| 1. |
- Ek Fälth, Hanna, 1992, et al.
(författare)
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Trade-offs between aggregated and turbine-level representations of hydropower in optimization models
- 2023
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Ingår i: Renewable and Sustainable Energy Reviews. - 1879-0690 .- 1364-0321. ; 183
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Tidskriftsartikel (refereegranskat)abstract
- To model a future power system with high shares of variable renewables, it is essential to capture the flexibility of dispatchable technologies such as hydropower. However, the representation of hydropower is often oversimplified in energy system investment models, such that the flexibility of hydropower is significantly exaggerated. This suggests the need for improved representations of hydropower that capture physical river dynamics but are computationally efficient to maintain the tractability of large models. Here, we develop a series of hydropower optimization models for a single river with various levels of techno-physical detail to evaluate options for hydropower representations in energy system investment models. All models operate hourly over a full year with perfect foresight. We explore trade-offs between accuracy and computational time involved in including features such as the river network, head-dependent power production, and discharge-dependent turbine efficiencies. We find that the level of detail significantly affects the optimal production and confirm that a simplistic hydropower representation similar to those often used in investment models significantly overestimates the flexibility of hydropower. The most detailed nonconvex model includes a full river network, head-dependency, and turbine efficiencies and is solved in just one hour on a modern desktop computer. Furthermore, we linearize this detailed model, thereby reducing computation time to one minute while featuring production dynamics substantially more similar to the full nonconvex model than a naive linear network model. These contributions pave the way for improving hydropower representations in investment models to avoid overestimating the flexibility that hydropower may provide.
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| 2. |
- Hedenus, Fredrik, 1976, et al.
(författare)
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Historical wind deployment and implications for energy system models
- 2022
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Ingår i: Renewable and Sustainable Energy Reviews. - : Elsevier BV. - 1879-0690 .- 1364-0321. ; 168
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Tidskriftsartikel (refereegranskat)abstract
- A critical parameter in modeling studies of future decarbonized energy systems is the potential future capacity for onshore wind power. Wind power potential in energy system models is subject to assumptions regarding: (i) constraints on land availability for wind deployment; (ii) how densely wind turbines may be placed over larger areas, and (iii) allocation of capacity with respect to wind speed. By analyzing comprehensive databases of wind turbine locations and other GIS data in eleven countries and seventeen states in Australia, Canada, and the US; all with high penetration levels of wind power, we find that: i) large wind turbines are installed on most land types, even protected areas and land areas with high population density; ii) it is not uncommon with a deployment density up to 0.5 MW/km2 on municipality or county level, with rare outlier municipalities reaching up to 1.5 MW/km2 installed capacity; and iii) wind power has historically been allocated to relatively windy sites with average wind speed above 6 m/s. In many cases, allocation methods used in energy system models do not consistently reflect actual installations. For instance, we find no evidence of concentration of installations at the windiest sites, as is frequently assumed in energy system models. We conclude that assumptions made in models regarding wind power potentials are poorly reflective of historical installation patterns, and we provide new data to enable assumptions that have a more robust empirical foundation.
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| 3. |
- Kan, Xiaoming, 1988, et al.
(författare)
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Into a cooler future with electricity generated from solar photovoltaic
- 2022
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Ingår i: iScience. - : Elsevier BV. - 2589-0042. ; 25:5
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Tidskriftsartikel (refereegranskat)abstract
- The fast-growing global cooling demand due to income growth in tropical countries necessitates substantial investments in new generation capacity. Despite the synergy between the temporal behavior of cooling demand and solar PV production, it is not clear whether the increased cooling demand will make solar PV more cost-effective or less so. We use a capacity expansion model to investigate the cost-effectiveness of investing in solar PV to meet the electricity demand linked to cooling for seven different regions under various CO2 emission targets. Solar PV plays a dominant role in meeting the additional electricity demand for cooling, and the share of solar PV in the additional generation capacity ranges from 64% to 135%. Additionally, powering electric cooling with mainly solar PV is cheaper than powering the rest of the demand. These results suggest that solar PV may comprise the backbone of electricity supply for cooling in the future electricity system.
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| 4. |
- Kan, Xiaoming, 1988, et al.
(författare)
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The cost of a future low-carbon electricity system without nuclear power – the case of Sweden
- 2020
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Ingår i: Energy. - : Elsevier BV. - 0360-5442 .- 1873-6785. ; 195
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Tidskriftsartikel (refereegranskat)abstract
- To achieve the goal of deep decarbonization of the electricity system, more and more variable renewable energy (VRE) is being adopted. However, there is no consensus among researchers on whether the goal can be accomplished without large cost escalation if nuclear power is excluded in the future electricity system. In Sweden, where nuclear power generated 41% of the annual electricity supply in 2014, the official goal is 100% renewable electricity production by 2040. Therefore, we investigate the cost of a future low-carbon electricity system without nuclear power for Sweden. We model the European electricity system with a focus on Sweden and run a techno-economic cost optimization model for capacity investment and dispatch of generation, transmission, storage and demand-response, under a CO2 emission constraint of 10 g/kWh. Our results show that there are no, or only minor, cost benefits to reinvest in nuclear power plants in Sweden once the old ones are decommissioned. This holds for a large range of assumptions on technology costs and possibilities for investment in additional transmission capacity. We contrast our results with the recent study that claims severe cost penalties for not allowing nuclear power in Sweden and discuss the implications of methodology choice.
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| 5. |
- Kan, Xiaoming, 1988, et al.
(författare)
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The impacts of the electricity demand pattern on electricity system cost and the electricity supply mix: A comprehensive modeling analysis for Europe
- 2021
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Ingår i: Energy. - : Elsevier BV. - 0360-5442 .- 1873-6785. ; 235
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Tidskriftsartikel (refereegranskat)abstract
- Energy system models for long-term planning are widely used to explore the future electricity system. Typically, to represent the future electricity demand in these models, historical demand profiles are used directly or scaled up linearly. Although the volume change for the electricity demand is considered, the potential change of the demand pattern is ignored. Meanwhile, the future electricity demand pattern is highly uncertain due to various factors, including climate change, e-mobility, electric heating, and electric cooling. We use a techno-economic cost optimization model to investigate a stylized case and assess the effects on system cost and electricity supply mix of assuming different demand patterns for the models. Our results show that differences in diurnal demand patterns affect the system cost by less than 3%. Similarly, demand profiles with a flat seasonal variation or a winter peak result in only minor changes in system cost, as compared to the present demand profile. Demand profiles with a summer peak may display a system cost increase of up to 8%, whereas the electricity supply mix may differ by a factor of two. A more detailed case study is conducted for Europe and the results are consistent with the findings from the stylized case.
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| 6. |
- Mattsson, Niclas, 1967, et al.
(författare)
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An autopilot for energy models – Automatic generation of renewable supply curves, hourly capacity factors and hourly synthetic electricity demand for arbitrary world regions
- 2021
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Ingår i: Energy Strategy Reviews. - : Elsevier BV. - 2211-467X. ; 33
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Tidskriftsartikel (refereegranskat)abstract
- Energy system models are increasingly being used to explore scenarios with large shares of variable renewables. This requires input data of high spatial and temporal resolution and places a considerable preprocessing burden on the modeling team. Here we present a new code set with an open source license for automatic generation of input data for large-scale energy system models for arbitrary regions of the world, including sub-national regions, along with an associated generic capacity expansion model of the electricity system. We use ECMWF ERA5 global reanalysis data along with other public geospatial datasets to generate detailed supply curves and hourly capacity factors for solar photovoltaic power, concentrated solar power, onshore and offshore wind power, and existing and future hydropower. Further, we use a machine learning approach to generate synthetic hourly electricity demand series that describe current demand, which we extend to future years using regional SSP scenarios. Finally, our code set automatically generates costs and losses for HVDC interconnections between neighboring regions. The usefulness of our approach is demonstrated by several different case studies based on input data generated by our code. We show that our model runs of a future European electricity system with high share of renewables are in line with results from more detailed models, despite our use of global datasets and synthetic demand.
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| 7. |
- Millinger, Markus, 1984, et al.
(författare)
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Are biofuel mandates cost-effective? - An analysis of transport fuels and biomass usage to achieve emissions targets in the European energy system
- 2022
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Ingår i: Applied Energy. - : Elsevier BV. - 1872-9118 .- 0306-2619. ; 326
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Tidskriftsartikel (refereegranskat)abstract
- Abatement options for the hard-to-electrify parts of the transport sector are needed to achieve ambitious emissions targets. Biofuels based on biomass, electrofuels based on renewable hydrogen and a carbon source, as well as fossil fuels compensated by carbon dioxide removal (CDR) are the main options. Currently, biofuels are the only renewable fuels available at scale and are stimulated by blending mandates. Here, we estimate the system cost of enforcing such mandates in addition to an overall emissions cap for all energy sectors. We model overnight scenarios for 2040 and 2060 with the sector-coupled European energy system model PyPSA-Eur-Sec, with a high temporal resolution. The following cost drivers are identified: (i) high biomass costs due to scarcity, (ii) opportunity costs for competing usages of biomass for industry heat and combined heat and power (CHP) with carbon capture, and (iii) lower scalability and generally higher cost for biofuels compared to electrofuels and fossil fuels combined with CDR. With a -80% emissions reduction target in 2040, variable renewables, partial electrification of heat, industry and transport, and biomass use for CHP and industrial heat are important for achieving the target at minimal cost, while an abatement of remaining liquid fossil fuel use increases system cost. In this case, a 50% biofuel mandate increases total energy system costs by 123–191 billion €, corresponding to 35%–62% of the liquid fuel cost without a mandate. With a negative -105% emissions target in 2060, fuel abatement options are necessary, and electrofuels or the use of CDR to offset fossil fuel emissions are both more competitive than biofuels. In this case, a 50% biofuel mandate increases total costs by 21–33 billion €, or 11%–15% of the liquid fuel cost without a mandate. Biomass is preferred in CHP and industry heat, combined with carbon capture to serve negative emissions or electrofuel production, thereby utilising biogenic carbon several times. Sensitivity analyses reveal significant uncertainties but consistently support that higher biofuel mandates lead to higher costs.
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| 8. |
- Reichenberg, Lina, 1976, et al.
(författare)
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Deep decarbonization and the supergrid – Prospects for electricity transmission between Europe and China
- 2022
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Ingår i: Energy. - : Elsevier BV. - 0360-5442 .- 1873-6785. ; 239
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Tidskriftsartikel (refereegranskat)abstract
- Long distance transmission within continents has been shown to be one of the most effective variation management strategies to reduce the cost of renewable energy systems. In this paper, we test whether the system cost further decreases when transmission is extended to intercontinental connections. We analyze a Eurasian interconnection between China, Mid-Asia and Europe, using a capacity expansion model with hourly time resolution. Our modelling results suggestthat a supergrid option decreases total system cost by a maximum of 5%, compared to continental grid integration. The maximum cost reductionis achieved when (i) the generation is constrained to be made up almost entirely by renewables, (ii) the land available for VRE farms is relatively limited and the demand is relatively high and (iii) the cost for solar PV and storage is high. This is explained by that a super grid allows for harnessing of remote wind-, solar- and hydro resources demand centers. As for low-cost storage, it represents a competing variation management option, and may substitute part of the role of the supergrid, which is to manage variations through long-distance trade. We conclude that the benefits of a supergrid from a techno-economic perspective are in most cases negligible, or modest at best.
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| 9. |
- Reichenberg, Lina, 1976, et al.
(författare)
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The error induced by using representative periods in capacity expansion models: system cost, total capacity mix and regional capacity mix
- 2024
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Ingår i: Energy Systems. - : Springer Science and Business Media LLC. - 1868-3975 .- 1868-3967. ; 15:1, s. 215-232
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Tidskriftsartikel (refereegranskat)abstract
- Capacity Expansion Models (CEMs) are optimization models used for long-term energy planning on national to continental scale. They are typically computationally demanding, thus in need of simplification, where one such simplification is to reduce the temporal representation. This paper investigates how using representative periods to reduce the temporal representation in CEMs distorts results compared to a benchmark model of a full chronological year. The test model is a generic CEM applied to Europe. We test the performance of reduced models at penetration levels of wind and solar of 90%. Three measures for accuracy are used: (i) system cost, (ii) total capacity mix and (iii) regional capacity. We find that: (i) the system cost is well represented (similar to 5% deviation from benchmark) with as few as ten representative days, (ii) the capacity mix is in general fairly well (similar to 20% deviation) represented with 50 or more representative days, and (iii) the regional capacity mix displays large deviations (> 50%) from benchmark for as many as 250 representative days. We conclude that modelers should be aware of the error margins when presenting results on these three aspects.
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| 10. |
- Brown, T., et al.
(författare)
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Decreasing market value of variable renewables can be avoided by policy action
- 2021
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Ingår i: Energy Economics. - : Elsevier BV. - 0140-9883 .- 1873-6181. ; 100
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Tidskriftsartikel (refereegranskat)abstract
- Although recent studies have shown that electricity systems with shares of wind and solar above 80% can be affordable, economists have raised concerns about market integration. Correlated generation from variable renewable sources depresses market prices, which can cause wind and solar to cannibalise their own revenues and prevent them from covering their costs from the market. This cannibalisation appears to set limits on the integration of wind and solar, and thus to contradict studies that show that high shares are cost effective. Here we show from theory and with simulation examples how market incentives interact with prices, revenue and costs for renewable electricity systems. The decline in average revenue seen in some recent literature is due to an implicit policy assumption that technologies are forced into the system, whether it be with subsidies or quotas. This decline is mathematically guaranteed regardless of whether the subsidised technology is variable or not. If instead the driving policy is a carbon dioxide cap or tax, wind and solar shares can rise without cannibalising their own market revenue, even at penetrations of wind and solar above 80%. The strong dependence of market value on the policy regime means that market value needs to be used with caution as a measure of market integration. Declining market value is not necessarily a sign of integration problems, but rather a result of policy choices.
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| 11. |
- Dimanchev, Emil, et al.
(författare)
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Consequences of the missing risk market problem for power system emissions
- 2024
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Ingår i: Energy Economics. - 0140-9883 .- 1873-6181. ; 136
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Tidskriftsartikel (refereegranskat)abstract
- 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.
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| 12. |
- Ek Fälth, Hanna, 1992, et al.
(författare)
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MENA compared to Europe: The influence of land use, nuclear power, and transmission expansion on renewable electricity system costs
- 2021
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Ingår i: Energy Strategy Reviews. - : Elsevier BV. - 2211-467X. ; 33
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Tidskriftsartikel (refereegranskat)abstract
- Most studies that examine CO2-neutral, or near CO2-neutral, power systems by using energy system models investigate Europe or the United States, while similar studies for other regions are rare. In this paper, we focus on the Middle East and North Africa (MENA), where weather conditions, especially for solar, differ substantially from those in Europe. We use a green-field linear capacity expansion model with over-night investment to assess the effect on the system cost of (i) limiting/expanding the amount of land available for wind and solar farms, (ii) allowing for nuclear power and (iii) disallowing for international transmission. The assessment is done under three different cost regimes for solar PV and battery storage. First, we find that the amount of available land for wind and solar farms can have a significant impact on the system cost, with a cost increase of 0–50% as a result of reduced available land. In MENA, the impact on system cost from land availability is contingent on the PV and battery cost regime, while in Europe it is not. Second, allowing for nuclear power has a minor effect in MENA, while it may decrease the system cost in Europe by up to 20%. In Europe, the effect on system cost from allowing for nuclear power is highly dependent on the PV and battery cost regime. Third, disallowing for international transmission increases the system cost by up to 25% in both Europe and MENA, and the cost increase depends on the cost regime for PV and batteries. The impacts on system cost from these three controversial and policy-relevant factors in a decarbonized power system thus play out differently, depending on (i) the region and (ii) uncertain future investment costs for solar PV and storage. We conclude that a renewable power system in MENA is likely to be less costly than one in Europe, irrespective of future uncertainties regarding investment cost for PV and batteries, and policies surrounding nuclear power, transmission, and land available for wind- and solar farms. In MENA, the system cost varies between 42 and 96 $/MWh. In Europe, the system cost varies between 51 and 102 $/MWh.
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| 13. |
- Hassanzadeh Moghimi, Farzad, 1994-, et al.
(författare)
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Climate Policy and Strategic Operations in a Hydro-Thermal Power System
- 2023
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Ingår i: Energy Journal. - : International Association for Energy Economics (IAEE). - 0195-6574 .- 1944-9089. ; 44:5, s. 67-94
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Tidskriftsartikel (refereegranskat)abstract
- Decarbonisation of the Nordic power sector entails substantial variable renewable energy (VRE) adoption. While Nordic hydropower reservoirs can mitigate VRE output's intermittency, strategic hydro producers may leverage increased flexibility requirements to exert market power. Using a Nash-Cournot model, we find that even the current Nordic power system could yield modest gains from strategic reservoir operations regardless of a prohibition on "spilling" water to increase prices. Instead, strategic hydro producers could shift generation from peak to off-peak seasons. Such temporal arbitrage becomes more attractive under a climate package with a €100/t CO2 price and doubled VRE capacity. Since the package increases generation variability, lowers average prices, and makes fossil-fuelled plants unprofitable, strategic hydro producers face lower opportunity costs in shifting output from peak to off-peak seasons and encounter muted responses from price-taking fossil-fuelled plants. Hence, a climate package that curtails CO2 emissions may also bolster strategic hydro producers' leverage.
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| 14. |
- Reichenberg, Lina, 1976, et al.
(författare)
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Revenue and risk of variable renewable electricity investment: The cannibalization effect under high market penetration
- 2023
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Ingår i: Energy. - 0360-5442 .- 1873-6785. ; 284
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Tidskriftsartikel (refereegranskat)abstract
- Wind and solar power depress market prices at times when they produce the most. This has been termed the ‘cannibalization effect’, and its magnitude has been established within the economic literature on current and future markets. Although it has a substantial impact on the revenue of VRE technologies, the cannibalization effect is neglected in the capital budgeting literature, including portfolio- and real options theory. In this paper, we present an analytical framework that explicitly models the correlation between VRE production and electricity price, based on the production costs of surrounding generation capacity. We derive closed-form expressions for the expected short-term and long-term revenue, the variance of the revenue and the timing of investments. The effect of including these system characteristics is illustrated with numerical examples, where we find the cannibalization effect to decrease projected profit relative to investment cost from 33% to between 13% and −40%, depending on the assumption for the future VRE capacity expansion rate. Using a real options framework, the investment threshold increases by between 13% and 67%, due to the inclusion of cannibalization.
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