The Potential for Energy Arbitrage Using Battery Energy Storage Systems in Norwegian Power Markets : An Economic Viability Study through Financial Valuation

arbitrage, the process of storing energy when prices are low and offering it when prices are high, has, through increased electricity prices and price volatility, shown greater economic potential over the past couple of years. In light of these developments, this study analyzes the economic viability, through a financial valuation, of a 10MW/10MWh Battery Energy Storage System (BESS) performing energy arbitrage in the Norwegian power markets over a 30-year project. To account for the latest developments in electricity prices and evaluate the economic viability of the BESS, the study incorporates 2022 electricity price data. Furthermore, the analysis includes electricity price data from the period of 2016-2019 to assess the BESS's economic viability in the event of a return to historically “normal” Norwegian electricity prices. The study aims to present a comprehensive and holistic valuation of the BESS through the inclusion of all factors affecting the profits generated and the related costs of performing the energy arbitrage. The optimal energy arbitrage trading pattern is identified through a Mixed-Integer Nonlinear Programming (MINLP) model, and the resulting trading profits are valued through a Discounted Cash Flow (DCF) encompassing all relevant expenditures. The discount rate in the DCF is derived from an estimated Weighted Average Cost of Capital based on a Comparable Companies Analysis. The results from the analysis show that a BESS performing energy arbitrage in the Norwegian power markets is not economically viable with the current BESS cost estimations and power market conditions. The results for the 2022 electricity price scenario show the greatest promise in the southern price zones of Norway due to the historically high electricity prices and price volatility. However, the Net Present Value (NPV) of the cash flows for the BESS in the best performing price zone is still significantly negative. With optimal trading profits of 39.6 MNOK, the best performing project generates a NPV of -120.4 MNOK when considering all Capital Expenditure (CAPEX), Operations and Maintenance (O&M) costs, and trading profits. When utilizing 2016-2019 electricity price data, the results worsen significantly due to the lower electricity price and price volatility in the period, resulting in a total trading profit of 2.3 MNOK and a total NPV of -157.7 MNOK for the BESS in the best performing price zone.nhhma

Technical and economic feasibility of a microgrid for a fire station in Humboldt County, California.

Microgrids are emerging as a promising solution to unreliable grid energy. Today, California is not only witnessing grid resiliency challenges from natural disasters such as wildfires, earthquakes, floods and heatwaves, but it is also seeking to green the grid and bring more renewables online. For example, Humboldt County, where this project is focused, has recently experienced an earthquake of 6.4M (on December 22nd, 2022), which shut down the regional grid for ~20 hours. Microgrid adoption enables critical facilities to operate seamlessly. The Humboldt Bay Fire Station (HBFS) No.1 is one such example, where first responders work to protect citizens against emergencies, be it emergency medical services (EMS) operations or fire rescue or even helping in restoration of power lines. This study involves a techno-economic analysis of a microgrid design that could support efficient and seamless operations for the fire station as it serves the people of Humboldt County during emergencies. A clean energy microgrid for the station aligns with the Humboldt County GHG emission target to reach net zero by 2030, and could provide resilient power to their general and critical loads during regular operations and emergencies. The recommended microgrid for the HBFS No. 1 facility includes a 70-kW photovoltaic (PV) array and a 90 kW/360 kWh battery energy storage system (BESS). The project cost ranges from $300k to$600k (depending upon the level of investment tax credits (ITC) the microgrid project would get). It provides 51-day resiliency in the best case and 28-hour resiliency in the worst case depending upon the weather condition. The system would also reduce greenhouse gas emissions from electricity use at the station by over 98% annually. Considering the potential availability of incentives and the value of resiliency (VoR), the microgrid project for HBFS No.1 demonstrates promising economic feasibility results. The next steps involve further evaluation of the project\u27s financial viability, engaging with relevant stakeholders to secure funding, and proceeding with the detailed design and implementation phases of the microgrid

Grid-Scale Battery Storage for Variable Renewable Electricity in Sweden

This thesis explores how a market for grid-scale battery energy storage systems (BESS) can become reality in Sweden. Higher penetration levels of distributed, variable renewable energy (VRE) from wind power challenge the incumbent energy regime and require new solutions for the grid integration of renewables. As a consequence, a more flexible power system is needed in order to deal with the induced supply-side variability. Batteries, as one flexibility solution among several other options, have shown promising technological development and are a versatile electricity storage option. BESS can provide multiple benefits for different application areas on the grid at various scales. The emergence of grid-scale BESS in Sweden was analysed using the multi-level perspective (MLP) framework on socio-technical transitions. Despite the great potential and the rapid technological progress of BESS, it was found that regulatory factors, both in Sweden and the EU, currently constitute a major barrier for the deployment of large-scale electricity storage. Moreover, Sweden looks set to continue to increase the uptake of VRE from wind power, whilst a gradual phase out of nuclear power over the next decades is also likely. Whereas this would normally have negative implications for the power system, the ample hydropower capacity and sufficient interconnection to the neighbouring Nordic countries provide, at least for the near future, enough system flexibility and therefore reducing the need for the installation of BESS. However, the uneven geographic distribution of electricity consumption and generation across Sweden might give rise to flexibility solutions for enhancing local distribution networks in the future in order to eliminate potential regional bottlenecks

Electricity Market Participation and Investment Planning Frameworks for Energy Storage Systems

The recent trend of increasing share of renewable energy sources (RES) in the generation mix has necessitated new operational and planning studies because of the high degree of uncertainty and variability of these sources. RES such as solar photovoltaic and wind generation are not dispatchable, and when there is excess energy supply during off-peak hours, RES curtailment is required to maintain the demand-supply balance. Furthermore, RES are intermittent resources which have introduced new challenges to the provision of ancillary services that are critical to maintaining the operational reliability of power systems. Energy storage systems (ESS) play a pivotal role in facilitating the integration of RES to mitigate the aforementioned issues. Therefore, there is a growing interest in recent years to examine the potential of ESS in the future electricity grids. This research focuses on developing market participation and investment planning frameworks for ESS considering different ownership structures. First, a novel stochastic planning framework is proposed to determine the optimal battery energy storage system (BESS) capacity and year of installation in an isolated microgrid using a novel representation of the BESS energy diagram. A decomposition-based approach is proposed to solve the problem of stochastic planning of BESS under uncertainty. The optimal decisions minimize the net present value of total expected costs over a multi-year horizon considering optimal BESS operation using a novel matrix representing BESS energy capacity degradation. The proposed approach is solved in two stages as mixed integer linear programming (MILP) problems; the optimal ratings of the BESS are determined in the first stage, while the optimal installation year is determined in the second stage. Extensive studies considering four types of BESS technologies for deterministic, Monte Carlo Simulations, and stochastic cases are presented to demonstrate the effectiveness of the proposed approach. The thesis further studies the investment decisions on BESS installations by a third-party investor in a microgrid. The optimal BESS power rating, energy capacity, and the year of installation are determined while maximizing the investor's profit and simultaneously minimizing the microgrid operational cost. The multi-objective problem is solved using a goal programming approach with a weight assigned to each objective. The BESS is modeled to participate in energy arbitrage and provision of operating reserves to the microgrid, considering its performance parameters and capacity degradation over the planning horizon. Finally, in the third problem addressed in the thesis in the context of electricity markets, the non-strategic and strategic participation of a pumped hydro energy storage (PHES) facility in day-ahead energy and performance-based regulation (PBR) markets, which includes regulation capacity and mileage, are examined. The PHES is modeled with the capability of operating in hydraulic short-circuit (HSC) mode with detailed representation of its operational constraints, and integrated with an energy-cum-PBR market clearing model. For its strategic participation, a bi-level market framework is proposed to determine the optimal offers and bids of the PHES that maximize its profit. The operation of PHES is modeled at the upper level, while the market clearing is modeled in the lower level problem. The bi-level problem is formulated as a mathematical programming with equilibrium constraints (MPEC) model, which is linearized and solved as an MILP problem. Several case studies are carried out to demonstrate the impact of PHES' non-strategic and strategic operations on market outcomes. Furthermore, stochastic case studies are conducted to determine the PHES strategies considering the uncertainty of the net demand and rivals' price and quantity offers

A Techno-Economic Analysis of Lithium-Ion and Vanadium Redox Flow Batteries for Behind-the-Meter Commercial/Industrial Applications with a Focus on Achievable Efficiency and Degradation Rates.

This thesis concerns vanadium redox flow batteries (VRFB), and whether their posited advantages over the more commercially advanced lithium-ion battery (LIB) can translate to improved economic outcomes in realistic use-cases. The key advantage of the VRFB is increased lifetime; the energy storage medium (and major cost component) is simply two solutions of vanadium at differing oxidation states hence here is no scope for the myriad permanent degradation mechanisms that exist in LIB. As such, over a project lifetime VRFB will potentially have lower economic and environmental costs than LIB. A second posited advantage of the VRFB was the low incremental cost of storage duration, allowing longer durations to be more cost competitive. However, VRFB are disadvantaged by lower round-trip efficiency and a higher power capacity cost due to the relatively complex power generating apparatus. In this thesis, bottom up cost modelling for a state of the art VRFB predicted that following cost reductions in LIB over the last 5 years, the cost of incremental usable duration would now be very similar for the two technologies, negating one of the posited benefits. For the full cost-benefit analysis, it was hence important to rigorously define the use-cases and resulting cycle rates. The chosen case study was a commercial/industrial facility in South California. This region is a very promising market for stationary electrical storage, and as such was considered an arena in which VRFB and LIB are likely to compete in the near future. In order to thoroughly explore the thesis two differing archetypal use-case were formulated. In use-case A, the battery was called upon to reduce the electricity bill at the facility by time-shifting power imports to cheaper hours, reducing the peak power consumption each month, and generate revenue by providing spinning reserve and frequency response to the grid operator. The objective was strictly economic; to maximise the net present value of a ten year project. In use-case B, the battery was deployed in conjunction with a PV array in order to achieve self-sufficiency in power. In this case the self-sufficiency objective is in competition with the economic objective (to minimise the levelised cost of electricity), hence a multi-objective optimisation was used to size the battery and PV array. An important contribution made by this thesis was the incorporation of detailed degradation models for both VRFB and LIB. For VRFB, previous case studies had assumed zero degradation, whereas in practice regular intervention is required to avoid electrolyte imbalance. For LIB, similar case studies had employed models attributing all degradation to cycling, whereas continual temperature dependent aging is also important. The latter was modelled in this work. A novel mixed integer-quadratic programming (MIQP) method was introduced that allowed the VRFB operation to be optimised while accounting for the considerable variation in efficiency with power input/output. This is an improvement over previous VRFB case studies where a constant efficiency is assumed. In use-case A this resulted in the discovery of an energy saving strategy whereby the charging was performed at moderate power in order to track the peak efficiency as closely as possible. In a further novel contribution, this model was used to demonstrate the benefit of operating multiple VRFB modules as an ensemble. The benefit arises when a low load must be covered, and some modules may be idled to reduce parasitic losses. In use-case A, it was concluded that VRFB may compete with LIB under certain scenarios at 4 h duration, although the most profitable system is a shorter duration LIB. Both were predicted to break even at 6 h duration when current long duration storage incentives were included. For use-case B, both systems were predicted to achieve a SSR of 0.95 at under ¢21.5kW−1 h−1. Although the costs overlap depending on the scenario, VRFB were estimated to be more likely to be cheaper up to 0.9 SSR, above which reducing cycle rates favoured LIB. This level of self-sufficiency called for a usable duration of 6 h - 7.5 h. An important finding for project developers is hence that 6 h would be a sensible duration for both LIB and VRFB systems as this would cover both use cases effectively. Another novel contribution of this work to estimate the benefit of a hybrid LIB/VRFB system, the hypothesis being that the LIB could be used to cover the less frequent high charge/discharge power events. In use-case B this had the hypothesised effect of increasing the LIB lifetime, but there was negligible predicted effect on the overall levelised cost of electricity. Lastly, a number of important findings were made relating to practical operation of both LIB and VRFB, which should be of interest to asset owners. Firstly, in use-case A, it is unlikely that bidding for regulation provision would be feasible alongside demand charge reduction, as performing the former can result in a loss in the latter. Maintenance timing was predicted to be important for VRFB in use-case A where available revenue varies seasonally, and the capacity should be replenished prior to the peak revenue periods of the summer months. For LIB, it was predicted that managing state of charge will prolong life considerably in use-case B, and climactic variations across Southern California may strongly affect lifetime in both cases

A comprehensive review of demand side management in distributed grids based on real estate perspectives

A major challenge in renewable energy planning and integration with existing systems is the management of intermittence of the resources and customer demand uncertainties that are attributed to climates. In emerging distributed grids, state-of-the-art optimization techniques were used for cost and reliability objectives. In the existing literature, power dispatch and demand side management schemes were implemented for various techno-economic objectives. In renewable energy-based distributed grids, power dispatch is strategic to system operations. However, demand side management is preferred, as it allows more options for customer participation and active management of energy in buildings. Moreover, the demand side management can simply follow supplies. This paper investigates the implications of demand side management as it affects planning and operations in renewable energy-based distributed grids. Integration of demand side management in customer-oriented plans such as the time-of-use and real-time-pricing on residential and commercial demands is conceptualised to ensure effective customer participation which maintains the valued comforts. Moreover, the optimised tariff integrated demand side management implementations based on the utility-initiated demand response programmes are envisaged to offset conflicting objectives of the economy and customer comforts within residential and commercial demands and are also viewed as a step towards efficient management of energy in buildings

Integration, control and optimization of the solar photovoltaic-battery system in microgrids

This document composes the work realised and the research results developed within the scope of electric energy storage at the Renewable Energy Chair of the University of Évora. The current legal and technological framework of electrochemical energy storage technologies is reported, and its framework is demonstrated in the Portuguese and European contexts. Next, the experimental microgrid that comprises several electric energy storage technologies is described. The lithium-ion and vanadium redox flow technologies were tested and characterized for later validation of the electrical models that describe their performance. A state-of-the-art review allowed the experimentation of energy management strategies that fit the technologies studied, allowing smarter management in residential and services sectors. In this thesis, management algorithms, battery models, and an indication of technical, economic and energy parameters were combined in a tool to study the simulation of the operation of these technologies, allowing to define different operating objectives, fine-tune parameters and even join the operation of different technologies. This work was accompanied by national and international projects, attempting to respond to existing problems in the operation of real systems and gaps identified in the design phase, such as a robust dimensioning tool, with the integration of different battery managing methods; Integração, controlo e otimização do sistema solar fotovoltaico-bateria em microrredes Resumo: Este documento compõe o trabalho realizado e respetivos resultados da investigação desenvolvida no âmbito do armazenamento de energia elétrica na Cátedra Energias Renováveis da Universidade de Évora. Os atuais enquadramentos legais e tecnológicos das tecnologias eletroquímicas de armazenamento de energia são relatados, nos contextos português e europeu. Seguidamente, uma microrrede experimental que inclui diversas tecnologias de armazenamento de energia elétrica é descrita. As tecnologias de fluxo redox de vanádio e de iões de lítio foram objeto de ensaio e caracterização, para posterior validação dos correspondentes modelos que descrevem a sua performance elétrica. A revisão do estado da arte permitiu a experimentação de estratégias de gestão de energia que se adequam às tecnologias estudadas, que permitam a sua gestão inteligente, no contexto residencial e de serviços. Nesta tese, os algoritmos de gestão, os modelos das baterias, a indicação de parâmetros técnicos, económicos e energéticos foram combinados numa ferramenta para estudo da simulação da operação destas tecnologias permitindo definir diferente objetivos, afinar parâmetros e até operar conjuntamente diferentes tecnologias. Este trabalho foi acompanhado pelo paralelismo de projetos nacionais e internacionais, tentado dar resposta a problemas existentes na operação de sistemas reais, e lacunas identificadas na fase de projeto, tal como uma ferramenta de dimensionamento robusto, com a integração de diferentes formas de gerir baterias

3rd Annual Meeting of the Portuguese Association of Energy Economics & 5th Meeting of Environmental and Energy Economics

The 3rd Annual Conference of the Portuguese Association of Energy Economics – APEEN and the International Meeting on Energy and Environmental Economics – ME3 took place on the 18-19 October 2018 in Braga, Portugal. The event was hosted by the Universidade do Minho and gathered the contributions of specialists in Energy and Environmental Economics to enrich the debate about the many issues raised by the management of resources and waste. The main topic was Managing Resources and Waste: challenges for Energy and Environmental Economics beyond 2030. ​Natural resources are the keystone in environmental and energy economics. Nowadays, resource management cannot ignore waste, traditionally seen as a by-product of consumption and production decisions, but increasingly recognized as a source of energy or as new type of resource

The benefits of distributed battery energy storage systems for customers and network operators based on measured data from deployed systems

The rapid growth in distributed energy resources such as solar photovoltaics and battery energy storage systems (BESS) has introduced unprecedented opportunities and challenges for the electricity sector. Although these systems increase the self-consumption of the customer, their integration requires further investment into the electricity network, and they reduce the revenue of the network operators. Conversely, there are opportunities to engage distributed BESS to perform multiple grid services that may benefit all customers and the network operator. Out of these services, the reduction of network demand peaks and photovoltaic export peaks are highly valued in the electricity sector. Currently, there is a lack of literature on detailed analysis of deployed, non-coordinated residential BESS and assessment of co-optimisation of commercial-scale BESS to maximise the financial outcomes for both the customers and the network operator. This thesis explores these gaps in the literature in the following contexts: i) the ability of residential BESS to reduce demand during network peaks, ii) the ability of residential BESS to reduce photovoltaic export peaks, and iii) the ability of commercial-scale BESS to be co-optimised for both the customers and the network operator. Analysing the measured data from deployed systems showed that on average, residential BESS that were operating as expected were already discharging to support the network during demand peaks but were unable to reduce photovoltaic export peaks because they were charged to full prior to the peak period. Different operational strategies for the BESS were modelled and it was found that setting a 27% limit on the batteries’ charging power can increase their export peak reduction from almost 0% to 15%, with no impact on their ability to increase self-consumption. A co-optimisation model was developed for a scenario of maximising the financial outcomes of installing commercial-scale BESS for both customers and the network operator. Although the outcomes are site-specific, the model could be used to assess the outcomes at different locations and under different assumptions. Taken together these findings should provide knowledge and methods that will contribute to the uptake of behind the meter BESS in a way that benefits all customers and the network operator

Optimisation, Optimal Control and Nonlinear Dynamics in Electrical Power, Energy Storage and Renewable Energy Systems

The electrical power system is undergoing a revolution enabled by advances in telecommunications, computer hardware and software, measurement, metering systems, IoT, and power electronics. Furthermore, the increasing integration of intermittent renewable energy sources, energy storage devices, and electric vehicles and the drive for energy efficiency have pushed power systems to modernise and adopt new technologies. The resulting smart grid is characterised, in part, by a bi-directional flow of energy and information. The evolution of the power grid, as well as its interconnection with energy storage systems and renewable energy sources, has created new opportunities for optimising not only their techno-economic aspects at the planning stages but also their control and operation. However, new challenges emerge in the optimization of these systems due to their complexity and nonlinear dynamic behaviour as well as the uncertainties involved.This volume is a selection of 20 papers carefully made by the editors from the MDPI topic “Optimisation, Optimal Control and Nonlinear Dynamics in Electrical Power, Energy Storage and Renewable Energy Systems”, which was closed in April 2022. The selected papers address the above challenges and exemplify the significant benefits that optimisation and nonlinear control techniques can bring to modern power and energy systems