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Several northern European countries have announced ambitious plans to become carbon neutral already before the year 2050. Recent research has, however, highlighted how potential bottlenecks in raw material and resource availability could significantly delay or hinder wind and solar photovoltaic (PV) expansion and continued biomass usage in parts of Europe. To address this issue, this paper assesses how exposed the national energy and climate plans (NECPs) of Finland, Estonia, Germany, Sweden, and Denmark are to resource limitations and techno-economic risks by reviewing and analysing 2030 NECP targets compared to statistical energy use data in these countries. The results indicate that the NECPs of Denmark and Germany are particularly exposed to risks related to global raw material availability, as Denmark plans to rapidly grow the share of wind and solar PV in electricity generation to 81% and 13% by 2030, respectively, followed by Germany, which outlines a 39% and 16% share of wind and solar PV in its national climate strategy. The NECPs of Finland and Germany are also shown to be vulnerable to limitations in biomass availability, as there is a significant disparity between the projected biomass usage and legally binding European Union (EU) targets for land use, land use change, and forestry (LULUCF) sector emissions in 2030 in these countries. [ABSTRACT FROM AUTHOR]

In pursuit of Finland's carbon neutrality objective by 2035, integrating renewable energy sources into the power grid is essential. To address the stochastic nature of these resources, additional sources of flexibility are required to maintain grid stability. Meanwhile, district heating network (DHN) operators in Finland are decommissioning fossil fuel-based combined heat and power plants (CHPs) and electrifying heating systems with heat pumps (HPs) and electric boilers. A techno-economic assessment and the optimized operation of DHN-connected HPs and electric boilers in providing ancillary balancing services were explored in this study. The primary goal was to maximize the potential revenue for DHN operators through participation in the day-ahead electricity market and frequency containment reserve (FCR) balancing markets. Three interconnected DHNs in the Helsinki metropolitan area were optimized based on 2019 data and each operator's decarbonization strategies for 2025. HPs are expected to achieve the highest profit margins in the FCR-D up-regulation market, while electric boilers could generate substantial profits from the FCR-D down-regulation market. In contrast to other balancing markets studied, the FCR-N market exhibited limited profit potential. Sensitivity analysis indicated that spot electricity prices and CO2 emission allowance prices significantly influence the profitability derived from balancing markets. [ABSTRACT FROM AUTHOR]

Demand response techniques can be effective at reducing heating costs for building owners. However, few studies have considered the dynamic marginal costs for district heating production and taken advantage of them for building-level demand response. In this study, a district heating network in the Finnish city of Espoo was modeled to define dynamic district heat prices. The benefits of two demand response control approaches for a Finnish office building, the demand response control of space heating and a thermal energy storage tank, were evaluated by comparing them to each other and utilizing them together. A 5 m3 storage tank was installed in a substation of a conventional high-temperature district heating network. A new demand response control strategy was designed to make the most of the storage tank capacity, considering dynamic district heat prices and the maximum allowed return water temperature. The results indicate that the demand response control of space heating and the storage tank cut district heat energy costs by 9.6% and 3.4%, respectively. When employing the two approaches simultaneously, 12.8% savings of district heat energy costs were attained. Additionally, thermal energy storage provides more potential for peak power limiting. The maximum heating power decreases by 43% and the power fee reduces by 41.2%. Therefore, the total cost, including the district heat energy cost and the power fee, can be cut up to 22.4% without compromising thermal comfort and heat supply temperatures to ventilation systems. [ABSTRACT FROM AUTHOR]

Recent years have seen the development of cutting-edge technology, such as offshore wind turbines and wave energy converters. It has previously been investigated whether integrating offshore wind turbines with wave energy converters is feasible. Diversifying the sources of offshore renewable energy also lowers investment costs and power fluctuation. This paper focuses on the development of a hybrid wind–wave energy system as well as the development of a techno-economic model to assess the system performance for a case study. A levelized cost of energy is calculated for the hybrid system by the Norwegian North Sea based on current knowledge about the technology costs. The economic benefits of sharing the common components of a wind-wave hybrid farm are inspected. Combinations of different wind–wave offshore hybrid systems are presented. Three technologies for both offshore wind turbines and wave energy converters are compared to find the most cost-efficient device pairing. The potential benefits of a shared infrastructure and the operational expenses are included in the evaluation. The combination yielding the lowest production cost of the cases studied is a combination of 160 MW of wind power and 40 MW of wave power, with a levelized cost of energy of EUR 107/MWh when the shared costs are 15%. In the study region, the average electricity price in Autumn 2022 was over EUR 300/MWh due to the European energy crisis. [ABSTRACT FROM AUTHOR]

European electricity prices soared to unusually high levels during 2021, which exposed vulnerabilities in the economy and led to concerns about affordability. The concerns were further exacerbated in 2022, as Europe strove to cut its dependence on the Russian fossil fuel supply, as a result of the Russian invasion of Ukraine. This article explores the causes of the price increases in 2021 and assesses their likely future development by using Finland as a case example. We address a gap in the existing energy literature by elucidating the origins and future outlooks of price spikes in highly interconnected electricity markets. Based on an interdisciplinary combination of legal and qualitative data analysis, this study approaches its key objective in three stages. First, we describe the European market and its regulatory design to demonstrate the legislative framework and preconditions within which the market is expected to operate and how these rules connect to guaranteeing the affordability of electricity. Second, we explore how these preconditions functioned in practice in 2021 by analysing the wider macro-level trends that resulted in the elevated prices throughout Europe, particularly in Finland. Third, we assess the impacts of these trends on Finnish electricity price development. Based on these descriptive and predictive analyses, we show that the European market design fundamentally necessitates price variation to ensure market-based investment and energy security in the long-term. Our analysis demonstrates that the high energy prices in 2021 were, in general, the result of various weather-related, economic, and political factors. Moreover, our findings indicate that the dynamics of price formation within a Member State are complex, and in the case of Finland, strongly impacted by neighbouring markets. [ABSTRACT FROM AUTHOR]

The Baltic countries Estonia, Latvia and Lithuania are well connected to the Nordic countries Finland and Sweden on the electricity market, yet in a different position facing the transition to a low-carbon electricity system. While especially Sweden is a large electricity producer and net exporter, the Baltic countries suffer from a lack of capacity, which makes them highly dependent on trade. In addition, the present electricity mix of Estonia is very carbon intensive compared to the Nordic countries. There is a debate regarding nuclear power in Sweden. This paper explores four possible solutions for a Nordic-Baltic electricity system: with and without nuclear power in Sweden and with the current transmission network, as well as with a considerably expanded network. The impact on electricity mix, electricity prices, carbon dioxide intensity and import dependence in the Baltic countries from the EU transition to electricity systems with very low carbon dioxide emissions is investigated. The electricity and district heat market model Enerallt is used to quantify electricity prices, electricity trade and system costs. The results show that the development of the transmission network affects electricity prices and especially electricity trade in the Baltic countries. With transmission expansion, the demand weighted average prices in the Baltic countries increase from 62 €/MWh to 65 €/MWh and 70 €/MWh with and without nuclear power in Sweden, respectively. If transmission is expanded, phasing out nuclear power in Sweden can increase the revenue from electricity export by over 100% for the Baltic countries. However, significant new investment in wind power is required. [ABSTRACT FROM AUTHOR]