Balancing energy

The graphic below gives a simple explanation of the way that load frequency control is used.

Fig 1: graphic representation of load frequency control

In the event of a major load fluctuation such as a power station outage or other unpredictable variations in injection and withdrawal in the UCTE grid (European Union for the Co-ordination of Transmission of Electricity), the control area managers' primary reserve is activated; this is available almost immediately. Contributions of reserve capacity are agreed upon control area managers. The amounts are expressed by an agreed formula based on generation output. This system maintains frequency stability.

Primary control is sufficient to stabilise the system where there is only a brief power deficit or surplus. Since the amendment of the legal definition in section 7 item 58 Elektrizitätswirtschafts- und -organisationsgesetz 2010 (Electricity Act) in 2006, primary control has been defined as "an automated reestablishment of the balance between generation and consumption … within no less than 30 seconds following such imbalance". If a longer disturbance occurs secondary control is activated after a defined period (max 30 secs) or simultaneously with the primary control, in order to relieve the burden on the primary reserve and free it to perform the above function. In contrast to primary control, which works at international level to maintain a stable frequency, secondary control balances power deficits and surpluses within control areas. It can take several minutes to restore frequency stability (Part A Technical and Organisational Rules [TOR]).

If the power flow deviation lasts for an extended period (more than 15 minutes) secondary gives way to tertiary control. The latter can also kick in during secondary control already. Tertiary control is activated either automatically or manually. It must be deployed in time to contribute to restoring balance no more than 15 minutes after the start of the deviation in the control area. Restoration of the secondary control range can take up to 15 minutes, whereas tertiary control may continue after this period. The available tertiary control reserve must be at least as large as the capacity of the largest power station unit in the control area.

The reason for the existence of the different control mechanisms is that, although the few power stations that are capable of adjusting output quickly enough for primary control could maintain system stability on their own, this would be prohibitively expensive. The number of power plants that meet the requirements for secondary control is greater, but still not large (injection: storage, gas turbine and other fast-reacting power stations). Many power stations are capable of contributing to tertiary control.

Responsibilities

The transmission system operators, in their capacity as control area managers, are responsible for system stability. They perform this task by means of load frequency control (section 7 item 60 Electricity Act), which is made up as follows (section 23 para 2 item 1 refers to the UCTE rules, which are also set out in Part A TOR):

• Primary control;
• Secondary control;
• Tertiary control.

Load frequency control gives rise to costs, as the control power and the provision of control reserve must be paid for. The procurement of both is the responsibility of the control area manager, and the clearing and settlement agent. Regardless of whether procurement is market-based, monopolistic or a mixture of the two, the control area manager and clearing and settlement agent pass on the costs.

Cost allocation

Section 68 para 1 Electricity Act provides for the control area manager to bill the primary control costs to generators with a capacity of over 5 MW. The costs are allocated in proportion to annual output.

In the case of secondary control there are charges both for the provision of control reserve and for the supply of control power. The cost of maintaining secondary control reserve is covered by the charge for system services, which is directly billed to the generators (section 8 Systemnutzungstarifeverordnung [System Charges Order] 2006). This is justified by the argument that the other components of the system charges are borne by the withdrawers, so that it is fair for part of the cost burden to fall on the generators. Section 8 subsection 2 System Charges Order 2006 limited the group of generators subject to these charges by introducing a non-technical threshold of 1 MW, subsequently raised to 5 MW by the 2006 System Charges Order (Amendment) Order 2009. The energy costs (control power) arising from secondary control are passed on to the balancing group representatives.

The power used for tertiary control is billed to the balancing group representatives. The provision of control reserve is assured by a market maker (weekly tenders of standby capacity).

Distinction between balancing energy and control power

Control power and balancing energy have the same purpose — that of balancing generation and consumption. A deviation from forecast supply or demand in a balancing group, e.g. as a result of an outage, gives rise to balancing energy (section 7 item 3 Electricity Act). The net balancing energy in all the balancing groups in a control area is the control power demand that the control area manager must meet. The total quantity of balancing energy may be many times the control power, as the balancing groups' needs may offset each other.

Put simply:

• Control power is the deviation from forecast in a control area;
• Balancing energy is the deviation from forecast in a balancing group.

The balancing energy used is invoiced to the balancing groups on the basis of the quantities recorded and the costs calculated for control power. The manner in which these costs are passed on to suppliers and consumers is a matter for the market players.