Canadian Energy Law : Lawyers & Attorneys for Environmental Energy Law

The MOE has directed the OPA to open the Small FIT application window as soon as possible and follow through with awarding 200MWs of projects. Additionally, the MOE directed the OPA to continue to develop rules and a contract as soon as possible for applicants with unconstructed buildings wishing to apply to Small FIT.

Ground Mounted Solar Photovoltaic Projects Siting

The directive provides further restrictions on the siting of ground-mounted solar photovoltaic projects (GM Solar Projects) larger than 10kW. These restrictions are to apply to rural zoned lands with multiple primary uses, where the residential is one such primary use (Rural Lands) and rural/agricultural zoned lands with abutting residential uses (Abutting Residential Lands).

For Rural Lands and Abutting Residential Lands, the MOE directed the OPA not to award new FIT contracts or consent to a site amendment of an existing FIT contract unless the Supplier commits to the three conditions. First, for GM Solar Projects between 10kW and 10MW on or proposed to be on Rural Lands, the Supplier must implement a minimum setback of 20 meters from all property lines. For GM Solar Projects larger than 10MW on Rural Lands or for GM Solar Projects larger than 10kW on Abutting Residential Lands, a 100 meter setback from all property lines is required. In each case, the 100 meter setback may be reduced to 20 meters if the municipality in which the GM Solar Project is located (Relevant Municipality) provides a resolution agreeing to such a reduction. Second, the Supplier must visually screen the GM Solar Project from bordering properties zoned to permit residential as a primary use. Third, the Supplier must make arrangements to maintain the visual screen of the GM Solar Project for the term of the FIT contract.

These conditions, among others, will not apply to existing FIT contract Suppliers who, prior to April 5, 2012, notified the OPA, the Relevant Municipality or the MOE in writing of the Supplier’s proposed site amendment and who provide evidence of such written notice to the OPA no later than Sunday, December 23, 2012 (Exempt Suppliers). However, the MOE has directed the OPA to make reasonable efforts to negotiate with Exempt Suppliers to include the setbacks, visual screening and maintenance arrangements for Solar Projects.

Community and Aboriginal Set-Aside

In an effort to prioritize community and Aboriginal participation, the directive allocates 100MW of contract capacity set-aside (“CCSA”) divided as follows:

For Small FIT:

• 18.75MW for First Nation equity participation projects;
   
• 7.25M for Small FIT Metis equity participation projects; and
   
• 25MW for Small FIT community equity participation projects.

For Large FIT:

• 18.75MW for First Nation equity participation projects;
   
• 7.25M for Metis equity participation projects; and
   
• 25MW for community equity participation projects.

In all cases, CCSA projects must have 50% community or Aboriginal equity participation.

In the event that any category of Aboriginal (First Nation or Metis) CCSA target is not reached, then, to the extent there are additional CCSA projects in another category that exceed the target, those projects will be considered in the undersubscribed category.

Once the CCSA targets are met or once all CSSA applications have been processed, then the OPA will no longer prioritize CCSA projects and will process applications for all projects based on prioritization points set out in the Prioritization Points Table in Appendix A of the July 11, 2012 Direction, which may include community or Aboriginal projects. 

The OPA has been directed to review FIT applications to verify that those applications seeking community or Aboriginal participation project priority points meet required economic interest criteria.

Re-launching the Community Energy Partnerships Program (CEPP) and Aboriginal Renewable Energy Fund (AREF)

The MOE has directed the OPA to align program rules and funding parameters of the CEPP and AREF to provide for Pre-FIT funding or Partnership Funding. Pre-FIT funding is meant to provide financial support to community and aboriginal projects submitting a FIT application. Partnership Funding provides aboriginal projects with support to perform due diligence associated with entering partnership agreements. Total funding from the CEPP and AREF is not to exceed $500,000 each. A number of rules limiting funding will apply. The CEPP will be developed and delivered through one or more third party provider.

Connecting Constrained MicroFIT Projects

The MOE has provided the OPA with a number of options to connect otherwise constrained MicroFIT projects. 
 

The proposed amendments to the PPS will make it a “greener” document in terms of protecting human health and the natural environment and recognizing the importance of matters such as sustainability, transit-supportive development, climate change mitigation and adaption, biodiversity and linkages, management of water and natural resources and energy efficiency and conservation in the development of communities that are both strong and healthy. The PPS will continue to speak to the promotion of opportunities for energy generation facilities to accommodate current and projected needs, and the use of renewable energy systems. These policies are relevant to those renewable energy systems/projects that are not exempt from the amendments made to the Planning Act pursuant to the Green Energy Act and are therefore also subject to the PPS.
 

A number of proposed changes to the PPS may be beneficial to renewable energy systems subject to municipal approvals under the Planning Act. For example, zoning and development permit by-laws will be explicitly required under Section 4.7 to be kept up to date with official plans which is in accordance with Planning Act provisions, however, they will be newly recognized as important implementation tools of the PPS and will also need to be kept up to date with the PPS. By extension, zoning and development permit by-laws will therefore need to promote the development of renewable energy systems.

As an additional direction to municipalities to promote renewable energy, Section 1.8.1 will require that planning authorities support energy conservation and efficiency, improved air quality, and climate change mitigation and adaptation through land use and development patterns which among other matters, include the promotion of design and orientation which maximizes opportunities for the use of renewable energy.

Additional siting flexibility may also result from the deletion of previous references to where renewable energy systems could be located-settlement areas, rural areas and prime agricultural areas.

Notable changes to Definitions Section 6.0 relevant to renewable energy systems include the expansion of the definition of “renewable energy” to include biogas in addition to wind, water, biomass resource or product, solar and geothermal energy. Additionally, biomass has been added to the definition of “agricultural uses”. These additional changes will further promote the development of renewable energy systems that are subject to municipal Official Plans, zoning and development permit by-laws.
 

Changes to Project Specifications
As was proposed in the draft contract, the OPA will be able to arbitrarily refuse any change to the specifications of a project listed in the contract or the application.  Based on FIT 1.0 experience, this could include minor changes to the connection point, GPS location, feeder and so on.  Under FIT 1.0 the OPA could not unreasonably reject those changes.  Developers should be cautious to carefully review and double-check their site specifics before submitting an application.

Pre-NTP Termination
The final version of the contract affirms the OPA’s right to assume any security paid by the developer as damages if the developer opts to terminate the contract before it obtains “notice to proceed”.  This is consistent with the OPA’s current practice.  The OPA is also entitled to terminate the contract before the notice to proceed is issued provided any security payments are returned to the developer and documented pre-construction costs, up to a maximum limit.

The final version of the contract clarifies that the “Stop Work Direction”, by which the OPA can force a developer to stop all construction and development, can only be issued if the OPA exercises its pre-NTP termination right, which was not clear in the draft contract.

Post-NTP Termination
Developers hoping to finance their projects will likely breathe a sigh of relief as the right the OPA had in the draft contract to terminate the contract at its convenience after notice to proceed was issued has been removed from the final version of the contract. Many lenders had suggested to us that they would not be prepared to lend to FIT 2.0 projects if the termination-for-convenience right remained in the contract.

Deadline Changes
While small FIT projects used to be able to submit their NTP requests at any time before the milestone date for commercial operation, an NTP request under FIT 2.0 contracts must be submitted at least 3 months before the milestone date.  Large FIT projects will still need to submit the request at least 6 months before the milestone date as failure to do so is an event of default that entitles the OPA to terminate the contract. Under the final version of the contract, large FIT projects that miss that deadline must provide whatever information the OPA requires, which will include at least status information regarding the project and a “credible and detailed project plan” demonstrating how the project will achieve commercial operation.

The milestone date for rooftop solar projects has been reduced to 18 months following the contract date whereas, under FIT 1.0, such projects had the same timeframe as those for projects using other types of fuel (i.e. 3 years).  However, rooftop solar projects can maintain the 3 year milestone date if they are part of a portfolio of two or more projects and the developer’s application for a designation as a portfolio is accepted by the OPA.  Developers should be cautious applying for portfolio status – once a project is part of a portfolio, the OPA will consider it to always be part of the portfolio and the developer may not be able to sell each portfolio in parts.

Term and MCOD Penalties
While under the FIT 1.0 contract, a developer could miss the milestone date and buy-back the portion of the 20-year term lost by the delay by paying liquidated damages, the term of FIT 2.0 contracts will now start to run on the milestone date and a term “buy-back” is not available.  Accordingly, each day after the milestone date before the project achieves commercial operation is one day of lost FIT revenue.  We expect this change will cause lenders to exert significant pressure to ensure projects achieve commercial operation on or before their milestone dates.

The additional $0.25/kW payable per day as liquidated damages for failing to reach commercial operation by the milestone date, as contemplated in the draft contract, has been deleted.

Contract Capacity
The OPA has reverted to substantially the same obligation as previously existed under the former FIT regime regarding meeting contract capacity, meaning a developer can satisfy its obligations by building a project which is able to produce at least 90% of its contract capacity at the commercial operation date.  As in the FIT 1.0 contract, if the project is above 90% but below 100% at commercial operation, the developer can still bring the project’s contract capacity up to 100% within 1 year after commercial operation.

Rooftop solar facilities, however, cannot be overbuilt by more than 120%.  In particular, the DC nameplate rating of the installed modules cannot be more than 120% of the AC nameplate rating of the installed inverters.

Domestic Content – Operation and Maintenance
The OPA has revised the domestic content obligations of wind and solar projects.  In addition to being developed and constructed in order to meet the minimum required domestic content level (e.g. 50% for wind and 60% for solar, based on the satisfaction of specific designated activities), each of those projects are also required to operate and maintain the project in accordance with the minimum required domestic content level.

Although the contract entitles the OPA to audit at any time, the developer is only required to retain records for a limited period of time and the developer only reports on its domestic content activities within 90 days after achieving commercial operation.  These audit and reporting obligations were not changed in the final version of the contract.  Thus, while the developer has an obligation to maintain the facility in accordance with its domestic content obligations, it’s unclear how it would demonstrate those obligations after it submits its domestic content report and its record retention obligation expires.

Regardless, developers should be cautious of this obligation when considering which designated activities it will rely upon to meet its domestic content obligation and whether the warranties offered by the equipment suppliers for those designated activities will satisfy the designated activities.  Developers should also take this obligation into consideration when looking at its insurance coverage.

Domestic Content Report
The domestic content report regime has improved from the draft 2.0 contract. The OPA is now required to review and respond to the report within 90 days of its receipt of the report rather than having a “reasonable” time.  Both parties are required to cooperate after the OPA requests any additional information in order to finalize the report within a reasonable period.  Under the FIT 1.0, the OPA had 60 days to review, then the developer had 30 days to respond and the OPA then had 30 more days to review the response.

REA Representation
As was the case in the draft, developers represent that they have made due inquiry into the requirements to obtain a renewable energy approval (where applicable).  The effect of this representation is that the developer will not be able to claim force majeure for any issue related its REA which ought reasonably to have been known to the developer at the time it made its application.  Developers requiring an REA should perform due diligence investigations prior to applying for a 2.0 FIT contract to ensure it can reasonably obtain an REA.

Participation Points
Developers who are relying on community, aboriginal or education or health equity participation should carefully review provisions relating to participation projects and the applicable definitions.  If, for instance, a developer has a community co-op as an equity participant and that co-op fails to maintain the minimum required number of members (who must, in addition to being a co-op member, also own land in the community in which the project is built over a rolling 2 year window), the OPA will be entitled to terminate the FIT contract.  Although there are certain rights to cure that kind of a default, it may be difficult for the developer to recruit new members to a co-op or to convince co-op members to remain landowners in the area.

Those relying on points for hosting the project on an education or health facility should seek comfort that the facility will remain an education or health facility for at least 5 years after commercial operation. Subject to the ability of the supplier to cure by either becoming a participation project or replacing the education or health host with a new education or health host (both of which may be difficult to do after the project is operational), if the facility changes use before such time (which could occur through no fault of the developer), the developer will be in breach of the FIT contract.  While still risky, the 5 year milestone will be more palatable to developers than the 10 year milestone contemplated by the draft contract.
 

Contract Capacity Set-Aside Projects

As mandated in the July 11, 2012 Directive, the Rules will continue to prioritize community and aboriginal participation projects. All applications that have a community or Aboriginal participation level equal to or greater than 15% will continue to receive 3 Priority Points and be eligible for a price adder under the FIT Contract; however, applicants that have a community participation level in excess of 50% that is held by a co-operative with membership of 50 or more local property owners or an Aboriginal participation level in excess of 50% (collectively referred to as “Contract Capacity Set-Aside Projects”) will now also receive a higher ranking than all other applications. Contract Capacity Set-Aside Projects will be ranked amongst other projects of the same class firstly, as to the number of Priority Points they receive, then by time stamp, and lastly if there is still a tie, by random selection.

Applicants may apply for designation as a Contract Capacity Set-Aside Projects by so identifying in their application. If so designated by the OPA, a failure to maintain a participation level of greater than 50% will constitute an event of default leading to a termination right on the part of the OPA.

The Rules now permit applicants with pre-existing applications to assign applications to an assignee for the purpose of designation as a Contract Capacity Set-Aside Project; however, any such assignment must be structured in compliance with other restrictions in the Rules relating to assignment.

Project Siting

A number of clarifying changes have been made in the Rules regarding project siting, including as follows:

• Projects (other than waterpower projects) must not be located 50 km or more from the proposed connection point;
• The definition of “Site” has been revised to expressly exclude land on which connection lines are located, and accordingly these lands are not subject to the restrictions in the Rules limiting the ability of applicants to site multiple projects on a deemed single property;
• Unless a project is located on provincial Crown lands, an application must now include evidence of access rights for all of the proposed Site (which as mentioned above, excludes connection line lands). Under the Draft Rules, it was only necessary to submit evidence that the applicant had site control over lands sufficient to build and operate its project;
• The Rules now provides that a property is considered to “Abut” another property if the properties share a common border or are only separated by a right-of way having a width of not greater than 15 meters. This change, in turn, helps to clarify whether certain properties would qualify as a deemed single property and whether a ground-mount solar project would satisfy siting rules that prohibit such projects from abutting a residential property; and
• There are a number of special considerations and evidentiary requirements now contained in the Rules for projects located on provincial Crown lands and for waterpower projects.

Additional details have also been provided in respect of the restrictions and documentation required for siting ground-mount solar projects. In the Draft Rules, there was a blanket restriction preventing ground-mount solar projects from being sited on organic and Class 1, 2, and 3 soils. Although the drafting of the Rules is not clear, it appears that projects can now be located on properties that contain Class 1, 2, or 3 soils or organic soils as long the project itself is not located on the portion of the property containing Class 1, 2, or 3 soils or organic soils, or so long as the project is located on lands that are used for certain non-agricultural purposes set out in the Rules (such as lands used as an aerodrome, closed landfill, military installation, contaminated property, or for industrial use or lands that are owned by a municipality).

Multiple Projects

Deemed Single Property

Pursuant to the Rules, there is a limit on the aggregate contract capacity that can be located on a deemed single property of 10 MW for solar and 50 MW for waterpower projects, which aggregate limit now includes the contract capacity of any renewable energy generating projects under contract with the OPA or the Ontario Electricity Financial Corporation.

Disclosure

The OPA now requires an applicant and any applicant related person to disclose whether it has submitted a separate application in respect of a separate project under the FIT Program.

Rooftop Portfolios

An applicant may apply to the OPA for a Rooftop Portfolio designation if it has a portfolio of two or more rooftop solar facilities with FIT Contracts and with an aggregate contract capacity greater than 15 MW. Rooftop Portfolios will benefit from an option to extend the Milestone Date for Commercial Operation under the FIT Contract to 36 months following each Contract Date; however, such projects may not be separately assigned under the FIT Contract.

Existing Applications

There are a number of changes to the transitional provisions for pre-existing applications in the Rules, as follows:

• A resubmitted application may not have a contract capacity that exceeds that specified in the pre-existing application;
• An applicant must still be the same person and have the same name as the pre-existing applicant, except as follows:
• The name of the applicant in a resubmitted application may be changed (i) for the purpose of qualifying the project as a participation project or a Contract Capacity Set-Aside Project; or (ii) where the name of the applicant has changed due to circumstances other than an assignment or a change of control, with the consent of the OPA; and
• A pre-existing applicant may assign its application in prescribed circumstances set out in the Rules.

 Pricing

The Rules provide that the contract price and the price adder will be those in effect at the time a contract award is made, not at the time that the application was submitted. If the prices set out in the offer for a FIT Contract are less than those at the date of the application, the applicant may elect not to enter into a FIT Contract and the OPA will return all application security.

Next Steps

The OPA has announced that the application window for small FIT projects is anticipated to open on October 1, 2012 and remain open until November 30, 2012. The OPA anticipates awarding 200 MW of small FIT contracts. The OPA will announce the timing for the large FIT project application window once details are finalized, but the OPA has not yet given any indication of when that window will open.

Once FIT contracts have been offered to successful applicants, all applications that were submitted in the first application window that do not receive contracts and those pre-existing small FIT applications that are not resubmitted in the first application window will be terminated and their time stamp will be lost. Application security for such applications will be returned.

Community and Aboriginal participation projects will continue to be prioritized. All applications with greater than 15% community or Aboriginal equity interest will still receive 3 priority points and those applications with greater than 50% community or Aboriginal equity interest will be offered contracts in advance of all other applications within the same application window.

The directive indicates that the FIT contract will be revised such that, where a project has received priority on the basis of a 50% or greater community or Aboriginal equity interest, any change in the ownership that would result in such ownership falling below the 50% threshold is prohibited and will constitute an event of default leading to a termination right on the part of the OPA. The OPA termination right will arise following a six-month cure period during which time the supplier can remedy the default. There will also be a six-month cure period in the instance of the community or Aboriginal equity interest falling below the 15% threshold required in order to be awarded prioritization points. With respect to community equity interest projects, in order to have the benefit of the cure period, a supplier must report the change in the membership of the co-operative within 12 months of any change that leads the supplier to fall below the 50% or 15% equity interest threshold.

Project Siting

With respect to project siting, as described in our April 9, 2012 post, the draft FIT 2.0 Rules prohibited ground-mount solar projects from being located on a site comprised (in whole or in part) of CLI Class 1, 2 or 3 Lands, Specialty Crop Areas or CLI Organic Lands. The directive provides that while a ground-mount solar facility cannot be located on any of these lands,  the site can contain a mix CLI Class 1, 2 or 3 Lands, provided that the ground-mount solar facility will not actually be located on the CLI Class 1, 2 or 3 Lands, as evidenced by a peer reviewed soil study. In addition, non-hydroelectric projects will not be permitted to be located 50 km or more from their proposed connection point to the existing transmission or distribution grid. This distance will be measured based on the distance to the connection point from land which the supplier has access rights over at the time of application.

FIT Contract Changes

As discussed in our earlier post, the draft FIT 2.0 Contract contained a new right for the OPA to terminate the contract for convenience at any time following Notice to Proceed. The directive appears to remove this provision and states that only those rights of termination in favour of the OPA which existed in prior versions of the FIT Contract shall be contained in the final FIT 2.0 Contract. It is not clear whether this also applies to the right of the OPA to give a “Stop Work Direction” under the draft FIT 2.0 Contract.

The directive also provides that, with respect to rooftop solar facilities, the Milestone Date for Commercial Operation will continue to be 18 months following the Contract Date, except in the case of a “portfolio of rooftop solar facilities greater than 15 MW”, for which the Milestone Date for Commercial Operation will be 36 months following the Contract Date.

The OPA is expected to release revised drafts of the FIT and microFIT Rules and Contract to reflect this directive and also to open an application window for microFIT and Small FIT Contracts.

The federal government projects that over the course of the next ten years, $500 billion worth of new projects are expected to start operating in Canada’s energy and mining sectors and the new legislation is intended to improve the regulatory conditions for business investment. It will be interesting to see how the global market responds to these regulatory changes and how natural resource investment unfolds in the upcoming decade.

Businesses would be able to apply to the program through two streams. Stream 1 would be available to companies looking to establish new operations in Ontario. To be eligible, companies would be required to make a minimum investment of $250 million that supports new technology, products or processes. Proposals from companies will be evaluated according to expected job and economic benefits. If a proposal is accepted, long-term contracts would be offered through the Ontario Power Authority, depending on the size of the proposed project.

Stream 2 would be available to companies which have already established operations in Ontario. To be eligible, companies would be required to expand their current operations. Such companies would be required to pay the market rate for electricity until 2020, after which they would qualify for long-term contracts at the reduced rates whose terms would depend on the size of the proposed project.

The Ontario government expects to consult with industry over the next three to four months. It plans to provide specific rules by Fall 2012 with a full program launch in January 2013. The program would not affect electricity rates for consumers. 

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.

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.

 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.

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. 

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.

Quebec’s greenhouse gas regulatory regime, mainly the Regulation respecting mandatory reporting of certain emissions of contaminants into the atmosphere and the Regulation respecting a cap-and-trade system for greenhouse gas emission allowances, is adopted pursuant the EQA.

In addition to greater fines, monetary administrative penalties may now be imposed by the Ministry’s relevant regional office director based only on his assessment of the file after a violation of the EQA is observed, without further investigation, collection of evidence or judicial procedures. A notice of violation will simply be sent, informing the contravener of the violation and amount of the fine, which may vary between $250 and $10,000, depending on the nature of the offence and whether it applies to a legal or natural person.

These amendments have an even greater impact on directors and officers whose participation in an offence under the EQA no longer has to be established by the Ministry to incur liability. Rather, if a legal person commits an offence under the EQA, its directors and officers are presumed to have committed the same offence unless they demonstrate their diligence.

The capping and reduction of GHG emissions will start officially on January 1, 2013. Starting on January 1, 2013 some 75 operators, primarily in the industrial and electricity sectors, whose annual GHG emissions equal or exceed the annual threshold of 25 kt CO2e (25 thousand tonnes of carbon dioxide equivalent), will be subject to the capping and reduction of their GHG emissions.

Starting on January 1, 2015, the operators of businesses that distribute fuel in Québec or import fuel for their own consumption, and whose annual GHG emissions due to its combustion reach or exceed the annual threshold of 25 kt CO2e, will also be subject to capping and reduction.

The Government of Québec has stated that, unlike traditional regulation, where companies must not exceed an emission standard (a strict limit on the discharge of pollutants), the cap and trade system will give companies flexibility in planning their short, medium and long term investments. In effect, the system will allow companies to buy emission allowances on the market until they are ready to modernize or replace certain equipment. Companies that reduce their GHG emissions below the regulatory requirement would have an allocation of emission units that is higher than what they actually produce. By selling their excess units, such companies could either recover part of their investments or use the proceeds to engage in further optimization.

Links to our previous blogs on this Regulation are available here.

Amendments are also proposed to calculation methods applicable to many other industry sectors in order to harmonize them with WCI requirements introduced in 2010, and a section on the estimation of missing data is added to all calculation methods.

Many articles are modified to clarify the scope of the regulation, applying reporting thresholds by establishment rather than enterprise, except for certain enterprises in the energy sector, which are considered as establishments under the proposed changes.  In addition, the number of years during which the emissions of an establishment must be below the reporting threshold to exempt it from reporting is proposed to be increased from 3 to 4 consecutive years.

Pursuant to the draft regulation, filing of the verification report will be required at the same time as the emissions report, on June 1st, whereas the current regulation allows the verification report to be filed three months after the emissions report, on September 1st. Furthermore, in addition to the current requirement for the verifying organization to be ISO 14065 accredited, the verification will have to comply with an ISO 17011 program.

Before the implementation of the OGAA, the regulatory framework governing oil and gas activities was over 40 years old. Since then, oil and gas activities have expanded, new technologies have developed and expectations relating to stakeholder input and environmental responsibility have evolved. As a result, the OGAA attempts to address these changes by balancing economic goals with environmental and socially responsible development.

The new legal regime consists of the OGAA itself as well several regulations passed under the Act. The Oil and Gas Commission, the regulatory agency that oversees oil and gas operations in British Columbia, is continued under the OGAA. The Commission has expanded compliance and enforcement powers and has the ability to set technical safety and operational standards. The Board of the Commission as well as the Provincial Cabinet has the power to make regulations under the OGAA. The Board has exercised this power to make regulations related to consultation and notification requirements, geophysical activities, drilling and production activities, pipeline and liquefied natural gas facilities, and fees, levies and security. The Provincial Cabinet has introduced the Oil and Gas Activities Act General Regulation and the Environmental Protection and Management Regulation. The Cabinet also amended regulations which fall under other acts, such as the Petroleum and Natural Gas General Regulation.

A key aspect of the OGAA framework is the expanded consultation and notification requirements that set out who must be consulted before an application is submitted to the Commission. These requirements do not replace the established processes for consultation by the Commission with First Nations.

The framework also establishes a new administrative appeal and review process. Specified eligible persons have the ability to request a review of certain administrative decisions under the OGAA. For example, industry participants can request a review or appeal of a Commission decision regarding a permit and private land owners can appeal a decision regarding the issuance or amendment of a permit that covers their land.

The OGAA and the Environmental Protection and Management Regulation implement environmental standards for oil and gas activities. The regulation sets forth the Provincial Government’s environmental objectives for water, riparian values, wildlife and wildlife habitat, old-growth forests, resource features and cultural heritage resources. The Commission is required to consider these objectives when deciding whether to authorize an oil and gas activity.

The framework also gives the Commission expanded compliance and enforcement tools. For example, the Commission can now levy penalties that reflect the gravity and magnitude of a contravention, including consideration of the operator’s compliance history.

The OGAA website contains detailed information about the OGAA framework and provides a variety of training materials for industry participants.
 

This legislative silence has caused uncertainty as to ownership of coalbed methane on freehold lands where mineral title is split between the coal owner and the natural gas rights holder, and where the instruments at issue do not refer expressly to coalbed methane. In some instances, this has resulted in litigation between the coal owner and the natural gas rights holder, with both parties claiming ownership of coalbed methane.

The history of coalbed methane ownership in Alberta originates in late 1800s, when the Crown granted 25 million acres of surface and mineral land to Canadian Pacific Railway (“CPR”). The CPR subsequently sold this land to settlers, but reserved to itself an interest in “all coal”, “all coal and petroleum” or “all coal, petroleum and valuable stone”. Since natural gas was not reserved it was sold with the lands. This has resulted in the split title situation that exists today, where freehold landowners hold natural gas rights and the CPR’s successors and assigns hold the rights to coal.

Because the initial grants and subsequent instruments did not until recently speak to coalbed methane, Bill 26 aims to clarify ownership of coalbed methane in split title situations. By declaring coalbed methane to be and at all times to have been natural gas, Bill 26 provides certainty as to the inclusion of coalbed methane in initial natural gas grants.

Coalbed methane is a natural gas found in coal. Coal seams with coalbed methane potential are found underneath much of Alberta, especially in southern and central Alberta. Notably, a study by the Alberta Geological Survey found that Alberta’s coalbed resource may contain approximately 500 trillion cubic feet (Tcf) of coalbed methane. In contrast, the estimated ultimate potential of marketable conventional natural gas in Alberta is between 205-253 Tcf.

The Bill will come into force on Royal Assent. Depending on the amount of questioning from opposition, this could take anywhere from two weeks to several months.
 

Existing agreements entered into by the natural gas mineral owner, or their lessee, that specifically granted coalbed methane rights to the coal owner, or their lessee, will not be affected. The Bill also protects the Crown, coal owners, or their lessee, and surface owners from being sued by the natural gas owner, or their lessee, for coalbed methane extraction, production or removal prior to the Bill coming into force.

Coal seams with coalbed methane potential are found underneath much of Alberta. Notably, a study by the Alberta Geological Survey found that Alberta’s coalbed resource may contain approximately 500 trillion cubic feet (Tcf) of coalbed methane. In contrast, the estimated ultimate potential of marketable conventional natural gas in Alberta is between 205-253 Tcf.

To take effect, the Bill must receive Royal Assent. Depending on the amount of questioning from opposition, this could take anywhere from a week to several months.

The most significant element of Bill 235 is that it provides for rate regulation of suite metering providers by the Ontario Energy Board. This provision was included in Bill 235 despite the opposition of smart sub-metering providers, who argued before the legislature that the industry is competitive and does not require rate regulation. However, the legislation does provide the government and the Board with the ability to rate regulate some segments of the industry while leaving others subject to competition. It remains to be seen how the government and the Board will exercise that power.

In addition, the provisions of Bill 235 will empower the government to regulate issues such as:

• Specifications for suite meters
• Designating when the installation and use of suite meters is permitted or required
• Creating energy efficiency requirements for units with sub-meters
• Information obligations for suite meter providers and landlords to customers and tenants

Bill 235 will also add significant amendments to the Residential Tenancies Act, 2006, including new rules for landlords that intend to transition their units to suite metering. This includes requirements to obtain a tenant's consent, to provide a rent reduction, and to maintain a rental unit's energy efficiency in terms of insulation and major appliances.

The other major goal of the legislation is to provide greater consumer protection. According to the Minister, the Ontario Energy Board receives on average between 100 and 150 consumer complaints about the practices of gas marketers and electricity retailers every week. The new Energy Consumer Protection Act created by Bill 235 will provide greater protection to energy consumers and enable the Board to "crack-down" on industry practices that violate the new Act.

The Board will also have the power to regulate issues such as the form of contracts and invoices, the availability of information in other languages, contract renewals, extensions and amendments, and enhanced rights for contract cancellation including a 10-day cooling off period. The Board will also be able to make regulations on security deposits and service cancellations.

Finally, the legislation will also empower the Board to make regulations respecting the employees of energy providers. This includes the power to issue directives on employee training, identification requirements such as badges, and background checks on employees. Employees may also be subject to new licensing and insurance requirements.

Canadian industrial emitters face deadline for emissions reporting

The Department of the Environment has given notice that Canadian industrial emitters of GHGs have until June 1, 2010 to report their 2009 GHG emissions. The reporting deadline, which was established by Environment Canada, applies to facilities that emit over 50,000 tons of carbon dioxide equivalent (CO_2e) per year. Environment Minister Jim Prentice has indicated that more detailed regulations will be released prior to the Copenhagen talks.

The Western Climate Initiative releases essential requirements of mandatory reporting

The partners of the Western Climate Initiative (WCI) are comprised of seven U.S. states and four Canadian provinces, namely British Columbia (B.C.), Manitoba, Ontario and Quebec. Other U.S. states and Canadian provinces (Saskatchewan and Nova Scotia) are currently WCI observers.

The WCI has recently released its final version of the first group of Essential Requirements for Mandatory Reporting (ERMR). The ERMR requires owners and operators that are subject to the mandatory reporting requirements to submit annual GHG emission reports by April 1 of each year for emissions in the previous calendar year. The initial reporting requirements will apply to the owner or operator of a facility that emits 10,000 metric tons of CO_2e or more per year in combined emissions, from one or more of the listed source categories, in any calendar year starting in 2010. Accordingly, companies subject to the ERMR that commenced operations prior to 2010 will be required to report their 2010 GHG emissions by April 1, 2011.

Subsequent to the year 2010, the ERMR contemplates that the reporting requirements will also apply to: (1) all importers of electricity (both retail providers and marketers) that import electricity into the WCI region, (2) any supplier that within the WCI region distributes transportation fuels in quantities that when combusted would emit 10,000 metric tons of CO_2e per year or more, in any calendar year starting in 2010, and (3) any supplier that distributes within the WCI region residential, commercial and industrial fuels in quantities that when combusted would emit 10,000 metric tons of CO_2e per year or more, in any calendar year starting in 2010.

The impact of the ERMR regime

In order to comply with the WCI-imposed obligations, the B.C., Manitoba, Ontario and Quebec provincial governments are each moving forward with legislation designed to implement the ERMR regime. For example, the B.C. government has announced its intention to introduce a mandatory GHG-emissions reporting regulation during the fall of 2009. The Ontario government has recently stated that its intention is to harmonize Ontario reporting requirements with those of the WCI (as well as with any U.S. federal trading system). Quebec has passed Bill 42 (An Act to amend the Environment Quality Act and other legislative provisions in relation to climate change), which establishes the reporting of GHG emissions by certain categories of emitters to be determined by regulation.

It should be noted that other Canadian provinces have also moved towards the adoption of legislation that will require companies to report GHG emissions. For example, in 2004, Alberta passed the Specified Gas Reporting Regulation, which continues to require industrial facilities that emit more than 100,000 tons of CO_2e in a calendar year to submit annual emission reports. Additionally, on August 14, 2009, the government of Nova Scotia released the Greenhouse Gas Emission and Air Pollutant Regulation. This regulation requires facilities located in Nova Scotia that emit more than 10,000 metric tons of CO_2e in a calendar year to submit annual emission reports.

Measuring and reporting GHG emissions is a labour-intensive process

In order to comply with the various provincial and/or federal legislation that may apply to them, companies will need to determine whether or not they emit the quantity of GHGs that triggers the various legislative reporting requirements. In order to do so, companies will need to measure their GHG emissions in accordance with the prescribed methods set out in the various legislation applicable to them. Measuring GHG emissions will be labour-intensive and will require that a detailed and mapped-out process be followed. Additionally, while governments have generally recognized the importance of standardized measuring methods (so as to help ensure the fair operation of multi-jurisdictional carbon cap-and-trade programs), there is no certainty that all legislation will contain common measuring techniques.

In the event a company is subject to GHG reporting requirements, the applicable legislation will also set out other obligations that the company will need to spend time considering. Typically, these obligations will include monitoring, record-keeping and retention requirements, as well as data-verification requirements. It can also be expected that GHG legislation will increasingly require emitters to reduce their GHG emissions towards established targets and/or to cover their GHG emissions with prescribed emission allowances, units or credits. 

Canadian reporting issuers and the impact of climate change

As was stated by the Canadian Institute of Chartered Accountants (CICA) in a Management's Discussion and Analysis (MD&A) disclosure guide published in November 2008 (the Guide), investors are increasingly seeking more detailed and nuanced information about how reporting issuers view the impact of climate change, in order to assess its effect on a company's current and future financial conditions, results of operations and cash flows. The CICA noted that the business impact of climate change will require reporting issuers - even those that do not directly produce GHG - to implement strategies, both to adapt to the effects of climate change on the reporting issuer's business and, in other cases, to take action to mitigate the extent of their GHG emissions. The CICA Guide outlines five types of information in MD&A that should address climate-change issues:

Business strategy. MD&A should present investors with an overview of the climate-change factors that the reporting issuer has factored into its business strategy.

Risks. MD&A should describe the risks presented by climate change on the reporting issuer, including physical risks (e.g. changes to weather patterns), regulatory risks (e.g. heightened regulatory oversight and scrutiny), reputational risks (e.g. negative customer perceptions of reporting issuers failing to address climate-change issues), litigation risks (e.g. lawsuits against heavy GHG emitters) and any other material risks.

GHG emissions. To the extent that it is material to evaluating the performance and future prospects of a reporting issuer, a reporting issuer's direct and indirect GHG emissions and related intensity data should be discussed in MD&A.

Financial impacts. The impact of climate change on financial operations, cash flows and the financial condition of the reporting issuer should be discussed in MD&A, along with the future financial implications.

Governance processes. MD&A should describe the governance and organizational processes used by the reporting issuer in identifying and managing climate-change issues.

While Canadian securities regulators have not yet specifically mandated the disclosure of climate-change strategies in a reporting issuer's public disclosure record, the requirements of National Instrument 51-102 Continuous Disclosure Obligations (NI 51-102), including the requirements applicable to a reporting issuer's MD&A, are sufficiently broad so as to capture such issues.

A reporting issuer's MD&A, for example, is required to discuss the effect of "known trends, demands, commitments, events or uncertainties" on the reporting issuer's "financial condition, results of operations and cash flows." Moreover, a reporting issuer's annual information form (AIF) is required to disclose such things as the "financial and operational effects of environmental protection requirements" on its financial position, including capital expenditures. An AIF is also required to detail risk factors, such as environmental risks, and "regulatory constraints.and any other matter that would be most likely to influence an investor's decision to purchase" the securities of the reporting issuer. As climate-change concerns continue to escalate and, as a result, increasingly stringent legislation is enacted , regulatory authorities may in the future require Canadian reporting issuers to provide more prominent and expansive disclosure with respect to the impact that climate change will have on their business.

In February 2008, the Ontario Securities Commission (OSC) issued Staff Notice 51-716 - Environmental Reporting, outlining the results of a targeted review by OSC staff of the degree to which Canadian reporting issuers were adequately disclosing information about so-called "environmental matters" in their annual financial statements, MD&A and AIFs. The OSC's written findings suggest that, at the time, the disclosure of certain Canadian reporting issuers with respect to potentially material environmental matters was inadequate and, in certain instances, consisted of insufficient, boilerplate disclosure.

Staff Notice 51-716 should continue to serve as a signal to Canadian reporting issuers that, regardless of whether or not they are subject to specific GHG-emission or other environmental reporting requirements, it is necessary for them to seriously consider the effect of environmental matters and climate change on their business and to ensure that such matters are adequately disclosed to investors. 

The stated purpose of the discussion paper entitled Staff Discussion on the Regulatory Treatment of Infrastructure Investment for Ontario's Electricity Transmitters and Distributors (Discussion Paper) is to fulfill the objectives of the GEGEA by incentivizing investment in distribution and infrastructure while ensuring that the interests of ratepayers continue to be protected. The Discussion Paper draws heavily on FERC's Rule 679, Promoting Transmission Investment through Pricing Reform, by identifying a range of mechanisms for alternative cost treatment of infrastructure investment, some or all of which could be applied in the context of a cost of service review, a multi-year rate adjustment mechanism or a specific rate application (or in the course of approving distributors' or transmitters' infrastructure investment plans as mandated by the GEGEA). The alternative mechanisms for cost recovery identified in the Discussion Paper include recovery of costs for abandoned facilities, accelerated cost recovery, the inclusion of construction work in progress (CWIP) in rate base, accelerating depreciation and providing for incentive-based ROE.

Similarly, in accordance with FERC's view, OEB staff suggest that beyond identifying certain investments that would be presumed to qualify for alternative cost treatment, it is not appropriate to be more prescriptive. Staff suggest that establishing more prescriptive criteria would limit flexibility by pre-judging which projects are eligible for alternative treatment and limiting the ability of applicants to request a combination of alternative cost mechanisms. Accordingly, staff suggest that the Board "should exercise its discretion to allow alternative treatment on a case-by-case basis for appropriate infrastructure investments by electricity transmitters and distributors in a manner that facilitates the achievement of the Government's policy objectives as reflected in the GEGEA while protecting the interests of ratepayers".

OEB staff have outlined 26 issues for written comment. These issues include the appropriateness of the foregoing alternative cost mechanisms and whether the OEB should be more prescriptive as to which types of investments qualify for alternative treatment and which do not. Staff have asked that written comments be filed by July 7, 2009 and have outlined the framework for cost award eligibility.

Feed-in tariffs

Arguably the most fundamental element of the GEA is that it paves the way for North America's first feed-in tariff program (FIT) which aims to simplify current procurement methods and provide incentives for investments in renewable energy technologies through standardized prices and long term contracts. FITs will replace the Ontario Power Authority's current request for proposal process and standard offer program.  On March 13, 2009, the Ontario Power Authority released draft FIT rules and a draft FIT price schedule.   It is anticipated that the Ontario Power Authority will finalize its FIT program this summer with the passage of the GEA.

Project approval streamlining

The approvals process for renewable energy projects will be streamlined through a one-window, one-permit process with province-wide standards. The GEA also creates a Renewable Energy Facilitation Office within the Ministry of Energy for the purposes of facilitating the development of renewable energy projects, including working with proponents of renewable energy projects and other ministries to shepherd projects through the various approvals processes and through engagement with local communities.   

Transmission and distribution

The GEA requires transmitters and distributors to connect renewable energy generation facilities provided that certain requirements are met. The GEA further empowers the Minister to direct the Ontario Energy Board  to take such steps, including through license amendments, to require transmitters, distributors and others to reinforce, enhance or expand their transmission, distribution or other systems to accommodate the connection of renewable energy generation facilities.

Conservation

The GEA will help promote a culture of energy conservation in Ontario by setting energy conservation targets for consumers and distributors and encouraging the development of small-scale renewable energy projects.

Smart grid

The GEA expands the Ontario Energy Board's objects to include the facilitation of the implementation of a "smart grid" in Ontario. In addition, every licence issued to a transmitter or distributor under the Ontario Energy Board Act will be required to prepare plans, in the manner and at the times mandated by the OEB, for approval for the development and implementation of the "smart grid" in relation to the licensee's transmission or distribution system. A licensee will be required in connection with any approved plans to make investments for the development of the "smart grid" in relation to the licensee's transmission or distribution system. 

The GEA provides the framework for a green energy renaissance in Ontario. The bulk of the detail regarding the implementation of that framework will only be known once draft regulations are released.  Current expectations are that such regulations will be released later this summer.

In developing Bill 185, the Government has consulted with environmental groups, as well as with nine industrial sectors expected to be involved in cap-and-trade that collectively represent approximately 40% of Ontario's total 2007 emissions¹. While the Bill sketches the broad outlines of the province's commitment to cap-and-trade as a strategy in the fight against climate change, much of the detail of the province's plan is still to be worked out in forthcoming regulations. To this end, the Government has produced a discussion paper that presents design issues and options for the key elements of a cap-and-trade system. It is seeking stakeholder comments to be used in the development of the proposed regulations. The discussion paper has been posted on the Environmental Registry for a 60-day public comment period ending July 26, 2009.

Key elements of Bill 185

Ontario's Environmental Protection Act (EPA) provides the Government with broad authority to implement emissions trading systems for contaminants (authority that has previously been used to establish cap-and-trade programs for nitrogen oxides and sulphur dioxide). In providing for the development of a GHG cap-and-trade system, Bill 185 deals with a number of key issues, including:

• Greenhouse gases: the Bill adds a definition of GHGs to the EPA, adding within its purview of contaminants gases including carbon dioxide, methane, and nitrous oxide.
• Market-based approaches: the Bill sets forth regulation-making powers with respect to establishing the scope of a cap-and-trade system, the persons and facilities to which such system would apply as well as monitoring and reporting requirements.
• Allowances and credits: the Bill includes regulation-making power with respect to the establishment of allowances and offset credits and well as the distribution, use, trading and retirement of such credits.
• Regional linkages: the Bill explicitly contemplates integration with other cap-and-trade systems, and further notes in its preamble that such linkages can provide emissions reductions at a lower cost, while improving the pace of innovation and allowing for larger trading volumes and improved liquidity. Significant action on this front has already been taken. In June 2008, the Governments of Ontario and Quebec signed a Memorandum of Understanding to collaborate on a GHG cap-and-trade initiative, while in July 2008, Ontario joined the Western Climate Initiative (WCI), a multi-sector trading program which includes British Columbia, Quebec and Manitoba and seven U.S. states. As noted below, it is also possible that Ontario would link to a future North America-wide trading system if and when such a system is developed.

Next steps

Bill 185 leaves numerous regulatory details to be determined, including whether allowances will be auctioned, sold or distributed free of charge, as well as the exact nature of the emission caps and to whom the legislation would apply. As noted above, the province has posted a discussion paper which incorporates feedback received from stakeholders to date, and is seeking further public comment until July 26, 2009 as it develops proposed regulations.

Ontario would be the third province to adopt a GHG cap-and-trade system, after British Columbia and Quebec. On May 12, 2009, Quebec introduced Bill 42 to create a cap-and-trade system in the province. Ontario Premier McGuinty recently commented that Ontario and Quebec have a responsibility to "put in place a carbon-exchange register" that will "serve as kind of a pilot project" in other jurisdictions. The manner in which these two jurisdictions plan to harmonize their approaches is something else to look out for in the coming months.

Finally, the province anticipates that a North American cap-and-trade plan could be in place as early as 2012 - another development that will undoubtedly be the subject of future updates.

When adopted, Bill 42 will establish:

• the reporting of GHG emissions by certain categories of emitters determined by regulation, so that an inventory of GHG emissions may be taken and updated;
• the ability of the Québec Government to set by order GHG reduction targets using 1990 GHG emissions as the baseline. It is currently expected that reduction targets will be phased in from 2012 to 2015 for certain electricity-producing companies and other major industries that emit more than 25,000 tonnes of GHG a year, and after 2015 for other emitters;
• requirements for certain categories of emitters determined by regulation to cover their GHG emissions with an equivalent number of emission allowances, including emissions units, offset credits, early reduction credits and other specified emission allowances;
• a cap-and-trade system to assist emitters to achieve the GHG reduction targets and to mitigate the cost of reducing or limiting GHG emissions. It is expected that the cap-and-trade system will allow persons and municipalities to trade emission allowances;
• the ability of Québec's Minister of Sustainable Development, Environment and Parks to enter into agreements with foreign governments, international organizations and agencies for the harmonization and integration of cap-and-trade systems;
• that all funds collected by the Government under the legislation will be used to finance GHG reduction, limitation or avoidance measures, the mitigation of the economic and social impact of emission reduction efforts, public awareness campaigns and adaptation to global warming and climate change, or to finance the development of and Québec's participation in related regional and international partnerships.

It is currently expected that Bill 42 will be adopted by the end of June and that the first set of regulations under the legislation will be implemented in Fall 2009. It is also expected that emission credits will be traded on the Montreal Climate Exchange (MCex) that was launched last year.

The genesis of many of these changes is based on European initiatives, some of which were initiated 15 to 20 years ago in countries such as Germany, Denmark and Spain.  The Ontario government has expressed a willingness to learn from these initiatives in order to develop a "made-in Ontario" renewable energy economy.  While the proposed GEA is short on detail, which may be frustrating for some, there is no doubt that the essential principles of the government's position are firmly in place. This principled commitment of the McGuinty government is reflected in the manner in which this legislation has been presented.  The government retains a strong central role in being able to issue directives, set priorities and regulate as necessary, in order to ensure that conservation and renewable energy retain the highest priority in Ontario.  It is clear that this initiative is critical to this government and the impact of the proposed legislation is intended to bring about change quickly and throughout a wide range of sectors and consumers.

The stated objectives of a number of the affected statutes are to be modified to ensure that all discretionary decision-making not otherwise directed by the government takes into account this new government priority.  With the framework clearly outlined, with details to follow, there is now a sense of urgency that is being placed upon the OPA, the IESO, the OEB, the transmitters and distributors and other stakeholders within Ontario to act quickly to take steps that will bring real change and results.  There are enough hints in the speeches, leading up to the introduction of the proposed legislation, such as the Minister's announcement at the Board of Trade in front of 750 people on Friday morning, that the government understands the practical side of implementing this major new policy initiative. Some key provisions of the proposed legislation include:

Conservation

• Individual Consumers.  The GEA would encourage energy conservation by individual consumers through real property energy audits and appliance and product efficiency requirements.  The GEA includes a broad requirement that sellers or lessors of real property must provide information regarding energy consumption and efficiency in respect of the real property to buyers or lessees.  The GEA would also require that prescribed appliances and products meet energy efficiency standards.  While the regulations defining such standards have not yet been released, the Minister has indicated that the government will continue to support EnergyStar ratings.
   
• Industrial Consumers. The Minister has clearly indicated that conservation must occur on every level of energy consumption.  The proposed GEA does not speak directly to specific emission or energy consumption reductions, but does amend the Ontario Energy Board Act to require that the OEB assess consumers, gas distributors, licensed distributors, the IESO and any other person prescribed by regulation, an amount, as prescribed by regulation, incurred by the Ministry in respect of its energy conservation programs.  The extent of these potential assessments remains unclear until further defined in the regulations.

Feed-in tariff

• A key component of the proposed GEA is the government's renewed and expanded commitment to feed-in tariffs.  Ontario experimented with feed-in tariffs in the last couple of years through the OPA's Renewable Energy Standard Offer Program (RESOP), which was originally directed by the Ministry.  However, issues with implementation, particularly from a transmission and distribution perspective, caused the RESOP to be put on hold in May 2008.
   
• A feed-in tariff will be viewed by many as a positive response to the strong demand from the renewable energy sector.  Proponents of renewable energy had been advocating that a long-term feed in tariff was the best way to ensure a strong renewable energy sector for Ontario.

• Recent remarks by the Minister acknowledge the need for certainty for a long term commitment at "fair price" to ensure that feed-in tariffs will work.  We anticipate pricing, timing and the rules relating to the feed-in tariff will be actively developed, with opportunity for public comment, by the OPA in the coming months.

Transmission and distribution expansion

• The GEA vests substantial powers in the Minister to mandate transmission and distribution reinforcements to integrate renewable energy resources and to require transmitters and distributors to give preferential or priority access to renewable energy projects.
   
• The GEA requires the OPA and the IESO to provide information about the transmission and distribution systems' ability to accommodate renewable energy generation and mandates the IESO to complete connection assessments within prescribed periods of time.
   
• The GEA requires transmitters and distributors to connect renewable energy generation facilities provided that certain requirements are met.   The GEA further empowers the Minister to direct the OEB to take such steps, including through licence amendments, to require transmitters, distributors and others to reinforce, enhance or expand their transmission, distribution or other systems to accommodate the connection of renewable energy generation facilities.

Project approval streamlining

• The Minister promised in recent speeches that the GEA would streamline cumbersome approval processes and would coordinate approvals from the Ministries of Environment and Natural Resources through a one-window, one-permit process and that it would aim to issue permits within a six-month service window.  The Environmental Protection Act will likely provide the platform for this process, although additional reforms will come through further regulations and directives.
   
• The GEA would create a Renewable Energy Facilitation Office within the Ministry of Energy for the purposes of facilitating the development of renewable energy projects, including working with proponents of renewable energy projects and other ministries to shepherd projects through the various approvals processes and through engagement with local communities. 
   
• The GEA amends the Environmental Protection Act to provide that persons engaging in renewable energy projects shall be exempted from specified approval and permitting requirements including certificate of air and certificate of waste approvals. The GEA also amends the Planning Act to exempt renewable energy generation facilities and renewable energy projects from demolition control by-laws, zoning by-laws and other related by-laws and development permit regulations.
   
• The GEA does not specifically reference the Environmental Assessment Act.  However, based on Minister Smitherman's promise of an expedited six month process, it is anticipated that, as in the case of recent regulations regarding transit project approvals for the Greater Toronto Area, regulations may be introduced exempting certain projects # e.g. transmission reinforcements to facilitate the integration of green energy sources # from individual or class environmental assessments. 

Participation by aboriginal peoples

• In connection with the procurement of up to 2,000 MW of Renewable Energy Supply, then Ontario Minister of Energy Dwight Duncan emphasized the importance of early consultation of First Nations and Métis peoples in the planning and development stages for new renewable energy projects. The Ontario Power Authority was directed by the Minister to develop processes and guidelines in connection with that renewable energy procurement to ensure appropriate consultation with First Nations and Métis peoples.  The GEA's proposed amendments to the Electricity Act build on this theme. 
   
• The GEA would amend the Electricity Act to permit the Minister to direct the Ontario Power Authority to establish measures to facilitate the participation of aboriginal peoples in the development and implementation of renewable energy generation facilities and transmission and distribution systems.  The amendment presumably seeks to address the perceived obstacles to obtaining meaningful participation by aboriginal peoples in renewable energy procurement.

OEB mandate

• The GEA would expand the OEB's mandate to include the promotion of conservation, the facilitation of the implementation of a smart grid and the promotion of the use and generation of electricity from renewable energy sources. 
   
• The GEA would also expand the OEB's rate-making powers beyond transmission, distribution and retailing to other "prescribed activities".  As well, the GEA requires that for leave-to-construct applications, the OEB, in addition to considering the interest of consumers with respect to prices and the reliability and quality of electricity service, consider "the promotion of the use of renewable energy sources". 
   
• The GEA would vest significant powers in the government to promote its green energy policies through the OEB.  Specifically, the GEA would authorize the Minister to issue directives to the OEB to establish conservation and demand management targets to be met by distributors and other licensees, including through licence conditions or, in the case of conservation targets applicable to distributors, through contracting with the OPA.
   
• The GEA would authorize the Minister to issues directives to the OEB requiring the OEB to take steps relating to the establishment, implementation and promotion of a smart grid.  Further, the GEA provides that the Minister may direct the OEB to amend licence conditions of distributors, transmitters and other licensees to enhance or reinforce their transmission, distribution or other associated systems to accommodate the connection of renewable energy generation facilities within prescribed period of time.

Procurement

• The GEA would amend the Electricity Act to give the Minister the authority to issue directions to the OPA to undertake a request for proposal, any other form of procurement solicitation or any other initiative that relates to the procurement of electricity supply and capacity, including supply and capacity from renewable energy sources, reductions in electricity demand or measures related to conservation or the management of electricity demand.

Electricity generation and distribution by municipalities

• Through amendments to the Electricity Act, the GEA would permit municipalities to directly own renewable energy generation facilities (up to 10 MW) rather than through a corporation incorporated under a business corporations statute.

Smart grid

• The GEA would amend the Electricity Act to permit the Lieutenant Governor in Council to make regulations setting a timeframe for the development of a "smart grid" in Ontario, including assigning roles and responsibilities for its implementation and standardization.
   
• A "smart grid" would be defined in the Electricity Act as, in part, "the advanced information exchange systems and equipment that when utilized together improve the flexibility, security, reliability, efficiency and safety of the integrated power system and distribution system" for the purposes of (a) enabling the increased use of renewable energy sources and technology, (b) expanding opportunities to provide demand response, price information and load control, and (c) accommodating the use of emerging, innovative and energy-saving technologies and system control applications.
   
• The GEA would expand the OEB's jurisdiction to include the facilitation of the implementation of a "smart grid" in Ontario.  In addition, every licence issued to a transmitter or distributor under the Ontario Energy Board Act will be required to prepare plans, in the manner and at the times mandated by the OEB, for approval for the development and implementation of the "smart grid" in relation to the licensee's transmission or distribution system.  A licensee will be required in connection with any approved plans to make investments for the development of the "smart grid" in relation to the licensee's transmission or distribution system.

Pricing

• In connection with the feed-in tariff program, the GEA would amend the Electricity Act to provide standard pricing for classes of generation facilities differentiated by energy source.  Pricing is to be guaranteed for the life of the project.
   
• The GEA would expand the powers of the Ministry of Energy and Infrastructure over pricing through amendments to the Electricity Act and the Ministry of Energy Act, allowing the Minister to issue directives specifying energy pricing.

The proposed GEA provides a principled framework within which further regulations will bring about significant changes to both the generation of and the conservation of energy.  The McGuinty government has indicated that this initiative is essential to the development of Ontario's economy and will be swiftly carried through to practice. As the regulatory aspect of the GEA is developed, watch for draft initiatives and opportunities for public comment. The regulatory component to the GEA will be critical in ensuring that the new energy sector is workable, effective, and affordable.

Green infrastructure

The budget contains a pledge by the federal government to provide $1 billion over five years to support a Green Infrastructure Fund.  The Green Infrastructure Fund will be used by the government to support green infrastructure projects on a cost-shared basis.  The budget states that green infrastructure includes infrastructure that supports a focus on the creation of sustainable energy - infrastructure such as modern energy transmission lines and other projects that will contribute to lower carbon emissions.

Clean energy fund

Noting Canada's commitment to reduce greenhouse gas emissions by 20 percent by 2020, the budget lays out the government's objective to support clean energy research and the development of clean energy technologies.  The budget contains a commitment of $150 million over five years to be used for clean energy research initiatives, and a commitment of $850 million over five years for the development and demonstration of "promising technologies", including large-scale carbon capture and storage projects.  The government predicts that through this support over the next five years, a total investment of at least $2.5 billion will be generated in clean energy technologies.

Capital cost allowance for carbon capture and storage

Since 2006, the government has been a significant proponent of the development of carbon capture and storage technologies. The budget notes that $375 million has already been provided to support the development of these technologies, including $250 million in the Budget 2008 for a commercial demonstration of the technology in Saskatchewan and research in Nova Scotia. The remaining $125 million is available for carbon capture and storage projects under the ecoENERGY Technology Initiative of Natural Resources Canada.

The budget contains a pledge by the government to consult with carbon capture and storage stakeholders to identify specific assets used in carbon capture and storage technology with a view to providing accelerated capital cost allowance in respect of such investments.  Such accelerated capital cost allowance advances the timing of capital cost deductions for tax purposes thereby deferring taxation and improving the financial return from investment in an asset.

Energy efficient homes

On an individual level, the budget contains measures designed to promote energy efficiency and conservation through a retrofit program intended to provide home and property owners with grants of up to $5,000 to offset the costs of making energy-efficiency improvements. The budget states that grants will apply to a variety of measures that reduce energy consumption, from increasing insulation to upgrading a furnace.  The budget pledges $300 million over two years to this program to support an estimated 200,000 home retrofits.