Canadian Energy Law

BC's LNG priorities

Stikeman Elliott LLP — Fri, 14 Jun 2013 12:57:20 -0500

On June 8, 2013, British Columbia Premier Christy Clark announced the creation of a new Ministry of Natural Gas Development. Rich Coleman, one of her most experienced Ministers, was named as the first Minister of the new department. The extraordinary step – of creating a new Ministry tasked with delivering on the current preliminary plans for LNG Facilities in British Columbia - is just the latest and perhaps the most concrete example of the Government’s consistent commitment to promoting natural gas development in British Columbia, and to LNG in particular.

Since Premier Clark first took office, the Government has first re-formulated its energy policy through the publication of the Natural Gas Strategy in February 2012, accompanied by a specific LNG Strategy. That LNG Strategy was updated in February 2013, and coincided with a Throne Speech that gave pride of place to a vision of the future of LNG in British Columbia generally. The Throne Speech specifically articulated a target of having three major LNG Facilities operational by 2020, and also proposed to establish a BC Prosperity Fund designed to reduce or even eliminate BC’s public debt, improve its social services and/or make life more affordable for BC’s families.

The size and scope of the Government’s commitment to the LNG industry was clarified through background reports by reputable accounting firms, commissioned by the Province and also released in February 2013. Each report analysed certain long-term economic effects of developing up to five significant LNG Facilities in British Columbia. One report indicated, among other things, that Provincial revenues from the LNG sector over a 20 year period from 2018 to 2037, inclusive, could be in the range of $ 80 - $160 billion. The other report indicated that the aggregate capital costs for LNG Facilities could be close to $100 billion for the period from 2013 to 2021, inclusive.

Of course, these various estimates and/or assumptions could ultimately prove to be optimistic, but there are a number of credible syndicates currently proposing to develop major LNG Facilities in British Columbia, involving world-class participants such as Shell, Chevron/Apache, Petronas, and British Gas/Spectra. As the Government pointed out in the Throne Speech, over $6 billion has already been invested to acquire gas fields and/or related facilities to produce LNG for export. The Throne Speech also estimated that a further $1 billion had already been spent in connection with background work for the development of the various proposed LNG Facilities themselves.

Regardless of the credibility of the proponents or sponsors and regardless of the amount of sunk costs incurred to date, these various projects may not be completed on time or at all. But the commitment, the stakes and the ambition involved here are demonstrably huge. History may well judge the Premier's first full term on her Government's success or failure in facilitating delivery of some or all of these LNG Facilities. From her actions in forming a special Ministry, and putting one of her most experienced Ministers in charge, she appears to share that view.

"Publish What You Pay" - New Canadian transparency rules expected for mining and oil and gas companies

Stikeman Elliott LLP — Fri, 14 Jun 2013 08:37:16 -0500

Ivan T. Grbešić -

Prime Minister Stephen Harper announced on Wednesday June 12, that Canada is adopting a G8 initiative requiring disclosure of payments by Canadian mining and oil and gas companies to foreign and domestic governments. As a result of this G8 initiative, citizens in resource-rich countries are expected to gain access to information to combat any corruption in their extractive sectors and to demand additional accountability from their governments.

It is expected that the Canadian federal government will consult with the provinces and territories, First Nations and aboriginal groups, and industry and civil-society organizations in developing a framework and setting up a new reporting regime, which would be enforceable by law. Based on some unofficial preliminary estimates, it could take up to two years to implement the new regime. Details relating to how the new regime will be policed and by whom, disclosure methods and timing, and possible fines and other penalties for non-compliance will need to be determined.

The announcement is in line with developments in the industry, which has been working hard on improving transparency. The U.S. and the European Union have already adopted measures requiring extractive firms to report taxes, royalties, fees (including license fees), production entitlements, bonuses, and other material benefits to governments, with the U.S. rules taking effect recently and the EU’s directive not yet having been fully implemented.

In light of the developments, issuers should be aware that they will need to consider how their legal, audit and IT functions will need to adapt to the new regime once it is finalized and implemented. We will continue to monitor and update our clients on any developments relating to the new regime.

For more information, please contact the author of this article.

Supreme Court rules on the taxation of assumed obligations in asset purchase transactions

Stikeman Elliott LLP — Wed, 12 Jun 2013 12:50:21 -0500

Doug Richardson and Julie D’Avignon -

The Supreme Court of Canada recently released a decision which overturned previous court decisions and confirmed that the assumption of reforestation liabilities by a purchaser does not constitute additional sale proceeds to the vendor if the liabilities are embedded in the underlying timber rights. This decision is also of particular importance to other resource sectors, where purchasers typically assume reclamation and other obligations.

Background

The case of Daishowa-Marubeni International Ltd. v. The Queen involved a vendor (Daishowa) that sold a forestry division, which included timber rights that gave rise to certain reforestation obligations. The agreement set out a purchase price of $169,000,000 and the assumption by the purchaser of reforestation obligations of $11,000,000 (subject to adjustment based on a post-closing estimate). The lower courts had held that the purchaser’s assumption of the reforestation obligations constituted additional proceeds of disposition upon which the vendor was taxable, although the Tax Court had discounted that amount on account of the uncertain nature of the reforestation obligations.

The Court’s Decision and the Implications

The Court noted that the assumption of a vendor’s liability by a purchaser may give rise to additional proceeds to the vendor depending on the circumstances. However, the Court held, in a unanimous decision, that the reforestation obligations were a future cost embedded in the timber rights and depressed the value of the timber rights. The reforestation obligations were not a distinct liability and could not be severed from the timber rights. The Court considered the reforestation obligations to be more akin to repairs required on a building, rather than to a mortgage that is a separate existing liability that does not impact the value of the property. In support, the Court observed that commercially the vendor could not have received more than the agreed purchase price (i.e., $169 million minus the equipment and related assets) for the timber rights.

The Court indicated that it is irrelevant whether or not the parties agreed on an amount for the reforestation obligations. Further, the Court noted that its approach avoided the asymmetrical tax treatment where any additional sale proceeds arising due to the assumption of obligations would be taxable to the vendor but would not give rise to an increased cost basis in the property for the purchaser.

This decision was eagerly anticipated due to its potential impact on various resource sectors, where the assumption of obligations is part and parcel of the sale of properties. The finding that the reforestation obligations were embedded in the timber rights was based on applicable law and policy that effectively required the purchaser to assume the vendor’s reforestation obligations in order for the transfer to receive government approval as required by applicable legislation and to relieve the vendor of future liability for those obligations. The Court specifically left open the possibility that certain liabilities may be embedded in the property where the purchaser is not required by law or government policy to assume those liabilities on the transfer of the underlying property. This is relevant to other resource sectors where purchasers generally assume certain reclamation or other obligations, but where there may be different legislative schemes in place.

The Court noted that whether the reforestation obligations were “contingent liabilities”, which had been addressed by the lower courts, was also irrelevant. The assumption of the reforestation obligations was excluded from the purchase price due to the embedded nature of such liabilities and independent of whether the liabilities were absolute or contingent. However, various types of obligations are assumed by a purchaser in asset transactions. Whether an obligation assumed by a purchaser is contingent may be relevant for assumed obligations that are not as clearly tied to a particular asset, such as pension, severance and tort obligations. The considerations for those types of assumed obligations will also likely be different as the parties may not agree to an estimate of those obligations.

Four reasons why Quebec should resurrect Hydro-Québec International

Stikeman Elliott LLP — Wed, 05 Jun 2013 09:58:09 -0500

Erik Richer La Flèche -

Quebec’s efforts in the energy sector are guided by its energy policy. The current policy covers 2006 to 2015. Quebec is putting its final touches on the next reiteration to be released fall 2013. A consultative process will follow.

Early indications are that the government is thinking of resurrecting Hydro-Québec International (HQI), the former wholly-owned subsidiary of Hydro-Québec.

This is an excellent idea.

Quebec’s electricity sector represents more than 5% of its GDP and is anchored by Hydro-Québec, a large vertically integrated stated-owned utility. During the 1980s and 1990s HQI was active on the world stage, first as a complement to the international activities of Quebec’s engineering sector, and then as a full-fledged developer, owner and operator of production and transmission facilities, primarily in emerging markets.

In the late 1990s and early 2000s Quebec, bowing to ratepayer pressure concerned about HQI’s impact on domestic electricity prices, ordered Hydro-Québec to concentrate its activities in Quebec. As a result HQI (profitably) sold its overseas investments and curtailed its foreign activities, with the exception of course of those activities directly linked to U.S. power exports.

There are four reasons why Hydro-Québec should resurrect HQI, both as a technical adviser and an investor and operator:

Brand: Hydro-Québec has a very good brand at home and abroad. By world standards it is well run and large. It is profitable and a recognized leader in a number of areas, including transmission and hydro-electricity (98% of HQ’s production is from hydro). Also, the fact that it is state-owned is an important plus in many markets. Local authorities often prefer to deal with a public-sector entity rather than one from the private sector.
Talent: Quebec, in large part thanks to Hydro-Québec, has the requisite technical, managerial, financial and legal skills and experience to design, finance, build, operate and maintain electricity assets abroad.
Opportunity: The population ofCanada and other first world economies is rapidly aging and growing more slowly. The demographic and economic growth over the next 25 years will be substantially higher in middle income and emerging markets. HQI is a way for Quebec to participate and benefit from such growth. For example, there are 1.2 billion people on earth who do not have access to electricity, and middle income and emerging markets are expected to add 2 billion people by 2050.
Exports: Quebec is expected to continue to have substantial electricity surpluses well into the next decade. As a result the need for new builds in Quebec will dramatically shrink in the medium term. Projects abroad may be part of the solution to maintain HQ’s supply chain.

LNG facilities under development in BC

Stikeman Elliott LLP — Mon, 03 Jun 2013 07:54:03 -0500

Cameron Anderson -

Canada is a relative newcomer in the global market for liquefied natural gas (LNG). Currently, natural gas prices in North American markets are significantly lower than world markets, reflecting the significant surplus supply that exists in the North American market. The discounted value of North American natural gas compared to its value in the rest of the world is expected to persist for a significant period. For Canadian producers, LNG exports offer the opportunity to access international markets and potential exposure to higher international prices.

The British Columbia provincial government has expressed support for the development of LNG export capacity within the province. In September 2011 the provincial government released Canada Starts Here: The BC Jobs Plan. According to the plan, the provincial government has set a target of 3 LNG facilities to be in operation by 2020. It is estimated that in the past year over $6 billion in investment have been made to acquire upstream natural gas assets and to execute joint ventures in the province. In addition, the provincial government estimates that up to $1 billion has been spent to prepare for the construction of LNG infrastructure in the province.

Recently the Ministry of Forests, Lands and Natural Resource Operations in partnership with the Ministry of Energy, Mines and Natural Gas announced that it is establishing a list of pre-qualified proponents who are interested in acquiring Crown land for the purposes of developing a LNG plant marine export terminal at Grassy Point near prince Rupert, British Columbia.

Imperial Oil Ltd./Exxon Mobil, Nexen Inc./INPEX, Australia’s Woodside Petroleum Ltd. and South Korea based SK E&S have recently submitted non-binding expressions of interest for Crown land at Grassy Point, British Columbia. The submissions are a preliminary step toward evaluating how many LNG sites the Grassy Point location can accommodate.

The following is a brief summary of the proposed LNG export facilities in the province of British Columbia announced to date.

AltaGas Idemitsu Joint Venture
Idemitsu Kosan Co. Ltd. and AltaGas Ltd. have entered into an agreement to form AltaGas Idemitsu Joint Venture Limited Partnership. The partnership plans to pursue opportunities to export LNG as well as liquefied petroleum gas from British Columbia to Asia. Idemitsu Kosan Co. Ltd. and AltaGas Ltd. each own a 50% interest in the partnership. The pipeline capacity required to transport natural gas to the LNG export facility is expected to be provided by Pacific Northern Gas Ltd., a wholly owned subsidiary of AltaGas Ltd. Under preliminary plans, LNG feasibility studies are anticipated to be completed in 2014 with an LNG export terminal in service by as early as 2017.
LNG Canada
LNG Canada is proposing to build a LNG export terminal in Kitmat, British Columbia. LNG Canada is a joint venture comprised of Shell Canada Ltd., Korea Gas Corporation, Mitsubishi Corporation and PetroChina Company Limited. The export facility is expected to have an export capacity of 2-3 billion cubic feet a day (Bcf/day). On July 27, 2012, LNG Canada applied to the National Energy Board (NEB) for a licence authorizing the export of up to 24 million tonnes of LNG per year, for a term of 25 years. On February 4, 2013, LNG Canada received approval from the NEB for a licence authorizing the export of up to 24 million tonnes of LNG per year for a term of 25 years. The project is currently undergoing an environmental assessment.
Kitimat LNG
Apache Canada Ltd. and Chevron Canada Limited each own 50 percent of the Kitimat LNG project. The facility is expected to have an export capacity of 0.75-1.50 Bcf/day. On December 9, 2010 Kitimat LNG applied to the NEB for an export licence authorizing the export of up to 468 Bcf per year for a term of 20 years. The NEB granted the export licence in October of 2011. The project is currently undergoing an environmental assessment.
Pacific NorthWest LNG
Pacific NorthWest LNG is a proposed LNG export facility on Lelu Island within the district of Port Edward on land administered by the Port of Prince Rupert. The companies sponsoring the project are Progress Energy Canada Ltd. and Petroliam Nasional Berhad (Petronas). The facility is expected to have a capacity of 1-2 Bcf/day. It is anticipated that detailed design of the facility will begin in late spring 2013. Construction is anticipated to begin by early 2015, with the earliest LNG shipments to customers occurring in late 2018. On February 19, 2013, Pacific NorthWest LNG submitted their project description to the Canadian Environmental Assessment Agency (CEAA). Currently CEAA is determining whether an environmental assessment is required for the designated project.
BC LNG Export Co-Operative
BC LNG Export Co-Operative (BC LNG) will be operated by Douglas Channel Energy Partners, which is a partnership between LNG Partners and the Haisla Nation in British Columbia. Currently, there are 16 members of the Co-operative. All members will be entitled to submit bids to supply natural gas to be liquefied and/or submit bids to purchase all LNG exported by the Co-Operative. The facility is expected to have an export capacity of 0.10 Bcf/day. On March 8 2011, BC LNG applied to the NEB for a licence to export 1.8 million tonnes per annum of LNG for a term of 20 years. The NEB granted BC LNG a 20 year licence for the export of 1.8 million tonnes of LNG annually. Recently, Golar LNG, an Asian and Bermuda-based company that runs a fleet of LNG tankers, announced they have purchased a 25 per cent stake in the project.
Imperial Oil/Exxon LNG Project
Imperial Oil Ltd. and its parent, Exxon Mobil Corp., are in the early stages of planning a LNG export business from British Columbia. The facility will build on their $3.1 billion acquisition of natural gas producer Celtic Exploration Ltd., as well as gas holdings they already own in western Alberta and in the Horn River shale gas play in British Columbia. The capacity of the facility has not yet been disclosed. As discussed below, Imperial Oil Ltd./Exxon Mobil have recently submitted non-binding expressions of interest to acquire Crown land at Grassy Point, British Columbia for development of an LNG export facility.
Prince Rupert LNG
BG Group Plc (BG Group) is in the early stages of developing the Prince Rupert LNG project. Recently, BG Group announced its plan to invest $16 billion in the proposed export terminal which is expected to have an export capacity of 3.3 Bcf/day. BG Group has also announced plans to partner with Spectra Energy Corp. to build a pipeline capable of transporting up to 4.2 Bcf/day of natural gas from production areas in northeastern British Columbia to the Prince Rupert LNG facility for export.

BG Group has secured an agreement with the Prince Rupert Port Authority to study the feasibility of an LNG export terminal on port lands. Plans call for a final investment decision to come sometime in the next few years. On May 2, 2013 BG Group submitted a project description to CEAA and the British Columbia Environmental Assessment Office.
Nexen/Inpex LNG Project
Nexen Inc. and a consortium led by Japan’s Inpex Corp. have a joint venture to develop unconventional shale gas assets in the Horn River, Cordova and Liard basins in northeastern British Columbia. As part of the joint venture, the partners intend to jointly investigate the feasibility of a potential downstream project, including an LNG export facility.
Kitisualt Energy LNG Project
Kitisualt Energy intends to establish a LNG export facility at Kitisualt, BC. The plan is in its infancy and Kitisualt Energy has not yet announced export capacity for the proposed facility.

Ontario Minister of Energy announces changes to FIT program rules; will comply with WTO ruling on domestic content

Stikeman Elliott LLP — Fri, 31 May 2013 07:37:04 -0500

Christian Brands -

On May 30th, 2013, Ontario Energy Minister Bob Chiarelli announced the much anticipated changes the current Liberal government is making to Ontario’s Feed-in-Tariff (FIT) program. Speaking at CanSIA Solar Ontario Conference, Chiarelli confirmed that they will replace the controversial approval process for Large FIT projects (+ 500KW) with a new competitive procurement process and provide municipalities with a greater role in locating projects in their communities.

In addition, the Minister announced OPA procurement targets for the next 4 years and the introduction of a roof top solar pilot program for unconstructed buildings.

The Minister is expected to issue a directive to the OPA memorializing these changes and programs in the coming days.

The Minister also affirmed the Ontario government’s commitment to complying with the WTO ruling regarding the FIT program’s domestic content requirements. (see our previous post). No details on the method of compliance were shared and it is not yet known whether compliance would have any impact on existing FIT contracts.

The following is a summary of the announced changes to the FIT program:

New Competitive Procurement Process for Large FIT projects:

Ministry will replace FIT program for projects over 500KW with a new competitive procurement process. This is not expected to impact existing contracts, but would apply to current FIT applications.;
Developers of prospective projects will be required to work with and seek the cooperation of municipalities before the Ontario Power Authority (‘OPA’) will approve contracts. It is not yet clear how the developer’s obligation to cooperate with the municipality would relate to the municipality’s involvement in the project. However, no veto over projects will be extended to municipalities, which suggests the OPA would have some power to offer a contract even if a municipality refuses to cooperate with the developer.
The OPA will approve Large FIT contracts partly on the basis of regional need, location to transmission grid and community participation.

Greater Role for Municipalities:

Projects led by, or in partnership with, municipalities will receive priority points on a similar basis as First Nations and communities receive priority under the FIT 2.0 regime.;
Smaller and mid-size municipalities will receive ‘soft funding’ from the Ministry in association with designing and developing community-based renewable energy plans
A portion of the annual procurement will be set aside for municipalities, universities, schools and hospitals.
Property tax on lands siting wind turbines will be increased by a yet unspecified rate.

OPA and Ministry of Energy Procurement Targets:

900 MW total procurement target for 4 year period between 2014 and 2018.;
Commitment to a procure 50 MW of microFIT and 150 MW of Small FIT each year between 2014 and 2018.;
Additional 90 MW window will be opening fall 2013, comprised of 70 MW Small FIT and 20 MW microFIT; and.
Rates will be reviewed on a yearly basis, beginning in the summer of (2013).

Pilot rooftop solar program

The OPA plans to award a select number of FIT contracts for rooftop solar projects on unconstructed buildings in the summer of (2013). The current rules require projects to be on existing buildings. The intention of this pilot is to encourage construction of buildings with roof surfaces capable of supporting solar panel installations.

Proposed Keystone XL Pipeline bill receives approval from United States House of Representatives

Cam Anderson — Thu, 30 May 2013 17:17:17 -0500

Derek Schiissler -

On May 22, 2013, the United States House of Representatives (the “House”) approved a bill that would allow construction of the Keystone XL Pipeline. The House voted in favour of the proposed Northern Route Approval Act, which gives congress the power to approve the construction of the Keystone XL Pipeline without the requirement for a presidential permit. Currently, the pipeline approval process requires the State Department to assess and review pipeline projects and issue a permit. The House voted 241-175 in favour of the Act with nineteen democrats voting in favour of the legislation. The bill will now come before the Senate for consideration.

The Obama Administration is expected to make a decision in regards to the Keystone XL Pipeline later this year.

Alberta Métis granted greater authority for resource development in settlement areas

Cam Anderson — Sun, 26 May 2013 21:52:39 -0500

On May 16, 2013, the Alberta government and the Métis Settlements General Counsel agreed to amendments to the existing co-management agreement between such parties, which will provide Métis settlements within the province of Alberta with increased benefits from oil and gas development on Métis settlement lands.

The original co-management agreement, which established rules for oil and gas development under Métis settlement lands, is a part of the Métis settlement accord signed in 1990. While the province of Alberta maintains ownership of mines and minerals, the original co-management agreement included provisions which permit the Métis settlements to negotiate an equity participation of up to 25 per cent in any oil and gas development occurring on such settlement lands. With passage of the amendments on May 16, 2013, this 25 per cent cap has now been removed. In addition, the new provisions provide that the Métis settlements now have the authority to require the highest three bidding companies to submit proposals in areas such as local employment, training or infrastructure improvements (the “Benefits Proposals”). The Benefits Proposals will then be submitted to the applicable Métis settlement counsel as part of a final selection process for energy projects occuring on thier settlement lands.

Alberta has eight Métis settlements in northern Alberta representing a land area of just over a half million hectares. According to the new provisions, the first mineral rights under Métis settlement lands will be made available for bidding at the June 3, 2013 bi-weekly provincial land sale.

National Energy Board approves tolls on the Trans Mountain Pipeline expansion

Cam Anderson — Sun, 26 May 2013 21:49:28 -0500

On May 16, 2013, the National Energy Board (“NEB”) released a decision approving the commercial aspects of the proposed Trans Mountain pipeline expansion. The NEB was asked to consider the toll methodology, and terms and conditions that would apply to the expanded Trans Mountain pipeline (“Trans Mountain”) if the pipeline's owner, Kinder Morgan Canada, ultimately decides to undertake the proposed expansion.

According to the decision, the NEB found that the proposed allocation of capacity between firm service and uncommitted service, and the proposed allocation of uncommitted capacity between dock and land destinations, is appropriate. As a result, the NEB found that Trans Mountain would satisfy its common carrier obligations. Further, the NEB found that the open season and negotiation process conducted by Trans Mountain was fair and transparent and that, on balance, the toll methodology proposed by Trans Mountain will produce tolls that will be just, reasonable and not unjustly discriminatory, pursuant to Part IV of the National Energy Board Act (Canada).

Two sides to every coin: SCC weighs collective and individual Aboriginal Rights in Behn v Moulton.

Stikeman Elliott LLP — Tue, 21 May 2013 09:33:58 -0500

Patrick Duffy and Christian Brands -

In recent years, proponents in the natural resource industry have become more comfortable with fulfilling the duty to consult with Aboriginal communities and Aboriginal and treaty rights. However, one of the issues that continues to create uncertainty is whether treaty rights reside with First Nation members individually or collectively, and, if collectively, whether individuals can assert that these rights have been infringed without authorization of the collective. In the recent decision of Behn v Moulton Contracting Ltd, the Supreme Court of Canada appears to have further muddied the waters.

Background

In October 2006, members of the Behn family, a community of the Fort Nelson First Nation (FNFN), camped along a lumber road in northern British Columbia to prevent Moulton Contracting Ltd. (Moulton) from harvesting wood on FNFN territory. Moulton had been granted licenses by the British Columbia Ministry of Forestry (MOF) earlier that year to carry out wood harvesting operations on tracts of land on FNFN territory. These licenses were only granted once the MOF had invited members of the FNFN, which is a party to Treaty No. 8 of 1899, to comment on the proposed forest development plan. The plan was adjusted in response to several of the FNFN’s concerns.

Before Moulton had begun operations, the head of the Behn family advised the MOF that he opposed the licenses and requested further consultation. Note that the FNFN allocated a part of the territory subject to the licenses to the Behn family to manage. Moulton was not notified of the Behn’s opposition until operations were underway and refused to postpone operations citing commitments to deliver lumber from that site. To prevent Moulton from accessing the licensed land, the Behns obstructed the access road by erecting a camp.

In defence to an action brought by Moulton for interfering with contractual relations, the Behns argued that their actions were lawful. The licenses, they claimed, were invalid on two bases: first, in granting the authorizations, the Crown was in breach of their duty to consult and, second, that they violated the Behn’s hunting and fishing rights. The matter at issue was whether the Behns, in their individual capacity and not as representative of the FNFN, had standing to assert either of these defence or, conversely, whether these defences constituted an abuse of process.

The Supreme Court’s Decision

Justice Lebel, writing for a unanimous court, upheld both the British Columbia Superior Court and Appeal Court’s decisions to strike the Behan’s defences on the ground that they constituted an abuse of process.

The Court held that the licenses’ constitutionality should have been challenged when granted and through the proper formal legal channels, such as judicial review. No attempt was made to legally challenge the Crown grants, and Moulton was led to believe that it was free to commence operations. Moreover, Justice Lebel remarked that permitting the assertion of treaty rights and breach of duty to consult as a defence would amount to condoning self-help remedies, which would bring the administration of justice into disrepute.

While the appeal was disposed of on that basis, Justice Lebel went onto discuss the nature of Aboriginal and treaty rights. He definitively affirmed that the duty to consult is owed to a First Nation’s band collectively. Because of its collective nature, an alleged breach of the duty to consult may be asserted by an individual or organization only where they are authorized to represent the interests of the band as a whole.

However, Justice Lebel was much more equivocal in respect of whether Aboriginal and treaty rights can be asserted by persons or groups in their individual capacity and not as agents of a band. Although prefacing with the caveat that “a definite pronouncement in this regard cannot be made in the circumstance”, he rejected approaching Aboriginal and treaty rights, in a binary, categorized manner (i.e. as either individual or collective). Instead, he remarked, Aboriginal and treaty rights, “have both collective and individual aspects…[and] may sometimes be assigned to or exercised by individual members of Aboriginal communities…in a broad sense, it could be said that these rights might belong to them or that they have an individual aspect regardless of their collective nature”.

Therefore, it appears that individuals or communities within a band may have standing apart from the band collectively to assert breaches of Aboriginal and treaty rights. This arises where an individual or community has a greater interest than other members of the band in protecting specific rights in relation to a particular territory.

Impact of the Decision

In some respects, the Court’s decision is helpful in clarifying some key principles; namely:

Aboriginals cannot exercise self-held remedies against apparent treaty right infringements or failures to discharge the duty to consult. The appropriate means of resolving a dispute is through formal legal channels.
The duty to consult is enjoyed by aboriginals collectively and alleged breaches may be asserted only by the band collectively or by an individual or organization that is authorized to represent the collective interests of the band.
Individual members or groups within a First Nation may have standing apart from the band to assert aboriginal or treaty right breaches where they have a greater interest in protecting the infringed rights in respect of a particular territory. Exactly how the comparative strengths of interests between individual members and the band will be evaluated is uncertain, however.

However, the Court’s decision has also left a number of questions unanswered. How exactly individual communities relative interests in respect of a given right and particular territory are to be evaluated is unclear. For instance, it is uncertain whether collective rights will be individually enforceable only where rights have been assigned to individual members, such as where a band’s territory is managed by individual families, or if other factors such as proximity to a particular territory or traditional exercise of a particular right will suffice.

Also, it is unclear what entitlements are conferred on individual groups within a band, both relative to the band as a whole and outside actors, such as industry or the Crown. Might individual groups who have a greater interest in the rights at stake have greater say in the decision-making process? Will individual groups within a band have recourse to assert a deprivation of their treaty rights even where a particular Crown decision has been approved by the band? It will be interesting to observe how these outstanding issues are addressed.

From the perspective of Aboriginal groups, this decision seems to afford a certain amount of increased protection to minority interests within a band by presenting the opportunity for individuals or communities to protect constitutional rights to which they have a special or unique interest apart from the band to which they belong.

The six conditions that must be satisfied for Quebec to become an oil producer

Stikeman Elliott LLP — Wed, 15 May 2013 09:39:49 -0500

Erik Richer La Flèche -

Quebec has a well-deserved reputation for excellence in hydro-electricity. Less well known is its potential as an oil producer. The province is home to at least three likely production zones: Gaspe Peninsula, Gulf of Saint Lawrence and Anticosti Island. Aside from the basic question of whether there is sufficient recoverable oil, there are five other conditions that must be satisfied before Quebec can become an oil producer.

Below is a look at each condition, and its current status.

1. Oil. It has long been known that there is some oil on the Gaspe Peninsula; but it is in the Gulf of Saint Lawrence and on Anticosti Island that very large quantities are thought to be recoverable thanks to newer techniques. Further exploration work is required in all three zones to confirm reserves. Status: More work required.

2. Political Will. There is considerable popular opposition in Quebec to shale gas. The attitude is different with oil, in large part because nearly everyone is a consumer. Electricity and oil currently vie for first place in Quebec’s energy mix, but natural gas is a distant third. Quebec already has oil refineries in Montreal and near Quebec City. Energy independence is a vote magnet: it creates jobs and helps Quebec’s balance of payment. Status: Ready.

3. Adequate Laws. Oil is currently a legislative afterthought. The sudden interest in 2008-2009 in Quebec’s shale gas brought into sharp relief the need for an adequate legal, tax and institutional framework for hydrocarbons. The Quebec government has promised legislation for the end of 2013. Status: In progress.

4. Environmental Approvals. Gaspe Peninsula: drilling on Quebec’s only oil well was stopped in January 2013 by the town of Gaspe due to water quality concerns. The matter is currently before the courts, even though the Quebec government has promised to enact appropriate standards and define more precisely what falls within municipal jurisdiction. Status: In progress.

Gulf of Saint-Lawrence: There is a moratorium on offshore drilling in Quebec waters. Quebec has tasked an outside consultant to make a preliminary environmental study. It is expected to be completed mid-year. The government will then most probably task Quebec’s independent environmental review agency to examine the matter in greater detail. Status: More work required.

Anticosti Island: Quebec currently views Anticosti as the most promising opportunity. Over the objections of NGOs, Quebec is allowing exploration work to continue this summer. The government’s position is that an environmental impact assessment need only be carried out once there is clarity on oil reserves. Status: More work required.

5. Oil Prices; Alberta Oil: Anticosti and Gulf of Saint Lawrence oil will be expensive. Oil prices will have to be sufficiently high to warrant the necessary investments. Also, it is not clear what impact, if any, Alberta oil would have on Quebec production. TransCanada and Enbridge each have plans to pipe oil to Quebec and early indications are that the Quebec government is sympathetic. Connecting Alberta oil to Quebec would materially reduce costs for Quebec’s refineries and create oil export activities. The fact that tankers already ply the Saint-Lawrence importing oil should also lessen environmental resistance, since this will not be a new activity. Status: More work required.

6. Third Party Agreements: Agreements may be required with (i) Newfoundland regarding the Old Harry oil field between Anticosti and Newfoundland, and (ii) municipalities and First Nations regarding the Gaspe Peninsula and Anticosti Island. As detailed in a previous post about the failure of the Great Whale project, a conscious effort on the part of government to consult and involve First Nations is the preferred development route. Status: More work required.

All of the above conditions can be met, but overall there is a fair bit of work to be done before Quebec may become an oil producer.

Ontario Intends To Improve Energy Planning Process

Stikeman Elliott LLP — Wed, 08 May 2013 07:53:49 -0500

Michael Nilevsky -

On May 6, 2012, Ontario’s Minister of Energy, Bob Chiarelli, sent a letter to both the Ontario Power Authority (OPA) and the Independent Electricity System Operator (IESO) requesting that both organizations work together to develop recommendations for a new integrated regional energy planning process. Ontario’s new government is hoping to improve the way in which large energy projects are planned, sited and built across the province and hopes that these two entities can provide recommendations that will help Ontario build energy infrastructure through a process that will have formal inputs from municipalities, Aboriginal communities, other stakeholders in the development process and the energy sector. The OPA and the IESO are expected to report back to the Minister with their recommendations by August 1, 2013. The Minister has specifically requested that the report contain details on how to “implement regional energy plans, including: suggested consultations, required policy and regulatory changes, as well as implementation timelines.”

The full details of the request can be found here. Stay tuned to this blog as well will continue to provide updates as this story develops.

Canada loses WTO appeal regarding Ontario's Feed-in Tariff (FIT) program

Stikeman Elliott LLP — Tue, 07 May 2013 19:20:40 -0500

Susan Hutton and Eric Bremermann -

As an update to our previous post, the World Trade Organization (WTO) has released its official ruling on Canada’s Appeal regarding Ontario’s Green Energy Act and its Feed-in Tariff (FIT) program. On Monday May 6, the WTO Appellate Body upheld the complaints from the European Union (EU) and Japan, stating that Ontario’s Feed-in Tariff (FIT) program discriminates against foreign suppliers of equipment and components for renewable energy facilities by requiring minimum thresholds for domestic content levels, and is not saved as government procurement.

To quickly summarize the claim, the EU and Japan first appealed to the WTO in 2011 claiming that the FIT program violated three WTO conventions: Article III:4 of the General Agreement on Tariffs and Trade; Article 2.1 of the Trade-Related Investment Measures Agreement; and Articles 3.1(b) and 3.2 of the Subsidies and Countervailing Measures Agreement (SCM). Specifically, Japan and the EU argued that the domestic content rules under the FIT program treat imported products less favourably than domestic ones and therefore violate the “national treatment” obligations under the General Agreement on Tariffs and Trade (GATT) and Trade-Related Investment Measures Agreement (TRIM). The complainants also argued that the programs constituted actionable subsidies under the SCM. The initial decision, released in December 2012, found the FIT program contravened GATT and TRIM but that the complainants had failed to show the program constituted a subsidy as defined in the SCM. Canada appealed the decision in February 2013 but in its May 6 report the WTO Appellate Body dismissed the appeal.

What this means for the Ontario’s Green Energy Act is yet to be determined. “As this is the first time Canada has received a WTO panel ruling arising solely from provincial policy or legislation, we will work with the Ontario government in order to respond to the decision,” said a Department of Foreign Affairs and International Trade spokeswoman. However, in formal terms, the WTO decision is not-binding on Ontario. The province plans to the review the ruling in consultation with the federal government before the next steps are determined.

Europe rejects higher carbon prices

Stikeman Elliott LLP — Wed, 17 Apr 2013 11:05:53 -0500

Monique Alicandri -

The media reported yesterday that the European Parliament has rejected an attempt to raise the costs of emitting greenhouse gases in a contentious 334-315 vote. Siding with opponents of increased energy costs, Members voted down a measure that would have temporarily cut a large surplus of carbon allowances currently being traded. The BBC reports that the price of carbon on the EU Emissions Trading Scheme has since plunged to less than 5 euros a tonne.

Given that energy prices are already significantly higher in Europe than in North America, the decision protected European manufacturers who would have been at an even greater disadvantage to their counterparts in the United States and Canada had the measure been passed. However, there is concern that the European Parliament’s decision will give ammunition to critics of carbon trading systems in other parts of the world including Canada.

California Governor approves link of State's carbon market with Quebec

Stikeman Elliott LLP — Wed, 17 Apr 2013 10:59:00 -0500

Last week, California Governor Jerry Brown approved the link of the state’s carbon market with Quebec. The next step is for California’s Air Resources Board to consider changes to its cap-and-trade program that will allow it to link with Quebec. The Board is scheduled to meet on April 19^th. A spokesman has stated that the Board intends to continue to work on all necessary additional steps to ensure California’s efforts to link with Quebec are successful.

If approved by the Board, California and Quebec intend to implement the link between their carbon markets on January 1, 2014. Once linked, they will hold joint auctions of carbon emission allowances which can be used for compliance in either jurisdiction. In the interim, the two jurisdictions will test their auction platforms and trading systems for compatibility.

Both governments are hopeful that linking the carbon markets will improve liquidity for carbon allowances by increasing the pool of permits and companies trading them, as well as encourage expanded investments in low-carbon technologies.

How Alberta and the Keystone XL pipeline can learn from Quebec's failed Great Whale project

Stikeman Elliott LLP — Mon, 15 Apr 2013 17:39:11 -0500

Erik Richer La Flèche -

Alberta, and by extension Canada, is learning a lesson Quebec learned the hard way 20 years ago.

U.S. opposition to the Keystone XL oil pipeline has been galvanized by less than favourable attention on Canada’s recent environmental record and the manner in which Alberta’s tar sands are exploited. The same is somewhat true in British Columbia and Quebec, where there is opposition to new pipeline routes from Alberta to the Pacific and the Atlantic, respectively.

If Albertan oil cannot be exported, then it will be stranded and its price heavily discounted. This will not just affect oil producers, but also Alberta’s finances and the Canadian economy as a whole.

It threatens to be Alberta’s Great Whale.

A Pocket History of Great Whale

It’s 1986. Quebec’s newly-elected premier, Robert Bourassa, announces his intention to build the Great Whale hydro-electric project in Quebec’s north. The project will add 3,090 MW to the more than 10,000 MW already completed at the La Grande complex.

Electricity generated at Great Whale is to be exported to New York and New England. In 1988, the New York Power Authority (NYPA) conditionally signs a 21-year $17 billion power purchase contract with Hydro-Quebec, Quebec’s state-owned power utility.

This contract is essential to make Great Whale feasible, and it’s great news for the Quebec economy.

But by 1992 the contract with NYPA is in tatters. Two years later, Great Whale is permanently beached.

Quebec’s Failure to Consult

One major mistake made by the Quebec government was that it undertook the Great Whale project with little inclination to consult, and even less to involve, the First Nations most affected by the projects, Quebec’s Cree and Inuit. This led to push back from First Nations, especially the Cree, resulting in lengthy and acrimonious lawsuits and public debates that galvanized opposition to the project.

The Quebec government and Hydro-Quebec were caught flat-footed and unprepared.

The Cree and Inuit advantageously used the courts and media. First Nations accused Quebec of not only destroying a fragile environment, but also of committing “cultural genocide” by flooding large swaths of their ancestral lands.

The high point of the First Nations campaign was the very telegenic arrival on Earth Day 1990 at New York City of a Cree/Inuit boat paddling down the Hudson. Advance notice ensured maximum media coverage. This in turn rallied U.S. NGOs and other pressure groups behind the cause.

In 1991, NYPA asked Hydro-Quebec for a one-year extension before confirming the previously signed power contract.

A year later, NYPA decided not to proceed. While economic factors were the main cause of the cancelation, the environmental and other social issues raised by the project made the decision easier to make and defend.

Great Whale was finally shelved by premier Jacques Parizeau in 1994 after a face-saving hiatus.

Quebec learned a valuable lesson from this episode: what happens at home resonates in export markets.

As a result, Quebec has been mindful in the last 20 years to repair and improve relations with its First Nations in general, and the Cree in particular. Several comprehensive agreements have been concluded, relations normalized and a repeat of the Great Whale debacle made less likely.

Auditor General releases special report on cancelled gas plant in Mississauga

Stikeman Elliott LLP — Mon, 15 Apr 2013 16:14:49 -0500

Andrew Sullivan -

On April 15, 2013, the Office of the Auditor General of Ontario (AGO) released its highly anticipated special report (the Report) on the Ontario government’s decision to cancel and relocate the Greenfield South Power Plant. The proposed 280 MW gas plant had been under construction for nearly six months when it was cancelled in late 2011 and subsequently relocated from Mississauga to Sarnia.

The decision is estimated to have cost approximately $275 million according to the Report. The gross cost is estimated to have been as high as $351 million when considering the cancellation and relocation costs in isolation. However, the AGO attributes a $76 million savings in association with the relocated plant's lower electricity prices and delayed construction schedule that better matches Ontario's electricity demand forecast. Of the $275 million, the AGO estimates that $190 million is being paid by Ontario taxpayers with the balance being paid by electricity ratepayers.

Among the key findings, the Report states that the decision to cancel the plant during construction weakened the Ontario Power Authority’s bargaining power and likely resulted in higher costs due to concessions made to the developer to halt construction.

National Energy Board Approves New Tolls for TransCanada Mainline

Cam Anderson — Mon, 01 Apr 2013 08:39:37 -0500

On March 27, 2013 the National Energy Board (the Board) provided their ruling on TransCanada’s application to revise the toll structure for TransCanada’s mainline pipeline. According to the Board’s decision, the new “multi-year fixed tolls are competitive and provide TransCanada with a reasonable opportunity to recover its mainline costs, given the increase in mainline throughput that is forecast”. In the short term, the Board’s decision has the effect of significantly decreasing the transportation toll from Empress, Alberta, to Dawn, Ontario, to $1.42 per gigajoule as opposed to $2.58 per gigajoule for 2013 had the Board not made changes to the tolling structure. The tolls are expected to remain in effect through 2017. In their decision, the Board noted that the Mainline faces challenges but “tolls cannot continue to increase each year in response to throughput decline”. The Board did approve some elements of TransCanada’s proposal giving TransCanada some flexibility in allocating costs on the Mainline and increasing the rate of return that it could earn should higher throughput on the Mainline be achieved.

Historically, the Mainline system once carried as much as 6 billion cubic feet of natural gas per day. However, increasing gas production from the Eastern United States, from supplies such as the Marcellus shale field in Pennsylvania, have resulted in decreasing throughput on the Mainline resulting in increasing tolls for shippers on the line. The decision comes more than 18 months after TransCanada first asked the Board to reconsider the tolling structure on the Mainline.

Feed-in Tariff Contract Update

Stikeman Elliott LLP — Thu, 28 Mar 2013 07:55:48 -0500

On March 22, 2013, the Ontario Power Authority (OPA) posted an amendment to the Feed-in Tariff (FIT) Contract. Specifically, the OPA has amended Exhibit C of the FIT contract which deals with the domestic content requirements. In the new contract (version 2.1.1), Table 1, Activity #11 (On-Shore Wind Turbine Towers) has been amended to allow for a mutually exclusive option for wind tower raw materials. The new domestic content option reads as follows:

“All steel that was formed and shaped into steel tower sections, if any, was processed into steel plates in a steel mill in Ontario; and

All steel for rebar for concrete tower sections, if any, must have been rolled or extruded in a steel mill in Ontario. Aggregate materials used in concrete tower sections, if any, must be sourced and mixed in Ontario, and the Portland cement used in the concrete tower sections, if any, must have been manufactured in Ontario.

The foundation of a tower is not considered part of the tower for the purposes of this Designated Activity 11.”

A link to a comparison of the new contract to version 2.1 can be found here.

Federal Government Announces Increased Tanker Safety Measures

Cam Anderson — Fri, 22 Mar 2013 09:52:39 -0500

On March 18, 2013 the Federal government announced proposed amendments to the Canada Shipping Act, 2001 (the Act) and introduced eight new tanker-safety measures. The announcement was made by Natural Resource Minister Joe Oliver and Transportation Minister Denis Lebel in Vancouver, British Columbia. Recently the province of British Columbia has expressed considerable concern regarding future tanker traffic arising from increased export of petroleum products from the province. The eight measures include increased inspections of foreign tankers, expanded aerial surveillance designed to monitor ship traffic and detect oil spills, a review of tug-escort requirements, expanded research into petroleum products to understand how they behave when spilled in the marine environment, and more ports being designated for traffic-control measures. The first port to be designated to receive traffic-control measures is Kitimat, British Columbia. The ministers also announced the creation of a tanker safety panel to recommend further measures for enhanced environmental safety.

Further, the newly announced Safeguarding Canada’s Seas and Skies Act will amend the Act to include measures to increase regulation regarding ship-source oil spill preparedness and response, introduce new requirements for oil handling facilities, and establish new offences for the contravention of the Act, including administrative monetary penalties.