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

The term "electricity rate" refers to the blended cost per kWh of electricity at any particular moment in time. The practical way of achieving a variable electricity rate is to add a peak demand charge onto the electricity bill to effectively increase the cost of peak coincident electricity consumption. This web page identifies the major issues relating to a variable electricity rate in Ontario where the non-fossil energy sources include both nuclear and renewable electricity generation.

It is shown that for Dependable Electricity Service (DES) electricity most non-administrative costs should be allocated to load customers in proportion to each customer's peak kVA. Ideally the kVA should be calculated with a 4.3 hour 90% step response to fairly take into account the actual cost of incremental electricity generation.

A simple formula is developed for billing load customers for use of both the Dependable Electricity Service (DES) and IESO dispatched Interruptible Electricity Service (IES) energy.

From the public's perspective it is necessary for reliable renewable energy and nuclear energy to be price competitive with one another. However, to be dependable renewable energy must be complemented by energy storage in order for renewable energy to be available when needed. Energy storage cannot financially exist unless the effective cost of electricity per kWh swings daily through a wide range. The motive for a variable electricity rate is the public need to keep the average cost of reliable non-fossil electricity as low as possible.

A variable electricity rate occurs when the effective cost of electricity per kWh varies daily. The purpose of a variable electricity rate is to incent load customers to efficiently utilize all of the available non-fossil generation capacity and all of the available energy transmission/distribution capacity.

The amount of available non-fossil electric power varies with time due to unprecictable variations in wind generation and solar generation and somewhat predictable variations in load that result from changes in time and outside air temperature.

In order to incent full utilization of available non-fossil electricity the effective electricity rate must be low when there is an electricity surplus and must be high when there is an electricity deficiency. The difference between the low and high rates must be sufficient to financially enable energy storage. If this storage does not exist wind and solar generation have little commercial value because wind sourced energy is not reliably available when needed.

With a variable electricity rate the effective cost of electricity per kWh should be less for high load factor customers than for low load factor customers, should be less for high power factor customers than for low power factor customers, should be less during the night and on weekends than during working days, and should be least for loads exclusively fed by interruptible electricity.

At times when interruptible electricity is not available the load control strategy should be to maximize the (power factor) X (load factor) product, which should minimize the average cost of electricity per absorbed kWh.

At times when interruptible power is available the load control strategy should be to maximize the (power factor) X (incident power) product over the periods when interruptible power is enabled in order to maximize electrolytic hydrogen production and economic displacement of fossil fuels.

The object of a time varying electricity rate is not to create a new demand peak during the off-peak period. The object is to encourage nearly constant supply of energy to the grid by reliable generators and nearly constant efficient absorption of energy from the grid by most load customers. A secondary object is to sell at a profit surplus non-fossil energy whenever that energy is available.

The generator compensation rate should incent non-dispatched generators to adopt sufficient energy storage to flatten their net generation profiles and the retail electricity rate should incent non-dispatched loads to adopt sufficient energy storage to flatten their demand profiles.

In a real electricity system generators sell electricity to the transmission grid and electricity consumers buy electricity from the grid. In supply/demand market theory at times of surplus power the electricity price per kWh should be low and at times of power deficiency the electricity price per kWh should be high.

However, the situation is complicated by the requirement for ongoing electricity supply reliability. At times of electricity deficiency it is essential that there be sufficient power from dependable generation sources to meet the uncontrolled demand.

Nuclear generation is highly dependable. Hydraulic generation is seasonal but quite dependable. Solar and wind generation are both intermittent and seasonal. To prevent extreme electricity price swings most of the generated electricity is sold to the grid via take or pay power capacity contracts instead of at a rate per kwh. The amount of contracted generation capacity is determined by the Independent Electricity System Operator (IESO) based on historic and projected power demand patterns. The contracted renewable generation actually available varies due to variations in sunlight, wind, rainfall and equipment maintenance. Thus the costs of non-fossil generation are almost fixed instead of being proportional to the number of kWh actually delivered.

Presently generated electrical energy is sold to customers at a price proportional to the number of kWh drawn by the customer instead of at a price proportional to the generator kVA capacity used by the customer. This rate structure incents conversions from electricity to fossil fuels instead of use of electricity to displace fossil fuels when there is surplus non-fossil electricity. This failed rate struture also provides no financial incentive for good power factor.

At any instant in time the total power demand is the sum of all the individual consumer power demands plus the total transmission/distribution losses. There are uncontrolled power demand variations that are functions of time of day, day of week, season, outside air temperature, humidity and economic activity.

To ensure electricity supply reliability in the face of uncontrolled random variations in generation and load, as well as unplanned equipment failures, the total available power capacity is designed to exceed the peak uncontrolled power demand by at least 15%.

The annual grid load factor is given by:
(annual load factor) = (annual average power demand) / (annual peak power demand).

In 2014 the Ontario annual grid load factor reached 70% due to a cool summer. However, the Ontario grid annual load factor most years is about 63%. Hence the average generator utilization factor is less than:
(63% / 115%) = 0.55

Hence, in Ontario almost 50% of the available average electricity generation capacity is not used to meet Ontario's immediate energy needs. Occasionally this unused generation capacity may be required by the IESO for reliability. Hence this power cannot be sold as dependable power and can only be sold as interruptible power.

About half of this unused generation capacity is non-fossil and has a negligible marginal operating cost.

This surplus non-fossil generation is suitable for displacing fossil fuels. Since this power is interruptible the IESO can, with no notice, redirect this power to meet power shortages. This interruptible power is referred to by the Ontario Society of Professional Engineers (OSPE) as "opportunistic energy". Some of this energy is exported at low prices ($0.01 / kWh) due to price suppression in the northeastern part of the continent. The market value of the interruptible power is theoretically set by the market value of the fossil fuels that it can economically displace. However, due to out of market payments such as Ontario's Global Adjustment, to secure long term fuel delivery commitments many plants can now bid into the market at prices lower than their actual fuel prices. This market value will increase when there is a price on fossil CO2 emissions. However, for a typical mix of gas fired plant technologies, the value of carbon pricing on electricity pricing is about 1 cent / kWh for each $30 per ton of tax on CO2 emissions. Consequently, CO2 reduction goals cannot be met by fossil carbon emission pricing alone because of political opposition to imposing very large fossil carbon emission prices on the economy.

The grid electricity supply has combined daily, seasonal and random variations. The total grid load has combined daily, seasonal and random variations. The difference between the non-fossil generation capacity and the uncontrolled grid load is potential Interruptible Electricity Service (IES) energy that can be sold to customers who have loads that are enabled and disabled by the Independent Electricity System Operator (IESO).

IES energy can be sold at a discount for applications such as displacing hydrocarbon fuels in heating applications and for electrolysis of water for production of hydrogen. The electrolytic hydrogen can be used to displace natural gas which is currently used to make industrial hydrogen. The zero emission hydrogen production can be used to produce high temperatures and to produce energy dense synthetic hydrocarbons using sustainable biomass as the carbon source.

Variable electricity rates are essential to maximizing electricity system load factor. Examples of customers who will consistently attempt to purchase electricity at a low price are owners of: electric and plug-in hybrid vehicles, stationary electro-chemical energy storage systems, thermal energy storage systems, hybrid oil/propane/gas-electricity heating systems and electro-chemical production systems. These same customers will attempt to minimize electricity consumption when there is a high electricity price.

Examples of generators who will consistently attempt to sell part or all of their electricity output at a high price are owners of hydro-electric generators with substantial storage reservoirs and owners of hydrocarbon fuelled electricity generation.

Examples of parties who will attempt to purchase energy at a low price and sell or use it later at a high price are owners of behind the meter energy storage systems. Because these transactions take place behind a customer meter they are only visible to the utility or the IESO as a change in customer load profile.

In order to encourage development of these customer groups, and hence electricity market liquidity, it is necessary to adopt a variable electricity rate with an effective price swing that is sufficient to allow all of these customer groups to exist and financially prosper. Thus far the IESO and the Ontario Energy Board (OEB) have paid insufficient attention to this critical issue. In order for energy storage to be economically viable the average blended cost of marginal off-peak energy must be only a small fraction of the blended cost of marginal on-peak energy.

Behind the meter energy storage should be subject to the retail price plan for that customer and the price plans should incentivize the customer to produce a grid friendly load profile.

Because centralized energy storage will affect the supply/demand balance it will also affect market prices. Consequently it is very important that centralized storage transactions are NOT cleared through the wholesale market auction.

Centralized storage should be an ancillary service to the grid as a whole and should be controlled by an independent entity such as the IESO whose mandate is to optimize the benefits for the grid and customers as a whole rather than gaming the transactions for self-interest. Using the IESO as the controlling authority for centralized storage has advantages because the IESO has forecasts on the future availability of various resources of energy that are critical to the effective deployment of centralized storage to avoid extreme price volatility.

Non-fossil electricity price variability is driven by four mechanisms: Peak Power, Load Factor (LF), Power Factor (PF) and IESO direct control.

Peak Power is entirely under customer control.

Load Factor calculations use interval kWh / h calculations to identify the peak load during a billing time period. This identification can be done by software internal or external to the meter.

Power factor calculations modify the load factor calculations to take into account power that is reflected from the load back into the grid where it is usually dissipated as heat.

IESO direct control operates by the LDC sending a signal via the Internet which enables the interruptible load.

Historically in large commercial accounts monthly peak power, load factor and power factor were used because they required only a small amount of data that could be collected via monthly manual readings of mechanical meters. However, the advent of smart meters that can collect and store 15 minute or 1 hour interval data has made it possible to implement metering algorithms that are more effective at achieving the desired customer response.

TOU electricity rates are superficially attractive to politicians because the TOU concept is easy to explain to the general public. However, politically acceptable TOU rates can have unintended consequences that are detrimental to overall electricity system performance. Political goals are legitimate in a democracy, but we must maintain an optimum balance among social, technical and environmental goals to ensure Ontario's economic prosperity is not sacrificed within a larger global marketplace.

During any specified time period the customer load factor LF is defined by the equation:
LF = (average power) / (peak power)
(average power) = (energy absorbed from the grid during the time period) / (duration of time period)

The fundamental requirement is to shift the electricity rate burden from high load factor customers to low load factor customers, thus financially enabling energy storage and peak load control. Similarly capacity factor weighted generator compensation can be used to incent energy storage behind wind and solar generator meters.

In order to minimize the impact of grid power demand peaks on generation, transmission and distribution costs it is desirable to financially encourage all non-dispatched load customers to maintain a high load factor at times of limited renewable generation availability.

A high load factor is encouraged by use of an electricity rate that financially rewards a consumer for maintaining a high load factor. Similarly generators that supply electicity to the grid but are not dispatched by the IESO should have a compensation rate that rewards maintenance of a high generator capacity factor.

Ideally a new electricity rate regime should rely on the statistical independence of random maintenance shutdowns of behind the meter electricity generation, energy storage and load control equipment, rather than requiring continuous 100% operational availability of all equipment at each site. A brief maintenance shutdown should have minimal effect on a customer's electricity bill. This issue complicates the analysis of data gathered by interval meters. To minimize this problem the proposed new electricity rate averages the peak over 2 hours to arrive at the monthly peak demand.

The electricity rate should also incent a high power factor PF, where PF is:
PF = [(Eib - Erb) - (Eia - Era)] / (Eib - Eia)
= [(Eib - Erb) - (Eia - Era)] / [(Eib - Erb) - (Eia - Era) + (Erb - Era)]
= [(Eib - Eia) - (Erb - Era)] / [Eib - Eia]
= [Pi - Pr] / [Pi]

Eia = Cumulative incident energy at time T = Ta;
Eib = cumulative incident energy at time T = Tb;
Era = cumulative reflected (reactive) energy at time T = Ta;
Erb = cumulative reflected (reactive) energy at time T = Tb;
Pi = incident power
Pr = reflected power
because a high power factor minimizes transmission loses within the electricity grid. Hence at the end of each time interval the electricity meter should record both the net absorbed energy (Ei - Er) and the reflected energy Er.

To minimize political and public resistance to a more effective price plan, a voluntary electricity price plan has been proposed by the Ontario Society of Professional Engineers (OSPE). The OSPE plan incentivizes consumers who are prepared to invest in energy storage and load control equipment to improve grid performance by receiving a lower marginal electricity rate.

Implementation of the contemplated voluntary electricity rate will lead to more electricity usage in the off-peak period and hence will increase the required base load generation capacity. However, the required peak generation capacity will be reduced.

Due to the change in rate structure there may also be a temporary increase the number of customer enquiry telephone calls to the local distribution company (LDC).

Under the proposed new voluntary rate plan the average electricity costs will increase for parties whose energy use is concentrated in the weekday on-peak period and who are unwilling to invest in technologies such as energy storage equipment to take advantage of the lower cost off-peak electricity. The electricity cost will also increase for parties that have a below average power factor and who are unwilling to implement power factor correction.

Electrical energy storage is typically only 30% to 90% efficient. Consequently use of electrical energy storage to decrease peak demand actually increases total electrical energy requirements.

This author's personal experience was that Ontario lost the benefits of variable electricity rates by years of failing to adopt and maintain electricity rates that reasonably reflect actual costs. During the 1960s and 1970s many buildings in Toronto were built with thermal energy storage systems. During the 1980s and 1990s these thermal energy storage systems were taken out of service because the electricity rates were changed such that continued operation of these thermal energy storage systems no longer made economic sense for the building owners. Building owners require a certainty regarding long term electricity rates before they will make the capital expenditures on energy storage systems that variable electricity rates are intended to promote. From the point of view of major building owners, the Ontario government has zero credibility with respect to claims regarding future electricity rates. In order to restore that credibility it will be necessary for the Ontario Energy Board (OEB) to fundamentally fix the retail electricity rate structure and for the IESO and local distribution companies (LDCs) to offer building owners and developers an electricity rate structure with future certainty.

A useful strategy for balancing the generation and load for grid voltage and frequency regulation is to offer interruptible electricity under IESO dispatch control at a discount from normal electricity rates. The purchasers of such electricity should be parties that have electrical loads that can tolerate frequent and ongoing power interruptions with no notice.

The obvious load for interruptible power is the electrical portion of a hybrid electricity-oil/propane heating system. At times when electricity is inexpensive electricity can be the heat source. At times when electricity is expensive oil/propane can be the heat source. Many buildings in rural Ontario, have an electricity service but no natural gas service, and typically heat with oil or propane, would fall into this category.

There are certain electrochemical processes that lend themselves to load dispatch with an interruptible electricity rate. These processes include production of ammonia compounds, electrolytic metal refining and production of methanol from electrolytic hydrogen.

These processes only make financial sense if the required electricity can be obtained relatively inexpensively. These processes are not time sensitive and can usefully absorb large amounts of surplus off-peak electricity.

These processes will only exist on a large scale in Ontario if the Ministry of Energy (MoE), OEB and IESO collectively act to offer suitable long term price discounted interruptible electricity supply, together with a reasonably priced Dependable Electricity Service (DES).

Discounted interrruptible electricity purchasers might include:
a. Parties in the electrolysis and electrolytic refining business;
b. Owners of parking lots for electric and plug-in hybrid vehicles;
c. Owners of energy storage systems;
d. Owners of electricity-oil, electricity-propane and electricity-natural gas hybrid heating systems.
e. Parties producing electrolytic hydrogen as a vehile fuel;
f. Parties producing synthetic methanol.

An issue with the IESO having direct dispatch control of customer loads is that such control changes the customer's gross load factor. Hence, the electricity rate structure and the customer billing software must be modified to differentiate DES consumption from IES consumption.

A potential problem with IESO dispatch control via the Internet is the possibility that sooner or later the communication will fail or be compromised. If there is a communication failure the load customers control system should default to maintenance of a flat demand profile with interruptible load off.

Centralized energy storage has the potential to eliminate the need for customers to shift their individual demand to when the energy is available. However, the current cost of centralized storage and associated transmission and the low round trip efficiency ratings make this approach currently uneconomic in Ontario.

In order to achieve high generator capacity factor and high customer load factor it is necessary to implement some short term energy storage at both intermittent generation sites and at consumer sites. For this energy storage to be economically viable for its owners there must be suitable variable electricity rates that are guaranteed by credible long term contracts or electricity plans.

If locally installed distributed energy storage systems have to pay transmission/distribution rates these energy storage systems are likely not economic. To avoid transmission/distribution charges energy storage systems shouldd be located either behind a generator meter or behind a load customer meter.

There is an upper limit to the benefit of variable electricity rates. A small predictable daily variation in the total electricity system load is desirable to allow some generators to be periodically shut down for preventive maintenance. Fortunately there is a natural weekday/weekend and seasonal variation in electricity demand that can be used to facilitate scheduled maintenance outages for generators. Consequently a flat load profile over the entire year is not necessary. This natural load variation considerably reduces the amount of behind the meter energy storage required for generators to achieve high capacity factors. A flat daily load profile has many advantages for improving overall grid performance both economically and environmentally.

A political problem with changing from a fixed electricity rate per kWh to a variable electricity rate per kWh is that at the time of initial implementation of the rate change some parties financially benefit and others do not. This issue makes implementation of variable electricity rates politically sensitive. If a new rate is voluntary parties that will financially benefit will quickly adopt it, which will have the effect of gradually forcing up the electricity rates for non-adopting parties. Generally compulsory adoption of a new rate regime needs to be phased in over several years to reduce its short term impact on the most affected customers.

In order to encourage good power factor this author recommends full implementation of directional interval kWh metering. Measurements of both incident energy Ei and absorbed energy (Ei - Er) during a measurement time interval provide a good indication of the generation and transmission/distribution resources used during that measurement time interval.

The reasons for using directional kWh metering for cost allocation are as follows:
1. Incenting high power factor;
2. Incenting low harmonic content;

Depending on the month there are between 2687 and 2977 0.2500 hour meter time intervals per month.

A normal smart electricity meter records the cumulative number of absorbed kWh registered at 0.25 hour intervals for industrial and large commercial customers (> 50 kW) and hourly for residential and small commercial customers and later reports this data to the utility, typically once or twice a day. During the reporting process the meter's internal time clock is synchronized to the utility's master time clock so that there is a precise time reference for the start and end of each time interval.

The difference between any two successive cumulative absorbed kWh readings divided by the interval period is an accurate measure of average absorbed power during that time interval.

A directional smart electricity meter also records the cumulative number of incident kVAh registered at 0.2500 hour intervals.

The difference between any two successive cumulative incident kVAh readings divided by the interval period is an accurate measure of average incident power during that time interval.

The reflected power is almost entirely dissipated as heat within the transmission/distribution network. Hence the grid resource usage during a metering interval is the incident power which equals the sum of the absorbed and reflected powers.

An interval meter for use with interruptible power should also flag the intervals during which interruptible power is enabled.

The local meter display is realized by performing certain numerical computations within the meter.

For customers purchasing interruptible power there should be an interruptible power control status input signal from an internet connected control box which enables the local load that is fed with interruptible power. This control box may also perform load shedding control functions.

Pi = incident power propagating from transmission line toward the load;
Pr = reflected (reactive) power propagating from load toward transmission line;
(Pi - Pr) = power absorbed in load;
PF = [(Pi - Pr) / Pi] = power factor;
Ta = time at start of a particular measurement interval;
Tb = time at end of a particular measurement interval;
Energy absorbed by load during a particular measurement interval
= [(Eib - Erb) - (Eia - Era)]
= [(Eib - Eia) - (Erb - Era)]

= Integral from T = Ta to T = Tb of:
(Pi - Pr) dT
Energy reflected from load and absorbed by transmission system during this particular measurement interval is:
(Erb - Era)
= Integral from T = Ta to T = Tb of:
Pr dT
Apparent energy (Eib - Eia) that must be supplied by generation during the measurement interval (Tb - Ta) is:
(Eib - Eia)
= Integral from T = Ta to T = Tb of:
[(Pi - Pr) + Pr] dT
= Integral from T = Ta to T = Tb of:
Pi dT
= Integral from T = Ta to T = Tb of:
[(Pi - Pr) / PF] dT
Pi = [(Pi - Pr) / PF]

Eia = cumulative (absorbed energy + reflected energy) registered at time T = Ta;
Eib = cumulative (absorbed energy + reflected energy) registered at time T = Tb;
(Eib - Eia) = total energy that must be supplied by generation during the interval (Tb - Ta);
= Integral from T = Ta to T= Tb of:
Pi dT
= Integral from T = Ta to T = Tb of:
[(Pi - Pr) / PF] dT
= [(Eib - Eia) - (Erb - Era)] / PF
= [(Eib - Erb) - (Eia - Era)] / PF

Thus the value of Pi during the interval (Tb - Ta) is given by:
[(Eib - Erb) - (Eia - Era)] / [PF (Tb - Ta)]

Tc = time at start of billing period
Td = time at end of billing period
(Td - Tc) >> (Tb - Ta)

The average power Pa dissipated in the load during the billing period (Td - Tc) is given by:
Pa = [(Ei - Er)d - (Ei - Er)c] / (Td - Tc)

Define Pp as the representative largest value of:
[(Eib - Erb) - (Eia - Era)] / (Tb - Ta)
during the billing period.

The load factor LF is:
LF = Pa / Pp

Pp = Pa / LF
= [(Ei - Er)d - (Ei - Er)c] / [LF (Td - Tc)]

However, recall that the generator power required to dissipate power Pp in the load is:
Pi = Pp / PF

Thus the generator capacity required to serve this load during the billing period is:
Pi = Pp / PF
= Pa / (LF PF)
= Pa / [(Pa / Pp) PF]
= Pp / PF

= representative maximum value of:
[(Eib - Erb) - (Eia - Era)] / [PF (Tb - Ta)]
= representative maximum value of:
[(Eib - Erb) - (Eia - Era)][Eib - Eia] / [[(Eib - Erb) - (Eia - Era)] (Tb - Ta)]
= representative maximum value of:
[Eib - Eia] / [(Tb - Ta)]

The quantity:
[Eib - Eia] = [(Eib - Erb) - (Eia - Era) + (Erb - Era)]
is easily measured with a directional interval electricity meter that can cumulate kVAh. Thus the best indication of generation capacity that must be allocated to this consumer during billing period (Td - Tc) is:
{[(Eib - Eia)peak / (Tb - Ta)] [Td - Tc]}
= [Pp / PF] [Td - Tc]

The units of this parameter are kVAh.

Thus the maximum generator power capacity Pip required during the billing period is:
Pip = (Pp / PF)
= [Pa / (LF PF)]


In the recent past commercial electricity rates have consisted of four components: an energy charge per kWh that reflects the cost of electricity generation, a global adjustment that is added to the energy cost per kWh, a demand charge that reflects the cost of transmission/distribution and a fixed charge that reflects the cost of metering and administration.

During the period 2007 to 2013 the Province of Ontario gradually phased out coal fired generation. The result was that in 2014 about 90% of Ontario's electricity came from non-fossil sources. One of the consequences of reducing use of fossil fuels was that subject to maximum power constraints the cost of owning and operating an electricity generator feeding the grid became almost independent of whether or not the generator was actually producing power.

The Ontario Society of Professional Engineers (OSPE) has propsed that the end user electricity rate should better reflect the costs of electricity supply. OSPE has proposed that base load energy cost much less than peaking load energy. Thus the blended electricity rate for high load factor customers should be much less than the blended electricity rate for low load factor customers. The practical means to achieve this objective is to obtain most of the electricity system revenue from a monthly peak kW or peak kVA charge instead of from a charge per kWh. A high peak demand charge encourages customers to install energy storage and load management equipment. A low energy charge encourages displacement of fossil fuels by off-peak electricity.

Implementation of the OSPE rate proposal should be optional in early years to smooth its implementation.

Each meter interval either contains interruptible power or it does not. The peak incident power (Pp / PF) is found using only interval data that is not affected by the interruptible power control signal. The number of intervals over which (Pp / PF) is averaged is chosen to realize the desired price swing from an extremely small low load factor to the maximum possible load factor.

When interruptible energy use is enabled the grid has surplus power, so power use is not a concern. In these circumstances the parameter that must be measured is energy. The simplest way to avoid the question of whether DES or IES energy was consumed is to avoid the issue by billing both services at the same rate for energy.

The customer's total monthly bill before tax would be of the form:
B = Bd + Be + Bf
Bd = demand portion
Be = energy portion
Bf = administrative portion

Rd = peak demand rate in $ / kW;
Pp = peak power during non IES periods in kW;
Pf = power factor;
Tc = time at start of billing period;
Td = time at end of billing period;
Rf = administration rate in $ / h;
Re = energy rate in $ / kWh.

For existing commercial accounts > 50 kW the demand charge Bd is of the form:
Bd = Rd (Pp / PF) (Td - Tc)
and the administrative charge is of the form:
Bf = Rf (Td - Tc)
where Rd and Rf are constants.

The peak power Pp value is measured when opportunistic energy is not in use. The value of the energy supplied during a billing period is given by:
Be = [[(Eib - Erb) - (Eia - Era)] / PF] [Re]
= [Eib - Eia] [Re]

Note that Re must be very small (~ $0.02 / kWh) to enable sale of interruptible energy for fossil fuel displacement.

Note that implementation of IES must not increase a LDC's costs. Thus the IESO computer that transmits signals to enable IES consumption must also disable the peak demand meter that senses power fed to the LDC.

Hence the customer's total monthly bill would take the form:
B = Bd + Bf + Be
= [(Rd) (Pp / PF) + Rf](Td - Tc) + [Eib - Eia] [Re]
Rd ~ $30.00 / peak kW - month

This billing methodology gives customers maximum incentive to flatten their usage profiles during normal power periods and to maximize power factor at all times.

Note that for both normal power and interruptible power the cost of a marginal off-peak kWh is low ($0.02 / kWh) which provides maximum incentive for customers to use off-peak and interruptible energy either to reduce Pp via behind the meter energy storage or to displace fossil fuels.

There will be parties that argue that this billing formula does not encourage energy conservation. The appropriate response is that the intent is to encourage use of low cost off-peak electricity for displacement of fossil fuels, not to minimize consumption of off-peak electrical energy.

There will be parties that argue that the billing formula should include an adjustment for peak demand diversity. The appropriate response is that the intent is to make every customer's load nearly flat so that within a LDC there is almost no peak demand diversity. The proposed metering and billing software takes 4.3 hours to respond to 90% of a step change in load. Hence this software filters out short term load dips and spikes and almost eliminates load diversity.

The methodology described herein is a simple means of making good use of off-peak and opportunistic energy. It avoids any requirement for a second meter, complex related data analysis and site inspections.

The load controller will need to have a LAN or WI-FI connection from the customers existing local internet router. Most rural customers with oil or propane heating systems already have either microwave or satellite internet connected to a local router.

At times when interruptible power is not available it is important for each customer to make maximum effective use of the power available to the customer without increasing the customer's measured monthly peak power Pp. There is a strong financial incentive for peak demand control at every participating customer premises whenever interruptible power is not available. The peak demand control system should emit an audible and visual warning if the instantaneous demand exceeds a customer set maximum at a time when interruptible power is not available.

From an implementation perspective the above described methodology is a simple way of encouraging utilization of off-peak energy and opportunistic energy for both reducing grid peak demand and for displacement of fossil fuels. The implementation costs are minimal.

This web page last updated March 17, 2019.

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