Fuel Switching and Decarbonizing Building Operations
Using downtown Toronto as a test bed, Toronto 2030 District researchers map out the costs and logistics—for building owners and cities—for getting to zero operational carbon in the buildings sector.
AED professionals are becoming increasingly adept at improving the energy performance of individual buildings. But meeting global carbon reduction targets will require much more than creating new buildings to higher standards, and retrofitting existing ones piecemeal. In provinces like Ontario, it will mean a wholesale switch away from the present carbon-intensive natural gas heating systems. While governments must decide what fuel will replace gas, architects need to understand what is coming—as it will influence the way they design in the future, and the advice that they give their clients today.
To better understand what will be needed to achieve a low-carbon future, I’ve been working with the Toronto 2030 District: a private-public initiative with 63 members, including building owners, operators, and investors; service providers like architects, engineers, and suppliers; and community groups like the OAA. The Toronto 2030 District is part of a North American network of 23 similar districts, linked to the non-profit organization Architecture 2030.
Using downtown Toronto as a test bed, we have taken on the challenge of exploring the wicked problem of reducing the operating emissions of buildings, which account for some 30% of global GHG emissions. The District’s physical area contains most of the building types found in Ontario: low-rise residential, high-rise residential, low-rise commercial and office towers, as well as Ontario’s Legislature, two stadia, a hockey arena, two universities, many hospitals, two city halls, hotels and restaurants. We are primarily addressing what to do about existing buildings, but we also expect the findings to influence regulation and leadership when it comes to new buildings. The Toronto 2030 District’s members are not new to greening buildings and have insight into what could work, and what will not.
Finding the Right Solution
It was once believed building owners could make individual decisions that, when added together, would save the planet, but it’s become clear that this idea is not working. Progress has stalled at about 30% operational energy savings. The savings achieved so far have relatively good paybacks, like the widespread implementation of lighting retrofits. However, achieving the next 30% savings will be a lot more costly—involving moves like envelope or mechanical retrofits—and businesses going it alone will be at a competitive disadvantage.
Programs like the LEED rating system have sometimes performed better, but LEED has penetrated only about 1% of the new construction market, and affected much less of our existing building stock. Even this program has struggled to achieve deep carbon reductions because of its measuring system—based on reference buildings and proposed alternatives—rather than real-world results.
Overall, what we have been doing thus far amounts to essentially random acts of energy efficiency. We have no idea if our efforts are addressing the climate imperative. We are like mountain climbers in a fog at the bottom of a mountain: we know we are going up, but we do not know if our path leads to the summit, or to the top of a foothill. If we are taking actions to reach a target for 2030, then we should be sure the efforts are in line with what is needed to reach the 2050 targets, and will not need to be undone. Nonetheless, what has been done to-date is not wasted. Our experience with LEED projects can be used to imagine what is required to take super-efficiency to scale.
It is becoming clear that what we urgently need is a political solution, rather than a consumer one. There is precedent for the work that needs to happen. In the 1950s and 60s, many governments (including Ontario’s) supported the conversion of “city gas” systems to natural gas, and continue to regulate the development and expansion of our natural gas system.
Just as happened then, the new solution will be first and foremost about fuel switching, and next about energy efficiency. In meeting our carbon reduction targets, there is no scenario where natural gas—whose primary component, methane, is a potent greenhouse gas, and which creates carbon dioxide when burnt—can continue to be used in its present form to heat buildings. There is no way to capture the resulting CO2 at the building level, and without doing so, we cannot meet the global targets of reducing our carbon emissions to 50 percent below 1990 levels by 2030, and reaching carbon-neutrality by 2050. We need to change fuels.
A New Vision
The Toronto 2030 District has already completed a utility data project that accounts for the annual energy use of all 7,216 buildings within its borders (www.toronto2030platform.ca). We are now researching the pathways to creating a decarbonized energy supply that meets the needs of buildings in the District. For this exercise, we chose a process developed by the Transition Accelerator, a Canadian non-profit whose work includes projects in Ontario, Quebec and Alberta. The process is a good fit because, like the District, it is driven by stakeholder engagement and defined goals.
To date, Toronto 2030 District has worked at understanding existing systems, co-developing an alternative vision, and analyzing some of the pathways to achieving that goal. Our group of private and public sector partners looks at the UN climate targets from the point of view of the options and costs to individual building owners: we don’t think it’s an option to say “it’s too expensive,” but rather, we have embraced the goal of showing how we can make it happen.
Notably, the project’s vision is not solely about airtightness, insulation, and efficient fans. We need to recognize the social and economic context for energy efficiency. We need to look for co-benefits—like increased value and comfort—which could pay for improvements. The District encompasses assets that are rich sources of data and ideas that can also be leveraged, like universities, research institutes, building organizations, and government agencies.
Our first in-depth analysis concerns fuel switching scenarios. We know for sure that we cannot achieve the UN climate targets while burning fossil-fuel-based natural gas as a primary heating source for buildings. Between now and 2050, we will need to fuel switch. Likely, we also will need to make buildings more energy-efficient to reduce costs.
To switch fuels, we will need to change the heating equipment at each building, as well as providing an energy system that can meet the shifted demand.
The fuels and technologies that are contenders for replacing natural gas are: electricity, hydrogen, and renewable natural gas. For electricity, the District looked at different heating technologies: electric resistance heaters, cold climate air source heat pumps (ASHPs), and ground source heat pumps. For the gaseous fuels, we also examined different production methodologies: blue hydrogen (created by splitting natural gas into hydrogen and captured carbon dioxide), green hydrogen (produced from water, using renewable electricity), and a hybrid of electricity and renewable natural gas (the latter captured from decomposing organic waste at farms and landfills).
Estimating the cost of the on-site building changes was very challenging. The over 7,000 buildings in the district come in a in a broad variety of shapes and sizes. Further, we wanted to work with real costs for switching out boiler, chiller and rooftop units.
To stand in for the building stock, we developed a set of 13 representative building occupancy typologies, each with typical floor plates and mechanical systems, to approximate the averages for the District’s building stock. We used public Energy Use Intensity (EUI) data for each occupancy type, and cross-checked this against actual consumption measures from our earlier data platform project. The result is a realistic, if approximate, model of how the District’s buildings are consuming energy, and the mechanical systems needed to support this.
In the analysis, we then replaced each typical mechanical system with appropriate equipment for the new fuels. We obtained current prices from an equipment supplier, and included soft costs and the cost of borrowing in our replacement estimates. Then, we translated this into square foot costs for each building type, which building owners could use to estimate their own costs and the impact on their businesses.
To estimate future utility bills, we calculated the amount of heat currently made by burning natural gas in each building type, and calculated how much electricity, hydrogen, or electricity and renewable natural gas (in a hybrid system) would be needed to generate the same amount of heat. We worked with a variety of reports and estimates to develop fuel costs that reflect the costs to generate the fuel and to build the needed energy plants, including carbon capture and storage in the cases where natural gas is the base fuel.
Adding together the capital costs and the fuel costs results in a total per-square-foot cost. This showed that blue hydrogen is the cheapest replacement for the combustion of natural gas. This is followed by a hybrid of standard air source heat pumps (accommodating heating peaks at -10°C) and renewable natural gas, then ground source heat pumps, then electric resistance heaters, then cold-climate air source heat pumps (accommodating heating peaks at -20°C), and finally, green hydrogen. The figure below shows the average cost per square foot across the eight most common building typologies.
Looking at this figure suggests that the decision is clear. But not so fast: cost is only one consideration. We also need to consider the potential for cost changes, as well as the likelihood we can make the system conversion before 2050.
To understand what a fuel-switching transition might look like from a larger perspective, the District 2030 partners and researchers devised a thought experiment, using the principles of project management to schedule the transition and gauge feasibility.
Blue hydrogen, the least expensive option in our initial analysis, is the name for hydrogen made with natural gas. The hydrogen and carbon in natural gas (methane) are split, the carbon is stored underground, and the hydrogen is sent by pipeline to be burned for heat at the building level.
However, there are two main issues with blue hydrogen. First, not all carbon from natural gas can be captured in the process: estimates range from 70% to 95%. We used 90% for our exercise, giving the benefit of the doubt to industry. Because of this problem, in order to be emissions-free, we would eventually have to switch to the more expensive green hydrogen (made with water and electricity) sometime in the future.
The second issue is that though it has successful pilot projects, blue hydrogen does not exist. While we have a lot of natural gas in Canada, we don’t currently make hydrogen with carbon capture and storage at this scale.
Hydrogen is a smaller molecule than natural gas. In a hydrogen-based fuel system, parts of the natural gas infrastructure could be reused, but all of the main distribution lines, as well as some of the local distribution lines, would have to be rebuilt. In Toronto, about a third of the local distribution would have to be replaced, meaning a lot of ripped-up roads.
Our natural gas infrastructure was not installed through a process of individual owner decisions. The provincial governments installed the system neighbourhood by neighbourhood, replacing old equipment alongside new equipment. Switching to hydrogen will require a similar process.
While we know how to manufacture the required boilers and furnaces for a hydrogen-based system, and may be able to make dual-fuel equipment, we don’t currently do it. There is no supply chain, no standards, no available safety monitors, design codes or regulations.
There are also concerns about our capacity to safely store CO2, and about the social acceptability of building or rebuilding pipelines. These amount to non-trivial project risks.
To meet the UN targets, a project schedule might look something like this. We allow two years to develop policy, consensus and regulations, which would be incredibly fast. We would then need to complete the following tasks: build the generation capacity; rebuild local infrastructure as required; manufacture heating equipment; and start switching over customers. Finally, we would need to replace the blue hydrogen with green hydrogen.
Because we would have to first build the supply system, the available time to convert would be a few years, and we would have to do so at an initial pace of 950,000 building plant renovations per year, followed by a more reasonable pace of 150,000 per year.
An Electrification Strategy
Electricity has a different issue than hydrogen: it has existing infrastructure, generation, codes, design standards and supply chains. But does it have the capacity to serve all of the heating needs of current natural gas customers?
When designing buildings, we do not size boilers or furnaces based on the total heat we will need in a year. Rather, we size them based on the maximum heat we will need to produce on the coldest day of the year. Similarly, when we are adding to the electricity supply system capacity, it’s the peak demand that matters, not the total load. Since electricity, unlike gas, cannot be stored, we need to size the generation system for the coldest day. The development of economical grid-scale storage is hotly pursued, and there are many pilot projects, but it is not widely deployed.
Either electric resistance technology (like baseboard heaters) or heat pump technology (a refrigerator run in reverse) can be used. Heat pumps work by taking either air or water, at some temperature, and squeezing heat out, exhausting cold water or air. Heat pumps are more efficient when the temperature difference between the incoming air/water and the desired temperature is smaller. Heat pumps are optimized for different incoming temperatures: the cold climate ones are rated to -20°C, and can handle our climate without backup heating systems.
What will happen to the peak loads if we convert to heating electrically? We based our scenario on converting all buildings to cold climate air-source heat pump technology, which although the most expensive system, gives us the lowest peak demands. In our test bed of downtown Toronto, the peak would switch from summer to winter, and increase by 100%. The electric system, as it stands right now in Ontario and most provinces, has additional peak capacity. We could start electrifying gas customers right away, and ramp up clean electricity generation at the same time.
Although electricity is sold by the kilowatt, the majority of the cost is in building the plants and distribution system. The marginal cost to produce additional clean kilowatts from existing plants is very little. It’s very likely that an all-electric system will generate additional revenue to offset upgrade costs, unlike with hydrogen.
What would a project schedule look like?
Again, we’ve assumed two years for consensus, policy and regulation. Fuel-switching in buildings could start immediately, as would building increased system capacity: we would not have to convert systems neighbourhood-by-neighbourhood like with gas. The pace of conversion
up to 2032 would have to average 393,000 buildings per year, followed by 150,000 per year up to 2050. Not all of the provinces have clean electricity generation, so at some point, the coal and natural gas plants would have to be closed and replaced with clean electricity sources.
The Hybrid Gas/Electric Strategy
This solution combines the benefits of the first two fuels, and takes advantage of the fact that “standard” heat pumps, which operate to about -10°C, are much less expensive than cold climate heat pumps. The idea is to electrify heating with the standard pumps, and use the existing gas system for the peaks.
Natural gas is the common name for methane extracted from the ground. Renewable natural gas (RNG) is also methane, but made from bio-based processes, such as capturing methane emissions from organic waste, landfills, and wastewater treatment. It is molecularly identical to natural gas, so infrastructure would not have to be rebuilt.
The downside of RNG is that we only have the feed stock to make about 15% of the methane that we currently use. This problem goes away if we are only using it for peaking, as peaking loads will require only about 5% of what we currently use. Furthermore, the operating costs would be high: RNG would likely cost the same as electricity. We would need to add a carbon price on top, to ensure that RNG was only used in peak periods.
The biggest project risk is that RNG would be a very flexible fuel, and the building sector will be competing with heavy industry and aviation for access to it, so operating costs could be high. Currently, natural gas use by industry is greater than its use by commercial and residential buildings. This would be a huge project risk. Another project risk is that if the conversion deadlines are not met, we would be forced to continue to use fossil-fuel based natural gas, and would therefore miss the UN targets.
This would have the lowest building-level capital costs, and low stranded assets. After policy is in place, it could start right away.
The Efficiency First Strategy
The premise of this solution is that we continue to use natural gas, but meet our targets by reducing emissions through energy efficiency measures. When we have gone as low as we can, we fuel switch at a lower level, thus reducing stranded assets in the energy system.
This strategy reduces gas use with more efficient mechanical equipment, by using controls to reduce unneeded heating, and by reducing the amount of heat lost through building envelopes. But how much efficiency is enough before you fuel switch? The City of Toronto has just released a study looking at this question. By their calculations, a 60% reduction is possible through deep energy retrofits, with energy efficiency similar to a net zero energy renovation.
Again, if this solution was proposed, we could allot two years for consensus, policy and regulations, and start renovations for gas customers immediately. In order to achieve a 60% reduction in emissions by 2032, we would need to renovate ALL gas customers in 8.5 years, or 706,000 buildings per year in Canada. Once that is done, we could change out their mechanical equipment to allow for fuel switching.
A 60% reduction in gas use cannot be achieved only with new windows and caulking. It would require significant envelope improvements. A City of Toronto report estimates the total value of renovating the building stock in Toronto to be $4.4 billion above what is currently spent on renovations. At a pace of completing all buildings in 8.5 years, this would amount to $517 million per year—for Toronto alone.
After the 60% reduction in gas use was complete, we would swap out the mechanical equipment in all of the buildings for fuel switching, at the more moderate pace of 562,000 per year.
“The scale of the challenge is huge, but that does not make achieving the goal impossible,” writes U.S. political scientist Roger Pielke Jr. “What makes achieving the goal impossible is a failure to accurately understand the scale of the challenge and the absence of policy proposals that match that scale.”
Architects and engineers do not make the final decisions about how to spend a building owner’s money—let alone drive larger policy changes—but it is our job to offer informed choices and insights to our clients. At minimum, we should stop calculating the net present value of energy savings measures based on today’s cost of natural gas. Instead, we should offer a sensitivity analysis including the potential years of available natural gas. We should offer envelope retrofits as a more expensive, but less risky option as they will serve all the future pathways.
While compromise is beneficial in human relationships, we cannot negotiate with physics. We need to comply with the UN targets, or we will fail, with catastrophic results for humanity. We should be looking for stronger government policy that includes a carbon tax of $340 per tonne or more, a commitment to develop agreements for one or more clean fuels in no more than two years, a commitment to set performance-based building renovation targets at the net-zero or Passive House level, and a commitment to streamline compliance using existing professional licensing systems and to provide the right data to support low-energy design.
Our conclusion? In the coming years, natural gas will cease to be used in buildings. When it comes to alternatives, there is no clear winner. Still, we have a clearer idea of the magnitude of the costs, which could be reduced with building energy efficiency measures. Whatever energy systems Canada ends up choosing, the only thing we know for sure is that to address the global climate challenge, change will need to come soon.
Sheena Sharp, FRAIC is founder and principal of Coolearth Architecture. She is a former president of the Ontario Association of Architects (OAA), and a past chair of the OAA’s Sustainable Built Environments Committee (SBEC).
The Toronto 2030 District research team for the fuel-switching study includes Co-Chair Sheena Sharp, Coolearth Architecture; Bruno Arcand, Carleton University; Peter Halsall, Purpose Building; Anton Kogan, SvN Architects & Planners; James Meadowcroft, Carleton University; Birgit Siber, retired principal, DSAI; Cara Sloat, Hammerschlag & Joffe; Geneva Starr, Purpose Building; Victor Tulceanu, BDP Quadrangle; and Svetan Veliov, Arup.