Canadian Energy Law

OPA FIT 2.0 program prescribed forms posted

Stikeman Elliott LLP — Tue, 08 May 2012 09:24:13 -0500

The OPA has posted draft prescribed forms for FIT 2.0 on its website. The OPA notes that the forms are for reference only and may be revised. No opportunity for public comment has been provided.

In a review of the draft FIT 2.0 Prescribed Forms, the following items are of note:

The OPA has issued a Municipal Council Support Resolution, as well as a Municipal Council Blanket Support Resolution. The blanket resolution enables a municipality to declare its support for all projects located anywhere within the municipality for a period of twelve months after its adoption by Council. The municipality can offer its support for all or select technologies in issuing a Municipal Council Blanket Support Resolution. Unlike the Aboriginal Support Resolution, which is a general declaration of support for the application and the project, each of the municipal council support resolutions are stated to have the sole purpose of enabling the applicant to achieve priority points.
The prescribed forms of Zoning Opinion and Zoning Certificate for Non-Rooftop Solar Facility do not provide additional clarity on the OPA’s interpretation of the land use restrictions on ground-mount solar PV under the FIT 2.0 Rules.
Despite the flexibility afforded in the definition of “Economic Interest” for ownership interests other than equity in a corporation or a partnership interest in a partnership and for indirect as well as direct interests, which the OPA may determine in its sole and absolute discretion to constitute an “Economic Interest”, the prescribed forms of Aboriginal Participation Project Declaration and Education or Health Participation Project Declaration are best designed to address direct ownership of securities and partnership interests or units.

The OPA has not yet released any of the prescribed forms relating to the FIT 2.0 Contract, other than the prescribed form for the Consent of Co-op Member & Property Owner Declaration for Community Participation Project Declaration, which is in a substantially similar form to that required under the FIT 2.0 Rules.

Alberta carbon capture and storage project cancelled

Stikeman Elliott LLP — Tue, 01 May 2012 09:02:11 -0500

Lewis Smith -

Capital Power Corporation, Enbridge Inc. and TransAlta Corporation have decided to cancel Project Pioneer, a carbon capture and storage project that was proposed for Capital Power and TranAlta’s jointly-owned Keephills 3 coal-fired power plant located approximately 70 kilometers west of Edmonton, Alberta.

The project was intended to include: a carbon capture facility that would have removed CO2 from a portion of the Keephills 3 flue gas, a pipeline to transport CO2 to a sequestration site approximately 6 kilometers from the power plant, and a second pipeline to transport CO2 to an existing oil production facility in the Pembina oil field, approximately 75 kilometers from the plant. CO2 from the second pipeline, which would have carried the majority of the captured gas, was to have been used for enhanced oil recovery. Project Pioneer was intended to demonstrate the commercial scale-viability of carbon capture and storage technology.

The federal government had committed $342.8 million to the project. These funds were to have come from its $1 billion Clean Energy Fund and its ecoENERGY Technology Initiative. The Province of Alberta had agreed to invest an additional $436 million from the Alberta CCS Fund, a $2 billion program announced in 2008 to advance carbon capture and storage technology.

A feasibility study conducted for Project Pioneer determined the technology was viable and that capital costs would be consistent with expectations. However, reports suggest that even with the committed government funding, the project would not have been economically viable because of two factors. First, because of the relatively low cost of carbon under Alberta’s carbon pricing scheme, the project would have generated insufficient savings on carbon offsets or carbon charges under that scheme. Second, the project was not able to secure sufficient guarantees of revenue from the sale of CO2 for enhanced oil recovery purposes.

These two factors are at play in the broader project development sector in Canada. Low or non-existent carbon prices across Canada make carbon-reduction projects (including non-carbon based power generation, energy storage, and CCS projects) less financially attractive, particularly in an era of already low natural gas prices. At the same time, a variety of energy (and non-energy) projects are challenged by an inability to secure bankable off-take agreements. For example, development of a number of renewable generating projects in Alberta is being slowed by a scarcity of opportunities to obtain long-term power purchase agreements.

The federal and Alberta provincial governments have focused their carbon strategies on capture and storage, rather than reduction. The failure of Project Pioneer, despite large amounts of government financial support, may force a rethink in tactics (although likely not in strategies).

Mexican Legislature passes robust climate change law

Stikeman Elliott LLP — Tue, 01 May 2012 08:44:20 -0500

Kim Lawton and Annie Pyke -

New Legislation

On Thursday, April 19, 2012, Mexico's lower and upper houses passed a sweeping climate change bill clearing the way for President Felipe Calderon to sign it into law. President Calderon is expected to sign it in the coming days. After three years of debate and revisions, the bill has very strong legislative support and overwhelmingly passed Mexico’s lower and upper houses (Chamber of Deputies and Senate, respectively).

The Mexican legislation is one of the strongest national climate change laws passed to date. The bill mandates several changes:

requirements that future governments meet regular emissions reduction targets with the goal of ultimately cutting carbon emissions 30% below business-as-usual levels by 2020, and by 50% below 2000 levels by 2050;
substitution of renewable sources for 35% of all electricity sources by 2024;
requirement of mandatory emissions reporting;
establishment of a carbon-trading market; and
creation of a commission to oversee implementation of the bill.

Mexico ranks 11th in the world based on measurements of both economy size and level of carbon emissions and industry estimates suggest that the legislation could result in the development of a new US$3 billion market over the next 20 years. This is the first climate change law of its kind to succeed in North America, and the first from a developing nation.

Global Trend

Mexico is following a global trend of countries implementing their own climate change laws, rather than relying on the international community. As the Kyoto Protocol winds down without a replacement, countries have begun executing their own strategies to reduce global warming.

As we’ve previously blogged, countries such as Australia, New Zealand, South Korea and China have all taken steps to create their own regimes for mitigating climate change, including the establishment of carbon markets. There have also been strong regional initiatives undertaken such as the EU Emissions Trading System and the Western Climate Initiative (California, British Columbia, Ontario, Quebec and Manitoba).

We will continue to follow these and other carbon trading initiatives on this blog.

Federal Government announces reforms to the Federal Environmental Assessment Process

Stikeman Elliott LLP — Thu, 19 Apr 2012 09:33:26 -0500

Patrick Duffy and Sean Gibson -

The federal government announced on April 17, 2012 its plan for “Responsible Resource Development” which contains a number of proposals to reform key aspects of the review process for federal environmental assessments.

Simplified and Set Timelines for Environmental Assessments

The government’s plan proposes to simplify the current structure of environmental assessments and replace it with two kinds of reviews: 1) a standard environmental assessment, or 2) a review panel. Though details on this proposal are currently lacking, it appears this reform is meant to allow appropriate projects to proceed in a more streamlined fashion through a standard environmental assessment.

The plan also proposes a set of timelines for the government to act within to speed up the environmental assessment process:

Decisions by the Canadian Environmental Assessment Agency (CEAA) on whether a federal environmental assessment is required will be made within 45 days.
Standard environmental assessments led by CEAA will have specific timelines of 365 days.
Panel reviews in regards to projects under the Canadian Environmental Assessment Act will have a 24 month beginning-to-end timeline.
Panel reviews in regards to projects under the National Energy Board Act will have an 18 month beginning-to-end timeline.
There will be binding (though currently undefined) timelines for key regulatory permitting processes, including the Fisheries Act, the Species at Risk Act, the Navigable Waters Protection Act, the Canadian Environmental Protection Act and the Nuclear Safety and Control Act.

While the establishment of binding timelines is a welcome step, our experience with similar timelines in provincial environmental assessment regimes is that they are difficult for a proponent to enforce where a project meets with significant opposition.

Consolidated Responsibility for Environmental Assessments

The plan proposes reforms to consolidate responsibility for environmental assessments with the CEAA for most projects, or the Canadian Nuclear Safety Commission (CNSC) and the National Energy Board (NEB) for projects within their respective mandates. Joint review panels for projects regulated by the NEB and the CNSC will no longer be required. This proposal would constitute a significant reform as, currently, over 40 federal government departments and organizations have responsibility for project reviews.

As well, the plan proposes to give the federal government the authority to, based on recommendations from the NEB, make the ultimate “go/no go” decision on major pipeline projects in the national interest. This proposal has already attracted attention in the media and could be a major point of contention with environmental groups.

Federal-Provincial Regulatory Equivalency

The plan proposes to provide the Government the authority, through substitution and equivalency provisions, to allow provincial environmental assessments that meet the substantive requirements of the Canadian Environmental Assessment Act to replace federal assessments, effectively allowing the integration of federal and provincial regulatory regimes. This proposal appears to go further than the agreements for environmental assessment cooperation that are currently in place between the federal government and several provinces.

The need for permits under the federal Fisheries Act is a frequent trigger for a federal environmental assessment. The plan includes a specific commitment to enable equivalency of Fisheries Act regulations with provincial regulations and to allow a single regulator, which could be a province, the NEB or CNSC, to issue authorizations under “key” provisions of the Fisheries Act.

Aboriginal Consultation

The plan proposes to designate a lead department or agency as a single Crown consultation coordinator for specific project reviews. The plan also proposes to establish specific consultation protocols or agreements with Aboriginal groups in order to clarify the expectations and level of consultation that will/should occur in project reviews. As well, the plan calls for agreements to be executed between the federal and provincial governments to, presumably, create a unified approach to consultation.

These proposals should help further two laudable goals: 1) improved relations between the federal/provincial government(s) and Aboriginal groups, and 2) the reduction of delays and uncertainties arising from the legal risks associated with the Crown fulfilling its duty to consult with Aboriginal peoples in regards to conduct that might adversely affect potential or established Aboriginal or Treaty rights.

Foreign asset income trusts revive interest in income trust market

Stikeman Elliott LLP — Fri, 13 Apr 2012 11:49:34 -0500

Doug Richardson

The public offerings of two foreign asset income trusts (FAITs) have revived interest regarding income trusts in Canada, bringing to light a relatively untapped market. The key factor driving this renewed attention is that FAITs are not subject to traditional Specified Investment Flow-Through (SIFT) rules, as a result of their ownership of assets outside of Canada.

The royalty trust and income trust markets trace their origins to 1986 and 1995, respectively. As interest rates declined during the period and beyond these trusts became popular, since they provided lofty yields well in excess of the prevailing interest rate payable by corporations with similar credit ratings. The reason for the discrepancy was primarily due to the fact that royalty trusts and income trusts were flow-through vehicles that avoided the payment of corporate level tax. The yields payable by these trusts varied, but were typically in the 8 – 10% range.

Unfortunately for investors, the party effectively ended on October 31, 2006 when the Department of Finance announced their intention to introduce rules (the SIFT rules) to tax income from “non-portfolio properties”, including Canadian real, immovable or resource property if the fair market value of the property was greater than 50% of the equity value of the trust, as well as property held by the trust and/or non-arm’s length parties that is used in the course of carrying on business in Canada.

The public offerings of two FAITs, Parallel Energy Trust (Parallel) and Eagle Energy Trust (Eagle), have revived interest in the income trust market, since neither Parallel nor Eagle are subject to the SIFT rules as a result of their ownership of U.S. oil and gas properties. As a result, provided they are able to return their oil and gas income from the U.S. without the incidence of U.S. tax, they act like the royalty and income trusts of yesteryear. Indeed, both trusts provide a hefty yield (13% for Parallel) and one that is relatively stable, since it is based on proved reserves. For example, in the case of Parallel, the proved and probable reserve life index and the proved reserve life index are roughly 27 and 13 years, respectively.

Despite the attractive and relatively secure yields, neither Parallel nor Eagle has a strong following in the market. The reason for this relative anonymity in light of the attractive yield offered could be a result of a confluence of factors. However, regardless of the status of FAITs there should be an untapped market that they can service, if properly marketed, provided they weather the initial storms that many new financial products suffer.

FIT 2.0 for lenders

Stikeman Elliott LLP — Thu, 12 Apr 2012 10:20:09 -0500

Lewis T. Smith

The Ontario Power Authority issued draft FIT program rules, draft definitions and a draft FIT contract for stakeholder comment on April 5, 2012. Information on submitting comments on these "FIT 2.0" documents is available on the OPA's website. Comments are due by April 27, 2012. A ministerial directive to the OPA concerning the FIT program was issued the same day.

Lenders should be aware of some important differences in the terms of the current FIT program and the proposed FIT 2.0. As well, the changes to the program will affect the types of projects that are most likely to move forward and therefore the types of projects lenders will be asked to finance.

Projects with aboriginal or municipal council support will be prioritized, as will those with equity participation from aboriginals, local community members, public schools, colleges, universities, hospitals and long term care facilities. Contracts will be awarded in batches, with the first batches to be for microFIT and small FIT projects. It is unclear when the next round of large FIT contracts will be offered. In addition, opportunities for ground-mount solar projects are limited, due to additional restrictions on siting these types of projects. Taken as a whole, the effect will be that projects receiving FIT 2.0 contracts will by their nature tend to present additional challenges for lenders.

Specific issues for lenders to consider under the draft FIT documents are discussed below.

Curtailment
It is important to note that one significant issue for lenders is not addressed in the draft FIT contract. The draft contains a note to the effect that the protective provisions in the current FIT contract dealing with changes to electricity market rules by the Independent Electricity System Operator will be amended in conjunction with the IESO's current renewable integration initiative (SE-91). Lenders will need to wait for further progress on the IESO front before they will be able to understand the potential economic risks to a FIT 2.0 project resulting from curtailment

Changes to Facility
Under the existing FIT contract, the OPA was not permitted to unreasonably withhold consent to material changes to a facility. The new FIT contract allows the OPA to withhold consent for material changes to a facility in its sole and absolute discretion. This may limit an electricity supplier's ability to change the connection point, feeder, transformer, site location, design or layout of the project after the application is made. Lenders will need to pay even greater attention to their technical diligence to ensure there is unlikely to be any need for changes to the facility after financial close.

Liquidated Damages for late COD
The new FIT contract requires all electricity suppliers to pay liquidated damages of $0.25/kW multiplied by the contract capacity of the facility for each day of delay in achieving commercial operation beyond the Milestone Date for Commercial Operation specified in the contract. (This only applies to a limited subset of projects under the existing FIT contract.)

Like the existing FIT contract, the twenty year term (forty years for hydro) of the new FIT contract commences on the Milestone Date for Commercial Operation even if commercial operation has not been achieved by that date. However, under the new contract the right of the supplier to "buy back" the truncated portion of the term has been eliminated. The term may now only be extended at the option of the OPA. Lenders will want to give careful consideration to the possible impact of these new provisions on project economics in the case of delays to commercial operation, and consider whether risk mitigants such as additional reserves are required as a result. This issue is likely to be of particular concern for lenders to rooftop solar projects, which will have eighteen months to reach commercial operation under the new FIT contract (in contrast to three years under the existing contract).

Domestic Content
The current FIT contract requires the OPA to respond within 60 days of its receipt of a domestic content report; however, the new draft proposes only a "reasonable" time period. The draft provides that the electricity supplier and the OPA will cooperate to finalize the domestic content report "within a reasonable time period" if the OPA finds the domestic content report deficient following its initial submission while the existing FIT contract provides the supplier with 30 days to respond to deficiencies and gives the OPA an additional 30 days to review those responses. Lenders were already uncomfortable with the post-COD nature of the domestic content report, so the lack of firm time lines is likely to add to this discomfort.

Termination for Convenience/Stop Work Direction
The existing FIT contract permits the OPA to terminate the contract prior to obtaining Notice to Proceed (though this right was waived by the OPA in many cases). Since receipt of Notice to Proceed is typically a condition precedent to financial close, this is not an issue of concern on a typical project loan transaction (although it may of relevance on portfolio level financings, depending on the conditions precedent for each draw).

The new FIT contract introduces a right for the OPA to terminate the FIT contract for convenience on 20 days' notice even after the issuance of Notice to Proceed. If the OPA exercises this termination right, the supplier is entitled to return of its completion and performance security, and payment of accrued amounts owing to it under the contract, plus its "Sunk Costs" (defined as the reasonably incurred costs to develop, construct and commission the facility) and the net present value of the supplier's anticipated profits during the term.

Of even greater concern, the new FIT contract introduces a right for the OPA to issue a "Stop Work Direction". This direction requires the supplier to permanently cease development and construction of the facility. Although one section of the new draft expressly entitles the OPA to issue this direction prior to issuing Notice to Proceed, in another section there is no time limitation. As such, it appears the OPA would also have the right to issue a Stop Work Direction after Notice to Proceed (or possibly even after COD, since it is unclear when "development and construction" is complete). Under the current drafting, it is also unclear whether the supplier is entitled to any compensation if it receives a Stop Work Direction.

In addition to the risk of not receiving compensation sufficient to pay out their loans, lenders will also want to consider what rights they will require vis-à-vis the supplier if a termination notice or Stop Work Direction is issued. For example, the FIT contract specifies a process to determine the amount of compensation payable to the supplier for termination for convenience by the OPA. Lenders are unlikely to want to sit on the sidelines and leave such an important issue to be determined without their input and involvement.

Force Majeure
The force majeure provisions in the new FIT contract are less supplier-friendly than those in the current contract. Specifically, a supplier will not be able to invoke force majeure to the extent that the event was within the reasonable control of the supplier or resulted from a failure of performance of a third party (unless the failure of performance of the third party was itself caused by a force majeure event as defined in the new contract). As well, if requested by the OPA, the supplier must provide evidence to demonstrate that it has made commercially reasonable efforts to remedy the force majeure situation and must represent and warrant that such evidence is complete and not misleading. Lenders are likely to focus on this issue most closely during the pre-COD period, particularly given the shorter milestone dates for rooftop solar discussed above.

Lender's Rights
A few changes have been made to the "Lender's Rights" section of the contract.

First, the draft FIT contract now permits lender's security agreements to cover assets and to secure debt relating not just to renewable generating facilities owned by the supplier, but also to those owned by affiliates of the supplier. This should generally facilitate cross-collateralization and portfolio-wide financings. However, microFIT facilities are not permitted to be included in multi-facility security agreements (although it is rare that a microFIT facility would be included in a portfolio given the restrictions imposed in that program). Also, a requirement has been added that the other renewable energy facilities included in the security agreements must be the subject of a contract with the OPA. This will make it more difficult to use projects in earlier stages of development as collateral for the financing of contracted facilities, and vice versa.

Second, while the current FIT contract includes the form of consent and acknowledgement agreement that the OPA will enter into with the lender, the draft contract refers only to an agreement "in the Prescribed Form". We believe the likely explanation for this change is that in some cases suppliers and lenders have entered into an out-of-date version of the agreement based on the form attached to the FIT contract, rather than using the version available on the OPA website, which has undergone some changes. Detaching the form of agreement from the FIT contract will eliminate this problem. However, given the crucial nature of the consent and acknowledgement from a lender perspective, it would have been helpful either to see the proposed new form or to get confirmation that the current form will continue to be used under the new FIT contract.

Ontario Assessment Review Board rules wind farm does not affect property value

Stikeman Elliott LLP — Wed, 11 Apr 2012 14:00:24 -0500

Patrick Duffy and Sean Gibson -

The Ontario Assessment Review Board has ruled that there is no evidence the presence of a wind farm affected the value of Ed and Gail Kenney’s waterfront property on the west end of Wolfe Island, a rural community located in the Township of Frontenac Islands on Lake Ontario.

The Municipal Assessment Property Assessment Corporation (MPAC) assessed the Kenney property at $357,000 for the 2009, 2010 and 2011 taxation years, a valuation that the Kenney’s objected to due to their proximity to the Wolfe Island Wind Project, the second largest wind farm in Canada, which has been in commercial operation since June 2009. The Kenney’s property is located within 1 km of three turbines, 2 km of 14 turbines and 3 km of 27 turbines. The Kenney’s argued that the existence of the wind farm reduced the value of their property because of the various nuisances or annoyances that it caused.

The Board rejected the Kenney’s arguments. In particular, the Board found that:

the noise from the wind turbines has not restricted the Kenneys’ activities;
there was no direct link between Ms. Kenney’s complaints about tinnitus and the wind farm;
neither “shadow flicker” or lighting on the turbines interferes with the Kenneys’ enjoyment of the property;
the Kenney’s view of the waterfront from their property (a view which could affect property value) was unaffected;
there was no evidence presented to show that industrial traffic from the farm causing increased wait-times for the island ferry reduced the value of properties on Wolfe Island; and
there was no evidence presented to demonstrate that the wind turbines caused a degradation of the natural environment on the Kenney property.

Because MPAC has not yet developed a category in its assessment formula for proximity to wind turbines, the only way for the Board to assess whether the property was over-valued was through analysing sales of similar property on Wolfe Island. The Board examined listings and sales of property on the island, focusing on sales of waterfront property, and found that sales of such property following the approval, construction and operation of the wind farm had not slowed and that the selling price of the properties did not indicate that the wind farm had any depreciative effect on value.

As a result of these findings, the Board concluded that there was nothing to indicate that the value of the Kenneys’ property had been negatively affected by the creation or operation of the wind farm and confirmed MPAC’s assessment of the property at $357,000.

For more information, see Kenney v. Municipal Property Assessment Corp. Region No. 05.

FIT 2.0 draft contract released

Stikeman Elliott LLP — Mon, 09 Apr 2012 13:56:18 -0500

Following the issuance of the Minister’s Directive to the Ontario Power Authority on April 5, the OPA released a draft of version 2.0 of the FIT contract, “FIT 2.0”. The new FIT contract is intended to implement the recommendations made following the 2-year review of the program and is open for public comment until April 27, 2012. See here for copies of the draft contract and for more information on how to provide feedback.

Some of the changes from the original FIT contract include:

Contract Changes

The OPA will no longer have any obligation to consent to reasonable changes in the facility features or specifications. This may limit a supplier’s ability to change the connection point, feeder, transformer, site location, design or layout of the project after the application is made.

Pre-NTP Termination

The new FIT contract maintains the OPA and seller’s respective rights to terminate a FIT contract before Notice to Proceed is issued. Current contract holders will recall the OPA offered to waive its pre-NTP termination right under version 1 of the FIT contract in the fall of 2011.

Like in past versions of the FIT contract, if the OPA exercises its termination right, the supplier will be entitled to claim its development costs incurred prior to the termination date, up to a predetermined limit (which for example is $250,000 per facility plus $10.00 per kW of contract capacity in the case of solar and $400,000 per facility plus $2.00 per kW of contract capacity in the case of wind).

The new FIT contract also introduces a new right in favour of the OPA whereby the OPA can issue a “Stop Work Direction” pursuant to which the Supplier will permanently cease development and construction of the Facility. As currently drafted, it is not clear whether the supplier is entitled to any compensation if it receives a Stop Work Direction.

Post-NTP Termination

In addition to maintaining the OPA’s right to terminate before Notice to Proceed, the new FIT contract introduces a right for the OPA to terminate the FIT contract for convenience following the issuance of Notice to Proceed and on 20 days’ notice. In the event that the OPA exercises this termination right, the supplier is entitled to its “Sunk Costs” (being the reasonably incurred costs to develop, construct and commission the facility) and to the net present value of the supplier’s anticipated profits during the term.

The OPA is also entitled to issue a Stop Work Direction following Notice to Proceed. As with the OPA’s right to issue a Stop Work Direction prior to NTP, it is unclear whether the supplier is entitled to any compensation if it receives a Stop Work Direction based on the current drafting of the new FIT contract.

Penalties for failing to achieve the Milestone Date for Commercial Operation (MCOD)

The new FIT Contract requires all suppliers to pay $0.25 per kW multiplied by the contract capacity of the facility for each day of delay in achieving commercial operation beyond the MCOD. In the existing FIT contract such penalty only applied to first-mover projects that elected to advance their MCOD.

The new FIT Contract also specifies that the twenty-year term (or forty-year term in the case of waterpower) will commence on the MCOD even if the facility has not yet achieved commercial operation (as does the existing FIT contract); however, unlike the existing FIT contract, there is no longer an opportunity to buy-back the term for a penalty of $0.15 per kW multiplied by the contract capacity of the facility for each day of delay in achieving commercial operation beyond the MCOD.

As a result, the supplier will face monetary penalty and a loss of term as a result of a failure to achieve commercial operation by its MCOD. These changes should be noted by rooftop solar developers, in particular, as such projects will have a MCOD eighteen months following the contract date in contrast to three years under the existing FIT contract.

Contract Capacity

While the old contracts allowed a facility to be built at 90% of its contract capacity, the new draft, as a condition to achieving commercial operation, requires the facility to be built at 100% of the contract capacity and requires the seller to deliver an independent engineer’s certificate certifying same. Prior to delivering this certificate, the Supplier may elect to reduce the contract capacity to a lower amount, provided that such amount is no less than 75 percent of the original contract capacity.

Force Majeure

The new FIT contract has tightened the force majeure provisions. In particular, a party will now not be able to invoke force majeure to the extent that the event was within the reasonably control of such party or if it was as a result of the failure or performance of a third party (unless the failure of performance of such third party was itself caused by a force majeure event). Further, upon the OPA’s request, the supplier must provide documentation or information evidencing the commercially reasonable efforts undertaken by the supplier to remove or remedy the force majeure and must represent and warrant that such documentation or information is complete and not misleading.

Domestic Content

The timing for the post-COD domestic content report has been removed. While the original draft required the OPA to respond within 60 days of its receipt of a domestic content report, the new draft proposes only a “reasonable” time period. Further, while it was unclear in the existing FIT contract what the effect would be if the seller repeatedly submitted a deficient domestic content report to the OPA, the current draft provides only that the supplier and the OPA will cooperate to finalize the domestic content report “within a reasonable time period”, if the OPA finds the domestic content report deficient following its initial submission. Given that lenders are already concerned with the post-COD nature of the domestic content report, the removal of a firm time line is unlikely to make lenders more comfortable.

REA Representation

A supplier is required in the new contract to represent that it is not aware of any reason, and that there are no reasons of which the supplier ought to have been aware, for which the supplier would not obtain a Renewable Energy Approval (where applicable). The supplier will not be entitled to make a force majeure claim with respect to any delay in obtaining a REA where those representations prove untrue; however if this representation is not true it will not constitute an event of default

Secured Lender Provisions

Unlike the existing FIT contract that prohibited a secured lender’s security agreement from securing indebtedness that is not related to the facility (except in relation to one or more renewable generating facilities in Ontario that are owned by the seller), the new FIT Contract allows a secured lender’s security agreement to secure indebtedness related to other facilities (other than a facility under a microFIT contract) in Ontario that are also the subject of a contract with the OPA and that are owned by the Supplier or its affiliates.

Participation Projects

As with the existing FIT contracts, there are special provisions for Aboriginal and Community Participation Projects.

Price adders will only apply if the projects retain status as participation projects as at the commercial operation date. If during the term, the applicable participation level decreases, the seller must provide written notice to the OPA and the price adder may be recalculated. If the participation project no longer qualifies as a participation project at any time prior to or during the term (1) and such project is not a rooftop solar facility, such failure will constitute an event of default; or (2) and such project is a rooftop solar project, then the supplier will no longer be entitled to a price adder. If a rooftop solar participation project fails to qualify as a participation project on or at any time during the term prior to the fifth anniversary of commercial operation, such failure will constitute an event of default.

For Community Participation Projects, the supplier will be obligated to certify on the commercial operation date and each anniversary of such date that it has the requisite number of “Qualifying Members” and to update its list of Qualifying Members” to reflect any changes to the participating co-op property owners. We note that a Qualifying Member must be a co-op member and property owner; however, the definition of property owner requires such person to be a registered owner of real property two years prior to the date of a FIT application, which creates an impractical result over a twenty-year or forty-year contract.

Stikeman Elliott's Energy Group will be discussing the changes to the Feed-in Tariff Program and the operational and commercial implications it may have on renewable power generators and others at a seminar on Wednesday, April 18 (8:00 am – 9:30 am). For further details or to receive an invitation, please contact Lyne Montpetit.

FIT 2.0 draft rules released

Stikeman Elliott LLP — Mon, 09 Apr 2012 12:44:09 -0500

Following the issuance of the Minister’s Directive to the Ontario Power Authority on April 5, the OPA released drafts of version 2.0 of the FIT Rules. All interested parties are encouraged to review the proposed changes and submit comments. Comments will be accepted by the OPA until April 27, 2012. See here for a copy of the draft FIT Rules and for more information on how to provide feedback.

The draft FIT Rules take a much more prescriptive approach to applications and application requirements, with multiple opportunities for the OPA to terminate applications at an early stage. A brief summary of certain proposed changes to the Rules follows.

Small FIT Projects and Large FIT Projects

The Rules now differentiate between "Small FIT Projects" and "Large FIT Projects." A "Small FIT Project" is defined as a capacity allocation exempt small embedded distribution generation facility. A Small FIT Contract must be no more than 250 kW where the facility is connected to a line of less than 15 kV or no more than 500 kW where the facility is connected to a line of 15 kV or greater. A "Large FIT Project" is defined as a project that is not a Small FIT Project.

Evaluation of Applications

Under the revised FIT Rules, it is proposed that evaluation of applications will now occur in four stages:

Stage 1 - Application Completeness Requirements - this is a pass/fail stage based on the application requirements specified in the Rules.

Stage 2 - Eligibility Requirements - this is a pass/fail stage based on the eligibility requirements specified in the Rules.

Stage 3 - Ranking by Prioritization and Time Stamp - applications will be ranked based on the number of "Priority Points" and their time stamp, as discussed below.

Stage 4 - Connection Availability and Procurement Limits - contracts will be awarded to applications, based on their ranking pursuant to stage 3, which are able to pass the TAT and, if applicable, the DAT, and subject to any applicable procurement limits.

The following is a brief summary of certain proposed changes to the Rules:

Application Prioritization and Ranking

Applications can be awarded "Priority Points" based on specified criteria. Every application must obtain at least one Priority Point in order to be eligible for a FIT Contract. Priority Points are awarded based on "Project Type" or "Non-Project Type" criteria.

Project Type Priority Points:

Community Participation Projects (3 points): To qualify, a Co-op (with at least 50 Co-op members for a Large FIT Project and 35 Co-Op members for a Small FIT Project) must have a direct economic interest in the Project. The Co-op members must be “Property Owners” (defined as natural persons that are and were, as of the date two years prior to the application, a registered owner of real property in the municipality in which the Project is to be located, in whole or part). Any economic interest in the Co-op by any entity or any affiliate of an entity whose primary business is, or of any person whose employment is in, the development of non-community based electricity projects will be discounted from the calculation of the Community Participation Level in the Project.
Aboriginal Participation Projects (3 points): An Aboriginal Community must have at least a 15% economic interest in the applicant or supplier to qualify for these points.
Education or Health Participation Projects (2 points): Projects where a university, school, college, hospital or long-term care has at least a 15% economic interest in the applicant or supplier qualify for these points.

Non-Project Type Priority Points:

Municipal Council Support Resolution and Aboriginal Support Resolution (2 points): These points will be awarded to a project that has received a Municipal Council Support Resolution or an Aboriginal Support Resolution, in the form provided by the OPA.
Project Readiness (2 points): These points will be awarded to projects which are able to evidence that they have title to, or a legally enforceable lease or option to lease for, the project site.
Education or Health Host (2 points): These points will be awarded to projects located on a site which they have been granted access to by a university, school, college, hospital or long-term care centre.
System Benefit (1 point): One point is available for a project which uses waterpower, renewable biomass, landfill gas or biogas, as its renewable fuel, or an on-farm biogas facility.

Project Type Priority Points cannot be combined with each other, but can be combined with Non-Project Type Priority Points. Non-Project Type Priority Points are cumulative. It is unclear whether the OPA can award partial points. Projects will be ranked according first to the number of Priority Points they achieve and then based on their time stamp. The time stamp assigned to pre-existing applications will be that assigned to it under the prior versions of the FIT Rules.

Project Siting

While it is still sufficient to evidence Access Rights through a lease, option to lease, letter of intent, memorandum of understanding or other grant, in order to be eligible for “Project Readiness” Priority Points under the new ranking system (as described above), it will be necessary to evidence a greater degree of site control.

For rooftop solar projects, the applicant must represent in the application that it has obtained written certification from an independent engineer (and provide the certificate) that the subject rooftop has sufficient useable surface area for the project and that it is either suitable to support the project or that it will be following improvements (the particulars of which must be described in the certification).

The rules for siting of ground-mount solar projects have become much more stringent. Projects cannot be located on a site that is comprised (in whole or in part) of CLI Class 1, 2 or 3 Lands, Specialty Crop Areas, or CLI Organic Lands. In addition, ground-mount solar projects cannot be located on a property (i) which is or includes residential property or abuts another property that is a residential property - unless the property is agricultural and residential use is ancillary to agricultural use; or (ii) on which commercial uses and/or industrial uses are permitted and one or more ground-mount solar projects would constitute the main or primary use of the property. In an application for a ground-mount solar project, the applicant must provide a map showing the grid cell number and site where the project is to be located and a written opinion of a Land Use Planner or written certification of a chief building official, municipal chief administration officer, municipal clerk, or equivalent, opining or certifying that the project satisfies the land use restrictions on non-rooftop solar projects set out in the Rules.

Connection Availability and Procurement Limits

Following the ranking, applications will be assessed, in order of rank, as to availability of, and impact on, the applicable transmission system and/or distribution system for the project, based on the transmission availability test and distribution availability test. Applications will also be assessed in light of any applicable "Procurement Limits". The OPA has reserved the right to specify limits on the procurement of renewable energy, based on fuel type, within each specified Application Period.

Domestic Content

On-shore wind projects will continue to be required to achieve 50% domestic content and solar PV projects will continue to be required to achieve 60% domestic content.

Pricing

As discussed in our earlier blog post, the price schedule has been revised and the Rules indicate that pricing will be reviewed every year. The contract price will be the price in effect at the time a contract award is made, not the time that the application was submitted. Aboriginal and community projects will continue to be eligible for price adders, however, unlike the existing FIT Program, for all projects other than rooftop solar, the price adders will be available for all project sizes and technologies and will be based on the level of equity participation (namely, between 15% and 50% or above 50%). The Settlement Provisions have not changed.

Multiple Projects on the Same Property

The Rules have provided the following guidance on whether multiple projects can be located on a single property:

An application cannot be made in respect of a proposed project located on the same property as (i) a project developed under the microFIT Program that uses the same renewable fuel; (ii) a project that has been the subject of any previous application unless that project has achieved commercial operation; or (iii) another project that is the subject of an application submitted during the same application period that is the same as or substantially similar to the proposed project;
Co-Located Projects cannot exceed 10 MW for solar PV projects and 50 MW for waterpower projects; and
In general, project splitting will not be permitted by the OPA, as discussed further below.

Project Splitting

The Rules specifically prohibit the splitting of a project in order to obtain a higher contract price, to circumvent the eligibility requirements, or to obtain any other benefit under the FIT Contract.

If the OPA determines that a project has been split, it may (i) terminate all applications in respect of the split projects; (ii) apply the contract price to such split projects which would have applied had the project been assessed as a whole, or (iii) take such other action as it may determine. In making the determination of whether a project has been split, the OPA may consider, among other factors, whether the applicants are the same person or related persons, the relative locations of the projects and the renewable fuel(s) used by such projects.

Assignment

An applicant may not assign its application to another person or permit a change of control of the applicant, failing which the OPA may terminate the application and draw on the application security as liquidated damages.

Existing Applications

Applications that were submitted prior to April 5, 2012 may be resubmitted under FIT 2.0 provided that the proposed project is located on the same Site and that the applicant is the same person and has the same name (other than name changes made for the purpose of the project qualifying as a Participation Project).

Pre-existing applications must be resubmitted (1) during the first application period for Small FIT Projects, in respect of existing Small FIT Projects or Large FIT Projects (provided that the Large FIT Project is restructured such that the resubmitted application is for a Small FIT Project); or (2) during the first application period for Large FIT Projects, in respect of Large FIT Projects. No information or supporting evidence in the corresponding pre-existing application will be considered in reviewing the resubmitted application. The OPA will return or cancel any existing application fee and security, and the applicant will be expected to submit a new application fee and application security with the resubmitted application.

If such pre-existing applications are not resubmitted during these initial application periods, the OPA may terminate the pre-existing application and will return or cancel the application fee and application security submitted to the OPA in connection with such existing application.

The OPA is proposing a non-refundable application fee of at least $500 and minimum application security of at least $1,000.00. The OPA has also expressly stated that an applicant will not be permitted to correct its application, including by providing the correct application fee or security following submission. Applications must also include specific representations and warranties from the applicant, including with respect to the requirements of the Renewable Energy Approval. The OPA may terminate any application it determines is incomplete, ineligible or which does not include satisfactory information.

Applications will only be accepted during specified application periods, to be announced by the OPA.

Ontario Ministry of Environment posts amendments to Renewable Energy Approval Regulation

Stikeman Elliott LLP — Fri, 06 Apr 2012 10:35:40 -0500

Annie Pyke -

Following the release of the Government of Ontario’s two-year review of the Feed-in Tariff Program, the Ministry of the Environment has published proposed amendments to the Renewable Energy Approval Regulation and the Environmental Assessment Act. The amendments include changes to the heritage and archaeological assessment process, amendments to the determination of solar nameplate capacity to reflect energy lost through inverters, and guidance for dealing with project changes.

Specific changes of note include proposed amendments to the definitions of “noise receptor” and “odour receptor”, which would require a part of the renewable energy project to actually be constructed on a parcel of land in order for the exemption from the definition (and corresponding setbacks to apply); this is in contrast to the current definitions which require only that the land owner has entered into an agreement with the developer to permit development of their land. The proposed changes also include an amendment to the requirement that final letters from the Ministry of Natural Resources and Ministry of Tourism, Culture and Sport be made available prior to the public meeting. In response to feedback received from proponents that this requirement made it difficult to address concerns raised at final public meetings, these will now be required for a complete REA submission instead of prior to the final public meeting.

The proposed amendments are available for review and comment until May 17, 2012 on the Ontario Environmental Registry. All interested parties are encouraged to review and comment on the proposed amendments.

Federal Budget 2012: regulatory efficiency for the energy sector

Stikeman Elliott LLP — Tue, 03 Apr 2012 07:38:35 -0500

Patrick Duffy and Daniel Suss -

Last Thursday, the federal government released Budget 2012. It contained a number of proposals to improve efficiency and predictability in the review and approval process for major resource development projects while shifting tax incentives and strengthening environmental protection and free trade.

One project, one review

The government plans to create a “one project, one review” policy in coordination with the provinces and territories for environmental assessments (EAs) and associated regulatory processes. Provincial EAs would substitute for federal EAs, and responsibility for review would be consolidated significantly from at present over 40 departments and agencies. Federal and provincial governments would also coordinate Aboriginal consultations and fully integrate them into project reviews.

Review Time

The government is proposing new fixed timelines as follows:

24 months for panel reviews
18 months for National Energy Board (NEB) hearings
12 months for standard EAs

The Major Projects Management Office initiative would receive $54 million over two years to continue its work that has already shortened the average approval process from 4 years to 22 months for a number of major natural resource projects, including for oil and natural gas pipeline and offshore oil developments. As motivation for these changes, the government cites delays between the NEB and federal approvals, and delays between federal approvals and provincial approvals of up to 2 years for projects including a $2 billion pipeline proposed by Enbridge and a 396 MW offshore wind project proposed by NaiKun Wind Energy Group.

Responsible Energy Development

The government is proposing to invest $35.7 million over two years to strengthen regulation over tanker inspection, the double hulling of vessels, oil spill emergency preparedness and response, oil products handling, research on marine pollution risks, and a further $13.5 million for the NEB over two years to strengthen pipeline safety.

Tax

The government intends to enhance the neutrality of the tax system by phasing out fossil fuel subsidies. Specifically, it will eliminate the 5% tariff imposed by a Canada Border Services Agency ruling on certain imported fuels used as manufacturing inputs in energy and electricity production, and will phase out the 10% Atlantic Investment Tax Credit for the oil and gas sector. On the other hand, the government proposes to extend tax support to certain thermal energy equipment fuelled by waste and plant residue.

Foreign trade and investment

With the launch of the Action Plan on Perimeter Security and Economic Competitiveness with the United States this past December, pilot projects at Prince Rupert and Montréal will soon begin to replace multiple freight inspections with a single screening. Through the Canada-United States Action Plan on Regulatory Cooperation also announced in December, the government is committing to align regulations with those in the United States in areas including the environment.

Deeper and more liberalized economic ties with other major trading partners including China, the EU, India, Japan, ASEAN and Mercosur are being pursued. The conclusion of a Foreign Investment Promotion and Protection Agreement with China this past February will facilitate investment flows between Canada and China by providing a more stable and secure environment for investors. The government also plans to “refresh” the Global Commerce Strategy of consultations with Canada’s business community in 2013 to better align trade and investment objectives with high-growth markets.

Ontario government releases feed-in tariff program review

Stikeman Elliott LLP — Fri, 23 Mar 2012 08:13:42 -0500

Lanette Wilkinson -

The Province released its Two-Year Review Report summarizing the results of its FIT Program review. The Report proposed the following material revisions to the FIT Program.

Commitment to 10,700 MW Original Target - The Long-Term Energy Plan target of procuring 10,700 MW of non-hydro renewable energy generation by 2015 will be maintained. At the end of 2013, the government will explore whether a higher target is required.

Prioritizing Projects - The time stamps of applications in the FIT Production Line will no longer solely establish the priority of contract award. The Report proposes the introduction of a point system into the application review process to give priority to certain applicants

Points will be awarded to applications as follows:

3 points for a minimum of 15% equity coming from either Aboriginal groups or the local community (being at least 50 or more property owners in the municipality where the project is located).
2 points for a minimum of 15% equity coming from public schools, colleges, universities, hospitals or long-term care facilities or if such facilities host the project.
2 points if a project has a resolution evidencing municipal council and/or aboriginal community support.
2 points to wind, solar ground-mount or bioenergy projects with a firm lease, firm option to lease or purchase or ownership of the subject land sufficient for the project or in the case of solar rooftop applicants that do not own the host building, with a firm lease or option to lease.
1 point will be granted to FIT projects with an ancillary system benefit (i.e. water or bioenergy).

Also, at least ten percent of the remaining capacity in the 10,700 MW target for 2015 will be reserved for local and Aboriginal projects with greater than fifty percent equity participation and up to 50 MW will be reserved for hydroelectric projects.

Ground-mount Solar - Solar ground-mount projects over 10 kW will be prohibited on prime agricultural land that contain class 1, 2, and 3 soils. All zoning exemptions that permitted projects to be located on lands zoned to permit non-agricultural uses as of October 1, 2009 will be removed. Ground-mount solar projects will be permitted in commercial or industrial uses where energy generation is a secondary use; however, regardless of size, will not be permitted in or bordering residential areas.

Rooftop Solar PV - The milestone date for commercial operation for rooftop solar PV will be shortened from three years following the Contract Date to eighteen months following the Contract Date, which does not affect the eligibility of these projects under the Program; however, it may affect project feasibility for existing applicants.

Interconnection – The OPA is to consult with stakeholders to develop a rule regarding the maximum distance between a project site and its connection point. Further, the Report dictates that where the OPA’s screening process indicates that upgrades are required to connect a project, the OPA will only offer contracts where the need for minor transmission upgrades are identified.

Transition Process – Because some existing applications will be rendered ineligible by the changes, there will be a transition process for all pre-existing FIT applications (which will also be available generally for microFIT applications submitted on or after September 1, 2011) that will allow applications to transition to eligibility requirements under the new rules. A revised application will retain its original timestamp.

Changes to the Price Schedule – Prices for renewable energy projects have been reduced by more than 20 per cent in the case of solar and fifteen percent for wind. The revised price schedule follows:

The Province will review the Price Schedule each year. It is expected the revised Price Schedule will be published each November, commencing on November 2012, with pricing to take effect on January 1st of the following year. The contract price will be the price in effect at the time a contract award is made, not the time that the application was submitted.

As with the existing FIT Program, a portion of the FIT contract price will escalate for inflation following commercial operation. The portion of the FIT contract price that escalates will remain 20% for wind and waterpower and 0% for solar; however, the Report has increased the escalation percentage from 20% to 50% for bioenergy.

In addition to prioritizing Aboriginal and community projects through the application process (as described above), these projects will still be eligible for price adders. Unlike the existing FIT Program, however, the price adders will be available for all project sizes and technologies (other than rooftop solar) and will based on the level of equity participation (namely, between 15% and 50% or above 50%).

Renewable Energy Approval (REA) - The Report recommends streamlining the REA process by expanding self-screening for small-scale solar (less than 500 kW) and bio-energy projects and shortening the timelines for agency review. MicroFIT solar projects will remain exempt. For the remaining projects, two streams of REA approvals are recommended.

Reestablishing Municipal Engagement - Proponents and project developers of large FIT projects will be required to meet with the municipality in a contract launch meeting. Further, the municipal consultation form for the REA will be revised in consultation with the Association of Municipalities of Ontario and the Ministry of Energy to better reflect municipal concerns.

The Report made several other notable recommendations:

The OPA will allow existing contracts to voluntarily withdraw from the FIT Program for a period of time and have their security fees returned.
A domestic content grid will be created for concentrated solar PV to facilitate participation in the FIT Program.
FIT project due diligence will be strengthened in areas such as awareness of regulatory approvals, structural safety and application security for small FIT.
Multiple projects on the same property will continue to be permitted on the basis of the aggregate MW price, as under the existing FIT Program. Future projects will also be permitted to be built on existing project sites so as long as the original project has reached commercial operation.
The Ministry of Natural Resources is to review its approach to renewable energy development on Crown land to release Crown land for renewable energy.
The OPA will not proceed with the Economic Connection Test.
The OPA will not launch the Municipal Renewable Energy Program or the Commercial FIT (CFIT) program, which was originally proposed to address commercial aggregators.
There will be certain changes to the microFIT Program, including limiting one microFIT contract per individual, removing the requirement that Aboriginal communities, schools, public colleges, and universities, hospitals, long-term care facilities and social housing own the land on which the project is located, and provided for an application approval notice, which will be valid for six months, instead of a conditional offer.

The Ontario Power Authority (OPA) will complete draft Rules and a draft Contract based on the Report’s recommendations and will post such materials to the microFIT and FIT website for review and comment.

Government of Ontario releases two-year FIT program review

Stikeman Elliott LLP — Thu, 22 Mar 2012 09:47:33 -0500

The Government of Ontario today released their two-year review of the FIT Program. Recommendations include, among others, (i) the reduction of prices - for solar projects by more than 20% and for wind projects by approximately 15% (see new price table below); (ii) the creation of a point system to prioritize FIT Applications which have demonstrated community or Aboriginal participation and municipal support; and, (iii) reserving 10% of the remaining capacity for projects for those projects which have significant local or Aboriginal participation.

Revised draft Program Rules and draft Contracts implementing the recommendations are expected to be released shortly by the OPA. We will continue to update the blog with further information and analysis regarding changes to the FIT Program.

Carbon tax vs. environmental regulations

Stikeman Elliott LLP — Thu, 08 Mar 2012 12:37:48 -0500

The Conservative government has rejected the proposal for a carbon tax in favour of the United States’ model of regulating emissions through environmental regulations.

Energy industry critics and environmental groups have endorsed the carbon tax model citing the high bureaucratic involvement and low flexibility of regulations, and arguing that a market-based approach minimizes administrative costs and maximizes mechanisms to price the cost of greenhouse gases. Supporting these arguments, a paper prepared by Nancy Olewiler, released by the University of Calgary, recommends the federal government institute a carbon tax as part of a full-cost pricing system.

The author will be presenting her views to the Natural Resources Minister on March 9, 2012, suggesting further pressure on Ottawa to choose taxation over regulation.

Layperson evidence on alleged health effects limited

Stikeman Elliott LLP — Mon, 05 Mar 2012 13:57:05 -0500

Patrick Duffy and Sean Gibson -

The Environmental Review Tribunal (ERT) has released a decision limiting the ability of laypersons to testify about health effects allegedly caused by proximity to wind turbines without providing medical records/expert opinions to substantiate their testimony.

The issue arose in an appeal to the ERT by the Middlesex-Lambton Wind Action Group of a Renewable Energy Approval (REA) issued to Zephyr Farms Limited for a wind farm under the Environmental Protection Act. In its appeal, the Appellant alleged that the proposed wind farm would negatively affect the health of the surrounding community. In pre-hearing disclosure, the Appellant listed numerous witnesses aiming to testify that they had suffered negative health effects caused by living in the vicinity of wind turbines. The Appellants provided no corresponding medical reports to substantiate, further explain, or allow professional medical scrutiny against, these statements.

In response, the Ministry of the Environment (MOE) requested an order for the Appellants to produce medical reports to corroborate the allegations. The MOE argued that, without medical reports properly subjected to medical scrutiny, the ERT did not possess the necessary expertise to judge how relevant, applicable and transferable the witnesses’ experiences would be to Zephyr Farms’ proposal. Consequentially, the MOE claimed that layperson evidence would be of little use in determining whether the Zephyr Farms project will cause serious harm to human health.

The Appellant argued that, largely due to the expedited timeline for the hearing of the appeal, the time and cost it would take to obtain the necessary medical records to buttress the witnesses’ statements made the exercise impractical and that if the ERT did require such records for its consideration, a significant adjournment would be necessary.

The ERT largely agreed with the MOE, and citing its own decision in Kawartha Dairy Limited v. Director, Minister of the Environment, found that the ERT cannot simply accept the assertion of a layperson that they suffer from a certain medical condition, let alone the cause of that condition. Such conclusions require the diagnostic skills of a qualified health professional. Accordingly, the ERT would only be willing to hear and consider the subjectively reported symptoms of such a witness. One can assume, though it is not explicitly stated, that the ERT would give little weight to such subjectively reported symptoms. The ERT also refused to grant an adjournment because the Appellant knew of the time constraints on REA appeals when it filed its Notice of Appeal and was unable to provide any viable explanation for its inability to obtain a single medical record for any of the witnesses it proposed to call.

Following the decision, the Appellants withdrew their appeal to the ERT.

ExxonMobil fined €3.3 million for failure to report emissions

Stikeman Elliott LLP — Thu, 01 Mar 2012 10:25:57 -0500

Kim Lawton and Annie Pyke

In what is surely a strong reminder to companies around the globe to comply with green regulations, oil giant ExxonMobil has been fined €3.3 million (approximately $4.4 million CAD) for failure to correctly report its carbon dioxide emissions from a Scottish chemical plant. This is the largest fine for an environmental offence in British history.

The fine was imposed by the Scottish Environment Protection Agency (SEPA) under the European Union Greenhouse Gas Emissions Trading Scheme (EU ETS) that came into effect in 2005. Under the EU ETS, companies which fail to report their greenhouse gas emissions can be fined €100 per tonne for unreported emissions.

The fine was imposed in 2010-11, but was only just revealed by SEPA when it published its 2010-2011 enforcement report.

TransCanada to re-apply for Keystone XL Project permit and pushes ahead with Southern leg

Stikeman Elliott LLP — Mon, 27 Feb 2012 15:59:07 -0500

TransCanada Corporation (TransCanada) announced on February 27, 2012 that it has sent a letter to the U.S. Department of State (DOS) informing DOS of its intention to reapply for a Presidential Permit in the near future for the Keystone XL Project. TransCanada will supplement this application with an alternative route in Nebraska that avoids the ecologically sensitive Sandhills area once this alternative route is determined.

TransCanada also informed DOS that the southern leg of the Keystone XL Project which runs from Cushing to the U.S. Gulf Coast will proceed independently of the Presidential Permit process because the Gulf Coast Project has its own independent value to the marketplace and no international border is involved. The approximate cost of the Gulf Coast Project is US$2.3 billion and subject to regulatory approvals, would likely be in service in mid to late 2013. Jay Carney, a White House spokesman, announced that the administration welcomed the decision on the southern leg, and would help speed up the permit process.

EU committee makes no decision on oilsands

Stikeman Elliott LLP — Mon, 27 Feb 2012 11:43:05 -0500

Javier Gonzalez -

In a highly anticipated vote, a European Union committee of technical experts failed to reach a decision on whether to approve a European Commission proposal to classify oilsands crude oil as more harmful to the environment than other forms of fuel. The proposal will now go to a council of EU ministers, with a final decision expected by June.

The proposal by the European Commission, the EU’s executive arm, would constitute a revision of the EU’s Fuel Quality Directive, which aims to reduce carbon emissions by 6% from 2010 levels by 2020. The proposal would not ban oilsands crude oil, but it would assign it a greater carbon footprint than conventional crude oil. Under the proposal, oilsands crude oil would be deemed to emit 22% more greenhouse gas by weight than average crude oil.

A “qualified majority” – 255 votes from a total of 345 – was needed to accept or reject the proposal. The committee voted as follows: 89 points in favour of the proposal, 128 against, and 128 abstained.

Key to the result was the abstention of France, Britain, and the Netherlands, home to oil companies with significant oilsands interests.

Europe does not directly buy crude oil from the oilsands, but Canada’s concern is presumably that it any adverse conclusion by the EU may damage the image of the oilsands, set a precedent for possible similar actions in other jurisdictions, and affect potential future sales.

Canada has lobbied against the proposal for months, arguing that it is discriminatory and could hinder trade relationships. It has even threatened to take the matter to the World Trade Organization if the committee approved the plan.

Top ten energy M&A trends in Canada

Stikeman Elliott LLP — Mon, 27 Feb 2012 08:42:58 -0500

Glenn Cameron, Susan Hutton and Lisa McDowell -

Despite uncertainty and slow growth in the US and Europe, Canada has continued, for the most part, to post impressive economic results. One reason for this has been the unceasing demand for Canadian natural resources including oil and gas. In addition, Canada’s stable majority government is a significant factor. In recognition of this economic strength, Forbes recently ranked Canada as the best country in the world in which to do business. It is the only country of the 134 surveyed that reached the top 20 in ten separate metrics. Consequently, we expect M&A activity in Canada will increase in 2012, particularly in the energy sector.

The following outlines ten trends that will impact M&A activity in the energy sector in the coming year.

1. Foreign Investment is Going to Continue

The year 2012 will most certainly experience continuing demand by foreign investors for Canadian energy plays, especially from China, India, Korea, Japan and India. In addition to going-private transactions in the form of takeover bids or plans of arrangement, this sector will also see creative and strategically oriented investment structures.

Significant transactions involving foreign investment in Canada’s energy sector that occurred in 2011 include:

the acquisition by Petronas (Malaysia) of a 50% interest in Progress Energy’s North Montney, British Columbia natural gas properties;
Korea Investment Corporation’s $251 million acquisition of Hunt Oil Company’s oil and gas properties and its investments in Alberta’s oil sands through shareholdings in OSUM and Laricina;
the acquisition by the INPEX (Japan) led consortium of a 40% interest in Nexen’s Horn River, Cordova and Laird shale gas plays;
Chinese National Offshore Oil Corp.’s acquisition of a 35% interest in the Long Lake oil sands project through its transaction involving OPTI Canada; and
Sinopec’s $2.1 billion acquisition of Daylight Energy.

Through transactions like these, foreign investors have acquired interests in some of Canada’s most significant oil and gas projects, securing long-term supply that is very important in the Asia Pacific region. In addition, those investors have gained experience in managing and developing unconventional oil and gas plays which they can apply to similar projects in their home countries.

In exchange, the counterparties to these transactions with foreign investors have gained needed access to significant amounts of capital investment, in order to accelerate the development of their unconventional projects.

Early indications are that foreign investment in Canada’s oil and gas sector will continue in 2012. Transactions already announced this year include:

PetroChina’s purchase of Athabasca Oil Sands’ remaining 40% interest in the undeveloped MacKay River oil sands project;
PetroChina’s agreement to acquire a 20% stake in Shell Canada’s Groundbirch shale gas project in north eastern British Columbia; and
Grizzly Oil Sands’ (US) $225 million agreement to acquire Petrobank Energy Resources’ undeveloped May River oil sands project.

Including the two PetroChina investments above, China will have spent more than $15 billion in Alberta’s oil patch alone. Additionally, the Canadian government is encouraging more of these investments. In February, Prime Minister Stephen Harper led a Canadian trade visit to China to attract further investment in the Canadian resource sector and to diversify markets for Canada’s energy, mining and forestry exports.

Investments by foreign entities have tended to focus on either acquisitions of interests in oil and gas properties concurrently with entering into partnerships or joint ventures for the exploration and development of those properties, or on investments in existing enterprises. However, the recent CNOOC/OPTI and the Sinopec/Daylight transactions were corporate acquisitions. These acquisitions may be indicative of the next stage of foreign investment in Canada’s oil and gas sector. If so, larger Canadian companies may become targets for foreign investors, although the Prime Minister signaled in February that hostile takeovers of key Canadian businesses could receive heightened scrutiny by Investment Canada.

2. Companies Will Position Themselves to Participate in Export Markets

President Obama’s rejection of the Keystone XL pipeline project has strengthened Canada’s resolve to expand the markets for its oil and gas away from the US. Prime Minister Harper told the World Economic Forum in Davos, Switzerland in January that:

… we will make it a national priority to ensure we have the capacity to export our energy products beyond the US and specifically to Asia.

This aim was repeated during the recent China trade mission.

Consistent with this objective, the Federal government made its intentions clear that it expects expeditious regulatory approvals of the proposed infrastructure required to diversify markets for Canadian energy. Natural Resources Minister Joe Oliver recently said in this regard that there is a need to make regulatory reviews of new projects less time consuming if Canada is keen to reach out to new markets.

This is a strong statement to the regulators currently reviewing Enbridge’s Northern Gateway project, which is proposed to ship 525,000 barrels per day of bitumen from Alberta’s oil sands to Kitimat, British Columbia for export to Asian markets. A decision on that project is expected to take over 18 months.

British Columbia also wants access to Asian markets for its natural gas industry. On February 3, 2012 the Province announced its Natural Gas Strategy, with LNG exports being a cornerstone of the plan.

Several LNG export projects based in Kitimat are at various stages of development.

A number of M&A transactions in 2011 focused on positioning companies to participate in energy exports from Kitimat. These included:

EnCana acquiring a 30% interest in the Kitimat LNG Project with Apache and EOG Canada;
the Kitimat LNG Project acquiring the remaining 50% of the Pacific Trails Pipeline system in order to control the delivery of natural gas from northeastern British Columbia across the province to Kitimat; and
Shell Canada and its partners, Mitsubishi, China National Petroleum Corp. and Korea Gas acquiring Cenovus’ marine terminal site at Kitimat.

More transactions of this nature are expected to occur in 2012. As an example of this continuing trend, BG Group PLC (UK) has just secured an agreement with the Prince Rupert Port Authority to study an LNG terminal on port lands. It is anticipated that companies participating in proposed LNG facilities will look for natural gas reserves to ensure supply for those facilities, which will lead to investments in producing oil and gas properties by some foreign investors as part of their integrated export strategy. Partnerships like Nexen and INPEX and PennWest and Mitsubishi are examples of this strategy. More recently, PetroChina’s motive for its purchase of a 20% interest in Shell Canada’s Groundbirch shale gas project in British Columbia may well be to source the LNG that PetroChina plans to buy from the Shell Canada consortium’s LNG project.

Japan’s ongoing shut-down of its nuclear plant infrastructure highlights the importance of long-term supply development.

3. Size Will Matter for Midstream Companies

There was significant M&A activity among owners of midstream facilities in 2011. These transactions included:

Kinder Morgan’s US$38 billion acquisition of El Paso Corp. Kinder Morgan’s properties include the TransMountain Pipeline System that transports oil from Alberta to ports and refineries in Vancouver and the Express Pipeline System that transports bitumen from Alberta to Casper, Wyoming and beyond;
Plains All American’s US$1.67 billion acquisition of BP’s natural gas liquids and liquefied petroleum gas businesses and related assets; and
AltaGas’ $230 million acquisition of Pacific Northern Gas and its natural gas distribution business in British Columbia.

Not only were midstream companies getting bigger, but they were expanding their properties and operations throughout North America.

Early indications are that these trends will continue in 2012. Recently:

AltaGas announced an agreement to acquire SEMCO Holding Corporation for US$1.14 billion. SEMCO owns natural gas distribution businesses in Alaska and Michigan;
Pembina agreed to acquire Provident to create a company with a combined enterprise value of $10 billion in energy infrastructure assets; and
Keyera acquired the isooctane manufacturing business of EnviroFuels and its related facilities and equipment in a US$237 million transaction.

The turn to liquids production in Canada, the demand for more complex processing arising from the oil sands and the very competitive cost of capital in the mid-stream sector have helped shape an active M&A climate in midstream. These trends will remain intact.

4. Natural Gas Producers Will Face Challenges

Unexpectedly low prices for natural gas over the winter heating season and unrelenting US production growth will put pressure on natural gas producers to manage through reduced cash flows and limited access to capital markets. Prices for Canadian natural gas have recently been lower than $2.00 per gigajoule, less than half of what prices were expected to be at this time of year. These low prices resulted from mild winter weather in North America and correspondingly less than usual demand. Low gas prices also occurred because of significant new gas supply being produced from previously untapped shale gas reserves.

The immediate consequence of weak pricing has been for several gas-weighted producers to announce reductions in their 2012 capital budgets to align their spending programs to available capital.

Annual borrowing base re-calculations and resulting reductions of lines of credit may further restrict the ability of gas producers to implement capital programs. As hedged production comes off in 2013, cash flow and covenant issues loom unless prices stabilize.

Shutting-in gas production has also been proposed, with some producers already taking this step.

Within a short time, consolidations of natural gas producers may occur. If prices remain weak, we also expect that assets or entire companies will be offered up for sale or become takeover targets as their market values decline.

Energy-focused and other private equity funds will be among the buyers of these assets. These funds are known to be bargain hunters with the patience to wait out dips in commodity prices. Velvet Energy’s $209 million acquisition of Alberta natural gas assets from Vero Energy is an example of what may become a growing trend. Velvet is backed by a US private equity fund.

Other gas-weighted producers with depressed market values will also be potential targets for private equity funds, participants in export projects looking to secure energy supplies and other strategic investors. Interestingly, pricing drives much of this activity towards asset packages. The weakness in gas prices and the concurrent downturn in the gas-weighted Canadian equity market has slowed corporate M&A in this space. Management teams will be looking to preserve battered option and incentive structures from the reality that the market will not quickly welcome a start-up transaction after the sale. It may make sense to eliminate G&A, but teams are avoiding that result in order to wait for the turn-around. At some point this trend will turn, but low prices aren’t leading to much corporate change. Dissidents have made noises, and have enjoyed some success, but there isn’t much concerted action in this regard.

5. There Will be More Aggressive Competition Regulation

Last year Canada’s antitrust regulator, the Competition Bureau, aggressively asserted itself on a number of important fronts. These included high-profile, ongoing M&A matters including an application to block Air Canada’s proposed joint venture with United Continental and the investigation of the Maple/TMX transaction. Many trace the more vigorous enforcement of Canada’s competition laws to amendments in 2009 that gave the Bureau enhanced information-gathering powers, longer periods of time to investigate mergers and greater penalties for anti- competitive conduct.

We expect this trend to continue in 2012.

6. Investment Canada Will Continue to Approve Foreign Investments, But …

Following the Minister of Industry’s rejection in late 2010 of BHP Billiton’s hostile bid for Potash Corporation of Saskatchewan, it appeared to be a return to “business as usual” under the Investment Canada Act, as the federal government reviewed and approved some 13 applications for review in 2011, apparently without incident.

Most of those reviews related to investments in Canada’s energy sector, including CNOOC’s acquisition of OPTI Canada, Sinopec’s $2.1 billion acquisition of Daylight Energy, and Korea Investment Corporation’s acquisition of Hunt Oil’s oil and gas assets for $251 million.

However the anticipated guidelines on Investment Canada’s approach to the “net benefit to Canada” test have not materialized. Those guidelines were promised with the minority government, in response to criticisms that the process was opaque following the Potash decision. Now that the government has a majority in Parliament, no such guidelines are expected. Prime Minister Harper commented in a February 2012 interview with Reuters news agency that Canada is open for foreign investment. However, he cautioned that not every foreign bid is good for Canada, singling out hostile takeovers of key Canadian businesses, and takeovers of critical technology companies as being of doubtful benefit to Canada. Hostile takeovers of some of the largest Canadian energy companies may accordingly not be approved.

We do not expect any material legislative changes to occur in 2012 in relation to the ICA as it pertains to its reviews of foreign investment in the energy sector.

The annual change to the review threshold under the ICA for direct acquisitions by WTO investors in non-cultural businesses has been set at $330 million for 2012 (book value of assets of the Canadian business – wherever located).

The government’s court action against U.S. Steel Corporation seeking penalties for breach of its undertakings in the wake of plant closures in the 2009 recession was settled in late 2011, with U.S. Steel providing new undertakings following a court ruling that the government’s action was not unconstitutional.

7. Cross Border Income Trusts Will Continue to be Offered, Cautiously

Rumours of the demise of the income trust may have been premature. That is positive news for M&A participants looking for “made in Canada” liquidity alternatives. By way of background, in 2006, the Department of Finance unexpectedly announced proposed changes to Canadian tax rules under which the same taxes imposed on corporations would also be imposed on publicly-traded trusts and partnerships. While these “SIFT Rules” did not become fully effective until January 1, 2011 (and do not affect REITs), the 2006 announcement largely signaled the end of business and resource income trusts. Up until 2011, these entities had effectively been treated for tax purposes as flow-through vehicles not subject to taxation. Needless to say, this characteristic made them very popular with Canadian tax-exempts, non-residents and even Canadian taxpayers who could earn business income through a public vehicle on a more tax-efficient basis than income earned through a public corporation. However, the SIFT rules do not apply to foreign source income, and in 2011 we began to see a few income trust offerings in Canada through which investors were given exposure to US resource-based assets (among others). Eagle Energy Trust and Parallel Energy Trust are examples of this. Argent Energy Trust launched in August 2011 but had to pull back. Look for others to try in 2012, with offerings providing Canadian yield-seeking investors with exposure to other foreign-based asset classes.

8. Cross Border Acquisitions Will Continue to be Structured Through Intermediary Jurisdictions

US buyers in cross-border M&A transactions into Canada will continue to utilize creative acquisition structures, including the continued use of Luxembourg companies and unlimited liability companies (ULCs) created under certain Canadian provincial jurisdictions. Due to the changes in the Canada-US tax treaty which can impact dividends received from a ULC, ownership of the ULCs is more frequently being structured such that there is an intermediary jurisdiction between Canada and the US.

9. Poison Pills May be More Effective as Defensive Tactics

For many years, the view of Canadian securities regulators on shareholder rights plans (commonly referred to as “poison pills”) was that poison pills were strictly limited to the single purpose of helping the board buy time to seek out improved or alternative offers. As a result, in contrast to US practice, poison pills could not be used by a board of directors in Canada as part of a “just say no” defence.

Over the past few years, a series of developments suggested that securities regulators were becoming more flexible in assessing the allowable purposes of poison pills, and that the conventional view that “eventually a pill must go” may be an overstatement, at least where securityholders had given a strong and recent endorsement to the pill or where a bid appeared to be an opportunistic attempt to wrest away control of the company during a difficult economic period.

Although rulings in 2010 and 2011 reversed this trend by reaffirming the traditional view of poison pills, the appropriate role of poison pills as a defensive measure continues to be debated by regulators and market participants. In late 2011, at a public roundtable discussion, the OSC revealed that it is currently reconsidering its historical approach to shareholder rights plans. New proposals being considered include allowing shareholder rights plans to remain outstanding if approved by shareholders, subject to the ongoing rights of shareholders to remove the plan on a “majority of the minority” vote (requiring a bidder to launch a proxy battle or proceed with a permitted bid). The purpose of the rule would be to provide more consistency and certainty in the context of defensive tactics and decrease the need for regulatory intervention. The progress of this proposal will almost certainly be among the most closely-watched developments in Canadian M&A in 2012.

10. Controlled Auctions Will Remain Important

As the M&A market continues to improve, we anticipate that controlled auctions will remain a preferred route for many sellers, particularly in the energy sector where they have been quite common. Because controlled auction transactions have been a major bright spot in the post-2008 Canadian marketplace, particularly in the mid-market, US firms looking for acquisitions north of the border will generally want to remain open to such a transaction as a means of entry into Canada. In its broad outlines, a controlled auction is similar in Canada and the US – however, there are important differences. For example, the Supreme Court of Canada’s 2008 BCE v. 1976 Debentureholders ruling established that Canada does not recognize a strict “Revlon” duty to maximize shareholder value in the context of change-of-control transactions. Instead, a director’s fiduciary duty is defined with respect to longer-term interests of the company and can include consideration of the interests of non-shareholder stakeholders (e.g. creditors or employees). It is not clear how broadly this concept will be applied.

With respect to the procedural aspects of controlled auctions, there is no reason to expect any change to Canada’s tradition of judicial deference to seller-established auction rules.

Finally, since Canada’s recent abolition of withholding tax on interest payments to foreign lenders, we are seeing more private equity and other financial buyers rely on their US-relationship banks for committed financing (often without commitment fees) at early stages of auction processes when success is still uncertain. This is often advisable because Canadian acquisition financing markets are generally more limited than their US counterparts.

Court rejects application of the prudent investment test to collective bargaining agreements

Stikeman Elliott LLP — Wed, 22 Feb 2012 11:38:04 -0500

Glenn Zacher and Patrick Duffy -

In two appeal decisions released this past week, the Ontario Divisional Court rejected the application of the “prudent investment test” to forecast costs under collective bargaining agreements negotiated between a utility and its unionized employees.

The prudent investment test is a regulatory principle that was first articulated by Justice Brandeis of the United States Supreme Court in the 1923 decision of Southwestern Bell Telephone Co. v. Public Service Commission. The purpose of the prudent investment test is to protect utility shareholders in respect of past investments in large capital projects that later prove to be unnecessary. Because of the long lead times for constructing infrastructure projects, courts and regulators have ruled that it would be unfair to utility shareholders to assess the prudence of the investment with the benefit of hindsight. Instead, managerial prudence is initially assumed and any subsequent challenges are assessed on the information available to a utility’s management at the time the investment was made.

In their respective rate cases before the Ontario Energy Board, Ontario Power Generation (OPG) and Hydro One Networks Inc. (HONI) argued that the Board was required to presume the prudence of their claimed compensation costs. They argued that the costs were set by previously negotiated collective bargaining agreements and the Board was limited to assessing the options available to the utility at the time it entered into the agreements. As successors to Ontario Hydro, the utilities had historic collective bargaining agreements that in some cases had a no strike/lockout provision that required disputes to be settled by arbitration. Effectively, the utilities were arguing that the Board was required to defer to the settlement negotiated between the utility and its unions or, where no settlement could be reached, to the decision of the labour arbitrator.

The Board disagreed. Rather than being limited to assessment of the utilities options in the collective bargaining process, the Board held that it could rely on benchmarking studies that compared the performance of the utilities with their industry peers. These studies showed high staffing levels, excessive compensation and, in the case of OPG, that the performance of its nuclear business unit was poor. Accordingly, the Board disallowed $145 million in compensation costs for OPG and $31 million for HONI. In disallowing these costs in OPG’s case, the Board recognized the constraints imposed by the utilities unionized workforces (and moderated its disallowance in this respect), but nevertheless determined that ratepayers should only be required to bear reasonable costs.

Each of the Board’s decisions was appealed to the Divisional Court. The Court heard the two cases together and issued companion decisions dismissing both appeals. In endorsing the Board’s decisions, the Divisional Court ruled that the Board, as a “market proxy”, needs the ability to consider how each utility was performing in comparison to its peers and cannot be limited to the type of retrospective review advocated by the appellants. This is particularly important in circumstances where the agreements were negotiated between a regulated monopoly that passes its costs onto to customers and a “near second monopoly” on labour in form of the unions. If the Board was bound to the outcome of the collective bargaining process, it would not be able to perform its statutory function of promoting market efficiency and protecting consumers. Further, the Court noted that, unlike other cases where the prudent investment test applies, the total compensation costs are not set solely by the collective bargaining agreements and the utilities have the ability “to manage, on a go-forward basis, to reduce total compensation costs within the framework of those agreements.”

The decisions discussed in this article are Ontario Power Generation v. Ontario Energy Board, 2012 ONSC 728 and Power Workers Union v. Ontario Energy Board, 2012 ONSC 1080. Glenn Zacher and Patrick Duffy acted as counsel for the Ontario Energy Board on the OPG appeal.