Behnam Zakeri

Economy of electricity storage in the Nordic electricity market: The case for Finland

Energy storage systems can be employed for benefiting from price arbitrage, smoothing the imbalance in the power systems for higher integration of intermittent renewable energy, and power quality services. The economic implications of electric energy storage systems should be analyzed based on the characteristics of each electricity market. To this end, in this study, costs and potential benefits of electricity storage in the Nordic power market are examined for the case of Finland, based on the historical prices in 2009-2013. We examine different electrical energy storage systems including pumped hydro, compressed air, NaS, lead acid, and vanadium-redox flow batteries. An algorithm is presented to determine the optimal life cycles of batteries to make the highest benefit to cost ratio. The optimal size of each electricity storage system is also analyzed for each operating market (day-ahead and balancing market). While no storage system is purely profitable in intraday price arbitrage, the results show that pumped hydro has the highest annual benefit-to-cost ratio, up to 25 % in day-ahead (Elspot) and 75% in balancing market. The levelized cost of power generation for pumped hydro is 32-46 €/MWh plus the cost of charging electricity for the Finnish power market. Other possible benefits for electricity storage are examined, including frequency-controlled normal and disturbance reserve. The results demonstrate that none of the batteries are profitable even with the aggregation of revenues from ancillary services, under current market conditions.

Value of energy storage in the Nordic Power market - benefits from price arbitrage and ancillary services

Electrical energy storage (EES) systems can offer different services in power systems, including flexibility for integration of variable renewable energy. The market value of energy storage in different power market designs should be quantified to justify business models and/or policy supports. This paper analyzes the economic potential of EES in the Nordic power market (Norway, Denmark, Sweden, and Finland) both in energy and ancillary services markets under current market conditions (2012-15). We propose a model for profit maximization of EES in different market levels, i.e., the day-ahead, intraday and regulation markets. The results introduce Finland as the most profitable area for price arbitrage in the day-ahead (Elspot) and regulation markets. According to the results, recent cross-border market couplings have diminished the price volatility in the intraday market (Elbas), yet the Danish bidding areas are the most lucrative places for flexibility solutions in this market. The actual benefits in the balancing market show higher uncertainties compared with inter-hour energy markets, but this market promises greater revenues. The aggregation of benefits from price arbitrage does not realize any storage profitable. The inclusion of ancillary services, however, suggests return on investment for low-cost, long lifetime batteries.

Is battery energy storage economic in islanded power systems? Focus on the island of Jersey

Battery energy storage (BES) is attracting increasing attention for balancing variable renewable electricity (VRE) production in mainland power systems. However, the application of storage systems is argued to be even more relevant in islands or isolated systems which suffer more acutely from existing challenges in power system management. This paper investigates the use of storage for the island of Jersey, primarily in for two applications; reducing exposure to peak pricing over the existing interconnector to France, and also deferring or removing completely the need to use of on-island generation to supply peak loads. The results demonstrate that an investment in energy storage cannot be justified merely by the benefits from making profits from these applications. However, we consider how the investment equation could change as the cost of BES falls into the future and if it can provide additional benefits such as avoidance of the cost of replacement generation.

Energy security impacts of a severe drought on the future Finnish energy system

Finland updated its Energy and Climate Strategy in late 2016 with the aim of increasing the share of renewable energy sources, increasing energy self-sufficiency and reducing greenhouse gas emissions. Concurrently, the issue of generation adequacy has grown more topical, especially since the record-high demand peak in Finland in January 2016. This paper analyses the Finnish energy system in years 2020 and 2030 by using the EnergyPLAN simulation tool to model whether different energy policy scenarios result in a plausible generation inadequacy. Moreover, as the Nordic energy system is so heavily dependent on hydropower production, we model and analyse the impacts of a severe drought on the Finnish energy system. We simulate hydropower availability according to the weather of the worst drought of the last century (in 1939-1942) with Finnish Environment Institutes Watershed Simulation and Forecasting System and we analyse the indirect impacts via reduced availability of electricity imports based on recent realised dry periods. Moreover, we analyse the environmental impacts of hydropower production during the drought and peak demand period and the impacts of climate change on generation adequacy in Finland. The results show that the scenarios of the new Energy and Climate Strategy result in an improved generation adequacy comparing to the current situation. However, a severe drought similar to that experienced in 1940s could cause a serious energy security threat.

Market Power With Combined Heat and Power Production in the Nordic Energy System

The trend toward increasing energy efficiency and variable renewable energy (VRE) production has implications for combined heat and power (CHP) plants, which operate in both the price-driven power market and the district heating (DH) sector. Since CHP will be important in VRE integration, we develop a complementarity model to analyze CHP producers’ roles in integrated markets. We use a Nordic case study to gain insights into, first, the effect of the link between CHP and DH on market power and, second, market powers impact on operations in the DH sector. The results indicate that, first, the link of CHP to DH supply can increase market power and, second, market power can induce shifts in DH production from heat only to CHP.

Adequacy of power capacity during winter peaks in Finland

Due to ambitious national and EU level climate targets, wind power capacity in Finland has grown rapidly, while a significant amount of thermal capacity has been decommissioned or mothballed. Moreover, Finland is growing more dependent on electricity imports and the current electricity prices do not encourage market-based investments in power capacity. Hence, the issue of power capacity adequacy during winter peaks has been present in the political discourse in Finland, especially since the record-high demand peak in January 7th 2016. We analyse the Finnish power system by simulating different stress factors and their combinations, e.g. faults in the largest power plants and transmission lines, in a period such as January 7th 2016 using EnergyPLAN simulation tool. The results show that, despite the record-high demand, the Finnish power system currently has both technical capacity and adequate measures of intervention to cope with severe stress factors in the simulated period.

Intersection of national renewable energy policies in countries with a common power market

The EU energy policy aims to establish an EU-wide common power market through market couplings and cross-border grid expansions. The outcome of such international power markets may intersect with national renewable energy policies. To analyze this case, we introduce a market-based multi-region energy systems model to investigate the mutual impacts of energy transitions in a group of interconnected countries. The proposed model is a combination (hard-linking) of a multi-region power market model and hourly energy systems modeling of each constituent region. The case of Nordic power market with highly coupled areas, a high share of hydropower, and interlinked heating and power sectors (e.g., by combined heat and power plants (CHP) and district heating) is examined. According to the results, predicted targets for integration of variable renewable energy (VRE) in one country (Finland) can be counterbalanced by changes in the energy policy of interlinked countries (e.g. by nuclear power phase-out in Sweden). Comparing cross-border transmission lines versus local electricity storage suggests that domestic flexibility is 5 times more efficient in reducing wind curtailment in this case. The cost of such energy storage is, however, 90% higher than electricity sales from respective VRE integration. This calls for international, coordinated joint efforts in energy planning to guarantee an optimal utilization of energy resources and maintaining required flexibility for integration of renewable energy in such coupled regions at minimum cost.

Economics of energy storage in the German electricity and reserve markets

The new Electricity Market Act (2.0) in Germany is to increase the share of renewable energy through an efficient market design and new regulatory framework. This has paved the way for further participation of different flexibility solutions (such as distributed energy storage) in the German balancing market. This paper examines the market value of electrical energy storage (EES) in the German day-ahead and balancing markets. We present a simple but robust mixed integer optimization model for profit maximization of storage in the day-ahead market. We examine five different energy storage technologies, i.e., pumped hydro storage (PHS), compressed air energy storage (CAES), NaS, Lead-acid, and Li-ion battery energy storage systems. The results show that the benefits from price arbitrage can cover up to 25% of the life cycle cost of EES. However, inclusion of benefits from reserve markets suggests return on investment for some systems like PHS. Aggregation of benefits from energy and reserve markets may not realize profitability for high-cost batteries with cost data in 2016. The theoretical sum of benefits from reserve services, however, suggests a breakeven in the cost-benefit of low-cost batteries with a long discharge time.