The Green Energy and Green Economy Act, 2009 (the “Act”) received royal assent on May 14, 2009. While many provisions have not yet been proclaimed into force (so far, only the amendments related to the Building Code Act and the Ministry of Natural Resources have been proclaimed), an array of initiatives are springing to life at an increasingly rapid pace reflecting a level of change not seen in Ontario’s electricity industry since market opening.
Our Energy Markets Group has continued to provide ongoing legal counsel to various renewable energy generation proponents, local distribution utilities, municipalities, industry associations and government agencies. Further, we are pleased to note that in June, Doug Mitchell, national co-chairman of Borden Ladner Gervais LLP, was named as the latest appointment to TD Securities' energy advisory board. "Doug will be a tremendous asset to the board, and a huge help in building on our momentum in this sector," said TD Securities Energy Advisory Board Chairman Frank McKenna.
Given the broad scope of initiatives currently underway, the range of forums in which these initiatives are taking place, and the interrelated nature of many of the issues these initiatives seek to address, we thought it worthwhile to take a moment to take stock of what has changed under the Act, what has happened to date, and what we can expect to see over the summer - all to help you put these developments into perspective for your business. Specifically, we will address:
- the OPA’s feed-in tariff program as updated to July 10, 2009;
- the Ministries of the Environment and Natural Resources’ proposed renewable energy approvals process as released on June 9, 2009;
- the Ministry of Energy and Infrastructure’s proposed regulations issued May 15, 2009; and
- various initiatives underway or contemplated at the OEB between April 3 and June 24, 2009 dealing with renewable energy infrastructure development and cost recovery.
1. The Feed-in Tariff Program (“FIT”)
On July 10, 2009, the Ontario Power Authority (“OPA”) released revised draft FIT program rules (the “Rules”) and pricing scheduled (the “Pricing”), updating the materials it originally released on March 13, 2009 and related materials distributed by the OPA during nearly two months of stakeholder consultations, and which, combined with the proposed form of FIT contract and related schedules released June 9, 2009 (the “Contract”) (the Rules, Pricing and Contract are collectively the “Materials”), provides the most comprehensive view yet of what North America’s first FIT will look-like, at least for projects that are larger than 10kW in capacity.1
The proposed FIT offers developers of new generation from renewable resources an attractive promise of a guaranteed price, buyer, and long-term revenue stream without having to incur the costs involved with participating in a competitive RFP process. In general, the Contract provides for the payment of fixed price (see the table below for the OPA’s current pricing proposal) over a 40-year term for waterpower and a 20-year term for other renewables. In return, as in most OPA procurement contracts, the FIT generator must provide the OPA with all related products, environmental attributes including carbon offsets (except those required by a facility to meet its own regulatory obligations), and 50 per cent of any payments received under the Federal ecoEnergy for Renewable Power program or any substantially equivalent program or successor that is implemented by the Federal Government from time to time.
To view table click here.
The proposed FIT Materials provide some promising improvements over RESOP, including the elimination of capacity limits (except for ground mounted solar and hydro) and the introduction of new anti-gaming provisions the most significant of which is the requirement that generators must post a sizeable initial security deposit at the time they apply under the FIT, plus an incremental deposit once awarded a FIT contract (the total initial plus incremental deposit ranging between $30,000/MW generally to $75,000/MW for solar).
All of the Materials are still in draft form, and are still subject to change. While the general themes of the FIT have been outlined, the devil is in the detail for sophisticated project proponents. The OPA has recently released its revised Rules and Pricing and has received numerous comments and feedback on the Contract and associated documents. The OPA plans to launch FIT “this summer.”
2. Renewable Energy Approvals Process
On June 9, 2009, both the Ministry of the Environment (“MOE”) and the Ministry of Natural Resources (“MNR”) posted information on the Environmental Registry regarding the approval and permitting requirements for new renewable energy generation facilities, or expansions, modifications and redevelopments of such facilities (“Projects”). Projects with a nameplate capacity equal to or less than 3kW would not be subject to these approval requirements.
The MOE has also posted proposed regulatory amendments that significantly alter the traditional requirements for environmental assessment for renewable energy generation facilities. Specifically:
- Ontario Regulation 116/01 (Electricity Projects) and the Environmental Assessment Act will not apply to renewable energy generation facilities, subject to two exceptions: the establishment of hydro electric facilities 200MW or larger and expansions to existing hydro electric facilities that result in both a 25 per cent increase in nameplate capacity and result in the facility having a nameplate capacity of 200MW or more. Under these two circumstances, individual environmental assessments will be required.
- Ontario Regulation 101/07 (Waste Management Projects) and the Environmental Assessment Act will not apply to renewable energy generation facilities that are also a waste disposal site.
- It is also proposed that renewable energy generation facilities and renewable energy testing facilities that are carried out by the Crown, municipalities or public bodies are exempt from the Environmental Assessment Act as well as undertakings required to implement such projects such as roads and water crossings.
Existing applications for Project approvals before the MOE will be returned to the applicant when the amendments to the Environmental Protection Act come into force. At that point, applicants will have to resubmit an application in accordance with the regulation to obtain a Renewable Energy Approval (“REA”) and meet all of the requirements of the regulation. Similar language exists in the MNR draft document.
Under the MOE’s proposed regulation, Project proponents will be required to submit to the MOE a REA Application Form, along with certain prescribed supporting documentation. Projects currently holding all required approvals for their facility will not require a REA until an amendment to such approval is required or expires; subject to certain exceptions.
Once the MOE and MNR (as applicable) have determined that an application is complete, they will post a proposal notice on the Environmental Bill of Rights Registry (“EBR”). Following the public comment period, the MOE and/or MNR (as applicable) will begin a formal review of the application and will consult, where appropriate, other ministries and federal departments and agencies. The MOE and/or MNR’s decision will also be posted on the EBR.
In addition, the MNR draft document indicates that proponents that seek amendments to the facility prior to commissioning of the project, or proponents that make requests to expand, modify or redevelop commissioned sites may be required to complete some or all of the prescribed requirements set out in the MNR draft document.
Both the MOE and MNR proposed documents refer to the following requirements that would apply to all renewable energy generation projects: (i) Public notice and community consultation; (ii) Municipal consultation; (iii) Aboriginal consultation; (iv) Cultural heritage; (v) Natural heritage, including minimum setbacks maintained; (vi) Water bodies; and (vii) Provincial plans.
Although the details of how to apply for and receive REAs from MOE and MNR have not yet been released, the proposed streamlined process will simplify current requirements by consolidating the various individual applications and individual approvals previously required from various governmental authorities into a “onestop- shop” for REAs. However, an REA does not necessarily consolidate all approvals that may be required for projects and it will be important for project proponents to confirm what specific approvals the REA will cover.
Setbacks and Other Technology Specific Requirements
The regulations also provide for certain technology-specific requirements, including, noise setbacks for wind turbines, which are being challenged by the wind power industry. The ministry is proposing a minimum setback for wind turbines of 550 metres to ensure noise levels do not exceed 40 decibels at the receptor. The applicable setbacks would rise with the number of turbines and the sound level rating of selected turbines. Specifically, the MOE has proposed the following matrix for determining setback.
The wind energy sector has serious concerns about the draft setback regulation. The 550 minimum could limit the development of several projects that are in preliminary stages of development. In addition, wind power industry groups are advocating that 40 decibel noise levels can be achieved at smaller setbacks distances than the draft regulation.
There will also be specific requirements for biogas facilities (anaerobic digesters), biomass facilities (thermal treatment), landfill gas facilities and solar photovoltaic facilities. The MOE has also proposed noise setbacks for transformer substations and setbacks from roads, railways and property lines. Small-scale wind turbines (facilities with a nameplate capacity greater than 3kW but a sound power less than 102dBA) will also be subject to certain requirements.
Further, solar power projects that are greater than 10kW will be required to undertake a noise study. Solar industry groups are also advocating for change to this part of the draft regulation.
3. Ministry of Energy and Infrastructure
On May 15, 2009, the Ministry of Energy and Infrastructure proposed a regulation aimed at removing the legal barriers, such as municipal by-laws or encumbrances on real property, that could inhibit the promotion and development of renewable energy projects. The Ministry is seeking public input about which by-laws, agreements or restrictions should be amended and which ones should continue to operate, taking into consideration “cultural, health, safety and environmental” factors.
While more regulations are likely forthcoming, they have not been released as of this update.
4. Ontario Energy Board Initiatives
The Ontario Energy Board (“OEB” or “Board”) has adopted an issue-by-issue approach to addressing the array of changes required to the Ontario regulatory framework once the relevant portions of the Green Energy and Green Economy Act, 2009 are proclaimed into force. The Board has released a new section website to help stakeholders access information on its Green Energy Initiatives:
The Board’s Focus: New Infrastructure Investments and Cost Recovery
On April 3, 2009, Howard Wetston, the OEB Chair, set the tone of the Board’s approach: recognizing that under the Act utilities will be expected to make significant investment in infrastructure, the Board intends to examine whether alternatives to the current approach to cost recovery from ratepayers for capital investment are required to provide greater regulatory certainty to utilities making significant capital investments.
On June 1, 2009, Howard Wetston made a further announcement regarding infrastructure investment in anticipation of the proclamation of the Act and its amendments to the Ontario Energy Board Act, 1998. The OEB announced its intent to launch three initiatives that “will lay the foundation for an integrated framework for electricity infrastructure development” in Ontario. The three initiatives tackle:
A. Infrastructure Planning: Planning and funding electricity distribution infrastructure related to renewable energy generation and smart grid development;
B. Cost Responsibility: Cost responsibility and allocation surrounding the connection of renewable energy generation facilities to the distribution infrastructure; and
C. Cost Recovery: Cost recovery for electricity infrastructure investment.
True to these priorities, the Board has released material in respect of each of the following three initiatives:
A. Infrastructure Planning
On June 15, 2009, the Board issued Guidelines setting out the preliminary regulatory framework relating to accounting, funding and planning for distribution system development to accommodated renewable generation and/or develop a smart grid in anticipation of the deemed licence conditions regarding distribution system planning provided for in the Act (the “Guidelines”).
The Guidelines provide a preliminary structure for distributors to follow in preparing a plan for review and approval by the Board in relation to the accommodation of renewable generation and/or the development of a smart grid (a “Plan”). The Plan should cover a five-year horizon, and should clearly identify the information that formed the basis for the development of the Plan. The Guidelines provide additional detail about what the Board expects would be included in a Plan. The Board will review each distributor’s Plan to determine whether it demonstrates that the proposed near-term projects and activities (and longer-term projects and activities if described at the requisite level of detail) are appropriate to accommodate the connection of renewable generation facilities or useful in developing a smart grid, as the case may be, and represent reasonable approaches to achieving these goals. The Board will also review the method and criteria that the distributor has proposed to prioritize near-term projects and activities in the Plan.
In the Guidelines the Board has also established four new deferral accounts that electricity distributors may use to begin recording capital investments and expenses incurred in relation to qualifying projects undertaken to accommodate renewable generation or the development of a smart grid. While the Board has not capped the amounts that can be recorded in these new deferral accounts, the Board expects distributors to file a system development plan if they anticipate significant expenditures.
The Board is not, at this time, requiring all distributors to file formal system development plans covering renewable energy connection or smart grid development activities. However, during the summer the Board will require all distributors to report on their progress in relation to such infrastructure planning. The Board has indicated that over the next few months, it intends to hold a consultation process to develop the distribution system plan filing guidelines. At the end of this process, the Board intends to issue revised Guidelines.
B. Cost Responsibility
On June 5, 2009, the Board issued a proposal to amend the Distribution System Code’s cost responsibility rules (EB-2009-0077). The proposed amendments are aimed at reducing the costs renewable energy generators would have to pay to connect to the distribution system by having distributors cover all the costs of improving the capacity of a distribution system in order to accommodate renewable energy generation; and by having distributors and generators share the cost of expansions to the distribution system.
Currently, a generator that connects to a distribution system is responsible for paying all of the costs of connecting its generation facility to the distribution network. Under the proposed amendments, the Board has distinguished between three categories of distribution system investments: connection assets; expansions; and “renewable enabling improvements.” The Board has afforded a different cost consequence for the connection of renewable generation facilities for each of these three classes of investments depending on whether the proposed investment is included in a Board approved distribution system plan.
The Board’s proposed cost responsibility, which effectively socialises the costs that have been incurred exclusively by generators to distributors, is summarized as follows.
C. Cost Recovery
On June 10, 2009, the Board issued a Staff Discussion Paper on the Regulatory Treatment of Infrastructure Investment for Ontario’s Electricity Transmitters and Distributors that sets out a range of innovative, alternative mechanisms that the Board might consider to ensure that its rate-making policies promote or facilitate appropriate infrastructure investment (the “Discussion Paper”). These proposed incentives will facilitate the rapid integration of renewable energy generation facilities onto the electricity grid.
These mechanisms will, if approved by the Board, expand LDC options when seeking regulatory approval of their infrastructure investments. Board Staff have recommended that the Board adopt a case-by-case approach to the review and approval of applications for one or more alternative mechanisms to encourage appropriate investment because this will provide the most effective way of balancing the unique challenges and the particular circumstances of an applicant with the public interest. At a minimum, Board Staff recommend that the alternative mechanisms should apply to the recovery of costs incurred by electricity transmitters or distributors to accommodate the connection of renewable generation or to develop the smart grid, or both.
The Discussion Paper details the following five alternative mechanisms, designed alternatively to provide provisions for unforeseen events, accelerated cost recovery, and create incentives, as follows:
- Recovery of Costs of Abandoned Facilities: To reduce the uncertainty associated with higher risk projects, thereby facilitating investment in these projects, staff suggest that an applicant be allowed to request confirmation from the Board that prudently-incurred costs associated with any abandoned projects would be included in rates if such abandonment is outside the control of management.
- Construction Work In Progress: Staff believe that including construction work in progress in rate base prior to the asset coming into service allows the rate-regulated company to recover the carrying cost on this capital investment, typically interest costs on debt and a return on the investment, may be appropriate for electricity transmitters with significant expenditures on major new infrastructure projects with long construction periods spanning several years.
- Contract-term Depreciation: In the context of the extended obligations of electricity transmitters and distributors to invest, staff believe that in certain circumstances it may be appropriate to adjust depreciation on a capital asset to reflect a contract term which will likely be consistent with the useful life of the connecting renewable generation facility. Doing so would reduce risk to the transmitter or distributor of under-recovery of their investment.
- Project ROE Adders: Where an electricity transmitter or distributor is not “required” to undertake a project, and the project is perceived as particularly risky, a project-specific ROE may be appropriate to encourage proactive investment.
- Project-Specific Capital Structure: Staff believes that the Board could allow applicants to file a projectspecific capital structure, and give them the flexibility to refinance or employ different capitalizations as may be needed to maintain the viability of new infrastructure projects.
The Board has invited all interested parties to participate in this consultation to assist it in determining its policy on these issues. Written comments must be filed with the Board by July 7, 2009, in accordance with the filing instructions set out in a Board's letter dated June 10, 2009.
Conservation and Demand Side Management
Conservation and Demand Management (“CDM”) appears to be taking a back seat to other more pressing issues faced by the Board. The Chair noted in his June 1, 2009, statement that the OEB is developing instruments to address the target based and global adjustment-funded regime for electricity CDM, however these instruments have not yet been released. Further, on April 14, 2009, the Board issued a letter requiring rate regulated natural gas distributors to file a one-year Demand Side Management (“DSM”) plan, in contrast to the multi-year DSM plans that were initiated in the past, primarily due to the impact the Act will have on CDM which might require the OEB to develop a new DSM framework.
Other Board Initiatives
In addition to these statements of direction, the Board has already commenced a number of specific initiatives to change elements of its regulatory framework in light of the Act. Specifically:
- On May 14, 2009, the Board issued a proposal to amend the Distribution System Code to ensure timely connection of energy generating facilities (EB-2009-0088). The OEB emphasised the need to change the DSC rules, primarily s. 6.2, to ensure that electricity generation projects, specifically renewable energy projects, are integrated to the system in a timely manner. The Board indicated that these amendments are necessary to tackle the present backlog of generation projects awaiting connection to the distribution grid and they are also intended to accommodate renewable generation projects that will be triggered by the FIT.
- On June 10, 2009, the Board announced Distribution System Code amendments to extend the date by which distributors must eliminate long term load transfer arrangements (where one customer within one distributor’s service area is served by another distributor) to June 30, 2014, to allow distributors to develop load transfer arrangements that take into consideration smart grid development and renewable energy projects (EB-2009-0095).