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China's wind power has experienced explosive growth and reshaped the overall energy mix since 2009. However, increasing investment in the wind power industry has been accompanied by persistent and serious wind curtailment since 2010, leading to significant efficiency loss. This paper argues that the interprovincial market segmentation, which is driven by political motivations, is a key factor contributing to wind curtailment. We first construct an interprovincial electricity market segmentation index. This is then used as an independent variable to explain the variation in wind curtailment rates. A panel dataset of 28 provinces during the 2009–2016 period is used for empirical analysis. The results clearly show that market barriers positively contribute to wind power curtailment. Specifically, a 10% decrease in the market segmentation index will lead to a 4.3–5.3% decrease in wind power curtailment.

Achieving temperature targets under the Paris Agreement requires urgent measures to curb construction of coal-fired power plants (CFPPs) and expediate the retirement of existing assets. As the world's fourth largest coal consumer, Japan's efforts to reduce coal usage are critical for international climate mitigation. Policies introduced after the Fukushima nuclear disaster have led to a rapid increase in solar. However deregulation of the electricity market has also prompted a rush of new CFPP constructions by new market entrants and incumbent utilities. In parallel, Japanese state agencies and industry are actively exporting CFPP technologies to developing countries. Although these domestic and international actions harbour serious consequences for global climate mitigation efforts, greater understanding of the factors driving Japan's coal dependency is needed to limit further lock-in of future carbon emissions. Filling this gap, this study critically examines narratives employed by actors in government and industry to sustain Japan's domestic and international coal industry. Our analysis shows how Japan's fossil fuel regime is employing recurring narratives to promote continuation of the current coal-based energy system and to mobilise further investments in high-efficiency coal power technologies. We conclude by recommending various policy pathways and institutional reform measures aimed at encouraging wider diffusion of renewable electricity sources while reducing coal dependency.

The share of hydro power in the energy mix of Pakistan has not exceeded beyond 40% despite abundant hydro-power potential in the country. Owing to the slow pace of hydro-power development under the public sector, various policy frameworks and institutional arrangements have been introduced to develop the resources by involving the private sector. Even those arrangements have not succeeded in directing the attention of private investment towards the hydropower but the thermal sector. This study investigates the reasons behind the slow progress of hydro-power sector in Pakistan. A mixed approach comprising NVIVO analysis and Q methodology has been used to explore the impending reasons. Both, primary and secondary data, in the form of interviews, published reports, papers and other documents related to the hydro-power sector of Pakistan were collected for the analysis purpose. NVIVO analysis of primary and secondary data identified important variables that were further used for Q methodology. Q methodology revealed four important discourses on barriers to the hydro-power development in Pakistan. Discourses included less participation of private sector in running the electricity market operations, incoherent planning, financial barriers and institutional barriers. The revelation of these discourses is important for framing policies on the development of indigenous renewable energy resources in Pakistan.

The demand for solar sources of electrical energy is increasing in the Brazilian electricity market. Investments in the sector are expected to significantly increase, thereby creating a demand for a reliable environmental licensing process. Analysis of the international regulatory frameworks allows for a critical comparison to national- and state-level frameworks. The results obtained via this comparison have helped to identify different assessment criteria that can be used to define the typologies for environmental studies for the Brazilian states included in this study, and to show the subjectivity of the process. The development of guidance regulations is also recommended to establish more universally applicable criteria. The proposed adjustments aim to reduce the risks of delays, unexpected costs, and availability of the projects, thereby increasing reliability for electricity sector planning, the investors, and the consumers.

Though the electricity market in China has gone through several reforms in the last few decades, the market is still not completely liberalized. The wholesale prices are regulated and for renewable it is based on feed-in tariff; there is not yet a competitive spot or derivative market concerning the generation side. Furthermore, with great potential, renewable energy is being gradually promoted by the government to compete freely with conventional energies. However, it is hard for a renewable generator to survive without subsidy. So, in this paper we propose a new round of revolution in power sector to introduce electricity futures into China with the expectation of perfecting the market and providing a proper hedging tool for renewable plants. We make an estimation of the risk premium and then simulate the futures prices in China's market. To support the establishment of the futures contracts, we also propose two pricing mechanisms: Demand-side price & Opportunity cost price and study their effects on the futures. Finally, some suggestions with regard to the construction of futures market in China and the operational strategy for renewable plants are given.

The European electricity market is immersed in an integration process that requires a fundamental transformation. In this process, Flow-Based Market Coupling, which was employed for the first time in the Central Western Europe electricity market in 2015 as a means to manage cross-border capacity allocation, is a crucial cornerstone. The novelty of this paper lies in the analysis of the price convergence or congestion across the Central Western Europe region since the Flow-Based Market Coupling was implemented. We propose using random forests to build learning models that are trained and tested with features from connected markets of this region during 2016 and 2017. These machine learning models are used for mining knowledge about our target variable, price equalization. To search for robust predictive patterns that decision-makers can use to understand congestion situations, we have tested different combinations of learning schemes, several estimators and different model parameters. The results of all implemented models are robust and reveal that promoting renewable energy can contradict the integration of the electricity market if the grid network and, in particular, the transmission lines are not adapted to the new paradigm.

The environmental concerns and dependency on gas imports push Turkish policy makers to find ways of increasing the share of renewable sources in electricity generation. Providing incentives for renewable energy in the form of feed-in-tariffs is one of the measures to achieve this goal. Basing on the data of Turkish electricity market operator, we quantified the magnitude of the price effects of wind and river type hydro generations on hourly average of day-ahead prices. We find that wind and river type hydro plants reduced the spot electricity prices during the period of 2012–2017, and despite these resources get the same incentives, their impacts on the spot prices and price volatility are different: this can be useful for a more comprehensive cost benefit analysis aimed at differentiating incentive schemes. The paper also discusses possible underlying reasons of these different impacts such as high seasonality of hydro generation and volatility of wind generation. Finally, we show that, assuming more than 75% of the price reductions were reflected into the consumer prices in Turkey, the net impact of wind and river type hydro generation on final consumer prices would be negative. This finding contributes to the discussions on renewable energy incentive mechanisms.

By taking the grid system in Fujian Province as an example, this paper establishes a power market system model to simulate the impact of nuclear and wind power on the system operation. The article employs the method of optimal power flow (OPF) analysis, under a framework of social welfare maximization with close-to-reality thermal power generation cost and technical constraints. The simulation results show that large-scale nuclear power can reduce the level of electricity prices and improve the difference in regional electricity prices; as a result, the thermal power can be in an unfavourable position and therefore undertake peak and load following; meanwhile, the development of large-scale wind power would increase the demand for following of load and valley load. Moreover, the simulation for the operation of the electricity market shows that in the case of electricity oversupply, the thermal power can be deliberately bid at a low price, and the nuclear power would assume the obligation of valley load following, even with the presence of PSHPs in the system; thus, the low-carbon energy can't be fully utilized. In conclusion, the general bidding model in the electricity market cannot be applied to the situation of long-term electricity oversupply.

Standard consumer theory predicts that under block pricing, quantities consumed should bunch below block thresholds where marginal prices rise. However, researchers have previously found little or no evidence of bunching. In this study, I examine whether consumers respond to the marginal prices by using a different form of block pricing, one that includes both marginal price and fixed charge increases at the threshold, called increasing fixed-charge block pricing. Under this pricing schedule, the price increase at the threshold is more salient compared to the standard block pricing due to the increase in fixed charge. As a result, consumers are predicted to bunch below the thresholds and generate a zero density hole above the thresholds. I empirically test this by using the case in South Korea and find evidence that consumers tended to respond to price increase at the thresholds in 2005 and 2006. The considerable consumer bunching is observed around the thresholds. However, this evidence suddenly disappears after 2007 and never returned. While the reasons for this disappearance are not fully understood, the absence of consumer bunching suggests that consumers tend to respond to alternative pricing schedules rather than marginal price even with salient marginal price increases at the threshold.

We present a computationally-efficient optimization model that finds the least-cost generation unit expansion, commitment, and dispatch plan to serve hourly electricity demand and ancillary service requirements. We apply the model to a case study based on data from the electricity market in Texas (ERCOT) to analyze the market and investment impacts of several incentive mechanisms that support variable renewable energy (VRE) investments and carbon emission reductions. In contrast to many previous studies, the model determines least-cost VRE investments under different cost and incentive assumptions rather than analyzing scenarios where VRE expansion is pre-determined. We find that electricity prices can vary significantly under different incentive mechanisms, even when comparable generation portfolios result. Therefore, the preferred incentive mechanism depends on stakeholder objectives as well as the prevailing electricity market framework. Our results indicate that a carbon tax is more system cost-efficient for reducing emissions, while production and investment tax credits are more system cost-efficient for increasing VRE investments. Similarly, incentive mechanisms that reduce electricity prices may increase the need for separate revenue sufficiency mechanisms (e.g. a capacity market) more than a policy that increases electricity prices. Moreover, the impacts on consumer payments are not always aligned with changes in system costs. Overall, the analysis illustrates the importance of considering electricity market impacts in assessing the economic efficiency of VRE and carbon incentive mechanisms.

Our paper investigates the effect of wind and utility-scale solar electricity generation on wholesale electricity prices in Australia over 2010–2018. We use both high frequency (30-min) and daily datasets for the Australian National Electricity Market (NEM). We estimate autoregressive distributed lag models (ARDL) to decompose the merit order effect of wind and utility-scale solar PV generation over time and across states. We find that an extra GW of dispatched wind capacity decreases the wholesale electricity price by 11 AUD/MWh at the time of generation, while solar capacity by 14 AUD/MWh. The daily merit order effect is lower. We show that the wind merit order effect has been increasing as a function of dispatched wind capacity over time. Despite of this, wholesale electricity prices in Australia have been increasing, predominantly driven by the increase in natural gas prices. Our findings further strengthen the evidence of the merit order effect of renewable energy sources, with important implications for the current energy policy debate in Australia.

As electricity consumption in Vietnam has continued to increase much faster than has GDP, electricity intensity ( EI ) in the country has risen to levels far exceeding those of other Asia-Pacific economies (APEs). By analyzing evidence from a comparative study of other APEs through using the World Bank data, this study proves that EI in Vietnam is excessive and that its escalation over the last few decades cannot be justified as being due to supporting the country's policy of high economic growth. Factor analysis of the economic and electricity indicators for 22 APEs was used to track the shortcomings of the economic structure leading to the EI escalation in Vietnam. Electricity tariff, service share of GDP, and level of institution were identified as determinants of EI across the region. Given the weak performance regarding these indicators, Vietnam has highest EI among APEs followed by China and Mongolia. To reduce EI , Vietnam should consider diversifying away from the electricity-intensive industry sector toward economic activities such as service and information technology. The economic reform should be accelerated to complete the competitive electricity market and reduce the inefficiency of electricity usage through poorly managed state-owned enterprises and inefficient public investment projects.

In this paper, we analyzed the competitiveness of an open-cycle gas turbine (OCGT) in the Korean electricity market and found reasons why OCGT has not been constructed since 2001, when the market opened. Through the analysis, we found that OCGT was weak in the Korean electricity market due to 3 factors: high load factor, high price of liquefied natural gas, and existing inefficient power plants. Using the conformity theory of the optimum in resource planning and the equilibrium in market dynamics, we verified the reasons by implementing resource planning using the Wien Automatic System Planning (WASP)-Ⅳ package with actual market data for the 16 years from 2001 to 2016. In addition, considering the new energy policy of Korea, shifting main sources of electricity generation from nuclear and coal to clean renewable energies and natural gas, we analyzed the competitiveness of OCGT in the future Korean electricity market. We identified the factors unfavorable for OCGT in the current market and suggested what should be changed to cope with high renewable energy penetration.

In some U.S. states that have undergone electricity market restructuring and deregulation, investor-owned utilities (IOUs) were required to divest the majority of their generation assets in order to purchase power from merchant generators, independent power producers, and power marketers competing in the new wholesale market. This paper examines the effect of the governance structures used to purchase power in the wholesale market, the bilateral forward contracts and market transactions, on the technical efficiency of IOUs during the post-divestiture period. Using a two-stage empirical strategy (the non-parametric data envelopment analysis and the difference-in-differences regression approach), I analyze the performance of 152 distribution utilities in the U.S. from 1994 to 2015. The results show that while the use of contracts has no significant effect, the use of market transactions has a significant negative effect on IOU technical efficiency. Trading arrangements in the restructured wholesale markets that rely on the concept of competition generate transaction costs that make it more costly for the utility to use market transactions rather than other alternatives. Thus, market transactions fall short to promote the efficiency purpose of IOUs as an economic organization in this policy-induced market and the adverse effect persists until 20 years after the divestiture.

In 2015, ASEAN established a goal of increasing its renewable energy share in its energy portfolio from approximately 13–23% by 2025. Renewable electricity, especially intermittent and variable sources, presents challenges for grid operators due to the uncertain timing and quantity of electricity supply. Grid flexibility, the electric grid's ability to respond to changing demands and supply, now stands a key resource in responding to these uncertainties while maximizing the cost-effective role of clean energy. We develop and apply a grid flexibility assessment tool to assess ASEAN's current grid flexibility using six quantitative indicators: grid reliability, electricity market access; load profile ramp capacity; quality of forecasting tools; proportion of electricity generation from natural gas; and renewable energy diversity. We find that ASEAN nations cluster into three groups: better; moderately; and the least prepared nations. We develop an analytical ramp rate calculator to quantify expected load ramps for ASEAN in an integrated ASEAN Power Grid scenario. The lack of forecasting systems and limited electricity market access represent key weaknesses and areas where dramatic improvements can become cost-effective means to increase regional grid flexibility. As ASEAN pursues renewable energy targets, regional cooperation remains essential to address identified challenges. Member nations need to increase grid flexibility capacity to adequately prepare for higher penetrations of renewable electricity and lower overall system costs.

Singapore began a huge step to deregulate its electricity market since 2003, with the creation of the National Electricity Market of Singapore (NEMS) allowing for bid-ask offers to be made for the dispatch of electricity supply on the wholesale side. Subsequently, the retail market liberalised in tranches, with 80% of electricity consumers currently already given an option to select their electricity retailers since late 2014. This paper aims to quantitatively analyse how competitiveness in both the wholesale and retail market led to price decreases from 2014 to 2017, using daily data for electricity and oil prices. We find that supply competition and the more recent retail liberalisation efforts has possibly led to a combinatorial decrease in wholesale electricity prices by up to 9.11%, accounting for the influence of oil prices and volatility components. This work seeks also to bring some insights on what to expect from full retail contestability after the latter half of 2018.

The political failure of China's first independent regulator in a strategic industry – the State Electricity Regulatory Commission (SERC), 2002–2013 – provides a natural experiment to uncover fundamental challenges to a gradualist approach to electricity market formation. Taking a political institutional approach, we show that while it was largely predictable that the breakup of the monopolistic power industry in 2002 created bureaucratic and corporate interests that would undercut the institutional role of SERC, subsequent difficulties in reforming electricity pricing, dispatch system, and integrating renewable energy sources strongly suggests that a central regulatory body would be necessary to lead a decisive transition to a market-based electricity market.

The recent history of Australia's National Electricity Market (NEM) from 2012 to 2016 was characterised by coal plant closures, tightening domestic gas market and sharply rising electricity prices. The supply-side response that followed from 2016 to 2021 could only be described as an investment supercycle – 16,000 MW of plant commitments comprising $26.5 billion across 135 (mostly) Variable Renewable Energy (VRE) projects. We examine causes and the effects of the supercycle. Underlying causes included disorderly plant exit and climate change policy discontinuity in prior periods. Adverse effects in the post-entry environment included connection lags, system strength-related VRE production constraints, ex-post remediation costs, system frequency careering outside normal operating bands, and rising system operator interventions. Market institutions were caught out and subsequently focused on market re-design and resource adequacy reforms. Yet analysis contained in this article reveals the NEM's most pressing problems relate to real-time power system security, not fundamental market design or resource adequacy issues. Resolution requires the establishment of ‘missing markets’ (i.e. fast frequency, additional operating reserves, ramping, system strength and inertia), and urgently, to restore power system resilience. Key insights for other jurisdictions are climate change policy continuity and policies which serve to defuse the risk of disorderly coal plant exit.

The European electricity markets have been undergoing significant regulatory reforms since the introduction of the first liberalisation directive in 1996. Theory predicts that liberalisation promotes cost-efficient production and competition and hence leads to lower prices. The goal of this paper is to assess the impact of regulatory quality and non-compliance with the law on electricity prices in the context of electricity market reforms. We address problems of endogeneity by using the Blundell-Blond System GMM estimator and find that vertical integration and market concentration lower end-user prices, all else equal. Moreover, improving regulatory quality and reducing corruption, both have a negative impact on prices when holding other factors constant. The intensity of the reforms has limited impact on electricity prices when these reforms are introduced in an institutional environment characterised by high levels of corruption and low quality regulation.

This paper examines the electricity demand, and its determinants, in 29 European countries during the liberalization of the electricity market. Based on panel data for these countries for the years 1995–2015 and using a dynamic partial adjustment model, price elasticities are estimated for both residential and industrial electricity demand. These elasticities and effects of other variables on electricity consumption are estimated using both GMM (generalized method of moments) and ML (maximum likelihood) approaches. It is found that the price elasticities are very small, especially in the short run, while the income elasticities are relatively large, especially for households and in the long run.

Residential solar PV Positive feedback cycle Panel data analysis 1. Introduction Micro renewable energy systems are small scale energy systems which generate small amounts of energy when compared to traditional centralized power plants. Micro renewable energy systems have now made it possible for home owners to retrofit their premises to generate their own electricity and/or heat, thus becoming more self-sufficient. Allen et al. (2008) references a study where it was predicted that electrical micro renewable energy systems could provide 30–40% of the United Kingdoms’ electricity needs by 2050. Governments worldwide have included strategies to stimulate the growth of micro renewable energy systems at the residential level as part of their overall energy policy aimed at combatting climate change. Governments have used a variety of support mechanisms to achieve their targets which include Feed-in Tariffs (Fit), point of sales rebates including Renewable Energy Certificates (REC), and tax benefits. These policies have been successful in increasing the number installations particularly that of solar photovoltaic systems in the residential sector in countries like the United States of America, Australia and the United Kingdom (Allen et al., 2008; Chapman et al., 2016). Though, the increasing popularity of residential solar photovoltaic systems in electricity markets has led some to suggest that it has created a positive feedback cycle or loop. Simply put a positive feedback cycle is a situation where, action A generates more of action B which in turn ⁎ Corresponding author. E-mail address: james.hanly@dit.ie (J. Hanly). ABSTRACT Micro renewable energy systems (MRES) such as Photovoltaic (PV) are an increasingly important element of National energy strategies. However, the success of these installations has given rise to a positive feedback cycle whereby increased customer adoption results in reduced demand from Utility providers. This leads to price increases and further incentives customers to adopt MRES. This paper investigates the existence of a positive feedback cycle by developing a theoretical model based on simultaneous equations and estimating it using the three stage least squares approach using data from the UK, Australian and Irish Markets. Results indicate strong support for the idea of a positive feedback cycle. This reinforces the need for stakeholders to consider this issue in framing future energy policies to ensure that the adoption of solar PV is supported in a sustainable way, while not punishing non-adopters with higher electricity rates.

This paper estimates the effect of starting the Midcontinent ISO electricity market in 2005 on wind generation. An average increase in wind plant capacity factors of 1.7–2.8 percentage points associated with the start of the market is estimated, relative to neighboring wind plants not in the market. These results are robust to potentially confounding variation associated with wind speed differences determined by weather. Policy makers in regions of increasing wind generation should consider expanding the wholesale market region as a tool to deal with variability of renewable generation. Many technical experts and market participants provide anecdotes that competitive wholesale markets are beneficial for wind energy, this analysis provides the first statistical evidence to support that claim.

This paper examines the drivers of technological change in the US wind industry from perspectives of technological learning, collaboration, and energy policies. Using a panel of 576 utility-scale wind farms between 2001 and 2012, this paper estimates the impacts of different learning mechanisms—learning through research and development in wind turbine manufacturing, learning from a wind farm operator or a turbine manufacturer's previous project experience, learning through collaboration among wind project participants, and knowledge spillovers—on technological change of wind power, measured as improved capacity factor. Empirical findings suggest that a wind farm's performance has improved over time as the project operator accumulates more experience. Moreover, its collaboration with turbine manufacturers and the transmission system operator leads to greater performance improvement, particularly when the transmission system is coordinated by an independent system operator or a regional transmission organization (ISO/RTO). This finding supports the institutional change in the US electricity market deregulation—the creation of ISO/RTOs. The ISO/RTO-governed transmission networks promote wind power integration through regional collaboration and coordination. In addition, evidence of knowledge spillovers on wind farm operation at the state level provides justifications for state energy policies that subsidize wind power generation.

After two decades of consistent economic and technical performance, conditions in Australia's National Electricity Market (NEM) deteriorated sharply in 2016/17. Prices more than doubled on the east coast, tripled in South Australia (SA), and the SA regional grid collapsed. Nothing spectacular occurred with final demand – this was a supply-side energy crisis driven by the exit of 18% of Australia's coal-fired generation fleet and the inadequate entry of new plant. Australia's NEM encountered an uncoordinated exit-driven episode of the Resource Adequacy problem. In the USA where 18% of coal plant has also exited, Resource Adequacy and low cost energy has been maintained by the entry of an enormous fleet of wind, solar and gas-fired generators. In Australia, an equivalent response did not occur; decades of climate change policy discontinuity meant the speed of coal plant exit was unpredictable, entry of renewables delayed through stop-start policy, and gas-fired plant was subject to critical hold-up due to excess LNG plant investment. Resolution requires a united and stable climate change policy architecture that works with, not against, the NEM's world-class institutional design, and greater transparency around planned plant exit.

Available online: 12 June 2018 The role of DSOs is evolving due to the increasing penetration of intermittent and distributed energy resources in the distribution system. On the one hand, TSOs are accessing flexibility resources connected to the distribution grid. On the other hand, DSOs are actively managing distribution grid congestion, moving away from the conventional fit and forget approach. As a result, the need for DSO-TSO cooperation has become increasingly important. In this study, we first discuss market and grid operation issues related to different system states and the corresponding congestion management approaches, in the context of the European electricity market design and regulation. Second, we discuss viable solutions that are inspired by inter-TSO cooperation solutions as well as solutions that are being adopted by DSOs. Our findings show that the issues are rather similar both at transmission and distribution level however, the need for cooperation and the solutions will depend on where structural congestion will occur and which borders will be managed. We also note that cooperation between DSOs as well as between DSOs and microgrids could become more important with the development of local energy markets in the long term.

This paper analyzes investment incentives for flexible manufacturing facilities under different market designs. We propose a multi-stage equilibrium model incorporating endogenous determination of generation capacity investment, network expansion and redispatch based on the model introduced by Grimm et al. (2016) , including flexibilization of industrial electricity consumption. The model allows to investigate incentives for flexibilization and the impact of flexible industrial electricity consumers on the system. An application to the German electricity market reveals that flexible industrial electricity consumption can be profitable for firms. If the share of flexible electricity consumers is high, price fluctuations are mitigated, which lowers the individual cost savings from demand flexibility. Comparing different market designs, positive impacts of flexible electricity demand on the system are observed in both the system optimum and the market equilibrium. In scenarios with flexible industrial electricity consumption, welfare is considerably higher than in those without. This is due to lower electricity costs of industrial consumers, but more importantly due to less investment in conventional power generation as well as a reduced transmission network expansion. However, a comparison of nodal and uniform pricing underlines the importance of regional price signals with respect to an efficient allocation of flexible industrial demand.

The liberalization process of European electricity markets has been a work in progress since early reforms beginning in the 1990's. A key goal of these reforms was to enable increased integration and attendant efficiency within these markets. In this paper, we analyse three major European electricity markets - (APXUK, NordPool and Phelix) – before and after the 2009/72/EC Directive was introduced, to examine the extent to which those markets are efficient and whether they have become more integrated. We find little evidence of significant long run relationships between the different markets. We also find that the NordPool and Phelix markets in particular exhibit volatility persistence and clustering behaviour that is inconsistent with the postulations of market efficiency. The existence of continued inefficiencies across these power markets indicates that the desired goal of achieving an efficient and unified electricity market in the EU context is still a work in progress.

The increasing role of intermittent renewable generation demands for an efficient spatial exchange of electricity. However, the technical characteristics of electricity transmission reduce the available cross-border capacity due to unscheduled flows in a zonal pricing framework. Using the detailed unit commitment and dispatch model stELMOD for the European system, we analyze the development of unscheduled flows under different market and network design scenarios for 2020. We apply ACER's flow definition to decompose commercial schedules and physical flows into unscheduled flows and its fractions, i.e. loop and unallocated flows. Our analysis reveals that unscheduled flows increase on average by 47% from 14.7 GW in 2013 to 21.7 GW in 2020 mainly driven by higher cross-border trade capacities and increasing renewable generation. These unscheduled flows, which affect adjacent countries through e.g. a reduction of tradeable cross-border capacity, can be effectively reduced through a delimitation of bidding zones or HVDC network expansion. Thus, even if a discussion of national impacts of national and European policies is inevitable, they can have substantial implications on adjacent regions through the interconnected electricity system. Therefore, a system-wide view should complement national perspectives to ensure an efficient system development with increasing shares of intermittent renewable generation.

In order to stimulate renewable energy and control carbon dioxide emissions, the Chinese government has already introduced lots of renewable energy generation policies. Under this background, it is of great significant to figure out the economic, environmental and social effectiveness of these polices. Firstly, this paper systematically studied the framework and content of renewable energy generation policies. Secondly, this paper built a basic partial equilibrium model to calculate the equilibrium state of electricity market and carbon emissions. On this base, the effectiveness of seven renewable energy generation policies was analyzed by introducing policies into the basic model, and comparing relevant indicators in different policy scenarios with that in basic scenario. Further, an empirical analysis was made to estimate the actual benefits of these policies in China. This paper proposed an analysis method for evaluating the mechanism, effectiveness and efficiency of renewable energy generation policies. All the results and discussions in this paper can provide specific suggestions for Chinese government to shape a blueprint for implementing different kinds of policies.

The increase of intermittent electricity generation from renewable energy sources (RES) requires more flexibility from the demand side. Different applications and processes exist, which can provide Demand Response (DR) potential by shifting or shedding their load. The availability of most applications depend on the ambient temperature and/or time of day. Furthermore, their commitment is limited by technical restrictions, e.g. shifting time. In this paper, the availability and the flexibility of DR is analysed to investigate its role for the system integration of RES in Germany. In a first step, DR potential on an hourly basis is calculated for today and for future years. In a second step, the use of DR in an electricity system with different RES shares is investigated with an electricity market model. Results show, DR reduces RES curtailment. However, due to its limited availability and flexibility, it cannot integrate high amount of RES surplus over a longer period. Instead, it balances short-term fluctuation of the residual load curve. The exploited potential varies between DR applications because of their different characteristics. Therefore, focused (on selected applications) rather than broad development of DR potential is needed to shape the future energy system in a cost efficient way.

Poor renewable energy (RE) integration is posing a huge challenge to China's electricity sector. This paper examines the extent to which China's power sector reforms will assist RE integration, and issues to effective implementation. It demonstrates that a well-established electricity market could provide practical solutions to RE integration challenge. China's existing power sector regime heavily regulated by administrative planning constrains RE integration. The on-going electricity reforms (new reforms) in the country such as the transmission and distribution (T&D) tariff reform, the direct trading of electricity, among others, along with new RE policies such as full purchase of guaranteed RE generation and green certificate system, should assist RE integration in the country. However, there are a number of implementation challenges such as the intervention from local governments in direct electricity trades and the lack of a quota system for RE, among others. If these challenges are not properly addressed, the potential positive impacts of the new reforms on RE integration will be undermined. It is recommended that the central government strengthen top-level design and supervision, design and build up electricity spot markets, push forward the regional electricity markets, and facilitate the establishment of a renewable quota system.

Grid investment optimization is an effective method for solving the mismatch between investment demand and the investment capacity of power grids. China is carrying out a new round of power system reform, and the main content is to control the revenue of the power grid enterprise through the transmission and distribution tariff policy. Revenue control may make the investment capacity of the power grid enterprise appear even more insufficient than it is currently. This paper studies the influence of the transmission and distribution tariff policy on the cash flow of the power grid enterprise and establishes an investment optimization decision-making model for the corporation using system dynamics theory. Then, taking a city as an example to undertake an empirical analysis, the paper puts forward suggestions and policy implications for the investment decision of the power grid enterprise after the reform of the electricity market.

The financial sense of reused automotive battery systems providing stationary energy storage is investigated in the paper. A comprehensive review of existing used batteries projects is presented, followed by an evaluation of individual European countries regulations and electricity market conditions. The authors performed detailed simulations of the Net Present Value of four battery system investments: residential solar panel + battery or battery-only, commercial/industrial level solar panel + battery and primary reserve battery investment. The combination of electricity prices and Feed in Tariff schemes can either act as an enabler or a barrier to the economics of battery investment. At the moment, the investment in used batteries makes sense mostly in Germany but countries such as UK and Italy or Spain could be future candidates. In terms of energy policy adjustments, appropriate financial incentives are necessary to encourage the investment in such systems. Most importantly, energy policy in EU should incentivise the use of 2nd hand automotive batteries for stationary applications.

This paper discusses the spark spread risk management using electricity and natural gas futures. We focus on three European markets in which the natural gas share in the fuel mix varies considerably: Germany, the United Kingdom, and the Netherlands. We find that spark spread returns are partially predictable, and consequently, the Ederington and Salas (2008) minimum variance hedging approach should be applied. Hedging the spark spread is more difficult than hedging electricity and natural gas price risks with individual futures contracts. Whereas spark spread risk reduction for monthly periods produces values of between 20.05% and 48.90%, electricity and natural gas individual hedges attain reductions ranging of between 31.22% and 69.06%. Results should be of interest for agents in markets in which natural gas is part of the fuel mix in the power generation system.

Canada’s electricity sector is predominantly low-carbon, but includes coal, natural gas, and diesel fuelled power plants. We use a new linear programming optimization model to identify least-cost pathways to decarbonize Canada’s electricity sector. We co-optimize investments in new generation, storage and transmission capacity, and the hourly dispatch of available assets over the course of a year. Our model includes hourly wind speed data for 2281 locations in Canada, hourly solar irradiation data from 199 Canadian meteorological stations, hourly demand data for each province, and inter- and intra-provincial transmission line data. We model the capacity of hydropower plants to store potential energy and respond to variations in renewable energy output and demand. We find that new transmission connections between provinces and a substantial expansion of wind power in high wind locations such as southern Saskatchewan and Alberta would allow Canada to reduce electricity sector emissions at the lowest cost. We find that hydropower plants and inter-provincial trade can provide important balancing services that allow for greater integration of variable wind power. We test the impact of carbon pricing on Canada’s optimal electricity system and find that prices of $80/tonne CO2e render the majority of Canada’s coal-fired plants uneconomic.

Wind generation in Portugal and Spain has grown due to a decrease in technology cost and the availability of renewables electricity generation incentives. There is a strong interconnection between Spain's and Portugal's transmission systems, resulting in common prices in both countries. However, Portuguese and Spanish producers receive the incentives for producing wind-based electricity that are specified in their own national policies, resulting in different costs to rate-payers. In this paper, we estimate the costs to Portuguese rate-payers associated with the current market design and policy incentives. To do so, we regress hourly spot electricity market prices as a function of hourly wind generation, and estimate the resulting feed-in-tariff costs distributional effects over the various rate-payer categories. Total costs for rate payer are at the minimum level if joint wind generation in Portugal and Spain increases by 5.5% from what it is today. If wind generation increases much further, then the costs increase due to the FiT overcost increase. If wind generation decreases from current levels, then costs also increase due to the merit-order effect. Furthermore, we find that rate-payer categories will endure different portions of the costs, with an increase in wind generation penalizing predominantly ≤ 20.7 kVA rate-payers.

The research of household electricity use is still relatively new for Singapore, where apart from some government surveys and sparingly available papers, not much has been done to understand the underlying socio-economic determinants that affect residents’ energy demand. Here, we seek to quantify price and income elasticities, as well as provide reasonable justification for price asymmetry in Singapore using a panel approach across dwelling types and geographical areas. We find that households do not react much to prices, and that price elasticities may decrease as income rises. There is also some evidence of price asymmetry, with surprising results putting responsiveness towards price decreases larger than price increases. This points towards similar behavioural patterns with the rebound effect for household energy efficiency, if found present in future studies. Our findings suggest that there will only be positive responses towards dynamic pricing and higher churn rates if more transparent information is provided on related cost savings, when households are exposed to retail choice in the electricity market after full retail competition is introduced in 2018. In addition, a large role will have to come from cultivating the young to engage in sustainable practices to achieve energy efficiency targets.

China implements brand new renewable portfolio standards (RPS) since 2020. Based on the newly issued RPS policy, this paper constructs the system dynamics (SD) model of the multi-market coupling trading system involving the renewable electricity market, the consumption above quota market, and the tradable green certificate (TGC) market. The simulation experiments based on six scenarios are conducted to explore impacts of policy parameters such as RPS quota planning goals, unit penalties, and TGC price ceilings. The results show that: (1) Not only does the new RPS affect the price and transaction volume of the multi-market, but it also promotes renewable power generation in China. (2) The RPS quota planning goals display significant influences on the multi-market stability and renewable energy production growth, but it's not that the higher the quota planning goal, the better its effects. (3) An appropriately higher unit fine compared to the TGC price cap is conducive to moderate market volatility and stimulate market consumer demand. (4) According to the current development of renewable energy in China, the 15% quota planning goal cooperates with a unit fine and a TGC price cap with a proper gap is favorable to achieve market equilibrium and moderately promote renewable energy power generation.

Member States have published National Energy and Climate Plans with challenging variable renewable electricity (VRE) targets. As VRE has a high peak to average output, the Single Electricity Market of the island of Ireland (SEM) will need to consider how best to balance the lost value of curtailment against the extra costs of higher Simultaneous Non-Synchronous Penetration (SNSP), more interconnector capacity and/or more storage. The paper develops a spreadsheet model to explore these options for the 2026 VRE targets in the SEM and her neighbours. Raising SNSP from 75 % to 85 % reduces curtailment from 13.3 % to 8.0 %, saving 1338 GWh/yr of spilled wind. Adding the Celtic Link of 700 MW at SNSP of 75 % reduces curtailment to 12.4 % and saves 235 GWh. Adding 100 MW of batteries saves 19 GWh/yr, but the costs of delivering these savings are high. The marginal spilled wind can be four times the average, creating a potentially significant market distortion and reducing the value of adding further VRE.

Auctions have recently become the most widely adopted approach globally to procure renewable energy projects. Countries starting to use auctions often struggle to secure sufficient bidder interest – resulting in limited competition levels and high project prices. Brazil, a pioneer in the use of auctions to stimulate investment in renewable energy projects, offers important lessons on not only how auctions can be designed and implemented to stimulate competition and deliver effective investment outcomes, but importantly also shows how auctions form part of the country's electricity markets and can be integrated in a country's broader institutional and policy framework to ensure long-term success. This paper presents the detailing and specifications throughout the process of contracts and auction design definition to integrate renewable energy sources (RES) into the electrical matrix, from the institutional and procedural side to policy implications of securing the revenue stream and addressing off-taker risk between the sellers and buyers of electricity sector.

The UK left the EU Integrated Electricity Market on 31/12/20 and with it access to Single Day Ahead Coupling that clears local and cross-border trades jointly – interconnectors are implicitly auctioned. The new Trade and Cooperation Agreement requires a replacement “Multi-region loose volume coupling” to be introduced before April 2022. Until then, interconnector capacity is allocated by an explicit day-ahead auction before the EU auction with nomination after the EU results are known. The article measures the risks posed by taking positions in each market separately and the resulting costs of uncoupling of GB's interconnector trade. It compares four forecasts of price differences under two sequencing of markets and explicit auction, determining traders' risk discounts for each. The current timing leads to lower mistakes on the direction of flows, arguing for retaining current timing. Competitive traders locking in their positions after the explicit auction (overstating costs as subsequent trading out of unprofitable positions is ignored) limit the total loss of interconnector revenue from uncoupling to €31 million/yr. The social cost of uncoupling is €28 million/yr, considerably below earlier estimates in the literature. Experience since uncoupling validates this finding.

We investigate the incentive, market-behavior, and welfare effects of a proposed profit guarantee and associated power purchase agreement (PPA), which was introduced to ensure that generating firms remain viable through periods of higher-than-normal costs. The PPA ensures a guaranteed profit level either by transferring excess revenues from the affected firms to consumers or levying a surcharge on consumers to fund a subsidy for the affected firms. We develop and analyze a stylized Nash-Cournot model of a wholesale electricity market to examine the incentive effects of the proposed PPA. We find that the proposed PPA has incentive impacts that are contrary to its stated aim. The PPA incentivizes uneconomic firms to remain in the market when otherwise they would exit and incentivizes the shutdown of otherwise economically viable firms to restrict output, increasing prices. We find that the effects are pronounced by the corporate-separation asset-ownership structure that is employed in many jurisdictions. The theoretical results of the Nash-Cournot analysis are illustrated with a numerical case study which shows the deleterious consumer- and social-welfare effects of this incentive scheme. We discuss practical implications for regulatory policy, namely, that the proposed mechanism is ill-conceived, inefficient, and creates perverse incentives.

The Africa Continental Free Trade Area presents an opportunity for the creation of a single continental electricity market in Africa. This market has the potential to promote the efficient development of electricity infrastructure and symbiotic electricity trading between members of Africa's five regional electric power pools. A framework is proposed to harness the opportunities presented by the African Continental Free Trade Area through the coordination of technical and commercial endeavors of the regional power pools in Africa. This includes fostering sharing mechanisms of best practices that support the development of national and international institutions, harmonizing regulations and grid codes, and promoting electricity trading opportunities that will catalyze the development of inter-regional infrastructure projects. In this paper, the authors propose a bilateral contract market that aligns with and complements the existing regional power pools without encumbering them with unnecessary bureaucracy. The paper's policy recommendations are designed to promote proactive adoption and compliance with the recommended best practices, market rules and regulations by market participants, motivated by their self-interests.

Extreme weather events can cause significant damage to power distribution grids, leading to extended power outages. Intentional islanding enables the use of distributed energy resources (DERs) to power critical loads and accelerate grid restoration. In this study, an innovative dynamic microgrid islanding scheme was investigated as a means of enhancing distribution grid resilience. If customers in a dynamic microgrid request emergency electricity services during an outage, the question of how the distribution system operator should price the DER emergency power service arises. To answer this question, an economic load dispatch model was implemented in a single-bid auction market to forecast the market-clearing price of electricity in the dynamic microgrid island. The results show that the cost of emergency service is impacted by the power supply and demand in the island. When the combined heat and power plant capacity of the dynamic microgrid exceeded the demand, the market-clearing price of electricity in the island could be even less than the on-grid electricity price during normal periods. Thus, the dynamic microgrid scheme provides a low-cost means of supplying end-users with emergency power.

Security of electricity supply has been an important topic of growing concern in the United Kingdom as the margin of supply over demand tightens and the risk to security of supply widens. The risk profile to security of supply is presented, in the United Kingdom, in terms of the conventional metrics capacity margin and loss of load expectation. However, increasing levels of disruption in the power sector, arising from a combination of policy, technological and customer change, challenge this traditional approach to characterise the risk to security of supply. The paper presents a framework to evaluate the risk profile to security of supply through a series of probabilistic metrics that establish the expected magnitude (power and energy), likelihood, frequency and duration of encountering supply shortfalls. This detailed characterisation of the risk profile enables risks to be fully identified, assessed and prioritised facilitating effective risk management.

This paper examines the trade-off between the economic gains to Great Britain (GB) from being integrated into the EU electricity market on the one hand and a loss of influence over policy and rule making on the other. The aim is not to predict how this trade-off will be resolved in practice, but rather to lay out what is at stake on both sides of the equation. Since the late 2000s the electricity market in GB has become increasingly integrated with continental European markets through market coupling and increasing interconnection capacity, with further integration expected up to the mid-2020s. Estimates of the economic benefits of this integration range up to the order of several £100 m to £1bn a year, representing the economic cost of a reversal of such integration. On the other hand, maintaining and expanding electricity market integration would require the acceptance of electricity policies and regulations made in European institutions in which UK actors would have little if any voice. An intermediate multilateral approach offering the possibility of retaining market integration with less cost in terms of influence is proposed.

In this article, we investigate the role that a Contract-for-Difference (CFD) might play in increasing investment in renewable energy in Australia. Two CFD schemes are investigated: two-way and one-way CFD. A financial model is developed that determines commercially viable CFD strike prices. Account is taken of revenue from wholesale electricity market and renewable energy certificate sales. Capital and operational costs of the project including distribution of funds to holders of equity and debt are also included. Findings based on analysis of the solar array located at the University of Queensland Gatton Campus in Australia is presented, employing a typical meteorological year framework. The major finding was that Government will prefer a two-way CFD scheme and Single-Axis tracking solar PV array technology. In contrast, project proponents will strongly prefer a one-way CFD design.

The paper aims to quantify the impact of the penetration of renewables on the flexibility needs and their price signal. It uses a generic Mixed Integer Linear Programming (MILP) model that integrates long-term power system planning with a Unit Commitment (UC) model, which performs the simulation of the Day-Ahead Electricity Market (DAEM). The integrated model evaluates the need of flexibility services, under different conditions of renewable penetration. A case study of the Greek interconnected electric system is examined. Results show that the main flexibility needs concern photovoltaics causing the sunset effect, while the needs from stochastic wind are alleviated from the fact that wind output is de-linked from the demand evolution and that wind installations’ positions are diversified. The identification of flexibility needs from the Transmission System Operators (TSOs) require detailed data to depict the spatial and technical characteristics of each power system, which can reveal that ramping rates, and not just the magnitude of ramping capacity, can be an important flexibility requirement, due to large single-hour ramp contribution in some months. Such an analysis can also reveal the options for increasing flexibility, which are power system specific.

There is growing policy and regulatory interest in better aligning electricity tariffs with the cost of providing network services to customers: to provide a better price signal for economically efficient use of the network, and reduce cross subsidies between different customers. Given that network costs are significantly driven by peak capacity requirements, many proposals for more cost-reflective tariffs include a demand (capacity) component. However, there are many complexities in the implementation of such tariffs. This paper first presents a method to visually assess how cost-reflective a particular demand charge network tariffs is. We apply it to a typical demand charge network tariff proposal within the Australian National Electricity Market and actual consumption data of 3876 Sydney households, and find it to have low cost-reflectivity in terms of aligning customer bills with their contribution towards network peak demand. Such misalignment has potentially significant adverse impacts on the economic efficiency of such tariffs – an issue that does not appear to have received sufficient policy attention. We then use this assessment method to demonstrate how a demand charge tariff structure can be adjusted to make it significantly more cost-reflective. This method can be applied to any tariff that includes a capacity-based component.