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

This web page addresses the reasons for allocating dependable clean electricity system costs to consumers based primarily on monthly peak demand in kWe rather than monthly energy supplied in kWhe.

An English language discussion of major retail electricity rate issues.

For the purpose of commercial transactions an adequate definition of energy is "capacity to do work". Doing work causes a change in measured cumulative energy of the form:
(Eb - Ea)
Ea = measured cumulative energy at time Ta
Eb = measured cumulative energy at time Tb.

However, the commodity that most power consumers want and are willing to pay for is power P on demand; that is, capacity to immediately do work at the rate desired by the consumer. If this power P is integrated from time T = Ta to time T = Tb the result is a change in energy:
(Eb - Ea).

Fuels such as coal, oil and natural gas contain chemical potential energy. These fuels can be burned at a consumer's premises at a consumer controlled rate to provide heat. Since hydrocarbon fuels can be economically stored at or near the consumer's premises the fuel delivery rate only needs to be sufficient to match the average thermal power demand, not the peak thermal power demand. However, hydrocarbon fuels deliver heat rather than work. In order to do work they require an additional engine which typically consumes 2 to 4 units of heat to provide one unit of work.

Electricity is propagating electro-magnetic field energy (photons). Electricity can do work but it cannot be economically stored. Electrical energy can be converted into chemical, gravitational or compressed gas potential energy, and then later converted back into electricity but the conversion efficiency is low and the cost of the required energy conversion and energy storage equipment is high.

Hence in practice in most jurisdictions, including Ontario, there is relatively little on grid energy storage. Instead the rate of electricity generation is modulated to match the total instantaneous consumer electrical power demand. Electricity generation and transmission systems are sized to reliably meet the highest anticipated annual consumer power demand coincident with a 15% unplanned generation and/or transmission capacity failure. In a clean (non-fossil) electricity system the fixed costs that must be borne by the electricity rate payers are proportional to the reliable peak power delivery capacity, not the average power used. The relationship between peak load power Pp and change in energy (Eb - Ea) is:
Pp (Tb - Ta) (LF) = (Eb - Ea)
where (LF) is known as the load factor. Note that:
0.0 < (LF) < 1.0

Rearranging the above equation gives:
(LF) = (Eb - Ea) / [Pp (Tb - Ta)]
= Pa / Pp

Pa = average power
= [(Eb - Ea) / (Tb - Ta)]

Further rearrangement gives:
Pp = Pa / (LF)
= [(Eb - Ea) / ((LF) (Tb - Ta))]

The amount of electrical energy absorbed by a customer in a billing period of duration (Tb - Ta) is:
(Eb - Ea) = Pa (Tb - Ta)

Ro = the blended electricity cost per kWh of dependable electrical energy at LF = 1.0

To encourage operation at a high load factor the monthly energy bill should be:
Ro Pa (Tb - Ta) / LF
= Ro Pp (Tb - Ta)
= Ro [(Eb - Ea) / ((LF) (Tb - Ta))]

The amount of energy actually drawn in billing period (Tb - Ta) is:
[Pp LF (Tb - Ta)]

The cost of that energy is:
[Ro Pp (Tb - Ta)]

Hence the customer's average cost of energy per KWh is:
[Ro Pp (Tb - Ta)] / [Pp LF (Tb - Ta)]
= [Ro / LF]

Notice that increasing a customer's load factor LF decreases the customer's average cost of dependable electrical energy per kWh.

This equation is of fundamental importance in electricity rate design. This equation shows that in a clean electricity system improvement of load factor LF is at least as important as is energy conservation in reducing electricity system costs. Energy savings that proportionately reduce load factor LF produce no electricity cost savings. However, an increase in load factor LF can reduce the peak power which creates system wide electricity cost savings. Hence an important issue in electricity rate design is financially incenting each customer to maximize his/her load factor LF.

Electricity rates should meet six fundamental objectives:
1. Provision of revenue sufficient to regulate, finance, build, operate, maintain, replace and continuously upgrade a highly reliable electricity system;
2. Fair allocation of electricity system costs to each load customer based on that customer's proportionate use of electricity system resources;
3. Fair allocation of electricity transmission/distribution costs to generators based on each generator's proportionate use of transmission/distributon system resources;
4. Provision of rate structure imbeded cost signals that encourage efficient use of shared electricity system resources by all parties (eg high power factor, high load factor, low harmonic generation);
5. Provision of control sigmals to load customers that trigger use of surplus clean electricity in place of fossil fuels at times when the electricity system has surplus clean generation capacity available that, if not immediately used, will go to waste;
6. Enabling price and performance competition between the electricity generators.

In an electricity system there are fixed and variable costs. Fixed costs are the ongoing costs of system capacity that remain the same irrespective of the amount of electrical energy consumed by customers. Variable costs are costs like fuel purchases that increase in proportion to the amount of electrical energy consumed by customers. As an electricity utility transitions from fossil fuels to nuclear and renewable energy the the variable costs decrease to almost zero but there are increased fixed costs. The cost of providing power on demand to a particular customer becomes dominated by that customer's fractional use of the dependable portion of the total electricity system power delivery capacity.

Electrical engineers are in general agreement that the best measure of the dependable electricity system capacity used by a customer is the customer's peak kVA measured during times when no interruptible electricity is available.

In calculating the peak kVA for billing purposes it is appropriate to ignore short term transient kVA peaks caused by electricity service interruptions that are outside the customer's control. It is also appropriate to award the customer any system cost benefits that arise from load diversity. To account for load diversity while still following the provincial load profile the measured peak kVA should be averaged over a sliding 2 hour period.

The electricity supply includes randomly operating renewable generation. Much of this randomly operating generation will be wasted unless the total load varies with the total generation. It is beneficial to incent customers to use surplus low cost interruptible non-fossil electrical energy (kWhe) in place of fossil fuel energy (kWht) whenever there are non-fossil electrical kWh available that are surplus to the dependable electricity service requirements. Since a non-fossil electricity system has times when there are surplus unused kVA and has other times when there may be insufficient kVA, it is beneficial to adopt an electricity rate that provides very low cost kWhe at times of surplus to customers who consistently reduce their kVA at times of electricity shortage. To fairly allocate the surplus kWhe a portion of the customer's electricity bill should vary in proportion to kWhe consumed. The monetary value of a kWhe should be approximately determined by the alternative free market export value of those kWhe. The Global Adjustment should be entirely recovered via the charge per kVA.

The per kWhe charge must be kept small to encourage fossil fuel displacement and development of energy storage.

The monetary cost of a marginal kWhe must be substantially less than the monetary cost of a kWht from fossil fuels so that customers are encouraged to use the surplus kWhe to displace fossil kWht whenever possible.

As a practical example, the electricity rate might be $30.00 / kVA-month + $0.02 / kWh. In this example it is assumed that the peak kVA meter is bypassed whenever the Independent Electricity System Operator (IESO) signals that non-fossil electricity surplus to Dependable Electricity Service (DES) requirements is available.

In each billing month each customer has a characteristic electricity load profile. This profile consists of N measurements of cumulative electricity consumption made at uniform time intervals. Each of these measurements of cumulative energy Eci indicates the average power Pci during the previous metering period dT.
Pci = (Eci - Eci-1) / dT

N = 730
dT = 1 hour.

If all customers had the same load profile, then each customer's profile would be linearly proportional to the grid load profile and it would be fair to allocate electricity system costs strictly in proportion to each customer's measured energy consumption. However, in general individual customer load profiles do not track the grid profile so pure energy billing is quite unfair and sends wrong signals to customers.

Another crucial issue is that in an electricity system dominated by non-fossil generation electricity system costs are only weakly proportional to energy consumption but are strongly proportional to a customer's contribution to peak grid power demand.

Another crucial issue is that the cost per kWh of providing electricity to base load customers is much less than the cost per kWh of providing electricity to customers with load peaks that coincide with grid load peaks.

One of the best ways to measure electricity system cost attributable to a particular customer is to measure the customer's monthly peak load and assume that the customer's peak load is co-incident with the grid peak load. However, if a customer has major appliances that randomly cycle on and off it is essential to use a mathematical averaging technique so that the customer is not over billed for a statistically random rare consumption peak. With single family residential customers this issue was historically addressed by treating them as a rate group in which diversity within the rate group reduces the peak demand cost for the members of that rate group.

For example, in a 200 suite high rise condominium tower with individual suite metering a bulk meter for the entire building will always measure a peak demand much less than the sum of the individual suite peak demands. This issue is known as statistical demand diversity. In the past high rise buildings in Ontario were all bulk power metered. In some buildings individual suites were energy metered and building peak demand charges were allocated to individual suites in proportion to suite energy use. This was a workable system of fair electricity cost allocation and politicians were foolish to tamper with it.

However, a problem with simple energy only metering is that it fails to reward customers who present flat loads instead of time varying loads to the electricity system.

A valid criticism of the above rate formula is that it does not include any incentive for additional interruptible electricity use at times when there is surplus non-fossil energy available. If a customer is serious about use of interruptible electricity that customer should adopt (demand + energy) metering and billing.

A major advantage of this billing methodology from the customer's perspective is that it does not overly penalize a customer for a rare load peak, whereas a peak demand based electricity rate charges a customer for his monthly demand peak regardless of when or why that demand peak occurred.

A major advantage of this billing methodology from a distribution utility perspective is that its implementation does not require any hardware changes. The implementation changes are strictly in the back office billing software. However, it is essential that the distribution utility not face extra costs such as might be caused by inappropriate application of the Global Adjustment (GA). The GA should be charged to the distribution utility based on that utility's monthly peak demand. The distribution utility has to pass that GA on to retail customers based on each customer's estimated contribution to the utility's peak demand. That estimate will be proportional to the otherwise billed amount. Hence a high load factor retail customer will pay less GA / kWh than a low load factor retail customer.

The aforementioned billing methodology will provide a financial incentive to retail customers to improve their load factor and hence reduce peak demand. However, that incentive is nowhere near as obvious to the customer as is a peak demand meter reading. Hence sophisticated customers who are prepared to invest in load control should be encouraged to adopt (demand + energy) metering and billing.

A load customer's use of power actually consists of three components. There is power that is converted into heat during the process of transmitting energy from the generator through the grid to the load customer. There is power that is absorbed from the grid and converted into heat or other energy forms at the customer's premises. There is power that is reflected from the customer back into the grid and then converted into heat within the local distribution system.

The electricity metering and billing system should take into account the total cost of grid resources required to reliably supply all of these power components when the grid is heavily loaded. Thus the customer's cost allocation should be based on the sum of transmission losses at a power factor of unity plus his/her absorbed power plus his/her reflected power. These measurements should be done at a grid peak load time using a directional interval electricity meters.

An electricity customer can be characterized by:
1. Absorbed energy over a billing period measured in kWh;
2. Absorbed power as a function of time;
3. Incident power as a function of time;
4. Response to IESO control signals.

The net absorbed energy in kWh is a parameter that most load customers conceptually understand. However, in a non-fossil electricity system the energy absorbed by a particular customer does not reasonably reflect the fraction of the electricity system resources that are used by that customer. A load customer that has behind the meter generation or that presents a reactive load can have a relatively small absorbed kWh consumption while using a lot of shared electricity system resources. A much better indicator of the electricity system resources used by a customer is the measured peak value of:
(Incident Power) = (Absorbed Power plus Reflected Power) = kVA
during each billing period. The peak demand meter should be calculated for each sliding 2 hour period.

Note that to fairly allocate electricity system costs the fraction of the electricity system resources used by a customer A is:
(Incident Power for customer A) / (Sum of all incident powers for all customers).
This fraction fairly allocates transmission/distribution loses and savings due to load diversity.

In any particular month the exact value of the denominator of this fraction may not be known at the time electricity bills are prepared. Hence it is common practice in rate determination to make a reasonable estimate of the denominator based on historical data. The value of the denominator is updated annually.

One of the properties of a balanced 3 phase resistive load is that its power drain from the grid is constant. Hence, for such a load, the instantaneous power is equal to the average power. This is the most efficient way of coupling a load to the three phase AC grid and at any particular time should attract the lowest transmission/distribution charges per kWh of energy transferred.

Inefficient use of the transmission/distribution system should be financially penalized. If a customer presents a reactive impedance, harmonic distortion or a fluctuating load to the grid then that customer should be allocated a larger fraction of the transmission / distribution costs.

The higher the uncontrolled fluctuations in power transfer rate, the less efficiently the generation and transmission/distribution systems are utilized. If a customer presents a resistive load that varies from measurement interval to measurement interval that customer should be charged more per kWh for for generation and transmission/distribution than is a customer that draws an equal amount of energy at a constant rate.

Major reliable dispatched non-fossil generation is purchased by capacity rather than by energy. Smaller unreliable random renewable generation is purchased by cumulative energy supplied. The total costs of major generation and transmission in Ontario are almost constant, independent of the number of kWh actually consumed by Dependable Electricity Service (DES) customers. These costs should be allocated to DES customers in proportion to the fraction of system generation and delivery capacity used by each customer, as indicated by a peak kVA measurement for each billing period.

Wind and solar generation intermittently supply energy to the grid. Run of river generation supplies seasonal energy to the grid. However these renewable energy sources provide little or no reliable kVA on hot summer evenings when generation is in shortest supply. Renewable energy has a low monetary value unless it is complemented by some form of energy storage that makes the intermittently generated energy available when it is needed.

The geography of Ontario is not conducive to seasonal energy storage, except for Lake Erie-Lake Ontario gravitational energy storage. However, these two water bodies are subject to numerous political jurisdictions, where there is difficulty getting any agreement. Hence in Ontario the primary opportunity for energy storage is daily thermal energy storage behind customer meters.

If generation and delivery costs are allocated to customers in proportion to the customer's use of shared generation and delivery resources a customer can minimize his electricity cost by using automatic load control and behind the meter thermal energy storage to maintain a nearly constant load. Hence it is essential that the electricity rate financially incent purchase, installation, operation and maintenance of behind the meter load control and thermal energy storage equipment. The object of this equipment should be to control the load to take advantage of available non-fossil generation. For loads that are not controlled by the IESO (Independent Electricity System Operator) the control objective should be to achieve a flat load profile over time.

There is potential opportunity for load customers in Ontario to install behind the meter thermal energy storage, but such energy storage will not be built unless the end user electricity rate is primarily peak kW demand or peak kVA based. This author points out that in the early 1980s there was a lot of behind the meter thermal energy storage in Ontario but by the mid 1990s most of that energy storage was decommissioned due to a shift from peak demand based electricity rates to energy based electricity rates. However, many buildings in Ontario built prior to 1980 still have the structural foundations, interior basement space and electrical services required for significant behind the meter energy storage.

Connected to the electricity grid are multitude of parties with different objectives. If the effective electricity cost per kWh is sufficiently dynamic there are parties such as owners of plug-in hybrid vehicles and/or thermal energy storage systems that will consistently increase electricity consumption at low marginal electricity prices and decrease electricity consumption at high marginal electricity prices.

Parties that will consistently attempt to sell most of their electricity output at a high price are owners of hydro electric generators with storage dams.

Parties that will attempt to buy electricity at a low price and sell it at a high price are owners of pumped energy storage systems.

In order to encourage development of these different groups it is necessary to adopt an electricity rate with sufficient dynamic range to allow all of these groups to exist and financially prosper. To achieve a high dynamic range the cost per kWh of energy at the margin must be low and the cost per kW for peak demand cost must be high. Thus far the Ontario Ministry of Energy (MOE) and the Ontario Energy Board (OEB) have paid little attention to this issue.

The electricity cost has 11 components: fuel, generation, transmission, transmission loss, central energy storage, central energy storage loss, retransmission, retransmission loss, distribution, local energy storage and administration.

In non-fossil energy systems fuel costs are low to negligible. Fuel and central energy storage can be lumped into the generation cost and the distribution can be lumped with transmission into a common delivery cost, so that the cost categories reduce to:
generation, delivery, local energy storage and administration.

For reliable non-fossil generation costs are almost fixed and are independent of the amount of electrical energy actually transferred.

The best indicator of reliable generation and delivery resources used by a load customer is the customer's measured peak kVA during the billing period averaged over a sliding four hour interval.

Generation costs are presently allocated to all customers in proportion to the customer's energy consumption. Instead generation costs should be allocated to all customers in proportion to the system capacity used by each customer as indicated by the customer's measured peak kVA during the billing period. If a peak kVA meter is not available then the best substitute is a peak kW measurement.

In Ontario at present a major portion of the electricity system fixed costs is contained in the Global Adjustment, which politicians have applied to kWh rather than kVA. This political misallocation of costs has led to a cascade of electricity system, renewable energy and climate change related problems that cannot be fixed until this cost misallocation is corrected.

Delivery costs are presently allocated to large commercial-industrial customers in proportion to the customer's monthly peak kW demand or peak kVA and are allocated to residential customers via a fixed or variable delivery charge. With smart metering delivery costs for all customers should be allocated in proportion to the customer's monthly peak kW or peak kVA. The billing meter software used for peak kW or peak kVA measurement should have a 90% step response time of 4.3 hours so that the peak kW or kVA measurement fairly indicates actual contribution to the Ontario grid load profile without over charging the customer for short term load peaks due to random load switching or due to load surges that occur on recovery from a prolonged grid power failure.

Half of total transmission costs should be allocated to transmission connected generators measured peak kVA. The other half of transmission costs should be allocated to transmission connected loads and to Local Distribution Companies (LDCs) in proportion to their measured peak kVA. Local distribution costs should be allocated to load customers in proportion to each load customer's measured peak kVA during the billing period. The billing period could be one week, two weeks or one month.

Measurements of transmission and distribution energy loss within the Hydro One system indicate that without any central energy storage the average transmission and distribution loss is about 9.2% of the energy actually absorbed by load customers. In the past in Ontario transmission loss costs were allocated to residential customers in proportion to the customer's energy consumption. In the future, transmission loss costs should be allocated to load customers in proportion to each customer's use of generation, transmission and distribution resources, as indicated by his/her measured peak kVA during the billing period.

At this time there is little transmission connected energy storage in Ontario and there is no specific allocation of transmission connected storage costs to load customers. Where transmission connected energy storage does exist its costs are rolled into either generation costs or transmission costs. However, the presence of more transmission connected energy storage would increase the value of renewable electricity generation by making more renewable energy available when customers need it. In this respect the 2016 500 MW intertie agreement with Quebec may be a small step in the right direction.

Distribution and administration are fixed costs which in a particular year are independent of the amount of energy actually consumed by electricity customers. At present these costs are allocated to residential and small business customers as a fixed monthly delivery charge. Distribution costs should be allocated to load customers in proportion to their use of distribution resources, as indicated by the measured peak kVA during the billing period.

Behind the meter energy storage costs are unregulated and may be the subject of a contract between a building owner and an energy management contractor. These contracts are complex because they involve substantial investments that in Ontario law are treated as fixtures to the building. Hence these investments should be secured by a first charge on property title. Mortgage lenders are frequently unwilling to grant that first charge to another party.

As a matter of public policy the wholesale electricity rate at which local electricity distributors purchase firm electricity from the provincial transmission grid is uniform across grid served areas of the Province of Ontario.

The only rate issues open to discussion are the time duration of kVA or KW meter averaging period and the length of each billing period (1 week, 2 weeks, 4 weeks, 1 month).

Historically the electricity billing period in Ontario has been one month. During an average year the cost of electricity generation is very high for about 50 hours per year or for 4.16 hours per month. There are complex statistics involved, which can be summarized by saying that in principle the average contribution of a particular customer's load to the peak grid load in any billing period can be obtained by finding the peak value of the customer's demand and applying a customer class diversity factor.

This author favors a one week billing period because field experience indicates that a one week billing period would provide more incentive for customer response than does a one month billing period. For administrative convenience four or five successive one week bills could be combined in a single monthly invoice.

Thus economic replacement of fossil fuels with electricity entails operation of most dispatched generators at a nearly constant power output and shifting the moment by moment grid power control from generators to loads. Under a kVA based electricity rate a firm electricity customer with a variable power requirement is financially incented to install sufficient energy storage and/or hybrid heating to convert his variable load into a nearly constant load.

It can be mathematically shown that a consumer's fair share of the distribution costs during a particular measurement time interval is proportional to the peak value of his/her incident power measured in kVA. This principle is not new. It has been used for many decades by electricity distribution companies for allocating costs. The methodology set out herein is simply a generalization of that principle. The customer's RMS current is proportional to the fraction of the current capacity of the distribution system that is used by the customer. The RMS voltage indicates the operating voltage of the distribution system. The product:
[(RMS current) X (RMS voltage)] = kVA
indicates the amount of distribution system transformer and power transmission capacity that must be allocated to the customer. A three phase customer can be viewed as being equivalent to two or three single phase customers, depending on whether the three phase customer is delta or wye connected.

There is a subset of electricity loads that need inexpensive energy, not power on demand. These loads involve processes that are not sensitive to the time at which the energy is delivered. These loads are best served by an Interruptible Electricity Service (IES). Examples of such loads are: fossil fuel displacement in hybrid heating systems, production of electrolytic hydrogen, electrolytic production of high energy content materials such as lithium, sodium, aluminum, fluorine, chlorine, ammonia; and charging of stationary energy storage systems. The value of IES supplied energy is proportional to the number of absorbed kWh.

An Interruptible Electricity Service (IES) rate is an electricity rate that applies only to an unreliable but low cost per kWh electricity that can only be effectively used by parties or processes where the supply of electricity can be randomly interrupted without notice and without serious consequences. Interruptible electricity generally comes from use of otherwise constrained or exported non-fossil electricity generation that presently produces little or no revenue for the electricity system.

There is a subset of grid load customers that can meet part of their energy needs via purchase of Interruptible Electricity which is under direct IESO control. These are customers with processes that only make economic sense at a very low electricity cost per marginal kWh. An interruptible electricity rate rewards customers that provide interruptible load that can be remotely controlled by the IESO to follow uncontrolled and unpredictable changes in the net available non-fossil generation.

The IES Rate is for energy supply that can be frequently interrupted without notice under dispatch control by the IESO or LDC. Today most Hydro One customers have a high speed internet service with a wireless router, so realizing wireless connections between their internet routers and their electricity meters should be technically straight forward. The large interruptible electricity load available from displacement of fossil fuels in the heating, energy storage and electrolytic chemical sectors could largely displace expensive constrained generation for grid voltage and frequency stabilization.

The IES Rate must be sufficient to recover the marginal cost of providing the Interruptible Electricity Service (IES). The benefit derived from IES electricity is proportional to kWh delivered, so the load customer bill for IES electricity should be proportional to the kWh absorbed.

Since interruptible electricity is generated with non-fossil energy the load customer has certainty that he/she is not contributing to CO2 based environmental degradation.

An integrated electricity rate is a proposed new electricity rate similar to the rate that was used by Toronto Hydro and Scarborough Hydro in the early 1990s and is currently being promoted by OSPE (Ontario Society of Professional Engineers). This integrated rate combines the best features of a Firm Electricity Rate and an Interruptible Electricity Rate. Adoption of the Integrated Electricity Rate generally requires installation of power control equipment at each IES customer premises. Each such customer must provide at his/her own cost an internet connection with a LAN wireless router to allow the IESO and the LDC to communicate with the enable/disable control circuit(s) of the interruptible electrical load.

At times when the LDC enables a customer's interruptible load measurement of peak demand in kW and kVA is disabled. Hence the peak values of these parameters are only calculated and recorded using data from times when the LDC signal indicates that IES for this customer is not available. Due to disabling of the peak demand recording system at times when IES energy is being supplied the apparent load factor can potentially be greater than unity.

To implement this new electricity rate it will be necessary to gradually educate millions of customers that the primary goal is minimizing peak kVA and minimizing fossil fuel kWht, not minimizing electrical kWh. This public education process may take several years. To make the shift to the new electricity rate politically acceptable in the early years adoption of the new rate should be voluntary.

An important aspect of an electricity rate the adoption of which is voluntary is that the affected consumers will attempt to understand it. An issue of concern to LDCs is the cost of responding to telephone calls from consumers who do not understand the new electricity rate.

Over a long period of time (likely 5 to 10 years) most electricity consumers in Ontario will likely voluntarily convert to the new rate without political fan fare in order to take advantage of the potentially lower blended cost per kWhe. Consumers will likely take several years to fully appreciate that an electricity rate based on the consumer's fair share of electricity system costs is to everyones advantage. The new electricity rate would provide early adopters who are prepared to invest in energy storage and load management equipment a clear opportunity for reducing their blended electricity cost per kWhe. A consumer group that might rapidly seize upon this opportunity is owners of existing major buildings that already have the basement space, structural provisions and electrical services required by a thermal energy storage system.

In the past, when the cost of coal was a major component of the electricity cost, it made some sense to allocate electricity costs to Dependable Electricity Service (DES) load customers in proportion to kWh consumed. Today in Ontario the cost of fuel is a relatively small portion of the total electricity system cost, so DES costs should be primarily allocated to load customers in proportion to each customer's use of available generation/transmission/distribution resources as indicated by peak kVA during each billing period. Where interval kWh meters already exist the next best indicator is peak kW demand. In calculating peak kVA or peak kW for billing purposes a 2 hour averaging period should be used.

When IES electricity is available its costs should be allocated by measured absorbed kWh and while IES electricity is available the peak kVA or peak kW calculation should not be updated. This IES methodology incents displacement of fossil fuels by electricity at times when surplus non-fossil electricity is available.

A typical retail electricity rate would be about [$30.00 / (kVA-month)] + [$0.02 / kWh].

For a single family home with a monthly peak demand of 3 kVA, a load factor of 50% and a power factor of 0.95 the monthly bill would be:
{[3 kVA X $30.00 / kVA-month] + [3 kVA X.95 kW / kVA X 0.50 X 730.5 hour / month X $0.02 / kWh]} + HST
= {[$90.00 / month] + [$20.82 / month]} + HST
= $110.82 / month + HST

However, the marginal cost of off-peak DES energy and IES energy for charging an electric vehicle or for displacing a fossil fuel heating would be only:
($0.02 / kWh) + HST

If this home owner has an electic vehicle he can charge that vehicle with off-peak DES energy. The amount of off-peak DES energy that is available to this customer without impacting his/her measured peak kVA and without relying on unreliable IES energy is:
[3 kVA X.95 kW / kVA X 0.50 X 730.5 hour / month] = 1040.96 kWh / month
= 1040.96 kWh / month X 1 month / 30.44 days
= 34.20 kWh / day

That is usually enough off-peak DES energy to power an average electric automobile.

The cost of that off-peak DES energy is:
(30.44 kWh / day X $0.02 / kWh) = $0.68 / day

If in the same home the owner runs 5 kVA of electric heating powered by IES energy for half the month to partially displace fossil fuel space and domestic hot water heating the additional electricity cost would be:
{5 kW X 0.95 X ((730.5 h / month) / 2 ) X ($.02 / kWh)} + HST
= $34.70 / month + HST

The primary financial motivation for a homeowner's adoption of the new electricity rate is to access low cost IES and off-peak DES energy for electric vehicle charging and partial displacement of fossil fuel heating.

The home owner would need to install a peak demand control system connected so that the sheddable major appliance loads (vehicle charger, water heater, clothes dryer, air conditioner compressor, and dish washer) do not all run simultaneously when IES power is not available and when the uncontrolled demand due to non-sheddable in-home loads is high. For example, at dinner time in the summer when the TV, the oven and the electric stove are all in use simultaneously and IES energy is not available the load control system would automatically disable: the vehicle charger, air conditioner and electric heating elements in the water heater, clothes dryer and dishwasher. When the oven and stove are turned off the load control system would automatically progressively re-enable the other loads to maintain the chosen peak electricity demand. The priorities of the various sheddable loads could be easily reassigned by the home owner in accordance with his/her lifestyle or daily needs.

The load control system can also be programmed to cycle so that selected low priority loads do not remain totally off for prolonged periods of time.

When the IESO control signal indicates availability of surplus non-fossil energy, subject to the available electricity service capacity, all the interruptible loads could be enabled simultaneously.

This web page last updated December 2, 2021.

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