Ontario’s Feed-in-Tariff program – what is still missing
There are a number of issues critical to the shape of Ontario's Feed-in-Tariff (FIT) program where provincial government action is still required. This second article on the FIT program will address these issues. To jump to a particular section, use the table of contents to the right. To read the first article on the main changes to the program, click here.
August 31, 2009 By Thomas Brett
Renewable Energy Approval (REA)
Perhaps most important is the final REA regulation. The Green Energy Act established a new approval process for renewable energy projects. A draft regulation prepared by the Ministry of the Environment to implement this approval process has been released and comments have been solicited from stakeholders. In addition, the Ministry of Natural Resources (MNR) has published a lengthy paper on policy and procedure. Under current law, projects with different renewable sources have different approval processes, and require different groups of permits. As noted earlier, the Renewable Energy Approval will replace the approvals currently required from the Ministry of the Environment under the Environmental Assessment Act, the Environmental Protection Act, the Environmental Bill of Rights, and the Ontario Water Resources Act. Moreover, the Green Energy Act exempts renewable energy projects from the provisions of the Planning Act. The REA does not replace any of the approvals currently required under the legislation administered by MNR, and that is not likely to change, at least in the short term. In addition, the draft regulation has proposed set-back requirements for wind projects and definitions of rooftops that appear not completely thought out and which have been strongly opposed by the wind and solar energy industries, respectively. They will likely be modified. The transition provisions are also very important as many applicants have spent considerable time and money complying with the existing laws and it is critical that they not be required to start over.
Solar on farm land
The Ministry of Energy is still dealing with the extent to which it should permit ground-mounted solar projects on Class I and Class II farm lands. The farm community appears divided on the issue, and the whole debate seems like a “tempest in a teapot” as the amount of ground solar likely to emerge would occupy a relatively small amount of prime farm land, even if it were all built on such land, which it would not.
Finally, the government has not yet published the regulations on Ontario content, which the Green Energy Act requires. The Ministry of Energy has been consulting with industry groups, but the details of the plan are still unavailable, with estimates of likely Ontario content ranging from 10% to 40% of project cost. The complexity of the issue is illustrated by Subsection 13.3(a)(ii) of the revised Rules, which requires any wind or solar project, which aspires to an early FIT contract during the launch period, thought by some to be a “guarantee” that their projects will get into production, to have purchased a defined “Major Equipment Component”, which has been through an “Irreversible Manufacturing Process”, in Ontario. The definition of the latter term appears to rule out machines that have been assembled in Ontario from parts produced elsewhere. A sensible balance between substantial requirements and some discretion is needed during the transition period.
What is missing
The most obvious gap in the scope of the program in the absence of any separate tariff for small residential scale, wind machines. While the economic benefits of project scale are reflected in the pricing for water, biomass, biogas and in particular, solar projects, small wind projects are paid the same price per kwh as large scale projects. No serious observer believes this is appropriate, particularly in an allegedly “cost-based” regime. In Australia, small wind projects enjoy a feed-in-tariff of about 60 cents. In Europe, prices are similar. In the United States, in addition to utility contracts, small wind projects enjoy an uncapped federal tax credit of 30% of total cost, and often additional state incentives. The market for small wind projects is increasing very rapidly in the United States, Britain, Germany, and France with substantial potential in Asia. While Canada has perhaps 700 small wind installations at the moment, there is potential in urban areas with the appropriate incentives. Moreover, there are small wind system and component manufacturers in Ontario, some of whom have received senior government R&D support. But the Canadian residential market is stalled.
Tariff levies (prices) have been adjusted in some cases. The revised prices can be viewed here.
Assessment and comments
The Ontario Power Authority (OPA) has worked long and hard on the FIT program, has consulted stakeholders extensively and, for the most part, made good progress. They, and the Ministry have also had to deal with a Minister who has strongly intervened on certain issues. With the exception of small, residential scale wind machines, the FIT contract prices seem about right. Prices for small wind projects need to be much higher, in the range of 60 to 80 cents. Aside from small wind pricing, there are several other areas where improvements are necessary.
First, the OPA needs to recognize the status of those generators that have received completed Customer Impact Assessments (“CIAs”) and capacity allocations from distributors (queue positions in the old parlance), pursuant to the Distribution System Code (“DSC”). These companies have acquired a right to connect which has real value (indeed some have sold these rights to others, which is legal under the current DSC, for considerable sums). They have also, in some cases, expanded considerable efforts to advance their projects, and that effort and legal status should be acknowledged in the launch period, by way of allocating a fifth criteria, to the ranking mechanism. In some cases, these companies will have already attracted investors, acquired site control, and made progress on the technical design of these projects. Some will have held off some development efforts after the cancellation of the RESOP program, pending clarification of the terms of the FIT program, and such action is understandable. In any event, the OEB’s proposed amendments to the DSC will ensure that their projects will now advance quickly or lose their capacity allocation. It will ensure the projects are shovel-ready very soon. Their status has been conferred by a regulatory agency under a well understood and clear legal process, which does not discriminate against other companies which have not acquired such status. The OPA can continue to use the launch period rules to set priorities for dealing with the remaining projects.
Second, an important practical issue is that the OPA will need to make sure it has the resources needed to assess a great many projects in a timely manner. The existing group of OPA and government ministries’ employees, and their outside advisors, have worked very hard to develop the program and deserve a great deal of credit for doing so. Although the task of assessing compliance with the program rules should be fairly straightforward, with the possible exception of the Ontario content issue, there will be many details to work out. For example, the OPA has only a skeletal legal staff and outside legal and contracting help may be needed to ensure timely resolution of any legal issues, in particular, site control, and the need to customize the standard OPA contract to the particular circumstances of a myriad of different types, sizes, and configurations of renewable generators. One contract will not fit all circumstances and the OPA will have to tweak the contract to some degree. The Feed-In-Tariff Program is likely to survive a long time due to powerful currents flowing in both energy and carbon markets. The Ontario electric utilities, heretofore reluctant partners in distributed generation, are displaying the zeal of converts, to the point of, in some cases, plunging into the generation business as part of their regulated utility businesses. That activity will tend to support the program, and, hopefully, reduce overall distribution losses and other costs.
Third, the OPA should not perform any “economic test” to rank order proposals in the FIT Production Line and FIT Reserve, for several reasons.
First, the government and the OPA have already decided the prices they will pay for each type of renewable energy. These decisions settle the “economics” of the commodity. Second, the cost of connecting the generation facility to the distribution system or the transmission grid is borne by the proponent. As for the costs of expansion of distribution and transmission assets, where necessary, to accommodate the connection, to the extent those costs are borne by parties other than the generator, the Ontario Energy Board already assesses the economics of any transmission or distribution expansion, or has the jurisdiction to do so, if it chooses, through both leave to construct and rate proceedings, the latter of which must, among other things, approve capital expenditure levels and projects, to a degree of granularity decided by the Board. In exercising its mandate in this area, the Board must follow the policy goals of the government and the Green Energy Act, in particular, those sections of the Act which direct it to require that the distributors that it regulates plan for, and work hard to implement the connection of renewable energy projects, on a “priority basis”.
The proposed revised Transmission System Code provides additional guidance as it speaks to the way in which the Board will ask transmitters to finance the connection of clusters of renewable energy generators.
In addition, the Ontario Energy Board (OEB) must review the OPA’s Integrated Power System Plan (now being revised by the OPA at the behest of the Minister of Energy) to ensure that it is “economically prudent” and “cost effective”.
Finally, a number of practical questions arise concerning the wisdom of the OPA trying to apply such an “economic test”. The “modeling” of the projects’ costs, especially system enhancement costs would be difficult. Distributors have very different cost structures, projects are situated in very different terrain, and are different in relation to structures, streets, waterbodies, and the like. “Modeling” is always controversial, and is only as valid as the data and assumptions that go into it. If there is a model, it will need to be made pubic, or its integrity will not be trusted, and either private or public, it will be controversial. It is one thing to use a high level model to sketch the broad priorities for generation sources and transmission locations in an energy plan, but quite another to use a model to differentiate between two projects, which allegedly have different impacts for the transmission and distribution system. The distributors have the necessary detailed information about their costs and system structures, and geography. They should be responsible for setting the priorities and timing for connection, subject to OEB supervision. The OEB also decides which transmission distributions expansions and enhancements will proceed, who will pay for them, and, which if any of the distribution system costs shall be deemed “transmission costs” and collected from all provincial ratepayers. OEB processes should ensure that aggrieved parties have an opportunity to make their case for connection in a relatively transparent and apolitical process and to convince the regulator that the expansion or enhancements are needed, and are sufficient, and that the rate impacts are tolerable. The OPA is more subject to political control exerted privately or publicly by way of specific directions. The OPA should not venture into this territory, other than through the preparation of the plan itself, which, as revised, must reflect, among other things, the priorities reflected in the Green Energy Act. Their proposed “economic test” is unnecessary and will serve to further delay projects.
It is worth repeating that the policy underlying the Green Energy Act is to ensure that as many green energy projects get built as possible, given the prices the government is willing to pay. By far the largest component of the cost of electricity is the commodity cost. The costs of distribution and transmission, in the aggregate, and on a unit basis, are much lower. The institutional framework should be organized to encourage the maximum feasible uptake of renewable energy, given the capacity of the transmission system and distribution system, and to respect the historic role of the Ontario Energy Board to regulate access to the transmission and distribution system. It is the Ontario Energy Board that should and will decide how much infrastructure is required and where, and at what cost, to implement the Green Energy Act. In this respect, it will be guided by its legislation and regulations and policy directives from the government, which require it to be guided in turn by, among other things, any OPA Integrated Power System Plan that it approves.
Change of control
The OPA should not restrict the assignment of an application, or a FIT contract, or put restrictions on the sale of control of an applicant, provided that it is satisfied that the transaction will not diminish the likelihood of the project being developed successfully or operated successfully, and that the new owner of the contract or the project, has agreed to be bound by the FIT contract provisions and the Rules. Project development is a disorderly business and entrepreneurs continually bring in new partners, selling down or increasing their economic interests, and assigning some projects to third parties in order to keep others. This pattern is as true of the renewable energy industry as it is in the oil and gas industry. Such transactions are frequent and are essential to building a company. There does not appear to be a significant policy interest to justify the current restrictions in the Rules and the draft contract. There is clearly a policy interest in having as many renewable projects as possible get into commercial production in the next few years, and one way to do this is to afford applicant companies maximum flexibility in their capital structure and contractual arrangements. The regulations here should be results driven, not process driven. Many other industry participants have made this point.
Unilateral contract termination
The OPA should not be able to unilaterally cancel a FIT contact once signed. This power will discourage investors from investing in the industry, not least because the proposed liquidated damages do not cover any equipment purchased or even cancellation payments pursuant to equipment purchase contracts. Again, it is not clear what the underlying policy interest is here. A relatively short deferral based on a delay in the transmission or distribution construction schedule may be understandable. But is inappropriate to attempt to apply another “economic test” to a project once it has a FIT contract. Once the contract is signed and the capacity is allocated by the distributor, the applicant must be sure that it will not be second-guessed. Such a practice or even the specter of it would be a substantial disincentive to investment.
A recent OPA response (in Q&A 10494) discussed the issue of what payments will be made to an operating generator where the IESO has requested them to reduce their output. The OPA indicated that, in that circumstance, it would pay an Additional Contract Payment, of an amount yet to be determined. Assuming the payment fully compensates the generator with the FIT price, that is acceptable. However, the answer goes on to suggest that if a generator is curtailed for any other reason, for example, in order to maintain grid stability, it would not be compensated. This approach is wrong. The generator’s costs have been incurred, and he has promised his investors a return. The generator should be given the FIT price whenever it is curtailed by anyone for reasons that are not performance related.
Thomas Brett ( firstname.lastname@example.org ) is a partner at Fogler, Rubinoff LLP.
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