ABT has been under discussion since 1994 when M/s ECC, an ADB consultant, first supported it. GOI constituted a National Task Force in February 1995. It had ten meetings till end 1998 where all the related issues were discussed. A draft notification was prepared for issue by government. With effect from May 15,1999 the jurisdiction was vested in the CERC. Papers were sent to the Commission in June 1999 by the MOP. The proceedings were held in the Commission from July 26 to 28, 1999. The ABT order dated January 4, 2000 of the Commission departs significantly from the draft notification as also from the prevailing tariff design.

Why ABT?

1. India plans to have an integrated National Grid. This will assist in meeting demand with the least cost supply. Five Regional grids already exist. Some linkages between Regions are also in place.

1. The five Regional grids work at vastly varying operational parameters today. Frequency level is one such operational parameter. The target frequency prescribed by the Indian Electricity Rules is 50 Hz
   
2. Integrated grid operations require the normalisation of frequency across all five Regions. The alternative is to insulate each Regional Grid by Back to Back HVDC links. This is an expensive option. Normalisation of frequency requires proactive load management by beneficiaries and despatch discipline by generators.
   
3. There is currently no formal system of financial incentives to promote grid discipline.
   
4. The ABT provides this mechanism.

2. Chronic surpluses in the East and shortages in the South, have resulted in sustained functioning of these grids at frequencies which are far beyond even the normal band, liberally defined by the IEGC as frequency variation within 49.5 to 50.3 Hz

1. Continued functioning at non-standard frequency results in long-term damages to both generation and end use equipment This is a “hidden cost” which is borne by the customer in the long term.
   
2. The ABT will induce corrections in the prevailing frequency to bring it within the permissible band.

3. Frequent fluctuations in frequency caused by short-term variations in the demand supply gap due to the tripping of load or outage of a generator or a transmission line impose substantial costs on generators and consumers.

1. The ABT will address this problem by inducing grid discipline.

4. Economic efficiency dictates that least cost power should be despatched in preference to more costly power (merit order despatch). This becomes difficult without a two part tariff for all stations. States tend to compare the total cost of central generators with the variable cost of their own stations, since for them the fixed costs of state level stations are sunk costs. This results in making central generation appear artificially more expensive than state level stations even though on variable cost basis the former may be cheaper.

1. The two-part tariff of the ABT by making the payment of fixed cost a fixed liability of the states converts it into a sunk cost thereby leveling the playing field between central generators and state level plants.

5. Currently beneficiaries are not liable for payment of the fixed cost associated with the share of capacity allocated to them. If a beneficiary decides not to draw any energy he can escape payment of the fixed charge, which then gets paid by the person drawing energy. This is unfair since it increases the cost of energy even for those beneficiaries who may be drawing energy within their entitlements.

1. The two-part tariff of the ABT assures that each beneficiary will be liable for payment of the fixed cost associated with its share of allocated generation capacity.

6. Currently generators have a perverse financial incentive to go on generating even when there may be no demand. This results in high frequency in the grid as is endemic in the East

1. The ABT will discourage such behaviour by pricing generation outside the schedule in relation to the prevailing frequency.

What Is ABT?

• It is a performance-based tariff for the supply of electricity by generators owned and controlled by the central government
  
• It is also a new system of scheduling and despatch, which requires both generators and beneficiaries to commit to day-ahead schedules.
  
• It is a system of rewards and penalties seeking to enforce day ahead pre-committed schedules, though variations are permitted if notified One and one half hours in advance.
  
• The order emphasises prompt payment of dues. Non-payment of prescribed charges will be liable for appropriate action under sections 44 and 45 of the ERC Act.

It has three parts:

- A fixed charge (FC) payable every month by each beneficiary to the generator for making capacity available for use. The FC is not the same for each beneficiary. It varies with the share of a beneficiary in a generators capacity. The FC, payable by each beneficiary, will also vary with the level of availability achieved by a generator.

- In the case of thermal stations like those of NLC, where the fixed charge has not already been defined separately by GOI notification, it will comprise interest on loan, depreciation, O&M expenses, ROE, Income Tax and Interest on working capital.

- In the case of hydro stations it will be the residual cost after deducting the variable cost calculated as being 90% of the lowest variable cost of thermal stations in a region.

- An energy charge (defined as per the prevailing operational cost norms) per kwh of energy supplied as per a pre-committed schedule of supply drawn upon a daily basis.

- A charge for Unscheduled Interchange (UI charge) for the supply and consumption of energy in variation from the pre-committed daily schedule. This charge varies inversely with the system frequency prevailing at the time of supply/consumption. Hence it reflects the marginal value of energy at the time of supply.

How is ABT different from normal proceedings to determine generation tariff?

1. The ABT proceeding has not attempted to consider most of the cost drivers like ROE, Operational Costs, depreciation rate, composition of the Rate Base, capital structure etc. Proceedings to redefine these norms are being held separately. Hence the ABT proceedings have been concerned more with tariff design rather than definition of tariff norms or determination of tariff levels.

2. It's incidence is a function not only of the behaviour of a generator but also of the behaviour of a beneficiary. Disciplined beneficiaries and generators stand to gain. Undisciplined beneficiaries and generators stand to lose.

Broad features of ABT design.

1. It implements the long held view that electricity tariffs should be two-part comprising of a fixed charge and a separate energy charge.
   
2. 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 NLC.
   
3. Misdeclaration of availability entails severe penalties.
   
4. 4. It rationalises the relationship between availability level and recovery of fixed cost.
   The draft notification provided for recovery of (annual fixed costs minus ROE) at 30% availability and recovery of ROE on pro-rata basis between 30% and 70% availability. This order provides for payment of capacity charges between 0% and target availability (as indicated in item 2 above) on pro-rata basis.
   
5. The draft notification had provided for payment of capacity charges for prolonged outages. This order disallows such payments.
   
6. It delinks the earning of incentive from availability and links it instead to the actual achievement of generation. Hence incentives will be earned by generators only where there is a genuine demand for additional energy generation unlike the prevailing situation, or the proposed draft received from the GOI, under which it is earned purely because the generator is available.
   
7. Draft notification linked incentives to equity. This order preserves the status quo of one paise per kwh per each 1% increase in PLF above target availability.
   
8. It increases the minimum performance criterion for the earning of an incentive from 68.5% deemed PLF at present to 80% (85% after one year) for all thermal stations, 85% for Hydro and 77% (82% after one year) for NLC.
   
9. It introduces severe financial penalties for grid indiscipline along with significant rewards for behaviour, which enforces grid discipline for both generators as well as beneficiaries.
   
10. The order permits market pricing for the trading of surplus energy by beneficiaries and generators.
    
11. 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.
    
12. It will be implemented in stages from April 1,2000 starting from the South. The new norm for incentive will however be applicable from this date for all central stations. In the case of NPC, GOI to decide applicability of the order.

COMPARISON OF EXISTING TARIFF SYSTEM AND AVAILABILITY BASED TARIFF