubic metres to the Haida. Additionally, the province agrees to pay C$10-million to the Haida for the purpose of acquiring forest tenure. This funding is a credit against future reconciliation payments.

  • Enhancement of Socio-Economic Wellbeing. This is the most vague part of the protocol as there is no accompanying schedule and no timelines. The parties state that they are committed to "an approach", which recognizes and strengthens the inter-relationship between environmental, social wellbeing and economic development. In addition, a socio-economic approach, with children and families at the centre, will be developed by the Haida.

Coastal First Nations Protocol (Signed December 10, 2009)
This protocol is between the province and six Indian bands from the Central and North Coast area. It has elements that are both parallel to and different than the Haida Protocol. Like the Haida Protocol, this protocol builds on pre-existing land use agreements from 2001 and 2006. The implementation funding of this protocol is identical to that provided under the Haida Protocol.

A centerpiece of this protocol is a framework for shared land use and resource decision-making. However, this protocol is much more prescriptive. It sets out an "Engagement Framework" that is to be implemented during the next six months. This framework has five different levels of decision processes and timelines, depending on the type of potential impact that a permit application may have. Interestingly, the protocol states that it is "not intended to affect any obligations that tenure or permit holders or other third parties may have with First Nations."

Other key elements of this protocol are:

  • Carbon Offsets Sharing and Resource-Revenue Sharing. The protocol contains a schedule identical to the Haida Protocol on this topic. Also, like the Haida Protocol, the parties also agree to pursue additional resource-revenue sharing opportunities around major natural resource developments.

  • Economic Opportunities and Economic Strategies. To facilitate the defined economic opportunities and strategies in the protocol, the Coastal First Nations have established the Great Bear Business Corporation. These economic goals deal with forest tenure volume allocations, recreational tourism and the development of an Alternative Energy Action Plan, to be worked on collaboratively by the province, independent power producers and First Nations.

Nanwakolas Framework Agreement (Signed December 16, 2009)
The province entered into a Framework Agreement with six First Nations, covering a land base from Port Alberni (Vancouver Island) to the north-eastern part of Vancouver Island and over into the Knight Inlet area of the central coast of the mainland. The province provides a three-year funding commitment to the Nanwakolas Council of C$685,000 per year, with a C$215,000 initial payment for 2009. This protocol establishes the Nanwakolas Strategic Forum, as the body with overall implementation authority.

This Framework Agreement is very similar in approach to the Coastal First Nations Protocol in that it sets out in considerable detail an engagement matrix for different types of resource decision-making. This matrix is even more detailed than the Coastal First Nations Protocol as it approaches the process by statutory type (i.e., a permit under the Wildlife Act or the Environmental Management Act). Plus, six different provincial agencies are also parties to it, unlike the above two protocols (simply represented by the Minister of Aboriginal Relations and Reconciliation).

The economic imperatives of this Framework Agreement are broader than those discussed in the previous two protocols. This agreement directs the Strategic Forum to pursue opportunities to achieve the closing of the social and economic gap between the Nanwakolas First Nations and other British Columbians. It also sets out that, through the Strategic Forum, the parties are to reach agreement on finfish aquaculture, a regional renewable energy strategy and guide outfitting.

Treaty 8 First Nations Protocol (Signed on December 17, 2009)
The province and three Treaty 8 First Nations (Doig River, West Moberly and Prophet River) entered into five different agreements which, collectively, provide somewhat similar components to the above protocols. However, the focal point of these collection of agreements is the amendment of an existing Economic Benefits Agreement (the Amended EBA) that previously included the Fort Nelson First Nation.

As part and parcel of this Amended EBA, three agreements dealing with land use decisions – being a Parks Collaborative Management Agreement, a Wildlife Collaborative Management Agreement and a Strategic Land and Resource Planning Agreement – were signed. These agreements are largely process- and goal-oriented and parallel the Haida Protocol in that specific decision-making frameworks are yet to be developed. In addition, given the withdrawal of the Fort Nelson First Nation, an adjustment to the Amended EBA was made to reduce the equity payments to the First Nations by 25%. Also, by signing the other related agreements that are a part of the land use decision-making parcel, the three Treaty 8 First Nations will receive that additional equity payment of about C$3-million as set out in the Amended EBA.

Copies of all of these reconciliation protocols are available on the province's website.

For further information, please contact:

Caroline Findlay 604-631-3333

or another member of our Aboriginal Law Group.




Sharon Wong

The Ontario government recently announced a number of new regulations and programs to give effect to some of the major components of the Green Energy and Green Economy Act (the Green Energy Act) which was introduced earlier this year (see our February 2009 Blakes Bulletin on Energy/Environmental Law/CleanTech). The aim of the Green Energy Act is to provide the legal platform to establish an attractive investment climate for green power developers, provide certainty for the market, and make Ontario a leader in renewable energy and energy conservation in North America.

As of September 24, 2009, the following key features of the Green Energy Act have been implemented:

  • Canada's first feed-in electricity tariff program will begin accepting applications as of October 1, 2009;

  • the new Renewable Energy Approval (REA) required for renewable energy projects is now available;

  • the province has announced a number of incentive programs to help with the costs related to developing a renewable energy project in Ontario;

  • the Renewable Energy Facilitation Office (REFO) has been established; and

  • a C$2.3-billion program for major upgrades to Ontario's electricity transmission grid is underway.

FIT Program
The feed-in tariff is a major component of the province's plan to develop green energy and jobs in Ontario. The FIT program establishes a government procurement process for electricity generated from renewable sources (wind, solar, water, bio-energy), providing standard program rules, standard contracts and standard pricing. For example, Ontario proposes to pay 13.5 cents/kWh for electricity generated from onshore wind turbines, 19.5 cents/kWh for electricity generated from offshore wind turbines, and 80.2 cents/kWh for electricity from small residential rooftop solar facilities. The Ontario government hopes the program will attract a diverse range of renewable energy producers including homeowners, community-based and First Nations groups, and larger scale commercial generators.

The FIT Contract contains Domestic Content requirements that are intended to help foster investment, green manufacturing, construction and installation jobs in Ontario. Wind and solar projects will be required to have a certain percentage of their project costs come from Ontario goods and labour at the time they reach commercial operation. For wind, the requirement will start at 25% and increase to 50% on January 1, 2012. For micro solar photovoltaic (10 kW or smaller), the requirement will start at 40% and increase to 60% on January 1, 2011. For larger solar photovoltaic, the requirement will start at 50% and increase to 60% on January 1, 2011.

Small renewable energy projects that generate less than 10 kW of electricity have a different application process than larger commercial projects and will be administered as micro-feed-in tariff (microFIT) projects. The Ontario Power Authority (OPA) is responsible for administering FIT, and applications to the program will be accepted starting October 1, 2009.

Renewable Energy Approval
Renewable energy projects are now exempted from existing environmental approval and permitting requirements, and instead these projects are required to obtain a new comprehensive Renewable Energy Approval (REA). The REA integrates two existing environmental approval processes. Environmental impact assessment requirements under the Environmental Assessment Act and air quality standards under the Environmental Protection Act are now combined in the single REA process. This new permit or approval replaces what was largely an applicant-driven environmental assessment framework and replaces it with specific provincial rules and requirements for Wind, Solar, Bio-Energy and Water generating facilities. Some highlights of the new rules follow.

Wind
Wind facilities generating less than 3 kW do not require an REA. Small wind facilities between 3 kWh and 50 kW must get an REA but the requirements are simplified and there is no mandatory setback requirement. Facilities generating over 50 kW require an REA, and if the facilities generate a noise level of 102 dBA or louder, they must meet a minimum 550-metre setback from buildings used by people. Where roadway noise exceeds 40 decibels, a noise study can be done to determine the appropriate distance. All turbines over 50 kW must be set back the height of the tower from properties where the landowner is not involved in the project. This can be reduced to a distance equal to the blade length plus 10 metres where there are no surrounding land use concerns. These facilities must also be set back a distance equal to blade length plus 10 metres from the right-of-way for roads and railways.

Solar
The most current form of solar electricity generation is the photovoltaic cell. Roof-Top or Wall-Mounted Solar Facilities of any size do not require an REA. However, most facilities mounted on buildings will require a municipal building permit.

Ground-mounted solar facilities over 10 kW require an REA and also require a noise study demonstrating they can meet a 40-decibel noise level (approximately the noise level experienced in a quiet office). The noise study assesses the potential noise impacts for a residence or other building due to sound emitted by the solar facility's electrical equipment.

Bio-Energy
Bio-energy facilities use organic matter (such as agricultural residues, animal manure, waste wood, wood chips and bark) to generate electricity. To qualify for an REA, the facility must use biomass, biofuel or biogas source material as defined in regulations under the Electricity Act.

The requirements that must be met to obtain an REA vary depending on the location of the facility, the material used to generate the electricity and the size of the facility.

Large industrial facilities will have to submit studies identifying noise, odour and pollutant impacts and how these impacts will be addressed.

Water
Water projects do not require an REA because the approach to the environmental review of waterpower projects was revised in 2008 with the introduction of the Class Environmental Assessment for waterpower projects, and water generating facilities must continue to meet those requirements. Waterpower facilities must also obtain the existing permits and approvals required from the Ministry of the Environment and the Ministry of Natural Resources.

Consultation
The REA has established requirements for public consultation and community awareness. Proponents must notify nearby landowners and the community early in the planning process, and hold at least two community consultation meetings. Proponents must also consult with municipalities and engage in consultation with aboriginal communities.

Incentive Programs
Ontario has announced a number of programs to help with the costs related to developing a renewable energy project.

The Community Energy Partnerships Program
Ontario will provide grants to community groups to pay for certain development costs like feasibility, engineering and environmental studies. Co-ops, charities, not-for-profit corporations, and individual Ontarians interested in being part of developing renewable energy projects can apply for the grants.

Aboriginal Support Programs
The C$250-million Aboriginal Loan Guarantee Program and the Aboriginal Energy Partnerships Program will support First Nations and Métis communities in renewable energy development. Aboriginal communities will be eligible for loan guarantees for up to 75% of an aboriginal corporation's equity participation in an eligible project in renewable generation and transmission projects.

The Aboriginal Energy Partnerships Program will provide support for aboriginal community energy plans, funding for feasibility studies and the development of an Aboriginal Renewable Energy Network.

There are also two incentives to encourage participation in the FIT Program by aboriginal communities:

  • reduced security payments – projects for which an aboriginal community has a 50% interest are eligible for reduced application security (C$5,000/MW, regardless of the renewable fuel type)

  • price adders – if an aboriginal community has 10% or more of an economic interest in a project, the project is eligible to receive an increased price per kWh (a "price adder") above the standard FIT price, proportional to the level of aboriginal involvement and up to a specified maximum amount. For example, the maximum aboriginal price adder for a wind or solar PV project is 1.5 cents/kWh above the standard FIT price. (Lower price adders are available for non-aboriginal community projects where community members have 10% or more of an economic interest in the project.)

Municipal Support Programs
The Municipal Renewable Energy Program reimburses municipalities for direct costs incurred as renewable energy generation facilities are developed. Examples of eligible costs to be paid through reimbursement intended under the program could include:

  • infrastructure affected by construction/installation phases of projects, including roads, drains, easements, parklands, cultural and natural heritage sites;

  • traffic management;

  • surface drainage to protect adjacent property and roads; and

  • emergency management costs, including details respecting on-site safety and measures to ensure emergency services personnel are adequately trained.

The Renewable Energy Facilitation Office
Ontario has established a Renewable Energy Facilitation Office (REFO) to assist renewable energy project proponents (developers, communities and municipalities). The REFO can connect proponents with the appropriate resources in various other government ministries and agencies, and provide information relating the various government incentive programs.

Transmission Upgrades
Ontario has given the go-ahead to Hydro One (the operator of the province's main electricity transmission grid) to begin work on 20 transmission projects across the province. Six core transmission network upgrades are moving forward, including North-South lines from Sudbury to Barrie and Barrie to the Greater Toronto Area and an East–West line from Nipigon to Wawa. Another series of core-supporting transmission projects and distribution upgrades are also moving ahead.

Currently, constraints on transmission facilities limit the ability to connect new generation facilities (including renewable generation projects) to the transmission grid. The planned transmission upgrades will relieve some of the existing constraint and allow the province to connect more renewable generation facilities to the grid.

Stay Tuned
More details on the new regulations and program rules will become available over the upcoming weeks and months. Blakes will continue to monitor and report on Ontario's ground-breaking renewable energy program and the business opportunities it is creating.

You can obtain additional information about the Green Energy Act from:

Sharon Wong 416-863-4178
Richard Corley 416-863-2183

or any member of Blakes Energy Group or our Clean Tech Group.




Howard Levine, Philippe Décary, Viorelia Guzun & Patrick Menda

On June 29, 2009, the Government of Quebec (the Government) unveiled its long-awaited mineral strategy (the Mineral Strategy) whose primary objective is to ensure the sustainable development of mining in the province of Quebec. The Mineral Strategy seeks to achieve this objective by way of three policy directions, namely: i) creating wealth and preparing for the future of the mineral sector; ii) ensuring environmentally friendly mineral development; and iii) fostering integrated, community-related mineral development.

A copy of the Mineral Strategy is available at http://www.quebecminier.gouv.qc.ca/english/publications.asp.

Background
In 2007, the Government announced that it would table a mineral strategy by late 2007. Concurrent with this announcement, the Government published a consultation paper which was open for comment until October 20, 2007. The consultation paper identified the following five principal challenges that must be overcome in order to prepare the Quebec mineral sector for the future and effectively position the province in a global marketplace: i) discovering new mineral deposits; ii) strengthening industry competitiveness and maximizing economic windfalls from mining activities; iii) ensuring the availability of a competent and qualified labour force; iv) balancing the protection of the environment with the development of mining activities; and v) involving the regions, including the native and Inuit communities, in current and future developments. While more than two years has passed since its targeted due date, the recently announced Mineral Strategy represents the fruits of the public consultation process.

Policy Direction 1: Creating Wealth and Preparing for the Future of the Mineral Sector
The Mineral Strategy's first policy direction is to create "wealth and prepare for the future of the mineral sector" (the First Policy Direction) and focuses primarily on increasing exploration, research and development, workforce training, networking initiatives among industry players and field data gathering.

The Government believes that the future of the mineral sector hinges upon increasing exploration activities. As such, the First Policy Direction relies heavily upon acquiring additional data with respect to Quebec's geological makeup, including extensive mapping and surveys of northern Quebec, in an effort to make more information available to prospectors with a view to increasing exploration in the region. Moreover, the Government plans to gather additional data using new technologies to determine whether any additional mineral potential is located in previously mined sites.

The diversification of Quebec mineral production is an important aspect of the Mineral Strategy. In this regard, the Government plans to continue its efforts to identify new copper deposits. The Government also intends to pursue its development strategy for the province's diamond potential and will continue to promote the province's potential with respect to gemstones (diamonds, emeralds, sapphires, rubies), decorative stones (garnet, topaz, zircon) and ornamental stones (agate, labradorite, amazonite).

In addition, to facilitate access to northern Quebec, an area which is currently poorly serviced by roads, the Government proposes to forge partnerships with mining exploration companies to develop the infrastructure in the region.

Another significant initiative under the First Policy Direction is the review of the Quebec Mining Act (the Act), specifically with respect to its provisions regarding mining claim renewals. Under the existing Act, in order to preserve their title to a claim, claim holders may pay a fee to the Minister of Natural Resources and Wildlife (MNRW) in lieu of conducting exploration work. The Government proposes to review the renewal regime with a view to generating increased exploration activities and eliminating "dormant" claims.

Further, the First Policy Direction proposes to overhaul the current mining royalties regime in an attempt to reflect the cyclical nature of the mineral sector and to ensure that the province receives what the Mineral Strategy refers to as its "fair share" from mining activities on its territory. However, the Mineral Strategy does not provide any additional information with respect to the scope or extent of the proposed changes in this regard.

Another important aspect of the First Policy Direction is its emphasis on research and development. In this respect, the Mineral Strategy proposes to have mineral sector businesses comply with the Government's research and innovation strategy which calls for allocating 3% of its gross domestic product to research and development activities. In addition, the Mineral Strategy proposes that funding be provided to public, private and academic research organizations, and that the federal government be lobbied to contribute financially to this initiative.

The First Policy Direction also contemplates supporting mining entrepreneurship, including the revision of the mandate of the Société d'investissement dans la diversification de l'exploration (SIDEX), in order to allocate up to 20% of its investment portfolio to assist junior mining exploration companies. The Société québécoise d'exploration minière (SOQUEM), the mining exploration arm of the Société générale de financement, will continue its mission of promoting the diversification of mineral production in the province.

With respect to the mineral sector workforce, the First Policy Direction seeks to enhance education and training opportunities and to promote mineral sector employment with the creation of the Institut National des Mines (the Institute) to co-ordinate such efforts.

The final component of the First Policy Direction provides for the creation of the Mining Heritage Fund (the Fund), whose primary purpose will be to fund the Government's geoscientific data gathering effort. The Fund will provide C$200-million in funding over 10 years, of which C$120-million will be dedicated to the data gathering effort. The Government intends to finance the Fund through a portion of the mining royalties collected from mining companies.

Policy Direction 2: Protecting the Environment
The Mineral Strategy's second policy direction is to ensure "environment-friendly mineral development" (the Second Policy Direction) and targets the following areas: i) the rehabilitation of abandoned mines; ii) the improvement of environmental protection for the future; and iii) land conservation for future generations.

In terms of rehabilitation of abandoned mines, the Mineral Strategy does not, on its face, appear to announce any new policy initiatives as it merely reaffirms the Government's undertaking set out in its 2007-2008 budget to rehabilitate contaminated sites under its responsibility. Such rehabilitation is to continue over a 10-year period.

With respect to the improvement of environmental protection for the future, the Second Policy Direction contemplates the amendment of those provisions of the Act regarding rehabilitation guarantees to be provided by companies conducting mining operations. Under the existing provisions, mining companies must file a rehabilitation plan at the start of the project planning process and provide a security deposit equal to 70% of the estimated rehabilitation costs. Such security deposit payments are made in accordance with a schedule based on the life of the mine. However, if a mining company goes bankrupt before all scheduled security deposit payments are made, the Government may potentially be required to pay for any unsecured rehabilitation costs. The Second Policy Direction proposes to rectify this situation by increasing the rehabilitation security deposits to cover 100% of the rehabilitation costs and expanding such costs to include more than merely the tailings accumulation sites. In addition, the security deposit payment schedule would be revised and accelerated so that the first such payment would be made in the first year of operation of the mine. Existing mine sites would be transitioned into this revised regime over a five-year period. Similar rehabilitation obligations will be proposed in connection with exploration activities.

The Second Policy Direction also contemplates imposing the obligation upon companies to present their rehabilitation plans to the Bureau d'audience publique en environnement (BAPE) in order to provide the relevant communities with the pertinent facts and information regarding post-closure site decontamination.

In addition, the Second Policy Direction contemplates lowering the ore production thresholds triggering the need for metallic minerals or chrysotile production mines to prepare environmental impact studies and potential BAPE hearings from 7,000 tons of ore per day to 3,000 tons of ore per day.

Reporting requirements with respect to discoveries of radioactive materials will also be implemented, as will stricter regulations concerning their exploration and mining. The Second Policy Direction also proposes to tighten the evaluation criteria for bulk sampling applications.

The third and final component of the Second Policy Direction promotes the Government's goal of efficiently managing and preserving land under its control. In this regard, the Government will continue to identify certain protected areas and limit mineral activities in those areas. In addition, an assessment and inventory of eskers located in Quebec will be conducted with a view to protecting these geological formations, created by glaciers during the last ice age, which can be an important source of drinking water.

Policy Direction 3: Involving the Interested Communities
The Mineral Strategy's final policy direction is to promote "integrated, community-related mineral development" (the Third Policy Direction) through fostering local and aboriginal participation in mineral development, disseminating information about mining titles and balancing land uses.

The Government intends to continue to work alongside regional communities in connection with the planning and implementation of mineral projects. In this regard, the Third Policy Direction states that the Act will be amended such that any metal or chrysotile mining projects expected to yield less than 3,000 tons of ore per day will be subject to public consultations prior to the start of mining operations.

The Act will further be amended to impose a notification obligation on claim holders requiring them to inform landowners and tenants of the existence of a claim on their land.

To encourage aboriginal involvement in mineral activities in the province of Quebec, the Third Policy Direction commits to extend the Native Mining Fund Assistance Program to 2013. The Native Mining Assistance Fund is a program aimed at promoting prospecting in less explored areas, developing mineral sector expertise among aboriginal communities and fostering the creation of aboriginal businesses in the resource sector. In addition, the Mineral Strategy will encourage the entering into of partnership agreements between mining companies and aboriginal communities and will facilitate access to training and employment by funding workforce training programs for aboriginal workers.

With a view to balancing land uses, the Third Policy Direction states that the Act will be amended to grant the MNRW the power to plan land uses and determine which sectors may or may not be used for mineral development. Amendments to the Act will also provide the MNRW with the power to deny leases for surface mineral substances and terminate mining titles for such substances, in circumstances where the public interest warrants. Lastly, modifications will be made to the Act empowering the MNRW to refuse leases for pits and quarries and clarifying expropriation rights under the Act.

While the Mineral Strategy provides insight into the Government's policy direction for mineral resource development in the province of Quebec, it does not elaborate upon the detailed steps that will be taken or the timeline that will be followed in order to implement such policy. It is expected that further announcements will be made by the Government in this regard.

For further information, please contact:

Howard Levine 514-982-4005
Philippe Décary 514-982-4074
Viorelia Guzun 514-982-4087
Patrick Menda 514-982-5051

or any member of our Mining Group.




Selina Lee-Andersen

On July 15, 2009, the Western Climate Initiative (WCI) issued the first version of its Final Essential Requirements of Mandatory Reporting (ERMR). The WCI is a collaboration of seven U.S. states and four Canadian provinces including British Columbia (B.C.), Manitoba, Ontario and Quebec participating as partners, along with Saskatchewan as an observer. The ERMR establishes general provisions for greenhouse gas (GHG) reporting, requirements for third-party verification and quantification methodologies for the following source categories:

  • general stationary combustion;
  • refinery fuel gas combustion;
  • electricity generation;
  • electricity imports;
  • primary aluminum manufacturing;
  • cement manufacturing;
  • coal storage;
  • hydrogen production;
  • iron and steel manufacturing;
  • lime manufacturing;
  • petroleum refining;
  • pulp and paper manufacturing;
  • soda ash production;
  • petrochemical production; and
  • adipic acid manufacturing.

Reportable GHGs include carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride. The WCI continues to work on the development of additional quantification methodologies for other source categories including zinc production, lead production, copper and nickel production, glass production, electronics manufacturing, coal mine fugitive emissions, gas processing plants, transportation fuel suppliers, residential/commercial/industrial fuel suppliers, upstream oil and gas production, and natural gas distribution. The WCI plans to issue draft methodologies for these categories later this year.

Responding to Stakeholder Concerns
The ERMR incorporates changes made in response to stakeholder comments on previous versions of the ERMR issued in January 2009 and May 2009. In its "Response to Stakeholder Comments", the WCI notes that one overarching concern of stakeholders is the potential for inconsistency with U.S. and Canadian national reporting requirements. As a result, the WCI has identified "alignment with national reporting programs in order to minimize the burden on facilities subject to both WCI and federal reporting requirements" as a key principle in the development of the Regional Emissions Database that will serve as the repository for data submitted under the ERMR. Stakeholders also raised concerns about other issues including later reporting deadlines, the need for uniform thresholds throughout the region, the desire for a higher reporting threshold (or a phase-in for lower thresholds), and whether third-party verification should be required at all.

Highlights of the ERMR
The following provides an overview of the ERMR's main provisions (more detailed information is available on WCI's website: http://www.westernclimateinitiative.org).

  • Reporting Entities. GHG emissions reporting requirements and related monitoring, recordkeeping and verification requirements of the ERMR will apply to the owner/operator of a facility that emits 10,000 metric tons of carbon dioxide equivalent (CO2e) or more per year in combined emissions from one or more of the source categories in any calendar year starting in 2010.

  • Future Applicability to Other Sectors. The ERMR includes references to requirements for reporting emissions from electricity imports and the combustion of residential, commercial and industrial fuels. The requirements for these sectors have not yet been completed by the WCI and will not go into effect for the 2010 reporting year. The WCI advises that WCI member jurisdictions may omit these references until the rules in such jurisdictions are amended to include reporting requirements for these sectors. Once this happens, reporting requirements will apply to: (i) all importers of electricity, including both retail providers and marketers (the definition of electricity importers is pending); (ii) any supplier within the WCI which distributes transportation fuels in quantities that when combusted would emit 10,000 metric tons of CO2e per year or more in any calendar year starting in 2010 (pending the future determination of point of regulation for transportation fuels); and (iii) any supplier that distributes within the WCI region residential, commercial and industrial fuels in quantities that when combusted would emit 10,000 metric tons of CO2e or more per year in any calendar year starting in 2010 (pending the future determination of point of regulation for these fuels).

  • Annual Reporting. Owner/operators subject to mandatory reporting will be required to submit an annual GHG emissions report to the relevant authority in their jurisdiction by April 1 of each year for emissions in the previous calendar year.

  • Reporting by Existing Entities. A reporting entity that commenced operation before January 1, 2010 will be required to report emissions beginning in 2011 for GHGs emitted in calendar year 2010.

  • Reporting by New Entities. A new reporting entity that commences operation on or after January 1, 2010 will be required to report emissions for the first calendar year in which the facility operates, beginning with the first operating month and ending on December 31 of that year. Each subsequent annual report must cover emissions for the calendar year, beginning on January 1 and ending on December 31.

  • Verification Requirements. Reporting entities emitting 25,000 metric tons of CO2e or more per year in combined emissions from one or more of the source categories listed above in any calendar year starting on or after 2010 will be required to obtain annual verification of their GHG emissions data reports.

  • Verification Deadlines. The verification process, including the submission of a verification statement to the relevant authority, will need to be completed: (i) for reporting years 2010 through 2011, by September 1 of the year following the reporting year; and (ii) for reporting years 2012 and later, on a date to be determined.

  • Recordkeeping. Reporting entities will be required to retain GHG reporting documentation for a period of seven years following submission of each emissions data report.

  • Designated Representative (U.S. only). The ERMR contains a rule which will apply only to reporting entities located in U.S. member jurisdictions. Under this rule (WCI.7), each fuel supplier, electricity importer and owner/operator of a facility that is subject to the ERMR is required to select a designated representative who is responsible for certifying and submitting GHG emission reports. The designated representative will be authorized by a certificate of representation agreement that is signed by the designated representative and owner/operator of a facility. The designated representative must be an individual having responsibility for the overall operation of the facility or activity (for example, the plant manager or superintendent of a facility) or an individual having overall responsibility for environmental matters for the entity. The designated representative will be required to provide certification statements in accordance with the specific language set out in Rule WCI.7.

  • Operator's Representative (Canada only). For reporting entities located in Canadian member jurisdictions, an "operator's representative" (rather than a designated representative) will be required to issue certification statements. In the "Response to Stakeholder Comments and Final Draft Essential Requirements for Mandatory Reporting" dated May 7, 2009, the WCI acknowledged that the concept of a "designated representative" is not used in Canada, so the ERMR language references certification by an "operator's representative" in the Canadian context. The provision for an operator's representative is meant to have the same effect as the designated representative provision, but is consistent with Canadian practices whereby the representative is based on either the corporate structure or the management of the operation.

  • Verification Bodies. Accreditation requirements set out in the ERMR will apply to all verification bodies that wish to provide verification services. A verification body is qualified to conduct verification services for the WCI if: (i) it has demonstrated knowledge of WCI reporting requirements; and (ii) it is accredited to ISO 14065 (Greenhouse gases – Requirements for greenhouse gas validation and verification bodies for use in accreditation or other forms of recognition) through a program developed under ISO 17011 (Conformity assessment – General requirements for accreditation bodies accrediting conformity assessment bodies) by an accreditation body that is a member of the International Accreditation Forum. A verification team must include a lead verifier and an independent peer reviewer. A verification body may also elect to subcontract verification services to another party.

  • Verification Process. The ERMR contains detailed information about the development of verification plans, verification statements, and conflict of interest issues for verification bodies. Reporting entities which are subject to verification requirements will not be permitted to use the same verification body for a period of more than six consecutive years (the reporting entity may contract again with the previous verification body only after not using them for a period of at least three years).

  • Quantification Methodologies. The ERMR contains methodologies for emissions quantification as well as sampling, analysis and measurement information for each of the source categories listed above.

Provincial Initiatives to Facilitate Cap-and-Trade
The ERMR serves as the basis for WCI jurisdictions to adopt initial rules for implementing the WCI's reporting program. It is anticipated that WCI member jurisdictions will have rules in place for the 2010 reporting year or as soon thereafter as possible. In B.C., the Ministry of Environment issued a policy paper (Intentions Paper) in October 2008 to outline its intention to introduce a Mandatory Reporting of Greenhouse Gas Emissions Regulation (B.C. Reporting Regulation) in 2009 to facilitate the implementation of the WCI cap-and-trade system. The main provisions of the Intentions Paper were drawn from the WCI's "Draft Essential Requirements for Mandatory Reporting Document", which was originally released in July 2008. While the proposed regulation has not yet been finalized, with the release of the ERMR, it is likely that the draft B.C. Reporting Regulation will be issued shortly. For more detail about the proposed reporting regulation in B.C., please see our December 2008 Blakes Bulletin on Environmental/CleanTech: A New Era of Reporting Obligations: British Columbia Proposes Mandatory Reporting of Greenhouse Gas Emissions for 2009.

While Manitoba has legislated a greenhouse gas emissions reduction target of 6% below 1990 levels by 2012 (which is consistent with the emissions reduction target under the Kyoto Protocol) and has committed to the WCI, it has not yet introduced any legislation to facilitate the implementation of a cap-and-trade system.

In Ontario, the provincial government has been taking steps to establish a framework in support of a cap-and-trade system. On May 27, 2009, the Ontario government introduced the Environmental Protection Amendment Act (Greenhouse Gas Emissions Trading) 2009, which will enable the government to set up a GHG emissions trading system in Ontario and provide the province with the ability to link Ontario's cap-and-trade system to other trading systems, including the WCI. This proposed legislation is subject to a 60-day public review and comment period, which ends July 26, 2009. In addition, the Ontario government issued a discussion paper in June 2009 entitled "Moving Forward: A Greenhouse Gas Cap-and-Trade System for Ontario". In the discussion paper, currently undergoing public consultation, the Ontario government says it is their intention to harmonize the province's reporting process with that of the WCI and any U.S. federal trading system.

In Quebec, Bill 42 (entitled An Act to amend the Environment Quality Act and other legislative provisions in relation to climate change) was tabled in the National Assembly by the Minister of Sustainable Development, Environment and Parks on May 12, 2009. The Act allows the government to set GHG emissions reporting requirements and establish a cap-and-trade system. Reporting provisions took effect on June 19, 2009. The Quebec government is expected to adopt a regulation this fall identifying subject entities and setting out reporting rules.

Continued Progress
The Canadian and federal U.S. governments continue to make progress on the climate change front. In June 2009, the Canadian Minister of Environment announced that the federal government is moving forward with its offset credit program for GHGs. Two draft guides were published in the Canada Gazette on June 12, 2009 which set out the proposed offset program rules and guidance for both offset project proponents and verification bodies. The final version of these proposed rules and guidance, together with the Guide for Protocol Developers (a draft of which was published in the Canada Gazette on August 9, 2008), are expected to be published in fall 2009. For more information on these guides, please see our June 2009 Blakes Bulletin on Environmental/CleanTech: Draft Federal Greenhouse Gas Offset Rules Issued – Subject to Comment Until August 12, 2009.

The federal government has indicated that Canadian offset program rules, federal regulations and enforcement mechanisms will be reviewed to ensure they are comparable with any U.S. climate change legislation that is eventually implemented. On June 26, 2009, the American Clean Energy and Security Act of 2009 (ACES) was passed by the U.S. House of Representatives. The ACES establishes the framework for a U.S. cap-and-trade system as well as energy efficiency initiatives and incentives for the development of clean energy technologies. The vote on the ACES in the U.S. House of Representatives is the first step in a two-stage process. In order for the ACES to become law, it must next pass the U.S. Senate. It is anticipated that the Senate debate on the ACES will take place in late summer and fall 2009. If passed, the U.S. will be required to reduce its GHG emissions by 17% below 2005 levels by 2020.

Laying the Foundation
The ERMR is an important first step in laying the foundation for the WCI's cap-and-trade system. Accurate emissions reporting and high quality data are essential to ensuring the integrity of any emissions trading system and fostering public confidence in that system. While the WCI continues to further develop reporting requirements and quantification methodologies, it is now up to the WCI jurisdictions to undertake stakeholder consultations and implement enabling legislation to facilitate the adoption of reporting requirements. The WCI has acknowledged stakeholder concerns about the administrative burden associated with multiple reporting systems and member jurisdictions have indicated their intent to harmonize reporting requirements with the requirements of the WCI and any federal system. These efforts to ensure consistency in reporting standards should help to minimize overlapping regulatory requirements and simplify the administration of the reporting system.

For further information, please contact the author or any other member of Blakes Environmental Group or CleanTech Group.




Richard Corley & Robert Fishlock

Canadian businesses need to assess their greenhouse gas emissions and consider options for reducing such emissions in light of the recently released NRTEE report.

On April 16, 2009, the National Round Table on the Environment and the Economy (NRTEE) issued its Achieving 2050 proposal for a Canadian carbon pricing policy, which includes a comprehensive and in-depth assessment of how to most efficiently reduce greenhouse gas (GHG) emissions in Canada. The NRTEE is an organization that was created in 1988 to generate and promote sustainable development solutions to advance Canada's national environmental and economic interests simultaneously, through the development of innovative policy research and advice.

The goals of Achieving 2050 are a carbon pricing policy that meets the Canadian government's medium and long-term GHG emission targets with the least economic cost, and to minimize adverse impacts on regions, sectors, and consumers. NRTEE aims to achieve maximum GHG emission reductions at the lowest cost through the implementation of comprehensive and integrated approach for developing and implementing a Canadian carbon pricing policy.

Achieving 2050 proposes a national carbon pricing policy that would establish a unified carbon price across all emissions, policies, and jurisdictions, and send a credible long-term price signal sufficient to drive new investment and technology development. NRTEE estimates that a unified carbon price across all emissions, policies, and jurisdictions would allow for a steady-state carbon price of C$300 per tonne of carbon dioxide equivalents (CO2e) some time after 2030, rather than a price in excess of C$350/tonne of CO2e that would result from a fragmented policy. Achieving 2050 submits that a credible long-term carbon price signal that generates confidence in the marketplace would result in lower GHG emissions overall, compared to alternatives which involve uncertainty about the future carbon policy and prices.

Policy Wedges

The proposed carbon pricing policy involves three main components or "policy wedges", as illustrated in the figure below. The first policy wedge is a single national cap-and-trade system, the second is complementary regulations and technology policies, and the third is international opportunities. The first policy wedge, which accounts for the majority of the GHG emissions, is targeted both at "large emitters" emissions (wedge 1A), and "rest of economy" emissions (wedge 1B) from buildings, households, transportation, and light manufacturing.

Emissions are expected to reach 1,100 MT by 2050 unless action is taken

The cap-and-trade system underpinning the first policy wedge is a system whereby the government sells a fixed number of permits to people who emit GHGs. The number of permits owned determines the amount of GHGs that may be emitted by a person, in excess of which such person will have to purchase offset credits under the system. As discussed in the first part of this bulletin, unregulated businesses and other organizations which reduce their GHG emissions may obtain offset credits which they can sell to businesses that wish to exceed their permitted GHG emission levels as determined by their permits allocated from the government. Since there are a fixed number of permits in the marketplace, the amount of GHGs that will be emitted is also fixed or "capped". And since permits can be purchased/sold by entities that emit more/less GHGs than their permitted allowance, the system is characterized as a "cap-and-trade".

For more detailed discussions of what the trading of permits might entail, see the Blakes Bulletins entitled The Role of Emissions Offset Trading in North American Greenhouse Gas (GHG) Emissions Regimes and Making Sense of Carbon Transactions: The Nuts and Bolts of an Emissions Trade.

The main disadvantage of a cap-and-trade system is that there is uncertainty with respect to the market price of permits. If GHG emissions are much greater than what is permitted based on the number of permits available, then the price of each permit will be high, because the demand for such permits will exceed their supply. The main alternative to a cap-and-trade system, and the way to achieve price certainty, is a pure carbon tax, whereby the government sets a tax on all GHG emissions. However, while a pure carbon tax may provide certainty for the cost of GHG emissions, it does not provide certainty for the quantity of GHG reductions.

In addition to the cap-and-trade system, the proposed carbon pricing policy includes a policy wedge of complementary regulations and policies to expand the policy coverage and address technology barriers. Specific regulations can broaden the coverage of the carbon pricing policy by targeting emissions in certain sectors that do not respond efficiently to a carbon price signal alone, such as in the transportation, buildings, oil and gas, and agriculture sectors. Technology barriers can be addressed with policies that support technology innovation, adoption, and deployment. Some of the technologies that are likely to help Canada reach its GHG emission reduction targets include increased energy efficiency, carbon capture and storage (CCS), and fuel switching to electricity and renewables.

The final policy wedge in the proposed carbon pricing policy involves low-cost international carbon abatement opportunities. Such opportunities allow for purchases of real and verifiable international carbon permits through links between the Canadian trading system and other systems. The result of this third policy wedge, if applied to 30% of Canada's targeted reductions by 2050, is that the steady-state carbon price could be reduced from C$300/tonne of CO2e to below C$200/tonne of CO2e. However, if Canadian entities are purchasing permits abroad, then the amount of GHGs actually emitted from Canada will still be greater than Canada's targets, because the fixed number of permits initially sold by the Canadian government will be supplemented by other permits obtained elsewhere. Furthermore, it is not yet clear how Canada will integrate its cap-and-trade system with its key trading partners such as the United States.

A governance framework is proposed to develop, implement, and manage the unified carbon pricing regime over time. This governance framework calls for ongoing collaboration between federal, provincial, and territorial governments, an expert Carbon Pricing and Revenue Authority with a regulatory mandate, and an independent, expert advisory body to provide regular and timely advice to government.

Comparisons and Challenges
Achieving 2050 is based on abatement goals set by the federal government, which appear increasingly out of step with the global scientific consensus around the need for greater reductions. The federal government has targeted a 20% reduction in GHG emissions by 2020 and a 65% reduction by 2050, relative to 2006 levels. Canada's equivalent targets relative to 1990 levels are a 3% reduction by 2020 and a 58% reduction by 2050. Canada's abatement goals are significantly less ambitious than those of the European Union, the United Kingdom, or the United States (based on President Obama's election proposal), all of which are targeting up to an 80% reduction in GHG emissions by 2050, relative to 1990 levels. (For a more detailed discussion of proposed GHG legislation in the United States, see the Blakes Bulletin entitled A Bold Step Forward: What the Draft U.S. Clean Energy and Security Act of 2009 Means for Canadian Industry.) Achieving 2050 is based upon Canada's current targets and would need to be recalibrated in the event that these targets were to change.

According to Environment Canada, Canada's GHG emissions have increased steadily from 592 Megatonnes (Mt) of CO2e in 1990 to 747 Mt CO2e in 2007. Kyoto called for the reduction of GHG emissions to below 1990 levels by 2012, which for Canada meant a reduction in GHG emissions to 556 Mt CO2e. However, Canada's 2007 GHG emissions were 34% above the Kyoto target. Even with the federal government's current plan of reducing GHG emissions to 577 Mt CO2e by 2020, Canada would still be above its Kyoto commitment for 2012.

Canada's GHG emissions levels are already higher than most countries, particularly on a per capita basis. According to The Conference Board of Canada, the average Canadian emitted 22.6 tonnes of CO2e in 2005, compared to 21.7 tonnes of CO2e emitted by the average American, 10.9 tonnes of CO2e emitted by the average Briton, and 8.1 tonnes of CO2e emitted by the average French or Italian. This higher level of per capita GHG emissions, combined with Canada's less ambitious targets for reducing GHG emissions, suggests that Canadians may continue to be among the world's greatest producers of GHGs and contributors to global warming.

While Achieving 2050 proposes a carbon pricing policy that would help to reduce Canada's GHG emissions, it is not as effective as proposals and legislation in other countries. For example, the United Kingdom's Low Carbon Industrial Strategy, including its "Budget 2009", has established concrete measures to achieve significant reductions in GHG emissions, with more than £60-billion (or C$100-billion) of low-carbon investment from now until 2011. As of April 1, 2009, the United Kingdom gas tax was increased to £0.5419/litre (or C$0.96/litre), which is more than the current price of gas in Toronto. Since 2.4 kg of CO2 is produced for every litre of gasoline used, a gas tax of C$0.96/litre is equivalent to an additional cost of C$400/tonne of CO2. The Canadian government should not only consider implementing the recommendations in Achieving 2050, but it should also consider realigning its initial targets and objectives with international best-practices.

It also remains to be seen if a unified and national system, as proposed in Achieving 2050, will replace the provincial and regional systems that are either emerging or currently in place:

As these various policy and legislative initiatives move forward, Canadian businesses will need to assess their GHG emissions and consider options for reducing such emissions in order to comply with current and proposed legislation. It is becoming increasingly clear that there will inevitably be a cost to emit GHGs, and the cost may be expected to increase substantially over time. As the cost of GHG emissions increase, the value of GHG emissions permits and offset credits will become an increasingly important economic factor for Canadian businesses.




Richard Corley & Matt Flynn

Canada's Environment Minister, Jim Prentice, recently announced that the government is moving forward with its offset credit system for greenhouse gases. Two draft guides were published in the Canada Gazette on June 12, 2009 to set out proposed rules and guidance for offset project proponents and for verification bodies, each of which is described in further detail below. The Environment Canada overview document describing the Offset System was also updated. The two draft guides are respectively entitled Program Rules and Guidance for Project Proponents and Program Rules for Verification and Guidance for Verification Bodies. To put these two guides in context, reference should be made to the April 16, 2009 report of the National Round Table on the Environment and the Economy.

The comment period for the draft program rules and guidance documents closes on August 12, 2009. Interested parties should review the draft program rules and guidance documents with a view to providing comments by this deadline. Requests for information, copies of documents and comments should be addressed to the Manager of Canada's Offset System for Greenhouse Gases at os_scc_consultations@ec.gc.ca. Final versions of the two program rules and guidance documents together with the Guide for Protocol Developers (a draft of which was published in the Canada Gazette on August 9, 2008) are expected to be published in the fall of 2009.

The objective of the Offset System is to establish tradeable credits and thereby to encourage cost-effective reductions in domestic greenhouse gas emissions in sectors that will not be subject to the proposed federal greenhouse gas regulations. Agriculture and forestry are two examples of such sectors.

Once the Offset System is established, regulated and unregulated businesses, organizations and individuals will be able to acquire and use the offset credits created under the system to offset greenhouse gas emissions resulting from their activities. These offset credits may be used by companies which are subject to greenhouse gas emission regulations to assist them to achieve compliance with their emission targets.

The Program Rules and Guidance for Project Proponents sets out draft rules and guidance on the requirements and processes which are to be used to create offset credits. The rules are to include step-by-step instructions for preparing the required registration, reporting and verification documents. The draft rules set out six principal eligibility criteria that greenhouse gas reductions must satisfy in order to be eligible to receive offset credits:

  1. The greenhouse gas reduction must occur in Canada and must achieve reductions in one or more of the specified greenhouse gases.

  2. The reductions must be real, meaning that the project includes one or more specific actions that result in a net reduction of greenhouse gases that could not be achieved as a result of decreasing the level of activity or production of the project vis-à-vis a comparable baseline.

  3. The reductions must be considered incremental, meaning:

    1. the project must have started on or after January 1, 2006,
    2. the reductions must have occurred on or after January 1, 2011,
    3. the reductions go beyond the applicable baseline,
    4. the reductions must also be surplus to all legal or regulatory requirements, and
    5. the reductions must not be subject to any other climate change incentives.

  4. The greenhouse gas reductions must be quantified as specified in an applicable offset system quantification protocol.

  5. The emission reduction or removal must be verifiable by an accredited third-party Verification Body ensuring that its quantification is accurate, transparent and replicable.

  6. A particular greenhouse gas reduction can only be used once to create an offset credit.

The Program Rules for Verification and Guidance for Verification Bodies provides rules and guidance on the processes and requirements which must be satisfied in order to verify the eligible greenhouse gas reductions or removals which are achieved by a registered project.

In the Canadian context, it should be noted that to date Alberta is the only Canadian province with a mandatory greenhouse gas reduction regime in place. This regime has been in place since July 2007 and applies to Alberta facilities that emit greater than 100,000 tonnes of CO2 equivalents (CO2e) annually. Like the proposed federal Offset System discussed in this bulletin, Alberta facilities subject to the province's regime are able to comply with their greenhouse gas emissions obligations by, among other options, purchasing emissions offset credits.

In Alberta, offset credits arise when an entity with emissions less than 100,000 tonnes of CO2e/year (i.e., a non-regulated entity) produces a product or completes a process in a manner that releases less CO2e than the business as usual or baseline case. The difference between the CO2e actual emissions and the business as usual case represents an emissions offset credit. Regulated emitters who cannot otherwise meet their required reduction requirements can purchase emissions offset credits and use those credits to offset their CO2e emissions. To qualify under the Alberta regime, emissions offset credits must:

  1. Occur in Alberta.
  2. Not be otherwise required by law.
  3. Arise on or after January 1, 2002.
  4. Be real, demonstrable, quantifiable and measurable.
  5. Have clearly established ownership.
  6. Only be used once.
  7. Be verified by a third party verifier.

To assist in calculating the business as usual or baseline case, and thus calculating emissions offset credits, Alberta has enacted 24 emissions quantifications protocols.

In its press release Backgrounder: Canada's Offset System for Greenhouse Gases, Environment Canada states: "As we finalize the [Canadian] offset system, we will explore approaches to harmonize the federal and various provincial offset systems, with an objective to ensure that carbon trading markets can function efficiently." The Alberta experience offers Canada valuable guidance in the area of offset credit systems – hopefully, Canada will take advantage of it.

Further information concerning the draft offset rules may be found on the Environment Canada website for Canada's Offset System for Greenhouse Gases.

If you have any questions, or would like us to assist you to prepare comments on the draft rules prior to the August 12, 2009 deadline, please contact the authors or any other member of the Blakes CleanTech Group or Environmental Group.




Dalton McGrath & Gavin Matthews

For the first time, a Canadian court in Don Hobsbawn v. ATCO Gas and Pipelines Ltd. (ATCO) has approved a private third-party financing arrangement to fund a putative class action. The plaintiff and BridgePoint Financial Services Inc. (BridgePoint), a non-party financial institution, applied, on an ex-parte basis (without notice and hearing from the other side), and were granted an Order by the Honourable Mr. Justice S. A. Lovecchio in the Alberta Court of Queen's Bench approving not only the retainer agreement between the representative plaintiff and his counsel but an indemnity agreement between the plaintiff and BridgePoint to fund the lawsuit. The financing arrangement has been sealed, so the details of it are not currently public.

The nature of the ATCO action is the same or similar to that in Garland v. Consumers' Gas Co. (1998), 3 S.C.R. 112, decided by the Supreme Court of Canada. The facts in Garland were that Consumers' Gas, a gas utility, billed its customers a late payment penalty for payments received after the due date specified in its invoices, calculated at 5% of the unpaid charges for that month. The penalty was implemented by Consumers' Gas in 1975 following a series of rate hearings conducted by the Ontario Energy Board. The representative plaintiff in that class action commenced an action on behalf of a large number of Consumers' Gas customers alleging that the penalty violated section 347 of the Criminal Code because, for a significant number of customers each month, it constituted an allocation of interest at a rate exceeding 60% per year.

The allegations in the Statement of Claim in ATCO are similar. It alleges that ATCO has, since January 1, 1982, charged late payment penalties in violation of section 347 of the Criminal Code. In addition, it alleges that ATCO did not comply with certain sections of the Canada Interest Act requiring an express statement setting out the yearly rate of interest to which the late penalty is equated.

While the substantive nature of the claim is not novel, the fact that the representative plaintiff was able to obtain approval by the court of third-party financing will no doubt send a chill to defendants in proposed class action proceedings.

Under class action and other proceedings in Alberta, unsuccessful plaintiffs must generally pay the taxable costs and disbursements of a defendant in circumstances where a claim is struck out or otherwise dismissed. This differs from the “no-costs” regime implemented by class proceedings legislation in most other provinces. While the taxable costs regime was not developed to fully indemnify a defendant for its costs, the stated intent of that regime in Alberta has been to provide a 40-50% form of costs indemnification. That partial indemnification has been said to reflect an attempt to balance two conflicting interests. One argument is that if a party is successful in defending a claim, it is unfair to require the successful party to bear the costs incurred in defending the action. The competing argument is that if the unsuccessful party is required to bear the costs of a successful defendant, litigants may be unduly hesitant to commence a claim and assert their rights (even if valid). The partial indemnification practice as it exists in Alberta is a compromise of those positions and is intended to give some consideration for each of the conflicting policy considerations. Historically, the ability to collect costs from an unsuccessful plaintiff has acted as a factor in reducing the number of unmeritorious cases being commenced or otherwise prosecuted. Procedurally, the ability of defendants, in some cases, to require plaintiffs to post security for costs or be exposed to increased cost sanctions following formal offers have also been very useful tools in managing actions for defendants.

The absence of cost consequences creates, in effect, a “free-option” to plaintiffs in commencing an action. It is undeniable that without facing cost sanctions, plaintiffs are more readily able to commence and maintain actions against defendants. The ability of a plaintiff to obtain indemnification for costs by a third party who was otherwise a stranger to the dispute defeats the important policy considerations of providing a costs sanction to unsuccessful litigants, and seems to be at odds with the intentions of the Alberta legislature which chose to retain the costs regime in the Class Proceedings Act.

Historically, the ability of a third party to fund a lawsuit has been prevented by virtue of the imposition of a public policy against a stranger funding or otherwise “stirring up” litigation. The tort of “maintenance” prevented an officious intermeddler – a stranger to the cause of action without any previous commercial connection – from inciting litigation. “Champerty” is a form of maintenance in which the stranger maintains an action in return for a payment conditional upon success in the lawsuit or based upon a percentage of recovery in the lawsuit.

The question of whether an arrangement to fund a lawsuit is champertous turns upon the specific circumstances of the case, and it is for the court to determine whether the stranger to the action is stirring up or inciting litigation. While the details of the agreement between BridgePoint and the plaintiff in this matter remain undisclosed, it is noteworthy that this action appears to have lain dormant for nearly eight years following its original filing on February 28, 2001, until very recently.

This decision in ATCO raises the concern that the express decision of the Alberta legislature to maintain the normal cost consequences in a class proceeding, rather than follow the lead of other provinces by setting up a no-costs regime, has been further eroded. While funding by a third party does not prevent a successful defendant from receiving its partial payment of costs following disposition of the matter, it does fail to address the very valid policy reasons behind making unsuccessful plaintiffs liable to pay for such costs directly. If the representative plaintiff is not exposed to cost consequences directly, then more marginal claims may be commenced and prosecuted. The decision further raises questions about the torts of maintenance and champerty and how those issues will be dealt with in Alberta.

Given that the Order was obtained on an ex-parte basis, it arguably has less precedential value. It will be interesting to see what the result would be if such an application was made on notice and in circumstances where the defendant was vigorously objecting to the relief claimed. We can expect that such an application will arise soon.

For more information, please contact:

Dalton McGrath 403-260-9654

or one of the following members of our national Class Actions Group:

MONTRÉAL Robert Torralbo 514-982-4014
TORONTO Nigel Campbell 416-863-2429
Jeff Galway 416-863-3859
Gordon McKee 416-863-3884
Joel Richler 416-863-2735
Mary Jane Stitt 416-863-2940
CALGARY Webster Macdonald 403-260-9604
VANCOUVER David Neave 604-631-3338
James Sullivan 604-631-3358



Caroline McGrath & Ted Betts

Does a severe downturn in the economy constitute an event of force majeure? If you can no longer get financing because banks do not have the money to lend, can you claim force majeure because events are beyond your control? Even Donald Trump is attempting to claim that a "once-in-a-century credit tsunami" is enough to establish an event of force majeure that would allow him to avoid a $40-million personal guarantee related to unit sales for the Trump International Hotel in Chicago. If the contract allows it, parties are generally relieved from their contractual obligations as a result of force majeure events beyond their reasonable control. But do Canadian courts support such a claim when it comes to economic events beyond their control? Not surprisingly, it depends almost entirely on the actual drafting of the contract provisions.

EXPRESS ECONOMIC FORCE MAJEURE
While "economic force majeure", or force majeure based on the state of the economy or relevant markets, is not widely addressed by the courts, judicial commentary has not ruled out its potential application. In situations where the force majeure clause in a contract expressly provides for a specific economic contingency or loss which has occurred (such as a direct reference to material or adverse changes in market conditions), the courts have accepted this as an event of force majeure. The requirements to establish such an event were enunciated by the Supreme Court of Canada in Atlantic Paper Stock Ltd. v. Anne-Nackawic Pulp & Paper Company Limited (Atlantic Paper):

  • one of the events referenced in the force majeure clause has occurred;

  • the force majeure event was beyond the control of either party, it was "unexpected" and "beyond reasonable foresight and skill";

  • the event prevented, hindered, or delayed the party seeking to rely upon the clause from performing its contractual obligations; and

  • there were no reasonable steps that could have been taken to avoid or mitigate the event or its consequences.

Beyond the Control of Either Party
The issue of control is a central determination in the court’s application of an express economic reference in a force majeure clause to the facts before it. The force majeure clause will not be construed to cover events brought about by a party’s negligence or willful default. This was a central consideration in the Supreme Court’s rejection of a claim to economic force majeure in Atlantic Paper in spite of an express reference in the contract to the "non-availability of markets" as a grounds for establishing force majeure. The court’s ruling was, however, directed by the factual determination that the "non-availability of markets" was caused by poor marketing and ill-informed business planning, actions specifically within the claimant’s control.

In West Fraser Mills Ltd. v. Crown Zellerbach Canada Ltd., the British Columbia Court of Appeal was asked to apply an "economic clause" (construed to be a force majeure clause) which specifically referenced "market conditions" as an event that would excuse performance under the contract. It was found that the decline in sales volume experienced by Crown Zellerbach was due to an industry-wide decline. Therefore they had no control over the market forces and could rely upon the "economic clause".

Prevented, Hindered or Delayed
A causal link between the decrease in demand and the inability to perform under the contract must also be established. In order to demonstrate "prevention" of performance, there must be evidence that the party was legally or physically prevented from performing, not merely that performance was made more difficult or unprofitable. Claiming that necessary financing was unobtainable because interest rates had suddenly jumped, for example, will not be considered to have prevented or made it impossible for financing to be obtained; the much higher interest rate merely makes financing unprofitable or uneconomic (Tom Jones & Sons Ltd. and the Queen (ON H.C.J.)). A determination of whether a party was effectively "prevented" will, however, be interpreted in light of the particular contract. For example, the case of Atcor Ltd. v. Continental Energy Marketing Ltd. (AB C.A.) (Atcor) suggests that the burden on the party invoking force majeure is not impossibility of performance and that "commercial reasonableness" of performance is an appropriate factor for the courts to consider.

Mitigation
In order to establish force majeure, evidence would further need to establish the impossibility of avoiding or mitigating the effects of the alleged force majeure event. In situations of an economic force majeure, the courts have modified "impossibility of avoiding" to require the demonstration that there was no "commercially reasonable alternative" open to the party seeking relief from the contractual obligations. For example, in a situation where a supplier in a chain of suppliers is "prevented" from performance by reason of a force majeure, it has been held that they are not liable under the contract even though they could have mitigated a force majeure event by purchasing the deliverable elsewhere and, in so doing, fulfilled the contract. It has also been held, however, that force majeure will not excuse a bad bargain – where the party’s reliance upon force majeure would be to relieve it of contractual obligation simply because it could not operate at a profit.

Unforeseeable
The party must also demonstrate that conditions have radically changed from what they were at the time the contract was entered into. This speaks not only to the magnitude of the force majeure event itself but also to its foreseeability. The Atcor case provides some guidance on "reasonable" expectations in this regard. Here the court suggested that the event need not be a catastrophe or "act of God", but just something not present in sound business calculations, which amounted, in the court’s determination, to a list of events for which insurance is not available at a reasonable cost. As such, the force majeure economic event must be shown to be beyond the general volatility of the market and to be such an unprecedented, sudden and extreme loss or impediment that it could not be seen to be a normal (case- and industry-specific) risk that would be allocated through the contract.

PRACTICE POINTS
There has yet to be a Canadian decision where the court decided the issue on the basis of an economic force majeure, absent an express provision for economic events in the force majeure clause itself. Notwithstanding the foregoing, the depth of the current economic downturn and the impact it is having on business in Canada could see an increase in interest in the force majeure clause and the effect of its inclusion in a contract.

For a claim of economic force majeure to be successful, the affected party will need to demonstrate that the impact of changes in the economy were beyond its control, the economic change prevented contractual performance, it had no reasonable ability to mitigate and the economic change was not reasonably foreseeable. More importantly, the party attempting to rely on force majeure will have to demonstrate that the terms of the contract allow it. To say the least, the burden is high, but in these economic times perhaps there is a greater chance of success for a claim of economic force majeure.

The success or failure of such a claim will depend primarily on the terms of the contract. Counsel are well advised to consider boilerplate force majeure clauses very carefully.

For further information, please contact any member of our Business Group.




Selina Lee-Andersen

INTRODUCTION
Since the Obama administration has come into office, the energy and climate change files have remained top priorities despite the economic crisis. This is clear from President Obama's address to the Joint Session of Congress on February 24, 2009: "It begins with energy. We know the country that harnesses the power of clean, renewable energy will lead the 21st century ... to truly transform our economy, protect our security, and save our planet from the ravages of climate change, we need to ultimately make clean, renewable energy the profitable kind of energy."

The United States took a bold step forward in the energy and climate discourse with the introduction on March 31, 2009 of the draft American Clean Energy and Security Act of 2009, also known as the Waxman-Markey bill. The 648-page draft bill requires U.S. greenhouse gas (GHG) emissions to be reduced 20% from 2005 levels by 2020, which is more ambitious than President Obama's call for a 14% reduction of GHG emissions by 2020. By 2050, the draft bill requires GHG emissions to be reduced by 80% from 2005 levels. The draft legislation addresses a number of issues including renewable energy, carbon capture technologies, low-carbon transportation, smart electricity grids, energy efficiency, emissions trading and green jobs. However, it does not address the thorny issue of how to allocate emission allowances to carbon-intensive industries under a future cap-and-trade system. It is anticipated that the issue of allocating emission allowances will be addressed when the draft bill is reviewed by the Energy and Commerce Committee, which is expected to complete its review by late May 2009.

Canadian industry, as well as both federal and provincial levels of government, have been watching climate change developments in the U.S with great interest. In recent months, the federal government made overtures to the Obama administration for a North American-wide cap-and-trade system. This represents a shift in policy for the federal government, given that Canada's emissions trading system as currently envisioned is intensity-based – a cap-and-trade approach necessarily means stricter targets. While the federal government and Obama administration have agreed to work together on developing clean energy technology, the Americans have shown little interest in developing a North American cap-and-trade system. This article will highlight some of the key provisions of the draft bill and will consider the potential impact of this legislation on Canadian industry, particularly on the energy sector and other companies that export goods to the U.S.

USCAP BLUEPRINT FOR LEGISLATIVE ACTION
The Waxman-Markey bill draws heavily from recommendations contained in the Blueprint for Legislative Action (the Blueprint), which was released by the United States Climate Action Partnership (USCAP) in January 2009. Founded in 2007, USCAP represents a coalition of industry and environmental groups. USCAP members include national environmental groups and over 30 leading corporations covering a broad range of industries including manufacturing, utilities, chemical production and automakers.

The Blueprint was two years in the making and sets out a framework for developing comprehensive legislation to address climate change and to facilitate the transition to a low-carbon economy. USCAP has been calling on Congress and the Obama administration to pass a cap-and-trade bill as soon as possible.

HIGHLIGHTS OF THE WAXMAN-MARKEY BILL
The draft bill has four titles: (i) clean energy; (ii) energy efficiency; (iii) reducing global warming pollution; and (iv) transitioning to a clean energy economy.

Title I – Clean Energy
This section is designed to promote renewable sources of energy, carbon capture and sequestration (CCS) technologies and clean transportation:

  • Renewable Energy – Retail electricity suppliers would be required to meet a certain percentage of their load with electricity from renewable sources.

  • CCS – Incentives would be provided for the wide-scale deployment of CCS technologies.

  • Clean Transportation – A new low-carbon transportation fuel standard would be established to promote clean transportation fuels and infrastructure for hybrid and electric vehicles. Under the draft bill, refineries would be required to reduce the annual life cycle emissions from their fuels to 2005 levels between 2014 and 2022, and then reduce them by at least another 5% between 2023 and 2030. Beyond 2030, at least another 10% reduction would be required. A related provision would authorize financial assistance for car companies to retool their plants to build electric vehicles.

In addition, the draft legislation provides for the development of a smart grid and directs the Federal Energy Regulatory Commission (FERC) to provide for new transmission infrastructure to support electricity from renewable sources.

Title II – Energy Efficiency
This section is aimed at increasing energy efficiency across all sectors of the economy including industry, buildings, transportation and appliances:

  • Buildings – Funding for retrofitting existing residential and commercial buildings would be authorized.

  • Transportation Efficiency – The draft legislation calls for the harmonization of transportation standards and directs the EPA to set emissions standards for other mobile sources of pollution including locomotives and marine vessels.

  • Industrial Energy Efficiency – The Secretary of Energy would be required to establish standards for industrial energy efficiency. In addition, the draft bill would create a program to award innovation for increasing the efficiency of thermal electric generation processes.

Title III – Reducing Global Warming Pollution
This section amends the U.S. Clean Air Act and places limits on GHG emissions. The provisions under this section are based largely on USCAP's recommendations as set out in the Blueprint:

  • Global Warming Pollution Reduction Program – The draft bill proposes a market-based program for reducing GHG emissions from electric utilities, oil companies, large industrial sources and other regulated entities that are collectively responsible for 85% of GHG emissions in the U.S. Entities emitting more than 25,000 tons of carbon dioxide equivalent per year would be covered and those entities would be required to have tradable federal allowances for each ton of pollution emitted into the atmosphere. The proposed program reduces the number of allowances issued each year to ensure that aggregate emissions from regulated entities are reduced by 3% below 2005 levels in 2012, 20% below 2005 levels in 2020, 42% below 2005 levels in 2030 and 83% below 2005 levels in 2050.

  • Offsets – Regulated entities would be allowed to increase emissions above their allowances if they could obtain "offsets" at lower cost from other sources. The total quantity of offsets allowed in any year could not exceed two billion tons, split evenly between domestic and international offsets. Any regulated entities using offsets would be required to submit five tons of offset credits for every four tons of emissions being offset.

In addition, the draft legislation provides for unlimited banking of allowances for use during future compliance years and the establishment of a "strategic reserve" of approximately 2.5 billion allowances that will effectively create a cushion in case prices rise faster than expected. FERC would be responsible for regulating the cash market in emission allowances and offsets, while the regulation of the derivatives market would be delegated to an appropriate agency.

Title IV – Transitioning to a Clean Energy Economy
This section is designed to protect U.S. consumers and industry, while promoting "green" jobs during the transition to a clean energy economy:

  • Domestic Competitiveness – To ensure that U.S. manufacturers are not put at a disadvantage relative to overseas competitors, certain industrial sectors (i.e., energy-intensive sectors that produce commodities for global consumption) would be eligible for rebates to compensate for additional costs incurred under the Global Warming Pollution Reduction Program. If the rebate provisions are not sufficient to correct any competitive imbalances, a "border adjustment" program could be established that would require foreign manufacturers and importers to pay for special allowances to account for the carbon contained in U.S.-bound products.

  • Export of Clean Technology – The draft legislation contains provisions that will enable the U.S. to deploy clean technologies to developing countries that have ratified an international treaty and undertaken mitigation activities to achieve substantial GHG reductions.

ASSESSING THE POTENTIAL IMPACTS ON CANADIAN INDUSTRY
With the interests of so many industries at stake, there is no doubt that the stage is now set for an intense debate over the allocation of responsibility and costs for GHG reductions. This debate has potentially significant consequences for Canadian industry, particularly for those in the energy and manufacturing sectors. However, this legislation also represents potential opportunities for Canadian companies. These potential impacts can be described as follows:

  • restrictions on the type of fuels that can be exported the U.S. as a result of the low-carbon fuel standard;

  • additional costs to Canadian manufacturers and exporters as a consequence of the "rebate" and "border adjustment"

    provisions; and
  • potential opportunities for Canadian companies to export clean power clean technologies to the U.S.

According to the U.S. Department of Energy, Canada is a top exporter of petroleum products to the U.S. (in January 2009, Canada was cited as the largest exporter of petroleum to the U.S., having exported 2.544 million barrels per day to the U.S.). The low-carbon fuel standard in the draft bill is modelled after California's proposed low-carbon fuel standard, which takes into consideration the entire GHG life cycle of fuel. The notion of a GHG life cycle for fuel stands to have repercussions in Canada, particularly for fuel derived from the Alberta oil sands. This is because oil produced from oil sands emits between three and five times more GHGs than oil produced by conventional means. While the low-carbon fuel standard does not prohibit fuel from derived from the oil sands, it does act as a disincentive.

The "rebate" and "border adjustment" provisions in the draft bill to keep U.S. companies competitive will likely cause controversy by creating additional costs for Canadian manufacturers and exporters. Indeed, these measures may be seen as protectionist in nature. As companies look for ways to remain competitive, Canadian businesses will increasingly need to consider the carbon footprint of their products and services, particularly if they do business in the U.S.

The draft bill contains a number of measures to promote renewable energy and energy efficiency. This will create potential opportunities for Canadian companies to export electricity generated by renewable sources to the U.S. Canada is a major supplier of electricity to the U.S. and the two countries are becoming increasingly interconnected. For example, the Montana-Alberta Tie Line (MATL) is expected to come into service in mid-2010 and will connect the electricity markets of Alberta and Montana. MATL will support the development of wind energy in Alberta and Montana by providing additional transmission capacity for wind projects. Furthermore, Canadian companies with innovative technologies aimed at energy efficiency and clean transportation will have potentially significant opportunities to market their technologies to willing customers south of the border. Finally, the proposed cap-and-trade system will create opportunities for Canadian project proponents to generate offsets for sale to regulated entities that need to comply with emission reduction obligations.

MEETING THE GLOBAL CLIMATE CHALLENGE
President Obama has asked Congress to pass energy and climate change legislation before the end of 2009. The proposed cap-and-trade program plays a key role in the Obama administration's long-term deficit reduction goals as the program is anticipated to raise US$650-billion over the next 10 years through the sale of emission allowances. There is also pressure on the U.S. to pass climate change legislation before the next major international climate change conference scheduled to take place in Copenhagen in December 2009. Without the backing of Congress, it will be difficult for President Obama to sign a new international climate treaty to replace the Kyoto Protocol (which expires in 2012).

Certain issues could derail the draft bill's progress through Congress. One is the need for the Obama administration to focus on the economy in the near-term. This focus will likely overshadow climate change until 2010, meaning that Congress will not be interested in working out the finer details of a cap-and-trade system until the economy starts to recover. Also, there is concern that the targets are too low and that the legislation should aim for emission reductions of 80% below 1990 levels by 2050, as called for by the Intergovernmental Panel on Climate Change. Finally, the mechanism for allocating emission allowances under a cap-and-trade system will no doubt be intensely debated by various stakeholders. However, the agenda for energy and climate change issues continues to move forward and the Waxman-Markey bill is a sign of things to come. Stay tuned for more developments.

For further information, please contact:

Selina Lee-Andersen 604-631-3303

or any member of our Energy, Environmental or CleanTech Groups.




Sharon Wong, Kimberley Broome, Robert Fishlock & Michael Mercer

The much anticipated and heavily promoted Green Energy Act bill, was introduced to the Ontario legislature this week on February 23, 2009. The ambitious proposal, Bill 150 (the Bill), will create a new Green Energy Act and amend more than 15 existing statutes. The Bill proposes to create wide-reaching policies to establish an attractive investment climate for green power developers, provide certainty for the market, and make Ontario a leader in renewable energy and energy conservation in North America.

Unfortunately, the Bill leaves many open questions about how the government will implement its various proposals. The details are left for future regulations not yet drafted and, until such regulations are developed, the when and how of implementation will remain uncertain. Conceptually, though, the Bill suggests a very different future for renewable energy projects and energy conservation in Ontario.

According to the Honourable George Smitherman, Minister of Energy and Infrastructure, the Bill is based on two equally important thrusts:

  1. making it easier to develop renewable energy projects; and

  2. creating a culture of conservation where each of us uses less energy per capita each year.

The Ontario government believes that not only will the Bill create a welcome climate for investment, it will also be the seed to develop a projected 50,000 jobs in the next three years alone. The Minister of Energy believes that many of these new jobs will come from planned upgrades to the electricity transmission and distribution system which will then allow more renewable projects – primarily wind and solar – to be connected to the grid.

The changes which the Ontario Energy Board recently made to the Distribution System Code to make it easier for small generators to connect to the electricity grid (see our February 2009 Blakes Bulletin on Energy/CleanTech: Ontario Eases Rules for Connecting Small Generators to the Grid) foreshadowed proposals in the Bill to establish a "right to connect" to the electricity grid for renewable projects, and proposals to facilitate the modernization of the electricity distribution system to a "smart grid" system. Proposed amendments to the Electricity Act will allow the province to make regulations governing the implementation of the smart grid including in respect of the time-frame for the development of the smart grid, and assigning roles and responsibilities for its development.

One of the key provisions of the Bill is a proposal to direct the Ontario Power Authority to develop "a feed-in tariff program", a European-inspired model that would establish a government procurement process for energy from renewable sources, providing standard program rules, standard contracts and standard pricing for different classes of generation facilities differentiated by energy source or fuel type, generator capacity and the manner by which the generation facility is used, deployed, installed or located. The feed-in tariff program is expected to entice renewable energy proponents by providing a guaranteed market, and price and long-term revenue commitments under a streamlined process without incurring the costs associated with a formal RFP process. The revenue certainty, flexibility and improved efficiency of the process under the feed-in program is expected to facilitate and expedite the development and financing of many new renewable energy projects.

Evidently Ontario is looking to build on the success of the Renewable Energy Standard Offer Program (RESOP), launched two years ago, which aided smaller renewable energy projects by guaranteeing a price for renewable energy. Applications to the RESOP program exceeded government expectations, and the province has not been processing new applications (except for very small projects) since May 2008. The new feed-in tariff program to be developed may end up replacing the RESOP program.

The Bill also aims to improve certainty and efficiency in the approvals process. Changes to the Environmental Protection Act (EPA) will transfer renewable energy projects from existing environmental approval and permitting requirements, and instead these projects will be required to obtain a new comprehensive "renewable energy approval" from the Ministry of the Environment. It remains to be seen whether this new approval is processed more quickly than the existing array of individual air, waste and water taking approvals. However, the Minister has committed the government to do so.

Concurrently, broad sweeping amendments to the Planning Act will exempt renewable energy generation facilities and renewable energy projects from various by-law and permit requirements. The combined changes to the EPA and the Planning Act appear to upload the planning process with respect to renewable energy projects from municipalities to the Ministry of the Environment. For example, the plan appears to be for the Ministry of the Environment to issue standardized requirements (in regulations that have yet to be issued) for the location of wind turbines that will apply province-wide to replace the current situation where location is governed by individual municipal zoning requirements.

On the energy conservation front, section 2 of the new Green Energy Act will require all home owners and other real property owners to undertake mandatory conservation and energy efficiency practices, by providing certain information relating to energy consumption and efficiency, prior to selling or leasing real property. The information that will have to be provided in these energy audits will be set out in regulations to be released in the future.

The Bill will also elevate the importance of energy efficiency in the Building Code, and enhance energy efficiency standards for household appliances.

In addition, proposed changes to the Ontario Energy Board Act will require that board to have as an objective the promotion of conservation, facilitation of investment to a smart grid, and promotion of use and generation of electricity from renewable sources when utilizing its decision-making power in respect to the province's electricity system and also to be guided by the objective of promoting energy conservation and energy efficiency when carrying out its responsibilities in relation to the province's natural gas system.

Though the McGuinty government has stated its commitment to green energy, the proposal is not without controversy. Some claim the Bill is driven by the desire to eliminate the environmental approvals process for projects that would not otherwise go forward. Conversely, the proposal has support from many environmentalists because of the increase in availability and use of renewable energy, and the promotion of reducing consumption of energy in the province.

As the proposed Green Energy Act makes its way through the machinery of the legislature, it will be interesting to watch for opposition. If the Bill is enacted, of greater interest will be the numerous regulations that will flow from the new legislation. It is the regulations to come and how they are implemented by industry that will ultimately determine if the new Green Energy Act lives up to the government's pre-release hype and ends up being just what Ontario needs to make life green in the realm of energy, environment and economics.

The text of the proposed Bill is available at http://www.ontla.on.ca/bills/bills-files/39_Parliament/Session1/b150.pdf.

For additional information, please contact:

Sharon Wong 416-863-4178
Robert Fishlock 416-863-2904

or any member of Blakes Energy Group, Environmental Group or CleanTech Group.




Caroline Findlay & Roy Millen

On February 18, 2009, the B.C. Court of Appeal issued two decisions requiring the British Columbia Utilities Commission (the Commission), when making its decisions, to assess the adequacy of Crown consultation with First Nations. With the tremendous continuing growth in B.C.’s energy sector, including B.C. Hydro’s purchase of electricity from independent power producers and the projected expansion of transmission infrastructure, these decisions mark a significant shift in the regulatory regime applicable to many businesses operating in this arena.

In the past, the Commission has typically deferred the issue of aboriginal consultation undertaken by B.C. Hydro (as a regulated utility and the Crown) to other regulators, such as the Environmental Assessment Office. In both decisions, the Court of Appeal clearly held that the Commission has an obligation to determine if the duty to consult arises, the scope of this duty, and whether it has been fulfilled. This puts the Commission squarely in the role of adjudicator of aboriginal consultation and accommodation related to matters before it. This is a role which the Court of Appeal considers integral to upholding the honour of the Crown.

We set out below a brief outline of the facts of each case, an overview of the Court’s reasoning, and some thoughts on the potential ramifications of these decisions.

Carrier Sekani Tribal Council v. British Columbia (Utilities Commission)

The backdrop for this case revolves around the historical creation of the Kemano power station in the 1950s by Rio Tinto Alcan (Alcan) and a proposed expansion in the 1990s, often called the Kemano II project. In short, water is diverted from the Kemano River to produce electricity (originally for Alcan’s aluminum smelter in Kitimat) and discharged into the Nechako River; water-flows in the river systems were altered, with implications for fish and wildlife. Alcan was granted a water licence to use the flow.

The Carrier Sekani Tribal Council (the Tribal Council) consider the diversion of the water for Alcan’s use a historical and continuing infringement of their aboriginal rights and title – a claim also made by the Tribal Council in its pending aboriginal title litigation and within treaty negotiations.

In 2007, B.C. Hydro negotiated an Energy Purchase Agreement (EPA) with Alcan to buy surplus electricity from Alcan’s Kemano power station near Kitimat. Before the EPA could be enforceable, B.C. Hydro was required under section 71 of the Utilities Commission Act to apply to the Commission for a determination that the EPA is in the public interest.

The Tribal Council sought to make submissions before the Commission in this section 71 hearing about B.C. Hydro’s duty to consult, but the Commission rejected this request. In its motion to be heard before the Commission, the Tribal Council argued that in addition to new physical impacts, the EPA would affect their aboriginal interests in a number of ways, including that it authorizes sales of electricity resulting from diversions of water that causes existing impacts and infringements and makes management and operational decisions about this resource.

The Commission took the position that it had no role in assessing consultation issues. Further, the Commission reasoned that since the EPA had no new physical impacts on Tribal Council territory, any lack of Crown consultation regarding the historical (but continuing) impact was irrelevant to the Commission’s assessment of whether the EPA was in the public interest. This was the basis of the Tribal Council’s appeal and, as discussed below, these decisions were overturned by the Court of Appeal.

Kwikwetlem First Nation v. British Columbia (Utilities Commission)

In 2006, the British Columbia Transmission Corporation (BCTC) proposed to build a new 246-kilometre 500kV transmission line from Merritt to Coquitlam, called the “Interior to Lower Mainland Transmission Project”. BCTC pursued two key approvals for this Project in two separate regulatory contexts. First, it applied for an environmental assessment certificate under applicable environmental assessment laws (the EA process). Second, it applied to the Commission for a certificate of public convenience and necessity (the Certificate) pursuant to s. 45 of the Utilities Commission Act. At the core of this case are two different understandings about these two separate regulatory processes and their interplay.

As part of the Project planning for the EA process, in August 2006 B.C. Hydro (on behalf of BCTC) undertook initial consultation with about 60 First Nations that were identified as potentially impacted by the Project.

In November 2007, BCTC filed its application with the Commission for the Certificate. As a preliminary matter, the Commission established a “scoping process” for deciding whether it should consider the adequacy of consultation and accommodation efforts as part of its determination to grant the Certificate. The Commission sought submissions from BCTC, B.C. Hydro and interested First Nations. Four days before an oral hearing was scheduled involving all of the parties, including about six First Nations registered as interveners, the Commission cancelled the oral hearing because it had decided that it should not address consultation as part of its Certificate decision. Consistent with two prior decisions the Commission had made for similar projects, the Commission reasoned that the EA process created a reliable regulatory scheme as the means for considering whether the Crown had fulfilled its duty to consult for the Project.

Four First Nations appealed this scoping decision to the Court of Appeal, which, as discussed below, overturned the Commission’s ruling. In the interim, pending the Court of Appeal’s decision, the Commission proceeded with its review of the Certificate and granted it to BCTC in August 2008. The Certificate has not been appealed.

The Court of Appeal’s Reasons

While the cases are factually distinct, and consider applications under different parts of the Utilities Commission Act, the Court’s approach and findings in each case are virtually identical. In each case, the Court first considered whether the Commission has the jurisdiction and competency to assess the adequacy of the Crown’s consultation efforts before assessing whether the Commission’s decision to decline to assess the adequacy of those efforts in each situation was justifiable.

Does the Commission have the jurisdiction and competency to assess consultation and accommodation?
The Court of Appeal answered this question with an unequivocal “yes”. While observing that the Commission has previously demonstrated an “aversion” to assessing the adequacy of consultation and has a “disinclination to grapple with the issue”, it stated that the Court should settle this point. The Court found that the Commission is a quasi-judicial tribunal with authority to decide questions of law on applications before it. As such, the Commission has the jurisdiction and capacity to decide the constitutional questions of whether the duty to consult exists and, if so, whether that duty has been met.

The Commission and B.C. Hydro and BCTC had argued that “Aboriginal law is not in the steady diet” of the Commission. The Court drew on the reconciliatory purpose behind the Crown’s duty to consult, holding that there is no other forum that is more appropriate to decide consultation and accommodation issues in a timely and effective manner.

Did the Commission make the wrong decision in declining to assess the adequacy of consultation?
Again, the Court answered “yes”.

In Carrier Sekani, the Court held that the Commission had erred by dismissing the Tribal Council’s arguments around inadequate consultation as a preliminary matter without allowing those arguments to be heard on their merits. The Court did not hold that the Commission was bound to find that a duty to consult was triggered on these facts, but that the Commission had erred by refusing to entertain argument as to the duty to consult in the context of a section 71 hearing.

Likewise, in Kwikwetlem, the Court held that the Commission was not entitled to rely on the issue of consultation being dealt with in a parallel EA process. The Court observed that the granting of a Certificate under section 45 of the Act is the “first important decision in the process of constructing a power line” and has an effect on the character and scope of potential infringements of asserted First Nations’ rights. Again, the Court held that the Commission was not bound to find that consultation efforts had been lacking but, up to that point, that it “is required to assess those efforts to determine whether the Crown’s honour was maintained in its dealing with First Nations regarding the potential effects of the proposed project.”

A critical point to each decision was the Court’s finding that the “Crown’s obligation to First Nations requires interactive consultation and, where necessary, accommodation, at every stage of a Crown activity that has the potential to affect their Aboriginal interests.” As such, the Commission could not deny its jurisdiction nor rely on a parallel or future process to assess the adequacy of the Crown’s efforts to consult and accommodate.

What is the appropriate remedy where the Commission fails to consider consultation?
In each case, the Court ordered the Commission to reopen its process and reconsider the adequacy of the Crown’s consultation efforts with respect to the applications under sections 71 and 45 of the Act, respectively. These re-hearings will undoubtedly create some delay for these two specific projects.

Conclusions

These cases highlight the policy considerations around the appropriate role and responsibility of the Commission in dealing with the evolving dynamics of energy growth and diversification in B.C. and the participation of First Nations. In particular, the Court of Appeal sees the Commission as having an integral role to assessing the adequacy of aboriginal consultation and accommodation. The Commission cannot avoid this role by refusing to hear submissions from First Nations, choose to limit its public interest mandate to exclude these considerations or rely on another regulatory process, such as the EA process, to address aboriginal consultation and accommodation.

The immediate effect of this decision is that – barring an appeal of this decision to the Supreme Court of Canada or a significant legislative amendment expressly limiting the Commission’s jurisdiction to consider the adequacy of consultation – proceedings before the Commission will now necessarily involve a consideration of the Crown’s duty to consult with First Nations in regards to the matter or project being considered by the Commission.

For further information, please contact:

Caroline Findlay 604-631-3333
Roy Millen 604-631-4220

or a member of our Aboriginal Group or Energy Group.




Sébastien Vilder and Aude Godfroy

On November 12, 2008, two decrees were published in the Gazette Officielle du Québec enacting two regulations on two separate 250 MW blocks of wind energy, one earmarked for aboriginal projects and the other earmarked for community projects. Two additional decrees relating to the economic, social and environmental concerns communicated to the Régie de l’énergie concerning these two calls for tenders were published on the same date.

On January 14, 2009, a decree was published in the Gazette Officielle du Québec enacting a regulation amending the Regulation respecting energy produced by biomass cogeneration.

REGULATIONS RESPECTING TWO SEPARATE 250 MW BLOCKS OF WIND ENERGY

Hydro-Quebec Distribution is expected to launch the call for tenders no later than February 25, 2009. The wind farms will have to be operational by the following dates: i) 50 MW, no later than December 1, 2012; ii) 100 MW, no later than December 1, 2013; and iii) 100 MW, no later than December 1, 2014. In addition, Hydro-Quebec Distribution has already announced certain wind measurement requirements for the bidders.

On February 9, 2009, Hydro-Quebec Distribution submitted the grid with respect to the weighting of the non-monetary criteria which would apply to both community projects and aboriginal projects for approval to the Régie de l’énergie. It proposes to allot 30 points to the cost of electricity and 70 points for the non-monetary criteria, including: the feasibility of the project, the experience of the bidders, the financial capacity of the bidders, the regional and Quebec additional content, and sustainable development.

To ensure optimal development of the aboriginal and community projects, the regulations provide – in particular, for each of these calls for tenders – a maximum price of 9.5¢/kWh in 2008 dollars indexed to the Consumer Price Index, excluding the costs of transmission and balancing services and supplementary capacity.

Moreover, it is planned that various communities representing a minimum of 30% of the ownership interest in the relevant project will participate. Aboriginal nations – a minimum of 50% of control by the communities or their institutions for the duration of the project is required. Each aboriginal project is limited to a maximum of 25 MW. In addition, each aboriginal nation is limited to an aggregate of 50 MW. Beyond 50 MW, an aboriginal nation could accommodate one or more additional projects, subject to the involvement of at least one other aboriginal nation. Community projects – a minimum of 30% of the control of the project is required. It is not specified, as for aboriginal projects, that this minimum control is required for the duration of the project. Each community project is limited to a maximum of 25 MW and no more than 25 MW may be granted on the territory of a same regional county municipality (RCM).

The definition of “community wind project” remains as set out in the draft Regulation published on May 14, 2008. It should be noted, however, that it is specified that a co-operative – a component included in a local community – must have a majority of its members domiciled in the administrative region where the community project is located. Furthermore, a legally constituted group of individuals – also a component included in a local community – must be held and controlled by members or shareholders, the majority of whom are domiciled in the administrative region where the community project is located.

The requirement that no less than 60% of the total cost of each wind farm, including installation of the wind turbines, be realized in Quebec is maintained. Moreover, at least 30% of the total cost of a wind energy production equal to 250 MW, excluding installation of the wind turbines, must include manufacturing expenditures or investments incurred in the Matane RCM and in the administrative region of Gaspésie-Îles-de-la-Madeleine. It is specified that preferential treatment will be granted to projects for expenses incurred in the Matane RCM and the administrative region of Gaspésie-Îles-de-la-Madeleine which exceed the above-mentioned thresholds.

The assessment of economic impacts associated with aboriginal projects, shall take into account all stages of a project realization, i.e., the pre-feasability, the feasibility, the call for tender process, permitting and the construction until commissioning of the wind park. It should be noted that the operation, maintenance, dismantling and re-equipment of the wind farm, if necessary, are no longer mentioned for such assessment.

REGULATION AMENDING REGULATION RESPECTING ENERGY PRODUCED BY BIOMASS COGENERATION

The Regulation respecting energy produced by biomass cogeneration enacted by decree no. 916-2008 dated September 24, 2008 was amended by decree no. 9-2009 dated January 7, 2009 in order to extend the time period granted to the electric power distributor to proceed with a call for tenders.

The Regulation respecting energy produced by biomass cogeneration provides for an energy block produced in Quebec by new biomass cogeneration facilities equal to a total of 125 MW. A minimum of 75% of biomass is required to be used as fuel by the new facilities for the production of electricity. Article 3 of such Regulation provided that the launching of the call for tenders was to take place no later than January 6, 2009 and the projects resulting from this call for tenders were to be carried out so that deliveries would begin no later than December 1, 2012. The amending Regulation extends the launching date for the call for tenders to before April 15, 2009. The postponement will allow the electric power distributor to, among other things, adequately prepare the tender documentation and maximize the quality of the bids received in connection with such call for tenders.

For further information, please contact:

Alain Massicotte 514-982-4007
Angelo Noce 514-982-4062
Sébastien Vilder 514-982-5080
Aude Godfroy 514-982-5086

or a member of our Energy Group.


Michael McCachen

Introduction and Background
On June 4, 2007, the Alberta Energy and Utilities Board (EUB) initiated an inquiry into the natural gas liquids (NGL) extraction business in Alberta (the Inquiry). Participation in the Inquiry was very broad including natural gas producers, pipeline owners and their customers, industry associations, owners of NGL straddle plants and fractionation facilities, petrochemical producers and governments, including the State of Alaska. The proceedings were extensive spanning 2007 and 2008. The main focus of the Inquiry was whether the existing convention for the extraction of natural gas liquids (NGLs) was equitable and in the best interests of the industry and the province.

Natural gas produced and delivered into the Alberta transportation system (the Alberta System) operated by NOVA Gas Transmission Ltd. (NGTL) is primarily methane but also often contains heavier hydrocarbons consisting of ethane, propane, butanes, pentanes and other molecules, all of which are referred to as NGLs. Extracted NGLs, when burned independently or used in a petrochemical process, have a higher energy value than methane and often attract a premium price even in excess of their thermal advantage over methane; this advantage is sometimes referred to as the liquid’s “uplift value”.

In the current regime, most natural gas producers sell their gas under the NOVA Inventory Transfer (NIT) trading system operated by NGTL which compensates gas sellers for the energy content of gas they deliver onto the Alberta System. In recent times, however, some market participants, especially producers, had begun to raise the concern that the NIT price does not fully recognize the uplift value that NGLs can attract.

On the NGTL Alberta System, the two most common types of transportation service are “receipt shippers” who deliver gas onto the pipeline at various receipt points throughout the province, and “delivery shippers” who own capacity to take gas off the system at Alberta border points. Much of the existing infrastructure for extraction of NGLs exists within “straddle plants” situated at or near the border points where the NGTL Alberta System leaves the province. As the Alberta NGL convention evolved over time, it had become the case that the delivery shippers contracted with the straddle plants for the value of NGLs extracted from the gas stream before it left Alberta. Although some of the upstream receipt shippers do engage in field extraction, the majority of the NGL extraction takes place at the straddle plants. Effectively, then, the NGL Inquiry was a contest between those who preferred the status quo (primarily the delivery shippers and the straddle plants), and the receipt shippers, concerning who should obtain the uplift value of NGLs extracted in the Alberta straddle plants.

Constitutional Issue
Prior to the conclusion of the evidence being presented at the Inquiry, NGTL publicly announced its decision to seek a ruling that the Alberta System operated by NGTL should properly be under the jurisdiction of the National Energy Board rather than the provincial regulators in Alberta. Given that a significant aspect of the NGL Inquiry was to consider, and potentially change, the methodologies employed by NGTL relevant to the NGL extraction business, this announcement by NGTL led to challenges by some parties over the jurisdiction of the EUB to complete the Inquiry. The challenges were primarily brought forward by those opposing any change to the Alberta NGL extraction convention. Following a jurisdictional hearing by the EUB, as well as certain proceedings before the Alberta Court of Appeal, it was determined that the EUB had jurisdiction to complete the Inquiry and to issue recommendations for change to the Alberta NGL extraction regime.

The EUB Decision
Citing earlier EUB Decisions, the Board concluded, in part, as follows:

… [R]esource ownership should remain with the producer of the resource until the producer relinquishes ownership through a commercial contract. NGL are part of the natural gas resource produced from wells, and thus in the Board’s view, the producers of natural gas have the right to the NGL entrained in the gas they produce until such time as they contract that entitlement to another party. Under the Current Convention, only an export delivery shipper has an entitlement to contract with respect to the extraction rights associated with gas being transported on the NGTL System.

...[P]roducers/receipt shippers do not have an opportunity under the Current Convention to realize an incremental value for extraction rights or to separately contract for the disposition of their proportionate entitlement to the NGL components of the Common Stream if they wish to sell their gas in the intra-Alberta market.

The “NEXT Model”
In the course of the Inquiry, NGTL had proposed a “receipt point convention”, referred to as the “NEXT Model”, which would monitor deliveries of NGLs onto the system at the upstream receipt point and compensate receipt shippers for their proportion of the total NGLs delivered onto the system using the Alberta reference price for NGLs. (The Alberta Reference Price is that which is used by the Alberta government for purposes of determining royalties on the specific NGLs produced from Alberta gas wells.) The EUB accepted that the NEXT Model successfully addressed many of the inequities in the Current Convention and recommended that it be brought forward as part of the NGTL tariff within three years. The EUB also recommended that NGTL should discuss with its stakeholders measures to facilitate the development of take-in-kind rights under the NEXT Model as well as other implementation procedures. By way of further recommendation, the EUB also suggested that ATCO Pipelines and AltaGas Utilities work with their stakeholders on the appropriateness of extraction conventions on those pipelines. Significantly, and partly with a view to attracting Northern gas volumes (Alaska and Mackenzie Delta) to the Alberta trading hub, the Board recommended:

… [T]hat NGTL should take immediate steps to encourage the development of a competitive, transparent NGL extraction rights market.

The full Inquiry Decision is extensive and contains considerable background on such matters as the long-term energy outlook for the province of Alberta, guidelines for future development of extraction facilities in the province, comments on jurisdiction as well as a full discussion of the history and operation of the NGL business in Alberta. Copies of the Decision are available temporarily on the EUB website at http://www.auc.ab.ca/applications/decisions/Decisions/2009/EUB2009-009.pdf or through Blakes.

For further information, please contact any of the members of Blakes Energy Group.




Michael McCachen

Introduction and Background
On June 4, 2007, the Alberta Energy and Utilities Board (EUB) initiated an inquiry into the natural gas liquids (NGL) extraction business in Alberta (the Inquiry). Participation in the Inquiry was very broad including natural gas producers, pipeline owners and their customers, industry associations, owners of NGL straddle plants and fractionation facilities, petrochemical producers and governments, including the State of Alaska. The proceedings were extensive spanning 2007 and 2008. The main focus of the Inquiry was whether the existing convention for the extraction of natural gas liquids (NGLs) was equitable and in the best interests of the industry and the province.

Natural gas produced and delivered into the Alberta transportation system (the Alberta System) operated by NOVA Gas Transmission Ltd. (NGTL) is primarily methane but also often contains heavier hydrocarbons consisting of ethane, propane, butanes, pentanes and other molecules, all of which are referred to as NGLs. Extracted NGLs, when burned independently or used in a petrochemical process, have a higher energy value than methane and often attract a premium price even in excess of their thermal advantage over methane; this advantage is sometimes referred to as the liquid’s "uplift value".

In the current regime, most natural gas producers sell their gas under the NOVA Inventory Transfer (NIT) trading system operated by NGTL which compensates gas sellers for the energy content of gas they deliver onto the Alberta System. In recent times, however, some market participants, especially producers, had begun to raise the concern that the NIT price does not fully recognize the uplift value that NGLs can attract.

On the NGTL Alberta System, the two most common types of transportation service are "receipt shippers" who deliver gas onto the pipeline at various receipt points throughout the province, and "delivery shippers" who own capacity to take gas off the system at Alberta border points. Much of the existing infrastructure for extraction of NGLs exists within "straddle plants" situated at or near the border points where the NGTL Alberta System leaves the province. As the Alberta NGL convention evolved over time, it had become the case that the delivery shippers contracted with the straddle plants for the value of NGLs extracted from the gas stream before it left Alberta. Although some of the upstream receipt shippers do engage in field extraction, the majority of the NGL extraction takes place at the straddle plants. Effectively, then, the NGL Inquiry was a contest between those who preferred the status quo (primarily the delivery shippers and the straddle plants), and the receipt shippers, concerning who should obtain the uplift value of NGLs extracted in the Alberta straddle plants.

Constitutional Issue
Prior to the conclusion of the evidence being presented at the Inquiry, NGTL publicly announced its decision to seek a ruling that the Alberta System operated by NGTL should properly be under the jurisdiction of the National Energy Board rather than the provincial regulators in Alberta. Given that a significant aspect of the NGL Inquiry was to consider, and potentially change, the methodologies employed by NGTL relevant to the NGL extraction business, this announcement by NGTL led to challenges by some parties over the jurisdiction of the EUB to complete the Inquiry. The challenges were primarily brought forward by those opposing any change to the Alberta NGL extraction convention. Following a jurisdictional hearing by the EUB, as well as certain proceedings before the Alberta Court of Appeal, it was determined that the EUB had jurisdiction to complete the Inquiry and to issue recommendations for change to the Alberta NGL extraction regime.

The EUB Decision
Citing earlier EUB Decisions, the Board concluded, in part, as follows:

… [R]esource ownership should remain with the producer of the resource until the producer relinquishes ownership through a commercial contract. NGL are part of the natural gas resource produced from wells, and thus in the Board’s view, the producers of natural gas have the right to the NGL entrained in the gas they produce until such time as they contract that entitlement to another party. Under the Current Convention, only an export delivery shipper has an entitlement to contract with respect to the extraction rights associated with gas being transported on the NGTL System.



...[P]roducers/receipt shippers do not have an opportunity under the Current Convention to realize an incremental value for extraction rights or to separately contract for the disposition of their proportionate entitlement to the NGL components of the Common Stream if they wish to sell their gas in the intra-Alberta market.

The "NEXT Model"
In the course of the Inquiry, NGTL had proposed a "receipt point convention", referred to as the "NEXT Model", which would monitor deliveries of NGLs onto the system at the upstream receipt point and compensate receipt shippers for their proportion of the total NGLs delivered onto the system using the Alberta reference price for NGLs. (The Alberta Reference Price is that which is used by the Alberta government for purposes of determining royalties on the specific NGLs produced from Alberta gas wells.) The EUB accepted that the NEXT Model successfully addressed many of the inequities in the Current Convention and recommended that it be brought forward as part of the NGTL tariff within three years. The EUB also recommended that NGTL should discuss with its stakeholders measures to facilitate the development of take-in-kind rights under the NEXT Model as well as other implementation procedures. By way of further recommendation, the EUB also suggested that ATCO Pipelines and AltaGas Utilities work with their stakeholders on the appropriateness of extraction conventions on those pipelines. Significantly, and partly with a view to attracting Northern gas volumes (Alaska and Mackenzie Delta) to the Alberta trading hub, the Board recommended:

… [T]hat NGTL should take immediate steps to encourage the development of a competitive, transparent NGL extraction rights market.

The full Inquiry Decision is extensive and contains considerable background on such matters as the long-term energy outlook for the province of Alberta, guidelines for future development of extraction facilities in the province, comments on jurisdiction as well as a full discussion of the history and operation of the NGL business in Alberta. Copies of the Decision are available temporarily on the EUB website at http://www.auc.ab.ca/applications/decisions/Decisions/2009/EUB2009-009.pdf or through Blakes.

For further information, please contact any of the members of Blakes Energy Group.




With numerous spending initiatives released in the days leading up to the January 27, 2009 federal budget (the Budget), many wondered whether the tabling of the Budget itself would be anti-climactic. The dollar amount of such measures and the impact of this cost on the government's finances will undoubtedly attract the lion's share of attention in coming days. However, the Budget did contain a few significant and positive tax proposals.

INTERNATIONAL MEASURES

a) Repeal of Section 18.2
Perhaps the most significant corporate tax proposal contained in the Budget was the repeal of the so-called "Anti-Tax Haven Initiative" in section 18.2 of the Income Tax Act (Canada) (the Tax Act) before it becomes effective in 2012.

Originally intended to have much broader application, this controversial provision attracted much criticism even after enactment in a much more limited form. As enacted, section 18.2 was applicable to certain types of "double-dip" structures used by Canadian companies to finance their foreign subsidiaries. The provision challenged a longstanding principle that permits the deduction of interest on funds borrowed to invest in shares of a foreign company. The Advisory Panel on Canada's System of International Taxation (the Advisory Panel), in its Report released in December 2008, joined many organizations in urging the repeal of this provision. This recommendation was made, in part, because it was felt that section 18.2 would put Canadian companies at a competitive disadvantage to their foreign competitors.

There is no indication in the Budget documents as to whether the Department of Finance will introduce any proposals in the future aimed at dealing with double-dip financings.

b) Foreign Investment Entity (FIE) and Non-Resident Trust (NRT) Proposals
First introduced a decade ago, the FIE and NRT proposals have had almost as tortured and a much longer history than section 18.2. The ultimate fate of these proposals, however, remains an open question as the Budget documents indicate that they will be reviewed in light of the many submissions received concerning their complexity, uncertainty and breadth. The Advisory Panel, in recommending that the FIE and NRT proposals be reconsidered, noted the issues surrounding the integration of these proposals with the foreign affiliate rules.

c) Outstanding Foreign Affiliate Proposals
The Advisory Panel's recommendations included some far-reaching suggestions relating to the treatment of income from foreign affiliates, as well as capital gains on the disposition of shares of foreign affiliates. The Budget documents announced that the government will consider the Advisory Panel's recommendations before proceeding with the existing backlog of foreign affiliate amendments, originally proposed in 2004 but not yet enacted. While this is a welcome development, it means additional uncertainty in this area.

Without a doubt, the people in the Department of Finance dealing with these proposals, and the NRT and FIE proposals, have a busy year ahead.

d) Other Recommendations of the Advisory Panel
The Budget states that other recommendations of the Advisory Panel are being studied. These recommendations were described in our December
2008 Blakes Bulletin on Tax: Changing the Borders – Report of Canadian Advisory Panel on International Taxation and included recommendations to amend the thin-capitalization rules that limit deduction by corporations of interest on debt owing to significant shareholders and modifying withholding tax procedures on certain payments made to non-residents in respect of services rendered in Canada on sales of property. Recommendations to amend the thin-capitalization rules would have such rules apply to Canadian branches of foreign corporations and would reduce the debt-to-equity ratio used in the determination of thin-capitalization from 2.0:1 to 1.5:1.

CORPORATE MEASURES

a) Acquisition of Control – ‘La Survivance' Legislatively Overturned
The Budget proposes an amendment to subsection 256(9) of the Tax Act, which generally deems an acquisition of control of a corporation to occur at the commencement of the day on which such control is actually acquired. It is proposed that this deeming provision not apply for purposes of determining if a corporation is, at any time, a "small business corporation" or a "Canadian-controlled private corporation" (a CCPC).

The purpose of this amendment is to address unintended effects that can result from the strict interpretation of the rule in subsection 256(9) endorsed by the Federal Court of Appeal in La Survivance v. R. The interpretation accepted in that decision meant that where control of a corporation that would otherwise be a small business corporation and a CCPC is deemed to have been acquired by a non-resident at the commencement of the day, but the actual sale giving rise to the acquisition of control does not occur until later in the day, the corporation would not be a small business corporation or a CCPC at the time of the sale. This would affect the vendor's eligibility for the lifetime capital gains exemption under section 110.6 of the Tax Act in respect of the sale or the classification of a capital loss realized on the sale as an allowable business investment loss.

The proposed amendment to subsection 256(9) is intended to prevent this result by ensuring that the deeming rule therein does not affect the status of a corporation as a CCPC or a small business corporation at the time of sale.

The proposed amendment will apply retroactively in respect of acquisitions of control that occur after 2005, except for acquisitions that occur before January 28, 2009 in respect of which the taxpayer elects, or is deemed to have elected, on or before the taxpayer's filing due date for the 2009 taxation year that this new measure will not apply. A taxpayer who has relied upon the interpretation endorsed in La Survivance in filing a tax return, a notice of objection or an appeal will be deemed to have made this election.

b) Capital Cost Allowance Measures
The Budget proposes a temporary 100% capital cost allowance (CCA) rate applicable to new computer hardware and systems software generally described in Class 50 and acquired after January 27, 2009 and before February 1, 2011. The "half-year rule" which generally limits the amount of CCA that may be claimed in the year of acquisition will not be applicable to such purchases. Certain conditions relating to the use of such property in Canada must be met, and the Budget documents indicate that the computer tax shelter rules will be applicable to computer equipment eligible for this 100% CCA rate.

The acquisition of qualifying equipment used primarily in manufacturing and processing in Canada is currently eligible for a 50% CCA rate on a straight-line basis. This temporary measure, originally proposed in the 2007 Budget and extended in 2008, was set to expire at the end of 2009 and be replaced by a 50% rate applicable on a declining balance basis for 2010 and 2011. (Proposed regulatory amendments to implement the original 2007 proposal were introduced in February 2008, but have not yet been enacted.) The Budget proposes extending the 50% CCA rate on a straight line basis for 2010 and 2011. However, the half-year rule will be applicable on such measure.

Finally, the Department of Finance will be consulting with stakeholders with a view to providing accelerated CCA treatment to qualifying property used in carbon capture and storage. The Budget documents do not set out when such an initiative may be expected to be put in place.

c) Small Business Deduction
The Budget increases the base amount of active business income of a CCPC eligible for the small business deduction under subsection 125(1) of the Tax Act (the small business limit) from C$400,000 to C$500,000 as of January 1, 2009. The increase to the small business limit will be pro-rated for corporations with taxation years that do not coincide with the calendar year.

A CCPC's eligibility for the small business deduction will continue to be reduced on a straight-line basis for corporations with taxable capital employed in Canada between C$10-million and C$15-million.

Hopefully the provinces will follow suit and increase provincial small business limits.

d) Mandatory Electronic Filing
Corporate Income Tax Returns
The Budget also includes procedural amendments to the Tax Act which will require corporations that meet certain prescribed conditions to file their tax returns electronically. The proposed amendments in the Budget do not include a detailed description of the conditions that will apply, but indicate that the electronic filing requirements will apply to corporations with annual gross revenues in excess of C$1-million for a taxation year. Exceptions may be made available by the Canada Revenue Agency for certain qualifying corporations such as non-resident corporations, insurance corporations and corporations filing in a functional currency.

The new electronic filing requirements for corporate tax returns will apply for taxation years ending after 2009. The Budget also introduces a penalty, applicable for taxation years ending after 2010, for taxpayers who fail to comply with the new requirement. The amount of the penalty is C$250 for taxation years ending in 2011, C$500 for taxation years ending in 2012, and C$1,000 for taxation years ending after 2012.

Information Returns
In keeping with the objective of improving efficiency through increased electronic filing, the threshold number of information returns required for mandatory electronic filing will be reduced from 500 to 50.

A new graduated penalty structure for failure to file information returns on time or in the correct form is also proposed. The maximum penalties under the proposed structure will be determined using fixed brackets based on the number of returns required to be filed. This would be a welcome change from the current regime, which imposes penalties on a per-failure basis and can therefore result in excessive penalties where a large number of information returns is involved.

These measures will apply to information returns required to be filed after 2009.

PERSONAL TAX MEASURES

a) Tax Brackets and Personal Amounts
The Budget proposes increasing the two lowest personal tax brackets and the basic personal amount by 7.5% from their 2008 levels. The ceiling for the first personal income tax bracket (taxed at a 15% federal rate) will be raised from the 2008 level of C$37,885 to C$40,726 for 2009. The ceiling for the second bracket, in which income is taxable at a 22% federal rate, will be raised from its 2008 level of C$75,769 to C$81,452 for 2009.

The basic personal amount, the spousal and common-law partner amount and the eligible dependant amount will all be increased from their 2008 levels of C$9,600 to C$10,320 in 2009.

These increased thresholds and amounts will be indexed for inflation for 2010 and subsequent years.

b) Mineral Exploration Tax Credit
The mineral exploration tax credit, which is currently scheduled to expire at the end of March 2009, allows individuals who have invested in qualifying flow-through shares to obtain a tax credit equal to 15% of specified mineral exploration expenses incurred in Canada by the issuer of the shares and renounced to such investors. The Budget proposes extending its eligibility by one year, to flow-through share agreements entered on or before March 31, 2010.

c) Housing Related Measures
Home Renovation Tax Credit
The Budget introduces a new limited duration 15% non-refundable tax credit (the HRTC), which will be available in respect of "eligible expenditures" made in respect of an "eligible dwelling" (generally, a dwelling that is eligible to be an individual's principal residence). The HRTC will apply to expenditures in excess of C$1,000, but not more than C$10,000, resulting in a maximum credit of C$1,350 (C$9,000 x 15%). This limit will apply to the pooled expenditures of each family unit, generally consisting of an individual, the individual's spouse or common-law partner, and their children who were, throughout 2009, under 18 years of age.

Eligible expenditures for purposes of the HRTC are generally defined as expenditures incurred in relation to a renovation or alteration of an eligible dwelling that are of an enduring nature and are integral to the eligible dwelling. Routine repair costs and similar expenditures will be excluded.

The HRTC will apply only to the 2009 taxation year and only in respect of eligible expenditures for work performed or goods acquired after January 27, 2009 and before February 1, 2010. The credit will not be available in respect of expenditures made pursuant to an agreement entered into before January 28, 2009. The Budget estimates that the HRTC will cost C$500-million in 2008-2009 and C$2.5-billion in 2009-2010.

Home Buyers' Plan
The Budget proposes to increase the amount that first-time home buyers may withdraw from an RRSP to purchase or build a home without paying tax on the withdrawal from C$20,000 to C$25,000. This increase will apply to 2009 and subsequent years in respect of withdrawals made after January 27, 2009.

First-Time Home Buyers' Tax Credit
In addition to the enhancement to the Home Buyers' Plan described above, the Budget also introduces a new non-refundable tax credit equal to 15% of qualifying costs associated with purchasing a "qualifying home", such as legal fees, disbursements and land transfer taxes (up to a maximum credit of C$750 or C$5,000 of qualifying costs) where the closing of the purchase occurs after January 27, 2009.

A qualifying home is one that is eligible for the Home Buyers' Plan that the individual or the individual's spouse or common-law partner intends to occupy as their principal place of residence not later than one year after its acquisition.

RRSP/RRIF Withdrawals After Death
The Tax Act generally requires the fair market value of the investments in a taxpayer's RRSP and RRIF at the time of his or her death to be included in the taxpayer's income for the year of death. Any reduction in value of the RRSP or RRIF investments on the disposition or distribution of such investments by the estate of the deceased taxpayer cannot currently be carried back and applied to the income of the deceased taxpayer in the year ending with his or her death. The Budget proposes allowing such post-death decreases to be carried back against the deceased taxpayer's year-of-death RRSP/RRIF income inclusion. This measure will apply in respect of deceased annuitants where the final distribution from the RRSP/RRIF occurs after 2008.

For further information, please contact any member of our Tax Group.

Montréal Jean Gagnon 514-982-5025 jean.gagnon@blakes.com
John Leopardi 514-982-5030 john.leopardi@blakes.com
Toronto Bryan Bailey 416-863-2297 bryan.bailey@blakes.com
Janice McCart 416-863-2669 janice.mccart@blakes.com
Kathleen Penny 416-863-3898 kathleen.penny@blakes.com
Ron Richler 416-863-3854 ron.richler@blakes.com
Paul Stepak 416-863-2457 paul.stepak@blakes.com
Paul Tamaki 416-863-2697 paul.tamaki@blakes.com
Jeffrey Trossman 416-863-4290 jeffrey.trossman@blakes.com
Chris Van Loan 416-863-2687 chris.vanloan@blakes.com
Calgary Ron Mar 403-260-9704 ron.mar@blakes.co
Edward Rowe 403-260-9798 edward.rowe@blakes.com
Wanda Rumball 403-260-9794 wanda.rumball@blakes.com
Wally Shaw 403-260-9766 wally.shaw@blakes.com
Vancouver Robert Kopstein 604-631-3317 robert.kopstein@blakes.com
Bill Maclagan 604-631-3336 wsm@blakes.com
Janette Pantry 604-631-4163 janette.pantry@blakes.com
Bruce Sinclair 604-631-3382 bruce.sinclair@blakes.com
Kevin Zimka 604-631-3363 kevin.zimka@blakes.com



Paul Cassidy & Selina Lee-Andersen

In October 2008, the B.C. Ministry of Environment (the Ministry) issued a policy paper (Intentions Paper) to outline its intention to introduce a Mandatory Reporting of Greenhouse Gas Emissions Regulation (GHG Reporting Regulation) in 2009. The purpose of the GHG Reporting Regulation is to enable the Ministry to track progress towards future greenhouse gas (GHG) targets. The main provisions of the Intentions Paper are drawn from the Western Climate Initiative’s Draft Essential Requirements for Mandatory Reporting Document (WCI Reporting Document), which was originally released in July 2008. The comment period for the Intentions Paper ended on November 28, 2008.

The proposed regulation, to be established under the Greenhouse Gas Reduction (Cap and Trade) Act, will specify the GHGs subject to reporting, the level of emissions requiring reporting, facilities required to report, quantification methods to be used in reporting, requirements and procedures for annual reporting, verification/audit mechanisms, and compliance obligations. The regulation is expected to come into effect in early 2009. To ensure your organization is prepared for any potential new reporting obligations, a thorough review of the Intentions Paper is recommended. The earlier you determine whether the proposed regulation will affect your operations, the more time your organization will have to prepare for these new reporting requirements. This article will outline the key provisions of the Intentions Paper and highlight some of the issues arising from the Intentions Paper.

OVERVIEW OF KEY PROVISIONS
The following are the key provisions of the proposed GHG Reporting Regulation:

  • Facilities in B.C. that will be subject to reporting and/or cap-and-trade compliance obligations (Reporting Facilities) include: aluminium; base metals smelting; cement; chemicals and petrochemicals; cogeneration and biomass generation; commercial facilities; food production and manufacturing; thermal electrical generation and import; electricity transmission; food production and manufacturing; lime; mining; pipeline transportation; natural gas transmission and distribution systems; non-metallic mineral products manufacturing; petroleum refining; pulp and paper; upstream oil and gas; wood products manufacturing; and other stationary combustion fugitive sources or industrial processes releasing GHGs.

  • Certain emission source categories will be exempt from the initial phase of mandatory reporting, including: forestry; non-combustion landfill emissions; non-combustion municipal and wastewater emissions; air and marine transportation; on-road and out of facility off-road transportation; petroleum products terminal fuel throughput; natural gas, propane and home heating oil delivered for consumer use; and hydroelectric facilities.

  • Reporting Facilities emitting more than 10,000 tonnes of carbon dioxide equivalent (CO2e) will be required to register and report their GHG emissions to the Ministry beginning with the 2009 calendar year and annually thereafter.

  • Reporting Facilities with emissions over 20,000 tonnes of CO2e will also be required to provide their best estimates of GHG emissions by source category for the 2006, 2007 and 2008 calendar years.

  • Reporting Facilities with emissions over 25,000 tonnes of CO2e in any calendar year from 2009 onwards will be required to report for all subsequent calendar years, regardless of emission level.

  • The GHG Reporting Regulation will include a separate threshold of 3,000 tonnes of CO2e per annum for “upstream oil and gas facilities”, which will be required to report for all subsequent calendar years if they have more than 3,000 tonnes of CO2e emissions from 2009 onwards.

  • For 2009 and subsequent emissions reporting years, the GHG Reporting Regulation will include or reference prescribed quantification methods for most source categories; WCI-approved quantification methodologies will be used wherever possible. Estimates for 2008 and prior calendar years will be made using the reporter’s choice of quantification methods.

  • The GHG Reporting Regulation will include provisions for verification of reporting information. It should be noted that facility operators who have submitted emission reports to the Ministry will be required to have verification documentation prepared and submitted by an accredited third party verifier to review and substantiate the content of the emissions report. The Intentions Paper does not specify the criteria by which third party verifiers will be accredited, but notes that verifiers will be accredited by “a recognized accreditation body, such as the Standards Council of Canada.”

  • Reporting information will be submitted electronically to the Ministry. The Ministry intends to use electronic reporting templates compatible with WCI jurisdictions and Environment Canada practices.

  • A statement of verification will be required within five months of the delivery date of the 2010 and 2011 emissions reports and within one month of submission of the annual report for 2012 and subsequent calendar years. No verification will be required for any reports in respect of the 2006, 2007, 2008 and 2009 calendar years.

  • Under the proposed GHG Reporting Regulation, reporting facilities will be required to retain all GHG reporting documents and records for a minimum of seven years.

  • Potential penalties for non-compliance may include written warnings, requests for further information, investigations, directives, administrative penalties and/or prosecutions. The Ministry is still considering the point at which enforcement action will be taken for items such as failure to submit a report or failure to use an approved quantification methodology.

  • The Greenhouse Gas Reduction (Cap and Trade) Act sets out the offence provisions relevant to the GHG Reporting Regulation. For example, failure to submit emissions reports could result in a fine of up to C$1-million, imprisonment for up to six months or both.

Milestone Dates
Under the proposed GHG Reporting Regulation, the following milestone dates have been established:

  • July 15, 2009 – all facility operators who reasonably expect to be subject to the reporting regulation for 2009 will be required to register with the Ministry by this date.

  • August 30, 2009 – for facilities with emissions over 20,000 tonnes of CO2e, initial best available data on emissions will be required to be submitted to the Ministry by this date.

  • June 15, 2010 – data for 2009 will have to be submitted by this date.

  • April 1 – for subsequent years, reporting information will be required to be submitted by April 1 of the year following the reporting calendar year for electricity generation and facilities with only stationary combustion sources; for all other source categories, reporting would be required by May 1 of the year following the reporting calendar year.

The GHG Reporting Regulation will allow the Ministry to grant an extension for the submission of emissions report, given a suitable reason.

Based on existing emissions information, the Ministry estimates that under the proposed GHG Reporting Regulation, 80 to 100 facilities will have reporting, allowance holding and third verification obligations while another 160 to 180 facilities will have reporting, but not allowance holding or third party verification obligations.

ISSUES TO CONSIDER

Low Reporting Threshold
As noted above, facilities emitting more than 10,000 tonnes of CO2e per year will be required to report their GHG emissions to the Ministry beginning with the 2009 calendar year. There is concern among some in the business community that the reporting threshold of 10,000 tonnes per year is too low and will place an undue burden on small and medium-sized firms in B.C. which may lack the resources to meet emissions reporting obligations. To facilitate the implementation of the GHG Reporting Regulation, the Ministry should identify those firms that will potentially be affected by the proposed regulation and implement outreach initiatives to ensure that those firms are aware of their reporting obligations.

With the end of 2008 quickly approaching, the timeline for implementing the GHG reporting program is extremely short. It is advisable for facilities that will be potentially affected by this proposed regulation (i) to confirm whether the new GHG Reporting Regulation will apply to their operations, and (ii) to implement a GHG reporting program if necessary.

Administrative Efficiency
The key to any effective reporting system is administrative simplicity. The provisions of the GHG Reporting Regulation are consistent with the parameters set out in the WCI Reporting Document, which will allow for increased administrative efficiency among WCI jurisdictions. However it will be important for B.C.’s GHG reporting system to be harmonized with the federal reporting system. Furthermore, the efficiency of the reporting process can be enhanced by providing access to a single-window reporting system, particularly since a number of affected facilities are already required to comply with federal reporting requirements. This will help to minimize costs and reduce overlap. The harmonization of reporting systems will lessen the burden on facilities to measure, monitor and report differently under separate programs.

Reporting Process
All Reporting Facilities emitting more than 10,000 tonnes of CO2e per year will be required to register and report such emissions to the Ministry. Under the Intentions Paper, the administrative burden of registering facilities and reporting emissions falls on the facilities themselves, which represents an additional cost to them. To minimize the administrative burden and costs of meeting reporting obligations, the GHG reporting format should be compatible with those used in other WCI jurisdictions or by Environment Canada. In Alberta, for example, GHG reporting is carried out using a single-window reporting system administered by Statistics Canada. Specifically, large industrial facilities in Alberta report their emissions through the Electronic Data Reporting System (EDRS), which information is provided to Alberta Environment and Environment Canada. The EDRS allows the federal government to collaborate with the provinces and territories to develop an efficient harmonized, single-window domestic reporting system for GHG emissions.

Quantification Methods
The Ministry’s commitment to using WCI-approved quantification methodologies for source categories is commendable. To ensure the accurate reporting of emissions, quantification methodologies should be consistent, transparent and equitable with respect to data input assumptions and calculations. Furthermore, there should be no variability in methodologies used by reporting facilities to ensure that, for the purposes of emissions trading under the WCI cap-and-trade system, the integrity of emissions allowances and offset credits is not compromised.

De Minimis Provisions
The Intentions Paper indicates that the Ministry is considering the use of de minimis emissions quantification methods in some source categories. The use of de minimis provisions, or specific exclusions for insignificant emission points, is an effective means to simplify the reporting process. This approach would be particularly beneficial to smaller emitters as it would reduce the complexities of reporting and lessen their administrative burden.

Verification
The proposed GHG Reporting Regulation will include provisions for third party verification of reporting information. These provisions will be applicable to facilities emitting more than 25,000 tonnes of CO2e per year. Under the proposed GHG Reporting Regulation, third party verifiers will need to be accredited by a recognized accreditation body such as the Standards Council of Canada. The Intentions Paper also indicates that verification service providers may be subject to a time-limited relationship with any single facility or company. For example, the same verification body would be unable to verify reporting data at a given company’s facilities for a period longer than six years. With a limited number of verification service providers in the current market, any limitations on accreditation or the relationship between verification service providers and reporting facilities will restrict the ability of companies to seek verification services. The Ministry should consider allowing other professionals, such as chartered accountants or professional engineers, to provide third party verification services. By allowing a larger pool of service providers, the verification services market will be more cost competitive and firms will have greater flexibility in choosing a third-party verifier.

FACILITATING AN EFFECTIVE IMPLEMENTATION

To facilitate the effective implementation of the Western Climate Initiative’s cap-and-trade system (planned for 2012), there is a need to accurately establish levels of GHG emissions in B.C. The implementation of the GHG Reporting Regulation is an important first step in capturing this information. As the GHG Reporting Regulation is anticipated to come into effect in early 2009, we recommend reviewing the Intentions Paper to assess whether the proposed regulation will apply to your operations and to ensure that your organization is not caught unprepared. In such a dynamic regulatory environment, organizational preparedness to meet new regulatory obligations is an effective tool for managing a company’s environmental risk.

For further information on this article , please contact:

Paul Cassidy 604-631-3390
Selina Lee-Andersen 604-631-3303

For information on our CleanTech Group, please contact any of the following members:
 
TORONTO Richard Corley 416-863-2183
Robert Fishlock 416-863-2904
Jonathan Kahn 416-863-3868
MONTRÉAL Sébastien Vilder 514-982-5080
CALGARY Matt Flynn 403-260-9693
VANCOUVER Paul Cassidy 604-631-3390



Sharon Wong

On May 16, 2008, the Ontario Divisional Court issued a decision which should be of great interest to companies involved in the distribution of natural gas and electricity who must obtain regulatory approval for their distribution rates.

The court held that the Ontario Energy Board (the OEB) does have the authority to set lower rates for the distribution of natural gas to low income consumers even though such a program would necessarily result in higher prices for the majority of residential consumers, and even though it would be a departure from the traditional model of rate making based on cost causality and cost of service.

Although the case related specifically to the Ontario Energy Board’s jurisdiction to set gas distribution rates, the court’s findings would likely apply equally to the Board’s jurisdiction to set electricity distribution and transmission rates in Ontario.

The case was brought on behalf of the Low Income Energy Network (LIEN). It started in August 2006 when Enbridge Gas Distribution (EGD) filed an application with the Board requesting a rate increase. LIEN proposed that the Board accept as an issue in the rates proceeding the following matter:

Should the residential rate schedules for EGD include a rate affordability assistance program for low-income consumers? If so, how should a program be funded? How should eligibility criteria be determined? How should levels of assistance be determined?

Several parties opposed the inclusion of the issue on the basis that the Board lacked jurisdiction to establish special rates for low income consumers.

In April 2007, the Board issued a split decision in which two out of three panel members held that the Board does not have the jurisdiction to establish rates based on rate affordability for low income consumers.

LIEN appealed to the Ontario Divisional Court. The Divisional Court decision was also a split decision, with two of the three judges reversing the Board’s decision and ruling that the Board does indeed have the jurisdiction to establish a rate affordability assistance program. The court, however, made it clear that even though the Board has the discretion to implement rates that favour low income consumers, the Board can refuse to establish such special rate classes when it exercises its discretion.

The Board’s jurisdiction to fix rates for the distribution of natural gas in Ontario is found in section 36 of the Ontario Energy Board Act, 1998 (the Act). Subsection 36(2) of the Act gives the Board the authority to fix “just and reasonable” rates for the distribution and transmission of natural gas, and subsection 36(3) of the Act states that in approving or fixing just and reasonable rates the Board may adopt “any method or technique that it considers appropriate”.

The court referred to the fact that the Board has traditionally set rates on a “cost of service” basis, that is, on the basis of cost causality and employing an approach which looks to the utility’s capital investments and maintenance costs including a fair rate of return to determine revenues required, with the revenue requirement then being divided amongst the utility’s rate paying consumers on a rate class basis (i.e., residential, commercial, industrial, etc.). Rates have been traditionally designed with the principled objective of having each rate class pay for the actual costs that class imposes upon the utility.

The previous legislation had required that the Board use the traditional cost of service analysis to determine rates, but that requirement was repealed when s. 36 of the current Act was enacted.

The court found that the Board could use the traditional cost causality approach to fix rates, but that “the Board need not stop there”. It held that the Board is authorized to employ “any method or technique that it considers appropriate” to fix “just and reasonable rates” within the context of the Board’s statutory defined objectives set forth in the Act.

One of the Board’s statutory objectives is protecting the interest of consumers with respect to prices. In this case, the objective of protecting “the interests of consumers” could mean taking into account income levels in pricing to achieve the delivery of affordable energy to low income consumers.

The Board’s jurisdiction to fix rates for the distribution and transmission of electricity is set out in s. 78 of the Act in exactly the same terms as are used in s. 36 of the Act in respect of the Board’s jurisdiction to set distribution and transmission rates for natural gas. Accordingly, electricity distribution companies may well find themselves facing similar arguments in the future from consumer advocacy groups seeking to obtain lower distribution rates for certain classes of low income or disadvantaged customers.

More generally, the LIEN decision is an important precedent for any party who may be seeking to have distribution or transmission rates set on a basis other than by the traditional method based on cost causality and cost of service. It may well be that in practice the Ontario Energy Board will exercise its discretion to depart from standard rate making principles only in exceptional circumstances, but the Divisional Court’s decision does establish that the Board has the jurisdiction to do so in appropriate circumstances, and those circumstances need not be limited to implementing rate relief for disadvantaged consumers.

The Board has several statutory objectives other than the protection of the interests of consumers with respect to prices, such as to facilitate the maintenance of a financially viable electricity industry and a financially viable gas industry for the transmission and distribution of gas, and it can be argued based on the LIEN decision that the Board has jurisdiction to depart from standard rate making principles in order to promote another of those objectives.

For information on this matter, please contact:

Sharon Wong 416-863-4178 sharon.wong@blakes.com

or any member of the Blakes Energy Group.




Bryan Duguid & Carol Hales (Articling Student)

The recent dawn of 2008 was quite likely met with justifiable anxiety by electricity market participants, wary of the monumentally increased penalties that might now be sought by the Market Surveillance Administrator (the MSA) under the new Alberta Utilities Commission Act (the AUCA). However, such concerns should be tempered, given that, at the very least, pre-existing investigations of the MSA will not be subject to the extreme penalty provisions of the AUCA.

Introduction

In Alberta, the MSA is to police electricity and natural gas markets, with a mandate to ensure a fair, efficient and openly competitive (FEOC) marketplace. To effect this mandate, the MSA has been given the authority to investigate and request sanctions against market participants for market behaviour that it perceives to be inappropriate.

When the AUCA was proclaimed into force on January 1, 2008, replacing parts of the Electric Utilities Act (the EUA), the role of the MSA largely remained the same, but the maximum monetary sanctions increased from C$100,000 per day to C$3 million per day. These penalties are in addition to various other sanctions that might be sought, as in the past, including disgorgement of profits and the imposition of terms and conditions on future conduct.

For any pre-existing MSA investigations, especially those investigations delayed or held in abeyance over a protracted period, the question that naturally arises is: "Can the MSA now seek the new, harsher penalties?"

The transitional provisions of the AUCA are entirely silent in relation to ongoing investigations of the MSA. Based on the protections afforded under s. 11 of the Canadian Charter of Rights and Freedoms (the Charter) and basic principles of statutory interpretation involving the presumption against the retroactive or retrospective application of statutes, market participants facing pre-existing investigations should expect the lesser maximum penalties to apply.

Section 11(i) of the Charter

Section 11(i) of the Charter provides that:

Any person charged with an offence has the right:

(i) if found guilty of the offence and if the punishment for the offence has been varied between the time of commission and the time of sentencing, to the benefit of the lesser punishment.

The protections afforded under this Charter right would allow any market participants that are currently the subject of an ongoing investigation by the MSA, to claim the benefit of the lesser maximum penalty provisions contained in the former version of the EUA. This conclusion is supported by a review of the elements of this Charter-protected right.

(a) “Any person”

The extreme administrative penalties and fines for offences under the AUCA might be directed at any person, defined in the EUA as including “an individual, unincorporated entity, partnership, association, corporation, trustee, executor, administrator or legal representative.” Individuals that face personal liability under these draconian measures would, without doubt, be afforded Charter protection.

While not all Charter rights extend to bodies corporate, corporations have been permitted to invoke rights to procedural fairness similar to those afforded by section 11(i) of the Charter, and are therefore entitled to the protection of the lesser maximum penalties previously set out in the EUA.

(b) “charged with an offence”

The issue of whether penalty provisions under a provincial regulatory scheme (rather than the Criminal Code) would attract Charter protection was decided by the Ontario Courts in McCutcheon v. Toronto (City). In that case, Justice Linden, citing from an earlier decision of the Ontario Court of Appeal, held that an “offence” would include any breach of law involving some penal sanction, whether the breach was contrary to a federal law, a provincial law, or otherwise.

Sanctions and penalties sought on a proceeding commenced under the AUCA would similarly constitute an “offence” for the purposes of s.11(i) of the Charter.

(c) “if the punishment for the offence”

Similar to the above issue, this question turns on the fact that the penalties envisioned under the AUCA are of a type or character that would attract Charter protection.

In R. v. Wigglesworth, the Supreme Court of Canada held that “a matter could fall within section 11 either because, by its very nature it is a criminal proceeding or because a conviction in respect of the offence may lead to a true penal consequence.” The Court also provided the definition of a "true penal consequence":

In my opinion, a true penal consequence which would attract the application of s.11 is imprisonment or a fine which by its magnitude would appear to be imposed for the purposes of redressing the wrong done to society at large rather than to the maintenance of internal discipline within the limited sphere of activity.

The Supreme Court of Canada reasoned that the recipient of payment of monetary sanctions may also be indicative of the general classification of the penalties. Fines that are to form part of the Consolidated Revenue Fund, for example, would suggest an intent to redress some public wrong.

Administrative penalties under the AUCA can be set at C$1 million per day, and fines for offences at C$3 million per day. One would be hard pressed to argue that these amounts would not fall within the “magnitude” envisioned by the Supreme Court of Canada in Wigglesworth. Further support for the conclusion that these monetary sanctions are a true penal consequence is found in the fact that the AUCA stipulates that payments of administrative penalties are to be made to the General Revenue Fund.

(d) “punishment for the offence has been varied”

Clearly the penalty provisions of the AUCA constitute a "varied” punishment, from that which existed previously.

The Presumption Against Retroactive or Retrospective Application

The common law presumption against retroactive or retrospective application of statutes also prohibits the MSA from seeking the new increased maximum penalties for conduct that occurred before the proclamation into force of the AUCA as of January 1, 2008.

In Benner v. Canada (Secretary of State), the Supreme Court of Canada provided the most consistently applied definition of the terms "retroactive" and "retrospective":

A retroactive statute is one that operates as of a time prior to its enactment. A retrospective statute is one that operates for the future only. It is prospective, but it imposes new results in respect of a past event. A retroactive statute operates backwards. A retrospective statute operates forwards, but it looks backwards in that it attaches new consequences for the future to an event that took place before the statute was enacted (...)

Both of these terms can be contrasted with a prospective statute, which would change the future effects of any future, ongoing or continuous situation. Prospective application is, of course, the normal effect of legislation.

As a general rule, there is a strong presumption against the retroactive application of legislation. Such applications are considered to be the most objectionable as they involve reaching into the past and declaring the law to be different from what it was, at an earlier date. The logic behind the strong presumption seems obvious enough – it is a serious violation of the rule of law and is inherently arbitrary for those who could not know the content of the law (as it would only apply after the amendment), when structuring their business or life plans.

Retrospective applications are often seen to be less offensive, as they involve changes for the future only. Leading academics on the issue of statutory interpretation have, however, opined that there should be at least a weak presumption against even retrospective application.

Whether the presumption in the case of the AUCA would be strong or weak is debatable; what is certain, however, is that a presumption would apply. And, having regard to the body of case law on this issue, there is no basis on which the presumption should be rebutted in these circumstances.

Conclusion

While the MSA may attempt to recommend the new, harsher penalties of the AUCA in proceedings brought in relation to its pre-existing investigations, a market participant whose impugned actions took place before the coming into force of the AUCA would be entitled to take the benefit of the lighter maximum penalty provisions of the former version of the EUA.

Further, it may well be that even a prospective application of the enormous penalty provisions of the AUCA would be unconstitutional and, thus, disallowed on certain bases including, among other things, the persisting vagueness and ambiguity surrounding the core benchmark of FEOC as an underlying source of liability.

The authors would like to extend a sincere thank you to Blakes Scholar-in-Residence, Peter W. Hogg, C.C., Q.C. for his invaluable counsel and advice in the preparation of this article.

Blakes would be pleased to answer any questions that you may have about the MSA, the penalty provisions under the AUCA, or the new legislation generally.

For further information about Blakes Energy Group practice, please click here.




  Next 25
MONTRÉAL   OTTAWA   TORONTO   CALGARY   VANCOUVER   NEW YORK   CHICAGO   LONDON   BAHRAIN   AL-KHOBAR*   BEIJING   SHANGHAI*
*Associated Office
Employee Access   Privacy and Copyright   Blake, Cassels & Graydon LLP