Abstract
A new Swiss TIMES (The Integrated MARKAL–EFOM System) electricity model with an hourly representation of inter-temporal detail and a century-long model horizon has been developed to explore the TIMES framework’s suitability as a long-term electricity dispatch model. To understand the incremental insights from this hourly model, it is compared to an aggregated model with only two diurnal timeslices like in most MARKAL/TIMES models. Two scenarios have been analysed with both models to answer the following questions: Are there differences in model solutions? What are the benefits of having a high number of timeslices? Are there any computational limitations? The primary objective of this paper is to understand the differences between the solutions of the two models, rather than Swiss policy implication or potential uncertainties in input parameters and assumptions. The analysis reveals that the hourly model offers powerful insights into the electricity generation schedule. Nevertheless, the TIMES framework cannot substitute for a dispatch model because some features cannot be represented; however, the long model time horizon and integrated system approaches of TIMES provide features not available in conventional dispatch models. The methodology of the model development and insights from the model comparison are described.
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Notes
There is no heat demand in the model. In order to cope with operation of CHP, heat output from CHPs is currently modelled to be exported with small price incentive.
Currency conversion : 1 euro = 1.4 CHF; 1 US$ = 0.93 CHF [55]
See footnote 1.
This assumption provides flexible exchange of electricity in the future years, but the future availability of interconnectors is quite uncertain and heavily dependent on electricity system development in the four markets.
We analysed hourly electricity spot market prices for 2008 [19] and generated time-dependent electricity import prices for all the 288 timeslices. However, this approach did not imitate the historical trade pattern. Thus, the current approach is implemented to model the trading mechanism, but this represents an area of further model development.
For instance, in May 2011, the Swiss Federal council decided to completely restrict investment in new nuclear power plants. The Base scenario does not include this restriction, which has been analysed in our other publications [33, 56]. Thus, we re-emphasise that the Base scenario is adopted as an illustrative case.
From our extensive scenario analyses [33], we found that the highly fluctuating demands in Switzerland (requiring around 3.5 GW of flexible power plants) are easily managed by the availability of large dam and pumped hydro storage facilities. In addition, the interconnectors also serve as additional sources of supply (import) and most importantly load dumping (export).
Years specified in the figures represent the mid-year of periods, i.e. 2020 represents 2018–22; 2048: 2041–55; 2080: 2071–2090. In the legends, Gas (Base) and Gas (Flex) refer to base load and dispatchable gas plants. Electricity consumed by pumped storage plant is shown as Pumps.
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Acknowledgments
Earlier versions of this paper were presented at the ETSAP Workshop held in New Delhi and Stockholm [36, 37]. The author thank many people, who offered their support during the development of this model, particularly addressing the computational and solver issues, MIP formulation and fixing the storage algorithms. This paper is partly conceptualised based on the review comments from an earlier publication [38] and the contribution from the reviewers is highly appreciated.
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Kannan, R., Turton, H. A Long-Term Electricity Dispatch Model with the TIMES Framework. Environ Model Assess 18, 325–343 (2013). https://doi.org/10.1007/s10666-012-9346-y
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DOI: https://doi.org/10.1007/s10666-012-9346-y