Electricity System Costs Research Articles

Oahu as a case study for island electricity systems relying on wind and solar generation instead of imported petroleum fuels

A macro-scale electricity model was used to evaluate whether wind and solar generation, combined with short- and long-duration energy storage, could cost-effectively provide 100% of Oahu's electricity. A least-cost renewable electricity system was developed with 100% of hourly averaged demand met, based on 14 consecutive years of hourly wind and solar resource and electricity demand data. The system used current asset costs for wind generation, solar generation, short-duration battery storage, and long-duration hydrogen energy storage. Our results indicate that Oahu could transition to an electricity system reliant on wind and solar generation and battery and hydrogen storage with electricity costs lower than today's electricity costs. For Oahu, a least-cost wind-solar-battery electricity system that would have met 100% of hourly averaged demand would have a system cost of $0.2458 per kWh. In comparison, from October 2022 through September 2023, electricity generation costs from the petroleum-dominated electricity system on Oahu were between $0.2126/kWh and $0.2987/kWh. This wind-solar-battery system would require 332 km2 (21.4%) of Oahu's land. Moreover, including hydrogen storage as a second form of energy storage led to reductions in system cost and land use. At current asset costs, a least-cost wind-solar-battery‑hydrogen electricity system that would have met 100% of hourly averaged demand would have a system cost of $0.1673/kWh and require 265 km2 (17.1%) of Oahu's land. This case study indicates that other isolated regions with similar resource profiles and a reliance on imported petroleum fuels could realize a decrease in electricity system costs when switching to renewables in conjunction with short- and long-duration energy storage, at current asset costs, while meeting demand in full over extended periods of renewable resource variability.

Opportunities and constraints of hydrogen energy storage systems

Abstract In contrast to battery storage systems, power-to-hydrogen-to-power (P-H2-P) storage systems provide opportunities to separately optimize the costs and efficiency of the system’s charging, storage, and discharging components. The value of capital cost reduction relative to round-trip efficiency improvements of P-H2-P systems is not well understood in electricity systems with abundant curtailed power. Here, we used a macro-energy model to evaluate the sensitivity of system costs to techno-economic characteristics of P-H2-P systems in stylized wind-solar-battery electricity systems with restricted natural gas generation. Assuming current costs and current round-trip P-H2-P efficiencies, least-cost wind and solar electricity systems had large amounts of excess variable renewable generation capacity. These systems included P-H2-P in the least-cost solution, despite its low round-trip efficiency and relatively high P-H2-P power discharge costs. These electricity system costs were not highly sensitive to the efficient use of otherwise-curtailed power, but were sensitive to the capital cost of the P-H2-P power discharge component. If the capital costs of the charging and discharging components were decreased relative to generation costs, curtailment would decrease, and electricity system costs would become increasingly sensitive to improvements in the P-H2-P round-trip efficiency. These results suggest that capital cost reductions, especially in the discharge component, provide a key opportunity for innovation in P-H2-P systems for applications in electricity systems dominated by wind and solar generation. Analysis of underground salt cavern storage constraints in U.S.-based wind and solar scenarios suggests that ample hydrogen storage capacity could be obtained by repurposing the depleted natural gas reservoirs that are currently used for seasonal natural gas storage.

Evaluation of decarbonization cost transfer: From transport to power sector in South Korea

To achieve net-zero emissions, major countries have implemented energy transition and electrification policies, incurring significant costs. Each sector, including generation, industry, transport, and buildings, has its own decarbonization strategy. However, as net-zero emission is a cross-sectoral issue, decarbonization efforts in one sector can impact others. In this study, we employed a combination of renewable energy adoption planning, battery electric vehicles (BEVs) charging pattern simulation, and electricity market modeling to evaluate the cost implications of transitioning to BEVs in the transport sector and its subsequent impact on the power generation sector. We considered long-term Korean policies for the power and transport sectors when constructing scenarios to compare transition costs. Our results indicate that, while the additional electricity demand from BEVs increases electricity system costs, utilizing nuclear power can significantly reduce these costs. The estimated cost of BEVs, totaling three billion US dollars, can be covered through the relevant transition policy in the power sector. However, nuclear power in Korea is only a temporary solution that delays the social costs of achieving net-zero emissions. Thus, the Korean government should develop alternatives for clean electricity. Our results also suggest that the decarbonization cost transition from a sector to the power sector should be considered in the net-zero policy.

Global transcontinental power pools for low-carbon electricity

The transition to low-carbon electricity is crucial for meeting global climate goals. However, given the uneven spatial distribution and temporal variability of renewable resources, balancing the supply and demand of electricity will be challenging when relying on close to 100% shares of renewable energy. Here, we use an electricity planning model with hourly supply-demand projections and high-resolution renewable resource maps, to examine whether transcontinental power pools reliably meet the growing global demand for renewable electricity and reduce the system cost. If all suitable sites for renewable energy are available for development, transcontinental trade in electricity reduces the annual system cost of electricity in 2050 by 5–52% across six transcontinental power pools compared to no electricity trade. Under land constraints, if only the global top 10% of suitable renewable energy sites are available, then without international trade, renewables are unable to meet 12% of global demand in 2050. Introducing transcontinental power pools with the same land constraints, however, enables renewables to meet 100% of future electricity demand, while also reducing costs by up to 23% across power pools. Our results highlight the benefits of expanding regional transmission networks in highly decarbonized but land-constrained future electricity systems.

Seasonal variation in electricity demand of solar-powered net-zero energy housing in temperate climates

Net-zero energy buildings produce enough renewable energy to meet their own annual energy requirements and have been proposed as an important method of reducing operational greenhouse gas emissions in the building sector. However, self-generation via building-integrated solar PV in cold and temperate climates is anti-correlated with increasingly-electrified heating demand and could increase seasonal variability in net electricity demand to the point that it poses challenges for future electricity systems. In this paper we explore scenarios of future large-scale uptake of electrically-heated, solar-PV net-zero energy residential buildings in New Zealand and quantify the seasonal variation of the resulting net electricity demand. A scenario of large-scale uptake of very high efficiency buildings leads to reductions in annual demand of −30% and seasonal variation of −50% in 2050 compared to a base case of current building standards. In comparison, a scenario with self-generation via solar PV without changes to the building standard reduces annual demand by −30% but increases seasonal variation by +40%. In a scenario where very high building standards are combined with solar PV, annual demand decreases by −65% and seasonal variation by only −4%. From a policy perspective, whether large-scale solar PV self-generation should be supported (in addition to very-high efficiency buildings) depends on an economic trade-off between the value of distributed solar generation (including any carbon emission reductions) vs the electricity system cost of seasonal variation. For New Zealand, given the low cost of renewable electricity from a variety of alternative sources, scenarios of large-scale uptake of solar-powered net-zero energy buildings are not favourable from an electricity system perspective.

Nuclear Fusion impact on the requirements of power infrastructure assets in a decarbonized electricity system

Electrification of final energy use and electricity generation by low-carbon technologies are key points of the path toward carbon-neutrality. Carbon free electricity can be generated by both nuclear and renewable energy sources. Nevertheless, although all of them can be economically viable in terms of ‘Levelized Cost Of Energy‘, their exploitation involve variable renewables, so as to require power system upgrades with adequate energy storage systems, dispatchable generation capacity and transmission/distribution grid enhancements (power infrastructure assets) that may lead to relevant additional system costs. To this respect, each power system is almost unique, due to its peculiarities as far as renewable potentials is concerned. In order to find the least cost feasible and reliable generation mix, detailed hourly simulations are necessary. In this paper, long term power generation scenarios will be simulated with the COMESE code, a dispatch model able to perform detailed regional power systems analysis. Carbon-free Italian power system long term scenarios are simulated, with high share of photovoltaic and to less extent wind electricity together with a possible contribution of nuclear fusion power plants. The operation of the transmission grid is simulated, through a transport model, in order to assess the necessary grid enhancement and to estimate the related costs. In this context the impact of fusion will be assessed in terms of mitigation of the overall system cost of electricity.

Optimum hybrid renewable energy system design for on and off grid buildings: Hotel, education and animal hospital building case

Optimum design of hybrid renewable systems is essential for the efficient utilization of the renewable sources and uninterruptible energy supply. The size and backup capacity of the system are effected by the hourly energy demand profile of the building.In this study, optimal design of PV/wind/battery/diesel hybrid renewable energy system (HRES) for the electrification of a hotel building (HB), education building and animal hospital (AH) for on and off grid cases are evaluated to compare buildings with different demand profiles. The hourly electricity consumption of the buildings is measured during January 2023. Nonlinear swarm optimization algorithm was used to minimize the system cost of electricity (COE) and maximize the renewable fraction.Optimal off-grid HRES found to include PV and wind turbine together. AH represented the most stable and highest hourly demand which resulted in minimum COE (0.18 $/kWh and 0.321 $/kWh) for on and off grids.Then annual electricity consumptions of the buildings are equalized to compare buildings with the same annual but different hourly load. On-grid HB found to have minimum COE (0.177 $/kWh) due to the closer hourly demand profile on weekends and weekdays then other buildings. Therefore, on-grid HRES configurations are found to be more cost effective in buildings utilized seven days of the week. However, in off-grid case minimum COE (0.321 $/kWh) was obtained for AH and maximum was found for HB which was due to the peak demands. The result shows that buildings with sudden increases require high battery capacity which results in high COE.

Technical and economic performance analysis of large flat plate solar collector coupled air source heat pump heating system

In rural areas of China, clean energy heating in winter is important for coal replacement. Winter temperatures in northwest China are usually below 0°Celsius and the heating season lasts for a long time, which is a huge expense for local residents. Solar energy, air source heat pumps(ASHP), and other energy-saving technologies are known to be effective in reducing heating expenses. However, due to the intermittent and unstable nature of solar energy itself, relying on solar heating is difficult to ensure stable heating and is certainly not economical. ASHP adds a financial burden to local residents due to the relatively high cost of winter heating. In response to the above problems, a new idea of ASHP coupled with solar energy for stable heating is proposed, and a large flat plate solar collector-air source heat pump(LFPSC-ASHP) heating system was established in Green Village, Lanzhou City. Experimental and simulation studies were conducted for this system to reveal the performance and economic benefits of the system for the heating season in three modes: solar collector heating, solar heat pump heating, and air source heat pump heating. The results show that the ASHP-assisted solar heating system is a great technical and economical improvement over the use of solar collectors or ASHP heating throughout the heating season. The LFPSC-ASHP system can continuously and stably heat the target building and has excellent economic and environmental benefits. In the operation of the whole heating season, the average collector efficiency of LFPSC is 0.42, the average COP of solar heat pump heating season is 3.75, and the average COP of ASHP heating season is 2.94. The solar fraction of the system in the whole heating season is 31.8 %, and the system energy efficiency ratio is 3.08. The system can save 7,690.5 CNY by running the whole heating season with a dynamic payback period of 6.58 years. ​Sensitivity analysis of the dynamic payback period shows that lower coal prices extend the dynamic payback period, while lower electricity prices and system costs reduce it. The primary energy saving rate of the system in the whole heating season is 67.5 %. The system can conserve 4,700.06 kg of standard coal in a whole heating season, which is equivalent to a reduction of 12,323.55 kg of CO2.

Integration of electric vehicles into transmission grids: A case study on generation adequacy in Europe in 2040

Electric vehicles (EVs) are expected to grow massively in the coming years, and grid integration of a large number of them could challenge electricity-system infrastructure. This paper aims at describing a methodology to study the technical and economic impacts on power systems of mass EV charging for several EV-owner connection behavior profiles (systematic, when necessary, when convenient) and the range of recharge modes available (uncontrolled, time-of-use tariff, smart unidirectional charging, and vehicle-to-grid). This framework is applied to a case study at hourly resolution of high penetration of electric vehicles and renewable energy sources in Europe at the 2040 time-horizon, in line with the ‘National Trends Scenario’ grid mix under the pan-EU ENTSO-E Ten-Year Network Development Plan. Results show that the European electricity system can accommodate large EV growth and that widespread adoption of smart charging in France can significantly reduce operational electricity system costs by up to 1.1 G€ and reduce carbon emissions by up to 3.2 MtCO2 per year. Multiple EV smart charging modes are also compared and the parameters have the largest impact on EV flexibility are identified, including gas prices, smart charging adoption, weekly flexibility, and mid-day charging.

The role of new nuclear power in the UK's net-zero emissions energy system

Swift and deep decarbonisation of electricity generation is central to enabling a timely transition to net-zero emission energy systems. While future power systems will likely be dominated by variable renewable energy (VRE) sources, studies have identified a need for low-carbon dispatchable power such as nuclear. We use a cost-optimising power system model to examine the technoeconomic case for investment in new nuclear capacity in the UK's net-zero emissions energy system and consider four sensitivity dimensions: the capital cost of new nuclear, the availability of competing technologies, the expansion of interconnection and weather conditions. We conclude that new nuclear capacity is only cost-effective if ambitious cost and construction times are assumed, competing technologies are unavailable and interconnector expansion is not permitted. We find that bioenergy with carbon capture and storage (BECCS) and long-term storage could reduce electricity system costs by 5–21% and that synchronous condensers can provide cost-effective inertia in highly renewable systems with low amounts of synchronous generation. We show that a nearly 100% variable renewable system with very little fossil fuels, no new build nuclear and facilitated by long-term storage is the most cost-effective system design. This suggests that the current favourable UK Government policy towards nuclear is becoming increasingly difficult to justify.

Impact of energy communities on the European electricity and heating system decarbonization pathway: Comparing local and global flexibility responses

This paper investigates how the European electricity and heating system is impacted when medium-scale energy communities (ECs) are developed widely across Europe. We study the response on the capacity expansion of the cross-border transmission and national generation and storage within the European electricity and heating system with and without ECs in selected European countries. The representation of ECs has a special focus on flexibility, and we analyze the difference between flexibility responses by ECs towards local versus global cost minimization. Results show that EC development decreases total electricity and heating system costs on the transition towards a decarbonized European system in line with the 1.5 °C target, and less generation and storage capacity expansion is needed on a national scale to achieve climate targets. We also identify a conflict of interest between optimizing EC flexibility towards local cost minimization versus European cost minimization.

Timed to save: the added value of accounting for hourly incidence of electricity savings from residential space-conditioning measures

Previous research has recognized that the value of measures that reduce electricity usage depends upon the timing of the savings generated, but the lack of hourly savings shapes has limited the demonstration of this concept. We develop empirical hourly savings shapes for residential space-conditioning measures from nearly 18,000 efficiency projects in California and show how they combine with the diurnal and seasonal variation in electricity system costs. We find that these measures (cooling replacements; windows, doors, and skylights; and other envelope measures) tend to save electricity when system costs are highest and that the hourly savings account for 1.4–1.5 times as much value as non-time-sensitive estimates of efficiency would predict. We present these impact multipliers for each measure to quantify the additional value revealed by the time-sensitive approach. We show that this additional value is similar in an evolving electricity grid with storage, rather than natural gas generation, as the marginal resource.

Cost optimal combinations of storage technologies for maximizing renewable integration in Indian power system by 2040: Multi-region approach

Preventing an increase in emission intensity requires a transition to a renewable-based electricity system. Wind and solar power are often the major contributors to this transition. The inherently variable nature of the generation pattern of these renewable sources impels the inclusion of storage technologies. But how to combine renewable and diverse storage technologies in a cost-competitive way? This paper addresses this question by constructing the first open-sourced, spatially, and hourly resolved model of the Indian power system and analysing the system for cost-optimal storage combinations. Increasing the renewable share targets from 30% to 75% of electricity supply, the levelized costs and storage technology options for various energy scenarios are assessed. Results show that the system cost of electricity can vary between 3.65 R/kWh and 4.37 R/kWh with the help of transmission expansion and inter-regional coordination. 50% of RES penetration is found to be a critical target beyond which the total annual system cost increments rise sharply. The optimal solution at 50% RES share includes a maximum of 11 GWh of battery and 29.8 GWh of hydrogen storage capacity. Sensitivity analysis shows that cost reduction in the storage technologies results in the lowest system cost even with limited transmission expansion.

The effect of differentiating costs of capital by country and technology on the European energy transition

Cost of capital is an important driver of investment decisions, including the large investments needed to execute the low-carbon energy transition. Most models, however, abstract from country or technology differences in cost of capital and use uniform assumptions. These might lead to biased results regarding the transition of certain countries towards renewables in the power mix and potentially to a sub-optimal use of public resources. In this paper, we differentiate the cost of capital per country and technology for European Union (EU) countries to more accurately reflect real-world market conditions. Using empirical data from the EU, we find significant differences in the cost of capital across countries and energy technologies. Implementing these differentiated costs of capital in an energy model, we show large implications for the technology mix, deployment, carbon emissions and electricity system costs. Cost-reducing effects stemming from financing experience are observed in all EU countries and their impact is larger in the presence of high carbon prices. In sum, we contribute to the development of energy system models with a method to differentiate the cost of capital for incumbent fossil fuel technologies as well as novel renewable technologies. The increasingly accurate projections of such models can help policymakers engineer a more effective and efficient energy transition.

Integrating palm oil biomass waste utilization in coal-fired power plants for meeting near-term emission targets

Biomass co-firing with coal can be adopted in the electricity sector to promote greenhouse gas reduction, renewable energy production, and resource efficiency improvement toward environmental sustainability. This realization, however, requires effective management of supply chain issues, such as the collection of biomass feedstock, the transportation of biomass, and the localization of biomass processing plants to deliver the co-firing scales needed. This work addresses these issues by providing a techno-economic assessment conducted in a spatially-explicit manner to investigate the opportunity for scaling up the co-firing deployment at the national scale. The modeling approach is applied to the case of Malaysia's coal and palm oil biomass industries. The number of cases involving the impact of energy decarbonization targets, economic policy instrument, and supply chain cost parameter variations on the co-firing scales deployed are assessed. The findings show that densified biomass feedstock can substitute significant shares of coal capacities to deliver up to 29 MtCO2/year of carbon dioxide reduction. Nevertheless, this would cause a surge in the electricity system cost by up to 2 billion USD/year due to the substitution of up to 40% of the coal plant capacities. In facilitating the maximal deployment of co-firing at the national scale, more than 100 solid biofuel production plants would need to be built to support a maximum of 41 TWh/year of co-firing capacity. Actions to minimize the specific cost elements of the biomass co-firing supply chain are thus needed in the near term to increase the effectiveness of economic policy instrument to promote co-firing and reduce environmental emissions.

The impacts of the electricity demand pattern on electricity system cost and the electricity supply mix: A comprehensive modeling analysis for Europe

Energy system models for long-term planning are widely used to explore the future electricity system. Typically, to represent the future electricity demand in these models, historical demand profiles are used directly or scaled up linearly. Although the volume change for the electricity demand is considered, the potential change of the demand pattern is ignored. Meanwhile, the future electricity demand pattern is highly uncertain due to various factors, including climate change, e-mobility, electric heating, and electric cooling. We use a techno-economic cost optimization model to investigate a stylized case and assess the effects on system cost and electricity supply mix of assuming different demand patterns for the models. Our results show that differences in diurnal demand patterns affect the system cost by less than 3%. Similarly, demand profiles with a flat seasonal variation or a winter peak result in only minor changes in system cost, as compared to the present demand profile. Demand profiles with a summer peak may display a system cost increase of up to 8%, whereas the electricity supply mix may differ by a factor of two. A more detailed case study is conducted for Europe and the results are consistent with the findings from the stylized case.

Economic impacts of achieving a net-zero emissions target in the power sector

With increasing concerns about climate change, calls for the adoption of net-zero carbon emissions targets are rising. Achieving this target necessitates a radical decarbonisation of the electricity system, including the shut-down of currently operating high-carbon energy infrastructure. In the light of this background, we develop a novel system dynamics energy-economy model to explore the long-term macroeconomic effects, and changes in the power system costs of different low-carbon electricity transition scenarios. Using the UK as a case study, our simulations demonstrate that there is no win-win policy solution. We argue that while the early retirement of a certain amount of brown energy infrastructure is required for the UK to achieve its emissions target, the amount should be determined with care in order to manage the electricity system costs and prices. By using an implicit carbon price, we find that certain trajectories lead to lower power system costs while achieving the net-zero target.

The curtailment paradox in the transition to high solar power systems

Summary Rising penetrations of variable renewable energy (VRE) in power systems are expected to increase the curtailment of these resources because of oversupply and operational constraints. We evaluate the effect on curtailment from various flexibility approaches, including storage, thermal generator flexibility, operating reserve eligibility rules, transmission constraints, and temporal resolution, by using a highly resolved realistic system. Results reveal two aspects of a curtailment paradox as the system evolves to higher solar penetration levels. First, thermal generator parameters, especially in restricting minimum operating levels and ramp rates, affect VRE curtailment more in mid-PV penetration levels (∼25%–40%) but much less at lower (∼20%) or higher (∼45%) PV penetration levels. Second, although allowing VRE and storage to provide operating reserve results in significant operating costs and curtailment benefits, the price suppression effect from these resources reduces incentives for PV to provide operating reserves with curtailed energy.

Deleterious effects of strategic, profit-seeking energy storage operation on electric power system costs

Energy storage will play a key role in the unfolding energy transition, but current market design and the modeling efforts that inform discussions surrounding its role broadly assume that these systems will not be deployed in ways deleterious to the objectives of the wider power grid. This is myopic: there are plausible and strategic modes of storage operation that clash with wider grid objectives while maximizing profits for storage system owners. Here we compare three modes: one that is commonly modeled and is broadly beneficial to the power system—peak shaving—with two plausible but deleterious ones—load leveraging and ramp augmenting—and show how the latter two increase system costs and help generators earn substantial profits even when they bid at marginal cost. Our work adds to a growing literature about the unintended consequences of energy storage on the power system and elaborates the essential role of policy makers and regulators in mitigating these effects.

Deep decarbonization in Northeastern North America: The value of electricity market integration and hydropower

In several countries, electricity systems are under strong decarbonization pressure. In particular, the Canadian provinces of Quebec and Ontario as well as the states of the northeastern United States have committed to cut their greenhouse emissions by more than 70% (with respect to emission levels of 1990). Increased collaboration and integration between jurisdictions could decrease such decarbonization costs, especially when important hydropower resources are available.Using a capacity expansion and dispatch model of the Northeastern North American electricity sector, we analyze the impact of emission reduction targets, load levels and availability of power technologies in a range of scenarios, in order to assess the benefits of regional cooperation. Our results show that for deep decarbonization, the electricity system costs can be significantly reduced through integration, especially by adding more interconnection capacity. These costs savings and benefits are however not evenly allocated between jurisdictions, creating potentially difficult collaboration incentives.