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This project uses the global TIMES Integrated Assessment Model in UCL (‘TIAM-UCL’) to provide robust quantitative insights into the future of natural gas in the energy system and in particular whether or not gas has the potential to act as a ‘bridge’ to a low-carbon future on both a global and regional basis out to 2050.

We first explore the dynamics of a scenario that disregards any need to cut greenhouse gas (GHG) emissions. Such a scenario results in a large uptake in the production and consumption of all fossil fuels, with coal in particular dominating the electricity system. It is unconventional sources of gas production that account for much of the rise in natural gas production; with shale gas exceeding 1 Tcm after 2040. Gas consumption grows in all sectors apart from the electricity sector, and eventually becomes cost effective both as a marine fuel (as liquefied natural gas) and in mediumgoods vehicles (as compressed natural gas).

We next examine how different gas market structures affect natural gas production, consumption, and trade patterns. For the two different scenarios constructed, one continued current regionalised gas markets, which are characterised by very different prices in different regions with these prices often based on oil indexation, while the other allowed a global gas price to form based on gas supply-demand fundamentals. We find only a small change in overall global gas production levels between these but a major difference in levels of gas trade and so conclude that if gas exporters choose to defend oil indexation in the short-term, they may end up destroying their export markets in longer term. A move towards pricing gas internationally, based on supply-demand dynamics, is thus shown to be crucial if they are to maintain their current levels of exports.

This briefing is based on two propositions.

First, that gas security matters, because today in the UK gas plays a dominant role in the provision of energy services, accounting for almost 40% of total inland primary energy consumption in 2017. Thus, a short run failure of gas security would undoubtedly have significant political and economic consequences.

Second, that the current measure is far too narrow to offer a comprehensive assessment of UK gas security, particularly in a post-Brexit context. Discussions at the Gas Security Forum suggested that: the measure of gas security focuses only on infrastructure capacity and not supply (capacity does not equal flow); it fails to take account of the time-lag for gas delivery; it does not measure diversity or spare capacity; it ignores the impact of multiple asset failures; and, does not consider the costs associated with ensuring greater security.

It is in this context that this paper seeks to address the following questions:

• What are the constituent factors to consider in assessing gas security?
• What alternative measures exist?
• What potentially threatens gas security in the UK?
• What would a better approach to gas security look like?

The thinking behind this paper is that a more extensive approach to measuring UK gas security is needed to address the less dramatic challenges that face UK gas security, as well as the chance of managing a Black Swan event.

This report assesses the currently available evidence on the size of unconventional gas resources at the regional and global level. Focusing in particular on shale gas, it provides a comprehensive summary and comparison of the estimates that have been produced to date. It also examines the methods by which these resource estimates have been produced the strengths and weaknesses of those methods, the range of uncertainty in the results and the factors that are relevant to their interpretation.

This working paper considers the risks and opportunities posed to UK heat sector businesses by a potential transformation towards a low-carbon heat system in the UK. It is an output from the Heat, Incumbency and Transformations (HIT) project which is part of the UK Energy Research Centre programme.

The HIT project is investigating the idea of incumbency, considering what the term means, how it is present in the UKs heat sector and what the implications of incumbency are for the UKs potential transformation from a high carbon heat system to a low-carbon heat system.

The previous working paper developed a working definition of incumbency (Loweset al., 2017). This working paper forms the second phase of the project, exploring who the incumbents are in the UK heat system and the implications of the potential transformation for incumbents.

An online m

This briefing note summarises Great Britain’s local gas demand from the 2nd of April 2017 to the 6th of March 2018 and compares this to electrical supply. The data covers the UK cold weather event on the 1st March, providing insights into the scale of hourly energy flows through both networks.

A peak hourly local gas demand of 214 GW occurred at 6pm on the 1st of March, which compared to a peak electrical supply of 53 GW occurring at the same time.

The data highlights a critical challenge – managing the 3-hour difference in demand from 5am to 8am on the local gas network during the heating season. Whilst flexibility in the gas system is provided using a change in pressure to store extra energy in the network to meet increasing demand, the electrical system has no comparable intrinsic equivalent.

The findings add to previous work funded by UKERC on thermal energy storage , heat incumbency, and flexibility of electrical systems to provide insights into the decarbonisation of heat in Britain, helping to inform decision-making, modelling of future networks and highlighting key areas for future research and innovation.

A greater research and innovation focus to reduce the 5am-8am 3-hour difference in heat demand is necessary.

A briefing paper Dr Christophe McGlade and Professor Paul Ekins, UCL Institute for Sustainable Resources and UCL Energy Institute, University College London; Professor Michael Bradshaw, Warwick Business School, University of Warwick; and Professor Jim Watson, UK Energy Research Centre.

The research on which this brief paper draws was carried out by the UK Energy Research Centre (UKERC). The views expressed are those of the authors, rather than of any institution to which they may be affiliated.

Two recently published reports (McGlade & Ekins (2015), McGladeet al.(2014)) examine possible futures for fossil fuels, with a particular focus on the bridging role that natural gas may be able to play during a transition to a global low-carbon energy system. A related report (Bradshawet al.2014) considers the UKs global gas c

This briefing note describes the amount of gas contained within Great Britain’s gas transmission and distribution networks, and how this changes over a day to support variations in demand. The hourly data covers the 63-month period from 2013-01-01 to 2018-03-07.

The amount of gas contained within the higher-pressure tiers of Britain’s gas transmission and distribution network is termed ‘linepack’; literally, it is the amount of gas packed into the pipelines.

Linepack is proportional to the pressure of the gas in the pipelines, increasing the pressure increases the amount of gas, and thus the energy contained therein. The amount of linepack changes throughout the day due to the varying levels of pipeline pressure. This flexing of pressure provides a method to help match the supply and demand for gas within a day.

The scale of energy that can be stored and released by varying linepack highlights its importance as a means of operational flexibility, helping to balance the changes in national primary energy demand.

The scale of the within-day flexibility currently provided by the natural gas transmission and distribution networks points to a formidable energy systems challenge; how to provide low-carbon within-day flexibility to future energy systems at a reasonable cost.

To recover the cost of energy policies which support the transition towards a low carbon energy system, levies are applied to household and business energy bills. This briefing note focuses on the levies applied to households.

Household energy policy costs

Energy policy costs are applied to household electricity and gas bills, equating to 132, or 13% of the average energy bill in 2016. This research highlights how low-income households are hit hardest by the current arrangements as the poorest households spend 10% of their income on heat and power in their homes, whereas the richest households only spend 3%, so any increase in prices hits the poor disproportionately.

Energy service demands in the UK

Household electricity and gas use represents only 12% of total final UK energy use. Total energy use includes all the energy used to provide househ

Natural gas plays a critical role in the UK’s energy system, providing twice as much energy as electricity, thus the secure and affordable supply of natural gas is an essential element of UK energy security and a key objective of Government policy. The starting proposition for this report is that Brexit is coming at a time when there are already major challenges to the UK’s future gas security.

This report deploys two aspects of previous UKERC research on UK gas security: first, a supply chain approach to assessing UK gas security; and second, a whole systems approach that places current and future gas demand within the context of the decarbonisation of the UK’s energy system. This is because there are key uncertainties in the wider system that have important implications for future gas demand. It is in this context that the Brexit decision has created additional uncertainty at a time when the UK energy sector needs to make critical investment decisions. In the current situation we can conceive of a ‘Brexit Interregnum’ whereby important decisions and policies are delayed because of the demands of the Brexit negotiations.

This report has three objectives:

• To identify the key challenges facing the UK’s natural gas market;
• To understand the role that EU policies and institutions currently play in the operations of the UK’s natural gas market; and,
• To identify the potential impact of Brexit and the key issues that should be addressed in a post-Brexit ‘UK Gas Security Strategy.’

Midstream Infrastructure

The Midstream Infrastructure briefing considers the critical infrastructures - both hard and soft - that are necessary to link gas suppliers to end users. In many ways this is the most complex, least studied and most important part of the UK's gas supply chain. This briefing describes the various elements of the Midstream, assesses their current status, considers the potential impact on Brexit, and the challenges they pose in relation to future UK gas security.

The key challenge that the Midstream has to manage is the strong seasonality of UK gas demand, which is driven largely by winter demand for domestic heating. However, in recent years the growth of low-carbon generation (wind and solar) has introduced the additional complexity of intermittency, which is resulting in swings in gas demand on a much shorter time-frame. This is a challenge that is only going to increase in the future as coal-fired generation closes (by 2025) and intermittent low-carbon generation continues to grow.

The Future Role of Gas

The majority of studies of energy security focus on upstream security of supply. More recently, as the low-carbon transition has gathered momentum, there has been increasing interest in security of future demand as a challenge to the integrity of the gas supply chain. 

This briefing is divided into five sections. The first section examines the current role of natural gas in the UK energy mix, as well as recent trends in power generation. The second section reports on recent research by UKERC on the future role of gas in the UK. The third section examines what National Grid’s (2017a) most recent Future Energy Scenarios have to say about the future role of gas. The fourth section reviews other industry analyses about the future role of gas. The fifth, and final section, examines the ways in which Brexit complicates the situation. The briefing concludes by highlighting the policy challenges in relation to future

This briefing reports the findings of the first UK Gas Security Forum, which brings together a range of stakeholders
from government, business, think-tanks and academia to consider the impact of Brexit on the UK gas industry. The aim of the Forum is to inform the Brexit negotiations and the formulation of a Post-Brexit UK Gas Security Strategy.

The Forum builds on previous research funded by UKERC on:The UKs Global Gas Challenge(Bradshaw et al. 2014) andThe Future Role of Natural Gas in the UK(McGlade et al. 2016). The approach adopted combines a supply chain analysis of energy security with a whole system approach, that places gas security within the wider context of the decarbonisation of the UK energy system. In keeping with the wider framing of UK energy policy within the energy trilemma, it is assumed that a future UK gas strategy must de

The report also focuses on the broadly ‘physical’ factors that may restrict the rate at which conventional oil can be produced, including the production profile of individual fields and the distribution of resources between different sizes of field. While these are invariably mediated by economic, technical and political factors, the extent to which increased investment can overcome these physical constraints is contested. Global oil supply is also influenced by a much wider range of economic, political and geopolitical factors (e.g. resource nationalism) and several of these may pose a significant challenge to energy security, even in the absence of ‘below-ground’ constraints. What is disputed, however, is whether physical depletion is also likely to constrain global production in the near-term, even if economic and political conditions prove more favourable. In practice, these ‘above ground’ and ‘below ground’ risks are interdependent and difficult to separate. Nevertheless, this report focuses primarily on the latter since they are the focus of the peak oil debate.

The report does not investigate the potential consequences of supply shortages or the feasibility of different approaches to mitigating such shortages, although both are priorities for future research.

This response is largely based on research carried out within the UKERC project: The Geopolitical Economy of Global Gas Security and Governance: Implications for the UK. It also draws on UKERC’s energy system modeling research which has explored the changes that are necessary to meet the UK’s climate change targets.

The gas and electricity sectors feature many different actors that interact in different ways, through commercial arrangements and physical transfers of energy. The activities of the larger actors – generators, suppliers, gas shippers, and network owners and operators – are regulated through various licences.

There is then a raft of standards and codes that govern the interfaces between the actors and many of the characteristics of equipment that is connected to the networks. Most of these documents were established when the gas and electricity sectors were first liberalised in the late 1980s and early 1990s. Although a number have seen various revisions since then, many industry observers have argued that they are out of step with technological and market developments and difficult to change.

This document contains the UKERC response to the 2019 consulation by BEIS/Ofgem about how and why the codes might be revised.

The west of Shetland region is physically a very different environment to the Gulf of Mexico, so environmental impact of a deep water spill in this area would be different, in many aspects.

A regulatory system could be enacted to compel companies to develop a shareddeep-water rapid response system to cap wells, and the levels of insurance cover companies are obliged to have could be increased.

The UKs regulatory system is robust but could be improved, though there is a limit to which increased regulation can be implemented and effective.

Scenarios which may reduce the need to exploit deepwater reserves during the transition to a low carbon economy are discussed. However, given our current reliance on oil and gas, such exploitation may be necessary.

Under free market regulations the contribution of deepwater reserves to security of supply may be limited, though there may be some economic benefits of exploitation

This UKERC working paper reviews the literature on modelling natural gas demand and supply. This includes modelling natural gas markets in isolation, and as part of its role in the wider energy system.

This review is part of the work on a new, global gas model at the Institute for Sustainable Resources at University College London, through a UKERC PhD Studentship. The focus of the new model is on global gas production and trade, and its coupling with the TIMES Integrated Assessment model at University College London (TIAM-UCL) to represent gas demand.

Trade-offs: simplifying complexity without diverging from reality

The main section of this working paper provides a review of existing methods which model both supply chain and demand dynamics of natural gas (Part 1: recoverable volumes and corresponding costs of natural gas; Part 2: wider energy-system models; Part 3: natural gas market models). As with any modelling, it was found that there is always a trade-off between necessary simplifications, and the uncertainties and complexities which surround energy-economic-environmental systems.

In Part 1, this paper reviews a range of studies that have estimated recoverable volumes of natural gas. This includes both deterministic (e.g. a single point estimates of natural gas) and stochastic (e.g. probabilistic estimates including ranges of uncertainty) modelling methods, and the strengths and limitations of the approaches employed. The overall conclusion is that some level of probabilistic assessment is required when estimating recoverable volumes of natural gas and the cost range of extraction, particularly given the huge uncertainties inherent in the development of these resources (techno-economic, geological, environmental).

A key contribution of this review, in Part 2, is how natural gas is represented in energy system and integrated assessment models. This represents how gas supply and demand dynamics are also driven by wider developments in energy and environmental systems. Standalone natural gas models, described in Part 3, include gas market complexities. These have more disaggregated time-slices/temporal horizons in order to capture seasonality and the interaction between market agents. However, there is a trade-off between the temporal disaggregation, and the overall scope of the model. In short, the decision to take gas consumption from TIAM-UCL yields the benefit of a whole systems approach in the long-run, whilst limiting seasonal disaggregation in the short-term.

Introducing a new bottom-up global natural gas production and trade model

In section III, the paper introduces a new natural gas production and trade model, which is linked to TIAM-UCL. This linkage includes an aggregation of supply cost curves from a field-level gas volume and cost database, into the regions in TIAM-UCL. The gas model is able to account for aspects of gas markets which TIAM-UCL does not have in its architecture; e.g. fiscal regimes, take-or-pay contracts, price indexation.

Given the proprietary nature of cost data for natural gas extraction, a linear regression model was used to assign supply costs (the capital and operating expenditures required to get the gas out of the ground) to gas fields where no public information was available. This gas model aims to provide insights by quantifying various parameters which determine supply costs for individual natural gas fields, both developed and undeveloped; these include water depths, reservoir depths, the levels of hydrogen sulphide or carbon dioxide, and assumed risks to investment (e.g. due to location, political conditions, etc.).

The combination of the two models is intended to model scenarios, providing new insights into future natural gas price formation mechanics and longer-term policy developments which could alter/influence supply and demand.

A multi-time period combined gas and electricity network optimisation model was developed. The optimisation model takes into account the varying nature of gas flows, network support facilities such as gas storage and the power ramping characteristics of electricity generation units. The combined optimisation is performed from an economic viewpoint, minimising the costs associated with gas supplies, linepack management, gas storage operation, electricity generation and load shedding. It is demonstrated on two case studies, a simple example, and on the GB network.

The RIIO (Revenue=Incentives+Innovation+Outputs) model, introduced in 2013, is designed to ensure that payments to companies running the gas and electricity transmission and distribution networks are fair to network users and permit the recovery of reasonable costs in developing, maintaining and operating the networks.

The network licensees allowed revenue is linked to their performance and should therefore offer them incentives for securing investment, driving innovation and delivering the service that customers expect. However, some commentators have suggested that the licensees have been making unjustified profits. With network charges making up around a quarter of the average household energy bill, it is anticipated that the new price control framework will be tougher and provide lower expected returns for networklicensees.

The RIIO-2 frameworkconsultation is welcome. Ofgems final view on price control allowances will be published by the end of 2020 with the new network price controls ('RIIO-2') due to be implemented in 2021.

In our submission we respondedto the individual points raised in the call. We also note the following:

We support the proposal to reduce the price control period from 8 to 5 years. The energy system is undergoing unprecedented change, not only with continued transformation of the generation background but also major changes to the way electricity is used, such as for transport and heating. However, the rate and precise locations of these changes is uncertain. A shorter price control period will provide the opportunity for incentives and cost recovery to be adapted to the changing circumstances.

Maintenance of acceptable levels of reliability while facilitating the energy system transformation at least cost requires substantial innovation in technologies, business processes and commercial arrangements. The development of new innovations and associated benefits to consumers often takes years to be realised, sometimes beyond a price control period in which network company shareholders would expect a return. We therefore support the proposal to retain dedicated innovation funding but encourage greater clarity on the scope of activities that can make use of such funding and on best practice in the generation and dissemination of evidence on proposed innovations.

We welcome moves to increase the accountability of the network companies and would urge Ofgem to concentrate on those measures that have a genuine and positive impact on the network companies activities in the context of the whole energy system. We note that thisis not restricted to the business plans submitted under RIIO-2 but extends to a whole raft of codes and interactions. These include the evolving responsibilities of the Electricity System Operator (ESO), the relationships between the ESO, the transmission owners and the Distribution Network Operators, and the processes for ensuring that the full set of codes, standards and market arrangements are coherent and fit for purpose. This is a challenging task that requires constant attention to the big picture and sufficient resources, commitment and expertise on the part of the network owners, system operators and Ofgem.

In applying tighter controls that avoid excessive returns to the network licensees owners, the upside and downside risks should be clearly assessed and incentives for managing risk placed on those parties best placed to do so.

Pathways that are consistent with legislated net zero targets are likely to see highly significant changes to demand for electricity. When these changes will start to take place and how quickly is uncertain, which leads to challenges when setting price controls. Key elements to circumnavigate this will be flexibility and scenario planning.

The need for network reinforcement can be reduced by the appropriate use of flexibility, e.g. in the timing of EV charging. However, the means by which different sources of flexibility might be encouraged and then utilised are still immature and it is not yet clear which will actors prove to be the most significant and efficient in providing services.

Flexibility can only go so far in helping meet power supply needs; at some point, network capacity often proves the most cost-effective means, especially when considering its reliability and lifetime, and the opportunities provided by asset replacement. The triggering of investment in network assets presents an opportunity not just to meet the immediate need or that forecast for the next few years, but to provide for the maximum transfer that can be envisaged throughout the path to net zero. This is likely to be cheapest for consumers over the longer term as the incremental cost of additional electrical capacity is small relative to the total cost of aproject, it avoids the need for repeated interventions, andit saves on the long-term cost of network losses.

Ofgem has noted in the consultation document that some form of scenario planning of investment is likely to be needed. A number of scenarios should be developed that encompass key uncertainties but are consistent across Britain in respect of the whole, multi-vector system, and associated assumptions.

There should be engagement with Local Authorities and other stakeholders to develop regional plans of future energy needs, such as a Local Area Energy Plan. This engagement is important as local, regional, or devolved administration policies as well as different geographies and starting points can drive different actions.

Innovation is a long-term process and uncertainty is inherent to it there is always the potential for unforeseen things to arise. What this means for the energy system is that:

1. Withinaportfolio of innovations, some will realise the intended benefits, but some will not.
2. Where benefits are realised for energy users, they will, in general, take time to accumulate.

Where there is uncertainty about the effect or cost of new practices or technologies on an energy system and its users who ultimately pay but also benefit from innovations that are adopted it is reasonable for those users to share the risk by sharing the cost of resolution of the uncertainties. However, arguments might be made that costs should be shared not by energy system users, i.e. its customers, but by taxpayers, e.g. through funding by UKRI.
A less than perfect set of arrangements for the sharing of costs between different parties should be accepted if that is what is necessary to support R&D capacity, address risks, and drive innovation. Moreover, the amount of network customers money that is being proposed in RIIO-ED2 to support innovation is modest compared with the network companies total expenditure and the benefits that will accrue to customers and society as a whole in the energy system transition.

Good governance and good practice on the part of network licensees is essential to ensure that customers money is used effectively. In particular, we agree with Ofgem that data transparency associated with network innovation projectsneeds to be much improved.

In order that the scope of Network Innovation Allowance (NIA) funding is not set too narrowly, we think it important to have a clear understanding of what a successful energy system transition involves. We include in our response a first draft of a definition and include recommendations for the threshold that projects must meet to be funded.

Summary: The greatest challenges faced by Distribution Network Operators (DNOs) in forming investment plans relate to the gathering and use of information with suitable levels of spatial and temporal detail. Access to smart meter data should help, but innovation will be required to turn data into useful information.

A final observation is that it is important for the UKs economy as a whole that the UK has the capacity to undertake research and development, to innovate, and to generate evidence in order to drive the commercial viability of ideas

UKERCs 2017 Review of Energy Policy, appraises energy policy change over the last 12 months, and makes a series of recommendations to help meet the objectives of the governments Clean Growth Plan.

Our main recommendations are:

1. ‘Develop a strategy to avoid ‘cliff edges’ for the energy sector due to Brexit, including effects on interconnectors, the single electricity market for the island of Ireland, and nuclear power.
2. A White Paper that includes stronger incentives for energy efficiency across the economy, and an enhanced programme of low carbon heat demonstration and evaluation.
3. Learn from the success of offshore wind by extending competitive auctions in the power sector.
4. Minimise the costs of electricity system change and renewables integration by increasing incentives for flexibility.
5. Complement the additional funding for CCS innovation with a new strategy for deployment in the industrial and power sectors.
6. Ensure that vehicle taxation and other incentives are compatible with the target for phasing out new conventionally fuelled cars and vans by 2040. This should be complemented by a wider strategy for mobility that takes into account anticipated new services and business models.
7. A more comprehensive programme of action to involve citizens and communities in the clean energy transition, building on ‘Green Great Britain Week’.
8. Identify opportunities for energy policy learning across the UK – particularly in the areas of heat, engagement and energy efficiency.

1. The transition to net-zero will affect the whole economy. Investment and policy decisions by all government departmentmes need to be compatible with this transition.
2. Policies to support renewable electricity generation should be more ambitious, building on deployment and cost reduction successes. Action is also needed to ensure electricity market rules are fit for a fully decarbonised power sector.
3. Decisions by the energy regulator, Ofgem, should also be compatible with net-zero. This includes enabling investment in local electricity networks to facilitate heat and transport decarbonisation, and ensuring more active use of existing networks.
4. Local energy systems could play a significant role in achieving net-zero, particularly in the integration of electricity, heat and transport. More resources and greater powers for Local Authorities will help to ensure the potential for local action is realised.
5. A clear plan is required for upgrading the UK housing stock. A heat and energy efficiency White Paper must include policies for widespread deployment of low carbon heat (including demonstrating hydrogen at scale) and for prioritising low income households.
6. Whilst the decarbonisation of industry is receiving more attention, policy initiatives are not joined up. Funding for specific projects and industrial clusters should be complemented by market creation policies, including for carbon capture and storage.
7. Our analysis shows that achieving net-zero requires the phase out of fossil-fuelled vehicles to be brought forward to 2030. Immediate action is also required to counter the rapid increase in sales of larger cars (including SUVs).
8. Plans to meet net-zero should maximise environmental co-benefits. Potential negative impacts on ecosystems should be assessed and mitigated.
9. Continuing uncertainty about the UK’s changing relationship with the European Union has already affected decarbonisation plans. Whatever the outcome, close co-operation with the EU is likely to make it easier to achieve net-zero.
10. The transition to net-zero should not compromise energy security. In light of the events on August 9th, responsibilities for ensuring system resilience need to be clarified and applied in a more rigorous way.

With a focus on gas and the UK continental shelf, industrial decarbonisation, heat, mobility and the environment, we look at developments both at home and internationally and ask whether the UK is a leader in decarbonisation, and if the transition is being managed as well as it could be.

As we reach the end of 2018, the scorecard for UK energy policy is mixed. Optimists can point to rapid emissions reductions, cost falls in renewables and the centrality of clean energy within the Industrial Strategy. Ten years after the Climate Change Act was passed, UK greenhouse gas emissions have fallen by 43% from the level in 1990. The UK is on the way to meeting the first three carbon budgets, and a transformation of the power sector is well underway.

However, if we turn our attention from the rear view mirror, the outlook is more pessimistic. As the Committee on Climate Change pointed out in June, there are an increasing number of policy gaps and uncertainties. If not addressed promptly, meeting future carbon budgets will be much more challenging. For some of these gaps, there is a particularly clear and immediate economic case for action.

Key recommendations:

The government needs to take urgent action to ensure that the UK continues to meet statutory emissions reduction targets, and goes further to achieve net zero emissions. This not only requires new policies to fill looming gaps in the portfolio, it also requires much greater emphasis on sharing the benefits and costs of the low carbon transition more equitably. Our main recommendations are:

1. We repeat our call for a heat and energy efficiency White Paper, and recommend that the Industrial Strategy mission to reduce building energy use is extended to existing buildings.
2. A better, more targeted approach to the energy needs of low-income households is required. Energy efficiency investment for these households should be funded via general taxation.
3. Urgent large-scale trials of heat decarbonisation using hydrogen are required to understand whether it could be technically, economically and socially viable.
4. A dashboard of indicators is needed to monitor gas security during the energy transition. The current one dimensional approach is not sufficient.
5. Future electricity policy should build on the Electricity Market Reform policies that have worked well, and adapt them in the light of changes in technologies and costs.
6. Changes in incentives for ‘black start’ and other ancillary services are necessary to ensure that the electricity system remains resilient as it changes.
7. The target for phasing out conventionally fuelled vehicles is inadequate and does not fit with our emissions targets. The 2040 date should be brought forward and linked to accelerated investment in networks and charging.
8. The Industrial Strategy needs to be strongly linked to market creation policies for low carbon technologies. Carbon capture and storage is in particular need of such policies to progress beyond its current holding pattern.
9. To ensure widespread support for the energy transition, there needs to be more focus on equity and justice. The UK government should consider setting up a process similar to Scotland’s Just Transitions Commission to achieve this.
10. Continued vigilance is required to mitigate any negative impacts of Brexit, particularly those that could affect integration with European energy markets.

This review takes stock of UK energy policy ahead of the Autumn Statement, Industrial Strategy and new Emissions Reduction Plan. Its main recommendations are:

1. An integrated, evidence based approach to the new Industrial Strategy and Emissions Reductions Plan. The Industrial Strategy should set out clear priorities and the mechanisms for realising benefits for the UK
2. A new White Paper on Heat and Energy Efficiency
3. A Gas by Design approach to the future of gas that is compatible with carbon budgets and targets
4. A new approach to CCS commercialisation and deployment, in response to the Oxburgh report
5. An extension of the Levy Control Framework beyond 2020, and plans for auctions that include most large-scale electricity technologies and demand reduction in a single auction
6. Reform of the Capacity Mechanism so it gives equal

• Negotiations over the terms of ‘Brexit’ are likely to be lengthy, complex and difficult. Energy is one policy area in which it may be easier for the UK and future EU27 to find common ground

• Energy cooperation over the past decades has helped European countries to enhance their geopolitical security, respond to growing climate threats, and create a competitive pan-European energy market. Maintaining close cooperation in this field, and the UK’s integration in the European internal energy market (IEM), will be important for the UK and the EU27 post-Brexit.

• Strong UK–EU27 energy cooperation could help ensure that existing and future interconnectors – physical pipes and cables that transfer energy across borders – between the UK, Ireland and the continent are used as efficiently as possible. As European economies, including the UK, look to decarbonize further, interconnectors will help minimize the costs of operating low-carbon electricity systems, and help lower electricity prices for UK consumers.

• The UK and the EU27 have identified the special relations between the UK and the Republic of Ireland as a priority for negotiations. Any future agreement needs to maintain the Single Electricity Market (SEM) across the island of Ireland, as failure to do so could result in an expensive duplication of infrastructure and governance.

• EU funds and European Investment Bank (EIB) loans account for around £2.5 billion of the UK’s energy-related infrastructure, climate change mitigation, and research and development (R&D) funding per year. Replacing these sources of finance will be necessary to ensure that the UK’s energy sector remains competitive and innovative.

• The UK intends to leave Euratom, the treaty which established the European Atomic Energy Community and which governs the EU’s nuclear industry. This process – dubbed ‘Brexatom’ – will have a significant impact on the functioning of the UK’s nuclear industry, particularly in respect to nuclear material safeguards, safety, supply, movement across borders and R&D. Achieving this within the two-year Brexit time frame will be extremely difficult. The UK will need to establish a framework that it can fall back on to ensure nuclear safety and security.

• Remaining fully integrated with the IEM would require the UK’s compliance with current and future EU energy market rules, as well with some EU environmental legislation. The UK government, British companies and other relevant stakeholders will need to maintain an active presence in Brussels and European energy forums, so that constructive and informed engagement can be sustained.

• Without a willingness to abide by the jurisdiction of the European Court of Justice (ECJ), and in the absence of a new joint UK–EU compliance mechanism, the UK may be required to leave the EU Emissions Trading System (ETS) – an instrument in the UK’s and EU’s fight against climate change. Leaving the ETS would be complicated, even more so if the UK leaves before the end of the ETS’s current phase (2013–20). To maintain carbon pricing in some form outside of the ETS, the UK would need to either establish its own emissions trading scheme, which would be complicated and time-consuming; or build on the carbon floor price and introduce a carbon tax. Either of these potential solutions would need political longevity to be effective.

• It is in both the UK’s and the EU27’s interests for the UK to continue to collaborate on energy policy with EU and non-EU member states. The best way to achieve this would be to establish a robust new pan-European energy partnership: an enlarged European Energy Union. In particular, such a partnership could offer a useful platform for aligning EU policies with those of third countries, including the UK, Norway and Switzerland, while allowing them to fully access the IEM and push forward common initiatives. Experience suggests that the EU27 would be more receptive to working within an existing framework or multilateral approach (as with the European Energy Community) than to adopting a bilateral approach (as the EU currently does in its energy relations with Switzerland).

Novel analysis from this paper shows that while gas-linked revenues accounted for 90% of generation and two-thirds of total costs in 2024, this is expected to fall to 60% and just under half of costs by 2028.

Three years after the energy crisis, residential electricity prices in the UK 2025 are still historically high, and the UK is amongst the highest priced countries for electricity. This paper finds that bills have risen by £150 in real terms since 2021, and that £112 of this increase is due to higher wholesale market prices driven largely by gas.

Britain's electricity system is also going through a profound change. As the share of output with a fixed price contract or CfD rises, the role of gas generation in setting household prices will fall, since increasing volumes of generation will be delinked from gas prices. Novel analysis from this paper shows that while gas-linked revenues accounted for 90% of generation and two-thirds of total costs in 2024, this is expected to fall to 60% and just under half of costs by 2028.

However, this 'automatic' reduction in the share of gas prices in bills is limited in effect by the volume of renewable generation receiving a CfD that is at or below the wholesale price. The authors argue that going further to reduce bills requires action on policy costs. They therefore recommend UKERC's Pot Zero proposal which targets the most substantial policy cost on bills (at £102): the Renewables Obligation (RO). Moving RO-supported projects onto CfDs could deliver consumer savings of £2-8 billion per year in the late 2020s, equivalent to £20-80 per consumer.

Key messages:

In future work, UKERC's Whole Systems mission will explore options to help hold CfD prices down, reduce the costs of curtailment, minimise the costs of network upgrades and refurbishment, and mechanisms to reallocate costs between categories of consumer, for example, through tariff reform.

Energy security is a central goal of energy policy in most countries and with rapid changes occurring throughout the UK energy sector, it remains high on the policy agenda. Recent concerns about UK gas supplies - highlighted by National Grid's gas deficit warning demonstrated just how fundamentally important it is to have a reliable energy system.

Using a number of indicators, ‘The Security of UK Energy Futures’ assesses aspects of security such as energy availability, reliability, sustainability and affordability to examine how energy security risks will change over time

The report draws three main conclusions:

1. There is an important role for energy efficiency and energy demand reduction in energy security strategies; by reducing our energy demand we reduce exposure to risks such as price shocks and energy shortages.
2. The relationship between decarbonisation and energy security is not straightforward. Energy imports are often cited as being insecure, however this can be controversial. Imports can help enhance security by providing additional sources of energy, by lowering costs, or by increasing diversity. What matters most is where the imports are from and whether they are dominated by risky sources or supply routes.
3. Many of the risks can be mitigated; security of the electricity and gas system can be improved significantly by investing in system flexibility. Increasing demand side response has a particularly positive impact on system reliability.

A UKERC Research Report exploring the UK's global gas challenge. This report takes an interdisciplinary perspective, which marries energy security insights from politics and international relations, with detailed empirical understanding from energy studies and perspectives from economic geography that emphasise the spatial distribution of actors, networks and resource flows that comprise the global gas industry.

Natural gas production in the UK peaked in 2000, and in 2004 it became a net importer. A decade later and the UK now imports about half of the natural gas that it consumes. The central thesis of the project on which this report is based is that as the UK’s gas import dependence has grown, it has effectively been ‘globalising’ its gas security; consequently UK consumers are increasingly exposed to events in global gas markets.

UKERC research highlights ‘lack of a clear vision of the future role for gas’ in the UK’s energy system, and cautions that, without CCS, a second ‘dash for gas’ could compromise decarbonisation ambitions. Please download the report using the button above.

The UK Energy Research Centre (UKERC) has provided research and analysis across the whole energy system since 2004, with funding provided by the Research Councils through a succession of five year phases. Research related to low carbon heat became a significant focus during Phase 3 (2014 2019) and the current Phase 4 includes a research theme devoted to decarbonisation of heating and cooling, with several of our other themes providing relevant insights. Our whole systems research programme addresses the challenges and opportunities presented by the transition to a net zero energy system and economy.

In this submission we address specific consultation questions where UKERC evidence and analysis provides us with relevant insights. In addition there are a number of high level observations that we provide in these introductory remarks.

Overall, we are concerned that the measures outlined in the consultation need to be set within a coherent and ambitious package of policies that work together to drive the UKs transformation to sustainable heating at a rate commensurate with the goal of net-zero by 2050. While we appreciate there are some uncertainties over the future role of the gas grid and the potential for hydrogen for heating, immediate progress in heat system decarbonisation is clearly required as part of this multi-decadal transformation. As the consultation notes, heat pumps offer a low regrets option in some applications and it is widely acknowledged that the UK has a small supplier base and very low level of heat pump deployment compared to many countries. Increasing consumer and installer familiarity, and growing the skills base and supply chain all feature strongly in the process of learning by doing that reduces heat pump costs. Ifheat pump deployment were to proceed linearly to 2050 in line with some scenarios for deployment, annual installations would need to increase by an order of magnitude. Whilst welcome, the current proposals are not sufficient to deliver a large scale market for heat pumps. Ambition and clarity of purpose are essential if heat system decarbonisation is to succeed. We also stress the importance of providing support to support the development of large low carbon heating systems, including systems attached to heat networks. We appreciate that the provisions laid out in the consultation pertain only to specific schemes and note the observations made in the consultation about support for heat networks.

Alongside the required policy changes necessary to support specific heating technologies, wider governance changes will be needed to drive the UK transformation to low carbon heating.Whilst regulation and other forms of financial support for building efficiency improvement are noted in the consultation, we note that it is likely to be important to use sticks as well as carrots if the highest carbon heating systems are to be removed and building efficiency increased. However, it will also be important to consider ownership and regulation of heat networks, the role of local authorities and opportunities for innovation that may be unlocked through regulatory change such as encouraging electricity suppliers to offer smart heating tariffs or enabling community ownership of heat distribution schemes.

While we appreciate these issues are beyond the scope of the current consultation, it is important that these considerations inform policy choices made now.

This UKERC Research Landscape provides an overview of the competencies and publicly funded activities in oil and gas research, development and demonstration (RD&D) in the UK. It covers the main funding streams, research providers, infrastructure, networks and UK participation in international activities.

UKERC ENERGY RESEARCH LANDSCAPE: OIL AND GAS

• Section 1: An overview which includes a broad characterisation of research activity in the sector and the key research challenges
• Section 2: An assessment of UK capabilities in relation to wider international activities, in the context of market potential
• Section 3: Major funding streams and providers of basic research along with a brief commentary
• Section 4: Major funding streams and providers of applied research along with a brief commentary
• Section 5: Major funding streams for demonstration activity along with major projects and a brief commentary
• Section 6: Research infrastructure and other major research assets (e.g. databases, models)
• Section 7: Research networks, mainly in the UK, but also European networks not covered by the EU Framework Research and Technology Development (RTD) Programmes
• Section 8: UK participation in energy-related EU Framework Research and Technology Development (RTD) Programmes
• Section 9: UK participation in wider international initiatives, including those supported by the International Energy Agency

The dispute between optimists and pessimists over the future of global oil supply is underpinned by equally polarised disagreements over a set of more technical issues. Given the complexity and multi-dimensional nature of this topic, the existence of such disagreements is unsurprising. However, the situation is made worse by the inadequacy of the publicly available data and the scope this creates for competing views and interpretations. Improved data on individual fields could go a long way towards resolving such disagreements, but this seems unlikely to become available in the foreseeable future. Nevertheless, there is potential for increasing the degree of consensus in a number of areas and some progress has already been made. This report looks in more detail at two of these issues, namely:

• Decline rates: how rapidly the production from different categories of field is

The primary objective of this report is to describe and evaluate these different methods. Primary attention is paid to the methods based upon the extrapolation of historical trends, since these are widely used by the analysts concerned about global oil depletion. A second objective is to summarise and evaluate the estimates that have been produced for the global URR of conventional oil and to assess the implications for future oil production. Of particular interest is the relative plausibility of the optimistic and pessimistic estimates and the implications of both for medium-term oil supply.

This systematic review assesses the insight offered by thesemethodologies and critically evaluates their usefulness in projecting future oil production.It focuses on models that project future rates of oil production, and does not address themodeling or estimation of oil resources (e.g., ultimately recoverable resources, or URR).Models reviewed include the Hubbert methodology, other curve-fitting methods, simulations of resource discovery and extraction, detailed bottom-up models, and theoretical and empirical economic models of oil resource depletion. Important examples of published models are discussed, and the benefits and drawbacks of these models are outlined. I also discuss the physical and economic assumptions that serve as the basis for the studied models.

The models that have been reviewed for this study are described below. As far as possible, the same format has been used to describe each model, to facilitate comparison. Each description commences with a list of the more common basic input and output parameters, assumptions, definitions, components and data sources, and a statement of the type of model. Where appropriate, a brief comment on the model is included at this stage.

This report provides a detailed comparison and evaluation of fourteen contemporaryforecasts of global oil supply. The forecasts are based upon mathematical models ofvarious levels of complexity, embodying a wide range of modelling approaches andassumptions. In addition, the views of two oil companies on the likely adequacy of future oil supply are also summarised.

This report summarises several of the significant issues associated with oil production and reserve data. A fuller understanding of these issues provides a necessary basis for an objective examination of global oil depletion. The report addresses the subject in four sections:

• Definitions used within oil industry data are often a subject of confusion.
• The Data Sources commonly available are also discussed.
• Reserve Estimates are the most contentious data reported by the oil industry.
• Finally Production Data is examined in Section 5.

The major inconsistency between reserve definitions is the choice of either a deterministic or probabilistic methodology. Within the class of deterministic definitions, the terms proved, probable and possible are widely used, but the use of this language is not standardised. Various descriptive terms are used which have very subjective interpretations. Within the class of probabilistic definitions there is wide agreement that 90%, 50% and 10% probability levels are appropriate to specify when reporting reserve estimates. Where deterministic terms such as proved are specified in a way allowing retrospective evaluation of estimates, the actual use of the term may not match the corresponding probabilistic definition.

There is a large physical uncertainty in our estimate of the oil originally in place due to the impossibility of measuring physicaland geological characteristics of the reservoir sufficiently accurately. Further uncertainty is introduced in estimating how much is both technically feasible and economically viable to extract, and again when aggregating results for individual fields to large areas.

Probabilistic estimates are therefore the most appropriate, because the definitions themselves include an acknowledgement of uncertainty. Probabilistic definitions do not lessen the intrinsic physical uncertainty in making an estimate but they can eliminate the possibility of deliberate or accidental bias. Because probabilistic definitions allow retrospective evaluation of the accuracy of reserve estimates, errors in estimation can be identified. This level of accountability is not achievable with deterministic definitions.

The term reserve growth refers to the increase in the estimates of ultimately recoverable resources (URR) of known fields over time. Reserve growth has contributed significantly more to reserve additions than new discoveries over the past decade and is expected to continue to do so in the future. But despite the crucial importance of reserve growth for future global oil supply, it remains both controversial and poorly understood. There is a great deal of work to be done before reliable estimates of future reserve growth can be made. This entails both the collation of adequate and reliable fieldlevel data from which to extrapolate future reserve growth, and updating and refining the very rough and preliminary forecast made by the US Geological Survey (USGS), which remains the most comprehensive study to date. 'Unpacking' the definition of reserve growth down to its constituent elements reveals that there are a number of definitional issues still to be resolved, in particular regarding the definition of reserves themselves and what categories of oil should be included. For the purposes of estimating reserve growth, it must be clearly defined what categories of oil are considered as their growth characteristics may be different.

This submission focuses on the potential impact of shale gas production on the global gas industry. Firstly, it suggests that the rapid development of shale gas production in the United States (US) has had a significant impact as it has resulted in the loss of a major market for LNG exporters. Events in Japan post-Fukushima are also an important factor in explaining the current situation. Secondly, the very low price for gas in the US, as a result of shale gas production, is putting pressure on gas price formation, both in Europe in relation to long-term oil-indexed pipeline imports and in the Asia-Pacific region in relation to long-term oil-indexed LNG imports. However, the high-price of oil is also a key factor in the current debate over the future pricing of natural gas. To conclude, the potential for significant shale gas production is an important factor in the current uncertainty over the future of the global gas industry, but it is not the only factor at play and any assessment of shale gas must be made in the wider context of multiple uncertainties.

This response addresses the first two questions of the call for evidence on the impact of shale gas on energy markets: firstly what estimates exist for the amount of shale gas in place in the UK, Europe, and the rest of the world, and what proportion is recoverable; and secondly why estimates for shale gas are so changeable.

UKERC recently conducted a comprehensive review of 62 studies that provide original estimates of regional and global shale gas resources [1

• There are extremely ambitious technology deployment rates (for example for CCGT, heat pumps and electric vehicles) within some scenarios that could be challenging in reality and should therefore be subjected to stress testing.
• In addition to the need for appropriate investment signals, analysis should address the incorporation of a very active demand side and if the current arrangements can handle large amounts of intermittent generation supplying an elastic demand side.
• UKERC recommends that Ofgem consider a stress test that examines the loss of Norwegian gas supplies.

Steering Committee consisting of female representatives from key organisations in the NI heat sector, including the Department for the Economy, the Utility Regulator, a local renewable industry group (NIRIG), the transmission and distribution system operators (NI Electricity Networks and SONI), an energy charity (NEA Northern Ireland), the Consumer Council and a public affairs consultancy (Stratagem).