Canadian Energy Law : Lawyers & Attorneys for Environmental Energy Law

The well-publicized 550 metre wind turbine setback prohibitions in the original regulation required proponents to consider all noise receptors at the time of construction and did not contemplate that the surrounding conditions could change between the time of approval and time of construction. This created uncertainty for proponents as they could not necessarily rely upon an approval as compliance with the setback requirement at the time of construction. This concern has been addressed by these amendments, which only require proponents to consider noise impacts to surrounding noise receptors that existed as of the date the location of the facility was made public.To allow the MOE to assess the cumulative impacts of the facility, the amended regulation will also require proponents to consider all existing and publicly known projects in the surrounding area when complying with the noise setback requirements and determining a site plan.

Other changes under the amendments affect the public notifications required for renewable energy projects and revise the requirements for municipal consultations.

A summary of the changes has been posted on the environmental registry.

Modernizing and Building New Nuclear Power Plants

The Plan reiterates the Province’s commitment to nuclear generation and its intention to refurbish 10,000 MW of existing nuclear capacity at Bruce B and Darlington stations over the next ten to fifteen years. In addition, it is intended that two new nuclear units will be constructed at Darlington and investments in Pickering B will be made to extend its operation until 2020.

Developing Renewable Energy

The Plan indicates that growth in the renewable energy economy would be facilitated through the continuation of the FIT Program (as the same will be revised following the review of the program in 2011, including the revision of the price schedules to ensure that the interests of ratepayers are balanced against the encouragement of investment in renewables in Ontario). 

The Province has exceeded its goal in the 2007 IPSP which projected a total of 7,708 MW of hydroelectric capacity by 2010. The Province will continue to develop hydroelectric capacity with a goal of 9,000 MW of total capacity by 2018, achieved through new facilities and investments to maximize the potential of existing facilities.

Maintaining Natural Gas Generation

The Plan diverges from the 2007 IPSP that projected that 12,000 MW of natural gas would be required by 2015, on the basis that changes in demand and supply mean that less capacity is required. It is expected, as non-utility generation contracts with natural gas-fired generators expire, that the IESO and OPA will determine whether natural gas generation is required to ensure reliability. The government will direct the OPA to design contracts with these non-utility generators as is necessary.

Developing Combined Heat and Power (CHP)

The Province intends to procure a total of 1,000 MW of CHP through the OPA, including through existing contracts, individual negotiations for large projects, and a new standard offer program offered in specific locations for CHP under 20 MW.

Upgrading and Investing in Transmission and Distribution Systems

The Plan indicates that the Province will continue to invest in upgrades to the transmission and distribution systems (including for the purpose of enabling renewable energy supply as applications to the FIT Program outpace needed upgrades to the grid). Five transmission projects (including three new lines and two upgrades) have been identified as a priority. Together with the Bruce to Milton transmission line that is in development and other station and circuit upgrades, approximately 4,000 MW of additional renewable energy will be enabled. In addition, the Province will issue smart grid principles to the OEB which will be designed to provide guidance to local distribution companies in modernizing the distribution systems. 

Increasing Conservation

The Province remains committed to conservation. Local distribution companies are expected to meet certain conservation targets and will be supported by a combination of new and existing province-wide and local programs and initiatives. Examples of new programs include a province-wide electricity conservation and demand management program for low-income residential consumers, a low-income energy program comprised of gas conservation, customer service standards, and emergency financial assistance, and a proposed regulation requiring the public sector to adopt conservation plans. 

Pricing

It is anticipated that energy prices will rise per year over the next 20 years by 3.5 percent for residential users and 2.7 percent per year for industrial customers.   To offset the expense, the government proposed an Ontario Clean Energy Benefit to give Ontario residents and small businesses a 10 percent benefit on their electricity bills over the next five years. Cost savings initiatives for industrial users include the Industrial Accelerator Program and changes in the calculation of the Global Adjustment Mechanism.

Snapshot of the WTO Dispute Settlement Process

The WTO Dispute Settlement process is a multi-stage process, with consultation being the initial stage before the establishment of a DSB panel. During the consultation stage, the parties to the dispute are required to reply to one another, with the objective of resolving the dispute without the need to advance to a panel review. After 60 days, if no resolution has been reached, the complainant may request the DSB to establish a panel1;The parties are then given up to 20 days to discuss the terms of reference and the composition of the panel. Ultimately, with the parties’ input, a panel of three to five independent experts will be chosen to examine the complaint. Examinations involve meetings with the parties, third parties and may also include an expert review group, and may take up to nine months to conclude. The final report, containing the panel’s findings and recommendations, are provided to the parties within six months of the completion of examinations. Any decision of the panel may be appealed to the WTO Appellate Body. If a complaint is upheld, then once all appeals have been settled, the losing party must inform the DSB of its proposed measures to implement the recommendations. If it is impractical to comply immediately, the losing party will be given a “reasonable period of time” for implementation, which can be determined by the DSB based on either the losing party’s proposal, agreement between the disputing parties, or through arbitration. If the losing party fails to act within the defined “reasonable period of time”, it is obliged to enter into compensation negotiations with the complainant, subsequent to which, the DSB may authorize the implementation of retaliatory trade sanctions by the complainant(s) against the losing party.2

Japan’s Complaint against Canada

The Japanese complaint targets the domestic content requirements in the Ontario FIT Program, arguing that such requirements discriminate against equipment for renewable energy generation facilities produced outside Ontario, and also constitutes a prohibited subsidy. Japan and the other complainants are arguing that, by providing guaranteed, long-term pricing for the output of the renewable energy generation facilities that contain a defined percentage of domestic content, the FIT Program is inconsistent with Canada’s WTO obligations. In particular:

• Under Articles III.4 of the General Agreement on Tariffs and Trade (GATT), Japan is to be accorded treatment no less favourable than that accorded to like products of national original in respect of all laws, regulations and requirements affecting their internal sale, offering for sale, purchase, transportation, distribution or use. Further, under Article III.5, Canada shall not establish or maintain any internal quantitative regulation relating to the mixture, processing or use of products in specified amounts or proportion of equipment for renewable energy generation facilities that require equipment to be supplied from Ontario sources. Japan is arguing that the measures imposed by the FIT Program afford protection to Ontario production of renewable energy generation equipment in a manner contrary to the principles of the GATT3
• Under Article 2 of the Agreement on Trade-Related Investment Measures (TRIMs), Japan also argues that the measures imposed by the FIT Program appear to be trade-related investment measures that are inconsistent with Article III of the GATT, and therefore also inconsistent with the TRIMs. 
• Under Article 3 of the Agreement on Subsidies and Countervailing Measures, Canada shall neither grant nor maintain subsidies contingent, whether solely or as one of several other conditions, upon the use of domestic over imported goods. Japan argues that the measures imposed by the FIT Program (requiring the use of equipment for renewable energy generation facilities to be produced in Ontario) appear to be a subsidy because they represent a form of income or price support that confers a benefit;

Japan has requested a reply from the Government of Canada, and has reserved the right to request production of further information and documents regarding the measures imposed by the FIT Program. Following the DSB consultation procedure, Canada has until the middle of November to settle the matter before Japan may return to the DSB to request the establishment of a panel. Both the Government of Canada and the Government of Ontario have taken the position that Ontario’s Green Energy Act is consistent with Canada’s international trade obligations under the WTO, and will defend the policy accordingly

In January 2010, Ontario signed a deal with a South Korean consortium led by Samsung C&T Corp, which agreed to build four wind and solar power manufacturing facilities in Ontario with a combined power-generating capacity of 2.6 gigawatts by 2016. In exchange, Ontario has agreed to provide the Samsung consortium premium energy prices, access to the transmission system and CDN$437 million in incentives tied to the timely completion of the manufacturing facilities. Samsung is trying to establish itself as a key renewable energy player that will compete directly with existing Japanese companies such as Sharp, Mitsubishi and Kyocera. Some critics have speculated that Japan chose to target Ontario in response to the deal with the Samsung consortium.   

In addition, the OPA has granted an extension regarding the 2010 domestic content requirements to eligible ground mounted solar PV applicants who applied to the microFIT program before 12 p.m. on July 2, 2010.  Such applicants will be deemed to have met the 2010 domestic content requirements of 40 percent if the project is installed and a connection request has been made by May 31, 2011.  Those applicants which submitted their applications after 12 p.m. on July 2, 2010 will be required to meet 2011 domestic content levels if they are not installed and connected by December 31, 2010. 

A webinar will be hosted on August 18 from 2 p.m. to 4 p.m. to answer questions about these recent developments.  Details on the webinar can be found at the OPA Website

FIT Rules and FIT Price Schedule amended to temporarily disallow applications for 10 KW or less

On August 16, 2010, the OPA announced that the FIT Rules have been revised such that applications for 10 KW or less are not permissible until the microFIT rules and application form have been updated to reflect the new price category and rules for microFIT ground-mounted solar PV projects.  The OPA has indicated new applications under the microFIT program will be accepted beginning on Friday August 20.  The FIT Price Schedule has been updated to reflect the revised price for ground mounted solar PV projects under 10 kW of 64.2 cents/kWh.

• FIT Prescribed Forms

On August 12, 2010, the OPA updated the Prescribed Forms for the FIT Contract.  The forms can be found at the OPA Website.

Notwithstanding this regulation, the province's largest municipal electricity distributor, Toronto Hydro Electric System Limited (THESL) adopted a policy of refusing to connect new condominium buildings unless the developer agreed to allow the distributor to smart-meter each unit in the building. The policy had the effect of forcing each unit owner to become a customer of THESL and undermined the competitive sub-metering market provided for in the legislation. The OEB brought a compliance proceeding against THESL in August 2009, alleging that THESL's policy was in breach of the distributor's obligation to connect and of the regulatory regime. In a decision released on January 27, 2010, the OEB found that THESL's policy was in breach and ruled that a distributor cannot frustrate a developer's right to use the services of a smart sub-metering provider. The OEB issued a compliance order requiring THESL to implement measures to ensure that developers are aware of and have access to the services of licenced smart sub-metering providers.

The situation for residential rental buildings or industrial, commercial or office buildings differs from that of condominiums. Although the practice of smart sub-metering such buildings in Ontario has been widespread for several years, the practice was not authorized by Regulation 442/07 and ran contrary to the prohibition on discretionary metering activities in the Electricity Act, 1998. After receiving complaints about the activities of landlords and smart sub-metering providers, the OEB initiated a proceeding in 2009 to consider the issue of discretionary metering further.

In a decision released on August 13, 2009, the OEB recognized that while the smart sub-metering of residential rental buildings is not authorized by legislation, it is consistent with the provincial government's policy objectives. In this respect the OEB noted that the government had made statements supportive of smart sub-metering in rental buildings and was drafting new legislation to address the issue. However, because of the time necessary to pass such legislation and the "aggressive pursuit of smart sub-metering by landlords," the OEB determined that it was necessary to provide interim regulation. Therefore, the OEB authorized the installation of smart sub-metering systems in residential rental buildings and imposed a number of terms and conditions to protect the interests of tenants. In the same decision, the OEB authorized the smart sub-metering of industrial, commercial and office buildings, subject to terms and conditions less demanding than those required for residential rental buildings.

As noted above, new legislation is forthcoming that will further impact smart sub-metering activities. In December 2009 the provincial government introduced Bill 235, the Energy Consumer Protection Act, 2010. If passed in its current form, the Bill would provide the OEB with authority to make orders approving or fixing rates for sub-metering and impose a number of consumer protection measures on smart sub-metering providers, including a requirement that landlords reduce rents when installing a smart sub-metering system and provide tenants with information related to energy usage and conservation. Bill 235 recently passed second reading and has been ordered for third reading.

Glenn Zacher and Patrick Duffy acted as Compliance Counsel on behalf of the Ontario Energy Board in the compliance proceedings against THESL.

Large-scale facilities

The OPA announced the second tranche of FIT contracts on April 8 - more than 180 FIT contracts representing almost 2500 MW of generation capacity. This is the first time that large-scale renewable energy projects have been able to access a standard offer contract program offered by the OPA. The Renewable Energy Standard Offer Program (RESOP) was replaced by the FIT program, but was limited to projects of 10 MW or less. Projects offered contracts under FIT range in size from less than 1 MW to 300 MW. Although seventy-six contracts were offered to proposed solar projects (representing 651 MW), the majority of the proposed generation capacity comes from on-shore wind projects, with forty-seven contracts offered to projects totaling more than 1229 MWs of capacity. One FIT contract was offered to a proposed offshore wind project with a proposed capacity of 300 MW. Once the contracts are finalized, project developers have a limited time to bring these projects online - three years from the date of contract for solar and wind projects.

Renewable energy - truly a sustainable resource?

The unprecedented growth of the renewable-energy generation market in Ontario over the first six months of the FIT program has many people questioning whether this rate of growth can be sustained. More than 2600 MW of capacity has been contracted for under FIT, which is double the 1300 MWs of renewable generation that has been developed in Ontario since 2003.

Generation is only one component to the growth of the electricity market in Ontario. Transmission and manufacturing are two other critical keys to ensuring these six-hundred-plus projects can be brought on to the Ontario grid. The FIT contracts granted so far have been assessed in light of the province's current transmission and distribution capacity, and will not require substantial expansion of either grid. But there remain more than 250 projects waiting for the OPA's "Economic Connection Test" (ECT), having been deemed by the OPA not economically viable under current transmission and distribution capacities. The ECT is intended to reassess the viability of proposed projects as new transmission capacity comes online. The completion of the approval process of the Hydro One Networks Inc. (HONI) Bruce-Milton transmission project represents a significant expansion of HONI's transmission grid and will add 1500 MW of transmission capacity to that region. The OPA has planned to run the first ECT in early fall 2010 and expects the Bruce-Milton transmission line will result in new FIT contracts being issued to projects affected by this development. The critical question that remains is "what next?" - HONI has been issued a directive from the provincial government to significantly build out its transmission capacity, and while the OPA and HONI have indicated that work on this expansion has begun, the timeline for the completion of any new transmission work is not clear, even for the Bruce-Milton line. Historically, obtaining all necessary approvals for transmission development projects can take years, and components of the Green Energy Act intended to streamline this process have yet to be tested.

The projects offered FIT contracts so far may not have to worry about transmission but, for the wind and solar projects, the domestic-content rules under the FIT contract continue to represent a significant hurdle to bringing these projects online. Currently, solar projects must meet a 50% domestic-content threshold and wind projects must meet a 25% domestic-content threshold; in 2011 the solar requirement is increased to 60% and in 2012 the wind requirement is increased to 50%. The 2011 and 2012 deadlines have caused many developers to fast-track development and construction plans for facilities granted FIT contracts in order to avoid the significantly more difficult domestic-content obligations. The OPA has been working with FIT program participants to try to clarify developer obligations under this aspect of the FIT contract. In March, the OPA announced that it will review and provide comments on a project's domestic content plan before the "Notice to Proceed" date, a change that will allow developers to get the OPA's feedback on certain equipment prior to entering into supply agreements. Further, the OPA has also indicated that it will provide developers with a non-binding reliance letter confirming that a project will meet the applicable domestic-content obligations under the FIT program. This is aimed at minimizing the significant barrier to financing FIT program projects that many project developers have been facing. Even with the changes to the domestic-content obligations thus far, many developers are hoping that the 2011 and 2012 deadlines will be extended.

The FIT program remains open to new applications; the OPA has received almost one thousand applications to date and more are expected. The announcement of the issuance of FIT contracts is an important step towards realizing the provincial government's goals under the Green Energy Act, but it is just that - a step. There remains considerable work to be done by developers, the OPA, local distribution companies, HONI, and the provincial government before any of the announced 2600 MW of renewable generation capacity starts powering the homes of Ontarians.

FIT program - launch period closes

On December 16, 2009, the OPA announced that more than 1200 microFIT applications (10 kW or less) and more than 1000 FIT applications were received throughout last October and November, representing nearly 9000 MW of potential electricity generation. Rooftop solar projects amounted to more than 97% of the microFIT applications. The OPA has already sent out more than 700 offers to enter into microFIT contracts for those applications received during the launch period and intends to start offering conditional contracts to those applications received after the launch period in February 2010. Project applications under the FIT program were divided between wind (79%), solar (16%) and biofuels and water (5%).

Although the OPA has estimated that there is approximately 2500 MW of available transmission capacity, the overwhelming popularity of the FIT program based on the submission of FIT applications to date and the announcement of the Samsung deal had left many potential developers wondering what progress has been made to develop new transmission capacity and when will that capacity be operable. The Distribution Availability (DAT) and Transmission Availability Tests (TAT), as well as the Economic Connection Test (ECT), all components of the application assessment under the FIT Program, will be critical tools to ensuring that the most shovel-ready projects can proceed as quickly as possible. The OPA has recently announced that it expects to start issuing contract offers to project launch applications in the next few weeks. Those projects not issued contracts will be subject to the ECT, which will be run on a regional basis and is tentatively scheduled to commence as early as the spring of 2010. It should be noted that DATs and TATs will be paused for periods of three months during the operation of an ECT in the applicable region - which will slow down the application review process. The OPA continues to accept FIT and microFIT applications and with the first ECT occurring imminently, prospective developers are working to ensure that new applications are received before the deadline for ECT consideration, being sixty days before the test begins.

Ministry of Natural Resources - Crown land release process

While project developers anxiously await news of FIT contract offers, the Ministry of Natural Resources (MNR) has released proposed revisions to its Crown land release process for windpower projects and the MNR and the Ministry of Environment (MOE) have each recently issued guides to the new permitting and approval framework for renewable energy projects in Ontario.

The MNR released draft revisions to its Windpower Site Release - Crown Land Policy and Procedure in late December, which outline the distinct stages in the process of developing windpower projects on Crown land including off-shore wind projects. Following the moratorium on Crown land applications for windpower projects in place since September 24, 2009, these proposed amendments represent the first phase of the MNR's review of its Crown land release process, and are intended to address the concerns of project developers with current applications under review by the MNR. The second phase of this review will focus on the long-term application of the site release process and the policy direction for renewable energy developments on Crown land in the context of Ontario's new green energy initiatives. It is unclear how the second phase of the review will affect developers who have not yet submitted applications under the site release process or when the MNR's review of this process will be completed.

The proposed revisions provide that the MNR will periodically establish "windows of opportunities" during which project developers may apply for the opportunity to secure Crown land. It is unclear how often and for what duration such "windows of opportunities" will be opened. The MNR must complete its initial review of an application for Crown land and schedule a pre-screening meeting with the applicant within 60 days after the receipt of the application. Following a required consultation process, the MNR will either issue an Applicant of Record (AoR) letter or deny the application. No estimate has been provided on how long the consultation process will take. Once an AoR letter has been issued, the formal site release process is complete. The MNR has expressly clarified that neither an application for Crown land nor an AoR status provides any right, title or interest in land and only the AoR status is transferable in limited circumstances. Following receipt of necessary approvals related to the proposed project, the MNR will instruct the applicant to submit an application for Crown land, which will include a current corporate profile and specified survey requirements. Authorization to construct the proposed project will be by Crown Lease, the term of which is generally 25 years. In certain instances, an interim Land Use Permit may be issued until all survey requirements are met (for a maximum period of one year).

Approval and permitting requirements for renewable energy projects

The MOE released its guide to the Renewable Energy Approval (REA) in late January, clarifying the new approval process that most renewable energy projects must undergo (there are limited exemptions for small-scale projects). The MOE, as the ministry responsible for coordinating the necessary review of proposed projects, has undertaken to complete the REA process within six months of receipt of a complete submission. Among the things that are to be included in submission packages are:

 

• a project description report
   
• a construction plan report
   
• a consultation report
   
• a design and operations report
   
• a decommissioning plan report
   
• technical reports
   
• proof that setback requirements are met, and
   
• archaeological and heritage resource studies/reports.

The REA regulations require that a project developer commence consultation with the applicable municipality, Aboriginal groups, and the public at least 90 days before submitting a REA application. Further, a developer must coordinate with the MNR in respect of certain issues falling under the MNR's scope of review, including those related to the Endangered Species Act and the Fish and Wildlife Conservation Act, in advance of a developer's REA application submission. As this new approval process has just begun, it remains unclear how long the entire process will take. This is particularly so given the need to file a complete application. Fulfilling the application requirements may be onerous and time-consuming, which may lead to uncertainty. Further, coordination with the federal environmental assessment process and the MNR release of Crown land process remains unclear.

The OSC embarked on a corporate sustainability reporting initiative earlier this year and on December 18, 2009, it publicized its escalating efforts on this front by issuing Staff Notice 51-717 Corporate Governance and Environmental Disclosure. Specifically, Staff Notice 51-717 details the OSC's plans to enhance the environmental and corporate governance disclosure requirements of reporting issuers (other than investment funds). As part of this initiative, the OSC agreed that it would make recommendations to the Minister of Finance by January 1, 2010 regarding potential next steps to enhance disclosure of environmental matters.

Meanwhile, in the US, the Securities and Exchange Commission (SEC) recently noted that it is taking a serious look at these matters. The SEC's actions follow requests by leading US and Canadian institutional investors responsible for trillions of dollars worth of assets for interpretive guidance on climate risk disclosure,¹ including physical and regulatory as well as litigation-related risks. Generally, investors are expressing concern that significant gaps exist between GHG and climate change disclosure among reporting issuers and insist that "reporting on climate risks is no longer a mere virtue, but a legal obligation and a necessity for investors." Investors have made it clear that valuable information reported in a clear and consistent manner is required in order to be able to make informed decisions about both climate risks and opportunities in their portfolios.

Similarly, in Ontario, the OSC is consulting with investors, climate change experts and other stakeholders as part of its corporate sustainability reporting initiative. Recently, James Turner, Vice-Chair of the OSC, stated that the OSC has heard support for more guidance to issuers on disclosure of climate change risk in order to improve the information disclosed to investors and the marketplace. Thus, the OSC intends to issue a notice by December 2010 that offers guidance on compliance with existing environmental disclosure requirements under National Instrument 51-102 Continuous Disclosure Obligations. Publication is planned for no later than December 2010 so that reporting issuers will have sufficient time to consider the guidance when preparing their 2010 annual continuous disclosure documents.

Companies in Canada and across North America are poised to prosper in an emerging clean energy economy, and investors want to know which companies are preparing to capitalize on this opportunity and which are trailing behind. Accordingly, regardless of whether or not they are subject to GHG or other environmental reporting requirements, issuers must seriously consider the effect of environmental matters and climate change on their business and ensure that such matters are adequately disclosed to investors.

We will continue to follow the progress of the OSC in establishing more detailed guidance for climate change disclosure. Look for further analysis and observation in future bulletins.

¹  Institutional Investors Group on Climate Change letter to the SEC; Investor Network on Climate Risk (a Ceres project) letter to the SEC; Ceres.
 

Key Elements of the Regulation

The new regulation requires a broad range of organizations in the province to report their GHG emissions, starting with emissions for the 2010 calendar year. The regulation addresses a number of key issues, including:

• Affected Facilities: All facilities that emit 25,000 tonnes of carbon dioxide equivalent (CO2e) or more per year are required to report GHG emissions data. The government anticipates that between 200 and 300 facilities in the province will fall into this category.¹
   
• Timing: GHG emissions from 2010 are to be reported in 2011, with annual reporting thereafter. The first emission reports are due on June 1, 2011.
   
• Phasing in: Facilities are permitted to apply best-alternative quantification methods in reporting GHG emissions for 2010. As of 2011, facilities will be required to use identified standard quantification methods. This phase-in approach allows facilities time to build quantification capacity.
   
• Third-Party Verification: Annual third-party verification, in accordance with ISO standards, will be required, with the first verification to be submitted in 2012 in respect of 2011 emissions. Facilities are encouraged to undertake voluntary third-party verification in reporting GHG emissions for 2010.
   
• Smaller Emitters: Facilities emitting between 10,000 and 25,000 tonnes of CO2e are not required to report GHG emissions. The government plans to develop an outreach program to encourage voluntary reporting by smaller emitters so that they are prepared to adapt to emerging continent-wide cap-and-trade requirements.²

The regulation is accompanied by a technical guideline, entitled "Guideline for Greenhouse Gas Emission Reporting," which outlines the best alternative quantification methods in emissions reporting for 2010 and mandatory standard quantification methods, to be used as of 2011, to quantify emissions. The government received submissions on the draft GHG emission-reporting regulation and guideline from stakeholders, including industry, associations, municipalities and consulting groups, during a thirty-day public-comment period. In response, several amendments were made in the final regulation. Third-party verification will be phased in to allow facilities to adapt to the new requirements. Additionally, some confidential business information has been removed from the reporting obligation. Technical modifications were also adjusted to be more consistent with federal and U.S. requirements, to give more time for preparation of certain reports and to allow emission factors to be used in the reporting of certain types of emissions.

We will continue to examine this regulation as part of our ongoing review of Ontario's climate change strategy. Look for further analysis and observation in future bulletins.

¹  Government of Ontario, news release, "Ontario Takes Next Step Toward a Cap-and-Trade System" (December 1, 2009)
²  Government of Ontario, Environmental Registry, "Regulation Decision Notice: Greenhouse Gas Emissions Reporting Regulation and Guideline" (December 1, 2009), EBR Registry Number: 010-7889.
 

Key Recent Announcements

Domestic Content Technical Notes: This component of the FIT program has raised extensive criticism from proponents. The OPA has indicated that the requirements set out in the original FIT contract will not be changed but has now provided further technical notes to assist proponents in interpreting these obligations. These notes can be found on the OPA website and will be updated periodically.

Agricultural Land Restrictions for Solar PV: The OPA has announced that it will provide guidelines for proponents that detail the benefits of more renewable energy with the need to protect Ontario's prime agricultural land and details on exemptions available for lands zoned for non-agricultural purposes. Contained within these guidelines will be details on the evidence that a proponent must provide for proposed projects on such lands. These guidelines have not been released as of the date of this update.

Transition options for microFIT (< 500 kW) projects: On October 30, 2009, the OPA announced new options for microFIT proponents that have projects in the late phases of development. These new options exempt such projects from domestic content requirements. Eligible proponents must have either a previous RESOP contract or have purchased generation equipment prior to October 1, 2009 and may elect to transition into the microFIT program or amend the RESOP contract to reflect microFIT prices.

Critical questions

Priority Access: As many generators are aware, Ontarian's demand for electricity has been, at certain times, well below the available generated load on the system. Renewable energy projects have been given a priority right of access to connect to the grid under amendments arising from the Green Energy Act (GEA) but have no defined prioritized right in the actual sale of generated electricity into the grid. As curtailment decisions from the Independent Electricity System Operator (IESO) and Local Distribution Companies (LDCs) become more common, renewable energy generators face the same risk of generation limitation that all other generators, including large scale gas generators, face.

Transmission and Distribution: The popularity of both the old Renewable Energy Standard Offer Program (RESOP) and the FIT program clearly indicates that there are countless project developers interested in entering the generation market. The current determining factor of how quickly these proponents are able to begin selling electricity is transmission and distribution capacity. Hydro One Networks Inc. (HONI) has been directed by the government to commence a large-scale transmission expansion program which is planned to be on stream between 2013 and 2017. Many proponents have raised concerns that the required expansions in both the transmission and distribution systems will cause significant delays in meeting the demand of proposed renewable energy generation facilities.

Conservation and Demand Management (CDM) and Smart Grids: Conservation was a key component to the GEA and it is expected that LDCs will play an important role in the development of CDM protocols. It is anticipated that CDM targets will be made a condition of distribution licences but the details of such an amendment have not been released. The Ontario Energy Board is expected to develop a CDM Code in the coming weeks which will provide a framework on licensing targets and CDM programs.

Despite the concerns raised by many renewable energy project proponents, the FIT program has been, thus far, very well received. As of November 10, 2009, the OPA had received more than 90 applications under the FIT program, representing more than 78 MW of generated capacity and nearly 500 applications under the microFIT program, representing more than 2.5 MW of generated capacity. In comparison to the RESOP program, which contracted more than 1,316 MW of renewable generation, these numbers seem small but the OPA has indicated that it expects these will more than double before the end of the Launch Period. After the November 30, 2009 deadline, the FIT program remains open to applications, although the standard contract rules for time stamping and transmission/distribution capacity allocation become applicable.

Key features of the FIT program

• Generally, in order to be eligible, projects must be (a) renewable generating facilities not already in existence; (b) located in Ontario, provided they are not located in expressly exempt areas; and (c) projects that do not have or have not had a prior power purchase agreement, unless such agreement was terminated prior to March 14, 2009 or more than twelve months before the date of application.
   
• Solar projects with a contract capacity greater than 100 kW are not eligible if located on certain high-quality Class 1 or Class 2 agricultural lands, and, if located on Class 3 agricultural lands, are only eligible if located on identified lands.

Application

• Application fees under the FIT program range from a minimum of $500 to a maximum of $5000, and the application security charge is $20/kW for solar projects and $10/kW for all other projects.
   
• A complete application must also include evidence of access rights to the project location. Such evidence may be in the form of a lease, an option, a letter of intent, a memorandum of understanding or a conditional grant contingent on obtaining a FIT contract.

Domestic Content

• The domestic content of a project is calculated based on the OPA's domestic content grid for each specified renewable energy source and contract capacity. This grid allocates a qualifying percentage to designated activities occurring within Ontario or completed by Ontario residents. Designated activities include the manufacturing and assembling of specified materials, certain construction and on-site labour, and certain consulting services.
   
• The following domestic content thresholds must be met:
   
  • wind power projects with a contract capacity greater than 10kW: (a) 25% for FIT contracts with a milestone commercial operation date (COD) prior to January 1, 2012; and (b) 50% for FIT contracts with a milestone COD on or after January 1, 2012;
     
  • solar projects with a contract capacity greater than 10 kW: (a) 50% for FIT contracts with a milestone COD prior to January 1, 2011; and (b) 60% for FIT contracts with a milestone COD on or after January 1, 2011;
     
  • solar projects with a contract capacity less than 10 kW: (a) 40% for FIT contracts with a COD prior to January 1, 2011; and (b) 60% for FIT contracts with a COD on or after January 1, 2011;
     
• The OPA must be provided with a plan, in a prescribed form, setting out how the FIT program applicant intends to meet the minimum required domestic content level, no later than six months prior to the milestone COD.

Launch Applicants

• All eligible FIT contract applicants who apply during the first sixty days following the launch of the FIT program (prior to November 31, 2009) will be assigned a time stamp, allocated in priority based on (a) the applicant's commitment to reduce the number of days between the date of contract and the milestone COD; (b) the project's acceleration characteristics, including whether it is REA exempt or has an executed EPC agreement; and (c) the date access rights were granted.

Advanced RESOP Applicants

• A Project Developer with a Renewable Energy Standard Offer Program (RESOP) contract can either: (a) retain the RESOP, unamended; (b) amend the RESOP before October 31, 2009, through the FIT program's Advanced RESOP FIT Amendment, where the RESOP is in respect to a wind generation project that has been issued a Certificate of Approval (Noise Emissions) from the Ministry of Environment; (c) repudiate and terminate the RESOP by applying through the FIT Program Launch, before November 31, 2009; or (d) repudiate and terminate the RESOP and apply through the standard FIT program after twelve months.
   
• The Advanced RESOP FIT Amendments include:
  
  
  • a substitution of the contract price with 12.1¢/kWh, comprised of a fixed portion of 9.68¢/kWh and an indexed portion of 2.42¢/kWh;
     
  • relief from the requirements of the RESOP to share with the OPA payments the applicant may be able to obtain under the ecoENERGY grant;
     
  • a requirement to maintain the completion and performance security, which will be returned on the COD; and
     
  • a requirement that the facility achieve commercial operation no later than December 31, 2010, with liquidated damages payable for each day commercial operation is late, culminating in an event of default if the COD is after December 31, 2011.
• Project developers who amend their RESOPs remain bound by the RESOP contract and are not subject to the terms of the FIT program, including domestic content requirements.

MicroFIT

• microFIT is a standard-offer program focused on homeowners and other micro-project developers. The rules and the governing contract have been simplified, but contain similar obligations regarding domestic content and environmental attributes. There are no application or security fees associated with contract application under the microFIT rules.

Renewable Energy Approvals

In addition to the commencement of the FIT program, the Ministry of the Environment released key regulations on September 24, 2009 relating to the Renewable Energy Approval (REA) amendment under the Environmental Protection Act.

A REA is required for all projects which were previously required to seek certificates of approval under s. 9(1) and (7) of the EPA (i.e. construction, altering, extending or replacing or operating any plant, structure, equipment, apparatus, mechanism or thing that may discharge or from which may be discharged a contaminant into any part of the natural environment other than water), s. 27(1) (waste management), and all those that generally were required by regulation to seek an "approval, permit or other instrument."

Prior to the EPA REA amendments, solar projects were not required to undergo an environment assessment (EA). Wind projects may have had to undergo an environmental impact study or potentially a full EA, depending on the location and the project's generation capacity. Certificates of Approval were required by regulation for both wind and solar projects.Projects are exempt from seeking a REA where:

 

• all approvals, permits and other instruments that are required to construct, install, operate or use the facility were obtained before May 14, 2009;
   
• no approvals, permits or other instruments listed above were required to construct, install, operate or use the facility and the construction or installation of the facility began before May 14, 2009;
   
• an EA Notice of Completion in respect of the facility was issued prior to May 14, 2009 and the facility has a power purchase agreement with the OPA;
   
• before May 14, 2009, (i) a power purchase agreement was entered into with the OPA; (ii) the use of the land at the project location was not prohibited by a zoning by-law or order under Part V of the Planning Act; and (iii) the facility was not an undertaking that was designated to be subject to the Environmental Assessment Act.

General REA obligations include:

 

• consultation with the public and aboriginal communities surrounding the project, including at least two public meetings;
   
• consideration of archaeological and heritage resources, where applicable;
   
• specified setbacks for wind energy facilities;
   
• submission of a project's construction plan report, construction report, decommission plan report, design and operations report, noise study report (for non-rooftop solar facilities with a capacity greater than 10 kW), project description report, and wind turbine specifications report or off-shore wind facility report (where applicable).

Care should be taken when reviewing the various transition provisions related to the RESOP and FIT programs and the REA requirements.

Commentary

The Ontario government should be pleased with the level of activity in the renewable sector these days. There is a flurry of new entrants, particularly from the U.S. and Europe, who are thoroughly investigating opportunities in Ontario, from both development and equity investment perspectives. At the same time, some organizations are suggesting that the FIT program needs to be more user friendly. For example, the solar industry is concerned about the restriction on the use of Class 1, 2 and 3 agricultural lands and is looking for certain relief from those provisions , as well as some loosening of the domestic content requirements. Those same domestic content requirements, which while lower for wind applicants, are also being raised as concerns by the wind industry. Both solar and wind proponents note that the current capacity in Ontario for meeting the domestic content requirements is seriously constrained and more time than the government has allowed may be necessary to meet the deadlines imposed. Finally, the great unknown-issues relating to transmission capacity constraints-will start to reveal themselves in the months to come, once the initial round of FIT applications are reviewed and queues start to form for new transmission development. Stay tuned for further word from the OPA as they work through the first round of mature applications that will be filed prior to the end of November 2009.

The launch of the FIT program and the commencement of the REA represent the final pieces that complete the implementation of Bill 150, which was first introduced in February. Watch for further guidance from both the OPA and the Ministry of Environment as these new pieces are "fit" into place.

We will continue to keep you regularly informed as the FIT marketplace develops and matures.

Although the requirement is not a condition for application to the FIT Program, it is important to note that certain projects will be required to achieve a certain level of "Provincial Content," pursuant to the FIT Contract. The definition of "Provincial Content" is still under review; however, other sections of the Program Rules make reference to an "irreversible manufacturing process" that occurs in Ontario.

The Program Rules also set out specific rules for Community Participation Projects and Aboriginal Participation Projects. Community and Aboriginal Participation will be assessed based on the aboriginal or community proponent's economic interest in the project. A project that receives either of these designations receives, among other benefits, reduced security requirements and an increased price/MW.

One of the most significant changes to the Program Rules is the inclusion of rules that specifically apply to early applications - i.e., Program Launch (a time period to be defined by the OPA).  These rules include "rated criteria," whereby applicants receive points for non-mandatory attributes.  The new rated criteria indicate the OPA's focus on ensuring that the initial projects awarded FIT Contracts will be able to begin construction immediately and achieve commercial operation on an expedited basis, to assist the Government of Ontario in achieving the goals of the GEA.

In 2007, GLP applied for new rates and, as part of its rate application, sought to recover through a rate ride approximately $15 million related to its rate deferral plan, which GLP claimed had been recorded since 2002 in a regulatory asset account. GLP, however, did not seek to have this amount subjected to a prudency review, and instead argued that the $12.7 million revenue requirement (and associated rate deferral plan) had been implicitly approved by the Board's 2002 interim order and could not be revisited.  The Board denied recovery on the grounds that the 2002 order was "interim" and issued in anticipation of market opening, and that there had never been a full hearing through which affected parties could provide input.  Under these circumstances, the Board concluded that it would be contrary to "reasonable regulatory practice or common sense" to permit the recovery of the deferred amounts.

GLP appealed the Board's decision to the Divisional Court and argued that the Board had committed an error of law by denying GLP an opportunity to earn a reasonable rate of return. Justice Lederman, writing for a unanimous panel, dismissed the appeal.  In his decision, Justice Lederman stated that the Board would have violated its statutory obligation to ratepayers and the regulatory compact if it had permitted recovery of the deferred costs in the absence of a prudency review. In his Honour's view, the "mere happenstance" of Bill 210 coming into force did not relieve GLP of the obligation to have its costs undergo appropriate scrutiny by the Board before recovering those costs from ratepayers.  Therefore, in his view, the Board did not commit an error of law when it denied GLP's request to recover these costs.

The authors represented the Ontario Energy Board before the Divisional Court.

Although setbacks requirements would apply to wind, solar, hydro, biogas, and biomass projects, the standardization of setback distances is specifically intended to target wind projects. At present wind developers are subject to multiple setback distance requirements as dictated by municipal governments. The Proposal would require that wind projects are set back a minimum of 550 metres from any receptor. A higher standard would be imposed depending on factors such as: (1) the number of turbines in the proposed development; (2) any existing or approved turbines in the area; and (3) the sound level rating of the turbines selected for the development. The Proposal also provides for a minimum setback from roads, railways, and side and rear lot lines that is equal to the turbine hub height plus the length of the blade.

In addition to recommending minimum setback distances, the Proposal would require noise studies to be conducted for any project involving wind turbines with a sound power level greater than 107 decibels, regardless of number, and for any project involving more than 26 turbines within 1.5 kilometres of any receptor. These studies would form part of the new provincial approval process for renewable energy projects.

The Proposal is open for public review and comment on the Environmental Registry until July 24, 2009.

As Union's 2008 earnings were more than 300 basis points above the OEB's formula, Union was required to bring a review application. As part of the application, Union agreed to a settlement under which the off-ramp provision was replaced by a commitment to share 90% of any earnings more than 300 basis points above the OEB's formula with ratepayers. One intervenor, the Industrial Gas Users Association (IGUA), objected to the removal of the off-ramp provision because it provided Union with a "licence" to continue to over-earn without review of the reasons for the over-earning.

While recognizing IGUA's concern, the OEB panel approved the settlement, noting that "even if the contractual right of the parties to review the plan disappears when the trigger mechanism disappears, the Board still has inherent jurisdiction to review situations it regards as unfair or unreasonable." In the panel's view, the 90/10 sharing mechanism was an appropriate check on Union's ability to over-earn and provided greater regulatory certainty. In reaching this conclusion, the OEB made it clear that, while parties have considerable latitude to design and alter earnings share mechanisms, it continues to have the ultimate responsibility to ensure such mechanisms are just and reasonable.

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.

Carrier Sekani was an appeal of a decision of the British Columbia Utilities Commission (BCUC) approving an Energy Purchase Agreement (EPA), under which BC Hydro will purchase electricity from a hydro-generating station owned by Alcan that has been in operation since the 1940s. The Carrier Sekani First Nation claimed that the diversion of water for use in the project was an infringement of their Aboriginal and treaty rights and that BC Hydro therefore had a duty to consult before entering into the EPA. The BCUC declined to deal with the issue, as the EPA will not affect water flows (it is a financial arrangement with limited physical consequences) and Alcan could have avoided the duty to consult by selling its electricity to a non-Crown entity.

In setting aside the BCUC's decision, the Court of Appeal was critical of what it called the BCUC's "aversion to assessing the adequacy of consultation" and concluded the BCUC acted unreasonably by not considering the duty to consult in circumstances where BC Hydro "was taking commercial advantage of an assumed infringement on a massive scale, without consultation." Moreover, the Court held that the BCUC's obligation to consider the public interest gave the BCUC the needed jurisdiction to consider "whether the Crown has a duty to consult and whether it has fulfilled the duty." The Court went on to state that the BCUC was the most appropriate forum to decide consultation issues in a timely and effective manner and that the BCUC has "the skill, expertise and resources to carry out this task."

The companion appeal of Kwikwetlem involved a BCUC approval for a proposed transmission line that will serve the lower mainland and pass through the traditional territory of a number of First Nations. Several of the affected First Nations intervened in the BCUC proceeding and claimed the duty to consult had not been fulfilled by BC Hydro. The BCUC again concluded that it did not need to consider the adequacy of the Crown's consultation and determined that this assessment could be deferred to the future environmental assessment process. The First Nations disagreed with this approach and asserted that the BCUC was effectively precluding their input on alternative solutions to satisfy the lower mainland's anticipated energy shortage.

The BCUC's decision in Kwikwetlem was also set aside by the Court of Appeal. The Court found that deferring the assessment was tantamount to denying First Nations timely access to a Crown decision-maker with authority over the subject matter, and was therefore inconsistent with the honour of the Crown. At the heart of the Court's conclusion was a finding that the BCUC approval process fixed the essential structure of the project and effectively determined the scope of any subsequent environmental assessment. In the Court's view, consultation cannot be deferred in such circumstances and the BCUC should have determined whether "the Crown's honour had been maintained up to that stage of the Crown's activity."

Underlying the two decisions was an understandable concern that in the absence of a forum to address consultation issues, First Nations will be forced to seek interlocutory injunctions in the courts and engage in complex litigation that takes years or decades to resolve. That said, it is questionable whether an economic regulator such as the BCUC has the expertise and resources to deal with these complex questions more expeditiously than the courts. The Court's vague direction that the adequacy of consultation be considered "up to that stage" could also prove troublesome in practice. For example, it is unclear if the OEB's decision in the Bruce to Milton proceeding to limit its assessment of consultation to matters within its jurisdiction would satisfy this threshold.

It should be noted there are unique elements in the British Columbia environmental assessment regime that were important in the Court's analysis and may lead to different conclusions in other Canadian jurisdictions. Legislative action may also fill the void identified by the Court in these two decisions. Nevertheless, these decisions are important precedents, and if followed in Ontario, they could significantly extend the complexity and length of leave-to-construct proceedings before the OEB. To avoid delaying projects dependent on the development of new transmission, it is critical that the Crown be proactive, and in this respect it is notable that the Ontario Power Authority recently announced the establishment of a First Nations and Métis Relations Department.

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.

Subsection 86(2) requires leave before any person may acquire shares of an electricity distributor that, together with any shares already held by that person, will in the aggregate exceed 20% of the shares of the distributor. Essex argued that the provision only applied to transactions that put the purchaser "over the threshold" of a 20% shareholding.  Board staff opposed the application and asserted that leave was required for any transaction that resulted in a person holding more than 20% of a distributor's shares, regardless of that person's shareholdings prior to the transaction.

The Board's three member panel split on the proper interpretation of subsection 86(2). The two-member majority, consisting of Vice-Chair Gordon Kaiser and Ken Quesnelle, sided with Board staff and adopted what they referred to as the "Major Shareholder" interpretation.  In their view, requiring leave for all transactions that result in a person holding more than 20% of a distributor's shares is consistent with the plain wording of subsection 86(2) as well as the legislative intent and history of the provision.   Drawing on the history of utility regulation in Ontario and the United States, the majority concluded that such transactions must be reviewed because they may expose the utility to greater financial risk (thereby increasing the cost of borrowing and leading to higher rates) or impose covenants that might impact a utility's operations. The two members determined that these concerns do not end when a shareholder crosses the initial 20% threshold and noted that further increases in person's shareholdings "only heightens concern" because those "with greater shareholdings are more likely to have the ability to control the financial structure of the utility."

The dissenting member, Paul Vlahos, criticized the majority's reasoning, stating that "[a] desire or inclination to exercise some form of regulatory oversight is not a proper guide in my view to the Board's consideration of its own jurisdiction." In his opinion, subsection 86(2) was properly interpreted to be consistent with the definition of "control person" in the Securities Act and only require a review at the 20% threshold.  He rejected the argument that subsection 86(2) provided for continued oversight of a distributor's major shareholders, noting that a review under subsection 86(2) is at best sporadic and, once a shareholder has effective control of a distributor, it can impose restrictive covenants at any time. Rather, Mr. Vlahos' opined that the appropriate way to protect ratepayers from harm is through the Board's broad ratemaking authority, which is not fettered by restrictive covenants, shareholder directives or any other shareholder agreements.

A number of intervenors objected to Union's proposed treatment of its cost reductions.  In particular, the intervenors argued that if Union had disclosed the transaction in a timely fashion, the cost reductions would have been factored into the IRM Plan.  In support of their position, the intervenors pointed to an internal Union memorandum from August 2007 that quantified the tax savings of the reorganization.  In response, Union argued the reorganization was "just a gleam in somebody's eye" in August 2007 and did not need to be disclosed until the plan received final approval from Union's board in September 2008.

In siding with the intervenors, the OEB stated that regulated utilities have a duty to disclose "all relevant information relating to Board proceedings it is engaged in" and should err on the side of inclusion.  Where information is not disclosed, the utility will bear the burden of establishing that "there is no reasonable possibility that withholding the information would impair a fair outcome in the proceeding."  With respect to Union, the reorganization should have been disclosed in the IRM Plan proceeding because the tax benefits had been quantified and there was a "real prospect" that it would occur.  The panel rejected Union's arguments on the ground that it was not believable that a sophisticated organization like Union would leave $50 million on the table.

Notably, the OEB accepted some responsibility for assessing the adequacy of the Crown's consultation, but limited that responsibility to consultation on matters within its jurisdiction. Consequently, the OEB ruled that leave could be granted if adequate consultation had been undertaken on matters within its jurisdiction, even if consultation for the entire project was not yet completed.

In support of its position, the OEB stated that there is "only one Crown" and that "confusion and uncertainty and the potential for duplication and inconsistency" would result if each Crown actor involved in an approval for a project undertook consultation for the entire project. The OEB also expressed concern that waiting for the completion of consultation for the entire project could lead to a circular situation in which each Crown actor is unable to render a final finding on consultation while it awaits the completion of other processes.

Based on the evidence provided, the OEB concluded that granting leave for the project would not adversely affect any Aboriginal or treaty rights. While Aboriginal consultation for the project was "clearly not complete", the panel identified the issues raised by Aboriginal intervenors as related to the environmental assessment process, which was beyond OEB's jurisdiction and under the control of another Crown actor, the Minister of the Environment. In addition, the OEB stated that a review of consultation for the project as a whole was unnecessary in this specific case as, for reasons unrelated to Aboriginal consultation, the leave to construct order was conditional on the successful completion of the environmental assessment process.

The OEB's approach to this issue is similar to that taken by the British Columbia Utilities Commission (BCUC) in several recent decisions where the BCUC held that a review of the duty to consult for a transmission project can be deferred to the environmental assessment process. One of the BCUC's decisions is currently under appeal to the British Columbia Court of Appeal (see Kwikwetlem First Nation v. British Columbia Utilities Commission, 2008 BCCA 208). The outcome of that appeal may be to fill the void of definitive judicial guidance on this issue to which the OEB referred in its decision.

In its supporting Background Paper, the OEB considered three alternative cost approaches to the status quo. The OEB ultimately settled on the "hybrid option" whereby initial enabler facility costs would be pooled temporarily and included as part of a transmitter's rate base, with generators subsequently making pro-rata capital contributions as and when they became connected (any unsubscribed portion of the enabler facilities would remain in the transmitter's rate base.) Notably, the OEB recommended that the hybrid option should apply not only to enabler facilities included in an OEB-approved integrated power system plan (IPSP), but also to those enabler facilities associated with renewable resources being developed pursuant to government directive. As well, the OEB indicated that it would be necessary to devise a "transmitter designation process" whereby the OEB, on application by a transmitter or on its own motion, would conduct a proceeding to designate a transmitter, including hearing and selecting among alternative or competing proposals for developing and constructing enabler facilities.

The OEB has given interested parties until December 1, 2008 to make written submissions on the proposed amendments
 

What is Carbon Capture and Storage?

CCS technology involves capturing high-volume CO2 from large industrial sources before it is emitted into the atmosphere and then compressing, transporting and injecting it into deep underground geological formations where it is intended to remain permanently trapped. In some cases, CO2 can be utilized in a process termed enhanced oil recovery (EOR) which entails pumping the gas into declining oil fields where it dissolves into the remaining oil, thereby reducing its viscosity and pushing it into production wells, resulting in increased oil production.

Why adopt CCS?

In Canada, proponents believe the potential of CCS to reduce the environmental footprint of both the oil sands industry and electrical generation plants powered by fossil fuels is vast. New facilities could be built "capture-ready", and the technology could also be retrofitted into existing industrial plants. However, while the individual components of CCS are all being deployed at an industrial level, the safety of the entire process has not been definitively proven and its commercial feasibility is reportedly still many years away.

Although CCS has yet to be implemented on a large scale in Canada, research at numerous demonstration plants has indicated that when applied to an industrial facility, CCS is capable of reducing CO2 emissions by approximately 80-95%. Moreover, Canada has an abundance of fossil fuel reserves located in close proximity to suitable underground storage sites with potential for EOR, providing ideal circumstances for CCS development.² The world's first CO2 measuring, monitoring and verification initiative, Weyburn-Midale, was launched in Saskatchewan in 2000. The demonstration project, in its second and final phase, is a government-industry partnership sanctioned by the International Energy Agency (IEA). Test results indicate that long term (i.e., 5,000 year) underground CO2 storage is safe, and the second phase is planned to result in a best practices manual to guide both technical and policy components of future CCS projects.

CCS regulation in Canada

CCS implementation, which would cover CO2 capture, pipeline transportation and injection, is expected to fall under the authority of provincial agencies that regulate oil and gas and power generation. Similarly, while responsibility for water management and regulation is shared by the federal, provincial and municipal governments, provincial agencies would presumably address the potential for leakage and conduct environmental impact assessments in respect of groundwaters that lie solely within a province's boundaries.

Existing federal and provincial oil and gas legislation covers certain aspects of CCS, including capture and transportation-related issues such as construction and health and safety. However, in most Canadian jurisdictions, CO2 storage activities such as access rights and legal characterization, and injection and post-injection activities such as monitoring and liability, have yet to be adequately addressed.³

Encouraging CCS deployment

In April 2007, the federal government released its "Turning the Corner" plan for reducing GHG emissions. The proposed regulatory framework includes mandatory and enforceable targets for emissions reduction from all major industrial sectors. Details of the plan were released in March 2008 and will effectively require the use of CCS or equivalent technology by 2018 in order to meet these targets. The federal government has committed $250 million in funding for the development of CCS and recently announced a call for proposals under a new $125 million fund to advance CCS technologies. In addition, various provincial measures to encourage or mandate GHG mitigation are being developed, including an existing $2 billion fund to advance CCS projects in Alberta.

Challenges and the road ahead

Notwithstanding these developments, a number of technical, regulatory and policy impediments cast a shadow of uncertainty on the future development and implementation of CCS in Canada. According to some experts, CCS will not be commercially viable for at least a decade - and even then large scale implementation will still be many years away. The IEA recently warned that the G8 countries must immediately make $20 billion available for CCS funding if the technology is to become established by 2020. In addition, regulatory uncertainty may discourage private investment in the technology, while environmental groups concerned with the safety and experimental nature of CCS argue that government investment should be directed instead toward proven renewable energy sources such as hydro, solar and wind power.

Clearly, several measures will be necessary to facilitate the successful adoption of CCS technology. Monitoring, reporting and verification guidelines must be developed and safety concerns, such as leakage, must be addressed. Further, Canadian governments will need to continue to provide research and development incentives to advance demonstration projects, akin to the U.S. industrial tax credit for CCS implementation included in the recently enacted Emergency Economic Stabilization Act of 2008.

According to proponents, the development of an effective, harmonized regulatory system in Canada is a key first step toward developing both industry and community confidence in the technology. Moreover, CO2 storage needs to be demonstrated rapidly and at a wider variety of locations in order to assess the potential for CO2 retention in varying geological formations and develop criteria for site selection. Proponents believe that expanded demonstration will also provide critical data to enable the development of CO2 monitoring and verification processes and risk management practices. This, in turn, is expected to accelerate the deployment of CCS and facilitate the progress required for large-scale commercial emissions reductions in the future.

¹ The IPCC is a scientific intergovernmental body set up by the World Meteorological Organization and by the United Nations Environment Programme, established to provide the decision-makers and others interested in climate change with an objective source of information about climate change.
² This storage potential is particularly immense in the rock formations of the Western Canadian Sedimentary Basin.
³ International Energy Agency website. In January 2008, the Canada-Alberta EcoENERGY CCS Task Force made a range of recommendations regarding how to address these outstanding issues.

Enbridge had only nine unbundled customers at the time of the hearing, and there was no opposition by intervenors to its proposal. Enbridge proposed following the aggregate excess method for most customers, but that large-volume unbundled customers should be free to choose an allocation of cost-based storage based on a method originally designed for gas-fired power generators that was part of a June 13, 2006 settlement proposal in the NGEIR proceeding.

The OEB ordered a different methodology for Union. At the time of the hearing, Union had 51 customers taking semi-unbundled service (T1 and T3 rates). The majority of Union's T1 customers on one-year renewable contracts have allocations that are higher than their allocations under the aggregate excess method, primarily because 22 of the T1 customers have "grandfathered" allocations based on an OEB-approved June 7, 2000 settlement agreement.

Customers whose allocations have been grandfathered since 2000 will now have those allocations reviewed upon contract renewal, which in most cases will occur within one year. The allocations of the small number of customers with long-term contracts will also be reviewed on contract renewal.

The Board agreed with Union that the storage allocation should not be based entirely upon a customer's past use, as that is not always indicative of "reasonable needs". The Board found that the maximum level of deliverability available to a T1 or T3 customer at cost-based rates should equal the greater of DCQ and (CD - DCQ). DCQ is "Daily Contract Quantity," the amounts that T1 and T3 contracts require customers to arrange for equal daily deliveries of natural gas to Union's system over a year. (CD - DCQ) is the customer's "Contract Demand," the maximum amount of gas that Union is obligated to deliver to a customer in any one day, less the DCQ.

The Board also agreed with Union's modifications to the aggregate excess method. The revisions include a 50% weighting for one year of forecast data in the calculation, forecast only for new customers and customers undergoing significant operational changes, and a new aggregate excess calculation for each contract renewal.

Union further proposed a 10 × DCQ formula for customers with process loads as opposed to seasonal storage patterns because the customers receive very small storage allocations under the aggregate excess method. The 10 × DCQ method would allow process load customers to elect to follow a method that would provide a storage allocation more reflective of their reasonable needs. Intervenors argued that more storage is required for process load customers, and the Board ordered that a 15 × DCQ method be applied.

The Board ordered that Union and Enbridge are to file draft rate orders reflecting this decision.

The accord invites other provinces and territories to sign on and "work together collaboratively on the cap and trade initiative". Further, the Ontario and Quebec Premiers have stated that they hope their system, once implemented, could become the foundation for a national cap and trade system. However, news of the Premiers' plans drew immediate criticism from federal Environment Minister John Baird, as well as Prime Minister Stephen Harper, who accused the Premiers of "political posturing" and suggested that the federal plan would be more aggressive and get underway sooner.

In addition, the accord contemplates forming linkages with other North American and international trading schemes, as well as working with "broader regional trading initiatives already under development". This could presumably include linking with the cap and trade scheme currently under development by the Western Climate Initiative (WCI), an alliance of seven American states and three Canadian provinces (Quebec, Manitoba, and British Columbia) that is jointly developing regional strategies to address climate change. Ontario has observer status with the WCI.

LIEN appealed and the Divisional Court set aside the OEB's decision. Two of the three judges on the panel, Justices Kiteley and Cumming, held the OEB could consider income levels in pricing to achieve the delivery of affordable energy to low-income consumers. The majority grounded its decision in the OEB's broad authority under section 36 of Ontario Energy Board Act to fix "just and reasonable rates" by adopting "any method or technique it considers appropriate". In their view, as long as the global amount of return to the utility is achievable, then the setting of rates to generate the required return is matter within the OEB's discretion. They went on to note that taking into consideration the ability to pay in rate-setting could also be used by the OEB to further its statutory objective of protecting "the interests of consumers with respect to prices". That said, Justices Kiteley and Cumming were careful to add that their decision was limited to the jurisdictional issue and they were not implying any preferred course of action in rate-setting by the OEB.

The third member of the panel, Justice Swinton, dissented. In her opinion, section 36 could not be viewed as conferring unlimited discretion on OEB; rather that authority was confined by the statutory regime and the longstanding principle that customers receiving the same service must be treated equally. Further, Justice Swinton noted the ability to order a rate affordability plan would be a fundamental departure from the OEB's traditional role and require it to assume a significant new role as a regulator of social policy. In support of this proposition, Justice Swinton cited cases from a number of other jurisdictions in which regulators were denied the authority to consider ability to pay in rate-setting. On these grounds, she concluded that the Legislature could not have intended to authorize the OEB to discriminate among customers unless it used specific words to express that intention.

While the decision leaves the OEB with the authority to decide how far to go in exercising this "unwanted" power, it could open up rate proceedings to a range of issues that fall outside of the traditional rate case. The OEB may feel restrained when determining whether to exclude issues raised by intervenors from the issues list. This in turn could result in longer proceedings to hear evidence on all of the issues included on the issues list.

The Standard Offer Program is paying a price of 42 cents per/kWh. This high price, compared with other forms of generation, reflects the fact that although the capital cost is high per/kWh installed, the environmental consequences provide significant benefits. Large solar PV systems can be constructed within months on sites, on the ground or on buildings that are south-facing and with an incline of approximately 45 degrees.

A number of world solar PV developers have now entered into the Ontario market and a series of solar PV projects totalling approximately 100 MW have been announced. These announcements may have been encouraged by federal tax law. Accelerated capital cost allowance is potentially available for solar cells and related equipment, excluding electrical distribution equipment. . Certain expenses to support solar PV projects may also be eligible for Canadian Renewable Conservation Expense (CRCE). This would allow for a flow-through of this expense to the shareholders of a solar PV company.

The OPA is required to update the plan every three years and file it with the OEB. The OEB is required to review the plan to ensure it complies with the Directive and is economically prudent and cost effective. The OEB has indicated that it expects its review of this initial IPSP to take approximately one year.

One of the emerging themes surrounding the IPSP is the need to streamline regulatory approval processes for major power projects. Notably, the Province's last attempt to develop an integrated electricity plan # Ontario Hydro's Demand Supply Plan (DSP) # was withdrawn in 1993, more than three years after it had been filed, and before it could be approved. As the OPA advised the current government, the withdrawal of the DSP before the review process was completed was, in part, "due to the ever broadening scope of the approval process as it proceeded and the fact that it was not at all clear that the approval process would come to a conclusion before the plan under consideration required revision due to the passage of time."

The IPSP and the current OEB review process are fundamentally narrower in scope than the DSP and its review process. The Directive removes policy decisions from the IPSP and the OEB's review powers focus on ensuring that the plan complies with the Directive and is economically prudent and cost effective. That being said, the challenges to implementation of the plan will be significant. The IPSP is a $60 billion plan that includes approximately $46 billion for new generation and $4 billion for transmission expansion. Following approval of the IPSP, generation proponents will have to pass projects through local reviews on land use and siting, as well as environmental screening processes. Further, a central feature of the plan # enabling the development of renewable energy resources, many of which are located in remote areas of northern Ontario # will depend on substantial new transmission enhancements. Proponents of new transmission projects will have to submit proposed projects to necessary regulatory reviews: in particular, an economic review by the OEB and an environmental review by the Environmental Review Tribunal.

Such challenges to implementation of the IPSP have triggered renewed calls for regulatory reform. Many of the stakeholders the OPA consulted in developing the IPSP identified regulatory approval risks and timelines as potentially the most significant impediment to the plan. These concerns have been echoed in recent months by industry leaders who have called on the government to streamline the regulatory approval processes for major energy projects. The OPA itself has advocated changes to meet the regulatory challenges of implementing the IPSP. The OPA's views are contained in the evidence filed in support of the IPSP and, more recently, have been expressed by the OPA's CEO, Jan Carr. Mr. Carr has argued that the public interest is served "by providing a regulatory approval process that can deliver decisions in a timely manner," and the OPA recommends that the separate economic and environmental approval processes for major transmission projects "be vested in one agency."

This debate is sure to play itself out over the coming year and it will be interesting to observe whether the IPSP can, in addition to assisting the Province in meeting its supply mix goals, serve as an impetus for positive regulatory reform.

AMPCO's application related to an assumption made by the IESO with respect to how quickly the output of a generation facility can be increased or decreased (referred to as "ramp rate") to meet demand. At the heart of Ontario's wholesale market are two parallel algorithms - a pricing algorithm that calculates the wholesale price in five-minute intervals and operates without regard for transmission constraints on the system, and a physical dispatch algorithm that recognizes transmissions constraints and is used to dispatch facilities to meet market demand.

In testing prior to market opening, the IESO observed price volatility in intervals where the facility with the lowest marginal price could not ramp fast enough to meet a significant shift in demand and more expensive generation had to be dispatched. To address this volatility, the parameters of the pricing algorithm were set to assume that generation facilities were able to ramp twelve times faster than is actually the case (commonly denoted as "12x"). As a result, in these intervals higher-priced generation that can ramp quickly is dispatched, but the pricing algorithm assumes that lower-priced, but slower ramping, facilities are being used for the purposes of calculating the wholesale price.

The discrepancy between the pricing algorithm and the physical dispatch algorithm reduces sudden price increases, but also dampens the wholesale market price by moving it further away from the true cost of production. This disconnect creates inefficiencies in the market that have been noted by the Market Surveillance Panel in a number of its reports. In particular, the Panel in its June 2006 report identified the dampening of the wholesale price in Ontario due to the ramp rate multiplier as a factor that was causing exports to flow to New York even in cases where the underlying cost of generation was actually higher in Ontario than New York.

The IESO viewed the 12x ramp rate multiplier as a temporary measure when it was introduced and began a stakeholder consultation process to re-examine it in January 2006. This process culminated in early January 2007 when the IESO approved a market rule amendment reducing the ramp rate multiplier from 12x to 3x. The accompanying decision document stated that the IESO approved the amendment because:

• it will better align price with operational drivers and will have the immediate effect of reducing uneconomic exports of energy that cause both an economic burden on Ontario as well as increased emissions from the additional operation of fossil generation in Ontario to supply these exports;
• it requires no development costs to implement; and
• it results in a very modest change to the financial distribution between consumers and suppliers when market responses and the mechanisms of the hybrid market are taken into account.

AMPCO, which was an ardent opponent of the proposed change during the stakeholder consultation process, applied to the Board for a review of the amendment under section 33 of the Electricity Act, 1998. Subsection 33(9) of the Act states that the Board shall revoke an amendment and refer it back to the IESO for reconsideration if the Board finds the amendment is inconsistent with the purposes of the Act or unjustly discriminates against or in favour of a market participant or class of market participants.

AMPCO's principal allegation was that the consultation process was flawed and the issue had been pre-determined to receive the support of generators on other initiatives. In the course of the proceeding, the Board ordered the IESO to produce all documents connected with the stakeholder consultation process on the ramp rate and other initiatives that AMPCO alleged were tied to it. The IESO objected that such issues were beyond the scope of the application and in any event, it was not practicable to produce all of the required documents within the sixty-day time frame for the proceeding set by the Act. Instead, the IESO countered with a plan to limit the scope of production that was accepted by the Board. The Board also agreed to deal with the relevance of the materials produced by the IESO at the outset of the hearing.

The application was heard by the Board over a two-day period on March 29 and 30, 2007. After hearing submissions on the "relevance issue", the Board determined that subsection 33(9) was a "jurisdiction-limiting provision" that restricted its mandate to an examination of the impact of the market rule amendment against the two criteria in that subsection. The Board noted that the legislature's intent for a limited review was also reflected in the Act's tight time frame for a rule review application. In its view, assessing whether the stakeholder consultation process was adequate is a matter for a judicial review application before the courts. Accordingly, the Board ordered that any evidence related to the consultation process be struck.

When the hearing reconvened, AMPCO, the IESO and other intervenors presented evidence related to the merits of the rule amendment and its impact on consumer's bills. After allowing for the exchange of final submissions, the Board released its decision denying the application on April 10, 2007, the last day of the sixty-day time period provided for in the Act. The notable findings in the Board's decision include the following:

• The burden of proof in a rule amendment review application is on the applicant to satisfy the Board that the requested relief should be granted.
• There is merit in pursuing amendments to the market rules that can be expected to result in efficiency improvements even in the context of Ontario's hybrid market.
• "Unjust discrimination" in section 33 of the Act means unjust economic discrimination and there must be more than an economic advantage accruing to one party rather than the other to meet this test.
• The change to a 3x ramp rate will result in greater efficiency in the IESO's real-time market and the expected impact on consumers' bills is relatively modest. While estimating the impact is a complex exercise and cannot be done with precision, the IESO's calculation of 0.004 cents/kWh is an indicator of the order of magnitude of the net effect of the Amendment.

Despite the Board's ruling on the merits of the amendment, market participants will not see an immediate impact on the operation of the Ontario market. While the Board refused AMPCO's request to stay the amendment while it sought to appeal the decision, the panel did state its expectation that the IESO would not move forward with the change until AMPCO had "a reasonable opportunity to request judicial recourse." On April 27, 2007, AMPCO filed an appeal of the Board's decision in the Divisional Court.

Adjudicative Hearings - The Board recommends that oral adjudicative hearings be limited to those circumstances where they are most appropriate - i.e. where factfinding is necessary to support an order. Further, the Board recommends that other tools, including pre-hearing processes, be used more effectively to circumscribe the scope of oral hearings.

The Board argues that while adjudicative hearings are critical to certain aspects of the Board's mandate, they are not best suited to other aspects; in particular, the development of regulatory policy. Regulatory policy, the Board states, is more suitably addressed through codes, rules or guidelines. The Board suggests that adjudicative hearings are too procedurally rigid to be adept at developing policy. Moreover, the Board's processes for articulating policy through rules and codes does not preclude stakeholders from challenging policy decisions, because draft code/rules are typically circulated for comment and are developed and refined through a consultative process.

Guidelines - The Board argues that guidelines, which are non-binding expressions of the Board's intended approach to the exercise of its statutory powers, may also be used to bring greater predictability to decision-making. The recent Discussion Paper issued by the Board, setting out its proposed guidelines for review of the OPA's IPSP and procurement processes, may be seen as an example of this. It is clear from the Board's Report that it also intends to use guidelines and other non-adjudicative policy instruments (e.g. technical conferences, interrogatories, etc.) to narrow issues and abbreviate adjudicative hearings.

Role of Staff - The Board's proposed reforms regarding the role of staff in adjudicative hearings will likely be the most controversial aspect of the Board's Report.

In the past, the Board has experimented with a two-staff model, whereby one staff team acts as public-interest advocate in the proceeding, and a second staff team supports and advises the Panel. In its Report, the Board proposes a single-staff model, where the same team of staff participates in the hearing and advises the Panel.

The principal rationale for the Board's proposal is that, whereas in non-adjudicative processes staff provides legal, technical and policy advice to Board members, in adjudicative hearings the Panel is quarantined from the Board's institutional expertises. The purpose of the proposed single-staff model is therefore "to integrate the Board's substantive expertises in its adjudicative processes to ensure that processes are consistent with the Board's commitment to procedural fairness."

The Board argues that it is beneficial for staff to participate in hearings so that staff can put forward all matters that are in the public interest, rather than leaving the Panel to choose between the limited options and assessments put forth by the parties. This, the Board argues, is more in keeping with the Board's public-interest mandate. Insofar as procedural fairness is concerned, the Board states that administrative hearings do not warrant the same procedural safeguards as other hearings and, in any event, sufficient procedural fairness can be ensured through transparency - in particular, requiring staff to present its view of the public interest on the record so that parties may respond to it.

Role of Parties - By increasing the role of staff in adjudicative hearings, the Board suggests that the role of other parties, particularly intervenors, may be reduced. To date, the minimal role of staff has required the Board to rely heavily on intervenors to express the range of stakeholder interests. The consequence of this has been lengthy proceedings and high costs through liberal intervenor funding requirements.

The Board suggests that more rigorous procedures be put in place to require proposed intervenors to demonstrate up-front how their participation relates to the specific and particular interests of their constituency. The Board also suggests that the Panel be given more latitude to control intervenors' participation in the hearing process.

Pre-Hearing Processes - The Board has proposed several innovative pre-hearing measures to further streamline adjudicative hearings. First, the Board, says that the interrogatory process has become inefficient because parties write interrogatories independently and at the same time; this causes considerable duplication. As well, there is little cost and no disincentive to asking numerous and irrelevant questions. The Board notes that recent experiments show that technical conferences involving the discovery of witnesses in the presence of other parties is a more efficient way of narrowing the issues. The Board also suggests that pre-hearing examinations, in lieu of an oral hearing before the Panel, may be appropriate in cases where there are no material facts in dispute. The Board has also proposed that the Board become more involved in the pre-hearing settlement processes by identifying those matters the Board believes ought to be settled directly between the parties. Lastly, the Board suggests that as an incentive to settlement, parties at settlement conferences be required to submit their final pre-hearing settlement offers on specific issues, and in the event parties beat their offers to settle, they may be entitled to costs awards; conversely, where parties achieve results at the hearing that were worse than the offer made to them, the Panel may consider disallowing parties a portion of their costs.

The framework for this initiative was set out in the Energy Conservation Leadership Act, 2006, which came into force earlier this year. The legislation allows for the creation of a "Smart Metering Entity" with the power to administer and deliver any part of the initiative and to engage in competitive procurement activities. Although details of the Smart Metering Entity have not been finalized, it appears that this entity will be responsible for procuring and operating the equipment necessary for the collection and management of data from the smart meters, while local distributors will provide actual meters. The government has yet to create or designate an agency as the Smart Metering Entity.

Responsibility for the initial stages of the smart metering initiative has been handed to the Independent Electricity System Operator (IESO). The Ministry of Energy has proposed a draft regulation that adds to the IESO's role the responsibility to "plan, manage and implement" and "oversee, administer and deliver" the smart metering initiative, or any aspect of the initiative. To fulfill these objectives, the draft regulation proposes that the IESO would have the authority to implement a schedule and plan for the initiative, to manage and develop the functional requirements for smart meters and the collection of data, and to prepare and manage competitive procurement processes for the services and systems necessary to operate smart meters. It is not clear whether the provincial government has any plans to eventually designate the IESO as the Smart Metering Entity.

On August 29, 2006, a regulation containing the principles that will govern the procurement of smart metering equipment by distributors came into effect. The regulation identifies authorized discretionary metering activities that can be undertaken by a distributor, notwithstanding the prohibition on such activities contained in the Electricity Act, 1998. The regulation also obligates distributors to ensure that the procurement process for smart meters meets specified criteria, including:

• the procedures used in the process and the selection criteria must be fair, open and accessible to a range of interested bidders;

• the procurement process must be competitive;

• bidders must disclose and implement measures to address any actual or potential conflicts of interest; and

• there must be no unfair advantage in the procurement process.

Regulations concerning the technical specifications and cost recovery for smart meters and the associated technologies also came into effect on August 29, 2006. For residential and small general-service consumers, the prescribed criteria are specified in the Ministry's publication entitled "Functional Specification for Advanced Metering Infrastructure," dated July 14, 2006. While ultimately subject to approval by the Ontario Energy Board, the regulations allow a distributor to recover costs that relate to the functionality of the smart meters and the associated technologies that meet the minimum criteria specified in the Ministry's publication. If a distributor's equipment exceeds the Ministry's minimum criteria, the distributor must convince the Board that the excess functionality will benefit the distributor's customers in order to recover any additional costs.

The proposed test distinguishes between transmission investments connecting generation or load facilities (radial lines) and "deeper" grid (network) investments. For a radial connection proposal, the test would first ask whether the facility investment would have a "significant impact on system efficiency and/or reliability." If it would not, the Board would evaluate the leave-to-construct application in accordance with the Transmission System Code. If, however, a radial connection would have a significant impact, the discussion paper proposes that a cost/benefit test be required.

The discussion paper also distinguishes network investments required to meet minimum reliability standards from other kinds of network investments. In the case of the former, a least-cost test might be acceptable. Other network upgrades would require analysis under a cost/benefit test.

Quantifying Reliability Benefits

In large part, the discussion paper attempts to create a cost/benefit approach that would quantify the reliability benefits offered by an investment. Board staff regard traditional reliability standards as too deterministic to evaluate transmission upgrades, potentially giving undue weight to large, but low probability, events and resulting in uneconomic overbuilding of the transmission network. As an alternative, Board staff propose a "probabilistic" standard so that only transmission investments that have a positive net benefit would be approved. Under a probabilistic approach, the Board would review data regarding the amount of unserved energy (i.e. lost load) arising from a specified contingency event, the value of unserved energy to the consumers experiencing loss of service, and the probability/frequency of contingency events. By explicitly valuing unserved energy, a probabilistic approach would allow reliability investments to be evaluated just as economic investments are evaluated.

Market Benefit

Where a proposed investment is necessitated solely by the inability to meet the minimum network performance requirements set out in the Transmission System Code or other relevant documents, Board staff considers that the investment would satisfy the cost/benefit test if it maximizes the expected net present value of the market benefit (the present value of the market benefit less the present value of cost) or minimizes the present value of costs, compared with a number of alternative options in a majority of reasonable scenarios. In all other cases, the proposed investment would have to maximize the expected net present value of the market benefit compared with a number of alternative options and the expected net present value of the proposed investment would need to be greater than zero. Market benefit would mean the total benefits of a proposed investment (or alternative option) to all those who produce, distribute and consume electricity in the Ontario electricity market. An assessment of the market benefit would include considering a number of possible benefits, including reductions in fuel consumption arising through different generation dispatch, reductions in the cost of demand site management, reductions in the value of involuntary load shedding and competition benefits.

Alternative Projects

Board staff acknowledges that some limit should be placed on the number of alternative projects considered as part of the cost/benefit analysis for any proposed investment. Only proposed investments that are technically and-for projects not required to meet reliability standards-commercially feasible should be considered alternatives to a proposed investment. They should also represent true alternatives, in the sense of being projects that would not be developed if the proposed investment or another alternative proceeded. Alternative projects would not have to be transmission projects, but could include distributed generation, distribution network enhancement and demand-side management.

Future System Conditions

Board staff also rejects assessing transmission investments based only on assumptions of average future system conditions. Since this could significantly underestimate or overestimate the net benefit of a project, Board staff proposes that the value of a transmission investment should be evaluated over a range of possible future system conditions or scenarios, to ensure the investment maximizes the public benefit. Scenarios would range from those likely to occur to those that have only an extremely remote likelihood of occurring. Board staff proposes that such modeling should take into account a range of reasonable market-development scenarios, including committed projects, anticipated projects and modeled projects.

Next Steps

The Board has now selected members of the technical advisory team. After considering the input of the team on the conceptual and practical merits of the potential cost/benefit test, the Board plans to develop a draft test and draft filing requirements for public comment, after which the Board will finalize the filing requirements.

On the surface, the government's deference to an independent agency should be cause for optimism amongst market proponents. Market proponents should be similarly heartened by comments Premier McGuinty made during the same speech wherein he vowed to "take the politics out of pricing" and allow "the OEB [to set] the price based on what electricity costs, not on what politicians think it should cost or wish it would cost." On the other hand, in the short time the Liberals have been in office Ontarians have watched the government break promises when political pressures intensified. Moreover, the prospect of new nuclear poses enormous political and economic challenges (not to mention temptations for would-be central planners). During one of the morning sessions at the OEA conference prior to Premier McGuinty's speech, one industry expert opined that the OPA will be a failure if it slips beyond its transitional mandate and becomes a dumping ground for governmental directives. The same expert cautioned - perhaps presciently - that one of the warning signs the industry needs to be watchful of is the government's use of the OPA to engage in grand new generation projects, particularly the refurbishment or construction of new nuclear facilities.

As always, predicting energy policy in Ontario is like reading tea leaves. That said, the prediction that profound changes lie ahead is probably a safe one. Dire conditions - and Ontario's electric supply profile certainly qualifies - are crucibles for transformation. Under such conditions, governments that typically shy away from dramatic changes, are forced into them, often with unexpected and irreversible consequences. Now more than ever, the Premier's comments signal the need for a cohesive industry voice.