The following is the text of a submission from APPrO to the OPA, July 8, 2008.
Ontario’s Clean Energy Standard Offer Program (CESOP) is a groundbreaking initiative that could position Ontario as a world leader in the development of distributed generation, and produce significant benefits for consumers and for the provincial power system as a whole. Much like the RESOP program, CESOP could foster innovation and attract investment that would otherwise be unavailable to Ontario. Because of the special characteristics of distributed generation, CESOP is expected to deliver a range of technical benefits well beyond those available through any other program, and could actually alleviate connection problems faced by other procurement programs in some cases.
In addition, CESOP projects can be expected to deliver significant environmental benefits. The environmental benefits fall into two broad categories: a) Those which result from the use of renewable fuels and/or the inherent efficiency of combustion in CESOP projects; and b) those benefits which result from the reduced operating losses and smaller overall investment requirements in the transmission and distribution systems.
The range of benefits does not stop there however. As outlined in APPrO submissions in previous consultation processes, there are economic benefits to local communities and businesses from small scale clean energy projects. They often help reinforce Ontario-based manufacturing and protect local jobs, and can be a key part of revitalization projects in urban and non-urban areas.
It is with an understanding of these potential benefits that the Minister of Energy issued his directive on August 18 2005 creating the CESOP program and its sister program, the Renewable Energy Standard Offer Program, or RESOP. Although the RESOP program has moved ahead quickly, Ontarians have been unable to benefit from CESOP because the program has not been released yet. APPrO believes this imbalance needs to be redressed in an expeditious manner and that it is therefore vital that the OPA respond to stakeholders quickly and remain firmly committed to its current schedule to release the program in the summer of 2008.
APPrO’s comments on the CESOP program are designed to facilitate the finalization and prompt release of CESOP, while ensuring that the expectations for attracting significant new investment into this important sector are met, as envisioned in the Minister’s directive.
It is crucial that the program be properly designed and oriented in order to attract the necessary investment, and deliver these benefits. Some changes are necessary to the CESOP rules if this is to be accomplished.
APPrO has invited input from a wide range of participants in the generation industry involved in the types of clean power generation under 10 MW that the CESOP program is designed to target. The following comments represent the collected wisdom of many people engaged in the industry, after significant reflection on the CESOP program as proposed and group discussion. APPrO provided similar advice to the OPA in July of 2007 when the previous draft rules were circulated for comment.
Although the group is recommending changes to the CESOP rules, there is wide support for the CESOP in principle, and for most of its basic design features. We congratulate the OPA for bringing forward a welcome addition to the procurement options available to distributed generation.
Recommendation 1: Keep the current model, but change a number of specific items on a timely basis
APPrO members believe the current program design is feasible but that change is necessary in a few specific areas. These areas can basically be outlined as follows
• Resolution of the basis for setting standard offer pricing
• Adjustment of parameters for Net Revenue Guarantee (NRG), seasonal heat rates, and VOM costs
• Correction of unlimited risk factor related to Revenue Sharing
• Minimum run times
• Refinement of outage options and eligibility rules.
Our recommendations in each of these areas are spelled out in the relevant later sections below.
We believe that a timely response is very important. This should not go back for additional analysis. It has taken nearly three years to get to this stage and there is no need for further delay.
Recommendation 2: Limit OPA risk by triggering program review at 24 months or 200 MW, whichever comes first
APPrO members believe that there is great value in having an open ended program with no upper limit on the program as a whole. Such an approach allows for complex projects which require extensive pre-development work to engage stakeholders to begin work with confidence the program will still be available when the pre-development phase is complete.
However, it is clear from the results of the RESOP program that the OPA needs to have a method to manage the risk that a large volume of standard offer applications could be submitted in a short period of time.
In particular because it is difficult to project the level of response to a standard price, SO programs usually feature a program review point at which the price is adjusted up or down to ensure it is reflective of current costs, and sometimes to increase or decrease the volume of applications.
For this reason, it is recommended that the CESOP program be reviewed, and potentially re-set its pricing, whenever contracts have been signed for 200 MW of new development, or 24 months after program launch, whichever comes first. It is assumed that the OPA will be applying milestones and other rules limiting applications to ensure that only genuinely viable projects would be counted amongst this 200 MW.
Although there may be some concern about sequencing of application reviews amongst developers who miss the cutoff point, we believe this can be managed within the OPA through a system of sequential numbering of applications, and a systematic approach to requesting complete documentation.
It must be noted however that this 200 MW figure is not a cap or an estimate of the potential level of CESOP development in Ontario. It is proposed purely to facilitate a quick refinement of the program in case its rules or pricing prove to be out of step with market realities. The technical potential for CESOP projects is of course many times this amount.
Recommendation 3: More rigorous development of the value based approach
The OPA has chosen to use a value-based approach to setting key program parameters, rather than a cost-based approach. (In other words, it is setting CESOP’s fixed capital and operating payments based on the expected value of CESOP projects to the Ontario power system, rather than setting those same payments based on actual costs of typical installations.)
APPrO believes that the value of CESOP services can best be estimated by looking at the results of the OPA’s CHP 1 RFP. There were four projects of 12 MW or less which received contracts under that RFP. This group has in effect set a realistic practical set of benchmarks for similar power projects – i.e. high efficiency and small scale. Net Revenues Required (NRR), the seasonal heat rates and the VOM (Variable Operation and Maintenance) costs for these projects would be a realistic and likely workable basis for the first phase of CESOP contracts. The parameters are demonstrably competitive, yet sufficient to allow for a certain amount of development.
The OPA said in its CESOP documentation that “the best definition of value is the cost that would otherwise have been incurred to acquire the same service as that offered by CESOP generation capacity.” The value provided by a CESOP project includes a combination of services including the amount of electricity, its load profile, reliability characteristics, auxiliary services, and its efficiency in production and distribution. CESOP is defined as part of the OPA’s efficiency and customer-side programs, so efficiency is clearly a component of the service being provided by CESOP projects.
It is inappropriate in principle to use a CCGT (Combined Cycle Gas Turbine) as the basis for estimating the value of CESOP projects because a CCGT does not provide the same service as CESOP projects. The primary difference is of course the higher thermal efficiency of CESOP projects, but there are other differences as well such as those related to load matching and integration into the distribution system.
There are serious pitfalls in the use of the value-based approach, primarily because it is so theoretical and requires testing against real-world experience. In fact, even the value-based approach used by the OPA to determine parameters for CESOP contracts includes a number of cost estimates, primarily those related to CCGT costs. The original Ministerial Directive did not specify the use of value-based systems, but to develop small high efficiency clean generation sources in Ontario.
APPrO members have concluded that the use of a value-based model as currently proposed is inappropriate for CESOP. We understand that when proper costs are included for CCGT projects, the model will produce inefficient results for the OPA, and relatively unattractive options for generators. We encourage the OPA to meet with analysts who can outline how these conclusions have been reached and in particular the likely results of a more rigourous recognition of CCGT costs.
Recommendation 4: Base Net Revenue Guarantee (NRG), heat rate and VOM costs on CHP1
The most useful and realistic figures for NRG, heat rates (seasonal) and Variable Operation and Maintenance costs come from the successful smaller scale proponents in the CHP 1 competitive process.
Recommendation 5: 4-hour minimum run-times
Given the need to maintain high efficiency profiles, continuous operation is important. A minimum run time of 4 hours allows for response to market conditions while meeting the requirements for scheduling human operators and the basic expectations for efficient operation.
Recommendation 6: Manageable exposure through RSP
It is not practical to expect small operators and third party hosts of power projects to enter into contracts that make them even partly responsible for an unknown and unlimited amount of cash outlays as implied with the Revenue Sharing Payment (RSP) system as currently understood. Typically, boards, lawyers and lenders will reject an obligation that carries that kind of risk for 20 years, particularly with smaller scale projects of this type whose owners and managers are typically focused on a primary line of business completely unrelated to the energy sector.
While the principle is reasonable that sharing excess revenue with the OPA when that revenue results from high prices is a natural consequence of the OPA limiting generators’ exposure to low prices, the revenue sharing mechanism should not create major unquantified risks for developers or hosts. Because deemed operation during high price periods could be used to create expected cash obligations to the OPA at times when a generator is not actually operating, the RSP should be structured as deductions from payments the OPA is obliged to make to generators in any given month. It should be designed with a cap and so as not to create any net obligations from generators to the OPA in any given month. If sustained periods of very high prices are anticipated, the system of deductions could be supplemented with further revenue sharing based on actual rather than deemed operation.
Recommendation 7: Flexible outage arrangements
Even though the current rules as proposed only require a 90% availability, there are situations in which unplanned outages could be experienced that are not the fault of the generator. The CHP contract allows for periodic restatement of heat rates, but that does not appear to be an option with CESOP. Therefore, to accommodate temporary shutdowns and/or other unexpected situations, it is recommended that the generator be permitted to declare voluntary outages on a short term or long term basis, during which time the OPA is under no obligation to make any payments to the generator, and the generator will be incurring no additional financial obligations to the OPA.
Recommendation 8: Broaden eligibility
If projects meet the other criteria of the CESOP program, we believe that projects in service before 2005 and those with previous contracts should be eligible for CESOP (as long as the CESOP contract does not apply to the same power output as the previous contract.) See the addendum below from July 2007 for further explanation of the principles underlying our thinking eligibility of existing projects.
Recommendation 9: Contingency plan and future changes
Because of the concern that the majority of potential projects may find the current terms insufficient to incent new investment, we put forward the following recommendations:
1. Consider a change to the rules such that any later strengthening of the CESOP program which is made by the OPA, such as the escalation of NRG, would be made available retroactively to the original applicants under the program.
2. We suggest that the OPA develop a contingency plan to strengthen the program and increase uptake if successful applications do not reach the expected level in the first six months, while maintaining the assurance of the present program terms as a minimum for 2 years.
3. We recommend a thorough stakeholder review of the program by the end of its second year of operation, or whenever 200 MW have been contracted, with a view towards making adjustments that would assure the CESOP delivers the desired level of generation.
4. It is important that the administrators of CESOP declare at an early stage that any subsequent changes made to the program will not adversely impact any existing projects contracted under this program.
Recommendation 10: Similar treatment for byproduct fuel-fired generation projects and projects fuelled by under-utilized energy sources
As stated in Recommendation 3, a more rigorous development of the value based approach is also required for this group of projects. The value estimation may follow the approach based on CHP 1 RFP described earlier. Alternatively, the biomass projects under RESOP may also be a suitable benchmark.
The capital structures of biomass and under-utilized fuel projects are quite varied and diverse. Like the small CHP projects, they often have very little in common with CCGT projects, in terms of their capital structure.
Further comments
As noted in our comments of July 20, 2007, our group is generally of the view that while the design of the CESOP is attractive in principle, uptake will likely be very modest in its present form. With prices as they are, the program is likely to be attractive to the small subset of potential projects that have a near-perfect thermal match to start with and low internal hurdle rates. As presently designed the CESOP will not likely elicit the desired amount of development from the much larger set of potential projects that could deliver efficiency benefits to the province: Greenfield projects, those which require significant investments to maximize their efficiency, and those which require the involvement of third party developers.
This program design is more complex than the previous version and as a result, more difficult to explain to hosts and potential partners. Third party developers can handle the level of complexity, but the current financial parameters do not allow room for third parties in most cases.
We believe it will be important for the OPA to help disseminate a broader understanding of capital costs, net revenues and the resulting ROI needed for high efficiency projects. Generally speaking, the higher the efficiency, the higher the capital cost of a project. More complete recognition of the $2000 to $2500 capital cost per kW, and the underlying reasons for it, in later refinements of the CESOP terms will very likely improve the success rate of the program. While certain projects may not require this level of capital costs, it should be recognized by the OPA as typical, and adjustments made to CESOP to reflect this understanding.
The current market does not properly compensate for increasing efficiency or increasing efficiency of generation. If it did, there would be no need for the OPA to have efficiency programs. However, once capital equipment able to take advantage of efficiency opportunities is installed and operating, its owners can be expected to respond to market incentives to ensure the available efficiency opportunities are met. This produces long term value for ratepayers, much greater than simply the value of displacing power from CCGTs.
The OPA should actively monitor and report to generator stakeholders the status of activity on the “Short Circuit issue” in the Toronto area.
There’s no direct recognition for distribution system benefits in the proposed CESOP rules. It has been clearly demonstrated that smaller scale projects, more widely dispersed as in CESOP, create undeniable system value. These benefits in large measure should accrue to the entity developing them as opposed to being averaged out and accruing to all rate payers who had little to no involvement in creating them.
Addendum
1. Eligibility of existing projects (From APPrO’s July 2007 submission)
It would be suboptimal if the CESOP program were encouraging new generation while existing generating capacity is allowed to go idle. If the program is to achieve provincial objectives for enhancing supply and reducing overall emissions, it is important to treat all generation that can provide the desired results as eligible for the program.
Generators recognize that it is unreasonable for a project to benefit from more than one contract at a time. For example, no one project should be able to benefit from a NUG contract or early mover contract while also qualifying for the CESOP. However, once the NUG or early mover contract has expired, or if it is voluntarily terminated, then the project should be eligible for CESOP for any power generated at a later time. And when expiry of a contract is anticipated, there should be no impediment on the representatives of a project seeking to secure another contract to allow for continued operation, as long as the two contracts do not apply to the same power production.
Fortunately, the total amount of existing generation that would likely qualify for the CESOP is relatively small. Recent research by Peter Ronson (provided separately to the OPA) indicates that even with the broadest definition of eligibility, there would be relatively small amounts involved. For example, going back to 1998 there are fewer than a dozen projects, 3 of which already have early mover contracts. The maximum amount of existing generation that could qualify for CESOP in this case would be less than 50 MW.
Although some may argue that the capital cost of existing generation is lower, this is not always the case because existing projects have to renew their capital investment. In any case, pricing under the CESOP is based on value to the OPA, rather than the cost of production. It is just as important to keep existing generation on the grid as to get new generation.
The principle should be that any plant that delivers the stated benefits and is not under a contract, be eligible for CESOP.
Note to reader: The comments above represent the general view of most participants in a discussion process led by APPrO, but they may not represent the specific positions of every individual involved or of their respective organizations. It is a general consensus and should be seen as the collected wisdom of many people engaged in the industry after serious reflection and group discussion.
For more information on this submission or on APPrO’s work in the area, please contact Jake Brooks, Executive Director: