Do you have any specific…

Do you have any specific ideas on how to reduce costs of new clean electricity infrastructure?

First, direct Ontario Power Generation to initiate discussions with Enwave Energy Corporation about supply of hot water from Pickering or Darlington nuclear generating stations. Stress that approval of refurbishment of Pickering B depends on this.

Second, change the name of the Electrification and Energy Transition Panel to Decarbonization and Energy Transition Panel. Get some district energy expertise on board and emphasize that the objective is to achieve zero emissions at minimum cost, not maximize electrification per se.
Enwave must decarbonize. The City of Toronto required it by 2030 in their TransformTO plan. Their owners, the Ontario Teachers Pension Plan, have stated their commitment to zero emissions in all their investments by 2030. It won’t be achieved by 2030, but it should be soon moving strongly in that direction. Their customers would be pleased, as it would enhance their Environment, Social and Governance (ESG) score. The road to decarbonizing would be to first convert from steam to hot water distribution, as was done successfully by Public Works in Ottawa and several universities (Dalhousie, UBC, Stanford, Rochester and the U of T is moving that way with its geo-exchange project).

That will be a billion dollar plus commitment for the public good from a private corporation, which is also striving to ensure our teachers get the pensions they richly deserve. Ontario could help by supplying heat from existing or new nuclear generating stations. Existing and refurbished nuclear units should be retrofitted to operate as Combined Heat and Power (CHP) units. CHP should be a condition of permitting any new base load, thermal generating units, whether nuclear or bioenergy.

Following conversion to hot water, and given access to a potentially very large source of low marginal cost, clean heat, Enwave could rapidly expand to supply many more buildings thereby obviating the need for heat pumps in every building. That would also facilitate expansion of their deep lake water cooling system, which would shave the summer peak.

This big win for district energy in Toronto would stimulate demand for its development throughout the province. The real estate industry would demand it when they saw how neatly it solved their problem of having to decarbonize and meet municipal green standards. It would avoid investments in their own equipment, with associated building modifications (e.g., to the roof of multi-story buildings to accommodate air source heat pumps).

Increases in winter peak demand, with consequent new electricity infrastructure, would be avoided. Not having to build it in the first place would be the most cost-effective way to reduce costs of new clean electricity infrastructure. And elimination of reliance on hydrogen would reduce costs. CHP and demand management could take over much, or all, of the intermediate and peaking duty.
District energy is highly bankable due to firm contracted long-term revenue streams from service fees, very similar to the real-estate business. It enables financing by pension funds and insurance companies, aided by the Canada Infrastructure Bank (for example as they have, respectively, invested in and provided debt financing to Enwave). Besides Enwave and Creative Energy (out of Vancouver, also active in Toronto), there is no lack of experienced, deep-pockets district energy developers in the world who would respond to requests for expressions of interest and do the job, given demand from the real estate industry and enabling government policies. Mandating new thermal generating stations to be CHP proved successful in Denmark.

There would be little to no adverse impact on hydro rate-payers. On the contrary, the electricity system would benefit from CHP. Steam turbine generators have the inertia valued by the IESO for frequency support. The ratio of power and heat production can be controlled to follow variation in electricity demand, thereby supporting more renewable energy, unburdened with overbuild and storage. CHP would be the backup, not gas plants, allowing compliance with the Clean Electricity Regulation. And it would avoid the delusion (or pretense) that hydrogen will eventually fill the role of intermediate and peaking generation, a vain hope that is another case of “wishing and hoping and dreaming and praying”.

Large-scale district heating with thermal energy storage would provide a market for surplus power, leveraged by industrial heat pumps. The extra revenue to the electricity system would mitigate hydro rate increases.
The potential for reduction in emissions from buildings by nuclear CHP is greater in Ontario than the avoidance of emissions from the electricity sector alone that could be accomplished by conventional nuclear. Hence, its social benefit would be higher, which would improve social acceptance and ESG standing, which, in turn, would lower financing costs, with consequent lower costs to hydro rate payers.

Buildings in rural areas, and very low-density residential areas, where they have space, could use ground-source heat pumps that are still efficient, and don’t lose capacity, at the coldest air temperatures, and are therefore not so stressful to either the grid or the local distribution system. They also have space for individual thermal energy storage, which could make them dispatchable loads.

District heating is inherently more suitable than the electricity system for delivering heating because heating has high and long duration peaks and district heating requires less capital per unit of peak demand, per kilowatt (kW), and thermal energy storage costs about 1/200th of electrical energy storage per kilowatt-hour (kWh) stored, loses little energy over time, does not degrade over time or overheat and can be charged or discharged rapidly. As already mentioned, but it bears repetition, electrical peaks are for a few hours but heating peaks last days. The magnitude and duration of heating peaks would be a threat to the security of the grid, but could be handled by district heating economically with no longer any peaking plants but instead very large thermal energy storage.
If building heating were to be electrified, the new electrical peaks would closely follow the heating peaks because the effective efficiency of air source heat pumps with supplemental resistance heating and defrost cycle is low at the very cold temperatures when heating peaks occur. Needless to say, they occur almost every year in Ontario, sometime in January or February.
For the purpose of estimating the impact of heat pumps on required electrical capacity, it is not the energy consumption that matters, but, rather, the peak demand. That is when kW of heating demand translates almost directly to kW of electricity demand. As previously mentioned, Ontario’s heating peak is estimated to be about 60 GW (adjusting gas consumption down for efficiency). That figures because Enbridge Gas state their annual peak demand is 120 GW (in their ‘Pathways’ report). Although that includes industry and power generation, more than half would be building heating, including domestic hot water.

Based on escalation of unit costs in a previous detailed study, The Potential for District Energy in Metropolitan Toronto (‘the Metro Study’), updated for pipe installation costs from recently built projects, recent proposals in the Greater Toronto Area, and many feasibility studies, it appears district heating can be provided in Ontario today generally for under $3,000/kW of connected load. That includes the equivalent of generation, transmission, distribution and the heat pumps in buildings. In contrast, Pathways calls for $400 billion of investment for 50 GW of effective new capacity (Appendix A, tab 11), i.e., $8,000/kW, and the individual building heat pumps would add another roughly $1,000/kW.

Hence, new electricity infrastructure to meet the heating peaks would cost customers about three times the equivalent district heating infrastructure. The latter would be paid for by heat customers, as it should, not electricity rate payers. It would entail a higher fraction of local economic content, being comprised mostly of engineering, installation, pipes, heat exchangers and valves, in contrast to the more expensive materials and equipment essential to the electricity system, mostly made outside Canada.

One canard often heard is that hot water cannot be supplied the required distance from central generating stations into urban areas. The contrary is proven by many systems in Europe. In the case of hot water supply from Pickering to supply a large part of Toronto, the capital cost of the connecting pipes, supply and return, (probably submarine on the lake bed part way, and part way in a tunnel), according to the recently updated unit costs for pipe, but subject to detailed design and costing, would be over a billion dollars, depending on how much of the capacity is connected and how. But the value of the market is over $3 billion per year. It may be suitable for a third-party developer to build, own, operate and maintain under a tolling arrangement much like Highway 407. It would certainly be essential to employ a constructor with specific experience in this type of undertaking.
The potential net margin can be appreciated by considering the business-as-usual cost of heating with gas, well over $100/Megawatt-hour (MWh) (which is just the cost of gas at today’s price, allowing for efficiency, and 2030 carbon price – there are additional significant avoidable costs of equipment maintenance and reinvestment) with the variable operating and fuel cost of nuclear energy, put at $3/MWh in Pathways Appendix A, tab 3.

And this should be factored down by the ratio of reduced electricity output per unit of heat output. At the extraction temperatures likely to be used that ratio is 0.2. (Reference District Heating Supply from Nuclear Power Plants: Technical and Economic Aspects, Power Magazine, March 1st, 2022, by Ishai Oliker, PhD, PE (jtcincorp@optonline.net), who at one time consulted for Ontario Hydro in a study of converting Lakeview Generating Station to CHP).

Applying the ratio to the variable cost of nuclear energy results in a wholesale heat energy cost of $0.60/MWh, leaving a considerable margin below the customer’s business-as-usual cost of well over $100/MWh, with a total market in Toronto of about 30 million MWh/year (not that the entire market would necessarily be served this way, but it’s a good indication of the business potential).
That would be the true economic cost of using surplus power. This assumes that since Pathways envisages considerable surplus power (see two paragraphs on) it must envisage some degree of turn-down is possible with the new nuclear units. Therefore, the economic cost of not turning down the reactors would be the variable cost.
Extracting steam to produce useful heat in the form of hot water does reduce electricity generation a bit (0.2 MWh of electricity per MWh of heat extracted). But this would not diminish generation from base load so long as there is surplus system-wide (including from wind generation).
An indication of the extent of surplus power in the decarbonization scenario can be seen from Figure 12, which shows 26 GW of installed nuclear capacity by 2050, which could generate 212 Terawatt-hours (TWh) at the assumed 93% availability, yet Figure 13 indicates only 133 TWh of nuclear energy would be used in 2050. Evidently some turn-down is assumed.

A similar calculation for wind is not as straight-forward because its availability varies by location. But the preponderance of wind locations (all but 2 out of 16 per Appendix A, tab 3) are above the average capacity factor of 40% implied by Figures 12 and 13. Therefore, it seems likely there would be additional surplus power from wind in the decarbonization scenario (as there is now, which tends to get curtailed).

Even just the 79 TWh/year of surplus nuclear electricity capacity would support production of over 200 TWh/year of heat. (The Metro Study included energy balance calculations for Pickering, Appendix 12, showing 1.3 GW of heat could be practically produced from each 0.52 GW electrical unit, thereby derating the units to 0.185 GW electrical, a derate of approximately 64%). The potential of over 200 TWh/year is more than the total heat demand in urban areas in the entire province.
The residential and commercial heat consumption in urban areas in Ontario over the 12 months prior to December 2022 is estimated to be a little over 120 TWh. This estimate is based on reported gas consumption, assuming 85% in urban areas and 80% average efficiency. “A little over” is because heating fuels other than gas were also used, although that tends to be outside the denser urban areas. Future heat consumption is likely to be close to this with increasing floor-space offsetting improvements in building envelopes. Therefore, the market for heat for district heating is a good match for a large portion of the likely volume of surplus nuclear energy.

Based on the Pathways results, it seems considerable surplus energy is likely. This is quite intuitive given the imperative to not burn fossil fuels for load following and the high expense of hydrogen as an alternative.

The cost of derating base load generation for heat production at times there was no surplus energy would depend on the marginal cost of the resource on margin at that time multiplied by 0.2, the ratio of electricity derate to heat production. If that was still methane it would be economic but result in more emissions (though less than displaced from the building gas heating systems). If it was hydrogen in combustion turbines at 38% efficiency, it would not be economic because the marginal cost of that electricity would be about $500/MWh, according to the price assumed for hydrogen in Pathways, Appendix A, tab 3, $41 USD/MMBtu.

But as argued in answer to the next question, wide-spread district heating and dispatchable nuclear and bioenergy and more demand response and dispatchable load would reduce, and could eliminate, the need for the hydrogen fuelled combustion turbines. If any hydrogen was used, it would be for fewer hours in the years, i.e., there would be more hours in the year when surplus energy was available and TES would enable heat production to be concentrated in those hours.

And if hydrogen is used it would be better in fuels cells with heat recovery giving an efficiency of 85%. Bringing those units on line to make up for the derate due to heat production from CHP base load units would make economic sense.

To be clear, the nuclear steam systems would be base loaded, but the steam turbine generators could follow the daily variations in electric load. The nuclear CHP would thereby replace methane gas plants and obviate hydrogen gas plants.

The incremental capital cost of building, or retrofitting a nuclear power plant to CHP would be less than 5% (same Power Magazine reference as quoted earlier). Going by the Pathways Appendix A, tab 3, 2030 Build Cost of large nuclear at $7,194 (2021USD)/kW and recognizing that the heat capacity could be about double the electrical capacity (per Metro Study as mentioned) derives a heating capacity cost of about $250/kW Canadian, which is a bargain for heat plant capacity. That’s because it builds on the back of capital committed in any case to produce electricity. It would give Ontarians a bigger bang for their buck.
Sufficient CHP together with demand response, dispatchable load and storage could substitute for gas plants, including hydrogen. (Hydrogen for power generation in combustion turbines is a wretched idea – see answer to next question).

Heat demand is mostly in winter, whereas the availability of surplus power or cogenerated heat would be spread throughout the year, probably a lot in the shoulder seasons and summer nights. However, the two could be closely matched economically using large scale thermal energy storage (TES). TES would be located close to the heat loads so as to minimize the long-distance supply pipe sizes. The stored energy could be topped up, as necessary, in winter using off-peak electricity, possibly with heat pumps. As with the long-distance connecting pipes mentioned earlier, preliminary calculations (based on surveys of large-scale TES construction costs in Europe) indicate the cost of required TES would be a low fraction of the energy value. The peaking energy would be a small fraction of the total, probably less than 10%, which would cause a minor increase in the average marginal cost of heat energy (over the base cost from CHP only).

CHP units could almost instantly revert to full electric power output at any time, so electrical capacity would not be reduced. The reduced electric power while cogenerating would effectively be hot spinning operating reserve. Increasing the electricity output on CHP would provide ramping capability, and decreasing would provide turndown capability, emulating gas plants.

TES in combination with CHP would be a practical form of otherwise very expensive long duration electrical energy storage and thereby help support more wind and solar on the system to lower costs and phase out gas. When the wind blew hard and the sun shone brightly, the CHP plants could automatically adjust to produce more heat and less power and vice-versa. And if then there were still surplus power available it could be turned into heat in TES by industrial heat pumps or resistance heaters. This would effectively store electricity because the stored heat would allow CHP to produce more power than heat later, while district heating would still be served continuously from TES.

The appropriate wholesale pricing structure for electricity from CHP would cover net revenue requirements, including all annual fixed costs, with capacity payments, and marginal operating costs with energy payments – this is essentially the deal gas plants get. CHP plants could then sell heat wholesale at a bargain for heat customers but much more than their marginal operating costs, earning more profit than they would generating electricity only. But they would be obliged to respond to the IESO’s direction to ramp up electricity generation per system needs in order to qualify for the capacity payments. The district heating systems, with their large-scale TES, would be happy to receive what they needed on an annual basis – the low variable cost of energy would justify extensive TES works, which have operating lives in excess of 50 years.

Pathways Appendix A, tab 8, suggests a decarbonization scenario would have 7 GW of SMR’s plus 11 GW of new large nuclear units. There are hints that some of the new nuclear capacity might be located at existing fossil stations; Wesleyville, Lambton, Lennox and Nanticoke come to mind. Wesleyville may be close enough to Port Hope (about 10 km), Lambton might be close enough to Sarnia (about 20 km). Lennox might just be feasible to connect with pipes to Kingston (approximately 50 km). But Nanticoke (like Bruce) is definitely not ideally located to serve district heating. Nevertheless, even if some of the new nuclear capacity was located where heat energy business would not be possible, that would leave a lot of scope for nuclear CHP. The largest heat load centre, the Greater Toronto Area, is close enough to be served from existing nuclear sites at Pickering and/or Darlington. And it would be relatively easy to also convert existing units to CHP, especially those being refurbished.

The SMRs, possibly about 20 units by 2050, could be distributed close to smaller load centres (Thunder Bay, Sudbury, Windsor, Sarnia, London, St. Catherines-Niagara Falls-Welland, Kitchener-Waterloo-Cambridge, Brantford, Guelph, Hamilton, Kingston, Ottawa). Some SMRs could be located on the sites of gas plants. They might re-use the steam generation cycle modified for CHP.

Without going through the whole list, several of the gas plants are located either in or close enough to urban areas, e.g., Portlands Energy Centre in Toronto, York Energy Centre, Goreway and Halton Hills.

The Portlands Energy Centre and York Energy Centre would be particularly good locations for SMRs. Gas-fired generation may be made illegal by the Clean Electricity Regulation and transmission solutions not possible. Referring to Toronto and York Region, Pathways Appendix B admits that “With all these facilities in place, however, winter 2050 demand could still not be met.”

Perhaps it could if winter peak demand was reduced through district heating and SMRs were located close to the city, e.g., in the Portlands area or Downsview. There is an enlightened segment of the public well aware that nuclear has no local health impacts, but gas does. The nuclear regulators, and cities and towns should accept SMRs and MMRs inside urban areas. This concept is currently being studied by the Electric Power Research Institute in the NuIDEA project, as reported in Power Magazine, March 2nd, 2023, Is a Nuclear Reactor Headed to the Heart of Your City? by Aaron Larson, executive editor (@AaronL_Power, @POWERmagazine).

Another idea, along similar lines to nuclear CHP, but which might be more applicable in certain locations, particularly smaller centres in wooded areas, is bioenergy CHP with Carbon Capture and Utilization or Sequestration (CCUS). Pathways dismissed CCUS as inappropriate for the peaking duty of gas plants. However, it did not consider CCUS with base load bioenergy CHP either for industrial process heat or district heating. An example of a likely scale for bioenergy CHP is the 65 MW heat/25 MW electrical, bioenergy CHP operated by District Energy St. Paul.

There is a broader emissions benefit associated with bioenergy (other than potential CCUS) that Ontario should consider and it concerns the lamentable state of our forests. Due to the decline of the pulp and paper industry, there is currently no market for wood fibre from forestry thinning to improve tree growth, or from damage from climate change effects (forest fires, insect infestations, storms/derechos, and natural die off). The boreal forest is very large. As a result of lack of management, greenhouse gas emissions from our forests will soon exceed anthropogenic sources. Better management could be put in place if bioenergy created a market for low grade wood fibre. This is another example of how the publicly owned electricity system should look at a bigger picture than considered by Pathways.

There is also an economic development aspect to bioenergy, particularly for Indigenous communities. An example is the Nipissing First Nation, which is active in forestry. A biomass CHP might be developed on their land to serve the North Bay Regional Health Care Centre and Nipissing University. That’s just one example.

With the amount of thermal capacity projected in Pathways, (inevitably in surplus in order to achieve zero grid emissions), the electricity system could serve as a local, clean, low marginal cost heat resource that could eliminate the province’s dependency on imports of billions of dollars per year of polluting fossil fuel, eliminate the need for communities to spend billions of dollars on building retrofits and heat pumps (for example an estimated $302 billion in the case of Toronto per their Net Zero Strategy for Existing Buildings) and eliminate possibly half of the $400 billion new investment contemplated in Pathways for electricity system expansion (which may itself be a low estimate because of the unrealistic assumption about the future capabilities of air source heat pumps at the coldest air temperatures).

To an extent, heating load occurs where electricity load is at. Therefore, reducing peak heating load would be a good way to alleviate “the cost and siting challenge for the required stations and distribution infrastructure (which) will also be substantial” (Appendix B, page 13).

In conclusion, the proven ‘real-world’ technologies of district heating, CHP and seasonal thermal energy storage should be looked to, rather than the ‘dream-world’ technologies of hydrogen and magically efficient air source heat pumps at low air temperatures. This would generate more revenue for the electricity system without excessive capital investment. That would help moderate hydro rate increases.