Renewable electricity capacity planning with uncertainty at multiple scales

Energy transition has become a priority for utilities worldwide.Renewable electricity generation represents one of the pillars of the European decarbonization policy and is included among eligible activities in the Taxonomy Regulation.The limited literature regarding the effects of investments in renewables on the financial performance of firms is fundamentally split in two lines: the first is focused on stock returns, the second concerns the determinants of the financial performance which is measured either through risk or accounting metrics. A limited set of studies has assessed the effects of investments in renewable power generation on the performance of utilities. In this article three linear regression analysis conducted on a panel-data composed of firm-year observations for 64 electric utilities from continental Europe between 2011 and 2020 are presented. The analysis has focused on: (i) profitability (Return-On-Asset), (ii) market valuation (Tobin's q) (iii) risk (Weighted Average Cost of Capital).The results show that the renewable generation share is significantly and positively correlated with the first two indicators, while not correlated with the cost of capital.This could represent a constraint to investments in renewable generation capacity with a negative impact on the achievement of the targets of the European decarbonization policy.

With the cost of renewable electricity generation like solar and wind decreasing, the share of total generation provided by such sources is growing. This leads to questions of how utilities should deal with integrating renewables into the grid. An interesting and not commonly studied case of this is when firms consume significant amounts of electricity in order to serve their customers (e.g., electric vehicle charging stations) and can get it either from the grid or through renewable generation they install themselves. Furthermore, if they have more renewable generation than needed to serve their customers they can sell it back to the grid. Therefore, the cost of electricity and value of excess generation affects firm’s interest in renewable generation, and has impacts on both the grid (by affecting how much renewable generation firms will provide) as well as the downstream market (by affecting the cost structure at both firms and how they compete).We study this though a two stage oligopolistic model. In the first stage, two differentiated firms choose a level of investment in renewable generation. In the second stage, they compete over prices to serve customers. We show equilibria always exist, and the difference between price of electricity and the feed-in tariff has potentially large implications for the number and type of equilibria as well as aggregate outcomes.

Backup flexibility classes in emerging large-scale renewable electricity systems

This article provides empirical contributions to our understanding of how small-scale renewable electricity systems (RES) can generate gender-equal opportunities for entrepreneurship in sub-Saharan Africa. This ties with our recent enquiry into the gender-electricity-entrepreneurship nexus (Osunmuyiwa & Ahlborg, 2019). Conceptually, we apply our recently developed Gender and Socially Inclusive Electricity for Entrepreneurship framework to explore the degree to which small businesses are growing or changing their production processes through access to RES and the gendered dimensions of these processes. This approach allows us to first; unpack how entrepreneurs in local spaces interact with RES and how this stimulates entrepreneurial opportunities and enables small businesses to develop new product or service offerings. Second, examine how RES reliance on existing socio-political systems and institutions might perpetuate socio-economic and gendered imbalances and affect entrepreneurial outcomes in case communities. We operationalise the analytical approach in a case study of small-scale RES in a rural district of Njombe, Tanzania. Our results reveal a boost in entrepreneurial activities. However, we found gendered differences in the capacity to initiate and sustain new product or service offerings. Similarly, while access to RES affected entrepreneurs' perception about social status by spurring significant changes in views around female business ownership, most women remained in low-growth enterprises due to existing socio-economic and power imbalances. We conclude by providing critical reflections for policy and developmental organisations aiming to deploy RES to promote inclusive electricity use for entrepreneurship in low-income communities.

Congestion Management in European Power Networks: Criteria to Assess the Available Options

In response to the looming climate crisis, many countries are adopting technologies to reduce the accumulation of greenhouse gases. However, national energy policies are often multiobjective and resolution deeply divisive. The result is a policy trilemma between the energy mix and the trade‐offs with other policy objectives, including cost and reliability. Utilising a discrete choice experiment (DCE), the objective of this study is to explore Australian household preferences for alternative electricity contracts containing features reflecting changes in future energy policy. The first set of features include investments in renewable generation and community‐based energy storage. The second set of features reflect demand‐side management policies, including installing smart meters and consumption limits being imposed on households during peak demand. Two versions of the DCE were developed to obtain both willingness to pay and willingness to accept estimates for the same features. In line with the literature, differences in the two sets of estimates were observed, with the willingness to accept estimates being statistically larger for some features. These dollar value measures can be used to support public policy decision‐making – the choice of which depending on the context of the policy problem being considered.

Peak reduction in decentralised electricity systems : Markets and prices for flexible planning

Many governments who preside over liberalised energy markets are developing policies aimed at promoting investment in renewable generation whilst maintaining the level of security of supply customers have come to expect. Of particular interest is the mix and amount of generation investment over time in response to policies promoting high penetrations of variable output renewable power such as wind. Modelling the dynamics of merchant generation investment in market environments can inform the debate. Such models need improved methods to calculate expected output, costs and revenue of thermal generation subject to varying load and random independent thermal outages in a power system with high penetrations of wind. This paper presents a dynamic simulation model of the aggregated Great Britain (GB) generation investment market. The short-term energy market is simulated using probabilistic production costing based on the Mix of Normals distribution technique with a residual load calculation (load net of wind output). Price mark-ups due to market power are accounted for. These models are embedded in a dynamic model in which generation companies use a Value at Risk (VaR) criterion for investment decisions. An `energy-only' market setting is used to estimate the economic profitability of investments and forecast the evolution of security of supply. Simulated results for the GB market case study show a pattern of increased relative security of supply risk during the 2020s. In addition, fixed cost recovery for many new investments can only occur during years in which more frequent supply shortages push energy prices higher. A sensitivity analyses on a number of key model assumptions provides insight into factors affecting the simulated timing and level of generation investment. This is achieved by considering the relative change in simulated levels of security of supply risk metric such as de-rated capacity margins and expected energy unserved. The model can be used as a decision support tool in policy design, in particular how to address the increased `energy-only market revenue risk facing thermal generation, particularly peaking units, that rely on a small number of high price periods to recover fixed costs and make adequate returns on investment.

A top-down model calculation based on real generation and demand data is presented for the hypothetical case of 100 % renewable electricity generation combined with hybrid electricity storage infrastructure in the Austrian control area (9 million inhabitants, electric demand ∼70 TWh per year). To reach 100 % physical coverage by renewables, the actual wind and photovoltaic generation curves in the selected reference year of 2022 were scaled by a factor of 2.8 and 30, respectively. In the scope of the presented system are lithium-ion battery storage (cyclic efficiency 90 %), pumped hydro storage (70 %) and power-to-gas storage with subsequent re-electrification in gas turbine combined cycle plants operated as combined heat and power (CHP) system (30 %). Our core aspect lies in the optimized operation of the hybrid storage system, where the charging and discharging of the storage technology with higher cyclic efficiency is given priority. A straightforward cascading control algorithm is applied with individual elements functioning as simple proportional controllers. The results show how a 100 % renewable electricity system in Austria could be configured, partially building upon existing electricity generation infrastructure (pumped hydro and gas turbine combined cycle plants) and on the implementation of new lithium-ion battery storage with a total capacity of 100 GWh and new electrolysis infrastructure with a power of 5 to 10 GW. To overcome existing limitations of the presented model, an extension to a more complex model with spatial differentiation and consideration of electricity grid characteristics and constraints is recommended.

Full decarbonisation of the electricity system is one of the key elements to limit global warming. As this transition takes place, the electricity system must maintain system adequacy and remain affordable to consumers. In liberalised electricity markets investors are seen as key actors driving this transition.Due to the intermittent character of renewable assets, such as wind or solar parks, electricity systems with large shares of renewable electricity will need to become increasingly flexible. Evaluating whether specific market designs provide the right incentives to invest in flexibility, requires the simulation of realistic investor behaviour. Agent-based modelling provides the means to explore heterogeneous, imperfectly informed and boundedly rational investor behaviour within different electricity market designs.We evaluated two market designs; “energy-only” markets and markets with a Capacity Remuneration Mechanism (CRM). We conclude that energy-only markets, even with strong carbon pricing, do not incentivise investors to deliver a fully renewable, reliable and affordable energy system. Therefore policy makers should focus on developing CRMs which can work in combination with market incentives to reach a fully renewable, reliable and affordable electricity system in the second half of this century.

BackgroundRenewable energies are key to reduce CO2 emissions and other environmental impacts of fossil-fueled electricity generation. However, renewable energy systems can also cause negative environmental effects. In this paper, we analyze the potential environmental trade-offs associated with different spatio-technical (de)centralization options for a renewable electricity system. For this purpose, we first review the potential environmental life cycle impacts of key technologies for renewable electricity systems. Subsequently, we develop a framework identifying which factors determine actual environmental effects of renewable electricity systems. We apply the framework to four basic spatio-technical (de)centralization options for the future Germany electricity system.ResultsOur analysis shows that all (de)centralization options are associated with potential environmental trade-offs. We find that the (de)centralization of the system is a relevant factor determining these trade-offs. For instance, the two more centralized options considered have lower environmental impacts related to PV, whereas the two more decentralized options have lower environmental impacts related to grid infrastructure. However, we also find that the trade-offs depend on the specific way (de)centralization is pursued. For instance, only in one of the two considered more decentralized development options, there is a potential environmental trade-off between higher impacts related to battery storage and lower impacts related to offshore wind power.ConclusionsOur analysis reveals that the spatio-technical (de)centralization of a renewable electricity system plays a role for its environmental trade-offs while further factors like the institutional and stakeholder management in place also shape the environmental trade-offs. Policy makers should acknowledge the identified potential environmental trade-offs and their influencing factors when making policies favoring certain spatio-technical (de)centralization options.

Spatial variation of emissions impacts due to renewable energy siting decisions in the Western U.S. under high-renewable penetration scenarios

Taking advantage of the electrification strategy, Northwest China has made full use of its natural resources endowment, to develop renewable energy as the substitution of thermal power. To evaluate carbon dioxide (CO2) emissions from electric power sector, an extended Kaya identity equation and the Logarithmic mean Divisia index decomposition method are applied to Northwest China from 1998 to 2017. Six explaining factors are analyzed, including carbon intensity, energy mixes, generating efficiency, electrification, economy and population. The results show that driving forces of CO2 emissions from electricity system varied greatly among provinces. Generally, economic growth has mainly contributed to increase CO2 emission, while the improvement in the power‐generating efficiency has crucially decreased CO2 emission. In 2017, Promoting electrification directly increased CO2 emissions from electric system, but indirectly reduced CO2 emissions from the whole region by 5.10% through the estimation of a clean development mechanism method. Therefore, local governments are suggested continuing to promote electrification to guide future emission reduction, while enterprises and individuals need to make their own contributions to low‐carbon development.Recommendations for Resource Managers: Variations of carbon dioxide (CO2) emissions of all five provinces in Northwest China are analyzed. Logarithmic mean Divisia index analysis is used to study the main drivers of CO2 emission change. Improvements in the generating efficiency significantly reduced CO2 emissions. Due to electrification effects, CO2 emissions from electric power increased, but CO2 emissions from the region decreased. Economy effects were still the biggest drivers affecting CO2 emission.

Prince Edward Island, already with the highest wind energy penetration of any province in Canada, aims to increase its renewable energy generation. A challenge is realizing better matching of intermittent wind and solar power with on-island electricity demand. This paper provides an initial perspective by considering the case of a 100% renewable island electricity system. Using time-series power data of wind, solar, and electricity demand for the province, varying capacities of wind and solar power along with battery energy storage and biomass are considered to model 100% renewable electrical energy scenarios. Wind, solar, and storage combinations without curtailment show how complementary supply combinations can reduce seasonal variations. Scenarios including curtailment demonstrate significantly reduced storage requirements. Scenarios that include biomass suggest little benefit in combining biomass and storage. Least-cost solar, wind, and storage capacities are estimated. Potential storage cost reductions appear to be transformative in enabling greater renewable energy integration.

Guest Editorial: Situational awareness of integrated energy systems