Heat is the toughest aspect of decarbonisation. The Energyst asked utilities, investors and industry associations for some thoughts on how to do it
According to Committee on Climate Change CEO Chris Stark, “it will be extraordinarily difficult to hit 2050 [net zero] without a plan in place for heat very quickly”. So what are the options?
There is a lot of faith being pinned on hydrogen, and the Committee’s report suggests in one net zero scenario that around 270TWh will be needed to help decarbonise peak heat, industry and transport. But that comes with a number of financial, technical and regulatory hurdles.
The gas networks are keen to use hydrogen as a replacement for natural gas, with projects such as H21 (which envisages switching Leeds to hydrogen) and Hydeploy (taking place at Keele University) touted as pathfinders. Government is also keen, with energy minister Claire Perry stating there are “enormous opportunities to work with the hydrogen economy”. Meanwhile, energy companies such as Shell and Vattenfall have suggested that hydrogen, particularly if produced by electrolysis rather than reformation, could deliver benefits across industries and economies.
Others believe hydrogen for heat is a waste of resource, particularly if carbon capture and storage (CCS) is required to bury emissions from hydrogen production via steam methane reforming (SMR).
“The Committee on Climate Change rightly states that CCS is a technology that has to be used in the right places,” says Tim Rotheray, director of the Association for Decentralised Energy (ADE). Heating homes with hydrogen is not one of the right places, he suggests.
“That would be an extremely poor use of the resource, because it is too valuable to aviation and heavy industry, where it makes much more sense. So government needs to think very carefully where to deploy it.”
Rotheray says lobbyists will always forward their own interests, “as do we”, but he questions the credibility of some of the gas networks’ plans.
“The question is, if you have a high value fuel that can fly planes and power ships … do you use it to heat air to 21 degrees? My expectation is that you do not.”
Rotheray and the ADE have pushed hard for heat network support and suitable regulatory frameworks for several years. Heat networks can reduce carbon emissions from heat due to the efficiencies of centralised plant. But most use natural gas, usually via combined heat and power (CHP) plants. How to decarbonise them?
Rotheray suggests waste heat is one under-utilised option (Bristol City Council thinks waste heat from incinerators can provide 40-45 per cent of the city’s heat load). Another is large-scale heat pumps. Rotheray says industry is working on solutions, but “government needs to put policy in place to ensure that heat resources are exploited”.
Vattenfall is grappling with how to decarbonise heat networks, having committed to do so by 2040 in Holland.
Bart Dehue, sustainable heat programme manager at Vattenfall, says some of the heat in its Dutch networks currently comes from incinerators – and WBR, the Rotterdam heat company, has plans to build a 40km pipeline to take heat from waste plants and refineries in Rotterdam to Lieden to replace the current gas source.
In Amsterdam, heat comes from a mix of waste and gas CHP. That saves about 50 per cent CO2 compared with a domestic gas boiler, says Dehue. “That’s nice but it has to go to zero. That is our ambition by 2040, so no more room for natural gas.”
So what are the options?
“We think there will be a mix of heat sources,” says Dehue. One is geothermal, “meaning deep geothermal, 2-5km deep, where you can achieve temperatures of 100 degrees plus,” he suggests.
Amsterdam also has a lot of data centres, whose low temperature heat, typically 20-30°C, could be boosted by a large industrial heat pump to 65-70 degrees. “We think that is probably a cheaper way [than putting heat pumps into every house],” says Dehue.
Another option is to take heat from water bodies. “Holland has quite a lot of water,” notes Dehue, especially sewage water, which has a higher temperature throughout the year than surface water, that could be combined with a heat pump.
Biomass will also likely play a significant role, he says, and Vattenfall has proposed a ‘transitional’ biomass scheme in Amsterdam to replace the current gas power plant.
“The UK has an equally fierce debate [around the sustainability or otherwise of biomass]. In our view, it has an important transition role. I think the other options [detailed above] can become very important in the long term. But they are very difficult to implement at large scale in the short term,” he explains.
“So if you want to get rid of natural gas, large scale, in the short-term, we see no other alternative to biomass.”
How long might that transition period be?
“The honest answer is that it depends on how fast we can deploy other alternatives. If geothermal is very successful, than by 2040, we may no longer have to use biomass. But it could also be a mix so that [other sources] come in the merit order before biomass – and that works, because pellets are expensive, versus geothermal, which would always have to be dispatched first,” suggests Dehue.
Over time, geothermal could therefore become baseload, then heat from data centres and water sources in conjunction with heat pumps, which require some electricity, and therefore some cost, and then biomass.
“So as we inject more heat sources to the mix, biomass will step from baseload to towards peak production only in the colder months, gradually to the point that you do not need biomass at all,” says Dehue. “This could be around 2040 … but we do not yet know how successful geothermal will be in this area.”
Biogas may also have a role to play in decarbonising heat. Doug Stewart, CEO of energy supplier Green Energy UK, says there has been a fourfold increase in production of biomethane since 2015, to 2.5TWh – the equivalent to supply a million homes, he says. Yet in the context of UK gas demand (800TWh+) that is tiny. As such, businesses that seek to decarbonise gas must pay a premium, though it is less than 10 per cent compared with standard methane, suggests Stewart.
While many biogas producers have largely burnt gas in CHP engines to generate electricity, Stewart thinks “in time” more producers will start injecting biogas into the grid – and will need to do so if the government is serious about net zero. But, given the current economics and incentives, Stewart questions, “who will build the anaerobic digestion (AD) plants?”
That is a good question, says Richard Barker, adviser and investment committee member at Iona Capital, which has invested in a significant chunk of the UK AD fleet. Barker who used to run BioGen, the UK’s biggest AD producer, has both a practitioner and investor perspective – and he says the answer is not straightforward.
“A lot of [AD] projects are not making money,” says Barker. Food waste AD makes up the lion’s share of UK biogas production.
“For me, that is quite a sick sector,” he adds. “The majority of the 300+ food waste AD projects in the UK are not full – there is not enough food waste to fill them.” At least, “collectable, suitable” feedstock. Meanwhile, gate fees have collapsed from £40-£70/tonne, to “quite often less than £10/tonne”, says Barker, “sometimes zero”.
He thinks that makes consolidation inevitable. Meanwhile, Barker believes gas prices will have to “at least” double for many AD operators to inject gas to grid rather than burn for electricity. That may require a significant environmental levy on gas, or other incentives.
“When I see headlines around ‘enough biogas for one million homes’, that’s great,” says Barker. “But it’s a rocky market. It started as a cottage industry and has not yet professionalised. There will be casualties along the way.”
From an investor’s perspective, Barker suggests “the battle for renewable heat and energy will be won at micro scale”. That is, “corporate rooftops, behind the meter commercial batteries”, and other pools of distributed assets. In commercial terms, he says the winners of that battle will be “fund managers and players that can aggregate loads of distributed energy solutions, implement effectively, and then find innovative financing approaches to push them into the big financial markets”.
Bean Beanland, chairman of the Ground Source Heat Pump Association, thinks heat pumps can be part of the solution. But the rate of installs to date is nowhere near that envisaged by the Climate Change Committee’s report. Beanland says uptake has been hampered by flawed building regulations, specifically carbon factors as set out under Standard Assessment Procedure (SAP) within Part L. Under those rules, grid electricity is has been recognised at 519g/CO2/kWh. Because heat pumps use electricity, it pushes up their recognised carbon emissions, while over-rewarding other technologies, says Beanland.
Government has consulted about reducing that figure to 233g/CO2/kWh, and the Greater London Authority is moving to implement the factor for new planning applications from 1 January. Beanland believes commercial projects will then favour heat pumps over other technologies.
“The fact that heat pump sector has survived in the UK is a miracle, but it’s the light at the end of a long tunnel,” he says, “and the supply chain is gearing up.”
This article appears in The Energyst’s June/July print issue. If you have some responsibility for energy procurement, management or sustainability for your organisation, you qualify for a free subscription.