Comments Off on Rebalancing energy levies is a practical way to increase the electrification of heat
Every year households in the UK install about 1.7 million gas boilers. In May, the Heating and Hotwater Industry Council reported that 2021 looks to be a record year for gas boiler sales, with year-to-date sales up 41 per cent from 2020. So far, low-carbon heating occupies a small — although growing — niche in the heating market.
One important factor supporting a booming boiler market is quite simple: Gas is cheap and electricity is expensive. Residential electricity prices per kilowatt hour are currently around five times higher than gas prices. This means that switching to a heat pump, even with an efficiency of 300 per cent, does not offer bill savings for customers on a standard tariff.
This is partly a political choice. Legacy policy costs drive part of the difference in price. Most of levy-funded energy and climate policies, which make up 23% of the total household bill, are presently paid for through electricity bills. In the UK, these legacy costs include charges for policies such as feed-in tariffs, the Energy Company Obligation, Contracts for Difference, the Renewables Obligation and the Warm Home Discount.
Most levy-funded energy and climate policies are presently paid for through electricity bills.
Electricity is also effectively covered by a carbon tax, the carbon price floor. By contrast, gas carries a mere 2% of environmental and social levies, and is not subject to a carbon price. Research by Oxford University shows that the current levy structure provides an active disincentive to adopt heat pumps, which is clearly at odds with the UK government’s goal of mass deployment by 2028.
In the past, when electricity was much more carbon intensive, such an approach could have possibly been justified. But electricity has now become cleaner than gas and is projected to emit only half of the greenhouse gases resulting from heating with fossil fuels by the mid‑2020s. A much needed rethink of levy costs could provide energy users with incentives that complement the need to fully decarbonise heating.
Other countries are introducing incentives
But how to do this? The government could take two potential approaches.
First, legacy policy costs could be moved from electricity to gas and other fossil fuel heating bills. Such an approach could act as a carbon tax proxy, reflecting the falling carbon intensity of electricity and encouraging a switch to increasingly clean power. For the average dual fuel bill, it would make very little difference if the levies recouped from gas were equal to those previously recouped from electricity. The total bill of a dual-fuel household would increase slightly, as levies from the 28 million households with electricity would be spread across 24 million households currently using gas.
Such a change, however, could also support other policy goals. Households that currently use electricity for heating are twice as likely to experience fuel poverty. For them, energy bills would come down, helping to meet statutory targets to reduce fuel poverty.
The Netherlands, which has one of the highest penetrations of fossil-gas heating in the world, has recently decided to take a similar approach. The Dutch government will increase taxation of fossil gas by up to 43 per cent by 2026 (compared to 2019 levels) and will lower taxation on electricity.
Second, a direct but modest carbon tax on fossil heating fuels could pay for the legacy policy costs and reduce the levies on electricity. This is an approach currently being discussed in Germany, where a carbon price of €25 per tonne of CO2 in 2021 rises to €55-€65 in 2026, after which an emissions trading system for transport and heating fuels will operate. The German government expects the new system to generate revenues of €40 billion from 2021 to 2024. The revenues will be used to lower the renewables surcharge on electricity and for financial support programmes, making the use of electricity more attractive. Sweden has also used this approach as part of the country’s heat pump deployment strategy over many decades.
A pragmatic approach to switching fuel is needed
Both of these approaches require policy reform and may face significant political barriers. A more targeted and potentially more pragmatic method would be to exempt the electricity used for running heat pumps from levies. Under such a scheme, households installing a heat pump would receive a discount on the amount of electricity used for heating. This option is attractive because it would not require major reform of either levies or taxes, but still offers an incentive to households to switch fuels.
Pragmatic levy reform can eventually tilt the market in favour of clean heating solutions and make high installation rates of gas boilers a thing of the past.
To meet the government’s target of 600,000 new heat pumps per year, about 2% of additional residential electricity demand would have to be exempted. Levies on a per-unit basis would remain constant for existing electricity consumption. Denmark has recently done just that: Since January 2021, electricity used for space heating is subject to the minimum allowable tax rate of just 0.8 øre (0.01 pence) per kilowatt hour of electricity. The Danish government is hoping that this incentive will help them roll out heat pumps faster and at a larger scale.
Levy reform, in one form or another, will be necessary to present a clear business case to households and the market. Without it, subsidies and regulation will constantly face the uphill battle of fossil-fuel heating’s lower running costs, a situation that is politically difficult and economically unsustainable. Pragmatic levy reform can eventually tilt the market in favour of clean heating solutions and make high installation rates of gas boilers a thing of the past.
Comments Off on How to get from a cottage industry to a million heat pumps a year
The UK has made incredible strides in decarbonising its power system beyond what many thought was possible. Carbon emissions were at a record low over the recent Easter weekend. While heat pumps have been seen as a strategically important sustainable heat technology for years, the rapid progress in the power sector offers an urgent opportunity to decarbonise heating whilst supporting the integration of renewables.
The government highlighted the importance of electrifying heat in its Energy White Paper, as did the prime minister in his ten point plan, in which he committed to installing 600,000 heat pumps a year by 2028.
Fewer than 30,000 heat pumps were installed last year
It is an ambitious target: the UK needs to increase the number of heat pumps installed in homes each year at least 25-fold by 2028 to meet it. And a nearly 40-fold increase is required to meet the Committee on Climate Change’s trajectory of 900,000 heat pumps by 2028. To put this in perspective, approximately 1.6 million gas boilers were installed in UK homes last year, compared to fewer than 30,000 heat pumps. This demonstrates the scale of the challenge but also the opportunity for reducing emissions.
With the UK hosting crucial climate negotiations this year, there is a lot riding on the prime minister’s heat pump target being credible. The government needs to take bold, co-ordinated decisions this year to stand a realistic chance of achieving the mass market for heat pumps that will be needed by the end of this decade to stay on track. While the scale and pace of transformation set out can appear daunting, it is a necessary and achievable investment in the UK’s future.
To put this in perspective, approximately 1.6 million gas boilers were installed in UK homes last year, compared to fewer than 30,000 heat pumps.
The decade old Renewable Heat Incentive – a quarterly payment linked to the production of clean heat – has been fraught with challenges and has fallen far short of expectations. It was supposed to have supported 491,000 heat pump installations by this April, but had accredited just 63,000 by late 2020, 87 per cent short of the target.
An urgent step change is needed, both in the rate of installations and the policies that support them. The government’s soon to be published strategy for heat and buildings presents a once in a decade opportunity to trigger exponential change. Our report in March set out how to drive large scale deployment of heat pumps, drawing on successful approaches used to accelerate the adoption of electric vehicles.
Four pillars of a new heat pump strategy
To achieve this upsurge, households need guidance, financial support, incentives and standards to meet. Success requires the government to be strongly joined up, between ministries, and between Whitehall and local councils, and to work in concert with industry, banks and the supply chain. Adapting approaches used for electric vehicles to clean heating, we have made four recommendations in four areas, and each needs a clear decision from government this year.
Convening a Heat Pump Council this year – similar to the Automotive Council that has been pivotal to ending petrol and diesel car sales by 2030 – would help the government to manage the step change and ensure every household opting for a heat pump has a good experience.
2. Financial support
Starting this year, to build the market, the government should begin scaling up the financial support offered to households to install heat pumps, mirroring the grants offered for electric cars. Initially, the plan could offer £6,000 for better off homeowners and £10,000 for low income households. Support should then peak at up to £3 billion in 2030, with the level of grant support for better off households falling over time as the market scales up and costs of heat pumps come down.
Adjusting prices for electricity and gas to reflect their true relative costs can provide incentives while protecting fuel poor households. This can be done by pricing the cost of carbon emissions into gas consumption, rebalancing how the costs of clean energy investments are recouped from energy bills, and pricing heat pumps into property values by linking stamp duty to home energy and carbon performance. All of these measures are urgent, requiring introduction by the end of this parliament. They would enhance the economics of owning and running a heat pump – accelerating the rate at which grant support can be phased out – and sustain the market for the long term.
The government needs to clearly signal this year that it will phase out fossil fuelled home heating systems, with regulation allowing for a market led approach similar to the phase out of petrol and diesel cars in 2030. Ideally, this plan would eliminate oil heating systems from the late 2020s and gas heating systems from the early 2030s, sparking long term commercial investment in the skills and innovations needed to deliver the mass market for heat pumps.
Taken together, these decisions will lead the transformation from a cottage industry to a mass market for heat pumps. They will help drive down costs, support good quality jobs in the industry across the country, ensure green growth, and reduce UK reliance on energy imports while boosting domestic innovation and manufacturing. All these positive economic effects means there is no time to wait in getting the UK’s homes on track to net zero.
Comments Off on Net zero is nowhere in sight for UK clean heat policy
For months, we have been waiting for the UK government’s proposal for the future of clean heat policy. After committing to a net-zero carbon target for 2050, the need to take aggressive action now to drive down emissions from heating became clear. Surely the government would announce something bold or step up support for climate-friendly heating technologies? We could not have been more disappointed.
The proposals finally came out last week. Under the current plans, 12,500 homes a year would receive support for switching to low-carbon heating solutions, largely air source heat pumps, in the financial years 2022-2023 and 2023-2024. Let’s put that into perspective: Last year, 1.7 million gas boilers were installed in British homes, up 1.8 per cent from 2018. At that rate, for every one new low-carbon heating system, more than a 120 gas boilers will be installed.
Less than two percent of UK homes have low-carbon heating
At the moment, fewer than 500,000 UK homes have some form of low-carbon heating, when not counting closed stoves or wood used on open fires. This is not even two percent. By 2050, the new policy would only support low-carbon heat in an additional 1.5 percent of the existing housing stock. At that rate, it would take more than 1,500 years to install the 19 million heat pumps that the Committee on Climate Change says we will need to meet the net-zero emission goals.
This is particularly disappointing as there is an immediate opportunity to reduce emissions from heating in the UK.
Clearly, this is incompatible with the government’s net-zero target for 2050. However, the consultation document claims that “these proposals strike the right balance between making an appropriate contribution towards our legally-binding carbon budgets, supporting the supply chain for low carbon heating […], strengthening value for money, and protecting the interests of consumers.”
This is particularly disappointing as there is an immediate opportunity to reduce emissions from heating: The UK is a leading country when it comes to the decarbonisation of electricity in Europe and has made great strides toward zero-carbon electricity. On heating, the UK also stands out, but unfortunately as being amongst the laggards in Europe. Only Ireland and the Netherlands are performing worse. This is a tragedy because the opportunities for reducing carbon emissions from heating have never been greater: Electricity is now so clean that electrification of buildings makes a lot more sense than ten years ago. Compare the UK to the Netherlands, which faces a similar challenge, with almost 90 percent of their eight million homes heated by gas. The Dutch government announced in 2018 that 200,000 homes a year will be transitioned off natural gas to alternative sources of energy by 2022.
Analysis by Imperial College shows that heat pumps can deliver a unit of heat, with carbon emissions being more than two-thirds lower than gas heating. And this figure will only increase with the additional electricity emission reductions the government predicts. At RAP, we recently published our thinking on the principles and policies for accelerating beneficial electrification of heating and found significant immediate potential.
There is some good news in the proposals too. Previously, payments for clean heat under the Renewable Heat Incentive were made over several years, following the installation of a low-carbon heating system. For those with limited capital, the upfront cost barrier often stood in the way of converting from fossil to clean. Under the new scheme, payments will be upfront in the form of a grant. This simplifies the system and addresses the cost barrier.
The Clean Heat Grant will be paid for through exchequer funding, as opposed to a levy on electricity bills. This is also a welcome step, however consumers still pay a lot more of the costs of the energy transition through their electricity bills than their heating bills, with gas carrying a much lower cost burden than electricity.
The excellent work by Jake Barnes of Oxford University’s Environmental Change Institute demonstrates that this unequal sharing of costs between electricity and gas makes heat pumps less financially attractive because of the higher operating costs. Unless consumers can see a financial benefit in the form of lower operating costs, it is unlikely that a modest upfront grant will provide sufficient incentive. Experience from countries such as Sweden and Finland shows that once fossil-fuel heating is no longer the cheapest option, the market changes rapidly. The UK should take note.
Regulation also needs to play a central role in accelerating change. There are simply not enough public subsidies to pull the market in the right direction and away from fossil-fuel heating. Other countries have led the way: Norway has banned oil-fired heating systems in all buildings, new and existing, from 2020. Oil boilers will need to be replaced everywhere. Poland has introduced tight emissions standards in most of its regions, covering all existing buildings. A softer approach involves only prohibiting the replacement of heating systems with specific technologies. The German government has announced a ban on the installation of oil heating systems by 2026, if a low-carbon alternative is technically feasible.
Clean heat has to be combined with greater energy efficiency
Finally, clean heat will only be achievable at scale if combined with aggressive energy efficiency improvements across the entire building stock. Since 2012, energy efficiency installation rates have collapsed and, despite government commitments, levels of efficiency are far below pre-2013 rates. RAP has looked at the potential for energy efficiency, in previous work with the UK Energy Research Centre, and demonstrated there is still substantial potential for energy savings. The government has yet to publish its proposals for upscaling energy efficiency, but what is clear already is that, similar to clean heat, business as usual just won’t cut it.
The opportunity for the UK to decarbonise heating is great. Doing so would cut carbon, improve air quality and people’s comfort and health, and help us to achieve the legal net-zero goals. This will require bold leadership, and policymakers are tasked with setting out how to make it happen. It is laudable that the clean heat consultation document acknowledges “the need for a consistent, long-term policy framework” and that it “is clear that regulations will be needed to underpin the transformation of our building stock.” The Heat and Buildings Strategy, due later this year, will lay out immediate actions for reducing emissions from buildings. This needs to go far beyond the current proposals for clean heat.
Comments Off on UK capacity market déjà vu: A solution that’s still in search of a problem
In November 2018, the EU General Court ruled in favour of a legal challenge mounted by Tempus Energy to the Directorate General for Competition’s (DG COMP) approval of the capacity market in Great Britain. In its challenge, Tempus successfully argued that, due to serious flaws in the design of the capacity market, DG COMP should have had doubts over its compatibility with State Aid rules and carried out a full “phase 2” investigation before approving the scheme.
Following the General Court’s ruling, DG Comp initiated an in-depth investigation in February of this year. Although such investigations normally last up to 12 to 18 months, some commentators believe that a decision re-endorsing the compatibility of the capacity market with State Aid rules is imminent.
In carrying out its comprehensive assessment, DG COMP not only needs to consider the validity of the original decision but also the need, if any, for a capacity market going forward. Unfortunately, the evidence presented to the Commission by the UK government supporting the continuing need for a capacity market is not in the public domain, the government having prevented National Grid from releasing the evidence.
However, the data generally available suggests that Great Britain has a considerable and increasing surplus of capacity, with no immediate need for new investment. Furthermore, there is no evidence to suggest that a capacity market is necessary to bring forward new investment, should that need eventually arise.
In fact, as illustrated in the chart below, National Grid’s Winter Reviews show that the de-rated plant margin, or the level of capacity above peak demand, has consistently exceeded the reliability standard in Great Britain over recent years. It has reduced peak demand and increased interconnector capacity, more than offsetting the continuing and welcome decommissioning of coal plant.
The impact of these trends is exacerbated by National Grid’s persistent over-estimation of peak demand, a fact highlighted by the independent Panel of Technical Experts, and use of other cautious assumptions. The result is a predicted plant margin of around 13% for this coming winter. In fact, if the de-rated plant margin is calculated as the excess of generation capacity over demand seen at the transmission level rather than total demand, the predicted margin for this coming winter is around 16%. This implicit inclusion of the contribution made by distributed generation suggests a margin that is more than four times that necessary to meet the reliability standard.
Excessive plant margins are a waste of consumers’ money. They place an additional burden on customers through inflated electricity bills, without sufficient value to justify the associated costs.
Let’s assume, for example, a combined cycle gas turbine plant has a new entry cost of 49 pounds sterling per kilowatt to recover its capital investment and fixed costs. The current excess capacity in Great Britain’s electricity market adds approximately 276 million pounds to consumers’ bills every single year.
In addition, paying outside of the energy market for an unnecessary capacity mechanism delivers excessive plant margins. This depresses the energy market signals necessary to develop the flexible resources such as demand response and storage that are vital to the successful transition to a low-carbon electricity system.
Ofgem’s 2019 State of the Market report confirms that imbalance price volatility continues to fall while there has only been one significant spike in prices during the last three years. Yet Ofgem’s report shows that balancing costs in Great Britain are still increasing year on year mainly due to transmission constraints and the growth in intermittent renewable generation outpacing transmission development. New sources of flexibility to manage both the increasing variability of a changing plant mix and the increase in transmission constraints are urgently required.
In recent years, Great Britain has introduced balancing market reforms that should provide the signals necessary to develop those new flexible sources. These reforms are now built into EU legislation via the recast Electricity Regulation as the means of securing electricity supplies without the need for direct capacity support. However, despite these initiatives, the combination of a capacity market and excessive plant capacity in Great Britain is preventing those reforms from doing the job they were intended to do.
We don’t know yet whether DG COMP will once again conclude that the GB capacity market complies with State Aid rules and that, despite ample evidence to the contrary, its continued operation is justified. However, the omens are not good, as the Commission’s opening opinion suggested that it is minded to accept the UK government’s case that a need for additional capacity support still exists.
This would be particularly unfortunate for the reasons expounded above. It would also suggest that the Commission does not intend to implement or enforce the requirement that the energy market reforms set out in the recast Electricity Regulation be relied upon in the first instance to ensure supply reliability without the need for market-distorting capacity mechanisms.
A version of this article originally appeared on Euractiv.
Comments Off on Stuck in the past: Energy performance certificates hold back heat decarbonisation
In 2014, we bought an old Victorian house in Oxford, UK, well aware it needed major renovation work. Our energy performance certificate (EPC), which shows the energy performance of a building, was a poor grade “E” on a scale of A to G, with A being the highest performing category. We have since carried out a major refurbishment programme, installing underfloor insulation, triple and double glazing, underfloor heating, internal solid wall insulation and an air source heat pump. We demolished the old kitchen at the back of the house and replaced it with a modern extension built according to the latest building codes. After all of these improvements, we expected a significant improvement in our EPC rating, yet we are still received an “E” grade.
It is possible the assessor made a mistake, up to 62% of EPCs contain errors of some kind, but the low grade is most likely due to the heat pump we installed. Official UK government policy is to roll out heat pumps across the housing stock. The Climate Change Committee, a government advisory body, believes 2.5 million heat pumps need to be installed by 2030 to meet climate targets. In contradiction to this goal, the EPC system penalises people for investing in heat pumps by regularly issuing poor ratings for their homes. Installers have also complained that EPCs do not recommend heat pumps as an energy performance improvement measure.
If we are to take heat decarbonisation seriously, all policies need to be aligned and based on reality.
There are at least three reasons why the installation of heat pumps does not result in improved EPC ratings and why it is usually not recommended by the EPC.
First, the main EPC rating is based on the cost of heating a property, and electricity prices are a lot higher than natural gas prices — approximately threefold in the domestic sector. This is partially a result of a disproportionately high burden on electricity for the costs of environmental programmes, which could drive homeowners to rely on less clean natural gas.
The second factor contributing to the low EPC scores is the estimated energy demand. Especially for larger properties such as ours, the estimated energy demand cited on the EPC is often higher than the actual measured energy demand. This is partly a result of assuming a poorer operational efficiency of heat pumps than field trials suggest.
Finally, the environmental impact score of the EPC is based on the carbon emissions of the fuels used in the building (note that this does not affect the main EPC rating though). The current algorithm, as determined in the so-called Standard Assessment Procedure, uses the figure of 0.519 kilogram (kg) of carbon dioxide (CO2) per kilowatt hour (kWh) for electricity. This compares to a carbon factor of 0.216 kg CO2/kWh for natural gas.
There is good news. The next version of the Standard Assessment Procedure will use a lower carbon emissions factor for electricity of 0.233 kg CO2 per kWh, compared to 0.210 kg CO2 per kWh for gas. This will most likely result in heat pumps leading to significant EPC improvements in the environmental impact part of the EPC.
The new rules will come into force when the building codes are updated, which will probably happen in 2020. The update is an important step towards rewarding properties with heat pumps with an improved EPC. But given the rapid decarbonisation of the power system, it is likely that in five years the Standard Assessment Procedure will already be out of date.
To avoid this happening and better take into account the rapid decarbonisation of the grid, I would recommend using a dynamic carbon factor that can be updated as the power system gets cleaner. This would more accurately reflect the real carbon impacts and value of low-carbon heating systems such as heat pumps.
Experiences from the UK provide useful lessons for other countries. If we are to take heat decarbonisation seriously, all policies need to be aligned and based on reality. EPCs should stop being stuck in the past and start truly reflecting the value of heat decarbonisation.
Comments Off on The UK’s August 9 blackout: Why did it happen and what can we learn?
The power outages that occurred in the United Kingdom on August 9 demonstrated our increasing dependence on secure electricity supplies and the extremely disruptive consequences when those supplies fail. The reasons for the extent of the disruption to transport and other critical infrastructure are beyond the scope of this blog. However, an examination of the events leading up to the supply failure provides useful insights into how decarbonisation is changing our electricity system, with conventional generation increasingly being replaced by wind and solar and the gradual transfer of generation capacity from the transmission to the distribution systems. As the nature of the electricity system changes, the way it is operated and regulated will also need to change.
National Grid’s final report on the events of August 9 shows that the disruption resulted from the cumulative loss of most of the Hornsea wind farm (737 MW), the total loss of the Little Barford combined cycle gas turbine power station (641 MW) and the loss of around 500 MW of small distribution-connected generation, presumably mostly solar, wind and some reciprocating plant. In total, some 1,880 MW of output was lost, far greater than the 1,000 MW loss National Grid was required to cover at the time, resulting in the automatic disconnection of around 3% of system demand. All three generation losses were associated with lightning strikes that tripped a high-voltage transmission line. There were no capacity shortages at the time.
What role did renewables play?
The events of August 9 were truly exceptional and there should be no knee-jerk reaction.
August 9 was windy. In fact, wind met 50% of demand — a record for the UK — earlier in the day. High levels of wind or solar output cause inertia levels to fall, with system frequency becoming more sensitive to sudden changes in the supply-demand balance. However, National Grid had ensured adequate levels of inertia to cover the largest expected loss of infeed on the day, and therefore the relatively high level of renewable output was not the primary cause of the incident. The loss of the Little Barford gas-fired plant contributed as much to the supply failure as did the loss of Hornsea, while several other offshore wind farms electrically closer to the initial fault were unaffected. It is also worth noting that a transmission fault caused by a lightning strike (or anything else) should not have resulted in the loss of either Hornsea or Little Barford. In that regard, the coincident loss of both was truly exceptional.
The role of distribution-connected generation
While the deployment of renewables was not the primary cause of the incident, the tripping of so much distribution-connected generation, much of it renewable, clearly did contribute. Distribution-connected or “embedded” generation is equipped with “loss of mains” protection designed to operate in the event of a failure of the local grid or its disconnection from the remainder of the network. Since the local grid operated just fine on August 9, the loss of local embedded generation capacity seems to have been entirely unnecessary.
As the nature of the electricity system changes, the way it is operated and regulated will also need to change.
The risk of loss of mains protection operating unnecessarily has been known for many years and there have been several instances of embedded generation losses following transmission faults. Consequently, a programme of de-sensitising this protection was initiated in 2014 with smaller installations having until 2022 to complete the work. The relaxed timescale associated with the programme is clearly relevant and, given the events of August 9, quite remarkable. Analysis of the sequence of losses that occurred on the day suggest that, had the 500 MW of embedded generation not tripped, then what turned out to be a disruptive event impacting over 1 million customers may have been relegated to a frequency excursion that few customers would have noticed.
What lessons do we need to learn?
Generation failures are a regular occurrence, and, like buses, they sometimes annoyingly all arrive at the same time. However, the fact that a large amount of embedded generation unnecessarily tripped is clearly a concern. As we continue to decarbonise our electricity system and the plant mix changes, more and more generation capacity will be embedded. This embedded, decentralised capacity has the potential to enhance the resilience of the grid but, sadly, at the moment it is needlessly reducing resilience. It is quite remarkable, given the known risk posed by loss of mains protection and concerns raised by National Grid about that risk, that more urgent action has not been taken to resolve the issue. One of National Grid’s sensible recommendations is that the programme timescales for de-sensitising the loss of mains protection be revisited and, hopefully, Ofgem will shut that particular door before any more horses have the opportunity to bolt.
In the longer term, the whole issue of how embedded generation should be protected needs to be revisited. As suggested above, decentralised embedded generation has the potential to enhance the grid’s resilience to severe events. However, for this potential to be realised, the current underlying philosophy of shutting down all embedded generation on loss of mains until the grid is restored needs to be replaced with something more appropriate for the future.
In the longer term, the whole issue of how embedded generation should be protected needs to be revisited.
It is a concern that National Grid have only been able to “estimate” the amount of embedded generation that tripped offline based on the increase in demand that occurred during the incident. In fact, it is still not clear exactly how much embedded generation actually tripped. With embedded generation set to contribute increasingly to meeting demand, its visibility to National Grid is unacceptably low, with too little information available to adequately assess the considerable uncertainties around its operation. As recommended by the Capacity Market Panel of Technical Experts, the distribution system operators should establish a complete register of embedded generation capacity. This would allow National Grid to more accurately forecast demand and predict the response of that embedded capacity to a range of operational circumstances.
Finally, it appears from their final report that National Grid’s actions before and during the events of August 9 were in accordance with the current requirements of the Standards of Quality and Security of Supply (SQSS), and that the transmission system responded to those events in the way it was designed to do. However, replacement of conventional generation with wind and solar will mean the loss of traditional sources of system inertia. Alternative sources have and are being developed, however it seems appropriate that existing arrangements for maintaining the resilience of the system to extreme events should be revisited. The SQSS have their origins in the middle of the last century and National Grid’s recommendation that the SQSS be revisited from the perspective of resilience, is sensible. The events of August 9 were truly exceptional and there should be no knee-jerk reaction. However, the energy mix and characteristics of the electricity network are changing significantly and the SQSS need to reflect the new realities.
Comments Off on Why I replaced my new gas boiler with a heat pump
After installing a new air source heat pump in my home, I posted a photo on Twitter, delighted about the carbon emissions we will save. My celebration, however, was short-lived. The post triggered an intense discussion with many people feeling that my decision to replace my six-year-old gas condensing boiler was unjustifiable. “Ripping out a perfectly well functioning gas boiler before the end of its natural life and replacing it with a heat pump is misguided. It won’t reduce much carbon.”
Of course, I had calculated the likely energy and carbon savings prior to the installation, but this and similar arguments made me realise the importance of digging deep into carbon emission issues (and any climate change issues, for that matter). Numbers need putting to the test and results need monitoring.
Rather than replacing an old, decrepit heating system with a new one, which is the main reason for installing a new heating system, I decided to remove the perfectly functional boiler installed by the previous owner.
We were already in the middle of major building work to extend our kitchen. With builders on site and our house in a state of disruption, it made sense to think seriously about our future heating system now.
I live in the UK, where more than 26 million boilers are installed, mainly running on gas. All will need to be replaced with low-carbon heating technologies if we are to reach a net-zero carbon emissions target. Feeling a sense of urgency, I decided to decarbonise our home’s energy use now, learn from it and inspire others to follow suit. We still install 1.6 million gas boilers a year in the UK compared to just 22,000 heat pumps, which are mostly in new buildings. Progress on stopping global warming is too slow, as the recent net-zero report from the Climate Change Committee highlighted.
But does it really make sense to replace a relatively new gas boiler with a heat pump? Let’s take a look at the impact the heat pump will have on carbon emissions. My energy use is expected to go down by as much as 60%. This is because a heat pump delivers about three units of heat using one unit of energy generated from ambient heat. A gas boiler delivers about 0.9 units of heat for one unit of energy. Being conservative, I calculated the carbon emissions from my heat pump using marginal emission factors for electricity, which are more appropriate for small changes in demand.
In 2019, the marginal emissions for each kilowatt hour of electricity use are 308 grams carbon dioxide equivalent (g CO2e). This figure is projected by the UK government to decline to just 130 g CO2e by 2030, which is 36% cleaner than gas. So not only does a heat pump use significantly less energy, it also uses a fuel that is getting cleaner. As a result, I have already reduced carbon emissions in my home by 42%. Coupled with solar panels, which I plan to install next, I expect to drive even steeper carbon reductions.
But what about the embodied carbon emissions of the new heat pump? Would it not be better to wait until a heating system has reached the end of its life before replacing it? In response to my Twitter post, someone suggested to me that “knee jerk installations of heat pumps over natural gas boilers ‘to save CO2’ are not done until the useful life of the gas boiler has been met. Premature boiler changes will cause more CO2 than they will save.”
Here again, the numbers support the early retirement of gas boilers. The total embodied carbon emissions for a typical air source heat pump installed in a UK home are 1,563 kg CO2e. My heat pump avoids 1,313 kg CO2e per year. It means that after less than 1.5 years, a heat pump starts saving carbon compared to a gas boiler, even if the gas boiler is replaced before the end of its life. Hence, from a carbon perspective, it makes sense to replace a gas boiler even if it was just installed. Assuming a 20-year lifetime for the heat pump, the embodied carbon emissions per year are just 78 kg CO2e per year, or 4% of the operational carbon emissions from fuel use.
Impact of heat pump on energy consumption and carbon emissions.
With all of this said, it is important to note that installing a heat pump in isolation in existing, and often inefficient, homes is not advisable. I have made an argument elsewhere for aligning energy efficiency and heat decarbonisation to maximise carbon reduction and avoid oversized heating systems. This is why we invested in energy efficiency measures in our Victorian 1880s home alongside the heat pump. We insulated the floor throughout, installed mostly triple or double glazing and insulated the attic.
Finally, let’s not forget that this is not a new idea. We support renewable energy technologies to speed up coal plant retirement. Efficiency programs support replacing “perfectly good” light bulbs and even compact fluorescents with new LEDs. Utility demand-side management programmes across the globe have “cash for clunkers” programmes to replace old fridges that are still in working order.
I learned a lot from taking a hard look at my own energy consumption and carbon emissions. I will monitor our energy use carefully over the coming year, compare the figures I calculated with real data, and report back once I have data for a whole year using the new system. With more energy efficiency improvements to come, I hope to beat my predictions and achieve an even lower carbon home.
Comments Off on Walking the walk on capacity mechanisms
Following the decision of the General Court of the European Union in November last year to annul the capacity market in Great Britain, the European Commission has now embarked on a detailed formal investigation of the market’s design.
The Court’s decision no doubt caused the Commission some embarrassment. However, a positive outcome of the annulment would be for the Commission to confirm its belief — clearly articulated in the recast Regulation on the internal electricity market — that appropriate energy market reform should preclude the need for a capacity market.
Unfortunately, the Commission’s recently published opening opinion suggests that it is minded to pass up this opportunity and accept Great Britain’s case that a capacity market is necessary to secure energy supplies in the future.
In 2014, Great Britain introduced a capacity market following the Commission’s conclusion that the initiative was necessary to ensure future security of supply and was compatible with State Aid rules. However, all of the capacity auctions held so far have been oversubscribed, with auction clearing prices consistently lower than anticipated.
This is hardly a surprise as, in fact, Great Britain currently has a surplus of capacity. The scale of this overcapacity is evidenced by a low loss of load expectation (LoLE) — or likelihood of any amount of power shortage — in recent winters. Compared with the reliability standard of three hours, the forecast LoLE for winter 2018‑2019 hardly registered at 0.001 hours.
Although we have yet to see National Grid’s Winter Outlook Report for winter 2019‑2020, a similar situation seems likely. While the closure of around 2.5 GW of nameplate capacity (Cottam and one Fiddler’s Ferry unit) during 2019 has been announced, this is partially offset by the newly commissioned 1 GW high-voltage direct current link to Belgium and the expected commissioning of the 1 GW Eleclink interconnector with France later this year. It is still possible that further transmission-connected generation closures will be announced, however this seems unlikely as generators will have by now committed to paying transmission charges for the year 2019‑2020. Furthermore, within 24 hours of the Court’s annulment of the capacity market, forward energy prices for winter 2019-2020 saw a step change upward, a fact likely to discourage further exit (as well as demonstrating clearly the energy price distortion effects of capacity markets).
Overall, it seems likely that Great Britain will have a healthy capacity surplus going into next winter.
With no indication of any imminent capacity shortage, looking further ahead, the government is committed to the closure of the remaining 8.5 GW of coal capacity by 2025. Some of this capacity will need to be replaced and the question is — do we need to reinstate the capacity market in order to ensure new investment takes place or can the energy market be relied upon to do the job?
At this point, it is instructive to return to the Commission’s recast Regulation, particularly to Article 20. Essentially, this requires Member States to establish a market reform implementation plan, including such measures as the establishment of a reliability standard, marginal imbalance energy pricing, the introduction of administered shortage pricing for balancing energy and increasing interconnection capacity with its neighbours.
Article 20 implies that a Member State may only introduce a capacity market with the Commission’s approval, and then only as a temporary measure. Where any residual concerns about capacity remain, Member States may consider implementing a strategic reserve, rather than a market-wide capacity mechanism. A strategic reserve is a targeted measure that allows the reformed energy market to operate as it should, signalling the real value of continued supply when capacity is scarce. Market-wide capacity markets, such as that introduced by Great Britain, undermine the Article 20 market reforms, depressing scarcity pricing, draining revenues from the energy market and devaluing flexibility options such as demand response and storage.
Great Britain has arguably already implemented the market reforms outlined by the recast Regulation. A reliability standard was introduced in 2014 while, in November 2018, imbalance prices were made fully marginal and the administered shortage-price raised to 6,000 pounds per megawatt hour. Interconnection capacity with continental Europe is increasing and is expected to rise from the current 4 GW to around 11 GW by 2022.
It is therefore difficult to see how Great Britain could do more to implement the energy market reforms required — reforms that the Regulation identifies as precluding the need for a capacity mechanism. From its submission, however, it is clear that Great Britain does not believe that these reforms are sufficient to ensure reliability of supply in the face of continued decarbonisation. It is also clear from the Commission’s opening opinion that it is minded to accept Great Britain’s position. The opinion focusses on issues such as potentially discriminatory differences in the treatment of demand-side resources, rather than the more fundamental issue of whether a market-wide capacity market is justified in the first place.
If this turns out to be the case and the capacity market in Great Britain is reinstated, possibly with a more favourable treatment of demand-side resources, then the Commission would appear to be at odds with itself.
On one hand, it seems to believe that appropriate energy market reform makes capacity markets unnecessary, based on its concurrence with the recast Regulation. Yet, on the other hand, it seems to believe that capacity markets are necessary to ensure supply reliability in the face of continued decarbonisation, regardless of what reforms have been adopted in the energy market.
The Commission’s eventual decision on the need for a capacity market in Great Britain will tell us what they really believe and whether the recast Regulation on the internal electricity market is ever likely to be fully enforced.
A version of this article originally appeared on Euractiv.
Photo: Ian Halsey via Flickr.
Comments Off on Britain’s capacity market: What Europe can learn
The U.K.’s marketwide capacity mechanism for electricity provides a solution to a supply problem that has yet to emerge, writes Phil Baker. A targeted strategic reserve is likely to be a more cost-reflective alternative, he argues.
In 2014 Great Britain introduced a marketwide capacity mechanism in the belief that necessary investment in generation capacity could not be supported by energy market pricing alone. The government has now begun a midterm review of the mechanism, looking at whether it is still needed and, if so, how its design could be improved. As part of our contribution to the review, we have examined the capacity mechanism’s performance to date and highlighted three issues that other EU Member States contemplating the introduction of a capacity mechanism may wish to consider.
Timing is important
Although the capacity mechanism has arguably fulfilled its primary purpose of contracting sufficient capacity to meet Britain’s reliability standard, it has failed to achieve its real objective of bringing forward sufficient investment in new combined cycle gas turbine (CCGT) capacity to replace aging coal and nuclear plant. This failure stems from a persistent surplus of capacity, which has resulted in auction clearing prices well below that necessary to deliver the desired investment. In other words, Great Britain has not really had a capacity problem to solve—the capacity mechanism is a solution to a problem that has yet to emerge.
Further evidence of the lack of any capacity problem is that Britain entered the winter of 2017-18 (the first delivery winter) with a de-rated capacity margin (excess capacity over peak demand adjusted for plant availability) of 10 percent, significantly higher than the 3 percent required to satisfy the reliability standard. In fact, despite a downturn in the first half of the decade, de-rated capacity margin has increased in recent years as illustrated in the figure below. This is mirrored by the fact that the most significant indicator of reliability in real time, the frequency of notifications of insufficient system margin (NISM) issued by National Grid, has declined markedly in recent years. It appears that, despite the government’s concern that the electricity market can no longer be relied upon to deliver new capacity, supply reliability in Great Britain is actually in very good shape.
Tendency to overprocure
Transmission system operators (TSOs), such as National Grid, will be deeply involved in the design and operation of a capacity mechanism. However, while TSOs are exposed to the operational and reputational consequences of a capacity shortfall, they are not exposed to the costs of measures taken to avoid those shortfalls. This introduces a tendency to overprocure, which, in Britain’s case, can arguably be seen in a number of areas. An analysis of National Grid’s demand forecasting over recent years shows an average overestimation of around 1.5 gigawatts, while a conservative approach can also be detected in generator availability assumptions and in the sensitivities used to determine capacity requirements. For example, the assumption of 11 to 13 percent CCGT non-availability seems unjustifiably high compared with both actual outturn of around 6 percent and international data, while the sensitivities around the non-delivery of contracted capacity seem unjustifiably pessimistic.
Although some prudence is justified given the uncertainties associated with estimating future capacity requirements, the costs to electricity consumers of an unnecessarily conservative approach do need to be recognised.
Marketwide or targeted capacity mechanisms?
There is strong evidence that well-designed energy markets are capable of supporting supply reliability at least cost, even in a renewables-dominated world. In fact, this is the rock on which the Commission’s Market Design Initiative is built. However, governments will not want to take chances with supply reliability, and it is easy to see the attractions of introducing additional measures to ensure reliability of supply.
One means of achieving this without moving to a marketwide capacity mechanism is to adopt a targeted strategic reserve. A limited amount of capacity would be held outside the market and used only when the market failed to clear. Wholesale energy prices would be allowed to rise to reflect scarcity. In this respect, a strategic reserve would be more consistent with the Market Design Initiative reforms.
Preliminary analysis suggests that continuing with the strategic reserve rather than bringing forward the first capacity mechanism delivery year would have resulted in a net saving for the year of around £100 million.
Recent British experience provides a useful insight into how cost-effective a combination of market reform and a strategic reserve could be in achieving reliability. The cost of contracting 3.5 gigawatts of strategic reserve for winter 2016-17 was £122 million, while that of its replacement—advancing the first capacity mechanism delivery year to 2017-18—was £378 million. Taking into account the estimated reduction in energy market revenues of around £150 million, this initial and admittedly tentative analysis suggests that continuing with the strategic reserve rather than bringing forward the first capacity mechanism delivery year would have resulted in a net saving for the year of around £100 million. In other words, market reform plus a strategic reserve may well be a more cost-effective option than a marketwide capacity mechanism.
Lessons from experience
It can be claimed that the capacity mechanism has contracted sufficient capacity to meet Great Britain’s reliability standard. However, it has failed to achieve its real objective of new investment in CCGT capacity—a failure rooted in a surplus of capacity depressing auction prices. This highlights the importance of timing: No market can be expected to signal the need for new capacity unless that need actually exists. The issue of timing is complicated by the conservatism of TSOs and governments who will be keen to avoid the reputational and political consequences of any shortfall in supply, even those that commonly accepted reliability standards assume will occur only on rare occasions. This conservatism leads to a tendency to overprocure capacity.
The final point of interest is that a targeted strategic reserve, together with well-designed market reforms, is likely to be a more cost-reflective alternative to a marketwide capacity mechanism. What is certainly true is that a strategic reserve is far more consistent with the Market Design Initiative reforms and represents a simpler exit option if it is decided that energy markets alone can deliver the required level of supply reliability.
Comments Off on Replacing copper with negawatts—how RIIO-2 could revolutionise network regulation
Ofgem’s recent framework decision on improving its performance-based regulation scheme, RIIO, indicates that it may be ready to take a much-needed step toward levelling the playing field between supply-side and customer-side resources. However, it is not yet clear what the details will look like. According to Jan Rosenow of the Regulatory Assistance Project, a global group of regulatory experts, Ofgem should put a network regulation scheme in place that will maximize the role of energy efficiency, demand-side resources, and customers. The U.S. provides instructive examples of such an approach.
Gas and electricity network companies hold a monopoly position. Households or businesses cannot choose which network to use. Therefore, regulators set price controls, a ceiling on the amount companies can earn from the charges to use their networks.
These controls offer an opportunity to incentivise network companies to deliver the services consumers value and to advance the clean energy transition at least cost. In other words, price controls direct how and where the revenues collected through network charges are being spent. At more than €60 billion, electricity distribution revenues in Europe are serious money.
RIIO and the U.K.
The U.K.’s performance-based framework RIIO (Revenue = Incentives + Innovation + Outputs) is one of the most innovative price control mechanisms in the world. In its recent RIIO-2 framework decision, Ofgem, the U.K.’s Office of Gas and Electricity Markets, placed “giving consumers a stronger voice” at the top of its list of methods for developing a reliable, safe, secure network—one that fosters a low-carbon future.
The report shares the results of the agency’s consultation on how to adjust its network price controls program as of 2021 and 2023 for gas and electricity, respectively. In the process, the regulator put the last five years of its program under the microscope.
Like many regulators the world over, Ofgem recognizes the valuable role of consumers as we face exponential change in today’s power sector and strive for decarbonisation. Facing criticism over unexpectedly high network company profits, Ofgem strives to strike a balance between consumer costs and the need to create a “smarter energy system” that keeps pace with critical changes in the energy sector. Customer-side resources and energy efficiency are powerful instruments for meeting these challenges, especially if supported by the right policies.
Network companies well-positioned to deliver energy efficiency
Stakeholders voiced a broad range of views in the public consultation, particularly on end-use energy efficiency. The Regulatory Assistance Project urged Ofgem to consider a stronger role for network companies in providing solutions that encourage lower energy use by consumers and thus reduce or defer the need for investments in energy networks.
This is important because end-use energy efficiency, such as thermal insulation of gas- and electricity-heated buildings and more energy efficient appliances, brings environmental benefits such as lower carbon emissions and lower emissions from burning fossil fuels and leads to lower costs. Network companies, including system operators, are in a unique position to evaluate the cost-effectiveness of end-use energy efficiency from a network system perspective. They have the data to identify where efficiency savings might replace or delay the need for investments in network infrastructure, thereby saving consumers money.
Con Ed estimated that the effect of its systemwide efficiency programmes reduced capital expenditures by more than $1 billion.
To mention an old example of this approach, in the 1990s, the Holyhead Powersave Project reduced peak demand by 10 percent on Holy Island in Wales through energy efficiency measures including efficient light bulbs, draught proofing, and the installation of energy-efficient electrical appliances. The electricity supplier and distributer for North Wales implemented the project in response to growing demand that would result in the need for a new substation on the island. By deferring the need for the new substation by five years, the project resulted in an avoided investment cost of an estimated 500,000 euros.
Thankfully, the regulator took a serious look at the role network companies can (and should) play in delivering end-use energy efficiency. At a high level, Ofgem committed itself to creating a level playing field for demand-side and supply-side resources. This marks an important step in the right direction.
In its consultation response, the regulator states: “Where energy efficiency, alongside other supply-side options, has the potential to defer or mitigate the need for network investment, then there should be no barriers to network companies pursuing this solution.”
However, it is not clear yet what this will mean specifically for network companies and for RIIO. Ofgem will develop more specific methodologies for RIIO-2 by December 2018 to fill this gap.
US experience with “non-wires” alternatives
Fortunately, there is valuable experience on energy efficiency and network infrastructure from the international realm to provide guidance.
The longest track record of regulators working with network companies to integrate cost‑effective “non-wires” or “non-transmission” alternatives into planning and investment can be found in the United States, although there is a growing track record of network companies piloting similar solutions in the U.K. These alternative solutions include end-use energy efficiency, demand response, and distributed renewable resources.
Consolidated Edison (Con Ed), the electric utility serving New York City and its northern suburbs, leads the pack in this approach. In its ten-year forecast, Con Ed estimated that the effect of its systemwide efficiency programmes reduced capital expenditures by more than $1 billion. Similarly, the New England Independent System Operator has identified more than $400 million in previously planned transmission investments in New Hampshire and Vermont that are now deferred beyond its ten-year planning horizon due to energy efficiency.
Regulatory framework needed to realise network benefits of efficiency
In order for network companies to identify and realise the network benefits of energy efficiency and other measures on the customer side of the meter, regulators must put the proper regulatory framework in place. California’s recent introduction of a non-wires alternative requirement provides an instructive example of how such a framework might be structured. The requirement has several key elements:
Regulators require network companies to identify any significant upcoming distribution system investment need.
Once identified, each utility must solicit proposals to meet the need with portfolios of distributed resources such as energy efficiency, demand response, storage, photovoltaic panels, and other resources.
Regulators then evaluate the proposals on a technology-neutral, least-cost, best-fit basis.
If the most cost-effective proposal with the best value is superior to the distribution wires investment solution, the utility must enter into a contract with the winner.
The utility is entitled to recover all costs of administering the non-wires solicitation and, as compensation for an effective solicitation, will be entitled to earn 4 percent on the annual contract cost of the non-wires alternative.
This is not a new approach. California’s non-wires requirement implements the “efficient reliability standardˮ developed by the Regulatory Assistance Project for the U.S. national regulators’ association nearly twenty years ago—a concept that is still entirely relevant today.
The expected impact of investment in non-network alternatives, including energy efficiency, is difficult to gauge, as it will depend on many factors. Instructive data on the benefits and potential scope can be drawn from discrete projects, including those listed earlier, where the savings resulting from investment in efficiency and other non-wires alternatives have been calculated in comparison to network-only investment.
Customer-side solutions for a transforming energy sector
Following the high-level commitment in the consultation response, Ofgem now needs to follow through on ensuring that energy efficiency and customer-side resources take a leading role. The agency will increasingly need to contend with electrification of the heat and transport sectors, further increases in distributed generation such as solar and wind, and greater uptake of storage and other technologies. Clearly, energy efficiency is one of the key ingredients to manage networks and make a success of the clean energy transition.
A version of this blog originally appeared in Energy Post.
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