5.Electricity and gas networks are divided into transmission and distribution. Transmission networks are long-range and high-voltage (electricity) or high-pressure (gas); distribution networks are short-range and low-voltage or low-pressure (relative to transmission). National Grid Electricity Transmission (NGET) owns and maintains the electricity transmission network in England and Wales, while National Grid Gas Transmission (NGGT) owns and maintains the GB-wide gas transmission network. As Transmission System Operator (TSO), National Grid operates and balances both transmission networks. Six companies own the 14 Distribution Network Operators (DNOs) responsible for electricity distribution; the eight Gas Distribution Networks (GDNs) are owned by four companies.
6.Network companies recover their costs from users—households, businesses, suppliers and generators—through various network charges. British Gas informed us that “network costs typically account for £270 of a £1,150 dual fuel residential bill (£134 for electricity network costs), and have risen by around 30% over the last 4 years”. As networks form natural monopolies, they are not given free rein to determine their revenues: these, and certain other restrictions and obligations to protect users, are specified in licence conditions and price controls. The current price controls are known as ‘RIIO’ (Revenue = Incentives + Innovation + Outputs): these are set by Ofgem, the electricity and gas regulator, and run for eight years—known as the ‘price control period’.
7.Network companies have a range of obligations, some enshrined in legislation, and others encouraged by RIIO. They must offer a connection to any user requesting one. They need to ensure a safe and reliable supply of energy for households and industry. Finally, the system operators—NGET and NGGT—have responsibilities to ensure supply and demand are balanced in real time. The networks do not actually generate electricity, or sell electricity or gas to consumers; indeed, they are legally precluded from doing so. Their job is to act as conduits for power generated, supplied and consumed by other parties.
8.Smaller electricity generators tend to connect to the regional, low-voltage distribution network, rather than the national, high-voltage transmission network: this is known as ‘distributed’ (or ‘embedded’) generation. Historically, the UK’s electricity has been generated by relatively-few large power plants connected to the transmission system. Recently, however, the UK’s distributed-generation capacity has grown explosively, rising by 54% between 2011 and 2014. Currently 19.1 gigawatts (GW), it could reach between 31 GW and 57 GW by 2036. Most distributed generation is onshore wind or solar PV: the Energy Networks Association (ENA) observed that solar PV is now connected to distribution networks “already close to the levels previously expected by 2030”. Andrea Leadsom MP, Minister of State for Energy and Climate Change, declared that “energy is undergoing a genuinely radical transformation. We have seen a massive increase in the number of local connection requests and in the type of power generation”.
9.This has strained DNOs’ ability to connect distributed generation. Smarter Grid Solutions claimed “connection moratoria, long queues, unrealistic connection dates, high costs and lapsing connection offers are very common in the grid connection process”. TGE Group, a solar PV installer, outlined the challenges in connecting to the grid:
Low voltage applications can take up to 45 days to process whilst high voltage applications take up to 65 days. Our fastest approval came in five hours whilst others have arrived at the last hour on the last day. This uncertain processing time makes scheduling work impossible, for a start, it can take the full 45 days before you know whether the customer can have, for example, a 50kWp system or a 100kWp system and it is not commercially viable to do the full design work until DNO approval has been received. It’s hard to accurately predict the outcome of an application, as every customer is different depending on location.
We heard that one DNO’s projections for distributed solar connections by 2023, the end of the current price-control period, was reached before the revenue control started in 2015: the system for connecting distributed generation has been overwhelmed by its unprecedented growth. Furthermore, DNOs in different regions are distinct companies and deal with distributed generation in their own ways. Tony Glover, Director of Policy at the ENA, claimed the organisation “is looking at how we can standardise, where appropriate and where practicable”. However, standardisation can be difficult as “you are looking at different distribution network operators operating in different types of locations—some of them, in fact, with differently configured networks, technically speaking”. Technical homogeneity may be impossible, but we should expect every DNO to provide a timely and reliable connection service. That service has been widely absent.
10.Ofgem’s response to the scale and urgency of this problem is its Quicker and more efficient distribution connections project. This project has “improved visibility and availability of flexible connections, flexible payment terms and consortia for connecting customers” and led to “an action plan for industry to progress more effective queue management”. Further plans in this project include:
i)‘Milestones in connection offers’, which would allow DNOs to make connection offers contingent on generators meeting targets for planning consent and construction in a timely fashion.
ii)Allowing ‘anticipatory investment’, where DNOs reinforce the existing network in advance of expected connection requests; this is currently being trialled in a handful of areas.
iii)Using existing network more efficiently, perhaps through better network management.
Active management of distribution networks is a central theme of this inquiry, and is addressed more fully in chapters 3 (at a technical level) and 4 (at an institutional level). We turn now to review points (i) and (ii) in greater detail.
11.Generators and their connections are often significant physical structures with potential impacts on their local environments, and as such planning consent is far from a foregone conclusion. Planning consent for connections lies with local and national authorities, whereas grid-connection processes are in the hands of the network companies.
12.DNOs are required to offer a grid connection to any generator (or other party) who requests one on a ‘first-come-first-served’ basis; there are currently no up-front application fees. It is therefore problematic if connection requests without meaningful prospect of fruition create blockages in the queue. Tony Glover suggested “about 70% of applications to connect are in fact speculative”. The Minister noted that one DNO “received 241 connection applications from one customer and none of the connection offers were taken up”. She cited arguments that upfront assessment and design fees for distributed connections would discourage speculative applications. We agree with this logic. However, excessive fees may shut out bona fide developers. The objective should be to find a ‘sweet spot’ between the minimum fee required to discourage speculative applications, and a level that would be a significant disincentive to the development of new generation.
13.The Renewable Energy Association (REA) argued “a new system of handing out grid offers is required which incorporates project milestones and ties developers to reasonable progression”. Ofgem’s Quicker and more efficient distribution connections project proposes ‘milestones in connection offers’ as a solution; a draft version of these rules indicates that connecting parties would lose their place in the queue if, for example, they failed to acquire planning permission or land rights by a certain date. Maxine Frerk, Acting Senior Partner in Networks at Ofgem, described this as “a form of ‘use it or lose it’ applied to connection queues”. Milestones in connection offers are a sensible and proportionate response to speculative and spurious connection requests, and we support their implementation.
14.Disjoint between connection and planning-consent processes impacts more widely than the distributed-generation connection queue, and we received many calls for these systems to be better integrated. The UK Energy Research Centre (UKERC) claimed that planning-consent problems can delay transmission connections. LDA Design, a spatial design consultancy, argued:
Network operators and energy developers need to engage with the plan-making process in much the same way as property developers do today. Local enterprise partnerships, local authorities and neighbourhood forums need to be given responsibility for planning for the growth and evolution of the network. This will allow wider spatial and growth decisions to be based as much around available energy and grid capacity as they are about housing need, jobs and transport today.
15.The more information developers have on network capacity, the more efficiently they can site new generation. Scottish Power Energy Networks (SPEN) publishes ‘heat maps’ indicating areas of spare capacity for connections; this is a useful development, and one we encourage. Tempus Energy, an energy technology and supply company, called for a single common application portal for all connection requests. Tony Glover cautioned that this “could well be quite a distraction at this time” and was “a bit of a challenge at the moment”, given “the tsunami of applications we currently have to deal with”. Nevertheless, we believe that any serious suggestion to simplify the connection process and centralise information about it is worth considering.
16.We asked John Fiennes, Director of Energy Strategy, Networks and Markets at the Department of Energy and Climate Change (DECC), about integration of the connection and planning-consent processes. He noted:
The national planning statements encourage people to put in their connection and their generation requests at the same time. However, the timeframes for the two elements of networks and generation can be quite different so it does not absolutely insist that the connection appear at the same time because you would lose the critical path, in effect, at that stage.
There is evident value in further integration of the connection and planning-consent processes, which could accelerate connections. Moreover, heat maps and possibly a centralised, standardised application procedure could improve information—and thus decisions—before those processes are even begun.
17.We call on the Government to establish a cross-departmental working group to investigate and report on improving the integration of the connection and planning-consent processes in England. This investigation should include an assessment of mechanisms—such as heat maps and centralised, standardised connection applications—that could simplify these processes and better inform generators about them.
18.Several written submissions called for anticipatory investment, or investment ahead of need, so that networks could develop infrastructure in expectation of future connection requests. ‘Anticipatory investment’ is variously used to describe either maintenance and upgrade work to meet general future capacity needs, or development targeted at expected (but not certain) future connection requests. The former is standard practice and uncontroversial. This section considers the latter.
19.Tempus Energy claimed that existing rules disadvantage “unfortunate customers who trigger a major reinforcement scheme”. The Sussex Energy Group at Sussex University suggested that anticipatory investment could reduce costs for developers, and also discourage ‘smearing’ (construction of longer-than-necessary lines to reach areas of spare capacity). It further contended that anticipatory investment may encourage non-traditional business models to emerge. UK Power Networks (UKPN), a DNO company, observed that “investing ahead of need will also help us to deliver a smarter grid at lower cost”. The Minister confirmed that DECC are “encouraging greater anticipatory connections”.
20.Cost recovery is the major problem for anticipatory investment: if not an actual, presently-connecting customer, who pays for the infrastructure? DNOs’ costs fall ultimately on their customers through network charges, and generators who take advantage of DNOs’ anticipatory investment should pay their fair share. The ENA contended that “without proper rules [anticipatory investment] could also reduce the important incentive for connections customers to ask for connection in areas where reinforcement isn’t required”. Anticipatory investment rules must also be designed to discourage DNOs from developing too many assets that end up unused or ‘stranded’: such misadventures are a necessary risk, but must be controlled. Andy Burgess, Associate Partner in Energy Systems at Ofgem, noted “if the network company invests and the investment is not needed, then consumers ultimately pay, so we want to get the right balance.”
21.Ofgem’s Quicker and more efficient connections project is supporting trials of anticipatory investment, including two (Western Power Distribution’s Grendon and Spalding) responding to distributed-generation applications. It is considering three systems of cost recovery:
(1)Costs are socialised across all network users;
(2)Costs are covered by the DNOs upfront, then recovered from subsequent users; or
(3)Costs are covered by the initial connector upfront, then recovered from subsequent users.
22.We support anticipatory investment in principle: it is likely to improve networks’ speed at connecting distributed generation. However, it also bears the risk of creating stranded assets at bill-payer expense. Anticipatory investment must therefore be accompanied by up-to-date modelling to minimise this risk.
23.Ofgem should carry out further impact assessment on systems of cost recovery for anticipatory investment; this should include analysis of who bears the costs of stranded assets, so that relevant decision-makers are properly incentivised to avoid them.
24.Building, maintaining and operating network infrastructure carries costs, and these are borne by bill-payers. This does not mean that networks must avoid necessary expense, but we cannot scrutinise network infrastructure without considering its price. Network charges form an increasing proportion of consumer bills; networks and their regulators must do more to achieve efficient outcomes. Moreover, network costs and connection costs are asymmetric both geographically and between transmission and distribution, and the Government must continue to consider the justifications for these disparities. Transmission tariffs for generators are also higher in GB than in the rest of the EU.
25.Network charges primarily comprise the following:
26.Suppliers recover network charges from consumers, who therefore contribute to all the above. Network charges on a typical dual-fuel consumer bill have risen approximately 30% in the last 4 years: Ofgem claims they account for approximately 24% of such bills; Scott Mathieson, Director of Network Planning and Regulation at SPEN, offered a more conservative estimate of 19–20%. Network companies universally outperformed Ofgem’s target rates of return under the previous price control and our predecessor Committee concluded as recently as February 2015 that the RIIO settlements “are too generous and the targets are too low”. We reprise their complaint that despite the introduction of RIIO, network charges are rising and networks and the regulator must do more to reduce them.
27.The Association for Decentralised Energy (ADE), the REA, RenewableUK, and the Solar Trade Association wrote to us about embedded benefits, which Ofgem and National Grid are separately reviewing. ‘Embedded benefits’ are distributed generators’ exemptions from BSUoS and TNUoS charges. Distributed generation directly affects system balancing—it is often variable—and the transmission network: National Grid informed us that “with an increasing penetration of distributed generation we are finding that the need for transmission development is growing”. However, distributed generation does not affect the transmission network as much as transmission-connected generation. Cornwall Energy, a consultancy, warns of higher wholesale electricity prices among other drawbacks if embedded benefits are removed. We will continue to follow the progress of these reviews and may return to this issue to scrutinise their conclusions.
28.Network charges also vary considerably according to location. Ofgem notes:
Electricity distribution charges are higher than average in North Scotland, Merseyside & North Wales and South West of England and lower in London and Eastern England. In contrast, electricity and gas transmission charges are higher in the south of England and lower in Scotland while gas distribution charges are higher in London and the south of England and lower in Scotland and the north east of England.
29.Our predecessors recommended “that the Government and Ofgem publish an evidence-based analysis of the advantages and disadvantages of introducing national tariffs for transmission and distribution network charges”. ‘National tariffs’ would standardise network costs, eliminating regional differences. Ofgem consequently produced a document, Regional differences in network charges, in October 2015; this concluded that national network charging would raise bills for 16 million households while lowering them for 11 million, though “in most cases the increase or decrease would be small”. The Minister told us national network charging “would risk an overall increase in network costs”.
30.Regarding generation, the ADE argued “the [current] cost reflective approach promotes efficient use of the network by larger users, for example, by providing a signal to generators that locating close to their customers requires less transmission network to be built”. However, among EU member states, the UK is one of only three with locational transmission tariffs. Indeed, transmission costs borne by generation are higher in GB than elsewhere in the EU. Haven Power, a supplier, observed TNUoS charges rising 16% in the past year alone. RenewableUK “support the principle of locational and cost-reflective charging, but this should be applied in a way that recognises that renewable resources are often location-specific and therefore projects exploiting them cannot respond to locational incentives”. A wind or solar PV installation should be sited where the resource is best, and this may not be near demand centres. This combination of high and regionally variable connection and transmission costs may disadvantage renewable generation in the UK which is distant from demand centres: Renewable UK further noted “GB is unusual in the EU in charging generators at all for the use of the system, and that this could lead to unfair competition as this country becomes more interconnected with others”.
31.Cost-reflective charging should account for the reality that many renewable-energy sources are location-specific and distant from demand sources, particularly as UK transmission charges remain high by EU standards. DECC should investigate the disadvantage UK generators may consequently face against other European generators as Great Britain becomes more interconnected, and the impact this may have on development of domestic renewable generation.
32.In addition to the general network charges described above, generators pay costs for connecting to the network; these costs vary with location and whether a distribution or transmission connection is sought. At transmission level, there are application fees ranging from £15,000 to £480,000 and the generator then covers National Grid’s costs in installing and maintaining the asset over its lifetime by an annual Connection Charge, which—depending on the specifics of agreements between the parties—totals approximately 10% of the connection’s Gross Asset Value. At distribution level, there are currently no up-front application fees (see paragraph 12) and generators are charged asset costs for network extension and a portion of reinforcement costs, though methodologies differ from DNO to DNO; payments can be staged but are usually upfront for smaller works. Locational connection-cost differences tend to be higher for distribution than transmission connections.
34.New connections are not the only infrastructure requirement that networks need to meet. Some physical assets are approaching the end of their expected lives and require replacement. In addition to reinforcing existing network infrastructure, it is increasingly becoming important to manage networks more flexibly in order to wring extra capacity from existing infrastructure with smart grid technologies. Though one approach may reduce need for the other, they are by no means mutually exclusive.
35.Some written evidence identified ageing network assets as problematic. RWE, a major supplier, told us:
The lack of sufficient network investment in the post-privatisation era is a well recognised limitation of our electricity system today. The recent significant surge in investment via increased revenue allowances under the RIIO regime is helping to ready the systems, but the impacts of chronic historic underinvestment will persist for some time. There is a need to replace aging infrastructure that is no longer fit for its current purpose as well as adapting and extending networks to serve an evolving low carbon economy.
36.UKERC pointed to “ageing generation and network assets which are reaching or have already gone beyond their expected lives” and argued that “whatever the benefits of a ‘smarter’ grid, progressive decarbonisation of the electricity system will still require significant investment in primary assets”. This challenge is not limited to the UK: we learned in Copenhagen that ENTSO-E (the European Network of Transmission System Operators for Electricity) has identified a need for 50,000km of electricity transmission line across Europe by 2030, costing up to €150 billion. The scale of the challenge to reinforce the UK’s networks is considerable. RenewableUK called for investment in new HVDC capacity to reinforce the network. National Grid are about to commission an HVDC link between Scotland and England which “provides a large step change in capacity”.
37.Phil Jones, CEO of Northern Powergrid, a DNO company, responded by noting that not all physical infrastructure will reach the end of its expected life simultaneously; he further indicated that RIIO-ED1 allocates “sufficient funds to replace and upgrade the ageing assets”. DECC agreed that “our electricity system will need to evolve […] this will require ageing assets to be replaced and upgraded”.
38.DECC and Ofgem define a smart grid as “a modernised electricity grid that uses information and communications technology to monitor and actively control generation and demand in near real-time”. Smart grids optimise electricity networks, particularly at distribution level, by providing them with better information on energy flows and giving them automated and discretionary tools to manage these flows. Stephen Goldspink, Director of Strategy and Business Development at Siemens Energy Management, an engineering firm, illustrated the problem that smart grids aim to solve:
We have to understand that our distribution networks in its truest sense are largely blind to the distribution network operators. We do not have automation right through the networks, we do not have sensors that can detect faults and give very rapid indication of where those faults are. We do not have the communications infrastructure right the way through the network, which enables things like demand response right across the distribution networks. So that automation, that monitoring, that real-time communications across the networks are just the fundamentals of smart grids.
Technologies enabling smart grids include “real-time equipment ratings and associated forecasting techniques”, “phase shifting transformers, series compensation and their co-ordinated use” and “integrated monitoring, protection, remote control and data collection for distribution networks”. Storage and Demand Side Response (DSR) can be thought of as components of smart grids, but we consider these separately in the next chapter.
39.Smart grids can enable networks to use their existing physical infrastructure more efficiently, allowing quicker connections for new generation and reducing reinforcement needs. ‘Active network management’ refers to networks controlling their energy flows rather than passively letting them occur, and ‘connect and manage’ denotes using these techniques to connect generators. Scott Mathieson drew our attention to SPEN’s Accelerating Renewable Connections (ARC) project:
We have our grid supply point at Dunbar that was potentially triggering a major reinforcement on the transmission system and through active network management, Accelerating Renewables was able to connect about 60 megawatts to that area. We were also able to connect and facilitate about 2.2 megawatts of photovoltaics, equivalent to about 750 homes in the Berwickshire area, through effectively investing in protection and control equipment that gave us in real time more information about how the assets were performing and the generation was operating within that area.
Mr Mathieson claimed this project had saved £6.2 million for a cost of £800,000, and avoided a further £20 million worth of reinforcement. Tony Glover observed that the Orkney Smart Grid has averted £30 million in network reinforcement at a cost of only £500,000. Phil Sheppard, Director of SO Operations at National Grid, emphasised “connect and manage” as the main mechanism to connect more renewables. He claimed that “actively managing voltage in the network, or at the connection point, or the interface between the transmission and distribution network, or automatic network management systems” had enabled an extra 5.7 GW of renewable connections in the previous 12 months, as opposed to “the old, traditional way of doing things”. Active network management has great potential to address the challenges in connecting new generation, reducing network costs and (virtually) reinforcing the network. Its rollout may require DNOs to acquire more power as Distribution System Operators; we return to this question in chapter 4.
40.DECC and Ofgem state that “smart meters are a key enabler of a smart grid”. A smart meter “is a gas or electricity meter that is capable of two-way communication […] that allows data to be read remotely and displayed on a device within the home, or transmitted securely externally”. These may contribute to DSR by encouraging consumers to respond to dynamic prices, as we discuss in the next chapter. In the context of smart grids, quicker and more accurate information from smart meters may help networks use infrastructure more efficiently. Phil Jones brought up Northern Powergrid’s Consumer-Led Network Revolution (CLNR) project with British Gas. CLNR analysed smart-meter benefits, and discovered that “the diversity in people’s behaviours [relating to time of electricity consumption] is much wider than was ever assumed”, and consequently that the maximum network demand “is about half of what was being assumed when networks were built”. Smart meters may thus reduce the need for physical infrastructure development, saving money. DECC estimates that smart meters will provide £1 billion worth of benefits to networks, among approximately £18 billion of wider benefits against the cost (approximately £12 billion) of their roll-out. The Minister reaffirmed that DECC is “absolutely committed to ensuring that everyone has been offered a smart meter by 2020”. However, our recent pre-legislative scrutiny of the Government’s draft legislation on energy highlighted “legitimate questions about whether the smart meter roll-out programme is on track to meet its 2020 targets”. We will continue to scrutinise the Government’s progress on the smart meter roll-out throughout our inquiry work.
42.Electricity is carried in the same form regardless of how it is generated, whereas heat can reach the home through different media, each of which requires its own network infrastructure. At present, the majority of UK heating is provided through natural gas piped directly into homes and businesses. Three approaches to decarbonising the heat sector have stood out in evidence: one is to electrify heating; another is to replace methane with ‘green gases’ such as biomethane and hydrogen; the third is to develop heat networks, or ‘district heating’.
43.Electrification of heat would increase the UK’s requirements of electricity network infrastructure. Several commentators suggested that electrifying heat completely would add 300 GW to peak electricity demand, a roughly five-fold increase from current levels. Dr David Clarke, Chief Executive of the Energy Technologies Institute (ETI), noted “the ramp rate that we have all got used to through gas central heating: the ability to turn the thermostat up and get an instantaneous response”. He told us that “it is inconceivable to deliver that ramp rate from electricity”. Electrifying heat immediately would be overwhelming, but remains a gradual, long-term prospect; Scott Mathieson illustrated this point:
From 2009, the collapse of the Lehmans Bank, right up to date there has been about a 1% to 2% reduction in demand. The work that we have done with the future energy scenarios shows that that begins to flatten out over the period between now and 2023 and gradually, with the switch towards potential electric vehicles or electric heating, demand begins to increase by about 1% to 2% per annum. With scenarios there is always a high, low or medium, but whichever of those scenarios you look at they all show a trend towards increasing electricity demand.
A long-term policy to electrify heat and transport will significantly impact networks. We will return to this issue in our ongoing inquiry into 2020 renewable heat and transport targets.
44.The Government’s most recent major strategy publication on low-carbon heat—2013’s The Future of Heating: Meeting the challenge—identifies biomethane and hydrogen as compliments or alternatives to natural gas. Biomethane is produced by extracting CO2 and other impurities from biogas, which is a mixture of methane and CO2 created by anaerobic digestion of organic material. As biomethane is chemically similar to natural gas, it can be used with or instead of natural gas in the gas grid without pipeline modification. However, its CO2 emissions are approximately 90% lower than natural gas, as the process of anaerobic digestion used to generate it absorbs CO2 from the atmosphere. Chris Clarke, Director of Asset Management at Wales and West Utilities, a GDN company, noted biomethane “is in its infancy” and that green gases in general are “perhaps like solar was 10 to 15 years ago […] at that stage of development”.
45.Unlike biomethane, hydrogen is insufficiently similar to natural gas to be injected into the current gas grid at high quantities. It may make steel pipes brittle (thus more vulnerable to cracks) especially at high pressures. It also has a lower calorific value than natural gas—it produces less energy per volume. Chris Clarke stated that hydrogen can be blended with natural gas up to 20%. Burning hydrogen does not itself emit CO2 (though producing the hydrogen may do). There is also a natural synergy with renewable electricity, where spare generating capacity could create hydrogen through electrolysis. Maxine Frerk noted “in the last year, we have seen a twelvefold increase in biomethane being connected to the network” and network innovation funding (examined in chapter 4) has been used for several biomethane and hydrogen projects.
46.Ofgem should build on the promise of green gases by continuing to investigate and clarify safe levels for their injection. Both the Government and Ofgem should set indicative targets for biomethane and hydrogen deployment, and consider what support might be needed to deliver consequential changes to network infrastructure.
47.Most homes in the UK are heated by an on-site water boiler powered by gas from the distribution system. District heating systems, also known as heat networks, use a large shared boiler to distribute hot water or steam to a number of homes. DECC provides the following summary of district-heating penetration in the UK:
There are thought to be over 2,000 heat networks and communal heating schemes of various sizes in the UK serving 200,000 dwellings and 2,000 commercial and public buildings. The largest heat network schemes are predominantly found in cities and on university campuses. There are also a large number of smaller schemes in the domestic sector, often linking communally heated blocks of flats. This extent of heat networks represents around 2% of the domestic, public sector, and commercial buildings heat demand. Benefits from the increased use of heat networks could include energy cost and Carbon Dioxide (CO2) emissions reductions for the UK, through allowing the exploitation of lower CO2 and higher efficiency forms of generation. These could include the use of CHP, biomass, heat pumps, waste heat and low grade heat sources.
48.Dr David Clarke suggested that power plants be sited with a view to utilising waste heat. Such synergies between electricity and heat development exemplify the benefits of a whole-systems approach, as we discuss in chapter 4. Dr Tim Rotheray, Director of the ADE, noted that district heating provides in-built thermal storage. The Government observed in 2013 that “up to 20% of UK domestic heat demand might be served by heat networks by 2030” and the Minister reaffirmed DECC’s commitment to this target. This would be a tenfold increase, in proportional terms, in uptake in less than a decade-and-a-half—an ambitious goal. The 2015 Spending Review and Autumn Statement announced £300 million of funding for district heating, “expected to support construction of up to 200 large heat networks in towns, cities and communities across England and Wales, and also to leverage up to £2 billion of private and local investment”. When asked in April how this money would be spent, the Minister noted that DECC would soon consult on this, though we are still waiting for this consultation to open. Wales and West Utilities observed commercial barriers to district heating in a study conducted in Bridgend: it found a payback period of 35 years, and that “80% of the consumers either could not or would not pay”. Drs Clarke and Rotheray argued, however, that a low-carbon network would require significant infrastructural investment regardless of the mix of technologies chosen.
49.We heard that district heating remains under-regulated: this could harm both existing customers, who are insufficiently protected, and future customers, if returns on investment are uncertain. The ADE has co-created a voluntary code of practice for district-heating providers. In November 2015, the ADE also launched Heat Trust, an independent customer protection scheme for district heating customers. This works with the Energy Ombudsman to manage complaints, and mandates audits for member providers every five years. While both of these are positive steps, and in no need of reversal, we would prefer that such self-regulation co-exists with independent regulation to ensure consumer protection. Furthermore, we heard it is unclear whether local authorities have the power to require district heat networks as part of local planning. Regulation could also stimulate investment in district heating. Dr Rotheray told us “the Government need to develop a regulatory investment framework, like the one we have for gas, water and other infrastructure […] so that if you are an investor like an institutional investor, you will be able to look at different options and evaluate them on a similar playing field”. As noted earlier, the Government’s plan to meet its 20% target for district heating relies, at this stage, on leveraging £2 billion of private investment; thus any measure that encourages such investment, while protecting consumers, must be looked on favourably. District heating currently has no independent regulation: Maxine Frerk noted that district heating “is not within [Ofgem’s] remit unless we were asked to pick it up.” She further observed:
You have the problem that once you have a district heating system in place, it is a monopoly. Customers cannot change supplier. There are a number of different ways to address that. It does not have to be through network regulation. I think you are aware that there is a voluntary code in place. On whether that could be given more teeth, there is the CMA, and there are general consumer protection regulations that could apply in this area. There are a number of different ways that it can be addressed. I am not sure it is about them being treated as guinea pigs at this early stage. I think there is an inherent issue in the fact that it is a monopoly provision of a service that has a long infrastructure cost.
50.Denmark, which developed district heating networks in response to the oil crisis of the 1970s, now uses them to provide for approximately 60% of its heat needs. When we visited Copenhagen, scientists at the Technical University of Denmark (DTU) described the tripartite Danish heat system: district heating in urban areas, some gas-network coverage, and individual boilers in rural areas. Danish district heating is decentralised, usually under municipality control, and this local ownership—combined with the low prices it offers consumers—has cemented its popularity. Heat is supplied by CHP plants, mostly small, though we did visit Avedøre Power Station, which provides significant heat to the Copenhagen area. Danish energy experts we met agreed that the UK could not reach Denmark’s levels of district heating provision, but did believe there was considerable scope for new-build housing to be connected to such systems. We feel there is much to learn from the Danish model of small, local CHP plants feeding district heating with effective local ownership and oversight.
51.The Government has rightly set an ambitious target for district heating—one which requires significant private-sector investment. A regulatory investment framework for district heating, similar to those for other networks, would aid this. It would also complement existing voluntary schemes in providing independent safeguarding for consumers. Ofgem should be required by the Government to regulate district heating networks, and the Government should seek to make whatever legislative changes are necessary to enable this.
3 Scottish Power and SSE own and maintain the electricity transmission network in Scotland.
4 British Gas ()
5 Department of Energy and Climate Change (DECC), Digest of UK Energy Statistics (DUKES), (MS Excel spreadsheet), July 2015
6 DECC, DUKES, (MS Excel spreadsheet), July 2015
7 National Grid, , July 2015, p134
8 DECC, DUKES, (MS Excel spreadsheet), July 2015
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11 Smarter Grid Solutions () para 3.4
12 Kilowatt peak, a measure of maximum power output
13 TGE Group ()
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17 Ofgem, , January 2016, p4
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19 Ofgem, , January 2016, pp13–18
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24 Ofgem, , January 2016, p21–4
26 RSPB (), RWE () para 1.3, ETI () para 32, LDA Design ()
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29 Q15 [Scott Mathieson]
30 Tempus Energy Supply ()
33 ENA (), Sussex Energy Group () paras 11, 25, UK Power Networks (UKPN) () para 1.15, Tempus Energy Supply ()
34 Tempus Energy Supply ()
35 Sussex Energy Group () para 11
36 Sussex Energy Group () para 25
37 UKPN () para 2.4
39 ENA ()
41 Ofgem, , January 2016, p13
42 Ofgem, , February 2015, pp5–10
43 British Gas ()
44 Ofgem, , Data Table, accessed 13 June 2016
46 Citizens Advice, , May 2015, pp19–22
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49 National Grid () para 22
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51 Ofgem, , October 2015, p5
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53 Ofgem, , October 2015, p5
55 ADE ()
56 Scottish Renewables ()
57 ENTSO-E, , June 2015, p13
58 Haven Power ()
59 RenewableUK ()
60 RenewableUK ()
61 National Grid, The Statement of Use of System Charges, (PDF download), p23
62 National Grid, (PDF download), October 2013
63 ENA, , June 2014, p47
64 ENA, , June 2014, p50
65 Q283 [Andy Burgess]
66 RWE () para 1.2
67 UKERC ()
68 ENTSO-E, , October 2014, p4
69 RenewableUK ()
70 Q202 [Phil Sheppard]
73 DECC () para 8
74 DECC and Ofgem, , February 2014, para 3
76 UKERC ()
79 Qq222, 255
80 System Operator
83 DECC and Ofgem, , February 2014, para 3
84 Ofgem, , March 2011, p1
85 Q179 [Phil Jones]
86 DECC, , January 2013, p3
88 Energy and Climate Change Committee, Sixth Report of Session 2015–16, , HC 776, para 12
89 Qq39 [Stephen Goldspink], 115 [Chris Clarke]
90 National Grid, (PDF download), October 2015, p15
94 Future of Natural Gas in the UK, , Parliamentary Office of Science and Technology (POST), November 2015, p3
97 Paul E. Dodds and Stéphanie Demoullin, , International Journal of Hydrogen Energy, vol 38 (2013), pp7189–7200
98 Q125 [Dr David Clarke]
100 Carbon Footprint of Heat Generation, , POST, May 2016, p2
101 Q230 [Tony Glover]
103 Combined Heat and Power (CHP) plants are thermal power stations which supply both electricity and hot water.
104 DECC, , 2015, p6
107 DECC, , March 2013, p45
108 Qq381–4 [Andrea Leadsom MP]
109 Q379 [Andrea Leadsom MP]
111 Q135 [Chris Clarke]
113 Q142 [Dr Rotheray]
116 Competition and Markets Authority, a non-ministerial Government department responsible for improving market competitiveness
118 , The Guardian, 20 August 2014
15 June 2016