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By Charles Rhodes, P.Eng., Ph.D.

The government of Ontario made a public commitment to phase out coal fuelled electricity generation. However, replacing coal fuelled electricity generation with any form of non-fossil fuel electricity generation is expensive.

From the perspective of the Ontario electricity ratepayer a kWh generated by renewable distributed generation located near an end user is a kWh that does not require central nuclear generation and does not have to flow through the transmission system. It seemed to make economic sense for the government of Ontario, acting on behalf of the electricity ratepayers, to offer a premium for environmentally acceptable distributed renewable electricity generation, subject to the amount of the generation being measured and the cost of the incentive, including its administration, being less than the cost of alternative nuclear generation and related transmission. However, the devil lay in the details.

A Feed-in Tariff (FIT) is a relatively simple means by which small renewable generators can be paid standard prices for the electricity that they generate. A Feed-in Tariff provides an administratively practical means of implementing distributed electricity generation. However, experience would show that the feed-in tariff offered was many times the market value of the electricity generated.

The Ontario Power Authority Feed-in Tariff (OPA FIT) was enabled by the Ontario Green Energy and Green Economy Act, 2009.

The OPA MicroFIT was a simplified version of the OPA FIT. The MicroFIT was intended to be applied to residential and small commercial installations where the maximum generator output is less than 10 kW.

On April 5, 2012 the OPA announced new FIT and MicroFIT price schedules.

The OPA FIT program allowed FIT generators to operate without constraint. The OPA implicitly assumed that the power and voltage fluctuations caused by unconstrained FIT generators would be balanced by dispatched generation. In effect the OPA implicitly assumed that FIT generation would always be a relatively small fraction of total generation.

This author believes that these assumptions by the OPA are inappropriate, expensive and dangerous. These assumptions implicitly commit Ontario to large amounts of transmission connected natural gas generation for balancing renewable generation and further commit Ontario to numerous transmission/distribution enhancements to meet worst case fluctuations in unconstrained renewable energy generation. This author believes that the OPA FIT and MicroFIT programs should be modified to strongly incent both local energy storage and generation constraint. The contemplated modifications would reduce renewable energy power fluctuations that must be met by dispatched central generation and enhanced transmission/distribution. The contemplated FIT program modifications would also largely eliminate the CO2 and other emissions related to operation of inefficient natural gas fuelled combustion turbines that the OPA plans to use for generation balancing. As of April 11, 2012 the OPA contmplated paying 1.35 times the posted FIT rate for on-peak power and 0.9 times the posted FIT rate at all other times. This rate difference is not sufficient to meet the generators costs related to energy storage and intermittant output.

The Ontario Power Authority (OPA) FIT circumvents existing Ontario electricity rate structure and rate determination problems related to generator financial compensation. A OPA FIT contract can be used by small generators to obtain a limited amount of commercial financing.

The present implementation of the OPA FIT allows unconstrained generators using renewable energy sources to operate at random times and sell the electricity that they generate to the grid at a fixed rate. With the exception of solar generation the present OPA FIT does not adequately reward reliable generation that is coincident with the provincial electricity demand peak and pays too much for electricity that is generated at times of low electricity demand. The present OPA FIT implicitly assumes that there is always uncommitted dispatchable energy generation and energy storage available for system balancing. However, after closure of coal fuelled electricity generation, there is relatively little low cost system balancing generation.

A problem with the present OPA FIT implementation is that it does not consider the costs of energy storage for balancing renewable generation. The OPA FIT should financially reward renewable generators that have sufficient on-site energy storage to maintain close to a 100% daily capacity factor and should pay more for late summer generation than for early spring generation.

Another problem with the present OPA FIT implementation is that participating generators are not required to contribute to grid voltage regulation. Hence these FIT generators reduce system reliability and increase the black start and voltage instability problems. These issues will become major in the future. The FIT program should be modified now to address these matters.

The OPA FIT and MicroFIT circumvent existing rate structure and metering issues through the use of interval kwh meters that are connected so that a building with behind the meter generation is billed as if the generation were not present. The FIT generator is treated as a separate LDC account. This metering methodology appears to be one of the major successes of the OPA FIT implementation. However, the FIT rules need to be modified to enable and encourage on-site energy storage. The FIT implementation must heavily penalize anyone who charges FIT energy storage from the grid.

With the exception of solar generation the OPA FIT does not presently provide a substantial price bonus for electricity that is reliably delivered coincident with the daily peak load on the electricity grid. One means of ensuring coincidence of generation with peak load is to reward high generator capacity factor, and hence efficient use of transmission/distribution.

The OPA FIT should provide electricity price bonuses for generators that assist in grid voltage regulation and grid black start and that do not require external reactive power. The present OPA FIT implementation does not achieve any of these electricity price bonus objectives.

A problem with the present implementation of OPA MicroFIT is that, with the exception of solar and biogas the pricing is less than the value of marginal energy for reducing rural Hydro One residential and small commercial electricity bills. Hence, participation in the OPA MicroFIT program does not make financial sense for many small rural generators. The cumulative effect of this behind-the-meter self generation is indistinguishable from rural electrical energy conservation.

A further issue with implementation of FIT and MicroFIt is that due to communication problems many rural areas are not yet served by functional TOU electricity meters. Hence the FIT and MicroFIT rules need a separate category for FIT and MicroFIT projects at sites where only rudimentary metering is practical.

Other major problems with the present OPA FIT implementation are:
1. The OPA FIT energy price offered for hydroelecticity that has late summer availability is not sufficient for commercial viability. Hence, the present implementation of the OPA FIT will not realize the amount of non-fossil fuel summer generation that Ontario requires;
2. The FIT AND MicroFIT energy pricing offered by the OPA does not incent energy storage;
3. The OPA FIT energy pricing for hydro does not provide sufficient "up side" potential to attract major equity investors.
4. The OPA FIT energy pricing does not contemplate all generators paying for grid use and hence lacks an administratively practical means of ensuring high power quality, high power factor and high capacity factor from OPA FIT generators;
5. The FIT rules do not adequately address the issues of directional interval kWh meters and implementation of an energy pricing formula that incents high power quality, high power factor and high capacity factor.

For about 25 years the full cost of non-fossil fuel electricity generation in Ontario has been concealed from the general public. The concealing accounting mechanisms are so complex that many senior persons in the energy sector do not understand them. Successive provincial governments of all political stripes have failed to properly address this issue. Currently Ontario has about $20 billion in stranded electricity bond debt. Electricity in Ontario is still sold far below its intrinsic value. Correcting this situation requires a substantial electricity rate increase which politicians are loath to face. However, the reality is that if this issue is not promptly faced insufficient non-fossil fuel generation will be built and Ontario will become more rather than less dependent on fossil fuels. Then extricating Ontario from fossil fuels will become much more difficult and much more expensive.

In addition to the existing $20 billion in stranded electricity bond debt the OPA is proposing about $60 billion in additional planned expenditures relating to transmission upgrades and replacement or refurbishment of existing electricity generation. However, the present OPA plan does not include any allowance for new generation or transmission/distribution required to meet the additional electricity load caused by: increases in air conditioning, increases in immigration triggered by global warming and by substitution of electricity for liquid fossil fuels in the transportation and heating sectors. A minimum estimate of the cost of this additional generation is:
$8000 / base load kW X 10,000 MW X 1000 kW / MW = $80 billion Recent experience indicates that when the cost of the related transmission/distribution is included this amount could easily double.

Hence the minimum amount of public electricity debt that must be financed over the forseeable future is about:
$20 billion + $60 billion + $80 billion = $160 billion
This amount could possibly increase to $240 billion

This debt principal is between $10,000 and $15,000 for every man, woman and child projected to live in Ontario. The only source of funds of this magnitude is insurance and pension funds, so the net return on investment to an investor providing financing for the electricity system must be competitive in the insurance and pension fund market. Servicing this debt will require at least $16 billion per year on top of existing electricity rates. Obtaining that additional revenue will require at least doubling the average end user electricity rate in Ontario.

The immediate task facing the OPA is to implement FIT program changes including distributed generation constraint and energy storage incentives that are sufficient to attract large scale private sector investment in non-fossil fuel electricity generation and related energy storage. Failure of the OPA to adequately address this matter will eventually lead to a non-fossil fuel electricity shortage in the Province of Ontario.

Issues that should be considered by the OPA in reassessment of FIT pricing include but are not limited to:
a) Charging all generators for transmission/distribution use on the same terms as general load customers, thus increasing the HOEP and reducing load customer transmission/distribution charges;
b) Use of direction sensitive interval kWh meters and congestion factor rates for fair allocation of both energy and transmission/distribution costs. These meters are applicable to a network containing distributed loads and distributed generation. These meters and congestion factor based electricity rates encourage use of energy storage by both generators and load customers while preventing excessive costs to equipment owners related to short term maintenance shutdowns;
c) Implementation of congestion factor rates for both generators and load customers to encourage use of energy storage at both generator sites and load sites;
d) Long term rate guarantees for parties willing to build distributed generation and/or energy storage;
e) Recognition that the cost of private sector capital for financing fixed assets for electricity generation and energy storage is much greater than the cost of government guaranteed debt.
f) Recognition that past vascillations of the government of Ontario caused many parties who invested in Distributed Generation and Energy Storage to lose money. In the near term an expectation of significant profit will be required to motivate these parties to reinvest.

Congestion Factor based electricity rates should be used by both the OPA and the Ontario Energy Board (OEB) to encourage use of energy storage for leveling generation and load profiles. To the extent that energy storage that is financially enabled via congestion factor based rates does not achieve matching of generation and load profiles, then more expensive dispatched generation and/or load must be used to achieve the required profile matching. The economics of distributed generation depend in part on how well the total generation output matches the total grid load. The cost of storing energy during one season and recovering this energy during a later season is quite high.

An alternative means of establishing FIT and MicroFIT pricing inclusive of energy storage and transmission/distribution is to use the same effective rate as is arrived at for large new non-fossil fuel generation projects such as out of province hydraulic generation or new nuclear facilities. If FIT and MicroFIT pricing is too low and if as a consequence insufficient FIT and MicroFIT generation or energy storage is built, then more expensive out of province hydraulic generation or new nuclear generation will be required. Conversely, if FIT and MicroFIT pricing is set too high the ratepayer would be financially better off with a large central non-fossil fuel generation.

The FIT related legislation effectively provides the OPA a mechanism to implement a large increase in electricity price without being bogged down in regulatory matters.

There are various practical issues relating to wind power. Wind generation without adjacent energy storage has several major problems.

1. The first problem is that without energy storage the reliable wind generation that is coincident with the peak electricity load is almost zero. In some weeks the peak co-incident wind generation is very low right across Ontario. Furthermore, most good wind generation sites are located near the shores of large water bodies. The wind at such locations reverses direction twice in each 24 hour period. At the times of the wind direction reversals the wind generation drops to zero. In order to provide reliable power coincident with the daily electricity demand peak wind generators must be complemented by local energy storage systems.

2. The second problem is that the daily peaks in wind generation usually occur at times when the provincial electricity load is close to minimum. In order to be economically beneficial the wind energy needs to be stored during the load off-peak period and then later released during the load on-peak period. Local energy storage is required to address this problem.

3. The third problem is that in Ontario the average wind generation in the summer is less than 20% of the peak wind generation. Hence wind generators without local energy storage use transmission very inefficiently and do not significantly contribute to meeting the summer peak load. In order to contain the costs of transmission remote wind generators should be fitted with adjacent electro-chemical energy storage. Excess wind power should flow to storage. Wind power deficiency should be made up from energy storage. At present there is no financial incentive for wind generators to adopt adjacent energy storage.

4. The fourth problem is that most wind generators currently in use in Ontario do not contribute to grid voltage stability. In principle this problem can be solved by adding electro-chemical energy storage, a voltage source inverter and a control system to each wind generator. The net power versus voltage input-output characteristic should be programmable.

The financial analysis at Distributed Generation indicates that, with government guaranteed debt financing, wind generation with sufficient energy storage to reliably follow a winter weighted load costs about $.31 / kWh. At present the OPA provides the wind generator $.115 / kWh for unconstrained land based wind generation.

In some circumstances, where the load is geographically close to the wind generator or where the load is winter weighted, wind generation with adjacent energy storage may be less expensive than new nuclear generation plus transmission.

It is believed by this author that in calculating the FIT energy rate for wind the OPA assumed that the FIT generator had nearly free access to the electricity grid. If the change in transmission/distribution rate structure proposed at Transmission/Distribution Cost Apportioning is adopted a generator will likely have to pay for transmission/distribution at an effective rate of about $.0157 per kWh delivered to the grid. Hence, in addition to the average energy rate of $.31 / kWh for wind generation with adequate energy storage, calculated at Distributed Generation, the Feed-in Tariff will have to be increased by a further $.0157 per kWh to offset the cost of transmission/distribution borne by distributed generators.

Natural gas fuelled co-generation could be provided under a Feed-in Tariff. As shown on the web page titled Distributed Electricity Generation the corresponding Feed-in Tariff for on-peak electricity generation with a 50% capacity factor and 80% thermal energy recovery via co-generation would have to be about $.40 / kWh. This rate may need further adjustment to reflect transmission/distribution and fuel costs borne by the generator.

The costs related to integrating the co-generation heat recovery system with an existing multi-zone building heating system should not be underestimated.

There are many practical operating and maintenance issues related to small natural gas fuelled prime movers that have yet to be fully appreciated by the regulatory authorities.

An issue that has not been appreciated by the Ontario Energy Board (OEB) is that addition of significant amounts of natural gas fueled generation to the local distribution grid frequently requires increasing the short circuit clearance capacity of nearby branch switchgear. Recently when Toronto Hydro sought a rate increase, in part to address this issue, the OEB denied Toronto Hydro the required rate increase.

This author is not a strong advocate of natural gas fueled co-generation because the combination of increased CO2 emission, increased capital costs, increased maintenance costs and complex legal, thermal storage and interface issues in practical applications indicates that other means of electricity generation often provide a better overall solution.

This web page last updated March 19, 2017.

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