Base case Present situation

This subsection is aimed at developing a simulation case that represents the present situation in Norway. The subsequently presented future scenarios will then expand on this case. Hence, the main objective of the “Base case” is to be a benchmark for future reference. For now, only subtle changes are made to the data set; the more substantial changes will be introduced in the future cases. Specifically, firm demand level is decreased somewhat, along with the addition of a modest amount of Norwegian wind power. Note that PHES is not considered for this case, even as the regression analysis showed that our modelled system had somewhat less pump usage than the Norwegian system. This is because most of the current pumping in the Norwegian power system is assumed to be seasonal pumping in specialized pump stations, not reversible pump stations.

All cases are run with the same run settings. For the run settings used in this case and the other, refer to sections 4.1.1 and 4.3.1 for EMPS and ProdMarket, respectively. Each model’s respective settings are also listed in Appendix A and B.

Picking up the thread from Chapter 2, the data set is to be tuned towards the key

characteristics of the Norwegian power system as presented there. This time, the regression analysis results from Appendix C are scaled down and used to quantify the wanted power mix in our Base case:

Table 12 - Wanted energy mix, Norway. BaseCase. Energy source % of prod. TWh GWh

Hydro 95,29 8,9 8900

Thermal 3,36 0,31 314

Wind 1,36 0,13 127

Total 100,01 9,34 9340

All data in Table 12, above, are scaled based on our data set’s approximate yearly hydro production, 8.9 TWh. Note that the rest of the table is calculated to a higher degree of accuracy than this number, which is limited to only two significant digits. Scientifically, this is not strictly correct, but it can be allowed as long as the results are not taken too literally. And as has been commented numerous times already, we are already aware that simulation results, no matter how good, are not perfect representations of the real world. There is also a considerable innate inaccuracy in the regression results. All aspects of the Norwegian power system are massively affected by the yearly inflow variations that control the hydropower production. And the yearly variations are considerable; take the recorded hydropower production in the years 2011 through 2013, for example: Table 29, Appendix C, shows how production increased by more than 21 TWh from 122 TWh in 2011 to 143 TWh the following year. In 2013, production was back down to a more average level of 129 TWh. Hence, the regression analysis has some uncertainty. To illustrate: The analysis returned 130 TWh as an approximate of the true mean inflow in 2014, and a total system production of about

138 TWh. But the numbers from the production mix analysis would mean that the mean hydropower production in 2014 was 0.9529 ∙ 138 ≈ 132 ≠ 130. We will stick with the number requiring the least amount of calculation, so 130 TWh is kept as an estimate.

Out of the three energy sources specified in Table 12, only one is given directly as input to the simulation models: Wind. So this is what we will focus on quantifying. Hydro production is also fairly constant (at least it should be in in the long run) for a given set of inflow levels and production units. The amount of thermal production is not considered explicitly, but is

affected by the other two. As discussed in the previous sections, thermal power and other variable power is handled as price-dependant power, controlled by the simulated power price. As the models search for cost minimization, the amount of thermal power bought is in

controlled by the energy balance of the system. In this respect, the energy balance is the balance between the free renewables, hydro and wind power, and firm demand. So demand is the second size which we will discuss.

Compared to the future cases then, the following aspects is not considered relevant in the Base case:

 Hydropower production capacity  Pumped hydroelectric storage (PHES)

 Size of interconnectors to UK and Germany; UK offshore wind, German PV. The first is considered not relevant because our system’s balance of production capacity and storage is based on actual production plants. Assuming that the three studied waterways are somewhat representative, the relation should be realistic for Norway as a whole as well. As for the other two aspects, both is present in the current power system. One could say that due to their limited penetration, they are negligible, but there is also another rationale for why they need not be relevant for the Base case: The future scenarios are mainly focused towards highlighting the changes compared to the Base case. So it is not crucial that the current impacts are non-existing, as long as the changes introduced in the future simulation cases are based on actual changes in the power system. And there is little doubt that the planned German and British HVDC interconnectors will affect the power system on both sides. Norwegian wind power

A wind series is added to the data set, as described in the previous section. As for the amount of wind energy added, note that we will stick to the production mix numbers from Table 12, as these all cover 2014. We will not use the 2015-figure from our discussion of wind in Subsection 2.3.1. So the wind series is scaled to contribute 127 GWh of energy per year, as per Table 12 above. Scaling up to the Norwegian system size, this means that we have estimated the 2014 mean wind energy production in Norway to 0.127[TWh] ∙130

8.9 =

1.89 TWh (as opposed to the 2015 figure of 2.22 TWh). Just over 0.1 TWh is relatively little compared to the system’s estimated hydro production of 8.9 TWh. It is plausible, however, that there are years where wind power could contribute significantly more, or less, than this level. Analysing all 50 years of wind input used, the largest and smallest observed power contribution is 155 GWh and 101 GWh, respectively. So the 50-year variation lies within

roughly ± 20 percent. This does not contribute a whole lot at this stage, but could be relevant as more wind is added to the power system.

The equivalent installed wind capacity can only be estimated from the energy production numbers based on estimated usage times. Using the average usage time in Norway in a normal year (as per 2015), from Table 2, page 12, the calculation is done as follows (for Norway and for the modelled system, respectively):

𝑃_{𝑤𝑖𝑛𝑑,𝑒𝑠𝑡𝑖𝑚𝑎𝑡𝑒,2014}𝑁𝑜𝑟𝑤𝑎𝑦 = 𝑊𝑦𝑒𝑎𝑟𝑙𝑦 𝑇_{𝑈𝑠𝑎𝑔𝑒}[h]= 106[MWh_TWh] ∙ 1.89[TWh] 2692[h] = 702[MW] 𝑃_{𝑤𝑖𝑛𝑑,𝑒𝑠𝑡𝑖𝑚𝑎𝑡𝑒,𝐵𝑎𝑠𝑒𝑐𝑎𝑠𝑒}𝑚𝑜𝑑𝑒𝑙 =1000 ∙ 127[GWh] 2692[h] = 47.2[MW]

Compared to the installed hydropower generating capacity of 1965 MW, the total wind production constitutes a mere 2.5%. It is once again clear that wind energy really is a minor factor in the current Norwegian power system.

Demand

The demand level is to be adjusted to match the current Norwegian demand level, as compared to the size of its hydropower production. As previously mentioned, hydro production is used as the scaling factor as this is the easiest to compare between our model and the Norwegian power system. From the introduction to Chapter 2 we already know that, based on the regression results, the Norwegian hydropower production roughly matches the demand level in a normal inflow year: Hydropower production was estimated to 130 TWh, so was the demand level. In essence, this is what is sought after for the modelled system as well. Due to a minor calculation error during implementation, however, the actual power balance of the Base case is as follows: Roughly 8.9 TWh of hydropower and (exactly) 0.127 TWh of wind power is to supply 8.83 TWh of load. In this respect, the actual load is 0.07 TWh, or 70 GWh too low, to maintain an energy balance between hydropower and demand levels. The error is, however, negligible. Moreover, it is plausible to be within the array of possible values for the actual hydropower production in our system (this entity is, as previously discussed, a result of simulations, and as such varies somewhat between models and between simulation cases). Including the wind power, the modelled system is now at a power surplus just by using renewable power: Hydro and wind power is estimated at a combined output of roughly

In practice, the new load level represents a considerable decrease from the default data set, which, as was discussed in Section 5.1, holds roughly 10.58 TWh of load. 10.58 − 8.83 = 1.75 TWh of load is removed from the data set. The below table shows the new size of the demand contract that where this change is implemented: The firm power demand contract in the “Term” area. In ProdMarket, the change is performed in the “Hode” area.

Table 13 – Size of demand contract “Fastkraftprogno-Term”, Base case. Total amount

(GWh)

Yearly amount (GWh)

Default data set 6300 2100

Base case 1050 350

Difference -5250 -1750

Base case implementation settings are shown in Appendix E. As the Base case is now created, it is time to shift focus towards the future scenarios.