Canada: Energy @ Gowlings: June 1, 2010

Last Updated: June 7 2010

Edited by Paul Harricks


  • Nuclear Liability Back in the House
  • Nova Scotia's 2010 Renewable Electricity Plan: A Path to Good Jobs, Stable Prices and a Cleaner Environment
  • British Columbia Clean Energy Act - Bill 17 - Electrifying Change
  • LDC Corner: Tomayyto, tomahhto; Potayto, potahhto: Green Fees or Green Tax?
  • Royal Dutch Shell plc's Report on its Oil Sands Operations
  • JRP Conditionally Approves the MacKenzie Gas Project
  • Duty to Consult and Small Caribou Herds: West Moberly First Nations v. British Columbia (Chief Inspector of Mines) and First Coal Corporation

Nuclear Liability Back in the House
By: Terry McNally

Bill C-15, An Act respecting civil liability and compensation for damage in case of a nuclear incident, was tabled in the House of Commons on April 16, 2010 by the Honourable Christian Paradis, Minister of Natural Resources. A copy of Bill C-15 can be found at .

This is the Government's fourth effort to update Canada's nuclear liability regime by replacing the Nuclear Liability Act (the "NLA"), first enacted in 1976. Each of the prior attempts - Bill C-63, Bill C-5 and Bill C-20 – died on the order table when its Parliamentary Session ended. Two of the drafts (Bill C-5 and Bill C-20) were fully reviewed by the Standing Committee on Natural Resources and reported to the House with amendments. Given the scope of this prior review, it is unfortunate that Bill C-20 was not reinstated in this new Parliamentary Session, with debate commencing at the Reporting Stage. Doing so would have avoided the delays associated with First Reading, Second Reading and review by the Standing Committee. We can now anticipate a repetition of prior debate on the same issues raised by many of the same members of Parliament and Committee members, and a repetition of the contributions from many of the same witnesses who will come before the Committee.

On a more positive note, when Bill C-15 was reintroduced, the Government included all amendments to Bill C-20 recommended by the Standing Committee. See a summary of these recommended changes in an earlier article published in energy@gowlings: .

Bill C-15 re-establishes the NLA's fundamental nuclear liability principles of absolute liability, exclusive liability, and mandatory insurance and other financial instruments to secure the liability obligations of nuclear operators in the event of a nuclear incident. Bill C-15 includes four major enhancements: an increase in the limited liability of nuclear operators in the event of a nuclear incident from $75 million to $650 million; an expansion of the categories of nuclear damage covered by the liability obligations; an extension of the time limit for bringing a claim for compensation from 10 years to 30 years; and a clarification of the procedural arrangements for the claims tribunal that would hear nuclear damage claims.

The motion for Second Reading of Bill C-15 was debated in the House on May 13 and May 14. The three opposition parties are generally in support of legislation advancing Canada's nuclear liability regime towards current international standards. However, this early debate identifies the $650 million limited liability threshold as a significant hurdle for speedy passage of Bill C-15, with Liberal members now joining their NDP colleagues in questioning its sufficiency. We hope that, the Government will return Bill C-15 to the order table quickly and expedite the Parliamentary agenda for this proposed legislation which is much needed for Canada's nuclear community.

Nova Scotia's 2010 Renewable Electricity Plan: A Path to Good Jobs, Stable Prices and a Cleaner Environment
By: Peter Murphy and Lisa MacDonnell

In April of 2010 Nova Scotia released its Renewable Electricity Plan (the Plan), which sets out a detailed program to accelerate Nova Scotia's movement away from carbon-based electricity towards greener, more local sources (the Renewable Electricity Plan is available, online: ). The Plan is designed to increase renewable electricity supply, improve energy security, stabilize long-term electricity prices and create opportunities for jobs and investment. The Plan sets out the Province's goal that 25% of electricity generated in the Province will come from renewable sources by 2015, and that 40% of electricity will come from renewable sources by 2020. The 40% target is nearly four times higher than 2009 levels.

The Plan outlines an aggressive program to move Nova Scotia away from imported coal-based electricity towards local renewable sources, including wind and tidal resources. Achieving the goal of 40% renewable electricity by 2020 will cut the Province's coal consumption in half in just 10 years. The Plan sets forth certain actions which will be taken to achieve this transition:

  • Large and medium-sized renewable electricity projects will be split evenly between Nova Scotia Power Inc. (NSPI) and independent power producers. Nova Scotia's Utility and Review Board will evaluate and approve NSPI-sponsored projects in the traditional way. Independent producers will compete for projects in a bidding process managed by a new authority, the Renewable Electricity Administrator.
  • To encourage a range of projects widely dispersed throughout the province, the Plan establishes a community-based feed-in tariff (COMFIT) for an expected 100 MW of renewable electricity projects connected to the grid at the distribution level. The Plan also introduces a variety of programs to assist community groups in the technical, financial, and regulatory work needed to develop these projects.
  • To give individuals and small businesses the opportunity to participate in green energy projects, the Plan expands and enhances current net metering programs available to consumers through NSPI. Projects up to one MW, and connected to multiple meters within a single distribution, will be eligible to use two-way meters, and participants will receive payment at retail rates for any excess power they produce over a year.
  • The Province will be reviewing further development of biomass energy, tidal energy and solar energy as sources of renewable energy.
  • Further analysis will be conducted to determine if Nova Scotia's transmission system should be expanded by adding capacity within the Province and/or by adding additional interties with Nova Scotia's neighbours.
  • The Province will use its share of a multi-million dollar grant from the federal Clean Energy Fund to test smart grid technologies.

In the process of transitioning to a system that is cleaner, more diverse, more domestic and more secure, the Plan will support up to $1.5 billion in green investment and is expected to create jobs in construction, supply, manufacturing and maintenance, with opportunities in both urban and rural areas.

The 2010 Renewable Electricity Plan continues Nova Scotia's efforts to increase power generation and to decrease the Province's reliance on sources of energy from outside the Province and the country. While the Province appears on track to meet its 2015 target, significant investment is required for Nova Scotia to meet its 2020 goals. The new goal of 40% renewable electricity supplies by 2020 is aggressive and indicates the direction and sets the pace for Nova Scotia to take in its quest for secure, sustainable electricity supply.

British Columbia Clean Energy Act - Bill 17 - Electrifying Change
By: Henry Ellis

On April 28, 2010, the government of British Columbia tabled the Clean Energy Act (Act) in the legislature, representing a structural change in the electricity industry in British Columbia. Three goals of the Act are to create power self-sufficiency with low rates for domestic consumers, create job opportunities throughout British Columbia and demonstrate environmental stewardship. The Act details 16 specific energy objectives to meet its goals.

The Clean Energy Act includes provisions for energy efficiency and conservation, a smart power grid with smart meters, developing electricity for export, merging the British Columbia Transmission Corporation into British Columbia Hydro and Power Authority (BC Hydro), a reduction in the role of the British Columbia Utilities Commission (BCUC) as a regulator of hydro projects and a First Nations clean energy fund.

BC Hydro is tasked with reducing the expected demand for electricity by at least 66% by 2020 through conservation and energy efficiency rather than adding new capacity. The Province is also required to reduce greenhouse gas emissions by 33 1/3% less than the 2007 emissions by 2020. BC Hydro will continue to deliver on its Power Smart programs while the Clean Energy Act provides for smart meters with pricing options so that customers can time their usage with periods of lower rates.

The Clean Energy Act includes the export of electricity as an objective so that BC Hydro can secure export contracts and work in partnership with renewable power producers to sell clean, reliable energy to other provinces and into the United States without risk to B.C. ratepayers. BC Hydro will now have the ability to secure long-term export power agreements and then fill the agreements with clean power calls from independent renewable power projects.

The British Columbia Transmission Corporation was created in 2003 by splitting off BC Hydro's transmission capacity, but not the physical assets, into a separate corporation. This Act will reunite the two entities. On the day the Act was tabled, the government announced that it anticipates that the combination will take effect in July, 2010 with a single board chaired by Dan Doyle, the current chair of BC Hydro. On the same day, the government also announced the appointment of Dave Cobb as the Chief Executive Officer of BC Hydro.

The British Columbia Utilities Commission will continue to regulate BC Hydro's domestic supply and rates, the safety and reliability of the BC Hydro system, operating costs and service complaints from ratepayers. However, many projects will now be exempt from BCUC review, including the Northwest Transmission Line, Mica Units 5 and 6, Revelstoke Unit 6, Site C, BC Hydro's independent power producer power calls (Bioenergy Phase 2 Call, Integrated Power Offer, Clean Power Call and Standing Offer Program), the Feed-in Tariff and BC Hydro's Smart Metering and Smart Grid programs.

The Act also provides for the establishment of a First Nations Clean Energy Business Fund to enable First Nations investments and partnerships in renewable power products. The initial capital is anticipated to be funded from future water taxes paid by independent power producers. The details are to be determined after consultation with First Nations and industry.

BC Hydro will also be required to submit a long-term integrated resource plan to the government detailing how BC Hydro intends to implement the energy objectives set out in the Act.

LDC Corner: Tomayyto, tomahhto; Potayto, potahhto: Green Fees or Green Tax?
By: Bernadette Corpuz

Ontario Regulation 66/10, innocuously entitled "Assessments for Ministry of Energy and Infrastructure Conservation and Renewable Energy Program Costs", was recently introduced with little fanfare, but the proverbial dung is certainly hitting the fan.

Ontario Regulation 66/10 (the Special Purpose Regulation) was made under sections 26.1 and 26.2 of the Ontario Energy Board Act, 1998 (the Act), provisions added by the Green Energy and Green Economy Act, 2009. The Act requires the Ontario Energy Board (the Board) to assess licensed distributors and the Independent Electricity System Operator with respect to expenses incurred and expenditures made by the Ministry of Energy and Infrastructure for energy conservation programs or renewable energy programs. The Act sets out various "special purposes", such as programs aimed at lowering certain types of fuel consumption, for which the assessed amounts are collected.

The total amount to be assessed under the Special Purpose Regulation is just shy of $54 million. On April 9, the Board wrote to electricity distributors invoicing them for their respective share. An electricity distributor is permitted to recover this amount from its customers. On April 23rd, the Board wrote to electricity distributors authorizing the account to be used for the assessments made under the Special Purpose Regulation.

At about the same time, the C.D. Howe Institute (C.D. Howe) published a study challenging the constitutional validity of the Special Purpose Regulation. C.D. Howe notes that while government is permitted to use regulations which are not approved by the Legislature to set fees to recover the cost of goods and services that they provide to people being charged the fee, the government is not authorized to use a regulation to fund the general activities of government. C.D. Howe argues that the assessment under the Special Purpose Regulation is an indirect tax because it is collected from electricity distributors in proportion to their electricity sales, and that the amounts collected are not related to the cost of the respective goods sold. The study can be viewed at .

On April 26, 2010, the Consumers Council of Canada (the CCC) filed a motion before the Board challenging the authority of the Board to levy the assessments mandated under the Special Purpose Regulation. Among other things, the CCC has requested that the Board cancel the assessments issued under the Special Purpose Regulation and Act and determine whether the Board has jurisdiction to issued the assessments to distributors pursuant to unconstitutional legislation. At this stage, the Board is not inviting intervention other than response from the Attorney General of Canada, the Attorney General of Ontario and the Ontario Ministry of Energy and Infrastructure. The Board has assigned the file number EB-2010-0184 to the proceeding.

While CCC's written arguments are not required to be filed until May 31, it is expected that they will reflect the constitutional challenges raised by the C.D. Howe.

This proceeding will be watched carefully. Although the immediate question may focus on the constitutionality of the assessments, with respect to the question that really matters – Who will pay? – won't the answer ultimately be the same?

Royal Dutch Shell plc's Report on its Oil Sands Operations
By: Wilson McCutchan

Shell Canada Limited owns a 60% stake in the Athabasca Oil Sands Project (AOSP) mining operation, where it partners with Chevron and Marathon Oil. Shell also has producing wells on acreage covering in-situ oil sands reservoirs. In 2009, production from the Canadian oil sands accounted for close to 3% of the worldwide oil and gas production of Shell Canada's parent, Royal Dutch Shell plc, and Royal Dutch Shell expects that the percentage will increase over the next few years.

A large proportion of Shell Canada's long-term oil sands resources lies deep enough to require in-situ extraction, a relatively high energy and cost intensive process.

In preparation for Royal Dutch Shell's 2010 annual general meeting in the Hague this May, institutional investors in England raised concerns about the financial viability and the environmental and social impacts of the Canadian oil sands projects. They tabled a resolution requesting that Shell produce a report for its 2011 annual meeting regarding the risks associated with its oil sands projects. Investors tabled a similar resolution for BP plc.

The resolution asks that Shell lay out its assumptions about future carbon prices, oil price volatility, demand for oil, anticipated regulation of greenhouse gas emissions, and risks arising from environmental damage and impairment of traditional livelihoods.

Shell made an immediate response to the shareholder concerns on March 17, 2010, with a 17-page report stating the following:

  • 2009 compliance with the Regulation to Alberta's Climate Change & Emissions Management Act is expected to be between $US2 and 3 million. The Regulation expires on September 1, 2014;
  • Shell includes an expected price of CO2 in its economic assessments which is higher than the current CO2 price in Alberta, anticipating that potential future greenhouse gas regulation could lead to a higher CO2 price;
  • In terms of oil prices, Shell screens all of its projects, including oil sands projects, within the expected range of $US55-$90 per barrel;
  • Production from Shell's Athabasca Oil Sands project was roughly 78,000 barrels per day in 2009, but Shell expects that will increase to 150,000 barrels per day over the next few years. Its production through in-situ recovery was roughly 20,000 barrels per day in 2009. Shell expects its oil sands assets to produce for the next 40 years;
  • With respect to the environment, the report says that Shell does not return any process water to the Athabasca River, and that 85% of all water needs are met with recycled water. Furthermore, it seeks to reduce emissions through projects such as ShellEnhance, a high temperature froth treatment process, and has invested in R&D of carbon capture and storage through a project called Quest;
  • Shell is committed to starting a large-scale reclamation of mined areas within 20 years from the date of first land disturbance; and
  • Shell involves the Aboriginal Peoples in the environmental review of its wildlife, groundwater, surface water and aquatics monitoring programs prior to reporting to the provincial or federal governments.

The link to the resolutions and the report are:

JRP Conditionally Approves the MacKenzie Gas Project
By: Ethan Sinclair

The Joint Review Panel (JRP), an independent body appointed in 2004 to evaluate the environmental and social impacts of the MacKenzie Gas Project (the Project) has issued its report conditionally approving the Project, subject to the implementation of a large number of recommendations.

The Project

The Project is proposed by a partnership between Imperial Oil, Royal Dutch Shell, ConocoPhillips, ExxonMobil Corp and Aboriginal Pipeline Group (the APG) to transport natural gas from the MacKenzie Delta (near the Beaufort Sea) into Alberta. The APG was formed in 2000 to represent the ownership interest in the Project of the Aboriginal peoples of the Northwest Territories. The proposed pipeline will extend 1220 km from Inuvik into Alberta and is designed to transport as much as 1.2 billion cubic feet per day of gas, including reserves held or currently being explored for by third parties.

Approval is being sought for the proposed pipeline, the development of three natural gas fields in the Delta including a system of gathering pipelines and a processing facility, and new facilities in northwest Alberta including a connection to the NOVA Gas Transmission Ltd. system. The cost of the Project is estimated at some $16.2 billion.

The JRP's Recommendations

The JRP includes representatives of three bodies: the Mackenzie Valley Environmental Impact Review Board, the Inuvialuit (represented by the Inuvialuit Game Council) and the federal Minister of Environment. It released its Report on December 30, 2009 following 21 months of hearings in 26 northern communities. The JRP approved the Project subject to fulfillment of 176 recommendations with respect to: "cumulative impacts monitoring and management", "sustainability", "natural environment", "economy", "social and cultural environment", and "public confidence in government preparedness".

The discussion on sustainability touched on five key issues: 1) cumulative impacts on the biophysical environment; 2) cumulative impacts on the human environment; 3) equity impacts; 4) legacy and bridging; and 5) cumulative impacts management and preparedness. The impacts on the natural environment addressed by the JRP included: project design, construction and operations; migratory bird habitat; species at risk; woodland caribou; marine and aquatic environments; greenhouse gases; and conservation measures. With respect to economic impacts, the JRP addressed: procurement and business; employment and income; revenues to governments; and project legacy.

The Report throughout emphasizes the importance of measuring impacts cumulatively and continuously, and the importance of using the Project as means of improving the livelihoods of local people and promoting a sustainable future for the MacKenzie Valley and the Beaufort Delta. The JRP stressed that its approval was conditional on the full implementation of all 176 recommendations put forward in its Report.

Next Steps

The next step in the process is for the federal government and the Project proponents to respond to the JRP's report. The National Energy Board (the NEB), which has been holding separate hearings since January 2006, began hearing final arguments on April 12, 2010. It is expected to issue a final decision in September of this year. If the NEB determines that the Project is in the public interest, it will recommend to the Governor General-in-Council that a Certificate of Public Convenience and Necessity be issued, allowing the Project to go forward subject to the NEB's own terms and conditions.

Given the Project's price tag, the terms and conditions put in place by the government and regulators, and the apparently fragile economics of the Project (particularly in view of continuing low natural gas prices), it remains to be seen whether, and when, the Project proponents will wish to see the Project through.

Duty to Consult and Small Caribou Herds: West Moberly First Nations v. British Columbia (Chief Inspector of Mines) and First Coal Corporation
By: Roland Hung

In a recent decision, the Supreme Court of British Columbia ordered a stay of provincial exploration permits for 90 days and ordered the Crown, in consultation with the West Moberly First Nation (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 ordering the stay was that:

"... a balancing of treaty rights of Native peoples with 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 provides an example of a court reviewing whether the accommodation flowing from a consultation process was adequate for the purposes of meeting the "honour of the Crown". Generally speaking, the courts, in most cases, have been more focused on the process of consultation, rather than making determinations regarding the actual adequacy of the accommodation offered. This case also demonstrates how aboriginal law is influencing the shape of current environmental law, particularly the protection of species at risk.

Background on West Moberly's Application

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: (1) obtain bulk samples of coal, (2) conduct an advanced exploration program, and (3) clear trees to facilitate this exploration. West Moberly claimed that, in issuing these permits, the Crown had failed to consult adequately and meaningfully concerning their Treaty 8 right to hunt caribou, and had failed to reasonably accommodate their hunting rights.


a) Duty to Consult

All parties agreed that the Crown was required to consult and accommodate West Moberly on the basis of their treaty right to hunt, but the parties diverged on the nature and scope of that right.

The Court found that while the Crown did consult, the consultation was not meaningful and that proper accommodation did not occur. Factors which influenced this finding included the following: (1) the Crown was extremely slow to consult on its initial assessment of the potential adverse affects of proponent's activities on the First Nation's treaty rights; (2) the "standard form referral letters" did not address the real concerns of the First Nations regarding the threatened herd; and (3) the Crown failed to consider the First Nation's report on the danger to the herd and its relationship to the First Nation's protected treaty right.

(b) Treaty Right to Hunt and Reasonable Accommodation

The West Moberly also argued that reasonable accommodation requires the Crown to implement a rehabilitation plan for the Burnt Pine Herd of caribou, which lives in the area of First Coal's mineral tenure, and whose population has been reduced to 11.

Following the Supreme Court of Canada in Mikisew Cree First Nation v. Canada, in which the Supreme Court of Canada held that the meaningful right to hunt under Treaty 8 means a right to hunt within the particular First Nation's traditional territories, the Court rejected the Crown's argument that because the Burnt Pine Herd of Caribou was only a "minor part" of the hunting potential of the West Moberly, they could hunt caribou elsewhere.

(c) The Remedy and the Species at Risk Act

The Burnt Pine herd of Caribou 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).

The Court's remedy of an order to plan recovery and augmentation of the Burnt Pine herd has caused much debate among those within industry. The remedy mandates a specific action regarding a small portion of a listed species' population which seems to run counter to the national development of a holistic 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. Arguably, as well, 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.

The decision also raises some questions as to whether the broad federal population-level recovery plans made under SARA will insulate provincial permit-holders from allegations that the permitted activity would impose unreasonable impacts on asserted aboriginal and treaty rights.

The decision can be found at

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