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

The term "Electricity System" encompasses all the components of the means by which we obtain electicity. Without limiting the generality of the definition the electricity system includes energy sources, electricity generation, energy storage, transmission, distribution, metering, construction, operation, maintenance, administration and regulation.

During the 20th century electricity became integral to our daily lives. The electricity system in Ontario is so reliable that we tend to take it for granted. Today we depend on reliable grid supplied electricity for numerous critical functions, including but not limited to: pumping water, lighting, space heating, space cooling, ventilation, water heating, transportation, refrigeration, communication and power for industrial processes.

The Ontario electricity system is composed of major generators, major loads and import/export interties interconnected by a high voltage transmission system. Some of the major loads are Local Distribuion Companies (LDCs) that distribute and sell electricity to local retail customers.

There is some distributed generation within the local distribution systems.

Much of the major generation is owned, operated and maintained by Ontario Power Generation (OPG) and by Bruce Power.

Major generators are primarily paid via capacity contracts with the Independent Electricity System Operator (IESO). Major generators may earn additional revenue by sale of electricity into the IESO spot market. The prices in the IESO spot market usually reflect the low marginal cost of uncommitted generation capacity and hence are not reflective of overall generation costs. Major generators are subject to output power constraint by the IESO so that total power fed into the transmission system matches total power drawn from the transmission system. In effect the IESO regulates the voltage on the transmission system.

Energy transfers through the transmission system are dispatched on a moment by moment basis by the the IESO. The IESO seeks to economically match major generation to major load.

The transmission network is owned and maintained by Hydro One Networks Inc. (HONI). HONI also acts as a Local Distribution Company (LDC) in many rural areas.

Very large electricity users such as major industrial plants are transmission connected and billed at wholesale rates as if they were LDCs.

Distributed generators are smaller generators that are located within and supply electricity directly to an LDC.

Behind the meter generation is located behind retail load customer meters.

Most distributed generators are paid via contracts with the IESO. Most distributed generators currently operate without generation constraint. However, in the future distributed generators may need to be constrained.

Small electricity users are supplied with electricity by an LDC.

The Ontario electricity system is designed to operate with unidirectional power flow. That is, it is intended that power flow from the transmission system to the LDC distribution systems and from each distribution system branch to a retail load customers. This system design minimizes the cost and complexity of switchgear and voltage control. A key safety aspect of this system design is that power line workers have certainty that if all known generators connected to a transmission line or distribution line are switched off then the transmission line or distribution line is not energized. There is also certainty that power islanding will not occur and hence there need not be complex and expensive provisions for recovery from power islanding.

If an electricity system permits reverse power flow then the number of isolation switches that are required for power line worker safety is much higher. Also the ratings of short circuit fault isolation switchgear must be higher because this switchgear must be able to isolate a fault fed by multiple power sources, some of which may have a very low effective source impedance because they are physically close to the fault.

The wholesale and retail electricity rates are subject to approval by the Ontario Energy Board (OEB).

Matters related to electrical inspection and safety are the responsibility of the Electrical Safety Authority (ESA).

Standards governing the fabrication of electrical equipment are published by the Canadian Standards Association (CSA).

The service life of generation and transmission equipment is the time interval between major prolonged shutdowns. For example, over time a hydraulic dam accumulates silt and may need to be drained for a season to allow dredging. Over time turbine components erode and may need major service or replacement. Over time the fuel channels of CANDU nuclear reactors degrade due to fretting and neutron bombardment and need replacement. Over time lattice transmission towers and transmission lines corrode and need replacement. These and other long term deterioration mechanisms result in prolonged equipment shutdowns for major service or replacement. The electricity system must have sufficient redundant capacity in generation, transmission and distribution that the system can accomodate prolonged equipment shutdowns without significant interruption of electricity supply to retail electricity consumers.

Generally the service life of major utility equipment is in the range of 20 to 90 years. The more complex the equipment the shorter its service life. Sometimes the service life is constrained by availability of critical replacement parts. For this reason, during prolonged equipment shutdowns electronic control and monitoring systems are often completely replaced. In the case of electronics the spare parts problem is compounded by ongoing evolution of hardware, firmware and software.

Problems with the environment, equipment depreciation, rural transmission and urban transmission have led to the electricity industry being subject to intense public scrutiny. Fear of public reaction to electricity system development has made elected politicians unwilling to make timely decisions related to important new generation and transmission projects. As a result the electricity system has deteriorated to such an extent that Ontario relies on fossil fueled electricity generation for meeting the Ontario peak electricity demand.

Most of the existing electricity utility staff are devoted to operating and maintenance. There is an infrastructure replacement backlog. There are insufficient human resources and there is no viable financial mechanism for undertaking major new integrated generation and transmission projects. There are multiple layers of required approvals that collectively discourage private sector investment.

The reliability of the electricity system in Ontario is now threatened by consequences of the electricity industry and the related governmental regulatory bodies failing to pay sufficient attention to environmental, depreciation and reserve issues. As long as electricity was obtained from hydro-electric dams at remote locations, and the environmental effects were largely confined to fish habitat and fish migration, there was relatively small public opposition to electricity system development. Hydro-electric dams usually have sufficiently long service lives that equipment depreciation is not a major issue. However, by about 1970 most of the economic major hydro-electric potential in southern Ontario had been developed and other sources of electricity were constructed.

These other sources of electricity were primarily thermal-electric generating stations, where the source of heat was either combustion of a fossil fuel or nuclear fission. The fossil fuel generating stations emit toxic products of combustion, particulate matter and green house gases. The CANDU nuclear generating stations, if not carefully operated and maintained, have the potential of releasing dangerous radioactive isotopes. Both coal and CANDU nuclear generating stations have significant long term solid waste disposal issues.

All thermal-electric generating stations emit large amounts of waste heat. Efficient operation of a thermal-electric generating station dictates that it be located in a rural area adjacent to a major river or a large body of cold water for cooling. In circumstances where the water supply is limited evaporative cooling can be used to reduce the cooling water requirements. However, evaporative cooling results in a lower heat to electricity conversion efficiency than direct cold lake water cooling.

Thermal-electric generating stations tend to depreciate faster than major hydraulic generation facilities. Ontario Hydro, Ontario Power Generation, the Ontario Energy Board (OEB) and the Ministry of Energy (MOE) of Ontario have repeatedly failed to make adequate allowance in the Ontario electricity rate structure for costs of thermal-electric generation station depreciation and reserve generation. These parties also made insufficient allowance for costs related to permanent solid waste disposal, toxic emissions, particulate matter emissions and global warming. The province of Ontario is now facing expanding its electricity generation capacity, but has no funds set aside for this purpose. In addition there is still a stranded electricity bond debt principal which is presently held by the Ontario Electricity Financial Corporation and which is guaranteed by the taxpayers of Ontario.

Successive delays by politicians have caused the Ontario electricity system to become dependent on fossil fuels for peak load following generation. The problem has been compounded by implementation of the Hourly Ontario Electricity Price (HOEP) which is strongly influenced by the low prices of fossil fuels without a fossil carbon tax. The HOEP causes more expensive emission free generation technologies to be rejected in favour of low cost fossil fuels. Both federal and provincial politicians have been unwilling to directly face the issue of implementing a fossil carbon tax in order to correct the HOEP problem. The HOEP is further distorted by the failure of successive Ontario governments to require existing central generation to pay down the accumulated electricity debt and by improper application of the Global Adjustment to the price per kWh instead of to the price per monthly peak kVA.

During the forty year period 1965 to 2005 the annual average temperature at the Toronto International Airport, as measured by Environment Canada, increased 2.44 degrees C. This temperature increase is due to a combination of an increase in local heat dissipation, a decrease in planetary albedo and an increase in the atmospheric greenhouse gas concentration.

If mankind's present pattern of use of fossil fuels for primary energy generation continues, during the 21st century Earth will enter an irreversible condition known as thermal runaway. The resulting increase in average Earth surface temperature will cause a global extinction of large land animals, including humans.

In order to avoid thermal runaway mankind must cease use of fossil fuels for primary heat and energy generation. Hence:
1. All electricity must be generated using non-fossil fuel energy sources;
2. Electricity generation and transmission must be expanded to displace fossil fuels in the transportation and heating sectors;
3. Electricity generation and load profiles must be matched using a combination of generation constraint, energy storage and load management;
4. Electricity rates must reflect the full costs of generation via non-fossil fuel means and related transmission/distribution.

In order to financially enable construction of replacement non-fossil fuel generation it is necessary for the the government of Ontario to impose a tax on fossil CO2 emissions. This tax must reflect the reality that the practical alternative to distributed generation is new nuclear generation. The last major new nuclear project in Ontario, commenced about 1978 and including construction financing cost about $4700 / (base load kW). Any new nuclear project will require training an entire new army of design, construction, operating and maintenance personnel, and purchase of materials at current prices, so it is unrealistic to contemplate a full cost of less than $12000 /(base load kW). Hence any alternative non-fossil fuel electricity generation fitted with sufficient energy storage and transmission to provide a nearly constant electricity output co-incident with the electricity system summer load peak is realistically worth about $12,000 / (base load kW) to the electricity ratepayer, and a fossil carbon tax should reflect this reality.

Electricity system power balance requires that the total instantaneous generation continuously matches the total instantaneous load, including transmission losses. Part of the potentially available generation and/or load must be IESO controlled or constrained in order to have a reserve that is immediately available to balance uncontrolled generation and load fluctuations. The electricity rates should fairly compensate constrained generation owners for the financial costs of maintaining this generation reserve. Power balance could also be achieved via direct IESO load control. Such load control requires an interruptible electricity rate, which is not presently offered in Ontario.

A major philosophical issue to be faced by electricity utilities in coming years is the present implicit assumption that grid customers (both generators and loads) need not be responsible for either their power factor or the shape of their generation/load profile over time. For many categories of grid customers the present electricity rate does not encourage efficient use of the generation and transmission/distribution systems. The present electricity rate structure in Ontario is a carry-over from a time when the generation and transmission functions were integrated in Ontario Hydro and fossil fueled generation was used for load following. In that integrated system sophisticated technical issues such as provision of variable reactive power generation for optimizing transmission efficiency were internally addressed. However, now that the generation, transmission and system operation functions are the responsibilities of separate entities, the electricity rate should contain strong financial incentives for high generation capacity factor, high load factor, high power factor and voltage stabilization. Otherwise the costs to ratepayers of generation and transmission/distribution will increase due to inefficient use of existing facilities.

Consider a rural wind farm that feeds an urban load via a long transmission line. A typical wind farm operates at a 30% capacity factor. A typical nuclear generator operates at a 90% capacity factor. Hence the cost of transmission for wind generated energy expressed in $ / km-kwh is about three times the corresponding cost of transmission for nuclear generated energy. However, suitable sites for wind farms tend to be about four times more distant from urban load centers than are suitable sites for nuclear generators. Hence the cost per kWh for transmission of wind generated energy to urban load centers is about:
(3 X 4) = 12
times the cost per kWh for transmission of nuclear energy to urban load centers. To put this matter in financial perspective, if the average cost of transmitting nuclear generated energy is $.015 / kWh, the corresponding cost of transmitting wind generated energy is about $.18 / kWh. The cost of transmitting wind energy can be reduced by use of behind the meter energy storage at the generator to increase the net generator capacity factor. However, the cost of that storage greatly increases the cost of wind generation. The fundamental problem is that in addition to daily variation wind generation in Ontario is subject to substantial seasonal variation. Ontario does not have sufficient seasonal hydraulic energy storage to balance wind generation.

The implicit assumption that "it is the responsibility of electricity utilities to provide generation and transmission/distribution to follow the uncontrolled load" in the past led to a large investment in central generation that can follow real and reactive load over a wide power range. However, much of the load following central generation relied on fossil fuels. In a low carbon world the assumption should be changed to: "It is the responsibility of the transmission/distribution utilities to provide for transmission of energy from generators to loads at a nearly uniform rate" and "each grid customer must accept responsibility for his/her generator capacity factor, load factor and power factor, as well as for the amount of energy exchanged". The driving issue is that conversion of transportation and heating from fossil fuels to electricity will require increasing the size of the present electricity generation and transmission/distribution system 7 fold unless the average generator capacity factor and the average load factor are both substantially increased. In order to limit the increase in generation, transmission and distribution costs, the present assumption that a load customer is entitled to draw any amount of electricity from the grid at any power factor at any time with little or no cost penalty will have to be discarded. A new electricity rate philosophy is required under which customers who draw energy from the grid at a constant power and at a high power factor pay much less per kWh than customers who draw energy from the grid at a low load factor and/or at a low power factor or who otherwise use a disproportionate amount of the shared electricity system resources.

With the increasing use of intermittent wind generation there is also a requirement for a new class of Interruptible Electricity Service (IES) customers that can be dispatched off frequently with no notice. Such IES customers would reduce the amounts of expensive constrained generation and energy storage that are required for the total generation to reliably track the total load.

In order to financially enable non-fossil fuel Distributed Generation financed by the private sector it is necessary to implement a fossil carbon emissions tax. This tax must value a kW of constant output from any non-fossil fuel generator together with supporting transmission and energy storage at the full cost of a delivered base load kW from new nuclear generation using the same private sector financing costs.

In order to implement Distributed Generation on a large scale with minimum increase in transmission/distribution it is necessary to implement energy storage near generation sites and at load sites. For this energy storage to be economically viable for its owners there must be suitable net generation capacity factor and net load factor dependent electricity rates guaranteed by credible long term contracts.

In order to permit reasonable maintenance of distributed electricity generation and distributed energy storage equipment the electricity rate must not overly penalize a facility owner for random equipment shutdowns that are required for normal repair and maintenance.

In order to put all parties on a level playing field all non-dispatched generators must be subject to the same metering and the same rate regime. In the absence of sufficient IES load, generators should earn a premium for being constrained in order to provide voltage regulation and electricity system reliability.

The cost of maintaining a high load factor or a high generation capacity factor should be reflected by introduction of load factor into the load customer electricity rate and and capacity factor into the generator compensation electricity rate. These factors financially reward high load factor and high generation capacity factor, which in turn minimize the required amounts of generation and transmission.

When the electricity rate structure fully reflects actual costs, load customers will find that it is less expensive for them to do their own power factor control, energy storage and load management than it is to pay the electricity utility for those services.

Electricity transmission equipment in rural areas is primarily used to guide electromagnetic energy from energy sources in rural areas to loads in urban areas. The unconstrained outputs of renewable energy sources are variable both with respect to time of the day (in the case of wind turbines and solar) and are variable with respect to the season of the year (in the case of wind turbines, run-of-river hydraulic generation and solar). The average annual output of a wind farm is typically only 30% of its peak output. Since the transmission line connected to a wind farm without adjacent energy storage must be sized to handle the wind farm's peak output, on average only 30% of that transmission line's capacity is effectively used. This problem is compounded by the fact that a wind farm requires balancing generation that is usually located elsewhere. The transmission line connected to that balancing generation is also inefficiently used. In simple terms, renewable energy generators without nearby energy storage generally require many times more transmission per kWh of electricity delivered to the load than do nuclear generators. The net result is that, without energy storage, as the fraction of total energy supply from renewable generation increases, the required amount of rural transmission increases many times faster.

The required amount of rural transmission can be mitigated through the use of daily energy storage located close to the generators and the loads. Seasonal energy storage, involving large hydroelectric projects and major transmission system enhancements, is also required for seasonal balancing of renewable generation. The combined cost of daily and seasonal energy storage may be many times the cost of the generation. Constructing rural transmission requires purchase or expropriation of lengthy corridors of land. The IESO, the electricity system planning agency for the government of Ontario, has yet to address the full costs of energy storage and rural transmission required to support large amounts of wind generation. The nearest suitable hydraulic energy storage is in Quebec and the required transmission intertie distance is about 1000 km. There are also generation constraints at the Quebec hydroelectric dams.

In urban areas most of the green house gas emissions come from combustion of fossil fuels in vehicles, heating plants and electricity generation. The technologies that can displace fossil fuel energy with non-fossil fuel energy in urban applications generally require that additional electricity be generated in rural areas and delivered via transmission/distribution to urban loads. The existing urban municipal plans often do not provide sufficient energy transmission corridors to allow electricity to displace fossil fuels. Hence, in order to reduce urban greenhouse gas emissions, substantial amounts of urban property must be purchased or expropriated to form the required additional energy transmission corridors.

Presently distributed wind and solar generation does not contribute to power and voltage stability. Distributed system power and voltage stability requires the use of a negative slope proportional output power versus voltage controller at every distributed generator and at every energy storage unit. These controllers should attempt to keep the line voltage within +/- 6% of its nominal value. During normal operation the distributed generator power output fed to a distribution feeder is controlled by the line voltage. The line voltage is controlled via the tap setting on the substation distribution transformer secondary to which the distribution feeder is connected. This tap setting is controlled by a proportional-integral line voltage controller. Note that the distributed generator power controllers must not have voltage error integrating control algorithms, because a multiplicity of such error integrating controllers leads to a phenomena known as "power hogging", which causes system instability and which reduces overall system efficiently. When "power hogging" occurs some generators are heavily loaded whereas other generators are only lightly loaded.

For distribution connected distributed generators the output power contollers should be set so that if the line voltage sags 6% below nominal the distributed generator net output power is maximum and if the line voltage rises 6% above nominal the distributed generator net output power is minimum. This type of power control is not consistent with the distributed generation contract terms offered by the OPA and then the IESO.

For substations the output power contollers to local distribution circuits are set to maintain the nominal line voltage. Increasing the nominal line voltage setpoint reduces the amount of distributed power generation and increases the load power consumption. Decreasing this nominal line voltage setpoint increases the amount of distributed power generation and reduces the load power consumption. Hence the IESO can in principle achieve system power balancing by making small changes to the nominal distribution voltage setpoints. Each substation line voltage controller must have control provisions to prevent short cycling of the substation transformer tap changer.

Energy storage devices require two control algorithms, one for charging and the other for discharging. In the charging mode an energy storage device behaves as a load. In the discharging mode an energy storage device behaves as a generator. A behind the meter energy storage system normally uses power control to achieve a very high load factor for its owner. In the past Toronto Hydro used behind the meter load control to minimize Toronto Hydro's peak demand.

Step controlled load shedding systems must have a control deadband equal to the largest single power step to prevent short cycling. Subject to suitable contract arrangements the Independent Electricity System Operator (IESO) could remotely adjust the nominal power setpoints of load control systems to meet unusually high or unusually low total grid load conditions.

This control methodology results in a stable power system that is highly resistant to software attacks by hackers because most of the power control algorithms are imbedded in firmware that cannot be changed via the communication links. This control system can still potentially be compromised by hackers shutting down generators, switching isolation breakers or adjusting the nominal power or voltage setpoints. However, since only a small amount of control data is involved this data can be highly encrypted. Furthermore, most voltage control is achieved locally rather than through the communication network. Thus the system can tolerate most network communication failures.

Stable operation of a distributed generator with a negative slope net output power versus line voltage controller imposes certain mechanical constraints on the generator system. For an engine-generator these requirements include a minimum flywheel size, a maximum time delay between a step change in line voltage and the engine output power response and a minimum load. These issues are well known to engineers who specialize in design of load following generators. However, many present wind turbines are not fitted with output power control systems that are capable of stable line voltage regulation. Such control systems should be required by all new IESO issued Feed-In Tariff contracts. These contracts should also provide for the distributed generator output power constraint that will result from use of line voltage regulating power control systems.

All distributed generators should be fitted with control systems that provide voltage and phase synchronization prior to generator connection to the external network and that gradually power up the generator after connection to the external network. Similarly, except in emergency circumstances, generators should gradually power down before disconnection.

In order to provide electricity without a severe environmental impact, much effort in recent years has gone into investigating generating electricity from wind, run-of-river hydro, solar and co-generation distributed energy sources. However, all of these distributed energy sources have the common problem that the time profile of their unconstrained electricity outputs does not match the time profile of the uncontrolled electricity load and that the average electricity outputs from renewable generators are substantially higher in the winter than in the summer. In order to effectively utilize these distributed energy sources, part of the total electrical energy generated during the winter must be stored in some form of potential energy and then converted back into electrical energy during the following summer. Seasonal storage of excess energy might be achieved via Pumped Hydraulic Energy Storage Between Lake Erie and Lake Ontario. Daily storage of excess energy could be achieved via Na-S-NiCl2 Electro-Chemical Energy Storage or by Compressed Electrolytic Hydrogen Energy Storage. Various means of energy storage are discussed under the heading Energy Storage.

The metering methodology must allow any party connected to the grid to be designated a generator, a load or both. The metering system and the related electricity rate must not impose a financial barrier to energy storage, which is essential to achieve reliability and voltage regulation with random intermittent distributed electricity generation.

A significant constraint on adding distributed generation to an existing local distribution circuit is the short circuit fault clearance capacity of the existing switchgear used to isolate branches off that circuit. This switchgear was originally sized assuming that the only energy source connected to the circuit was the utility substation transformer. Addition of distributed generation along the circuit lowers the source impedance seen by a load and hence increases the potential short circuit fault current. Usually there are no inexpensive solutions to this problem. The short circuit fault clearance capacity of every branch isolation switch may need to be doubled in order to safely accommodate maximum distributed generation. If the branch isolation switches are privately owned by parties that are not involved in distributed generation there is presently no clarity as to who is responsible for the cost of the required switchgear upgrades.

The IESO seeks to purchase kW capacity or kWh rather than fixed assets from private sector distributed generation. Consequently the generation facilities must be funded by the private sector without government guarantees except with respect to the power purchase price. Absent government guarantees the blended cost of construction financing can increase from approximately 7% / annum to approximately 20% / annum. Few who have not been directly involved in funding power system construction, operation and maintenance fully appreciate this issue. A consequence of abandoning government financing guarantees is to approximately double the cost per kWh of electricity from new generation.

The mission of the private sector is to make a profit, not to make electricity. Private sector capital for the electricity system is only available to the extent that this capital provides the same return on investment as other activities such as construction of major buildings or financing credit card debt.

The Ontario Energy Board (OEB) will have to have to face and deal with this issue. There is no magic solution. The government of Ontario has accumulated $320 billion of debt. There is presently inadequate provision for reducing the principal of this debt. This debt makes it difficult or impossible for the government of Ontario to guarantee further debt financing for major electricity projects. In order to mitigate the cost of new generation and new transmission the OEB should implement a electricity rate change that is aimed at selling more electricity from existing generation to reduce the debt principal.

There must be a cultural shift. The object is not to conserve electrical energy. The object is to efficiently use electrical energy to displace fossil fuel energy while minimizing peak demand on the electricity grid. Financial incentives for electrical energy conservation must be replaced by financial incentives for peak demand minimization.

There must also be new revenue sources. Revenue from a fossil carbon emissions tax should be applied to financing new nuclear generation and supporting transmission. This author suggests a fossil carbon emissions tax of $200 per CO2 tonne emitted. A tax of this magnitude is required to make new nuclear generation financially competitive with fossil fuels. At some future time the Canadian government may impose a fossil carbon emissions tax. However, in the interim Ontario should impose its own price on CO2 emissions to reduce the Ontario debt.

This web page last updated February 25, 2017.

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