The pressing challenge of climate change, driven by escalating carbon emissions, necessitates urgent global action and innovative policy frameworks. Among various strategies, Emissions Trading Systems (ETSs) have emerged as a pivotal tool to mitigate greenhouse gas emissions while fostering economic efficiency. However, as countries strive to meet ambitious carbon neutrality targets, China faces a critical specific challenge: the integration and expansion of its nascent national carbon market (CN-ETS) amid the complexities of transitioning from the local carbon market (CL-ETS). And it was exacerbated by data inconsistencies and regulatory complexity. Despite the growing body of research on carbon markets, a significant knowledge gap persists regarding insufficient understanding of how multi-level carbon markets (local/national) can synergistically coexist to accelerate sectoral coverage while leveraging international policy pressures (e.g., Carbon Border Adjustment Mechanism (CBAM)). Our study employs Triangulated Institutional Analysis (policy archaeology, cognitive mapping, quantitative validation) of 346 documents and 22 expert interviews. Key findings reveal: (1) CN-ETS expansion is constrained by Measurement, Reporting, Verification (MRV) bottlenecks; (2) EU CBAM imposes a 2034 deadline for full CN-ETS maturity; (3) CL-ETS pilots retain vital u201Ctriple innovation functionsu201D (small and medium enterprise (SME) coverage, carbon finance, regulatory experimentation) under a dual-track coexistence model. We challenge three prevailing assumptions: u201Cdomestic priorityu201D (CBAM drives domestic reform), u201Csystem-firstu201D (local pilots enable national legislation), and u201Ctechnological determinismu201D (political mutual recognition trumps pure tech upgrades). Our framework offers emerging economies a strategic blueprint for carbon market integration under cross-border carbon pressures.

In this paper, we discuss electricity market design in Europe in light of the 2021-23 energy crisis, drawing on several of our Centre on Regulation in Europe (CERRE) reports. We outline the relevant theoretical background with respect to wholesale electricity markets, retail electricity markets, excess profits regulation, renewables support schemes and emergency interventions. We next outline the responses of the European Union, France, Norway, the Netherlands and Great Britain to the crisis. This allows us to make a number of recommendations about the future design of the electricity market in the light of theory and recent experience. These include a role for long-term contracts, the extension of the single market, the place for increased price granularity, appropriate energy taxation and the necessity of better monitoring of National Energy and Climate Plans to ensure adequate aggregate investment.

Competition usually increases firm productivity; but in network industries, effective competition requires vertical separation, which might reduce productivity and lead to a potential trade-off. We analyze the combined effect of competition and vertical separation on inefficient costs for US electricity industry restructuring. We estimate firm-level inefficiencies with the use of different nonparametric models of the technology and calculate net benefits with the use of difference-in-differences. The results depend on how we model the production technology and the length of the post-treatment horizon. The more flexible is the production frontier, the greater is the net benefit from divestiture and competition. Across our models the combined effect of divestiture and competition is positive.

There is a growing consensus that the distribution system operator (DSO) role is changing, given the implications of net zero. The transition process requires additional roles for the DSO in facilitating the new technologies and business models that will contribute to decarbonization. Although discussions on the active DSO abound, a working definition is still missing. This paper proposes a working definition and a methodology for measuring the extent to which a DSO is active. The methodology will be applied to electricity and natural gas DSOs in the UK, and the challenges will be presented and analyzed.

This paper examines how the likelihood of a transition to net zero could play out on the UK's total factor productivity growth over the longer term. It does this in the context of a potential trade-off between net zero goals and productivity growth. We begin by discussing the concept of green growth and a green industrial revolution, and then relate the green economy to the circular economy, as well as GDP measurement and how this relates to productivity growth under climate policies. We use a simulation method for the projected growth under net zero of the electricity sector in Great Britain to provide a context on the consequences of increasing input growth as output growth declines, and the result shows that the 2020s are challenging decades as productivity declines by -3.24 % p.a. in the electricity sector due to the combination of high input and low output growth. However, our findings reveal that the 2030s and 2040s look more promising, with productivity growth of 3 % p.a. and 1.6 % p.a. respectively as electrification increases and fossil fuel and labour inputs decline. Overall, the analysis offers a glimpse of just how challenging raising even maintaining the level of TFP will be in that sector in the earlier years out to 2050.

The paper uses a social cost benefit analysis (SCBA) approach to measure the effects of the power system reform starting from 2015 in Jiangsu province, China. We review the background of Jiangsu power system and summarize the implemented policies since the publication of “Document #9.” Then we pick the average industrial and commercial retail price and analyze the sources of price reductions. We show that the nominal industrial and commercial price fell by 21.3 percent between January 2012 and May 2021. We then analyze the likely overall welfare change facing industrial and commercial customers using SCBA and conclude that there is a permanent gain equivalent to 9.1% lower prices per year mainly because of the reform. This figure is a significantly more positive consumer gain than that calculated in previous SCBAs of electricity reform in other countries. JEL Classification: L94, Q48

In this paper we explore further how energy network regulation might better be adapted to the uncertainty challenges that are raised by net zero climate policy. We do this with specific reference to energy regulation in the UK. We discuss the drivers of change and the nature of the uncertainty that is faced by energy regulators. Next, we examine theories of dynamic/responsive/adaptive regulation for lessons that regulators can learn in the light of net zero. We look for regulatory learning from water regulators in Scotland and England and Wales and airport regulation in London. Drawing on evidence from a recent consultation with 41 stakeholder responses, we explore how energy regulation might need to change in the areas of planning, uncertainty mechanisms, regulatory incentives, financing arrangements, stakeholder engagement, innovation processes, and industry governance.

The gas industry in Great Britain has witnessed periodic regulatory reviews and large corporate reorganization over the last few decades. We assess how these changes have impacted total factor productivity growth using a data envelopment analysis (DEA) approach by setting out different models, each for gas transmission and distribution network. We also construct a combined single series for distribution and transmission using financial data to show whether productivity growth can be attributed to corporate reorganizations. Our results show a negative productivity growth of -1.6% p.a. for gas transmission over the sample period, but reversed to a positive TFP growth once quality is included. For gas distribution, we find productivity regress at -6.2% p.a. over the sample period, with a negative productivity trend observed across all the models, despite the inclusion of quality variables. However, the findings reveal a slightly higher productivity growth of 1% p.a. using corporate data, with pre-restructuring period having a positive productivity growth compared with the post-restructuring era with a negative productivity growth.

Russia's invasion of Ukraine has reaffirmed the importance of scaling up renewable energy to decarbonise Europe's economy while rapidly reducing its exposure to foreign fossil fuel suppliers. Therefore, the question of sources of flexibility to support a fully decarbonised European energy system is becoming even more critical in light of a renewable-dominated energy system. We developed and used a Pan-European energy system model to systematically assess and quantify sources of flexibility to meet deep decarbonisation targets. The electricity supply sector and electricity-based end-use technologies are crucial in achieving deep decarbonisation. Other low-carbon energy sources like biomethane, hydrogen, synthetic e-fuels, and bioenergy with carbon capture and storage will also play a role. To support a fully decarbonised European energy system by 2050, both temporal and spatial flexibility will be needed. Spatial flexibility, achieved through investments in national electricity networks and cross-border interconnections, is crucial to support the aggressive roll-out of variable renewable energy sources. Cross-border trade in electricity is expected to increase, and in deep decarbonisation scenarios, the electricity transmission capacity will be larger than that of natural gas. Hydrogen storage and green hydrogen production will play a key role in providing traditional inter-seasonal flexibility, and intraday flexibility will be provided by a combination of electrical energy storage, hydrogen-based storage solutions (e.g., liquid H2 and pressurised storage), and hybrid heat pumps. Hydrogen networks and storage will become more critical as we move towards the highest decarbonisation scenario. Still, the need for natural gas networks and storage will decrease substantially.

The widespread deployment of flexibility services e.g. by generators, energy storage units and demand response, are causing novel challenges to Distribution Network Operators (DNOs) or Distribution System Operators (DSOs) when managing their power systems. The aim of this research is to understand the economic impact that these flexibility services could cause on possible future world scenarios. This paper presents the main findings obtained from the MERLIN project, which explores and compares the techno-economic impact of managing network operational constraints through traditional reinforcement and flexibility services over a ten-year forecast period. Two case studies were carried out, the realistic case (RC), which focusess on realistic load and generation forecasts, and the worst-case (WC), which is what is traditionally performed by DNO system planners to model the impact of peak demand when generation is turned off over a period of time. The analysis was conducted on the 33/11 kV network in Fort William, (Western Scottish Highlands). The study revealed insights into the anticipated costs of traditional reinforcement and influenced when flexibility services would be a more favorable investment option. Results suggest that flexibility services are preferred only to deal with thermal constraints in the 33 kV line, with no or negligible savings in the 11 kV line. The results show discounted savings of around £175k for four year deferral (by 2050), equivalent to 12% of reinforcement costs.

The UK left the European single market in energy on 31 December 2020, having been a leading light in its promotion. It entered into a new energy relationship with the EU-27 as outlined in the EU-UK Trade and Cooperation Agreement (TCA) on 1 January 2021. This paper discusses what has happened to the UK energy sector since the Brexit referendum of June 2016. Since our previous paper on this topic in 2017, there has been a significant clarification in the impact of Brexit on the energy sector in the UK. We outline what the TCA says about energy. We then discuss the current and potential future effects of Brexit on the UK electricity and gas systems in turn. We observe that the likely economic welfare impacts on electricity are larger than the impacts on gas, but the overall microeconomic impact appears likely to be modest (but negative). We offer a number of concluding observations.

This paper quantifies the benefits of introducing reactive power markets that promote the participation of distributed energy resources (DER) in a coordinated way, between the electricity system operator and the electricity distribution utilities. The contribution that DER could make by displacing conventional network assets in supplying reactive power support is evaluated in the context of a case study, the Power Potential (PP) project in Great Britain. We discuss the rising need for absorptive (leading) reactive power in the PP trial area, driven by the rapid connection of renewable generation in an area of low demand growth. A social cost benefit analysis (SCBA) is performed to quantify the net benefits, with sensitivities regarding bid prices, % of DER participation, time horizons. Price information from the PP live trial conducted between January and March 2021 is also used to evaluate the robustness of the SCBA and to estimate benefits using actual prices. Our results suggest that energy consumers could save from 8 to 21% of business as usual asset costs by 2050. The introduction of actual bid prices increases these savings by around 3% of business as usual asset costs out to 2050. Potential sources of additional benefits on top of those identified in the SCBA are also discussed.

We analyse the productivity growth of electricity transmission and distribution networks in Great Britain and how changes in incentive mechanism have influenced the measured total factor productivity. In doing so we are also concerned to examine the effects of quality of service and environmental targets on measured productivity growth. It is increasingly important that productivity measures adjust for the increasing regulatory pressure to reduce the wider societal impacts of the electricity sector and improve quality of service. Failure to do so, may mean that productivity growth may look slower than it actually is. We employ a Data envelopment analysis technique which considers the underlying data without a stochastic element. Our findings show that productivity growth is consistently low for the period we examine, in the region of 1% p.a. over the 29 years from 1990/ 1991-2018/2019. For both electricity transmission and electricity distribution we try to monetise a wider range of quality and emissions variables in order to show the difference their inclusion makes to measured productivity growth. We show that it can make a difference both positively and negatively, though often this difference is small (e.g. 0.1% p.a.). However, the impact can be much larger (c. 1% p.a.), especially with respect to im-provements in quality of service in the distribution network. In the context of generally slow productivity growth, we therefore show the importance of appropriate measurement.

This paper considers the current proposal to extend the EU ETS to cover CO2 emissions from the combustion of heating and road transport fuels. We argue that increased coverage of the EU ETS, together with a binding cap consistent with a net zero trajectory, would be a powerful dynamic incentive to efficient emissions reduction. In addition, it would complement standards-based policies currently enacted in these sectors in several ways. Distributional implications remain a serious challenge to such an extension but several mechanisms are available to alleviate them.

Ancillary services markets (ASMs) are gaining higher importance in renewable-based power systems. They, however, remain less explored than the energy markets (EMs) of different regions. For limited energy units, such as battery energy storage systems (BESSs), it is vital to investigate the relative predictability of the two markets as suitable bidding hours of a less predictable product are more challenging to identify, thus entailing less certain revenues. This paper develops forecast models of the two markets of three countries – Denmark, Finland, and Norway – to quantify the difference in their predictability. Frequency containment normal reserves (FCR-N) are considered as a case of the Nordic ancillary service product. The dataset of 315648 datapoints contains three years (2019 – 2021) of hourly FCR-N, and spot market revenues of each country. Generalized additive models (GAMs) are used to develop week-ahead forecasts based on smooth curves of daily and weekly patterns. The forecast allows both inter country – between same markets of different countries – and intra country – between different markets of the same country – comparison. The results show that the FCR-N markets of the Nordic countries are less predictable than their respective spot markets except for the case of Denmark due to its fixed hourly volumes. Moreover, the smoothing curves of FCR-N models differ for each Nordic country despite their similar market requirements. This is in contrast to the Nordic spot markets where the smoothing curves indicate similarity in inter-country market behaviors. Considering market predictability differences in addition to their hourly prices is thus vital for BESS units performing multi-market bidding.

This paper seeks to shed light on the nature of optimal regulation of the electricity distribution system operator (DSO) over the period to 2025 and beyond, following the implementation of the EU Clean Energy Package and its constituent parts: Electricity Regulation (EU) 2019/943 and Electricity Directive (EU) 2019/944. We conducted two parallel surveys of DSOs and their national regulatory authorities (NRAs) across 39 European countries. This produced 39 responses from DSOs and 12 responses from NRAs covering, respectively, 40% and 78% of customers in those countries. We asked both DSOs and NRAs three sets of questions related to: (1) the definition and regulation of the future system operator function of the DSO; (2) lessons learned from transmission system operator (TSO) regulation that can be translated to the DSO; and (3) the way in which regulators support the capacity of the DSO to operate and coordinate the system. Our findings are consistent with the observation that the move towards a more active role for the DSO remains work in progress for both DSOs and their NRAs, given the fact that the Clean Energy Package has only passed into European Law relatively recently and some Member States are still implementing its provisions.

The aim of this paper is to analyse and evaluate the deployment of smart platforms (operated by distribution system operators—DSOs—or by independent parties) in key jurisdictions that facilitate the trading of flexibility services—primarily by DSOs. We look at key innovation projects/initiatives from seven jurisdictions, including Australia, France, Germany, Great Britain, Japan, The Netherlands and Norway. We have deliberately selected 13 use cases that operate under different regulatory frameworks and market rules, and have been recently implemented (from 2017 onwards). With the selection of key use cases this study seeks to discuss the different smart architecture solutions and main capabilities across different demonstrators and their relationship to business as usual. It also analyses flexibility market designs, identifies main characteristics, and compares different price formation schemes and procurement methods. The value of flexibility for DSOs is also discussed.

Traditional restructuring of power markets has focused on legally separating monopolistic transmission and distribution infrastructure with sufficient regulatory oversight to ensure non-discriminatory access to networks, and transparent and cost-reflective tariffs. There is consensus that ownership separation for transmission assets is beneficial for competition and transparency. However, at the distribution level the benefits of going beyond legal unbundling are questionable. This paper reviews the theoretical arguments for ownership unbundling and summarises the findings from 23 academic papers and consulting reports. In addition, this paper empirically demonstrates that forced distribution ownership unbundling in New Zealand (from 1998) and the Netherlands (from 2009) did not increase retail competition and did not increase network quality. It resulted in significant one-off and structural costs. The combination of increasingly active distribution networks with bi-directional power flows from distributed renewables, in combination with the digitalisation of energy supply and creation of distribution data platforms, suggests that interaction between networks and customers, traditionally separated from a regulatory and competition perspective may become more interlinked in future. Policymakers should therefore assess a broader set of policy measures, taking into account this changing network landscape, when focusing on increasing retail competition and network quality.

This paper identifies and explores regulatory issues that may have an impact on the use of flexibility services by distribution utilities to solve grid constraints. This can be done by flexible distributed energy resources which can be instructed, for instance, to reduce export generating capacity or increasing consumption. We want to identify how regulation can better support the development of the future distribution utility in its role as neutral market facilitator, enabling more competition in local flexibility markets and optimal use of resources. A set of questionnaires were designed to capture the insights around important aspects of the regulation of flexibility markets (utilities’ network incentives, network tariff structure, market design for flexibility markets, etc.). These were sent to distribution utilities, energy regulators, energy marketplaces, energy associations and relevant experts from seven jurisdictions. The responses suggest a collective interest in the procurement of flexibility services by distribution utilities from distributed energy resources. New regulations, the adaptation of current rules and recent consultations reflect this. However, the amount of progress with and preferences for key regulatory changes differ across jurisdictions.