The costs of managing the Spanish Electricity System in 2018

Introduction

In an increasingly electrified society, it becomes crucial to understand the cost of consuming electrical energy. This cost can be divided into four main groups: market purchase, transportation, distribution and other regulated costs and taxes. In this article we will focus on analyzing mainly the costs associated with transmission and grid management and, therefore, directly or indirectly related to the Transporter System Operator (TSO) Red Eléctrica de España (REE onwards).

With a network of more than 40000 km of high voltage lines, REE is exclusively responsible for the operation of the electricity system and the transport of electricity. Any generator or consumer wishing to connect to the grid must initiate a relationship with REE. Maintaining security of supply and developing a reliable network is costly and entails a series of costs that the operator passes on to all the agents involved under different mechanisms defined in the corresponding Official State Gazette (BOE). Without going into detail on each concept, we will describe what each of the electricity costs that REE passes on to final consumers consists of and we will classify them by their magnitude during the year 2018.

In order to make it easier for readers less familiar with the functioning of the electricity market to understand, it is recommended that they consult the article “Fundamentals of the Iberian electricity market” (Spanish), accessible from our blog here.

System costs

The first cost we are referring to are the imbalance costs (DSV), already commented in deep detail in a previous post on our blog (link). This cost is generated by a difference between the energy initially programmed by a consumer and the energy finally measured in power plant busbars. This difference means that the operator must manage this difference to ensure a correct demand-generation balance. Together with this cost the concept of Balance Deviations (EXD) is also managed by the TSO, which basically represents the allocation of the surplus or deficit of the balance derived from the valuation of the system’s own deviations.

The following costs are related to the operator’s efforts to solve technical restrictions. The PBF restrictions (RT3) refer to the cost of adjusting the Base Daily Operating Programme (PBF) due to technical limitations in the system that prevent the delivery and transport of electrical energy. In this regard, the consumer must also pay for the operator’s management of real-time restrictions (RT6), which also arises from the need to constantly adjust the programming units’ programs according to the technical limitations of the system in real time.

On the other hand, in order to ensure that demand is always covered by generation power, a reserve of additional power to be increased (PS3) is set in motion. This reserve ensures a higher available capacity if it is necessary to activate it in the event of an anomalous and unforeseen situation. In line with ensuring enough capacity to cover electricity demand, the Payments for capacity (PC3) are also created, which must be complied with by retailers and direct consumers. These payments for capacity, which are regulated, arose as incentives for investment in combined cycle power plants that would provide the electricity system with a safe power capacity.

It is also necessary for electricity consumers to cover the cost of Secondary Band (BS3), a cost that arises from the need for the operator to have a rapid action mechanism to correct sudden alterations in the system that cause deviations in the frequency of the system (and therefore in its stability). In line with the commitments that a participating agent acquires in the different adjustment systems previously mentioned, the Energy Balance Failure (BALX) was created, which encompasses the costs associated with the failure to comply with the net assignment to rise or fall of energy for the management of deviations and/or tertiary.

In relation to international exchanges, two concepts arise which REE passes on to the participants in the system. The Exchange of Support with Price (IN3) represents the additional cost of exchanges of support with established price (as much of import as of export). That is, it is derived from the extra costs of energy exchanges with other border systems through the interconnections that the System Operator has needed to set up. The concept of Support Exchange Without Price or Account Balance (IN7) reflects the hourly compensation for support exchanges carried out by REE through the return of energy between systems.

Another operating cost of the electrical system is the so-called Power Factor Control (PFC), which arises from the need to design control measures for the integration of new technologies into the grid, mainly renewable energies which, due to their technical characteristics, have a greater risk of destabilizing the system.

Finally, the Interruptibility Service (SI3). This service, regulated like PC3, represents the cost of the power offered by large consumers, who, at the request of the System Operator, must cease or reduce their demand to guarantee the stability of the system. This service has provoked much controversy due to the high cost to consumers and its dubious usefulness since in recent years it has been activated on just a few occasions.

It should be stressed once again that both the Interruptibility Service and Capacity Payments are regulated costs, which fixed costs by the government, while the other costs are included within what it calls Adjustment Services and many of them are fixed in open markets governed by the laws of supply and demand.

Costs in 2018

Red Eléctrica publishes all the costs in its successive settlements. Although the final costs for 2018 will not be known until the end of 2019 in the closure settlement, we will now advance the values that these concepts have in one of the partial settlements of REE (C2). The reader should therefore understand that these values approximate the final one and in no case should they be taken as definitive.

Table 1.- Average Costs in €/MWh

In general, there was a decrease in the management costs of the Spanish electricity system in 2018 with respect to the previous year. However, this decrease is completely overshadowed by the rise in the average OMIE market price, which rose from an average value of approximately €53 in 2017 to €58 in 2018, increasing by 9%. Therefore, although the Adjustment Services and the Interruptibility System have been reduced to around 1.3% and 40% respectively, it will be difficult for the end consumer to enjoy this improvement.

The highest cost of the Adjustment Services derives from maintaining the balance between generation and demand mainly through the resolution of PBF restrictions and secondary regulation. Also noteworthy are the high costs of capacity payments and interruptibility services which, despite the reductions with respect to 2017, maintain a considerable impact on the final consumer’s bill. For example, a direct consumer on a 6.x tariff whose annual consumption is around 35 GWh may end up paying more than 35,000€ per year for each of the above concepts (the prices shown are average and, depending on the characteristics of the direct consumer, may vary considerably).

We have seen that, without considering taxes and the spot market, the management costs of the system amount to values of around 6 or 7€/MWh. Adding this cost to the already high price of the spot electricity market and the corresponding taxes means that we have excessively high final electricity prices and we should never lose sight of the objective of reducing these also this management costs if we want to have a competitive electricity system.

More information regarding system costs can be found in the latest document on 2018 System Adjustment Services published by REE at this link.