By corresponding author Anders N. Andersen, PhD, Ext. Ass. Professor at Aalborg University, R&D projects responsible at EMD International and Poul Alberg Østergaard, Professor at Aalborg University
Published in Hot Cool, edition no. 7/2023 | ISSN 0904 9681 |
Our analysis will take a starting point on Ringkøbing District Heating[1], which lies in Western Denmark. It is, of course, a little ambitious to guide decision-makers based on only one case. However, it is an interesting case, and we will also include some of the viewpoints that came up at and after the meeting in Copenhagen.
Ringkøbing DH produces around 110,000 MWh-heat/year. The plant has already invested in 30,000 m2 of solar collector and 3,000 m3 thermal storage connected to this solar collector and a tiny heat pump. However, in the analysis, we have taken the liberty of assuming that Ringkøbing DH could redo these investment decisions based on the present investment costs in Denmark. Thus, we present a counterfactual analysis of what could have been done instead.
The analysis of the investments is made in the energy system analysis tool energyPRO[2]. A model for 2023 is made, as shown in Figure 1. The reference model maintains three existing heat-producing units – a natural gas engine, a natural gas boiler, and an electric boiler. These units have access to the existing 4,800 m3 thermal storage made when the natural gas engine was installed, allowing the engine to primarily produce electricity and heat in hours with high Day-ahead prices. Furthermore, the existing thermal storage in the reference simulation allows the electric boiler to consume electricity in hours with low Day-ahead prices.
In the reference calculation with the assumed technical and economic assumptions, the Net Heat Production Cost (NHPC) for producing the 110,000 MWh-heat is calculated as 8.02 M EUR, which gives an average production price of 72.9 EUR/MWh-heat. The Net calculation means that the value of the sold electricity is subtracted from the operating expenditures.
Figure 1: Model of Ringkøbing DH implemented in the energy system analysis tool energyPRO.
The reference simulation includes no new investments in solar collectors, photovoltaic, wind power, heat pumps, or additional thermal storage. Heat pump capacity is an interesting possible new investment since it is closely related to wind power or PV investments, given heat pump electricity demand. The price for the used electricity at the heat pump may be low in hours, where the wind turbine covers the heat pump consumption behind own meter, thus avoiding taxes and grid tariffs. Heat pumps may, of course, also simply operate on grid electricity.
Of significant importance for choosing the optimal investment of solar collector, PV, wind turbine, heat pump, and new thermal storage is the assumed natural gas and Day-ahead electricity prices in a lifetime of 15-20 years. For these analyses we have assumed that the prices are the same in all years as in 2023, and that natural gas and Day-ahead electricity prices in 2023 are found by multiplying the hourly natural gas and Day-ahead electricity prices in 2022 with the factor 0.4209. This factor is the ratio between the average Day-ahead electricity prices in the first eight months of 2022 and 2023. It shows that the average price was more than halved in these months from 2022 to 2023. Figure 2 shows a clear relation between daily average natural gas and Day-ahead prices in 2022. Thus, the same factor is used for natural gas and electricity prices.
Figure 2: Daily average gas and Day-ahead prices in Denmark in 2022.
The specific investment costs used in this analysis are shown in the Fact Box. The investment costs are estimated in collaboration with the manager of Ringkøbing District Heating, who has the general task of tracking potential investment options and costs.
The reason for also including cable cost is that it may be relevant to invest in a direct line between the plant and, e.g., a wind turbine, to allow the benefits of operating behind the same meter in private wire operation.
For the analyses, we will optimize the benefit of a total investment of 8.9 M EUR. This corresponds to what the present 30,000 m2 solar collector and 3,000 m3 additional thermal storage would cost today.
For example, Figure 3 shows the optimized operation in seven days in May, where the 8.9 MEUR is used exclusively on PV. In the upper graph is shown the Day-ahead electricity prices. The following two graphs show the heat and electricity production and consumption. At the bottom are shown the contents of the existing thermal storage.
Notice that the electric boilers are operated in the first three days due to low prices in the Day-ahead market. However, the prices are higher on Sunday, June 28, yet the electrical boilers are still operating up to the PV production level during these hours. This is because the PV is operated behind own meter, thus providing cheap electricity to the electrical boilers.
In the last three days, there have been hours with high Day-ahead electricity prices; thus, the natural gas engine is operated.
Figure 3: The optimized operation in seven days in May, where all the total investment of 8.9 MEUR is used on PV.
In the previous section, we demonstrated some system effects of devoting the 8.9 MEUR investment sum to PV. It is, however, a multi-dimensional challenge to choose the right investment among the several possibilities, investments that typically live for at least 15 to 20 years.
Table 1 shows the yearly benefits of extreme investments, where all 8.9 MEUR is used on solar collectors, PV, wind turbines, or heat pumps (with appropriate investments in additional new thermal storage).
The yearly benefit is calculated as the reduced NHPC subtracted from the annual annuity of the investment. For example, no new investment has a yearly NHPC of 8.02 MEUR. When investing exclusively in solar collectors and storage, this NHPC is reduced to 6.46 MEUR, giving a surplus of 1.55 MEUR. The yearly annuity of the investment of 8.9 MEUR amounts to 0.60 MEUR, which offers a benefit of 0.96 MEUR per year.
It is seen from Table 1 that these extreme investments give roughly the same yearly benefit, with a slight preference for Only wind turbines.
Table 1: Yearly benefits and effects on sold and bought electricity of four alternative investments in heat and power production technologies.
It is seen that Sold electricity and Bought electricity differ significantly between these extreme investments. Only solar collector and storage reduces the sold electricity compared to the reference, so the solar collector covers most of heat demand in the summer period, reducing the natural gas engine production. Also, the electricity bought for the electrical boiler is reduced for the same reason.
Only heat pump and storage significantly increase bought electricity, and Only PV and Only wind turbine significantly increase the sold electricity.
The analyses presented here show a slight preference for spending the investment sum on wind power rather than on solar collectors and additional thermal storage. Before actual investment decisions, further investigations must cover sensitivity, scenarios, and alternatives. First, results must be analysed for variations in technology costs and energy prices. Secondly, we need to observe the energy transition future we are looking into and how that affects choices and prices. How will the phasing out of natural gas engines affect the system in question – and how will future electricity prices develop when the system transitions? And lastly, only extreme cases were analysed, not mixtures such as wind, heat pump, and storage in a combined solution.
[1] Live data from this plant are shown at www.emd.dk/livedata/energyweb/.
[2] https://doi.org/10.1016/j.energy.2022.124792
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