XYLENE POWER LTD. - REVISE

ELECTRICITY RATE STRUCTURE

By C. Rhodes

ONTARIO ELECTRICITY RATE STRUCTURE PROBLEMS AND THEIR SOLUTIONS:
Various parties have advocated that Ontario adopt a distributed electricity generation system with private sector owned generation to minimize risk for the ratepayers. The rate structure of this contemplated system should incorporate either a fossil carbon emissions tax or a non-fossil fuel generation incentive. However, the electricity rates presently approved by the Ontario Energy Board (OEB) are not consistent with the return-on-investment required by new privately owned generators, are not sufficient to repay the existing stranded electricity debt principal, do not penalize fossil carbon emissions and do not discourage inefficient use of the transmission/distribution system by renewable generators.

Correcting the problems in the Ontario electricity system requires energy storage equipment, suitable Generator Capacity Factor and Load Factor dependent electricity rates, behind the meter generation and replacement of monthly peak demand metering and billing with cumulative directional kWh metering and congestion factor based billing.

There is also merit in offering a discounted electricity rate for power that can be frequently interrupted under dispatch control without notice. Such interruptable power can potentially displace expensive constrained generation for grid voltage and frequency stabilization. Potential applications for such power are charging the batteries of plug-in hybrid vehicles, charging energy storage systems and displacing fossil fuels in hybrid heating systems.

ENERGY STORAGE:
The first major problem with the existing rate structure is that it does not sufficiently reward renewable generators for providing generation that reliably contributes to meeting the peak provincial electricity demand and does not sufficiently reward consumers for reliably reducing load coincident with the peak provincial electricity demand.

In order to reliably provide electricity coincident with the peak provincial electricity demand wind generators require adjacent energy storage facilities. Such energy storage facilities will not be built unless there is a capacity factor based rate benefit that is sufficient to fund the energy storage system.

In order to minimize transmission requirements all generators must be billed for transmission/distribution use in proportion to transmision capacity dedicated to the generator. A congestion factor within the rate provides an incentive for wind generators to use adjacent energy storage to achieve efficient use of transmission/distribution.

STRANDED ELECTRICITY DEBT:
The second major problem with the existing Ontario electricity rate structure is that stranded electricity debt related to old nuclear facilities is charged to all electricity users rather than just the old nuclear generators and the charge is not sufficient to reduce the stranded debt principal. The costs of servicing this stranded debt should be met from revenue earned by existing nuclear generation facilities and by a fossil carbon emissions tax. This revenue should be sufficient to discharge the stranded debt in a reasonable time frame (< 10 years). As shown on the web page titled Stranded Debt Retirement the required increase in the nuclear generation price is about $.042 / kWh and the consequent effect on the average HOEP is an increase of about $.021 / kWh.

New non-fossil fuel generation will be more expensive than existing nuclear generation, so it is unrealistic to continue with an electricity price that is not sufficient to fully fund the existing base load nuclear generation.

FOSSIL CARBON EMISSIONS TAX:
The third major problem with the existing electricity rate structure is that the energy portion of this rate structure is derived from the HOEP which in turn is strongly affected by the cost of electricity obtained by combustion of coal and other fossil fuels. In order to encourage construction of non-fossil fuel generation to displace coal it is necessary to compensate owners of this non-fossil generation at the rate that would prevail if fossil fuels were subject to a coal prohibitive fossil carbon emissions tax.

On the web page titled Fossil Carbon Emissions Tax it is shown that the fossil carbon emissions tax required to effectively prohibit use of coal for electricity generation is about $200 / emitted CO2 tonne. This tax causes a cost adder for coal fueled electricity generation of about $.244 / kWe-h. Since coal is about 18% of total Ontario electricity generation, the increase in the average HOEP that would be caused by application of this tax to coal fuelled electricity generation is:
.18 X $.244 / kWe-h = $.044 / kWe-h.
When similar adjustments are made for existing oil and natural gas fuelled electricity generation, the net effect of applying a $200 / emitted CO2 tonne fossil carbon emissions tax to electricity generation in Ontario is to increase the average HOEP by about:
$.054 / kWe-h.

Regardless of whether or not a formal fossil carbon emissions tax is actually implemented, an electricity revenue source of this magnitude is required to fund rapid repayment of the Stranded Electricity Debt principal, which is a prerequisite for economic funding of the OPA Integrated Power System Plan (IPSP).

Even if a formal fossil carbon emissions tax is not implemented in Ontario in the near term, it is essential to immediately reward new non-fossil fuel generators as if such a fossil carbon emissions tax were in effect, in order to build up sufficient non-fossil fuel electricity generation to displace existing fossil fuelled electricity generation. That is the objective of the Feed-In Tariff under the Green Energy Act. It is also important that this non-fossil fuel generation be fitted with adjacent energy storage and output controls so that the IESO can modulate the net generation output to match the grid load.

TRANSMISSION/DISTRIBUTION COST ALLOCATION:
The fourth major problem with the existing rate structure is that large generators such as Ontario Power Generation (OPG) and Bruce Power have free use of transmission/distribution whereas small behind the meter generators do not have free use of transmission/distribution. The hidden cost of providing large generators with free use of transmission/distribution is an obstacle to implementation of both energy conservation and distributed generation. If the Ontario Energy Board (OEB) forced large generators to pay for transmission/distribution at the same rate per kVAh as small electricity customers, then as shown on an adjacent web page titled Transmission/Distribution Cost Apportioning, generators would have to add about $.013 / kWh onto their energy rate in order to have the cash flow to pay Hydro One Networks. Hence the Hourly Ontario Energy Price (HOEP) would increase by about $.013 / kWh. Then Hydro One Networks and the Local Distribution Companies (LDCs) could lower their transmission/distribution charges to end users by the same $.013 / kWh. For electricity consumers that made no change the net effect is zero. However, for those customers that implement generation that exports energy to the grid, the value of that exported energy increases by:
2 X $.013 / kWh = $.026 / kWh.

EFFICIENT USE OF TRANSMISSION/DISTRIBUTION:
The fifth major problem with the existing rate structure is that it does not reward generators for efficient use of transmission/distribution. Recent experience with wind turbines indicates that the average hourly wind turbine output can easily vary over a 25:1 range through a month. In order to efficiently utilize transmission/ distribution wind turbines require adjacent energy storage facilities to reduce their output power range by about a factor of three. These energy storage facilities will not be built unless there is a significant rate incentive. This rate incentive has two components, a Time-Of-Generation (TOG) kWh rate and transmission/distribution related daily kVAh rate. A cumulative daily kVAh meter is required to fairly allocate transmission/distribution costs.

REPLACEMENT OF LOAD CUSTOMER PEAK DEMAND METERS WITH CUMULATIVE DAILY DIRECTIONAL kWh METERS:
A sixth major problem with the existing rate structure is that existing transmission/distribution costs for commercial customers in most LDC service areas are based on monthly peak kVA or monthly peak kW instead of cumulative daily directional kWh. The practical effect of monthly peak kVA or monthly peak kW billing is to excessively penalize small behind the meter generators and energy storage systems, thus eliminating these generators and energy storage systems from the electricity market. Such generators and energy storage systems typically need to be briefly shut down for routine electrical, mechanical or thermal load service about once per week. However, since the service times are random and statistically non-coincident, less than 10% of the recorded monthly peak demand billed to the building owner by the LDC as a result of equipment shutdown for routine maintenance is actually billed to the LDC by Hydro One Networks. This opportunistic discriminatory billing by the LDCs seriously devalues behind the meter generation and energy storage from the building owners' perspective. The metering methodology and LDC rate structure must be changed if distributed power generation and customer owned energy storage are to be realized.

OPPOSITION BY UTILITIES:
A related problem with the existing rate structure is that changes to this rate structure will be strongly opposed by LDCs, Hydro One and OPG unless the package of rate changes is implemented in a manner that leaves these parties financially whole. The lead opponent of large scale distributed generation will be Toronto Hydro. With reasonable transmission/distribution rates, widespread implementation of co-generation in high rise residential buildings within Toronto would likely reduce Toronto Hydro's gross annual revenue by over $100,000,000. This financial estimate is based on the actual performance of co-generation systems that were installed in high rise residential buildings during the period 1996 to 2000 when there were favourable TOU rates. Toronto Hydro, Hydro One and OPG may take the position that absent corresponding electricity rate increases that leave them financially whole, they are unable to absorb revenue losses of that magnitude.

Eliminating the present discriminatory peak demand charges may require the OPA to make temporary interim payments to the LDCs to keep them financially whole.

TRANSMISSION/DISTRIBUTION INFRASTRUCTURE:
During the last 20 years there has been under investment by the Province of Ontario in electricity transmission and related rural distribution. The surplus capacity that existed in the early 1990s has been taken up by a growing population and delayed maintenance. The problem of locked in power at the Bruce Nuclear Generation Station has re-emerged after being dormant since 1992. The Ontario Power Authority (OPA) is facing immediate multi-billion dollar expenditures on transmission system upgrades that will have to be financed by via increases in transmission/distribution rates.

INFLATION:
Another major problem with the electricity rate structure is that it does not recognize inflation that affects the cost of new generation. The Ontario electricity supply is presently dominated by relatively low cost old generation. New generation is inherently more expensive because the available low cost renewable energy generation sites have been exhausted and because of inflation in costs of labor and materials. New non-fossil fuel generation cannot be built for the average cost of old non-fossil fuel generation. New non-fossil fuel generation will not be built in appreciable quantity until the electricity purchasing process recognizes this inflation issue. Thus the TOG energy rate applicable to new generation must recognize this issue. A good estimate of the average TOG payment rate for new generators is the theoretically constrained cost of new nuclear power, which from Equipment Financing with government guaranteed debt, is reasonably estimated to be:
$.3252 / kWh + transmission-distribution cost.

This average TOG rate for new non-fossil fuel generation should put existing central generators and new distributed generators on a level playing field except for the cost of financing and should enhance the reliability of the Ontario electricity grid by encouraging development of non-fossil fuel distributed electricity generation and energy storage where ever that generation and energy storage make economic sense.

COST OF CAPITAL:
In various speeches executives of the OPA have indicated that it is the intention of the OPA to obtain new generation from multiple parties at guaranteed long term rates. Such guarantees require the use of private capital instead of taxpayers and ratepayers funds. The return on investment required by such private capital for Ontario electricity sector investments is typically three times the return on investment required by Ontario government guaranteed debt. The use of private capital without government debt guarantees will substantially increase the cost of electricity but will introduce competition and will prevent irresponsible governments from accumulating further public debt relating to electricity generation. It remains to be seen whether or not the OPA will actually implement feed-in tariffs that are sufficient to attract the necessary private capital. The proposed feed-in tariff for unconstrained on-shore wind generation of $.135 / kWh may not be sufficient to attract private capital on the scale that is necessary to solve Ontario's long term electricity supply problems. Also the present feed-in tariff proposal does not address the issue of the energy storage required to ensure that the total electricity load is reliably met.

Distributed generation, new nuclear generation and energy storage cannot be built on the scale required until the cash flow received by the owners of the new generation and energy storage is sufficient to fully fund design, construction, operation and maintenance of these new facilities.

OTHER CHARGES:
Toronto Hydro also bills end use customers $.0015 / kWh as a Market Transition Charge and $.0062 / kWh as a charge for Wholesale Market Operations including Rural Rate Protection.

ADJUSTED END USER ELECTRICITY RATE:
After the aforementioned rate adjustments, the average cost of electricity to an end user will be:
+ $.062 / kWh (present average HOEP)
+ $.013 / kWh (transmission/distribution cost transferred to HOEP)
+ $.0157 / kWh (transmission/distribution paid by end user)
+ $.021 / kWh (electricity debt retirement transferred to HOEP)
+ $.054 / kWh (fossil carbon emissions tax effect on HOEP)
+ $.0015 / kWh (market transition)
+ $.0062 / kWh (regulation)
= $.1734 / kWh plus GST

This rate represents the average cost of electricity with the present generation mix. Rate increases related to funding the IPSP and due to more peaky than average load profiles are additional to this amount.

The minimum required average net increase in the end user electricity rate is:
$.068 / kWh
and is composed of:
$.054 / kWh (fossil carbon emissions tax applied to debt retirement)
+ $.021 / kWh (ongoing debt retirement)
- $.007 / kWh (existing debt retirement)
= $.068 / kWh
In the view of this author this rate increase should be implemented immediately in a single step because it is required now to encourage non-fossil fuel generation and energy storage and to discharge existing stranded electricity debt. This debt discharge is a prerequisite for economic funding of the IPSP. The OEB should be aware that there will have to be an additional substantial rate increase in order to fund the IPSP. It is hoped that by the time the IPSP costs significantly impact the rate payers the electricity related fossil carbon emissions will have diminished sufficiently that the net cost effect of the additional rate increase on electricity consumers will be quite small.

RATE CHANGES AND INTERIM INCENTIVES:
It will take many years for the effects of past government capital financing guarantees to work their way out of the HOEP. In the interim the OPA and the OEB should encourage construction of distributed non-fossil fuel generation by imposing a $200 / emitted CO2 tonne fossil carbon emissions tax on electricity generation in Ontario, should triple the stranded electricity debt retirement allocation and should provide realistic additional rate incentives to non-fossil fuel generators.

If new non-fossil fuel generation is privately financed with no government guarantees the TOG rates received by the generation owner should be twice the rates that would prevail with an Ontario government debt guarantee. This issue is detailed on the web page titled Equipment Financing.

The proceeds from the fossil carbon emissions tax should be applied to reduction of the stranded electricity debt principal.

Presently wind generators and run-of-river generators without energy storage take up a disproportionate fraction of Ontario's transmission capacity and diminish the economics of other non-fossil fuel generation that is needed to meet Ontario's peak power requirements. To avoid this problem all new generators should be subject to TOG rates that have sufficient on-peak / off-peak price differential that wind and run-of-river generators can and will finance adequate adjacent electro-chemical energy storage. This adjacent electro-chemical energy storage should have sufficient storage capacity that the net electricity output is a constant fraction of Ontario's total electricity requirement throughout the year.

The limited amount of available hydraulic generation and pumped hydraulic energy storage should be reserved for seasonal balancing of wind generation and IESO controlled load following for grid voltage regulation.

INTERRUPTABLE LOAD:
One method of reducing the amount of energy storage required at wind and run-of-river generators is to sell their electricity output as interruptable power. Interruptable power is electricity that can immediately be replaced by another fuel such as oil, gasoline, diesel fuel, propane, ethanol, etc. For example, the electricity might be used for hybrid heating or for charging the batteries of a plug-in hybrid vehicle. Provided the customer also has a fully functional alternative fuel system, then the electric power is interruptable. Interruptable electricity is not as reliable as firm power, but it has the advantage of costing less because of the reduced requirement for energy storage at the supplying generators.

A load customer with his own electro-chemical energy storage or thermal energy storage should benefit from a Time-Of-Use (TOU) rate differential similar to the TOG rate differential provided to renewable energy generators.

Amounts paid to new non-fossil fuel generators, in excess of the adjusted HOEP, should gradually diminish over time as the aforementioned rate structure problems are eliminated and HOEP increases.

IMPLEMENTATION:
The payment changes and rates to generators and load customers set out herein could be immediately implemented by the OEB and the OPA by amending the Feed-In Tariffs and the general electricity rates. Resolving these tariffs and rates is primarily a matter of political will.

This web page last updated July 18, 2009.