Do you have any comments or…

Do you have any comments or concerns regarding the development and adoption of hydrogen or other low-carbon fuels for use in electricity generation?

Pathways decarbonization scenario employs 15 GW of new hydrogen plants, while apparently assuming that heating would add about 25 GW to the peak demand (+ reserve margin). A district heating/ground source heat pump strategy could make that 15 GW of new hydrogen unnecessary, certainly for meeting heating peaks.
Absent heating, following normal daily load variations could be accomplished with a combination of CHP, some manoeuvrable nuclear without CHP (e.g., Bruce A and some new SMRs), demand response, dispatchable load and storage. In perspective, with 20 GW of installed nuclear capacity (less Bruce) per Figure 12, and 93% availability, and a potential maximum derate of about 60% (per previous studies on Pickering) there would be up to about 11 GW of dispatchable nuclear CHP capacity, which is more than the usual 5 GW of daily load variation even without resort to the other tools mentioned. This would be made possible by large scale thermal energy storage being able to accept lots of heat at night thereby keeping the reactors at full power while the generators were derated (turned down).

It makes no sense at all to convert electricity to hydrogen at 75% efficiency, then convert the hydrogen back into electricity at 38% efficiency, then suffer 10% losses in transmission and distribution to deliver electricity for heating during the heating peaks for an overall power to heat efficiency of about 25%. Contrast that with extraction of heat from CHP, notionally 500% efficiency, with 5% distribution heat losses for an overall power to heat efficiency of 475%. Consumers would pay dearly for this strategic mistake, not to mention the cost of seventy-five new 200 MW combustion turbines with transmission connections.

Appendix D, tab 9, cell D3 states that “Economic adoption of Hydrogen at scale will most likely require Blue Hydrogen to be imported into Ontario.” There are many issues with this: (1) it will not be 100% emissions free because no known technology captures 100% from steam methane reforming, (2) it would cost even more than hydrogen does today (which is already too expensive to use for power generation) because of the additional cost of carbon capture, (3) compression or liquefaction for storage and transport will add more cost, and probably emissions because generation in Alberta will likely evade Clean Electricity Regulations (for example, behind the fence and/or cogeneration) and (4) there is not going to be a Hydrogen Trans-Canada pipeline so trucking costs will add to the costs and emissions, as well as being a public safety hazard.

The most reasonable expectation is that hydrogen will always be expensive and have higher value competing uses and will be best manufactured at point of use.

Based on the price of hydrogen assumed in Pathways, the cost of electricity generated from hydrogen at the assumed 38% efficiency would be approximately $500/MWh, 50 cents/kWh. Pathways projects 12 TWh/year from hydrogen. That would cost over $6 billion/year in fuel (2022 $). This does not seem to be included in the System Costs, the basis of the 20-30% increase in unit rates, so the increase would be more if hydrogen was used (and even more would probably be used because of the aforementioned erroneous assumption about improved efficiency of air source heat pumps and the apparently unforeseen by Pathways several days duration of heating peaks).

The overall impression is that Pathways uses hydrogen as a dog-whistle to more or less say “we can’t actually think of a way to phase out the gas plants”. This is not good enough. The IESO should be sent back to the drawing-board and told to come up with an economical way of getting to zero emissions as surely and as soon as possible. Rather than pretend hydrogen will be the solution, it would be better to honestly accept that the twin constraints of decarbonization and reliability may have to be reconciled by having even more base load nuclear even if it means more surplus power. Better to have surplus than not enough. CHP and district heating could turn the surplus into a valuable, marketable co-product. And so could heat pumps operating off-peak saving the energy in large-scale thermal energy storage. And so could green hydrogen at the point of use, though probably not for burning in combustion engines (unless Toyota’s dreams become reality).

Pathways painted itself into this corner by uncritically accepting the dogma that building heating must be electrified. That made an already difficult task harder than necessary. The seriousness and difficulty of decarbonization calls for a higher level of imagination, more searching for viable options, collaboration, more work and more willingness to learn from the on-going development of 4th generation district heating in almost every other cold country.

What are your thoughts on balancing the need for investments in these emerging technologies and potential cost increases for electricity consumers?

Hydrogen generation is not really an emerging technology as used in the way described in Pathways. It’s not emerging anywhere like that on a utility scale. Some industries currently use their excess hydrogen for generation behind the fence when they have it. There have been demonstrations of hydrogen fuel cells for power or CHP, e.g., in the U of T Mississauga campus. But transporting large volumes from Alberta to Ontario to burn in inefficient combustion turbines as an essential permanent pillar to support our electricity supply makes no sense at all, as previously discussed, when there is a better alternative.

Green hydrogen made from surplus power at night with diurnal storage, perhaps hydrides, on the site of gas plants, to fuel generation only during the day, might make more intuitive sense as a small adjunct to day-time resources. In that case, it would be more efficient to use CHP fuel cells at 85% efficiency. District heating and TES would be needed for the heat off-take.

SMRs and MMRs will be useful in place of new transmission that would be required for other generation sources. In some cases, new transmission would be next to impossible to build in time, or at all. Similarly, they would get CHP close enough to heat loads for optimal efficiency. District heating has several advantages over industrial steam customers: (1) thermal energy storage (TES) of hot water allows CHP to be dispatchable for electricity, (2) lower cost of heat production because the electrical derate is lower at lower extraction temperature, (3) TES largely deals with the lower load factor of building heating, (4) potentially larger heat hosts, (5) more of them (every city, town and cluster of buildings) and (6) more secure longevity of heat off-take contracts (“safe as houses”).

In the case of Pickering Nuclear Generating Station there is not a lot of room for SMRs and the existing station would be in the way of lake water cooling. But refurbishment of existing units could include modification to CHP.

The SMR planned for Darlington by 2028, and probably others later, is a BWRX-300. This is a boiling water reactor requiring an additional heat exchanger for district heating. This would be a steam-to-steam transformer upstream of the district heating condenser. That would be a little more complicated, but has proven to work on a large scale. Steam transformers were used for 26 years to interface between Bruce Nuclear Station A and the Bruce Heavy Water Plant.