Availability Based Tariff
Availability Based Tariff
Electricity Act 2003 and Availability Based Tariff (ABT) have been the most momentous and authoritative steps taken to instill practicality in the industry. The ABT order became a part of the system on January 4, 2000 and has been implemented in all the regional grids of India for improving grid discipline by frequency dependent pricing. Currently, it is limited to short-term energy transactions between the beneficiary states and Central generating stations without the need for negotiations on price or quantum in real time.
Need for ABT
Prior to the introduction of Availability Based Tariff, the regional grids were operating in a very undisciplined and unsystematic manner. There were large deviations in frequency from the rated frequency of 50 cycles per second (Hz) leading to low and high frequency situations. The low frequency situations resulted due to a higher consumer load than the total generation available in the grid and high frequency resulted as a result of insufficient backing down of generation when the total consumer load fell during off-peak hours. This continued functioning at non-standard frequency resulted in long-term damages to both generation and end use equipment resulting in hidden costs that ultimately had to be borne by the end consumers.
Apart from this, the earlier regime did not provide any incentive for either backing down generation during off-peak hours or for reducing consumer load/enhancing generation during peak-load hours. The reasons for the same were that the full fixed charges were payable at achieving a PLF of 68.49% and an incentive was payable for each unit of electricity generated above this PLF which made it profitable to go on generating at a high level even when the consumer demand had come down. Further, if a beneficiary decided not to draw any energy, he could escape payment of the fixed charges, which were paid by the person drawing energy. Also, there was no provision of penalizing any consumer who was overdrawing power. The new increased cost of electricity was covered by other beneficiaries.
What is ABT?
The term Availability Based Tariff, particularly in the Indian context, stands for a rational tariff structure for power supply from generating stations, on an availability basis. It is a performance based tariff structure for the supply of electricity by generators owned and controlled by the central government that provides for a new system of scheduling and dispatch which mandates the generators and beneficiaries to commit to day ahead schedules through a system of reward and penalty. The defaulters are liable to pay a penalty which entails payment of prescribed charges, non-payment of which will call for appropriate action under sections 44 and 45 of the ERC Act. The most significant aspect of ABT is the splitting of the existing rigid energy charges into three components viz. capacity charges/ fixed charges, variable charges and a third charge viz. the unscheduled interchange (UI) charges.
- Capacity charges/ fixed charges: The fixed charge (FC) in case of ABT is payable every month by each beneficiary to the generator for making generation capacity available for use. However, it is not the same for each beneficiary and varies with the share of a beneficiary in a generators capacity. It also vary with the level of availability achieved by a generator. As per the ABT mechanism, FCs excluding RoE is payable on a proportionate basis for 30% availability. Pro-rated RoE is payable from 30- 70% availability and beyond this level, an incentive is payable to generating station at 0.4% of equity for each percentage increase in availability in the 70- 85% range. Thereafter the incentive falls to 0.3% in order to discourage generating facility from overloading the units at the cost of maintenance and equipment life. It is a function of ex-bus MW capability of the power plant for the day declared in advance, paid by beneficiaries proportionate to their respective % share in the plant.
- Variable charges : It is the energy charge per kwh of energy supplied as per a pre-committed schedule of supply drawn upon a daily basis by LDCs. Under the earlier regime, fixed and variable charges were bundled together and payable in proportion to the actual energy drawn by the consumer. The splitting under the new regime will promote power trading which is discussed later on in this paper. Energy charges are calculated as:
- Energy Charge = MWh for the day as per drawl schedule for the beneficiary finalized in advance x Energy Charge rate for the plant (OR) Energy Charge = Scheduled Energy X Energy Rate
- Unscheduled Interchange: Under the earlier regime, no penalty was applicable for deviation from generating/drawal schedule by an entity. An attempt has been made to do away with this drawback under the ABT regime through introduction of UI charge. Here, for any withdrawal of power other than the schedule, the beneficiary has to pay an unscheduled interchange (UI) charge for deviation from the day ahead schedule which is linked to the frequency. The relationship between the UI rate and grid frequency, for the inter-state system, is specified by Central Electricity Regulatory Commission. UI charges are calculated using the following relationship:
- A generator generates more/less than the schedule causing grid frequency to deviate upwards/ downwards.
- Beneficiary draws more/ less than the schedule causing grid frequency to deviate downwards/upwards.
Participants in Inter-state ABT
- Interstate generating station (ISGS) from generating side
- SEB/ State/ Union territory from load side
- Other regions for import and export
- Regional grid for transmission
How ABT Promotes Trading?
The splitting up of fixed charges and variable charges is said to encourage trading in power. For example, a generating capacity of a central coal fired power plant is 1000 MW and has three beneficiaries states- A, B and C with allocated shares of 30%, 30% and 40 % respectively. If the plant declares its day ahead scheduled generating capacity as 900 MW to the RLDC , the states then get 270, 270 and 360 MW electricity allocation respectively. Assuming states A and B request for entire share during the next 24 hrs and C applies for 360 MW only during day time and 200 MW during night, the generator has three options:
- Back down the station during off-peak hours, i.e., generate power only according to the schedule given by RLDC by combining the requisition of the three states, or
- Find a buyer (other than State C) for the above off-peak surplus and accordingly generate power for all the buyers viz. existing buyers A, B and C and the new buyer. As long as the energy sale rate agreed upon is higher than the fuel cost per kWh of the station, it would be financially beneficial for the station to enter into such a deal. It would also reduce the technical problems associated with backing down the station and improve the station’s efficiency. If time permits, the Central generating station may look around to find a party which would pay the highest rate and maximize its profit.
- Instead of selling the off-peak surplus power through a bilateral agreement, the station may accept the schedule given by the RLDC, but generate power to its full capability of 900 MW even during off-peak hours. The result would be an over-supply of 160 MW (as a deviation from schedule), for which the station would get paid from the regional UI pool account at the prevailing UI rate. In effect, it would be a sale to the regional pool, and would make financial sense as long as the prevailing UI rate is higher than the fuel cost per kWh of the station.
Trading opportunity for State C
Here, State C also has three options:
- Procure power from the station only as per its requirement.
- Requisition full entitlement of 360 MW from the central station for the entire 24 hour period, find a buyer for the off-peak surplus and schedule a bilateral sale. This would make sense as long as the sale rate per kWh is more than the energy charge rate of the central station.
- Requisition the full entitlement for the next 24 hrs and draw power only as per its requirement. In this case the state would get payment against the prevailing UI rates. If the grid frequency is on the lower side then the UI rates would be higher and the state shall profit from under drawing. In case the frequency rises and the UI rates fall below the energy charges, the state should reduce its requisition and stop under drawing. The state has to make sure that the UI charges during the off peak hours remain higher than the energy charges of the Central generating station.
Salient features of ABT w.e.f 2000
- It implements the long held view that electricity tariffs should be two-part comprising of a fixed charge and a separate energy charge.
- It increases the target availability level at which generators will be able to recover their fixed costs and RoE from 62.79% deemed PLF at present to 80% (85% after one year) for all thermal stations, 85% for hydro in the first year and 77% (82% after one year) for Neyvelli Lignite Corporation (NLC).
- Under the ABT regime, the Indian Electricity Grid Code (IEGC) has fixed the grid operating frequency variation within 49.5 to 50.3 Hz which helps to reduce the gap between supply and demand by scheduling of power supply in every 15 minutes block. Each day has 96 such blocks.
- Mis-declaration of incorrect schedules entails severe penalty.
- The order permits market pricing for the trading of surplus energy by beneficiaries and generators.
- The order urges the GoI to allocate the unallocated capacity a month in advance so that beneficiaries know their exact share in capacity in advance and can take steps to trade surplus power.
- In the earlier regime, the beneficiary had to pay charges even for prolonged outages. The availability tariff rules out any such payments on account of outages.
Benefits of ABT
- Rational recovery of fixed costs from beneficiaries.
- It provides a fiscal mechanism to encourage high availability of plants to meet the peak demand.
- Merit order and most economic generation is encouraged as a result of which low cost power gets a priority in generation.
- Rationalization of the contractual demand between the SEB’s and the generators.
- Fiscal disincentives for over drawl during low frequency conditions and under drawl during high frequency conditions.
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