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The Role of Firm Low-Carbon Electricity Resources in Deep Decarbonization of Power Generation
Abstract
We investigate the role of firm low-carbon resources in decarbonizing power generation in combination with variable renewable resources, battery energy storage, demand flexibility, and long-distance transmission. We evaluate nearly 1,000 cases covering varying CO2 limits, technological uncertainties, and geographic differences in demand and renewable resource potential. Availability of firm low-carbon technologies, including nuclear, natural gas with carbon capture and sequestration, and bioenergy, reduces electricity costs by 10%–62% across fully decarbonized cases. Below 50 gCO2/kWh, these resources lower costs in the vast majority of cases. Additionally, as emissions limits decrease, installed capacity of several resources changes non-monotonically. This underscores the need to evaluate near-term policy and investment decisions based on contributions to long-term decarbonization rather than interim goals. Installed capacity for all resources is also strongly affected by uncertain technology parameters. This emphasizes the importance of a broad research portfolio and flexible policy support that expands rather than constrains future options.
... Carbon dioxide (CO 2 ) capture and storage (CCS)-the process of capturing CO 2 from an industrial exhaust stream or, in the case of direct air capture (DAC), ambient air and storing it permanently or for use in other industrial processes-has garnered increasing attention in recent years given its potentially critical role in achieving a decarbonized US power system (and, more broadly, a decarbonized economy) [1][2][3]. The deployment of variable renewable energy (VRE) technologies such as wind, solar, and some hydroelectric technologies can achieve deep reductions in power system CO 2 emissions when combined with storage technologies and with limited costs. ...
... The deployment of variable renewable energy (VRE) technologies such as wind, solar, and some hydroelectric technologies can achieve deep reductions in power system CO 2 emissions when combined with storage technologies and with limited costs. As the VRE share of total generation approaches 100%, costs increase non-linearly [1,[4][5][6], predominantly driven by declining relative contributions of VRE to meeting resource adequacy needs [5,7]. As such, a number of studies conclude that achieving a zero-carbon target at lowest cost is supported through deployment of other low-to negative-emitting, non-VRE technologies such as biomass, geothermal, hydropower, CCS, hydrogen, and nuclear to meet this final portion of the load [1,2,6,8]. ...
... As the VRE share of total generation approaches 100%, costs increase non-linearly [1,[4][5][6], predominantly driven by declining relative contributions of VRE to meeting resource adequacy needs [5,7]. As such, a number of studies conclude that achieving a zero-carbon target at lowest cost is supported through deployment of other low-to negative-emitting, non-VRE technologies such as biomass, geothermal, hydropower, CCS, hydrogen, and nuclear to meet this final portion of the load [1,2,6,8]. ...
Carbon dioxide (CO2) capture and storage (CCS) is frequently identified as a potential component to achieving a decarbonized power system at least cost; however, power system models frequently lack detailed representation of CO2 transportation, injection, and storage (CTS) infrastructure. In this paper, we present a novel approach to explicitly represent CO2 storage potential and CTS infrastructure costs and constraints within a continental-scale power system capacity expansion model. In addition, we evaluate the sensitivity of the results to assumptions about the future costs and performance of CTS components and carbon capture technologies. We find that the quantity of CO2 captured within the power sector is relatively insensitive to the range of CTS costs explored, suggesting that the cost of CO2 capture retrofits is a more important driver of CCS implementation than the costs of transportation and storage. Finally, we demonstrate that storage and injection costs account for the predominant share of total costs associated with CTS investment and operation, suggesting that pipeline infrastructure costs have limited influence on the competitiveness of CCS.
... De Sisternes et al. [6] also found that the most cost-effective approach would be to include nuclear power; the results from this paper indicate that energy storage may be essential to enable climate mitigation strategies dependent exclusively on very high shares of wind or solar energy, but storage is not a requirement if a more diverse mix of flexible, low-carbon power sources is considered. Other studies have achieved similar results [10], indicating that firm capacity from conventional generation could play a vital role in the energy transition to lower total power system costs, especially considering the prospects of carbon capture and storage (CCS) [43]. Some authors have highlighted that the availability of these zero-carbon firm technologies could diminish the need for LDES, but most of these studies fail to correctly model LDES due to oversimplification [41]. ...
... However, CCS is still an immature technology with the potential of being a high-cost, high-risk solution on economic, environmental, and social grounds [43]. One reason is that CO 2 is not the only harmful emission associated with burning fossil fuels, and the technology does not address sulphur oxide, nitrogen oxide, or heavy metal emissions [2]. ...
... The ongoing decarbonisation of the energy sector, including stricter emission requirements, is one of the main drivers for the market creation of LDES [4]. Generally, the more stringent permits, the faster the market opens, as fossil fuels have increased difficulty competing in VRE balancing [6,43]. This effect is also shown in Childs et al. [24], where LDES needs increased substantially when a more restrictive greenhouse gas target was adopted. ...
The relationship between a region’s dependency on variable renewable energy (VRE) and the viability of long-duration energy storage (LDES) technologies is recognised through various electricity grid modelling efforts in the contemporary literature. Numerous studies state a specific VRE penetration level in total electricity generation as an indicator of the emergence of an LDES market. However, there is considerable variability across studies when comparing VRE penetration levels in conjunction with LDES technology utilisation, and significant diversity exists in electricity grid modelling approaches. This review aims to highlight these inconsistencies by offering an overview of disparate findings and dissecting the influencing variables. Sixteen parameters are identified from reviewed studies, complemented by an additional five recognised through in-depth analysis. This comprehensive examination not only sheds light on critical aspects overlooked in previous reviews, requiring further investigation, but also provides novel insights into the complexity of this correlation, elevating the understanding of LDES market creation by unravelling the factors that influence the technology adoption across various contexts. Furthermore, it provides clarity in LDES research terminology by rectifying ambiguous language in the existing literature. Altogether, seven databases were explored to produce a trustworthy foundation for the study.
... Wind and solar power are the key drivers of electricity decarbonization. While the global energy infrastructure is still in the early stage of a transition away from the fossil fuels toward the energy sources with near-zero greenhouse gas emissions, projections and proposals indicate electricity supply relying on wind and solar power will continue to expand in the near-term (Jacobson et al., 2017;Sepulveda et al., 2018;Williams et al., 2012). ...
... Despite their growing importance, wind and solar energy are subject to inherent limitations, which include intrinsic variability, substantial land requirements, technical difficulties in grid integration, and others (Albertus et al., 2020;Gowrisankaran et al., 2016;Jurasz et al., 2020;Sepulveda et al., 2018;Shaner et al., 2018;Tong et al., 2020;Ueckerdt et al., 2013). These limitations make it challenging to guarantee a stable and reliable supply of electricity from wind and solar energy to the power grid. ...
Plain Language Summary
A carbon neutral future depends upon deep decarbonization of the electricity sector. As we move toward a future where we use cleaner energy sources, like wind and solar, it is important to ensure that the electric grid stays reliable. Scientists have been studying how climate change affects the weather, but we know less about how climate change affects periods when there is not enough wind or sunlight to generate renewable energy—known as “power droughts.” And to plan for the future, we need to study power droughts in global climate models. We analyze the climate models to assess how good they are at predicting when these energy shortages might happen in two regions of the United States. We found that adjusting the models to better match real‐world conditions improved how well they predicted the frequency of these power droughts. Refining model horizontal resolution from 100 to 25 km, did not impact the simulation of historical power droughts. Our results also show that in the future, the frequency of these power droughts will vary in a region‐dependent manner. Such information can help us plan for a future that is increasingly dependent on more sustainable energy sources.
... Numerous potential solutions to this problem have been studied by researchers 11 . Some studies focus on "firm" low-carbon resources capable of flexible operation [12][13][14][15][16] . Other studies focus on transmission expansion and inter-regional coordination as a source of flexibility 17,18 . ...
... Finally, numerous papers have discussed the benefits of firm generation such as carbon capture and sequestration (CCS) technologies [13][14][15][16]21,66,67 . In this paper, we include some firm generation technologies in the model (i.e., biomass and geothermal) but do not include CCS technologies. ...
Long-duration energy storage (LDES) is a key resource in enabling zero-emissions electricity grids but its role within different types of grids is not well understood. Using the Switch capacity expansion model, we model a zero-emissions Western Interconnect with high geographical resolution to understand the value of LDES under 39 scenarios with different generation mixes, transmission expansion, storage costs, and storage mandates. We find that a) LDES is particularly valuable in majority wind-powered regions and regions with diminishing hydropower generation, b) seasonal operation of storage becomes cost-effective if storage capital costs fall below US$5 kWh⁻¹, and c) mandating the installation of enough LDES to enable year-long storage cycles would reduce electricity prices during times of high demand by over 70%. Given the asset and resource diversity of the Western Interconnect, our results can provide grid planners in many regions with guidance on how LDES impacts and is impacted by energy storage mandates, investments in LDES research and development, and generation mix and transmission expansion decisions.
... Growth in variable renewable energy (VRE) is already occurring and this is expected to continue. Given Alberta's relative lack of transmission capacity with neighbouring jurisdictions and barring significant improvements in large-scale energy storage, the challenge will be in the ability to turn this cheap raw energy into the clean and reliable power consumers demand (Sepulveda et al., 2018). ...
... The Strathcona Salt Cavern (see Figure 3, below) is located near the backbone (240-kilovolt) alternating-current lines of the Alberta grid, and the high-voltage direct current Western Alberta Transmission Line and Eastern Alberta Transmission Line (of 500 kilovolts each) meet near the cavern, allowing transmission of renewable-sourced energy to and from the cavern site from southern Alberta. A facility like Intermountain over the Strathcona Salt Cavern, running initially on a methane and hydrogen mix, then 100 per cent hydrogen, or two-way solid-oxide fuel cells, could create multiple firm renewable power benefits Sepulveda et al. 2018). Electricity could be purchased when cheap ($0.01 to $0.03 per kilowatt-hour) to produce hydrogen, which would be stored in the cavern, helping stabilize electricity prices during surplus. ...
This paper explores the role that hydrogen can play in helping Alberta decarbonize its electricity system. Alberta has an abundance of natural gas resources that can be converted to hydrogen fuel and further used to generate electricity either through a turbine or through a fuel cell. Since Alberta has a significant portion of its current electricity needs supplied by combustion and steam turbines, such turbines can be repurposed to use hydrogen fuels and therefore reduce the amount of stranded assets as the province moves towards lower emissions in the electricity industry. Using hydrogen in the electricity industry can also complement a higher percentage of variable renewable energy resources, like wind and solar, by absorbing excess generation via electrolysis and providing much needed reliability as a peaking product. The carbon price and associated carbon policy in Alberta appears to be a key driver incentivizing hydrogen use in the electricity industry. Our model comparing the marginal costs of natural gas versus hydrogen for electricity production concludes that with the current carbon policy in Alberta and a rising carbon price to $170 per tonne CO2e in 2030, hydrogen has the potential to compete with natural gas as a dominant, "on-demand" power source.
... Multiple studies assessing strategies to decarbonize the electric power sector underscore the need for low-carbon, reliable power sources such as hydropower, nuclear, geothermal, biomass-fuelled thermal power, while also emphasizing the necessity of thermal power fuelled by fossil fuels alongside carbon capture and storage (CCS) or carbon capture utilization and storage (CCUS) [1]. Integrating these dependable, lowcarbon power sources into the electric power sector is likely to significantly reduce the required VRE capacities and consequent investments in the sector [2]. According to the net zero emissions (NZE) scenario of International Energy Agency, approximately 60% lower global nuclear power output and 99% lower thermal power plant capacity equipped with CCUS than in the NZE scenario requires additional 2400 GW VRE, 480 GW battery, and > 300 GW other dispatchable capacity, resulting in additional USD 2 trillion investment in the power sector [3]. ...
... (i) Necessity of energy storage capacity: As discussed in [1,2], during the period of abundant wind and solar insolation, large VRE capacities significantly produce and curtail the wind or solar power outputs. Furthermore, building sufficient energy storages is not cost-effective (e.g., NaS (Sodium-Sulphur) or Li-ion batteries). ...
... The most direct manifestation of the low-carbon transition in the power sector is the shift from the dominance of coal-fired power plants to a more diverse energy mix, with a focus on renewable energy, such as new energy sources. This entails long-term, macro-scale low-carbon power planning [6][7][8]. Currently, China is working to build a new power system centered around renewable energy, characterized by a renewable energydominant power structure; a highly flexible, digitalized, and intelligent grid; interactive systems involving power generation, grids, load, and storage; and a comprehensive energy service system focused on electricity. Through a unified, efficient, and well-coordinated electricity market, these elements are expected to be closely linked and operate in a stable and orderly manner across all aspects of the power system [9,10]. ...
Innovation in key low-carbon technologies plays a supporting role in achieving a high-quality low-carbon transition in the power sector. This paper aims to integrate research on the power transition pathway under the “dual carbon” goals with key technological innovation layouts. First, it deeply analyzes the development trends of three key low-carbon technologies in the power sector—new energy storage, CCUS, and hydrogen energy—and establishes a quantitative model for their technological support in the low-carbon transition of the power sector. On this basis, the objective function and constraints of traditional power planning models are improved to create an integrated optimization model for the power transition pathway and key low-carbon technologies. Finally, a simulation analysis is conducted using China’s power industry “dual carbon” pathway as a case study. The optimization results include the power generation capacity structure, power generation mix, carbon reduction pathway, and key low-carbon technology development path for China from 2020 to 2060. Additionally, the impact of uncertainties in breakthroughs in new energy storage, CCUS, and hydrogen technologies on the power “dual carbon” pathway is analyzed, providing technological and decision-making support for the low-carbon transition of the power sector.
... In contrast, variable renewables such as wind and solar are subject to daily, seasonal, and interannual variations. Variable renewables and storage could theoretically provide 100 percent of electricity-but at steeply increasing costs as their share surpasses the 80-90 percent range (Abrahams 2023;Cole et al 2021). 1 If variable renewables are complemented by clean firm generation such as geothermal, nuclear, and hydropower, electricity costs in a decarbonized grid could be reduced 10-62 percent (Sepulveda et al. 2018). ...
This paper provides an overview of next-generation geothermal systems, including enhanced geothermal systems, closed-loop and superhot systems. It covers current developments within the industry, environmental impacts and policy options. While geothermal energy can be used as a source of both heat and electricity, this paper focuses only on uses in the electricity sector.
... Since transmission infrastructure will have changed by 2055, we make use of TEP model to come up with individual, intermediate, and cooperative transmission line capacities at every 5-year time step. A case with no TEP in the future (i.e., keeping transmission capacities constant through 2055) is not considered because it would not be realistic as significant transmission investments are expected for the future due to decarbonization efforts [63][64][65][66]. In this study, future individual, intermediate, and cooperative TEP approaches persist throughout the experiment (up until 2055) and do not affect each other. ...
There is growing recognition of the advantages of interregional transmission capacity to decarbonize electricity grids. A less explored benefit is potential performance improvements during extreme weather events. This study examines the impacts of cooperative transmission expansion planning using an advanced modeling chain to simulate power grid operations of the United States Western Interconnection in 2019 and 2059 under different levels of collaboration between transmission planning regions. Two historical heat waves in 2019 with varying geographical coverage are replayed under future climate change in 2059 to assess the transmission cooperation benefits during grid stress. The results show that cooperative transmission planning yields the best outcomes in terms of reducing wholesale electricity prices and minimizing energy outages both for the whole interconnection and individual transmission planning regions. Compared to individual planning, cooperative planning reduces wholesale electricity prices by 64.3 % and interconnection-wide total costs (transmission investments + grid operations) by 34.6 % in 2059. It also helps decrease greenhouse gas emissions by increasing renewable energy utilization. However, the benefits of cooperation diminish during the widespread heat wave when all regions face extreme electricity demand due to higher space cooling needs. Despite this, cooperative transmission planning remains advantageous, particularly for California Independent System Operator with significant diurnal solar generation capacity. This study suggests that cooperation in transmission planning is crucial for reducing costs and increasing reliability both during normal periods and extreme weather events. It highlights the importance of optimizing the strategic investments to mitigate challenges posed by wider-scale extreme weather events of the future.
... For the following reason, whatever scenario is realized, combustion will still play a highlighted role, even with zero allowed CO 2 emissions. An energy portfolio based on solar and other renewable energy sources with only batteries for load balancing would lead to tripled energy prices compared to the case when combustion systems provide balancing while the produced CO 2 is entirely captured [6]. According to The Intergovernmental Panel on Climate Change [7], CO 2 , N 2 O, NO x , SO 2 , and soot are identified as harmful emissions of combustion, which directly contribute to climate change (especially CO 2 and N 2 O), while the rest pose an adverse effect for both the environment and human health. ...
... Accurately modeling PTES systems is essential for determining their value within grid systems [6,23]. Capacity expansion models (CEMs) optimize the design of electricity grids given cost and performance details of generation, storage, and transmission technologies; emission limits and other policies; and electricity demand time series [39]. CEMs have been used to study the value of PTES [14] and LDES [40]. ...
The increasing need for energy storage solutions to balance variable renewable energy sources has highlighted the potential of Pumped Thermal Electricity Storage (PTES). In this paper, we investigate the trade-offs between model accuracy and computational efficiency in PTES systems. We evaluate a range of PTES models, from physically detailed to simplified variants, focusing on their non-linear charging and discharging capabilities. Our results show that while detailed models provide the most accurate representation of PTES operation by considering mass flow rate () and state of charge (SoC) dependencies, they come at the cost of increased computational complexity. In contrast, simplified models tend to produce overly optimistic predictions by disregarding capability constraints. Other approximated model variants offer a practical compromise, balancing computational efficiency with acceptable accuracy. In particular, models that disregard -dependency and approximate nonlinear SoC-dependency with a piecewise linear function achieve similar accuracy to more detailed models but with significantly faster computation times. Our findings offer guidance to modelers in selecting the appropriate PTES representation for their investment models.
... GenX has been used in a number of studies to evaluate emerging low-carbon technologies, power system decarbonization strategies, and policy interventions (e.g. [16][17][18][19]). ...
Direct air capture (DAC) of carbon dioxide (CO2) is energy intensive given the low concentration (<0.1%) of
CO2 in ambient air, but offers relatively strong verification of removals and limited land constraints to scale.
Lower temperature solid sorbent based DAC could be coupled on-site with low carbon thermal generators such
as nuclear power plants. Here, we undertake a unique interdisciplinary study combining process engineering
with a detailed macro-energy system optimization model to evaluate the system-level impacts of such plant
designs in the Texas electricity system. We contrast this with using grid power to operate a heat pump to
regenerate the sorbent. Our analysis identifies net carbon removal costs accounting for power system impacts
and resulting indirect CO2 emissions from DAC energy consumption. We find that inefficient configurations of
DAC at a nuclear power plant can lead to increases in power sector emissions relative to a case without DAC,
at a scale that would cancel out almost 50% of the carbon removal from DAC. Net removal costs for the most
efficient configurations increase by roughly 18% once indirect power system-level impacts are considered,
though this is comparable to the indirect systems-level emissions from operating grid-powered heat pumps
for sorbent regeneration. Our study therefore highlights the need for DAC energy procurement to be guided
by consideration of indirect emission impacts on the electricity system. Finally, DAC could potentially create
demand pull for zero carbon firm generation, accelerating decarbonization relative to a world without such
DAC deployment. We find that DAC operators would have to be willing to pay existing or new nuclear power
plants roughly 150–400/tCO2 respectively, for input energy, to enable nuclear plants to be
economically competitive in least cost electricity markets that do not have carbon constraints or subsidies for
nuclear energy.
... This is driven by the fact that the wind and solar ITC policy fails to incentivize investments in the CCS technology (as shown in Figure 3-a). At levels of deep decarbonization, adding small shares of gas with CCS, which is assumed to be fully flexible, is more cost-e↵ective than additional renewable capacity in our case study power system, in line with previous literature (Sepulveda et al., 2018). In contrast to the renewable ITCs, the carbon tax provides a technology-neutral investment signal, which incentivizes CCS deployment (Figure 3-c). ...
... All these studies above have not considered the role of coal plant retrofits in decarbonizing India's power system, even though the retrofitted coal plants as the low-carbon, firm generation resources could significantly contain carbon abatement costs, such as in the U.S. [17] and China [18]. Coal plants can be retrofitted in several ways to be compatible with a renewable dominant power system, such as by adding carbon capture and storage (CCS) or via fuel-switching strategies involving the use of biofuels or carbon-free fuels such as ammonia and hydrogen. ...
India set two Nationally Determined Contribution targets to achieve the net zero carbon emission goal by 2070, which requires deep decarbonization of India's power generation sector. Yet, coal power generation contributes to more than 60\% of its total power generation, and policies still permit further coal fleet expansion and lifetime extensions. In this paper, we investigate the role of retrofitting India's coal plants for carbon capture and storage and biomass co-firing in developing the net-zero power system. We model the power generation and transmission network expansions across 30 Indian states in four representative grid evolution scenarios under progressively tighter carbon emission caps, taking into account sub-national coal price variation and thermal efficiency of individual coal plants. We find that coal plant retrofitting could happen by 2035 when an annual carbon cap for the power generation sector is less than 1,000 million tons CO. This reduces the unabated coal plant capacity, electricity generation, and carbon abatement costs. Exploiting renewable energy potentials solely, such as wind resources, could reduce carbon abatement costs significantly but will result in low coal plant utilization and uneven renewable generation deployment between Southern and Central regions concerning energy justice.
... Capacity expansion models that do not include these capabilities (e.g. [5,22,26,49]) can potentially overestimate interconnection reinforcements on the order of 10% or more with battery capacity at 2.5-10% of regional peak demand. The declines in interconnection capacity correspond with an increase in the ratio of VRE capacity to interconnection capacity (1.5-1.6 MW PV: 1 MW inverter, 1.2-1.3 ...
Expanding transmission capacity is likely a bottleneck that will restrict variable renewable energy (VRE) deployment required to achieve ambitious emission reduction goals. Interconnection and inter-zonal transmission buildout may be displaced by the optimal sizing of VRE to grid connection capacity and by the co-location of VRE and battery resources behind interconnection. However, neither of these capabilities is commonly captured in macro-energy system models. We develop two new functionalities to explore the substitutability of storage for transmission and the optimal capacity and siting decisions of renewable energy and battery resources through 2030 in the Western Interconnection of the United States. Our findings indicate that modeling optimized interconnection and storage co-location better captures the full value of energy storage and its ability to substitute for transmission. Optimizing interconnection capacity and co-location can reduce total grid connection and shorter-distance transmission capacity expansion on the order of 10% at storage penetration equivalent to 2.5-10% of peak system demand. The decline in interconnection capacity corresponds with greater ratios of VRE to grid connection capacity (an average of 1.5-1.6 megawatt (MW) PV:1 MW inverter capacity, 1.2-1.3 MW wind:1 MW interconnection). Co-locating storage with VREs also results in a 10-15% increase in wind capacity, as wind sites tend to require longer and more costly interconnection. Finally, co-located storage exhibits higher value than standalone storage in our model setup (22-25%). Given the coarse representation of transmission networks in our modeling, this outcome likely overstates the real-world importance of storage co-location with VREs. However, it highlights how siting storage in grid-constrained locations can maximize the value of storage and reduce transmission expansion.
... Most studies conducted in the contiguous United States have focused on PV penetration levels below 50% [12]. Therefore, further research and analysis are necessary to fully comprehend the effects of PV on the national grid and ensure its long-term sustainability [13]. To address this issue, it is necessary to expand the spatial extension and modeling resolution of studies examining very high PV scenarios. ...
There is a clear growth trend that can be seen in the solar PV industry, and solar systems will become an integral part of our society and thus our environments. In this context, understanding the effects of the expanded entrance of the control system on solar PV generation is important technically to overview the challenges. This article provides a comprehensive analysis of the necessary improvements in various aspects of PV modules to facilitate their successful integration into the grid systems of leading countries worldwide. By considering key important factors such as installation capacity, power generation, and electric power demands, these improvements will enable PV modules to achieve high penetration scenarios and contribute significantly to the global shift towards renewable energy. The initial section of the solar power-energizing transformation is the part that conveys the controlled energy load to a grid system for onward transmission to consumers. The study emphasizes the potential of integrating solar PV systems, distributed generation technologies, and local flexibility measures for a sustainable energy mix, reducing greenhouse gas emissions. The present review provides an overview of the present status of solar power generation and a high-penetration scenario for the future growth of solar energy. However, the study ends up with a future recommendation for developing better penetration in PV technology and generation.
... Indeed, while existing sources of zero-carbon electricity can reduce carbon emissions efficiently, reaching net-zero emissions with existing technology is predicted to be exorbitantly expensive (refer e.g. [4], where full decarbonization could yield costs exceeding $220/MWh). Therefore, there is a strong case for seeking additional new, broadly deployable 'firm' (available on demand) energy sources. ...
This theme issue collects together papers summarising the conceptual design of the Spherical Tokamak for Energy Production (STEP). In 2019, the UK government funded the first design stages of a prototype fusion powerplant based on a compact toroidal geometry, called STEP. The primary technical aims of STEP are to produce net energy, to be self-sufficient in tritium fuel and to demonstrate a maintenance regime that would extrapolate to appropriate availability for commercial powerplants. After 5 years and over 1000 person-years of detailed scientific and engineering conceptual design, this theme issue acts as a compendium of the current design basis for STEP, noting that this is a snapshot in time and that the design will continue to evolve.
This article is part of the theme issue ‘Delivering Fusion Energy – The Spherical Tokamak for Energy Production (STEP)’.
... This scenario illustrates a limiting low-carbon emission scenario with low capital cost, flexible, firm generation that can buffer the system from the most severe instances of weather variability. Flexible, dispatchable generation has been shown to substantially reduce electricity costs in systems heavily dependent on variable renewable generation [31]. Additionally, considering the useful lifetime of gas plants being built today, it is possible many regional to continental power systems will transition through a low-emission state with substantial solar and wind generation and constrained rates of natural gas dispatch [32]. ...
Resource adequacy, or ensuring that electricity supply reliably meets demand, is more challenging for wind-and solar-based electricity systems than fossil-fuel-based ones. Here, we investigate how the number of years of past weather data used in designing least-cost systems relying on wind, solar, and energy storage affects resource adequacy. We find that nearly 40 years of weather data are required to plan highly reliable systems (e.g., zero lost load over a decade). In comparison, this same adequacy could be attained with 15 years of weather data when additionally allowing traditional dispatchable generation to supply 5 % of electricity demand. We further observe that the marginal cost of improving resource adequacy increased as more years, and thus more weather variability, were considered for planning. Our results suggest that ensuring the reliability of wind-and solar-based systems will require using considerably more weather data in system planning than is the current practice. However, when considering the potential costs associated with unmet electricity demand, fewer planning years may suffice to balance costs against operational reliability.
... Detailed analyses have shown that while the intermittency of solar and wind is not a major issue now, it will make shifting the last 20% or 10% of generation to renewable sources unacceptably expensive [5] Thus we can expect a role for constant technologies even if more costly. ...
As humanity accelerates its shift to renewable energy generation, people who are not experts in renewable energy are learning about energy technologies and the energy market, which are complex. The answers to some questions will be obvious to expert practitioners but not to non-experts. One such question is Why solar and wind generation are expected to supply the bulk of future energy when they are intermittent. We learn here that once the baseline hurdles of scalability to utility scale and the underlying resources being widely available globally are satisfied, the forecasted cost of solar and wind is 2-4X lower than competing technologies, even those that are not as scalable and available. The market views intermittency as surmountable.
... Dispatchable (i.e., "firm") low-carbon power can provide substantial value to decarbonizing the electricity system (Sepulveda et al., 2018;Bistline and Blanford, 2020;Cole et al., 2021), which is an essential step towards economy-wide decarbonization (Bistline and Blanford, 2021;EPRI and GTI Energy, 2022). Geothermal power plants are one of the many technologies that could provide this service (Wongel and Caldeira, 2023): they can provide "firm" dispatchable power because they are comprised of similar components as coal or natural-gas power plants (e.g., turbines, compressors), but emit substantially less CO 2 because they are driven by thermal energy from the subsurface. ...
Introduction: Sedimentary basins are naturally porous and permeable subsurface formations that underlie approximately half of the United States. In addition to being targets for geologic CO2 storage, these resources could supply geothermal power: sedimentary basin geothermal heat can be extracted with water or CO2 and used to generate electricity. The geothermal power potential of these basins and the accompanying implication for geologic CO2 storage are, however, understudied.
Methods: Here, we use the Sequestration of CO2 Tool (SCO2TPRO) and the generalizable GEOthermal techno-economic simulator (genGEO) to address this gap by a) estimating the cost and capacity of sedimentary basin geothermal power plants across the United States and b) comparing those results to nationwide CO2 sequestration cost and storage potential estimates.
Results and discussion: We find that across the United States, using CO2 as a geothermal heat extraction fluid reduces the cost of sedimentary basin power compared to using water, and some of the lowest cost capacity occurs in locations not typically considered for their geothermal resources (e.g., Louisiana, South Dakota). Additionally, using CO2 effectively doubles the sedimentary basin geothermal resource base, equating to hundreds of gigawatts of new capacity, by enabling electricity generation in geologies that are otherwise (with water) too impermeable, too thin, too cold, or not deep enough. We find there is competition for the best sedimentary basin resources between water- and CO2-based power, but no overlap between the lowest-cost resources for CO2 storage and CO2-based power. In this way, our results suggest that deploying CO2-based power may increase the cost of water based systems (by using the best resources) and the cost of CO2 storage (by storing CO2 in locations that otherwise may not be targeted). As such, our findings demonstrate that determining the best role for sedimentary basins within the energy transition may require balancing tradeoffs between competing priorities.
... This economic outlook for existing U.S. NPPs also makes investments in new NPPs, based on next-gen small modular reactor (SMR) concepts, challenging. However, despite their higher capital costs per kW relative to VRE generation sources, these NPP designs represent a type of low-carbon, dispatchable generation resource which has been shown to be critical to minimizing the cost of achieving deeply decarbonized power systems [2]. NPPs are not fully compensated for this benefit in current markets, so there is a need for alternative business models and revenue streams to support deployment of new NPPs to support economy-wide decarbonization goals. ...
Increasing wind and solar electricity generation in power systems increases temporal variability in electricity prices which incentivizes the development of flexible processes for electricity generation and electricity-based fuels/chemicals production. Here, we develop a computational framework for the integrated design and optimization of multi-product processes interacting with the grid under time-varying electricity prices. Our analysis focuses on the case study of nuclear-based hydrogen (H2) and electricity generation, involving nuclear power plants (NPP) producing high temperature heat and electricity coupled with a high temperature steam electrolyzers (HTSE) for H2 production. The ability to co-produce H2 along with nuclear is widely seen as critical to improving the economics of nuclear energy technologies. To that end, our model focuses on evaluating the least-cost design and operations of the NPP-HTSE system while accounting for: a) power consumption variation with current density for the HTSE and the associated capital and operating cost trade-off, b) heat integration between NPP and HTSE and c) temporal variability in electricity prices and their impact on plant operations to meet a baseload hydrogen demand. Instead of formulating a monolithic optimization model, which would be computationally expensive, we propose a decomposition approach that reformulates the original problem into three sub-problems solved in an iterative manner to find near-optimal solutions. Through a numerical case study, we demonstrate the potential synergies of NPP and HTSE integration under alternative electricity price scenarios. This synergy is measured via the metric of relative breakeven H2 selling price that accounts for the opportunity cost of reduced electricity sales from H2 co-production.
... These could facilitate ecological utilization of an anaerobically digested fertilizer to nearby farms 44 . This could also mean that once all processes can be regionally integrated well, such as biogas consumption, breeding intensity and form, and planting structures, the benefits of circular agriculture realization may be achieved with the intrinsic synergistic interaction 45 . Thus, rural communities in developing areas are encouraged to achieve energy equality and regional carbon mitigation by deploying upgraded CBPDs, because of the high feasibility of biogas demand and supply matching and efficient nutrient circularity of manure 46 . ...
On-site conversion of organic waste into biogas to satisfy consumer energy demand has the potential to realize energy equality and mitigate climate change reliably. However, existing methods ignore either real-time full supply or methane escape when supply and demand are mismatched. Here, we show an improved design of community biogas production and distribution system to overcome these and achieve full co-benefits in developing economies. We take five existing systems as empirical examples. Mechanisms of synergistic adjusting out-of-step biogas flow rates on both the plant-side and user-side are defined to obtain consumption-to-production ratios of close to 1, such that biogas demand of rural inhabitants can be met. Furthermore, carbon mitigation and its viability under universal prevailing climates are illustrated. Coupled with manure management optimization, Chinese national deployment of the proposed system would contribute a 3.77% reduction towards meeting its global 1.5 °C target. Additionally, fulfilling others’ energy demands has considerable decarbonization potential.
... Thus, as LDES, hydrogen can smooth long periods of energy imbalance on a VRE-based grid [3]. Second, hydrogen from electrolysis using zero-carbon electricity can be used as an international carrier of decarbonized energy [4,5], enabling widespread decarbonized power generation in countries where zero-carbon energy sources are limited [6,7]. These applications, while complementary, are also competitors in that their deployment hinges on their relative economics and the development of electricity markets to encourage their use. ...
With countries and economies around the globe increasingly relying on non-dispatchable variable renewable energy (VRE), the need for effective energy storage and international carriers of low-carbon energy has intensified. This study delves into hydrogen’s prospective, multifaceted contribution to decarbonizing the electricity sector, with emphasis on its utilization as a scalable technology for long-duration energy storage and as an international energy carrier. Using Japan as a case study, based on its ambitious national hydrogen strategy and plans to import liquefied hydrogen as a low-carbon fuel source, we employ advanced models encompassing capacity expansion and hourly dispatch. We explore diverse policy scenarios to unravel the timing, quantity, and operational intricacies of hydrogen deployment within a power system. Our findings highlight the essential role of hydrogen in providing a reliable power supply by balancing mismatches in VRE generation and load over several weeks and months and reducing the costs of achieving a zero-emission power system. The study recommends prioritizing domestically produced hydrogen, leveraging renewables for cost reduction, and strategically employing imported hydrogen as a risk hedge against potential spikes in battery storage and renewable energy costs. Furthermore, the strategic incorporation of hydrogen mitigates system costs and enhances energy self-sufficiency, informing policy design and investment strategies aligned with the dynamic global energy landscape.
... The nonlinear increase in system costs indicated in Frew et al. (2016) is consistent with the findings of similar modeling studies that deliberately explore different shares of variable renewables, and the impacts on integration costs and total system costs. See for example Shaner et al. (2017), Platt et al. (2017), and Sepulveda et al. (2018). The nonlinearity in costs can be dampened, as noted above, by transmission expansion, successful large-scale load shifting, and by substantial decreases in storage. ...
The evidence that climate change is underway grows
stronger every year, along with the evidence that it is
largely attributable to human activities. To avoid the
worst effects of climate change, the United States
and the world as a whole must dramatically reduce
greenhouse gas emissions over the next 30 years. In
the latter half of this century, nations collectively must
aim for net negative emissions and begin removing
carbon dioxide from the air. In the energy sector, CO2
emissions must be virtually eliminated by mid-century.
This will require the “deep decarbonization” of the
world’s economies, and the transition to a “clean energy
economy.” An energy transition of this scope will be
challenging in many ways, but it is technologically
and economically feasible, as are reductions in other
greenhouses, including: methane, nitrous oxide and
fluorinated gases (IPCC, 2018).
... For batteries, we assume capacity will not exceed 25% of peak demand. Both the storage and renewable bounds are informed by prior work modeling capacity mixes in low-carbon power systems across a large range of scenarios (Sepulveda et al., 2018). In sensitivity testing, relaxing these bounds increased solution times but did not change our results. ...
Liberalized power markets are characterized by a missing market problem: a limited availability of long-term contracts leaves risk-averse investors exposed to uninsured risk. We explore how this problem affects a power system's capacity mix and overall emissions. For this purpose, we develop a new equilibrium generation expansion model that endogenously captures investors’ risk exposure in incomplete markets. Our approach addresses the problem of multiple equilibria and, partly, the computational burden inherent to such models. We solve our model for an abstract system with gas, wind, solar, and battery storage under demand and gas price uncertainty. The results first show that, when risk markets are missing, investment risk can cause higher emissions and less clean energy investment than what would be implied by a model that omits investment risk. The impact of risk on investment depends only partly on technologies’ capital intensities and largely on how technologies interact at the systems level. We also compare system outcomes with missing long-term markets to the socially optimal case, where risk-averse investors and consumers trade risk via complete long-term markets. In the absence of long-term markets, we observe higher emissions, less investment in renewables and storage, and more investment in gas. These results suggest that long-term market mechanisms for electricity generation and storage may advance climate goals while addressing inefficiencies in current markets.
... Based on their circumstances and concerns, different countries make and implement various legal policies and actions (Chang and Carballo 2011). Among these programs, we can refer to reducing carbon in this industry, increasing electricity generation by renewable and clean energies (CCC 2010;Eurelectric 2018;Hanisch et al. 2018), raising the efficiency of thermal power plants (Ozer et al. 2013), enhancing energy efficiency (Nebernegg et al. 2019;Sepulveda et al. 2018), using systems and technologies that reduce carbon and pollutants (Kusumadewi et al. 2017a, b;UNEP 2016), setting taxes (Ambec and Crampes 2019), etc. ...
The present study evaluated carbon reduction policies (decarbonization) by comparing energy efficiency improvement in thermal power plants and the incremental development of renewable and clean power plants in different scenarios in the power generation sector. For this purpose, the optimal portfolio for power generation expansion was considered until 2050. Likewise, regarding environmental considerations, the values of environmental emissions and their external costs in different power generation methods were modeled for the first time in an inclusive electricity system. Then, the Matrix Laboratory and Long-Range Energy Alternative Planning software were used to model electricity supply and demand toward long-time planning and estimate and solve technical, economic, and environmental functions. The modeling outcomes showed that, under the Steam Power Plant repowering scenario, the efficiency-improving actions in thermal power plants were prioritized over the development of clean and renewable power plants, including large hydroelectric and nuclear power plants, and could reduce the total power generation cost by 38% until 2050 and environmental and greenhouse gases emissions by 3,572 MMT and 2,624 MMTDCO2E compared to the BAU scenario. It was also found that although developing renewable energies could decrease the external environmental costs by 73,188 million U.S dollars in the 2017–2050 period relative to the other scenarios, its development would not be optimal technically and economically since it was a function of technical, economic, environmental, and political factors and was not the sole approach to reducing carbon emissions in all countries.
... Both these strategies will increase the spatial and temporal variability in electricity supply and demand that complicates system operations and requires enabling technologies to ensure cost-effective, low-carbon and reliable electricity supply. Recent studies evaluating deep decarbonization of power systems [3][4][5][6] highlight the importance of relying on a broad suite of supply and demand-side technologies to provide flexibile system balancing and complement the low-marginal cost and intermit-tent nature of variable renewable energy (VRE) generation. On the supply side, this could include deployment of short and longduration energy storage technologies, network expansion as well as deployment of firm low-carbon generation resources, such as carbon capture and storage (CCS) equipped fossil fuel power plants. ...
Deployment of carbon capture and storage (CCS) equipped fossil fuel power plants on the supply-side and direct air capture (DAC) technologies on the demand side can address the dual challenge...
Bioenergy with carbon capture and storage for power generation (BECCS-power) is a negative emissions technology that could potentially play significant roles in helping achieve climate-change mitigation goals. We evaluate a novel BECCS-power technology utilizing molten carbonate fuel cell-based post-combustion carbon dioxide (CO2) capture (MCFC-CC). We present detailed, internally self-consistent plant-level performance simulation results, techno-economic analyses, and lifecycle greenhouse gas emissions assessment for this technology, with comparisons against conventional monoethanolamine-based post-combustion CO2 capture (MEA-CC) and biopower without CO2 capture. We additionally carry out grid capacity expansion modeling to 2050 to assess how BECCS-power options might compete with other generators in a case study region (southern region of the Midcontinent Independent System Operator, MISO). This comprehensive work is not only the first rigorous engineering assessments of MCFC for BECCS but also the first techno-economic analyses of MCFC-CC of any type that includes its evaluation in the context of power grid operation. For a biomass input rate of 500 MWthHHV, a MCFC-CC plant generates triple the power and has nearly double the efficiency of a MEA-CC plant (261.5 MWe at 33.5% efficiency vs. 87.2 MWe at 17.4% efficiency). The plants generate comparable levels of negative emissions per tonne of biomass input: 1.3 and 1.5 tCO2, respectively. For a fully-depreciated coal-fired steam-cycle plant repowered for biomass and CO2 capture, the (Nth plant) levelized cost of electricity (LCOE) for MCFC-CC (2,479/kWnet vs. 85/MWh). From the capacity expansion modeling, if the southern MISO grid would have a target grid-average carbon emission intensity of 50 kgCO2/MWh or less in 2050, several gigawatts of Bio-MCFC-CC would be economically deployed, and the marginal cost of emissions abatement ($92/tCO2) would be dramatically lower than if it were not a deployment option.
Green hydrogen has the potential to address two pressing problems in a zero-carbon energy system: balancing seasonal variability of solar and wind in the electricity sector, and replacing fossil fuels in hard-to-abate sectors. However, the previous research only separately modeled the electricity and hard-to-abate sectors, which is unable to capture how the interaction between the two sectors influences the energy system cost. In this study, focusing on China, we deploy an electricity system planning model to examine the cost implications of green hydrogen to fully decarbonize the electricity system and hard-to-abate sectors. Our results reveal that green hydrogen enables a 17% reduction in the levelized cost of a zero-carbon electricity system relative to that without hydrogen. However, cost savings hinge on the availability of underground hydrogen storage capacities and electric transmission expansion. More importantly, coupling hydrogen infrastructure in the electricity and hard-to-abate sectors not only reduces energy costs compared to a decoupled energy system but also makes green hydrogen cost-competitive compared to fossil fuel-based gray and blue hydrogen in China.
Postcombustion capture (PCC) by means of mono-ethanolamine and hydrogen co-firing, combined with exhaust gas recirculation (EGR), were applied to a typical 2 × 1 combined cycle (CC) with the goal of reaching net-zero CO2 emissions. The novelty lies in integrating decarbonization solutions into the daily operation of the CC, when power generation is adjusted according to fluctuations in electricity demand, throughout two representative days in summer and winter. More specifically, off-design thermodynamic modeling was adapted to incorporate a multivariable optimization problem to find the maximum power plant efficiency as a function of the following decision variables: (1) load of each gas turbine (GT), spanning from minimum turndown to full load; (2) EGR rate, in a range that depends on the fuel type: [0; 0.4] for 100% natural gas (NG) versus [0; 0.55] when hydrogen is fed to the combustor; with the constraint of net power output equal to electricity demand, for given environmental conditions. Suggestions were made to mitigate the energy penalty due to decarbonization in the load-following operation mode, taking the integration of mono-ethanolamine CO2 capture into the NG-fired CC as a benchmark. The solution in which EGR combines optimally with hydrogen in the fuel mixture, with the addition of PCC to abate residual CO2 emissions, has proven to be the most efficient way to provide dispatchable clean energy, especially in cold climates.
As the world races to decarbonize power systems to mitigate climate change, the body of research analyzing paths to zero emissions electricity grids has substantially grown. Although studies typically include commercially available technologies, few of them consider offshore wind and wave energy as contenders in future zero-emissions grids. Here, we model with high geographic resolution both offshore wind and wave energy as independent technologies with the possibility of collocation in a power system capacity expansion model of the Western Interconnection with zero emissions by 2050. In this work, we identify cost targets for offshore wind and wave energy to become cost effective, calculate a 17% reduction in total installed capacity by 2050 when offshore wind and wave energy are fully deployed, and show how curtailment, generation, and transmission change as offshore wind and wave energy deployment increase.
Wind power has considerable potential to decarbonise electricity systems due to its low cost and wide availability. However, its variability is one factor limiting uptake. We propose a simple analytical framework to optimise the distribution of wind capacity across regions to achieve a maximally firm or load-following profile. We develop a novel dataset of simulated hourly wind capacity factors (CFs) with bias correction for 111 Chinese provinces, European countries and US states spanning ten years (∼10 million observations). This flexible framework allows for near-optimal analysis, integration of demand, and consideration of additional decision criteria without additional modelling. We find that spatial integration of wind resources optimising the distribution of capacities provides significant benefits in terms of higher CF or lower residual load and lower variability at sub-, quasi- and inter-continental levels. We employ the concept of firmness as achieving a reliable and certain generation profile and show that, in the best case, the intercontinental interconnection between China, Europe and the US could restrict wind CFs to within the range of 15%–40% for 99% of the time. Smaller configurations corresponding to existing electricity markets also provide more certain and reliable generation profiles than isolated individual regions.
Analyzing low-renewable-output events, termed “energy droughts” is crucial for renewable energy systems. However, due to the challenges in hydropower regulation and complex spatiotemporal correlations among resources, the assessment and contributions of various resources to energy droughts in hydro-wind-photovoltaic (PV) energy systems (HWPSs) remain unexplored. To address these issues, this study evaluated energy droughts and compound resource droughts rather than single-resource in HWPSs, exploring the propagation. Assessments of frequency, duration, and severity relied on weather-to-resource conversion models and total power obtained through complementary operation. Estimating propagation probability from resource to energy droughts was achieved via the C-vine copula, quantifying resource contributions to drought propagation. Results of a case study in the Yalong River Basin indicated that (1) short-lived compound resource droughts have been increasingly frequent recently, peaking during winter or summer. After incorporating hydro energy resources, the severity and annual average occurrence of compound droughts decreased (from 18.56 to 5.24 events/year). (2) Complementary operation effectively reduced the probability of drought propagation. (3) Hydro and PV energy resources were pivotal contributors to drought propagation, contributing 49.1% and 40.1% when representing 53.4% and 22.5% of the total system capacity, respectively. Therefore, the study offers valuable insights into energy drought warnings and risk mitigation.
I find it fascinating how we construct our conversations and the manner in which we incorporate logos within them. And to be honest, I have been noticing this since I was a teenager. The moment I was able to learn and apply a more rigorous framework, rather than relying solely on intuition, was truly enlightening. Perelman and Olbrechts-Tyteca [1] write: dialogue, as we consider it, is not supposed to be a debate in which the partisans of opposed settled convictions defend their respective views, but rather a discussion in which the interlocutors search honestly and without bias for the best solution to a controversial problem. Certain contemporary writers who stress this heuristic viewpoint, as against the eristic one, hold that discussion is the instrument for reaching objectively valid conclusions .
Energy systems are undergoing a transformation toward a “long tail.” Market liberalization and affordable technologies are enabling massive deployment of distributed energy resources, the development of new services, the entry of new types of players, and the emergence of new business models. Much of this innovation is taking place at the edge of the grid, closer to consumers. The emerging highly fragmented and dynamic markets are composed of numerous scattered assets and multiple players with different motivations, capabilities, and interests—and varying levels of expertise, resources, and financial viability. Although this new landscape offers many benefits for the environment, energy security, and consumers, it also poses new regulatory challenges, raises safety concerns, and may bring unintended consequences.
This perspective describes the characteristics of the evolving long-tail electricity system, including new technologies, services, players, and business models. It highlights this transformation’s potential positive and negative impacts on the environment, society, and energy security, considering regulatory and governance gaps.
This dissertation focuses on energy system optimization models (ESOMs). These are mathematical models which are used to generate possible transition pathways of the entire energy system in a single or multiple countries over a time horizon of multiple decades. Experimenting with different transition pathways allows gaining insights and can help in forming a long-term vision of a cost-effective transition towards a sustainable energy system. As such, these models form valuable tools for policy makers.
Due to the large scope of ESOMs, solving these models quickly becomes computationally demanding. To limit the computational cost, ESOMs have historically used a low level of temporal and technical detail to represent the operation of the power system, i.e., intra-annual variations in demand and renewable generation are typically represented by 4-48 so-called time slices and the technical constraints faced by thermal power plants when changing their power output, starting up or shutting down are neglected. However, in the context of an increasing penetration of intermittent renewable energy sources (IRES), such as wind turbines and solar PV panels, of which the instantaneous electricity generation is weather dependent and therefore highly variable and limitedly predictable, this low level of temporal and technical detail might not be sufficient to grasp the economic and technical challenges related to integrating these IRES into the system.
In this regard, the main objective of this dissertation is to assess the impact of this low level of temporal and technical detail on the results provided by ESOMs and to improve the modeling of the temporal and technical aspects related to the operation of the power system. The presented research shows that, due to the low level of temporal and technical detail, the transition pathways deemed optimal by ESOMs tend to have a bias towards baseload technologies (e.g., coal-fired power plants and nuclear power plants) as well as IRES (e.g., wind turbines and PV panels), while the value of more flexible technologies (e.g., gas-fired power plants and storage technologies) tends to be underestimated. Additionally, the low level of detail is shown to lead to an underestimation of the efforts required to achieve certain targets (e.g., a greenhouse gas emission reduction target). For high penetrations of IRES, particularly the low level of temporal detail is shown to have a strong impact on the obtained results. To overcome these issues, a novel method, based on selecting a number of representative historical days, to represent intra-annual variations in demand and renewable generation within a year is developed. This method is shown to strongly increase the accuracy of ESOMs without increasing the computational cost. Additionally, reduced formulations of the mathematical constraints which are used to model the technical constraints faced by thermal power plants when changing their power output are proposed. These reduced formulations are shown to be sufficiently accurate for long-term planning purposes while reducing computation time by a factor of 5-600 with respect to the model which integrates the detailed technical constraints.
Electricity generating power plants do not exist in isolation. They interact with each other and
their customers through the electricity grid as well as with the wider economic, social and natural
environment. This means that electricity production generates costs beyond the perimeter of the
individual plant. Such external costs or system costs can take the form of intermittency, network
congestion or greater instability but can also affect the quality of the natural environment or pose risks
in terms of the security of supply. System costs in this study are defined as the total costs above plantlevel
costs to supply electricity at a given load and given level of security of supply.
Accounting for such system costs can make significant differences to the social and private investor
costs of different power generation technologies. Not accounting for them implies hidden costs that can,
if not adequately anticipated, pose threats to the security of electricity supply in the future. The present
study continues the work of the OECD Nuclear Energy Agency (NEA) on the full costs of electricity
generation in the wake of recent reports on Projected Costs of Generating Electricity (2010), The Security
of Energy Supply and the Contribution of Nuclear Energy (2010) and Carbon Pricing, Power Markets and the
Competitiveness of Nuclear Power (2011).
While the study analyses the system costs of all power generation technologies, it concentrates on
the system effects of nuclear power and variable renewables, such as wind and solar PV, as their
interaction is becoming increasingly important in the decarbonising electricity systems of OECD
countries. In particular, the integration of significant amounts of variable renewables is a complex issue
that profoundly affects the structure, financing and operational mode of electricity systems in general and
nuclear in particular. System costs also vary strongly between different countries due to differences in the
generation mix, the share of variable renewables and the shape of the daily and seasonal load curves.
The study focuses on grid-level system costs that are composed of the costs for network connection,
extension and reinforcement, short-term balancing and long-term adequacy in order to ensure
continuous matching of supply and demand under all circumstances. Such grid-level costs are real
monetary costs that are already being borne today by network operators, dispatchable power producers
using nuclear, coal or gas, as well as electricity customers. An important contribution of this study is
the first systematic quantification of such grid-level system costs for six OECD/NEA countries (Finland,
France, Germany, the Republic of Korea, the United Kingdom and the United States). Including system
costs increases the total costs of variable renewables, depending on technology, country and penetration
levels, by up to one-third.
The study also looks at total system costs in a qualitative manner. This broader set of system cost
would include local and global environmental externalities, impacts on the security of energy supply
and a country’s strategic position as well as other positive or negative spillover effects relating to
technological innovation, economic development, accidents, waste, competitiveness or exports. In
addition, the study also considers the ability of nuclear energy to contribute to the internalisation of the
system costs generated by intermittency in low-carbon electricity systems.
In addition, the study examines the important “pecuniary externalities” or financial impacts that
the introduction of variable renewables has on the profitability of dispatchable technologies both in
the short run and in the long run. In the short run, with the current structure of the power generation
mix remaining in place, all dispatchable technologies, nuclear, coal and gas, will suffer due to lower
average electricity prices and reduced load factors (“compression effect”). Due to its lower variable costs,
however, existing nuclear power plants will do relatively better than gas and coal plants. In particular,
gas plants are already experiencing substantial declines in profitability in several OECD/NEA countries with high shares of variable renewables. In the future, dispatchable technologies, including nuclear, will
require that a portion of their revenues be derived from other sources than “energy-only” electricity
markets if they are to stay in the market and provide the necessary back-up services. Capacity payments
or markets with capacity obligations will play an important part in addressing this issue.
In the long run, nuclear energy will be affected disproportionately by the increased difficulties
to finance large fixed-cost investments in volatile low-price environments. This can have significant
impacts on the carbon intensity of power generation. If, for instance, such baseload is currently produced
by nuclear power, replacing the latter in the future by a mix of variable renewables and gas will mean
that carbon emissions will rise rather than fall.
System costs, both technical costs at the grid level and pecuniary impacts, vary strongly between
countries, depending on the amount of variable renewables being introduced, local conditions and
the level of carbon prices. The latter are particularly important. While nuclear power has some system
costs of its own, it remains the only major dispatchable low-carbon source of electricity other than
hydropower which is in limited supply. Carbon prices will thus be an increasingly important tool to
differentiate between low-carbon and high-carbon dispatchable technologies.
System costs are not only country-dependent, as a policy-relevant issue they are also a complex,
relatively new phenomenon that poses a number of methodological challenges, not all of which have yet
been resolved in a generally accepted manner. The present study provides a contribution to the debate,
which is still ongoing. Further research is necessary and will undoubtedly refine both methodologies
and empirical results. Nevertheless, by building on a systematic review of the available literature and
by contributing some carefully considered methodological advances, the findings herein should help
inform discussions.
The policy implications for governments are clear and unaffected by these methodological considerations.
First, governments need to ensure the transparency of power generation costs at the system
level. When making policy decisions affecting their electricity markets, countries need to consider the
full system costs of different technologies.
Second, governments should prepare the regulatory frameworks to minimise system costs and favour
their internalisation. This includes remunerating the capacity services of dispatchable technologies,
allocating the costs for balancing, adequacy and grid connection in a fair and transparent manner and
monitoring carefully the implications for carbon emissions of different strategic choices for back-up
provision. Failure to do so will rebound in terms of unanticipated cost and environmental emission
increases of the overall power supply for many years to come.
Fundamental characteristics of solar and wind power have generated controversy about their economic competitiveness and appropriate techniques for assessing their value. This research presents an approach to quantify the economic value of variable renewable capacity and demonstrates its dependence on renewable deployment levels, regional resource endowments, fleet flexibility, and trade assumptions. It assesses economic and technical impacts of large-scale renewable penetration by linking two models, representing electric-sector investments and detailed operations. Model results for California and Texas suggest operational constraints and costs of dispatchable generators (e.g., minimum load levels, ramping limits, startup costs) can impact renewable integration costs, but the temporal and spatial variability of solar and wind are larger determinants of their value. Restrictions on transmission and regional coordination in capacity planning and dispatch decrease the economic value of variable renewable energy, highlighting the potential roles of market design and trade. Energy storage is shown to be a valuable balancing asset at higher solar and wind penetration levels, but potential revenues diminish with increased storage deployment.
Many studies have quantified the cost of Carbon Capture and Storage (CCS) power plants, but relatively few discuss or appreciate the unique value this technology provides to the electricity system. CCS is routinely identified as a key factor in least-cost transitions to a low-carbon electricity system in 2050, one with significant value by providing dispatchable and low-carbon electricity. This paper investigates production, demand and stability characteristics of the current and future electricity system. We analyse the Carbon Intensity (CI) of electricity systems composed of unabated thermal (coal and gas), abated (CCS), and wind power plants for different levels of wind availability with a view to quantifying the value to the system of different generation mixes. As a thought experiment we consider the supply side of a UK-sized electricity system and compare the effect of combining wind and CCS capacity with unabated thermal power plants. The resulting capacity mix, system cost and CI are used to highlight the importance of differentiating between intermittent and firm low-carbon power generators. We observe that, in the absence of energy storage or demand side management, the deployment of intermittent renewable capacity cannot significantly displace unabated thermal power, and consequently can achieve only moderate reductions in overall CI. A system deploying sufficient wind capacity to meet peak demand can reduce CI from 0.78 tCO2/MWh, a level according to unabated fossil power generation, to 0.38 tCO2/MWh. The deployment of CCS power plants displaces unabated thermal plants, and whilst it is more costly than unabated thermal plus wind, this system can achieve an overall CI of 0.1 tCO2/MWh. The need to evaluate CCS using a systemic perspective in order to appreciate its unique value is a core conclusion of this study.
High shares of intermittent renewable power generation in a European electricity system will require flexible backup power generation on the dominant diurnal, synoptic, and seasonal weather timescales. The same three timescales are already covered by today's dispatchable electricity generation facilities, which are able to follow the typical load variations on the intra-day, intra-week, and seasonal timescales. This work aims to quantify the changing demand for those three backup flexibility classes in emerging large-scale electricity systems, as they transform from low to high shares of variable renewable power generation. A weather-driven modelling is used, which aggregates eight years of wind and solar power generation data as well as load data over Germany and Europe, and splits the backup system required to cover the residual load into three flexibility classes distinguished by their respective maximum rates of change of power output. This modelling shows that the slowly flexible backup system is dominant at low renewable shares, but its optimized capacity decreases and drops close to zero once the average renewable power generation exceeds 50% of the mean load. The medium flexible backup capacities increase for modest renewable shares, peak at around a 40% renewable share, and then continuously decrease to almost zero once the average renewable power generation becomes larger than 100% of the mean load. The dispatch capacity of the highly flexible backup system becomes dominant for renewable shares beyond 50%, and reach their maximum around a 70% renewable share. For renewable shares above 70% the highly flexible backup capacity in Germany remains at its maximum, whereas it decreases again for Europe. This indicates that for highly renewable large-scale electricity systems the total required backup capacity can only be reduced if countries share their excess generation and backup power.
Recent work on operational flexibility—a power system’s ability to respond to variations in demand and supply—has focused on the impact of large penetration of renewable generation on existing power systems. Operational flexibility is equally important for long-term capacity expansion planning. Future systems with larger shares of renewable generation, and/or carbon emission limits, will require flexible generation mixes; yet, flexibility is rarely fully considered in capacity planning models because of the computational demands of including mixed integer unit commitment within capacity expansion. We present a computationally efficient unit commitment/maintenance/capacity planning formulation that includes the critical operating constraints. An example of capacity planning for a Texas-like system in 2035 with hypothetical RPS and carbon policies shows how considering flexibility results in different capacity and energy mixes and emissions, and that the omission of flexibility can lead to a system that is unable to simultaneously meet demand, carbon, and RPS requirements.
Significance
The large-scale conversion to 100% wind, water, and solar (WWS) power for all purposes (electricity, transportation, heating/cooling, and industry) is currently inhibited by a fear of grid instability and high cost due to the variability and uncertainty of wind and solar. This paper couples numerical simulation of time- and space-dependent weather with simulation of time-dependent power demand, storage, and demand response to provide low-cost solutions to the grid reliability problem with 100% penetration of WWS across all energy sectors in the continental United States between 2050 and 2055. Solutions are obtained without higher-cost stationary battery storage by prioritizing storage of heat in soil and water; cold in water and ice; and electricity in phase-change materials, pumped hydro, hydropower, and hydrogen.
We explore the operations, balancing requirements, and costs of the Western Electricity Coordinating Council power system under a stringent greenhouse gas emission reduction target. We include sensitivities for technology costs and availability, fuel prices and emissions, and demand profile. Meeting an emissions target of 85% below 1990 levels is feasible across a range of assumptions, but the cost of achieving the goal and the technology mix are uncertain. Deployment of solar photovoltaics is the main driver of storage deployment: the diurnal periodicity of solar energy availability results in opportunities for daily arbitrage that storage technologies with several hours of duration are well suited to provide. Wind output exhibits seasonal variations and requires storage with a large energy subcomponent to avoid curtailment. The combination of low-cost solar technology and advanced battery technology can provide substantial savings through 2050, greatly mitigating the cost of climate change mitigation. Policy goals for storage deployment should be based on the function storage will play on the grid and therefore incorporate both the power rating and duration of the storage system. These goals should be set as part of overall portfolio development, as system flexibility needs will vary with the grid mix.
High cost and technical immaturity of bulk (multi-hour) electricity storage (BES) systems are often cited as major hurdles to increasing the penetration of intermittent renewables. We use a simple model to assess the economics of BES under carbon emissions constraints. Size and dispatch of a green-field generation fleet is optimized to meet a variable load at a 15 minute time resolution. Electricity supply options are wind, gas turbine, BES, and a generic dispatchable-zero-carbon (DZC) source as a proxy for fossil fuel plants with carbon capture or nuclear plants. We review the cost of selected BES technologies and parameterize the performance of storage, focusing on the energy- and power-specific capital costs. We examine sensitivity of the electricity cost to storage performance under a range of emissions constraints. Availability of inexpensive BES systems in general and particularly electrochemical technologies has a small impact on the overall cost of decarbonization. Proportional reductions in capital costs of wind and DZC lower decarbonization costs far more. We find no economic justification for seasonal storage. Intermittent renewables can be used to decarbonize the electricity supply with a proportionally small requirement for BES because gas provides much of the intermittency management even when the carbon emissions intensity is cut to less than 30% of today's U.S. average. Substantial BES is required only when emissions are constrained to nearly zero and DZC is not allowed.
Sustainable biomass can play a transformative role in the transition to a decarbonized economy, with potential applications in electricity, heat, chemicals and transportation fuels. Deploying bioenergy with carbon capture and sequestration (BECCS) results in a net reduction in atmospheric carbon. BECCS may be one of the few cost-effective carbon-negative opportunities available should anthropogenic climate change be worse than anticipated or emissions reductions in other sectors prove particularly difficult. Previous work, primarily using integrated assessment models, has identified the critical role of BECCS in long-term (pre- or post-2100 time frames) climate change mitigation, but has not investigated the role of BECCS in power systems in detail, or in aggressive time frames, even though commercial-scale facilities are starting to be deployed in the transportation sector. Here, we explore the economic and deployment implications for BECCS in the electricity system of western North America under aggressive (pre-2050) time frames and carbon emissions limitations, with rich technology representation and physical constraints. We show that BECCS, combined with aggressive renewable deployment and fossil-fuel emission reductions, can enable a carbon-negative power system in western North America by 2050 with up to 145% emissions reduction from 1990 levels. In most scenarios, the offsets produced by BECCS are found to be more valuable to the power system than the electricity it provides. Advanced biomass power generation employs similar system design to advanced coal technology, enabling a transition strategy to low-carbon energy.
The renewable power generation aggregated across Europe exhibits strong seasonal behaviors. Wind power generation is much stronger in winter than in summer. The opposite is true for solar power generation. In a future Europe with a very high share of renewable power generation those two opposite behaviors are able to counterbalance each other to a certain extent to follow the seasonal load curve. The best point of counterbalancing represents the seasonal optimal mix between wind and solar power generation. It leads to a pronounced minimum in required stored energy. For a 100% renewable Europe the seasonal optimal mix becomes 55% wind and 45% solar power generation. For less than 100% renewable scenarios the fraction of wind power generation increases and that of solar power generation decreases.
Nuclear power plants are commonly operated in a “baseload” mode at maximum rated capacity whenever online. However, nuclear power plants are technically capable of flexible operation, including changing power output over time (ramping or load following) and providing frequency regulation and operating reserves. At the same time, flexibility is becoming more valuable as many regions transition to low-carbon power systems with higher shares of variable renewable energy sources such as wind or solar power. We present a novel mixed integer linear programming formulation to more accurately represent the distinct technical operating constraints of nuclear power stations, including impacts of xenon transients in the reactor core and changing core reactivity over the fuel irradiation cycle. This novel representation of nuclear flexibility is integrated into a unit commitment and economic dispatch model for the power system. In a case study using representative utility data from the Southwest United States, we investigate the potential impacts of flexible nuclear operations in a power system with significant solar and wind energy penetration. We find that flexible nuclear operation lowers power system operating costs, increases reactor owner revenues, and substantially reduces curtailment of renewables.
We analyze 36 years of global, hourly weather data (1980–2015) to quantify the covariability of solar and wind resources as a function of time and location, over multi-decadal time scales and up to continental length scales. Assuming minimal excess generation, lossless transmission, and no other generation sources, the analysis indicates that wind-heavy or solar-heavy U.S.-scale power generation portfolios could in principle provide ∼80% of recent total annual U.S. electricity demand. However, to reliably meet 100% of total annual electricity demand, seasonal cycles and unpredictable weather events require several weeks’ worth of energy storage and/or the installation of much more capacity of solar and wind power than is routinely necessary to meet peak demand. To obtain ∼80% reliability, solar-heavy wind/solar generation mixes require sufficient energy storage to overcome the daily solar cycle, whereas wind-heavy wind/solar generation mixes require continental-scale transmission to exploit the geographic diversity of wind. Policy and planning aimed at providing a reliable electricity supply must therefore rigorously consider constraints associated with the geophysical variability of the solar and wind resource—even over continental scales.
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Clara F. Heuberger is a PhD student in the Centre for Process Systems Engineering and the Centre for Environmental Policy at Imperial College London. She holds a Bachelors and Masters in Mechanical Engineering from RWTH Aachen University. Clara studied and conducted research abroad at Carnegie Mellon University Department of Chemical Engineering and Department of Engineering and Public Policy.
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Niall Mac Dowell is a Senior Lecturer at Imperial College London, where he currently leads the Clean Fossil and Bioenergy Research Group with Bachelors and Doctoral degrees in Chemical Engineering. He is a Chartered Engineer with the IChemE and is a Member of the Royal Society of Chemistry.
This work explores the technical challenges associated with flexible operation for nuclear power plants (NPPs) and evaluates whether a flexible operational mode could improve the profitability of nuclear units by allowing nuclear plant owners/operators to reduce output when prices are low and instead shift capacity to the ancillary services markets. As compared to conventional power plants, NPP flexible operation capabilities are affected by additional physics-induced constraints. Among the most limiting constraints is the negative reactivity insertion following every reactor power drop due to the increased concentration of xenon, a strong neutron poison. In this work, a previously available power system operation model based on mixed-integer linear programming optimization was improved by implementing a dedicated representation of these physics-induced constraints for pressurized water reactors (PWRs). Because the xenon-related constraint involves nonlinear governing dynamics, a dedicated parametric approach was implemented. To evaluate the economic implications of flexible PWR operation, a case study using realistic power system data representative of the southwestern United States was analyzed. The results indicate that flexible operation can increase the revenue of nuclear units while at the same time reducing total electric system operating costs.
A new approach is required to determine a technology's value to the power systems of the 21st century. Conventional cost-based metrics are incapable of accounting for the indirect system costs associated with intermittent electricity generation, in addition to environmental and security constraints. In this work, we formalise a new concept for power generation and storage technology valuation which explicitly accounts for system conditions, integration challenges, and the level of technology penetration. The centrepiece of the System Value (SV) concept is a whole electricity systems model on a national scale, which simultaneously determines the ideal power system design and unit-wise operational strategy. It brings typical Process Systems Engineering thinking into the analysis of power systems. The model formulation is a mixed-integer linear optimisation and can be understood as hybrid between a generation expansion and a unit commitment model. We present an analysis of the future UK electricity system and investigate the SV of Carbon Capture and Storage equipped power plants (CCS), onshore wind power plants, and grid-level energy storage capacity. We show how the availability of different low-carbon technologies impact the optimal capacity mix and generation patterns. We find that the SV in the year 2035 of grid-level energy storage is an order of magnitude greater than that of CCS and wind power plants. However, CCS and wind capacity provide a more consistent value to the system as their level of deployment increases. Ultimately, the incremental system value of a power technology is a function of the prevalent system design and constraints.
Current emission pledges to the Paris Agreement appear insufficient to hold the global average temperature increase to well below 2 °C above pre-industrial levels. Yet, details are missing on how to track progress towards the â € Paris goal', inform the five-yearly â € global stocktake', and increase the ambition of Nationally Determined Contributions (NDCs). We develop a nested structure of key indicators to track progress through time. Global emissions track aggregated progress, country-level decompositions track emerging trends that link directly to NDCs, and technology diffusion indicates future reductions. We find the recent slowdown in global emissions growth is due to reduced growth in coal use since 2011, primarily in China and secondarily in the United States. The slowdown is projected to continue in 2016, with global CO 2 emissions from fossil fuels and industry similar to the 2015 level of 36 GtCO 2. Explosive and policy-driven growth in wind and solar has contributed to the global emissions slowdown, but has been less important than economic factors and energy efficiency. We show that many key indicators are currently broadly consistent with emission scenarios that keep temperatures below 2 °C, but the continued lack of large-scale carbon capture and storage threatens 2030 targets and the longer-term Paris ambition of net-zero emissions. © 2017 Macmillan Publishers Limited, part of Springer Nature. All rights reserved.
Carbon capture and sequestration (CCS) may be a key technology for achieving large CO2 emission reductions. Relative to “normal” CCS, “flexible” CCS retrofits include solvent storage that allows the generator to temporarily reduce the CCS parasitic load and increase the generator’s net efficiency, capacity, and ramp rate. Due to this flexibility, flexible CCS generators provide system benefits that normal CCS generators do not, which could make flexible CCS an economic CO2 emission reduction strategy. Here, we estimate the system-level cost-effectiveness of reducing CO2 emissions with flexible CCS compared to re-dispatching (i.e., substituting gas- for coal-fired electricity generation), wind, and normal CCS under the Clean Power Plan (CPP) and a hypothetical more stringent CO2 emission reduction target (“stronger CPP”). Using a unit commitment and economic dispatch model, we find flexible CCS achieves more cost-effective emission reductions than normal CCS under both reduction targets, indicating that policies that promote CCS should encourage flexible CCS. However, flexible CCS is less cost-effective than wind under both reduction targets, and less and more cost-effective than re-dispatching under the CPP and stronger CPP, respectively. Thus, CCS will likely be a minor CPP compliance strategy, but may play a larger role under a stronger emission reduction target.
Electrical energy storage could play an important role in decarbonizing the electricity sector by offering a new, carbon-free source of operational flexibility, improving the utilization of generation assets, and facilitating the integration of variable renewable energy sources. Yet, the future cost of energy storage technologies is uncertain, and the value that they can bring to the system depends on multiple factors. Moreover, the marginal value of storage diminishes as more energy storage capacity is deployed. To explore the potential value of energy storage in deep decarbonization of the electricity sector, we assess the impact of increasing levels of energy storage capacity on both power system operations and investments in generation capacity using a generation capacity expansion model with detailed unit commitment constraints. In a case study of a system with load and renewable resource characteristics from the U.S. state of Texas, we find that energy storage delivers value by increasing the cost-effective penetration of renewable energy, reducing total investments in nuclear power and gas-fired peaking units, and improving the utilization of all installed capacity. However, we find that the value delivered by energy storage with a 2-hour storage capacity only exceeds current technology costs under strict emissions limits, implying that substantial cost reductions in battery storage are needed to justify large-scale deployment. In contrast, storage resources with a 10-hour storage capacity deliver value consistent with the current cost of pumped hydroelectric storage. In general, while energy storage appears essential to enable decarbonization strategies dependent on very high shares of wind and solar energy, storage is not a requisite if a diverse mix of flexible, low-carbon power sources is employed, including flexible nuclear power.
This study explores various scenarios and flexibility mechanisms to integrate high penetrations of renewable energy into the US (United States) power grid. A linear programming model – POWER (Power system Optimization With diverse Energy Resources) – is constructed and used to (1) quantify flexibility cost-benefits of geographic aggregation, renewable overgeneration, storage, and flexible electric vehicle charging, and (2) compare pathways to a fully renewable electricity system. Geographic aggregation provides the largest flexibility benefit with ∼5–50% cost savings, but each region's contribution to the aggregate RPS (renewable portfolio standard) target is disproportionate, suggesting the need for regional-and-resource-specific RPS targets. Electric vehicle charging yields a lower levelized system cost, revealing the benefits of demand-side flexibility. However, existing demand response price structures may need adjustment to encourage optimal flexible load in highly renewable systems. Two scenarios with RPS targets from 20% to 100% for the US (peak load ∼729 GW) and California (peak load ∼62 GW) find each RPS target feasible from a planning perspective, but with 2× the cost and 3× the overgeneration at a 100% versus 80% RPS target. Emission reduction cost savings for the aggregated US system with an 80% versus 20% RPS target are roughly 80 billion/year cost for the same RPS range.
In this paper, we demonstrate the role of electricity storage for the integration of high shares of variable renewable energy sources (VRES) in the long-term evolution of the power system. For this, a new electricity module is developed in POLES (Prospective Outlook on Long-term Energy Systems). It now takes into account the impacts of VRES on the European power system. The power system operation relies on EUCAD (European Unit Commitment and Dispatch), which includes daily storage and other inter-temporal constraints. The innovative aspect of our work is the direct coupling between POLES and EUCAD, thus combining a long-term simulation horizon and a short-term approach for the power system operation. The storage technologies represented are pumped-hydro storage, lithium-ion batteries, adiabatic compressed air energy storage (a-CAES) and electric vehicles (charging optimisation and vehicle-to-grid). Demand response and European grid interconnections are also represented in order to include, to some extent, these flexibility options.
It is expected that an energy system faces increasing flexibility requirements in order to cope with increasing contributions from variable renewable energy sources (VRE). In general, the instant balance of temporal and spatial inequalities of the electricity system can be achieved by many compensating measures. However, a thorough and precise quantification of the flexibility demand of a VRE based energy system turns out to be a complex task. So far, literature on energy economics and engineering has provided analyses concerning various aspects of the system requirements for flexibility. Accordingly, this review paper primarily aims to categorize the scientific approaches that have been used in "flexibility demand" studies. In this context, we classify exemplary study results from the German and European energy systems into technical, economic, and market potential categories to enhance their comparability. Moreover, we conduct a methodological evaluation of the literature findings to determine further research requirements. Against this background we also discuss a conceptual framework to quantify the market potential of flexible technologies.
Many impacts projected for a global warming level of 2 °C relative to pre-industrial levels may exceed the coping capacities of particularly vulnerable countries. Therefore, many countries advocate limiting warming to below 1.5 °C. Here we analyse integrated energy-economy-environment scenarios that keep warming to below 1.5 °C by 2100. We find that in such scenarios, energy-system transformations are in many aspects similar to 2 °C-consistent scenarios, but show a faster scale-up of mitigation action in most sectors, leading to observable differences in emission reductions in 2030 and 2050. The move from a 2 °C- to a 1.5 °C-consistent world will be achieved mainly through additional reductions of CO 2. This implies an earlier transition to net zero carbon emissions worldwide, to be achieved between 2045 and 2060. Energy efficiency and stringent early reductions are key to retain a possibility for limiting warming to below 1.5 °C by 2100. The window for achieving this goal is small and rapidly closing.
The paper reviews different approaches, technologies, and strategies to manage large-scale schemes of variable renewable electricity such as solar and wind power. We consider both supply and demand side measures. In addition to presenting energy system flexibility measures, their importance to renewable electricity is discussed. The flexibility measures available range from traditional ones such as grid extension or pumped hydro storage to more advanced strategies such as demand side management and demand side linked approaches, e.g. the use of electric vehicles for storing excess electricity, but also providing grid support services. Advanced batteries may offer new solutions in the future, though the high costs associated with batteries may restrict their use to smaller scale applications. Different “P2Y”-type of strategies, where P stands for surplus renewable power and Y for the energy form or energy service to which this excess in converted to, e.g. thermal energy, hydrogen, gas or mobility are receiving much attention as potential flexibility solutions, making use of the energy system as a whole. To “functionalize” or to assess the value of the various energy system flexibility measures, these need often be put into an electricity/energy market or utility service context. Summarizing, the outlook for managing large amounts of RE power in terms of options available seems to be promising.
This paper analyzes the role of transport electrification in the broader context of energy system transformation and climate stabilization. As part of the EMF27 model inter-comparison exercise, we employ the MESSAGE integrated assessment modeling framework to conduct a systematic variation of availability, cost, and performance of particular energy supply technologies, thereby deriving implications for feasibility of climate stabilization goals and the associated costs of mitigation. In addition, we explore a wide range of assumptions regarding the potential degree of electrification of the transportation sector. These analyses allow us to (i) test the extent to which the feasible attainment of stringent climate policy targets depends on transport electrification, and (ii) assess the far-reaching impacts that transport electrification could have throughout the rest of the energy system. A detailed analysis of the transition to electricity within the transport sector is not conducted. Our results indicate that while a low-carbon transport system built upon conventional liquid-based fuel delivery infrastructures is destined to become increasingly reliant on biofuels and synthetic liquids, electrification opens up a door through which nuclear energy and non-biomass renewables can flow. The latter has important implications for mitigation costs.
Wind and solar PV generation data for the entire contiguous US are
calculated, on the basis of 32 years of weather data with temporal resolution
of one hour and spatial resolution of 40x40km, assuming
site-suitability-based as well as stochastic wind and solar PV capacity
distributions throughout the country. These data are used to investigate a
fully renewable electricity system, resting primarily upon wind and solar PV
power. We find that the seasonal optimal mix of wind and solar PV comes at
around 80% solar PV share, owing to the US summer load peak. By picking this
mix, long-term storage requirements can be more than halved compared to a wind
only mix. The daily optimal mix lies at about 80% wind share due to the nightly
gap in solar PV production. Picking this mix instead of solar only reduces
backup energy needs by about 50%. Furthermore, we calculate shifts in FERC
(Federal Energy Regulatory Commission)-level LCOE (Levelized Costs Of
Electricity) for wind and solar PV due to their differing resource quality and
fluctuation patterns. LCOE vary by up to 35% due to regional conditions, and
LCOE-optimal mixes turn out to largely follow resource quality. A transmission
network enhancement among FERC regions is constructed to transfer high
penetrations of solar and wind across FERC boundaries, based on a novel
least-cost optimization approach.
Based on a large number of energy-economic and integrated assessment models, the Energy Modeling Forum (EMF) 27 study systematically explores the implications of technology cost and availability for feasibility and macroeconomic costs of energy system transformations toward climate stabilization. At the highest level, the technology strategy articulated in all the scenarios in EMF27 includes three elements: decarbonization of energy supply, increasing the use of low-carbon energy carriers in end-use, and reduction of energy use. The way that the scenarios differ is in the degree to which these different elements of strategy are implemented, the timing of those implementations, and the associated macroeconomic costs. The study also discusses the value of individual technologies for achieving climate stabilization. A robust finding is that the unavailability of carbon capture and storage and limited availability of bioenergy have the largest impact on feasibility and macroeconomic costs for stabilizing atmospheric concentrations at low levels, mostly because of their combined ability to remove carbon from the atmosphere. Constraining options in the electric sector such as nuclear power, wind and solar energy in contrast has a much smaller impact on the cost of mitigation.
This paper presents high renewable electricity penetration scenarios in the United States using detailed capacity expansion modeling that is designed to properly account for the variability and uncertainty of wind and solar resources. The scenarios focus solely on the electricity system, an important sector within the larger energy sector, and demonstrate long-term visions of a U.S. power system where renewable technologies, including biomass, geothermal, hydropower, solar, and wind, contribute 80% of 2050 annual electricity, including 49–55% from wind and solar photovoltaic generation. We present the integration challenges of achieving this high penetration and characterize the options to increase grid flexibility to manage variability. Four high renewable pathways are modeled and demonstrate the robustness and diversity of renewable options. We estimate 69–82% annual greenhouse gas emission reductions and 3%–30% incremental electricity price increases associated with reaching 80%-by-2050 renewable electricity relative to reference scenarios. This paper affirms and strengthens similar analysis from the Renewable Electricity Futures study by using an improved model and updated data to better reflect investment and dispatch decisions under current outlooks for the U.S. electricity sector.
The storage and balancing needs of a simplified European power system, which is based on wind and solar power generation only, are derived from an extensive weather-driven modeling of hourly power mismatches between generation and load. The storage energy capacity, the annual balancing energy and the balancing power are found to depend significantly on the mixing ratio between wind and solar power generation. They decrease strongly with the overall excess generation. At 50% excess generation the required long-term storage energy capacity and annual balancing energy amount to 1% of the annual consumption. The required balancing power turns out to be 25% of the average hourly load. These numbers are in agreement with current hydro storage lakes in Scandinavia and the Alps, as well as with potential hydrogen storage in mostly North-German salt caverns.
The variability of wind and solar power crucially affects their social value. This paper determines the welfare-optimal market share of wind and solar power under different technology, price, and policy assumptions, focussing on the impact of variability. A numerical electricity market model with high temporal resolution is used to represent variability realistically, and empirical data are used to capture crucial correlations over time and across space. Results indicate that variability significantly limits the role that wind and solar power should play in a cost-optimal energy system. The optimal share of wind power in North- Western Europe is estimated to be 7-10% in the medium term and around 25% in the long term. If wind speeds were constant, the optimal deployment rate would be up to twice as high. Solar power is too expensive to be deployed efficiently, even at very optimistic assumptions regarding cost development.
We examine the changes to the electric power system required to incorporate high penetration of variable wind and solar electricity generation in a transmission constrained grid. Simulations were performed in the Texas, US (ERCOT) grid where different mixes of wind, solar photovoltaic and concentrating solar power meet up to 80% of the electric demand. The primary constraints on incorporation of these sources at large scale are the limited time coincidence of the resource with normal electricity demand, combined with the limited flexibility of thermal generators to reduce output. An additional constraint in the ERCOT system is the current inability to exchange power with neighboring grids. By themselves, these constraints would result in unusable renewable generation and increased costs. But a highly flexible system - with must-run baseload generators virtually eliminated - allows for penetrations of up to about 50% variable generation with curtailment rates of less than 10%. For penetration levels up to 80% of the system's electricity demand, keeping curtailments to less than 10% requires a combination of load shifting and storage equal to about one day of average demand.
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