Key issues at stake as EU electricity market reform nears finishing line

A quick side-by-side of the positions in Parliament and Council

Reform of the European electricity market design should enter the final stages ahead of next year’s elections. Will the racers be able to cross the finish line in time? This largely depends on how far removed the positions of team Parliament, Council, and Commission are from each other.

Although political motivations are, as usual, a big factor in the fate of the file, we will not speculate about them here.

The triple whammy of scarce Russian fossil pipeline gas, low hydropower reservoirs in a summer drought, and defect-crippled French nuclear plants pushed energy prices in 2022 to uncharted territory, causing many to call for rethinking the design of European energy markets.

The European Commission eventually presented proposals in March 2023 to improve the electricity market’s functioning. These are not revolutionary but build on the 2019 ‘clean energy package’ to better protect vulnerable consumers, support non-fossil flexible resources and stabilise prices over the long term.

The clock is ticking. Ideally, negotiations between the three institutions start in September, allowing them to finish before the end of 2023. Some parliamentarians are trying to disrupt the next step of plenary adoption as a last-ditch effort to weaken the compromise, but it seems unlikely this will have a substantive impact.

Regardless, the Belgian presidency begins in January, and they effectively only have a few months before attention turns to the European and Belgian national elections.

Tracking the different positions

There are many minor and major differences between the Parliament and Council positions.

For starters, the Parliament made specific additions to the Commission’s stance on grid operator governance in support of demand-side flexibility and increased transparency. They mention locational price signals and propose a detailed framework to assess the need for flexibility in the Member States.

All of this should support the transition to a clean energy system. Parliament is also very expansive about energy sharing, adding lots of detail. This should enable owners of solar installations to distribute production among other consumers.

The Council doesn’t go into the same level of detail on grid governance, flexibility and energy sharing, but the differences don’t seem insurmountable. Parliament also suggests important additional consumer protection clauses, including a ban on disconnections.

The Council has reportedly settled on most of the issues in their position. They tend to be more cautious than Parliament, asking the Commission to analyse positive new elements like regional hubs and long-term transmission rights.

The Commission proposes to give transmission system operators the option to procure peak-shaving services directly in the market to limit the need for fossil-gas peaker plants — similar to a product National Grid offers in the UK. The Council would strictly limit this option to times when there is a price crisis to prevent such a product from interfering with the existing regular market and keep the power system in balance.

A much more controversial aspect of the reform is the Commission’s proposal to reinforce long-term contracts between private actors (defined as PPAs – power purchase agreements) or with a public entity (defined as CfD – contracts for difference).

The Commission proposes that if investments in clean energy need support, the go-to tools are ‘double-sided’ contracts for difference. Double-sided, because they have a floor, below which the public pays the project for the difference, but also a ceiling, above which the project owners have to pay the public entity back. This is considered the most cost-effective support mechanism, lowering financing costs and acting as a buffer against windfall profits.

The Council has not finalised its position on long-term contracts yet. Parliament, for its part, is lukewarm on double-sided contracts for difference as best practice for investment support. It also created a very broad — and therefore probably not very useful — list of how the costs and revenues involved with CfDs can be distributed among different consumer classes.

For instance, more focus would probably be advisable to support low-income households and those at risk of energy poverty. Distributing costs and revenue to businesses risks distorting intra-European competition. It may also shield industry from the price signals that should incentivise them to change their energy and production processes.

We understand that the design and the distribution of costs and revenues of CfDs is also what the Council is still debating. As usual, a lot of energy is being spent on treating nuclear energy in this file. More focus on smart CfDs and vulnerable consumers would be most aligned with the original intention of the reform proposals.

The biggest gap between the Council’s position and that of Parliament, along with the original Commission proposal, is on capacity mechanisms. The standing regulation considers these temporary patches to resolve security of supply concerns. They come with a risk of over-procurement, especially from large fossil power plants. This may lead to higher costs to consumers than necessary and risk locking in polluting fossil fuel power plants.

The Council seems intent on making capacity mechanisms permanent. They are even considering a derogation for coal and lignite plants to allow them to receive capacity subsidies beyond the current deadline of 2025. Considering the time and effort that went into the 2019 clean energy package capacity mechanism discussion, there is a real risk that re-opening this discussion under tight time constraints could derail the whole file.

The sprint to the finish

There is still room to finalise the new legislation before the 2024 elections — by refocusing the long-term contract sections, accepting safeguards to diminish the risk of peak shaving services distorting markets, and moving deliberations on capacity mechanisms to another file altogether.

The electricity market reform is meant to achieve better consumer protection, more and cheaper renewables and a financial return for people making the flexibility in their heat pump or electric vehicle available to the grid.

The finish line may seem elusive, but it’s close.

A version of this article originally appeared on Euractiv.

The RAPPORT, Europe edition, September 2023

The UK is sleepwalking into a big problem with its gas network

To decarbonise the UK, the long term use of gas for heating, including any potential for hydrogen, is limited. Getting off gas is now an obvious climate change and energy security necessity. Both the UK government and its adviser, the Climate Change Committee (CCC), have signaled the need for the gas network to be wound down.

It should be crunch time for the regulation of gas network infrastructure. With government due to make a decision on the future of the gas grid in 2026 and Ofgem now planning for the next price control period (to start in 2026), this is a critical juncture in UK energy network regulation.

But, to all appearances, it’s still business as usual for these heavily regulated parts of the UK energy system, which continue to have capital poured into them. This is exposing UK citizens to significant financial risk while bolstering gas network returns.

The system is risky for consumers

There are large financial liabilities associated with the gas grid, related to stranded assets and decommissioning costs. Yet little thought is being given to them or how they should be managed, apart for some work by Frontier Economics for the CCC seven years ago.

The UK’s gas distribution networks are privately owned and split across four companies. These are regulated by Ofgem to operate the networks and, where they are allowed, to invest in new or replacement assets. Assets in these networks are costed by Ofgem to give something called a ‘RAV’, or regulatory asset value, and networks get a financial return on this. Networks can also profit from their operations. Ofgem assumes a certain amount for running costs and if the networks do better, consumers and networks share the difference. This system hasn’t always worked in the best interests of consumers.

The current regulatory model assumes that gas network assets have long lives; assets are given a 45 year financial lifetime; ie gas network owners recoup the costs of their investments over a 45 year period.

As the customer base shrinks, costs will rise

And herein lies the first problem: If we’re going to move to low carbon heating by 2050 and, as seems to be increasingly clear, the gas network will only play a very small role at that point, there is a significant stranded asset problem. Even with ‘front-end loaded’ depreciation, we are still talking about multiple billions (perhaps £3 or £4 billion) of stranded assets in 2050. And that’s assuming all capital investment stops in 2026, which it won’t; the Iron Mains Risk Reduction Programme (the big yellow plastic pipes you see when roads are dug up) is expected to continue to 2032, so these assets won’t be paid off until 2077.

Compounding this issue is that, over time, the number of consumers attached to the network will decrease rapidly if climate targets are to be met. So gas network charges will increasingly fall on a smaller number of customers. Without mitigation, increasing transportation costs could lead to a gas disconnection network death spiral and major equity impacts, as those without the means to switch, end up trapped.

The second issue is about the decommissioning of the gas grid. For obvious safety reasons, leaving a pressurized network of pipes full of an explosive gas across the entire country would not be sensible. In the UK currently, as was the case for me, if you get rid of gas appliances and have your gas meter removed, eventually the local gas network operator will come and make the supply line safe. This can involve digging, cutting the service pipe and then capping it underground as close to the main as is possible. This comes at a cost, borne by the network, unless (bizarrely) you ask them to come and do it, in which case you pay. This strange process and cost allocation is currently being considered by the government but highlights the need to think about what happens to the gas grid in a much more co-ordinated way.

The government needs a plan to manage the risks

If all 23 million connected homes do eventually remove their gas meter, there is a big question about how such a programme should be funded and what needs to happen in practice. This is a big unknown but, as cost estimates suggest around £8 billion, clearly efforts should be made to understand the practical and financial implications. In any case, decommissioning is an uncosted liability, the costs of which will sit with UK energy consumers.

In a briefing, just published, I consider the options for government and the regulator to attempt to manage these risks. Each has upsides and downsides.

Under option 1, the government could maintain the current regulatory model, and Ofgem could shorten the depreciation timescales to reflect the net zero target, and also collect a levy to fund decommissioning. This would mean higher gas bills and probably very significant equity impacts.

Under option 2, Ofgem could regulate gas network companies to become clean heat providers, mandating a shift towards becoming heat network owners and operators. This would make use of existing skills and relationships but comes with risks around how to regulate such a complex transition, particularly when network companies have been unwilling to shift their business models and have lobbied heavily for continued gas use.

Under option 3, the government takes a much more active approach and, as Denmark has done, renationalises the networks, with the express goal of running them down. Such an approach would enable a more co-ordinated and planned exit from gas, but it would transfer all stranded asset risks and decommissioning costs to the government. Equity impacts could potentially be more actively managed.

All of these options require a significant change from business as usual and there is no obvious frontrunner. But business as usual does not seem able to run-down and decommission regulated infrastructure rapidly in response to major external pressures.

Alongside broader reforms needed for the heating sector, I recommend four government actions, none of which should be particularly controversial, considering what’s at play, and all of which reduce risks for consumers. These are: to improve understanding of what’s needed and the costs; for the Department for Energy Security and Net Zero, Ofgem and others to work together on a plan to allocate the high costs and risks associated with stranded gas assets and decommissioning; to consider whether the Iron Mains Risk Reduction Programme is value for money and intervene if not; and, finally, to ensure heating policy and planning across the country is properly co-ordinated with gas grid decommissioning.

This is a problem laden with consumer risk and significant equity implications. The sooner something is done, the more those risks and costs can be limited and the faster climate action will be.

The original version of this article appeared in Inside Track, the Green Alliance blog. 

Decompression: Policy and regulatory options to manage the gas grid in a decarbonising UK

For countries with significant proportions of gas in their heating mixes that are looking to decarbonise and reduce exposure to gas imports, there is a major question around how to deal with existing gas distribution infrastructure in an equitable way which supports consumers. Yet this question has received only limited policy focus.

This briefing considers this problem for the United Kingdom, a country which has a well-developed gas distribution network with high coverage (85% of homes) which is both privatized, fully unbundled and split into regions — and which is looking to remove direct fossil fuel use in heating by 2050 at the latest.

The UK energy regulator, Ofgem, is imminently due to embark on a price control process to regulate the gas networks from 2026 onwards and the UK government is also expected to make a decision on the potential of a role for hydrogen in heating in 2026. We hope this briefing can support policy makers and regulators working on these processes.

If decarbonisation of heating by 2050 is successful, there is a high likelihood of stranded UK gas network assets. There will also be some costs associated with the physical disconnection of buildings and decommissioning of the gas grid. Ultimately, consumers bear the responsibility for and risks of these issues. The briefing proposes three options for the British government to manage better these issues on behalf of consumers:

1. Business-as-usual wind-down with accelerated depreciation and the potential for a decommissioning fund.
2. Evolutionary regulation to encourage gas networks into clean heating.
3. Nationalisation with planned wind-down.

In addition to the above, we would encourage greater consideration of the issues of decommissioning, continued capital investment and the role for local area energy planning in gas network decision making. While regulation, governance and ownership vary between countries, many of the technical and regulatory challenges in countries with major gas distribution infrastructure will be similar to the UK.

Implications of the Fit for 55 package on Member States’ energy saving obligations

The Council of the European Union voted on 25 July 2023 to adopt the final text of the recast of the Energy Efficiency Directive. This was the last step in the decision-making process and is the right time to consider the implications of the latest changes in the EU legislation.

What will EU Member States need to do to meet their new energy savings obligations under the Energy Efficiency Directive (EED)?

1. More ambitious energy efficiency policies.
2. Target action amongst households in energy poverty.
3. Stop supporting fossil fuel combustion technologies like gas boilers.

And how will the Fit for 55 package affect Member State implementation?

1. Most new legislation complements the EED; energy efficiency helps to meet higher climate change and renewable energy targets, and lowers the price of Emissions Trading Scheme (ETS) allowances.
2. More ambitious eco design and new vehicle CO2 standards reduce some of the additional energy savings available to national policy.
3. Some new legislation has both effects. The ETS increases energy prices, simultaneously supporting previously uneconomic energy efficiency actions and driving autonomous energy efficiency improvements amongst the most cost-effective actions.

This report, part of the ENSMOV Plus project, gives a bird’s eye view of all the changes that affect the implementation of the EED energy savings obligation. More to come on this topic from once the EPBD is negotiated.

Solar and wind only cannibalise prices if you let them: A Power System Blueprint Deep Dive

A recurring theme in energy market discussions is the fear that increasing shares of solar and wind with negligible running costs will lead to plummeting electricity prices — so-called price cannibalisation — making further investments in renewables uneconomic.

This has fuelled concerns that investment in renewables — having at last reached cost competitiveness — may yet stall and fail to deliver the required total decarbonisation of the power sector. Merchant investment might be unfeasible. Ever-growing subsidies might be required, and perhaps even these won’t suffice to decarbonise completely. We find this to be entirely avoidable.

In this deep dive — part of our Power System Blueprint website — we look at the options policymakers have in avoiding price cannibalisation and make the case for how to deploy renewables in a cannibalisation-free environment. We also assess the extent to which options to counter unhelpful price cannibalisation are currently deployed in the current European market design and regulatory framework. Since it comes out as a mixed bag, we identify needed improvements to build on the strengths of European policy framework.

How to reap the benefits of district heating? Make it local

The city of Groningen in the Netherlands has long been home to Europe’s largest fossil gas field. As fossil fuel production winds down, city authorities are looking for alternative residential and commercial heat sources. One of the solutions they found is a district heating system using locally available waste and renewable heat.

Clean, efficient and smart district heating, like the system being built in Groningen, can play an important role in decarbonising our buildings, using the huge potential of excess, ambient and renewable heat and providing crucial energy storage and flexibility.

But, matching this supply of clean heat with demand requires a coordinated policy approach and substantial infrastructure investments. The decarbonisation of existing and the development of new district heating networks will need to be aligned with making buildings ready for clean heat.

In countries with extensive fossil gas use, there is the added challenge of simultaneously phasing out gas grids. Moreover, end users will need to have confidence that district heating will be a good choice financially, environmentally, and in regard to service provision.

This is not easy. But, if lawmakers, regulators and industry can get three things right—heat planning, societal trust and regulatory frameworks—we stand a good chance.

Local heat planning

Heat, especially the low-temperature heat that most clean sources provide, needs to be used close to where it is produced to be energy-efficient and prevent high infrastructure costs. Similar to the electricity sector, heat production will be increasingly decentralised, as we switch to clean heat.

Local heat planning is a crucial instrument in matching local demand and supply of heat. This involves mapping locally available clean heat sources and heat demand, assessing area building stock and identifying solutions with the lowest societal cost for each region.

Municipal authorities are well placed to lead this process and bring together the key actors involved such as district heating and building owners, operators and users and potential suppliers of heat. Yet very few European countries require their local governments to engage in strategic heat planning.

The Nordic countries have a long history of heat planning. More recently Germany, the Netherlands and Scotland have introduced obligations for municipalities to do so.

The revised European Union (EU) Energy Efficiency Directive, however, will make heat planning mandatory across the EU for all municipalities with over 45,000 inhabitants. Although this obligation is a great start, it should be expanded to include smaller municipalities and will require careful implementation and monitoring.

Regulatory update

Municipalities cannot do this alone. They will need a supportive regulatory framework.

Firstly, national governments could empower local jurisdictions with the authority to decide which heating solution should be deployed for each area (known as zoning) and set standardised methodologies for decision-making, for instance on how to weigh societal costs and benefits of different solutions, and how to prioritise when each area is switched to clean heat.

Secondly, regulation should find a balance between enabling economically viable business models for district heating while protecting end users. District heating systems are often vertically integrated, with one entity operating both the distribution network and delivering heat to end users.

Moreover, networks are natural monopolies. Once consumers are connected, it is costly for them to switch, and it is not attractive for competitors to set up a rival network. This means relying on competition between providers to drive down prices does not work well in the heat sector.

There are different ways to address this issue, with some countries limiting district heating profits, and others regulating heat and connection prices or ownership models. The challenge is finding a model that ensures district heating can provide affordable heat while ensuring public and/or private investment in the construction of new infrastructure.

Finally, it is key to provide long-term certainty and the assurance that enough end users will connect to the networks. As upfront investments are high and payback times long, a critical mass of heat demand is necessary for networks to become economically viable.

Societal trust

It is important that lawmakers and industry also work on building trust among potential end users. This will be key in areas where district heating is currently underutilised, such as northwestern and southern Europe, because people are usually wary of “new” solutions, even more so when it comes to a significant investment decision such as changing their heating system.

Although, according to a recent EU-wide survey, public perception of district heating varies between countries, people saw a risk of becoming dependent on a single energy supplier when joining a district heating system. Moreover, in several countries, there was an overall negative perception of district heating.

In Denmark and Sweden, countries with the most positive public view of district heating, transparency and provision of information to consumers have shown to be key elements in bolstering end-user trust. It facilitates monitoring of the sector, leading to increased accountability on pricing and performance—a safeguard that regulatory frameworks can foster.

Act quickly

Clean, efficient and smart district heating has huge potential, but governments need to act quickly. Consumers rightfully expect clear direction and clarity on how to heat their homes in the future.

If action is not taken soon, municipalities and consumers will not be in a position to make informed decisions about their clean heat solutions. Heat pump markets are booming, with prices of installation dropping and newer, smaller and more efficient models further increasing their attractiveness. Yet in many, especially urban, areas, district heating will be the most economical choice.

Heating with existing fossil boilers will become increasingly expensive as the expanded EU Emissions Trading System goes into effect in 2027. This date might seem far away but is just around the corner considering the long planning timelines for energy infrastructure.

As the date nears, people will vote with their wallets and switch to individual solutions such as heat pumps in areas that could potentially be served by a district heating network, at lower overall societal cost.

To make the most out of the benefits district heating has to offer, we need to accelerate the development policy and regulations for the deployment of clean district heating.

The original version of this article was published here in Foresight. This is the third part in a district heating series written by Sem Oxenaar. The first and second parts are also available in Foresight.

Business as usual? Heating and cooling in the EU’s updated Renewable Energy Directive

On 28 June, a committee made up of members of European Parliament finally signed off on a new EU Renewable Energy Directive (RED III), the landmark law that aims to speed up the deployment of renewable energy across the EU. This paves the way for a final plenary vote in September and final rubber stamping from Member States after that. Once the Parliament and Council formally adopt the deal, it will replace 2018’s RED II.

The provisional political agreement reached back in March garnered plenty of media attention – in part because of last-minute political hold-ups to its formal signing off – but also for its increase to the headline target: the EU has now set itself on a binding path to double its share of renewables in final energy consumption by 2030, from 22% in 2020 to 42.5%. This is a large increase in ambition from the previous target of 32%. To achieve it, the share of renewables in heating and cooling, around half of the EU’s final energy consumption, should also reach around 43% by 2030.

However, despite overcoming weeks of political roadblocks to win over the Parliament’s Committee on Industry, Research and Energy on 28 June, the RED III agreement contains important, unresolved issues that hamper its effectiveness for renewable heating and cooling. Member States can fill these gaps with more ambitious efforts, but they must move quickly.

EU heating and cooling: RED struggles to ramp up ambition

RED II aimed to address heating and cooling by setting an indicative sub-target for Member States to gradually increase the use of renewables for purposes such as space heating and cooling, industrial process heat and more. The updated RED III is set to make this sub-target binding. Once it becomes law, each Member State must achieve an increase in its share of renewable heating and cooling: an annual 0.8 percentage point increase from 2021 to 2025 and 1.1 percentage points annually from 2026 to 2030. For example, if a country’s share is 20% in 2023, then it must be 20.8% in 2024.

Unfortunately, RED III’s binding targets do little more than follow this existing, business-as-usual path.

This target falls short of putting Europe on a decarbonisation pathway for heating in line with the bloc’s climate targets, however. RAP’s 2022 publication Metrics Matter explored the math behind the previous sub-target in detail. We found that the share of renewables in heating and cooling has been rising at around 0.6 percentage points per year over the previous decade. With renewables currently contributing 23% to heating and cooling, it puts the EU on track to only reach about 31% by 2030 under the current trajectory.

Unfortunately, RED III’s binding targets do little more than follow this existing, business-as-usual path, as shown in the figure below. Our calculations show that if the EU achieves the bare minimum percentage-point increases outlined in the RED III, it will still only reach a renewable share of 32% in heating and cooling by 2030, just above the status quo trajectory of 31%. In other words, the EU has set itself a target that it can achieve while continuing with business as usual.

Although the picture may look different when broken down by Member State, as the binding targets apply to each country individually, RAP calculations show that an increase of at least 2.0 percentage points annually – starting in 2020 – would be necessary to achieve a level high enough to reach the RED III headline target.

Not all renewable energy technologies are created equal

Another issue with RED III is which renewable energy technologies will be used. Here, a major sticking point is biomass. By and large, over the past decade, the biggest increases of renewables in heating have been observed in countries where biomass constitutes a significant share of heat production, especially in district heating. Not all Member States can follow suit, nor should they, as the potential for biomass use is limited and can be accompanied by sustainability issues. That means a new approach is needed, and electrification of heat – for both individual heating systems and district heating – is widely expected to play a central role.

Yet heating technologies using electricity have previously been disadvantaged in RED II for two main reasons. One, any electricity used for heating (and cooling) did not count towards the heat target in RED II. It simply was not considered in the sector; all renewable electricity statistically was placed in the power sector bucket. Concerning electric heat pumps, only the ambient heat harnessed by the heat pump was classified as “renewable,” whereas the electricity used to drive the process, even if renewables-based, was not. This means that, with electrification technologies unable to fully count towards meeting the EU’s heating target, there was less incentive to deploy them, and more incentive to install alternatives, including combustion technologies for biomass.

In fact, renewable combustion technologies are heavily favoured due to a second key reason: the way the units of renewable heating are counted. The methodology to determine the contribution of each renewable energy technology accounts for the energy harnessed to make the heat (for example, by burning biomass), not the useful heat itself. In other words, it does not reward efficiency.

Member States can ensure that the right incentives are in place to encourage efficient heating systems over inefficient combustion.

Consider an application where you need 100 units of heat. A 50% efficient furnace would need 200 units of biomass to produce this heat. Yet, those 200 units of biomass are counted as “renewable energy consumption.” While in the case of an electric heat pump with an efficiency of 300% (the coefficient of performance is 3), the 100 units of heat could be produced using only 33 units of electricity and 67 units of ambient heat. Previously, RED II only counted the 67 units of ambient heat towards the renewable energy target; the 33 units of electricity – even if it came from renewable sources – did not count. Counterproductively, this punishes heat pumps for being efficient by undervaluing their contribution to the renewable energy target.

Member States have important tools to hand

Fortunately, RED III seems to have addressed the calculation methodology issue. It now considers renewable electricity used for EU heating and cooling as contributing to the target if devices have an efficiency above 100%. This tricky wording avoids crediting inefficient electric resistance heaters with a renewable energy contribution.

What still remains unresolved, however, is the failure to fully value electrification technologies. The least-efficient devices are still credited with producing the most renewable heat. Efficient devices such as heat pumps have received a small boost under RED III, but combustion technologies retain a serious advantage and are likely to be further deployed to help meet EU Member States’ binding renewable heating and cooling targets.

Although it is now too late to adjust the RED III text, Member States can nevertheless ensure that the right incentives are in place at national level to encourage efficient heating systems over inefficient combustion. That means easing permitting, investing in skills and manufacturing, providing targeted support to low-income households and rebalancing taxes and levies from electricity onto fossil fuels.

The RAPPORT, Europe edition, June 2023

Lowering flow temperatures is key in the switch to efficient clean heat

Two important factors are advancing the shift to clean heating in Europe: First, the fossil gas crisis underscored the value of saving energy and the urgent need for affordable heat for all. Second, the race to meet climate goals has inspired many European countries to introduce policies that prioritise clean and renewable heat over fossil-fuel-based heating sources.

The European Union (EU) is still heavily reliant on fossil fuels when it comes to space heating, with three-quarters of the energy used coming from fossil sources. Reducing the flow temperatures of water in heating systems is a key method for saving energy from heating and for integrating a more diverse range of clean resources into the heating mix. As such, this relatively novel approach is a no-regrets option for building owners and occupiers. Lowering the flow temperature can improve the efficiency of heat pumps, solar thermal collectors, condensing boilers and district heating systems.

A critical consideration when lowering flow temperatures is ensuring that buildings can still be heated to the desired temperatures. Changes to two key variables can be considered to decrease flow temperatures: reducing the heat load of the building through building fabric improvements and increasing the heating capacity of the heat distribution system. Understanding this interaction is important for decisions on best-placed investments.

A new report by ifeu and the Regulatory Assistance Project explores approaches and policy measures to ensure buildings are ‘low flow temperature ready.’