Getting Prices for Prosumers Right? Incentivizing Investment and Operation of Small-scale PV-Battery Storage Systems Through Prices, Charges and Levies

Abstract

We assess how the design of retail prices, grid fees and levies for household prosumers affects the attractiveness and resulting operation of small-scale photovoltaic battery storage systems (PVBSS), using a detailed modeling approach applied to a case study of six households in Germany. The selected pricing schemes and reform proposals are evaluated regarding the investment attractiveness for the prosumer and the impact on system-oriented operation, considering both market and grid integration. We show that the current business models for PV and PVBSS are only exist because they are based on avoiding the need to purchase electricity from the grid and thus avoiding paying taxes and levies on consumed electricity. Introducing time-variable pricing schemes or price components increase the value of PVBSS for the customer and the market, but lead to a less grid-friendly operation. It is shown that the term “system-oriented operation” should be defined carefully, since under the analyzed incentives, the two objectives included in system-oriented operation (market and grid integration) do not necessarily go hand in hand, sometimes even contradicting one another. Both the tariff design and the design of single tariff components have a considerable impact on the attractiveness and the resulting system integration of PVBSS and should be evaluated thoroughly to avoid unintended outcomes.

Zusammenfassung

Es wird untersucht, wie die Ausgestaltung der Endkundenpreise, der Netzentgelte und der EEG-Umlage den Betrieb und die Rentabilität von kleinen PV-Batteriesystemen (PVBSS) beeinflussen. Dazu wird eine detaillierte Modellierung einer Fallstudie mit sechs unterschiedlichen Haushalten durchgeführt. Die betrachteten Preismodelle und Reformvorschläge werden hinsichtlich ihrer Attraktivität für Prosumer sowie ihres Effekts auf eine systemdienlichen Betrieb bewertet, wobei systemdienlich sowohl die Markt- als auch die Netzintegration umfasst. Es wird gezeigt, dass die derzeit existierenden Geschäftsmodelle für PV und PVBSS auf der Vermeidung von Netzbezug und damit der Einsparung von Abgaben und Steuern beruhen. Die Einführung von zeitvariablen Strompreisen oder Preisbestandteilen erhöhen den Wert des PVBSS für den Prosumer und den Markt, führen dabei aber zu einer weniger netzdienlichen Betriebsweise. Es wird gezeigt, dass der Begriff „Systemdienlichkeit“ sorgfältig definiert werden sollte, da Markt- und Netzintegration nicht notwendigerweise Hand in Hand gehen, sodass ein Anreizsignal nicht notwendigerweise dazu führt, dass beide Ziele erreicht werden. Die Ausgestaltung der Strompreise, insbesondere deren Zeitvariabilität, sowie einzelner Preisbestandteile haben einen erheblichen Einfluss auf die Attraktivität und die erreichbare Systemintegration von PVBSS und sollten daher zur Vermeidung unerwünschter Effekte sorgfältig evaluiert werden.

Appendix

1.1 Cost Components of the Different Price Scenarios

 

Table 6 Cost components for the purchase prices in the three basic scenarios

Table 7 Compensation Schemes for electricity feed-in

1.2 Annual Electricity Cost for all Households

 

Table 8 Annual electricity cost normalized to annual cost at CEP without any own generation in Euro

Table 9 Annual electricity costs for all households with a PV system normalized to the annual cost at CEP without any own generation in Euro

Table 10 Annual electricity cost for all households with a PVBSS normalized to the annual cost at CEP without any own generation in Euro

1.3 Market Value for all Households

 

Table 11 Cost changes due to storage operation of all examined PVBSS—household combinations in €/MWh

1.4 Peak Loads for all Households for PV only and PVBSS

 

Table 12 Peak loads of all households using a PV system for self-consumption in kW

Table 13 Peak loads of all households using a PVBSS for self-consumption in kW

1.5 System Peak Feed-in to the Superior Grid for all Scenarios

For the considered households, the peak values for the electricity feed-in considerably exceed the peak load values. Thus, the analogous factor for the coincidence of feed-in is determined and displayed in Fig. 9. It can be seen that for the feed-in, the coincidence factor significantly differs from the load coincidence factor. There is less variation in the temporal distribution of electricity feed-in than in peak load, leading to high coincidence factors in all scenarios except the combined scenarios. The feed-in seems mainly driven by excess PV generation as it shows such a high coincidence in most scenarios.

In the Spot scenario, the system peak feed-in is the highest feed-in of all scenarios. Due to the completely spot market-driven operation and low withdrawal prices, there is no incentive to optimize self-consumption and to reduce the amount of electricity fed into the grid. Additionally to the high peak feed-in, the coincidence factor for the feed-in is as high as in the other scenarios, making it the most stressful scenario for the grid infrastructure.

Both combined scenarios are the only scenarios with lower coincidence factors. While the peak feed-in in the CEP_combined scenario is similar to the majority of scenarios, RTP_combined shows a considerably higher peak feed-in. Increasing relative temporal fluctuations and reducing the gap between withdrawal and feed-in price in the combined scenarios seems to favor a higher temporal coincidence in the feed-in. Hence, the most system-oriented scenario in this regard is the CEP_combined scenario. However, the higher relative price fluctuations in the RTP_combined scenario increase the peak feed-in and thus the stress in the grid. Combined with the lower coincidence factor, this indicates that individual peak loads are higher than in the other scenarios and that a higher feed-in takes place in more time-steps than in the other scenarios. This considerably increases the stress on the grid infrastructure and thus the need for reinforcements in the long-term. Higher relative fluctuations in the withdrawal price combined with a varying price signal for the feed-in hence lead to a remarkably worse result than a varying withdrawal price combined with a flat feed-in price in regard to grid load.

Fig. 9

Peak feed-in into the superior grid and the corresponding coincidence factor for the system of six households

Since the absolute values for feed-in are higher than for the system load, the feed-in would be the determining factor in grid dimensioning. Since it is argued that more and more grid congestions will occur in the distribution grid and the need for reinforcements will increase (Agricola et al. 2012), this should be considered as a systemic aspect for the evaluation of the regulatory reform proposals and their effects alongside with the indicators for peak demand. The relevance of the local feed-in is also indicated by the grid cost estimation, given in Table 16, as the costs for feed-in into the superior grid are two to seven times higher than the grid usage cost for the demand from the superior grid.

1.6 Cost Estimation for Local Electricity Feed-in and Withdrawal

To estimate the grid cost for the individual households load and feed-in, the following calculation was done. To derive the pure LV grid tariff, the MV tariff multiplied with the coincidence factor of the considered system of 0.37 was subtracted from the gross LV tariff. This gives the following tariff values:

$$\textit{Power}\,\textit{price}=17.59\,\text{\EUR} /kW-0.37\cdot 19.07\,\text{\EUR} /kW=10.50\,\text{\EUR} /kW$$

$$\textit{Energy}\,\textit{Price}=0.0451\,\text{\EUR} /kWh-0.37\cdot 0.0391\,\text{\EUR} /kWh=0.0311\,\text{\EUR} /kWh$$

The household peak load/feed-in was then valued with the power price of 10.50 €/kW and the sum of household grid withdrawal/feed-in valued with the determined energy price of 0.0311 €/kWh. The results are displayed in Tables 14 and 15. The corresponding value for the system load to the superior grid level, displayed in Table 16 is valued at the LV/MV tariff of 19.07 €/kW and 0.0391 €/kWh.

Table 14 Net grid cost for electricity withdrawal^a

Table 15 Net grid cost for electricity feed-in ^a

Table 16 Summary of economic values of all indicators in absolute numbers as the basis for Table 5