ABT : Meaning, Implementation and Bottlenecks


1.      Background

2.      Introduction

3.      ABT at state level

4.      ABT in deregulated market

5.      Bottlenecks

6.      Recommendation

7.      Conclusion

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.

Ø      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.

Ø      Integrated grid operations require the normalization 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. Normalization of frequency requires proactive load management by beneficiaries and dispatch discipline by generators.

Ø      There is currently no formal system of financial incentives to promote grid discipline.

Ø      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

Ø      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.

Ø      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.

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

4. Economic efficiency dictates that least cost power should be dispatched in preference to more costly power (merit order dispatch). 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.

Ø      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.

Ø      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

Ø      The ABT will discourage such behavior 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 dispatch, 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 behavior of a generator but also of the behavior 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.  It rationalizes 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 behavior, 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.



Sl. No.

Description of Item

Existing System

Draft ABT Proposal

ABT Order


Capacity / Fixed Charge

Annual Fixed Charge (AFC) include :a). Interest on loan
b). Depreciation
c). O&M
d). Return on Equity
e). Income-Tax
f). Interest on Working Capital 

Fixed charges excluding ROE i.e. all other five items of the existing system. ROE treated separately

Capacity charge as per existing system


Basis of recovery

Recovered at 62.79% deemed PLF. 50% AFC at 0% PLF and full recovery at 68.49% deemed PLF.

FC excluding ROE recovered at 30% availability on pro-rata basis between 0% and 30% availability.ROE recovered on pro-rata availability between 30% and 70%

Pro-rata recovery of capacity charge for :i) NTPC stations: Between 0 to 80% availability in the first year and 0 to 85% availability in the second year. ii) NLC Stations Between 0 to 77% availability in the first year and 0 to 82% availability in the second year. iii) NHPC Stations Between 0 to 85% availability in the first year and availability in the second year to be announced by the commission separately. 



Above 68.49% deemed PLF, incentives at 1 paise/KWh for each 1% increase in PLF.

Incentive beyond target availability of 70% is as follows: 70% to 85% - 0.4% of equity for each 1% increase in availability beyond 85%.

1 paise/KWh/each percentage increase in PLF of 80%/ 85% in the first/ second year for NLC and 85% in the first year for NHPC.




Sharing of fixed cost


Based on actual energy drawls


Based on allocated capacity


Based on allocated capacity


Recovery of variable cost

Based on actual energy drawls

Based on Scheduled Energy

Based on Scheduled Energy


Deviations from schedule – UI charges

No penalties for such deviation

Varying between 0 to 360 paise/kwh for the frequency range of 50.5 Hz to 49 Hz

Varying between 0 to 420 paise/kwh for the frequency range of 50.5 Hz to 49 Hz


Norms for tariff determination

GOI Tariff notification

GOI Tariff notification

GOI Tariff notification till such time Commission finalizes its views


Procedure for payment of capacity charge if ABT is introduced in the middle of a financial year

Not applicable

Not specified



Prolonged Outages

Included in item (2) above

Provided for payment of adjusted capacity charges

Does not provide for payment of capacity charges


Marketing of surplus energy

Not applicable

Not specified

Encouraged and will not require commission’s approval


Splitting up of capacity and energy charge for hydro stations.

Capacity charge covered depreciation and interest on loan. Energy covered ROE, income tax, O&M and interest on working capital.

Capacity charge covered depreciation and interest on loan. Energy covered ROE, income tax, O&M and interest on working capital.

Till such commission notifies peak and off-peak energy rates for hydro-stations, primary energy charge would be taken as 90% of the lowest variable charge of the thermal power station in the concerned region. The balance of total charges would be recovered as capacity charges.




Payment of dues to generators


As per agreements


As per agreements


As per orders of the commission



All central generating stations

All central generating stations staggered region wise

i). ABT implementation is staggered region wise. ii) Fixed charge recovery and basis for incentive payments revised from 1st April, 2000.iii) GOI to decide about ABT for automatic power stations.


PLF for incentives during interim period

Not applicable

Not specified

Till the introduction of ABT in other regions and after 1.4.2000, the actual PLF for incentive purposes for NTPC shall be 80% instead of deemed PLF of 68.49%. The PLF in the first year for incentive purposes for NHPC shall be 85%.


Power generation and distribution in India started towards the end of the nineteenth century. However, it was only after our independence in 1947 that the power sector got the required momentum and power generation was identified as a key area for our development. With sustained efforts over the decades, the power generation scenario in India presents a rich and composite mixture of hydro, nuclear, thermal, wind and solar generation. Our installed capacity across the nation well exceeds 100,000 MW, a major share of which is derived from thermal sources (coal/lignite, gas, diesel). Though rich and diverse, the thrust on the power generation sector so far has been on capacity addition and our power sector has not really kept pace with the emerging technologies on the power management front, especially in leveraging the tremendous potential unleashed by information technology (IT). Power generation in India has been largely state owned and like so many other public enterprises donned a traditional outlook and lagged in extracting the benefits offered by digitization and automation owing mainly to a lack of economy centric approach.How well we can manage this vast infrastructure and how close it can keep pace with our increasing energy demands will be a crucial deciding factor in achieving our dream of an annual double digit growth. And in the wake of opportunities thrown up by liberalization and deregulations, the state machinery started mooting on introducing these effects to the power sector also. ABT (Availability Based Tariff) along with the Electricity Act of 2003 is perhaps the most significant and definitive step taken in the Indian power sector so far to bring more efficiency and focus to this vital infrastructure. The fact that the ABT regime was introduced to replace the

Electricity Supplies Act of 1948 would perhaps be an indicator of how overdue reforms were. This document is an attempt to introduce the significant clauses and implications of ABT in a concise manner.


Salient clauses of ABT:


ABT concerns itself with the tariff structure for bulk power and is aimed at bringing about more responsibility and accountability in power generation and consumption through a scheme of incentives and disincentives. As per the notification, ABT is applicable to only central generating stations having more than one SEB/State/Union Territory as its beneficiary. Through this scheme, the CERC (Central Electricity Regulatory Commission) looks forward to improve the quality of power and curtail the following disruptive trends in power sector:


i)          Unacceptably rapid and high frequency deviations (from 50 Hz) causing damage and disruption to large scale industrial consumers.


ii)         Frequent grid disturbances resulting in generators tripping, power outages and power grid disintegration.


This objective is to be brought about by encouraging generators to produce more during peak load hours and curtail generation adequately during off-peak hours on one hand and discouraging consumers from overdrawing on the other hand. The new tariff regime aims at inducing this discipline at the generation and consumption end through adequate monetary incentives. The most significant aspect of ABT is the splitting of the existing monolithic energy charge structure into three components viz. capacity charges (fixed), energy charges (variable) and UI(unscheduled interchange) charges. It is the last component that is expected to bring about the desired grid discipline. Splitting of the tariff into fixed and variable cost components is meant to

act as an incentive for power trading which shall (ideally) conclude in a self-regulating power market regime. It is also expected to promote the concept of ELD (Economic Load Dispatch) among power generators. Let us now look at these tariff components in a bit more detail:


Capacity charges: Fixed charges are payable to the generating station, by the intended beneficiaries of the generation facility (state governments of the region in most cases). In the present tariff regime, capacity charges are payable against the (deemed) PLF (Plant Load Factor) of the station. Full fixed charges are payable at achieving a PLF of 68.49%, and incentive is payable for each unit of electricity generated above this PLF. Under the ABT regime, fixed charges are payable against the availability(declared capacity) of the generating facility. Fixed charges excluding ROE is payable on a prorated basis for 0-30% availability. Prorated ROE is payable from 30-70% availability. Incentive is payable to the generating station for availability beyond 70%. The incentive is pegged at 0.4% of equity for each percent increase in availability in the 70-85% range. Thereafter, the incentive falls to 0.3%. This decrease in incentive after 85% is

aimed at discouraging the generating facility from overloading the units at the cost of

maintenance and equipment life. ABT also contains provision for penalizing the generating utility for over/under declaration of the availability. Fixed charges are payable by the beneficiaries in proportion to the allocated capacity and does not depend on the actual consumption.


Variable charges: Under the present tariff regime, there is no bifurcation between fixed and variable charges. Both are bundled together and payable in proportion to the actual energy drawn by the consumer. As we have seen already, under ABT fixed charges vary with the allocated capacity and has nothing to do with actual energy consumed. In contrast, variable charges are to be paid against the actual energy consumed. This splitting is expected to promote power trading.


UI charges: In the present regime, there is no penalty for deviation from the generating/drawl schedule by an entity. The ABT regime stipulates that UI (Unscheduled Interchange) charges are payable under the following conditions:


a) A generator generates more/less than the schedule causing grid frequency to deviate upwards/downwards


b) A beneficiary draws more/less than the schedule causing grid frequency to deviate downwards/upwards


The penalty imposed varies with the grid condition at the time of the indiscipline and the magnitude increases with the severity of the frequency deviation caused.Apart from this tariff structure, ABT provides for -

a) Implementation in a phased manner.


b) Generation and drawl schedules to be managed in 15 minute blocks (96 blocks per day).


c) Mechanism for communication and co-ordination of the schedules and how rescheduling is to be done in case of a generator/beneficiary being unable to meet the schedule.


d) Role of regional load dispatch centers (RLDC) in managing and coordinating the schedule and managing the schedule in the event of grid disturbances.


e) Methodology for calculating the capabilities for different types of power stations (such as hydro, thermal, nuclear) and for demonstrating the same.


f) Details on metering, accounting, billing and payment of energy charges under the ABT regime.


g) How disputes arising under ABT shall be resolved.


Benefits professed by ABT:


By ushering in the Availability Based Tariff, the CERC looks to bring forth the following positive changes in the Indian power sector:


1. Enhanced grid discipline that will pave the way for higher quality power with more reliability and availability. Grid disturbances and frequency fluctuations as occur in our power system today are serious problems and would be considered unacceptable in any advanced economy. The system of incentives and disincentives allow for penalization of the party responsible for any disruption. This will serve all participating bodies in a power grid to be self-disciplined ensuring quality power supply for all consumers.


2. A more economically viable power scenario that alleviates some of nagging problems of the power sector such as outdated technology, poor management and maintenance, cross subsidization, over staffing, poor accounting practices etc. In breaking the tariff into fixed and variable components and making the fixed charges depend on the declared availability of a plant (subject to demonstration), there is a lot of reason for generators to bring in efficiency. The current diktat at most of the public sector generating station is “to produce as much as you can”. Under the influence of ABT, this will change to produce only as much is needed i.e. supply will need to closely follow the projected demand schedule. Also there is a lot of reason for the generators to usher in the latest technology to ensure that the power generation is predicable, controllable and can be monitored easily. At the consumption end also there is scope for technology investment now in terms of load forecasting and monitoring.


3. Promote competition, efficiency and economy leading to power trading which shall ultimately pave way (step-by-step) for a self-regulating power market. The variable cost component for the energy consumed is the first step for facilitating trading of power. Also, since the fixed charges are now payable based on declared availability rather than actual power consumed, there is a lot of reason for beneficiaries to trade in capacity as well. And this kind of trading will automatically induce competition and efficiency into the power scenario. In fact it is hoped that ABT will prove to be the first step for Indian power industry towards a completely market oriented regime which is self-regulating and does not need the tariffs or other parameters to be regulated externally. Adequate transmission capacity (so that there is no bottleneck in terms of purchase or delivery) is the most important infrastructure requirement to support such a market regime.


4. Introduce and encourage MOD (Merit Order Dispatch) in the Indian power scene. In the current scenario, the generators tend to produce as much as they can irrespective of the demand side of the power equation. Under ABT, generators will need to ramp up and ramp down generation based on the declared generation schedule given by the RLDC (Regional Load Dispatch Center). Thus when the plant (or a cluster of generating stations owned by a single entity) will need to use the power generation combination that will incur the least cost for all loads below the maximum load. This exactly is the formulation of the MOD, which is an optimization problem. MOD is used by modern power plants to save millions of dollars in generating cost every year. Thus introduction of MOD is expected to benefit the power industry greatly.


Concerns on ABT:


While ABT is acknowledged to be a welcome measure to tackle the major problems in our power scenario and is expected to be the welcome step towards a self-regulating market, there are a lot of concerns that need to be addressed by this new system. We will, in this document, concern ourselves only with issues of a technical nature and not with those having political or statutory implications (such as whether a particular clause of ABT is within the jurisdiction of CERC). For information regarding these and detailed information on the clauses of ABT, the reader is referred to the full text of the ABT notification. Some of the important technical concerns to be addressed by ABT are:


a) What happens to the schedule and UI charges in instances of the grid disruption beyond the control of generator or consumer? ABT delegates the responsibility of resolving such instances to the RLDC. However more clarity needs to be brought forth on this issue as this point can potentially cause a lot of contention regarding the UI charges.


b) A fundamental concern on ABT is whether it is the right measure to be introduced. While the spirit and intention of the act is widely appreciated, there is serious concern that it introduces elaborate and complicated procedures that shall give rise to a lot of contentions between involved parties on their interpretation. Some of these aspects include the declaration and demonstration of availability by a generating station, computation of variable and UI charges, rescheduling of generation and consumption etc. It may be required to evolve the current proposals to a more simplified and transparent system over a period of time.


c) Acceptable availability may vary depending on the energy source of the generating station. And in some cases, such as hydro and wind stations the availability may not be accurately predictable except in the very short term. This will pose problems in calculation of fixed charges based on availability.


d) Plants commissioned in different times tend to use vastly varying technology and thus tend to differ a lot in efficiency and cost of production. Since revenue for the generator vary significantly with efficient and controlled operation, old (though fully functional) plants may be at a disadvantage. The investment required to bring them to par with their modern counterparts may not be justified by the professed returns. On the other hand if CERC relents to discriminate between plants based on this factor, it will just add to the opacity of the proposed system.


e) Another significant concern on ABT is the possibility of gaming (deliberate manipulation of availability, daily demand and capacity schedules etc.) by the involved parties to derive undue benefit from the UI charges. ABT system introduces clauses meant to discourage gaming through severe penalties. Whether this will prove a sufficient enough deterrent and whether the checks and balances prove adequate to detect gaming need to be ascertained.


f)  Another interesting concern is the CERC diktat that any revision in schedule by the RLDC will deemed to be effective irrespective of the successful communication of the same to concerned parties. As has already been pointed out, most of the concerned parties being PSUs lagging on the technology front are yet to have fool-proof or redundant communication infrastructure in place. Thus rescheduling may fail to reach concerned parties in a timely manner and if somebody is caught unawares on the wrong side of the UI charges, they are not going to be pleased about ABT.


Implications for different industry players:


Put succinctly ABT requires all the actors in the great power drama to get their technology act right. There is no room for laxity on control or efficiency fronts. The technology dependency is going to be more on the generation side.


Capital cost of the generating facility being redeemable only against declared availability and successful demonstration of the same will require the generators to really have a tight rein on their complete infrastructure. All the generators will now need to set a target of 85% availability to ensure that complete capital costs, ROE and incentives are available to them. And the provision for surprise audit to demonstrate the availability will need to them to monitor all the equipments and ensure adequate and timely maintenance of their overall infrastructure. This will usher a modern outlook and calls for the latest and best technology in performance calculations, efficiency and IT.


Variable costs and UI charges will require the generators to closely match their output with the demand curve and the ability to take corrective actions in the shortest possible time. ABT also calls for elaborate computation of the payable tariffs and close monitoring of the cost of production. Ushering in of MOD is going to be a positive development for all generators enabling them to make huge savings on cost. All these factors will involve a good amount of technology investment but will set the right background for an efficient power structure and the right launching pad for a market oriented approach. This will naturally result in higher reliability and increased customer confidence giving the right impetus for more industrialization and enhancing our development process.


 At the consumption end also there is going to be the need to forecast demands as accurately as is possible and to follow the strictest possible grid discipline. This again will prove vastly beneficial to the power industry as a whole.

Impact of ABT on different Players



Impact on generation utilities:


Of the three, power generation utilities will need to adapt most to the ABT regime. This because most of the changes specified in the ABT, such as computation of capacity charges, assessment of plant availability, revised tariff structure, UI (unscheduled interchange) charges etc. will be of direct significance to power generation companies. Initially only those power stations that cater to more than one SEB (state electricity boards) are expected to abide by ABT. However, since the objective of ABT is to usher in more responsibility and accountability and thereby improving the quality power, it is quite likely that all generation companies would soon need to abide by ABT or similar acts. Such abidance and discipline will only increase as ABT slowly paves the way for a completely deregulated and market driven energy economy.


Under ABT, there is a paradigm shift for generating stations from maximum power to maximum reliability. Pre-ABT generating stations used to generate to their capacity irrespective of load demand in the network. Under ABT regime, the loads requirements are given in 15-minute blocks and the generating station needs to closely follow this demand curve so that frequency deviation on either side of 50 Hz is a minimum. Some of the technology requirements thrown up by this paradigm shift are:


a)         Advanced control and monitoring systems to closely monitor the ex-bus output of the plant and ensure that it is closely in heel with the 15-minute schedule provided by the RLDC (regional load dispatch centre). Ex-bus output information is already available in all power plants. What will be required of ABT is to integrate this information with the 15-minute load demand information so that plant operators have a clear and up-to-date information on what is the requirement and what is being provided. Alarms can also be incorporated to provide escalation in case of significant deviation of output from demand.


b)         Integrated information and communication system to capture data from all the components in the power generation cycle starting from the fuel store for the plan to the ex-bus point. Unscheduled downtime is not very acceptable in the ABT regime. Plant engineers need to have information regarding all aspects of the power generation suchmas whether fuel of sufficient quality and quantity is being made available, are all the components of the system (say, the boiler, reheaters, superheaters, economizers, soot blowers etc. for a fossil fired power plant) working without hitches to ensure smooth production. This will require an advanced data acquisition system and other software solutions suitably integrated with each other to provide the most up-to-date information. And smooth functioning of such a system will call for the necessary communication infrastructure.


c)         Production following demand will mean that the plant will not be operating at peak capacity at all times. This will require for an optimization problem between different units of a power plant since the cost of generation, ramping, start up and shut down associated with each unit will vary. This is called the merit order dispatch (MOD) problem. MOD solutions can potentially provide huge savings for a power plant and ABT will require most plants to accommodate MOD to ensure economic operation.


d)         In addition to MOD, performance calculation for each unit of the power plant and corresponding optimization also needs to be done. Different parameters that may affect the plant performance such as superheat temperature, reheat temperature, inlet/ outlet temperatures, excess air ratio etc. will need to be monitored. It should be possible to suggest to the operator regarding the effects of varying these parameters. Powered with such information the user can attain the optimum plant performance during operation.


e)         As already mentioned, under the ABT regime unscheduled deviation from the power generation schedule incur considerable penalties (termed UI charges). It is thus in the interest of any generator to ensure that any unexpected downtime of the power plant does not occur. This requirement calls for a more pro-active management plan than is being practiced by most generators now. Equipment condition monitoring is a significant area that can benefit generators by telling them which components in the cycle are likely to fail and for what reason. This will enable the operator to ensure proper and adequate maintenance for such components. In addition the generator is encouraged to plan all activities well in advance and co-ordinate the same between different units in the power plant and to ensure optimal use of plant equipment without overloading.


f)          The economy of power generation is vastly altered under the ABT regime. Earlier capacity charges were paid against PLF (plant load factor) and power charges against the power sent out. Under ABT capacity charges are payable against declared (deemed) availability and a UI (unscheduled interchange) component is payable as part of the power charges for any grid indiscipline. UI charges are a system of incentives and disincentives and depend on the declared demand, declared availability, deviation from forecasts, grid conditions etc. As a result of this new structure, the parameters influencing the monetary returns from power generation are much more complex. Power generation stations would do well to have a full-fledged tariff calculation system that can do a detailed computation and optimization of power generation from the revenue angle. This kind of digitized linking between power generation and revenue will prove greatly beneficial during the journey to a full-fledged market system.


Impact on grid operator


Grid operator typically manages the power transmission infra-structure. This will correspond to the role of the ISO (independent system operator) in more evolved power markets. ISO’s are typically no-profit organizations formed by a consortium of all interested parties in a specific geographic area for a power market. Their goal is to ensure smooth operation of the grid and to ensure adequate load-supply balance in the grid. In India this role of power transmission and coordination is handled by PGCL (Power Grid Corporation of India Limited) which incidentally is the single largest power transmission utility in the world. PGCL is responsible for operating the national and regional power grids as well as managing the RLDCs (Regional Load Dispatch Centres). Under ABT regime, the role of balancing the demand and generation side of power is vested with the RLDCs. As such some of the system requirements at the grid operator for the successful implementation of ABT will be:


a)         Improved and efficient transmission systems: A unique nature of electricity as a commodity is that it needs to be generated just in time for consumption. With addition and modernization of different power resources adding the total generating capacity, transmission is soon going to present one of the major bottlenecks in the smooth operation of our power systems. It will be the responsibility of the grid operator to ensure that such a scenario is averted. Merely adding of transmission capacity to the existing infrastructure may prove inadequate. It will be equally imperative to smoothly and efficiently manage the system with proper simulation tools, load balancing features etc. to ensure that the bottleneck in transmission is removed and that all the available energy is efficiently delivered to the needy consumers.


b)         Better forecasting systems: Presently the RLDCs are vested with the role of coordination between consumers and generators regarding the demand and generation schedule for each day split into 15-minute intervals. Since UI charges are payable by the generator or consumer, it may seem that the onus of forecasting more lies with these parties (especially consumers). However to ensure that the spirit and objective of ABT is not thwarted, it would indeed be important for the PGCL to predict as accurately as is possible the demand in different consuming regions. Variations as a result of climate, festivals and other events also need to be taken into consideration. Only then can they ensure that enough bandwidth is available across different routes to carry adequate power to each region.


c)         Better communication and information systems: It is the responsibility of the RLDC to communicate the 15 minute generation and consumption schedule to each party. It is also the role of the RLDC to convey any unforeseen change in such a schedule. ABT envisages that the UI charges will get suspended for specific periods in the event of an unforeseen disruption in the grid for which responsibility cannot be pinned down on any particular generator or consumer. It is very important that the disruption and revised schedule is communicated in a timely fashion to all the concerned partied failing which the credibility of the whole system may soon get pulled into the question. This aspect requires the grid operator to have excellent communication and information infrastructure in place.


d)         Improved metering and billing system: Under ABT specifications it is the responsibility of the PGCIL/RLDC to ensure adequate metering capabilities for proper implementation of the tariff structure. Under the revised structure, specialized energy meters that can keep track of 15-minute energy aggregates as well as frequency for each 15 minute interval need to be implemented to take care of the normal energy charges and the UI charges. Telemetry capabilities (with associated hardware and software solutions) also need to be put in place to ensure accurate and timely completion of the exercise. The alternate of manual reading of meters will prove too much extensive, time consuming and likely to be error prone and may jeopardize the credibility of the ABT regime.


Impact on consumers:


As already mentioned, the major thrust of ABT is to improve the reliability and quality of the power grid. Primary beneficiary of such an enhanced system would be the consumers. Consumers in the ABT regime consist of SEBs (State Electricity Boards) and other major distribution companies. Most important benefit they can realize from an improved power grid is to pass on these benefits of quality and reliability to their consumers in turn, who are typically the end user links in the T&D (transmission and distribution) chain. While providing these benefits, ABT also confers some responsibility on the consumers which will require them to fine-tune their process. Some of the requirements ABT will make on consumers are:


a)         Enhanced load forecasting system: Under ABT regime, each SEB will need to provide their load requirements in ninety six 15-minute intervals for each day. The consumer is expected to stick to this schedule in the absence of external grid disturbances and corresponding revisions by the RLDC. Failure to comply with the schedule will attract penalty in the form of UI charges. Thus it becomes very critical for the SEBs to have accurate short-term load forecasting systems in place. Once the ABT regime moves to further deregulation, long term forecasting will also become critical since only on that basis can the SEBs enter into commercial agreements with the generating utilities.


b)         Reliable communication and information infrastructure: Any load forecasting solution (short term or long term) is highly reliant on historical data for delivering accuracy. Thisremains true irrespective of the algorithm employed by the forecasting solution (with thepossible exception of astrology). Thus it becomes very important for the consumers to have highly reliable and available information management systems that can make available historical consumption data. Communication systems are also called for to ensure smooth coordination with the RLDC and generating stations as well as to ensure proper integration with the telemetry systems.


c)         Provision for in-house generation: UI charges can be termed as vague and distant forerunners of a market aligned price (may be what the Neanderthals are to homo sapiens). This can be reasoned out as the following: when the grid frequency is low it indicates a situation where demand for power is in excess of supply in the grid. If at this time a consumer needs to draw more power, he needs to pay a heavy penalty in terms of UI charges. This can be compared to a consumer paying a premium in the market for additional power than what he has hedged for. The comparison is not fully justified, but was put forward to indicate that SEBs at some point of time will have to face a make or buy decision in terms of power, to avoid customer wrath and UI charges alike in a high demand situation. And this may manifest in terms of captive power plants that are going to be more and more popular during the slow but sure transition to a decentralized and deregulated power market. And with captive power plants need to be integrated with the power grid will come a host of other technology challenges that are best dealt as a separate paper.



ABT at state level Back to top





The development of appropriate mechanism for introduction of ABT regime at State level, need to be viewed in the context of objectives laid out hereunder such as improvement of grid frequency, instilling forecasting and load management discipline amongst distribution licensees, instilling dispatch discipline amongst generators, encouraging more participation in state level balancing mechanism. Further, ABT mechanism will have to be devised taking into consideration several criteria such as cost of power for Maharashtra power system should not increase, fair and equitable allocation of risks amongst participants, constraints of system operation and stability, availability of metering and communication infrastructure, promoting long term development of market etc.




The primary objectives which have to be fulfilled by the new system have to be looked

at. The most important objectives are:

Ø      To bring in more generation in the system and improve the grid frequency. Currently, Maharashtra is facing acute power shortage with peak demand growing at a very high rate. During peak summer months, even Mumbai licensee faced acute power shortage necessitating initiation of load regulation measures. While the future position of demand-supply will depend on load growth and capacity additions, tapping of surplus power available today, if any, would assist in improvement of grid frequency and quality of supply.


Ø      To instill forecasting and load management discipline in Distribution Licensees

Prior to introduction of ABT at State level, the Distribution licensees did not face the implications of any inter-state UI earning or payment by the State. Under the integrated power system operations scenario, however, distribution licensees would be required to forecast their requirements accurately. In the market mechanism being developed, it is envisaged that the UI incident on the State will have to be passed on to the distribution licensees through appropriate mechanism, so as to incentivize Distribution licensees to accurately forecast their load requirements and manage the load accordingly.


Ø      To instill dispatch discipline in generators. In the current scenario, some state generators may deviate from their despatch schedules and not face any commercial implications for the same. For example, they may generate beyond their schedule even when the frequency goes beyond 50 Hz. The payment to generators being based on actual generation and not scheduled generation, and the incentives linked to maintaining a high PLF can be the reasons behind these. Therefore, a mechanism might be required to instill despatch discipline among generators.


Ø      To encourage participants within the state in balancing the system.  A balancing mechanism tries to match supply and demand on almost real-time basis. In developed markets, the system operator manages the balancing mechanism through a system of contracts. In India, at the regional level, this is sought to be achieved through ABT where, through a pre-determined price (UI rate), the participants are provided a signal to balance the system. At the state level, the SLDC is expected to play this role. It may do so by using reserves such as hydro capacity or by instructions to the demand side such as load relief measures. We may complement this system by an intra-state ABT mechanism which would encourage the involvement of participants in balancing the system.




Before looking into the various aspects of design of a new mechanism to be implemented in the state of Maharashtra, a few important principles have to be kept in mind which could act as the essential criteria for evaluation of any new alternatives. Based on these considerations and the objectives already discussed, we need to devise the system at the state level.


Ø      Cost of power in the Maharashtra system as a whole should not increase. Any increase in the cost has to be borne by the end consumer and hence, any new mechanism that is implemented should not increase the cost of the system as a whole. Thus, while introducing intra-state ABT with the objective of tapping more generation, we should bear in mind that the extra generation does not come at a very high cost. At the same time, while extending ABT to the state participants, there should not be any significant financial loss to the Distribution Licensees. In the recent past, MSEDCL has incurred significant cost on account of UI. While designing the new system, the intra- state UI mechanism should be such that the utilities do not incur significant UI costs on account of inter-state UI mechanism.


Ø      Quality of supply and the efficiency of various entities should improve .One of the most important objectives behind reforms in the electricity sector in the State will have to be improvement in efficiency of the various entities and improvement in the quality of supply. The generating stations should dispatched in most efficient manner taking into account economy of operations and merit order dispatch principles for the power system as a whole irrespective of the ownership. Any new system should promote/incentivize the improvement in efficiency and quality of supply and exchange of power amongst market participants. Tapping of excess generation will improve the frequency profile of the system and thus will lead to improvement in quality of supply.


Ø      The new system should promote the development of market, i.e., encourage participation by many buyers and sellers. Another objective behind the reform process has been the development of a market in the long term. Therefore, any new system should be in line with the overall objective of market development. The new system should offer opportunities to many buyers and sellers to take part in the market and maximize economic gains.


Ø      Fair and equitable sharing of risks amongst various State participants The proposed arrangement should not result in in-equitable allocation of risks and costs amongst the State participants. The proposed mechanism should take into consideration existing contractual arrangements and agreed risk sharing arrangements amongst the State participants. The risk and returns should be commensurate with each other.


Ø      System Operations and Stability SLDC has the responsibility to maintain system security and stability and for that purpose SLDC can exercise control on the system participants. Before implementing any new mechanism in the State, it is extremely important to examine the impact and implications of the new mechanism on critical system parameters and to ensure that the stability and security of the system is not jeopardized in the new mechanism. The system

parameters which are of critical importance are frequency of the grid, line loading, voltage profile, transformer loading etc.





Specific areas covered under this are (a) Objective of Governance under state level ABT mechanism (b) Constitution of Maharashtra State Power Committee (c) Functions of Maharashtra State Power Committee (d) Powers of Maharashtra State Power Committee




As a part of the proposed ABT mechanism at State level, an institutional mechanism

needs to be created to address commercial issues, which may arise between the trading partners. A Maharashtra State Power Committee (MSPC) is recommended for this purpose.


The main objectives of this institutional arrangement shall be to:-

(a) Develop and provide a platform for better governance of a market oriented trading mechanism


(b) Provide a framework for efficient reconciliation and settlement of differences between the trading partners.


(c) Recording of commercial arrangement and accounting of energy exchange amongst parties.

(d) Bring transparency in operation and improve upon the system and procedures of market operation.



Entities involved in Intra-State ABT


Intra-state ABT shall be applicable on suppliers and drawers involved in the State Grid, who are required to give daily schedules to State Load Dispatch Center (SLDC), and have agreed to pay as per ABT for any deviations from schedule.


(a) Generating Stations:


All generating station except the following shall be covered by intra-state ABT, if:-

(i) Covered by inter-state ABT,

(ii) Nuclear, Wind and Solar Power Stations,

(iii) Hydro Stations,

(iv) Power Plants of capacity below 10 MW and

(v) CPPs & Co-Generating Stations.


On account of generation from hydro, wind & solar power stations being dependent on nature and their generation cannot be predicted with certainty, these power stations have to be excluded from Intra-State ABT. Similarly Nuclear Power Stations because of their nature of operating in base load, cannot adjust their generation to load demand and hence they have also been excluded. Renewable sources such as biomass, solid waste, etc. are controllable and a schedule can be generated day-ahead. However, given the many benefits for the generation from renewables, and also in view of the relatively very small capacity of units, biomass and other renewables have also to be

exempted from ABT. As UI rate applies on deviation of actual generation from the scheduled generation, generating station of capacity up to 10 MW shall not give daily schedule and as such they cannot be covered by ABT.


(b) Licensee:


A Distribution/trading licensee shall be covered by intra-state ABT, if


(i) it effects drawl from generating stations & licensees governed by interstate and/or intra-state ABT and

(ii) Its total drawl during any time block exceeds its drawal from Non-ABT sources i.e. generating, trading licensee & distribution licensees not governed by interstate or intra-state ABT .Provided that the intra-state ABT shall be applicable on bilateral exchanges only, if for such exchanges, scheduling & payment as per ABT for deviations from schedule has been agreed.


(c) Open Access Consumer:

An open access consumer, within the State, shall be governed by intrastate ABT only in respect of electricity supplied to him by the generating station / licensee governed by inter-state/ intra-state ABT. Intra state ABT shall be applicable to the extent of such supply only.



Basic infra structure and other requirements for intra state ABT


a) Metering:


The Forum of Indian Regulators (FOR) sub-committee has rightly pointed out that for implementation of Intra-State ABT, the activity of installation of special energy meters on the periphery of all entities would be the critical part. The meters should be capable of recording the following parameters in a 15 minute block.

• Cumulative active energy

• Cumulative apparent energy (KVAhr)

• Cumulative reactive energy under high voltage (> 103 %)

• Cumulative reactive energy under low voltage (< 97 %)

• Active energy

• Average frequency

• Date & Time

• Average power factor

The interface points such as interface of IPP’s with the grid, CPP’s / Co generators with the grid, open access consumers with the grid, CGS ( NLC1) with the grid etc., will have to be metered. by the SEB within a certain time frame .


b) Communication facility:


In ABT mechanism, the metering data should be transferred from Special Energy Meters to ALDC/SLDC on a real time basis. Hence adequate & reliable communication facilities should be established by TNEB/STU. In order to provide load forecast to the SLDC on a daily basis, communication facility from the ABT compliant meters at the interface points to the ALDC of the distribution licensee should also be established along with SLDC.


c) Tariff:


The basic requirement for implementation of ABT is a three-part tariff comprising of fixed charges, variable charges and UI charges. As discussed earlier, the fixed charge would be linked to availability and variable charges to the scheduled energy. The UI charges shall be applicable for the deviations from the schedules. A three-part tariff for the central generating stations is already in force under the inter-state ABT.


Regarding the third part of the tariff i.e. UI charges, the UI rate determined by the CERC is already in force for inter-state ABT and it has been recommended by various experts including the Forum of Indian Regulators (FOIR) sub-committee to adopt the same UI rate for intra-state ABT also. Hence it is appropriate to adopt the same UI rate as determined by the CERC for intra-state transactions also.

d) Setting up of Area Load Dispatch Center (ALDC):


Each Distribution Licensee should have an Area Load Dispatch Centre to monitor and control the drawl of power within their jurisdiction. Even though some SEB still remains as a vertically integrated utility and a deemed Licensee for the present, they have to design the system for intrastate ABT to suit the future scenario with multiple Licensees. This involves additional investments and may have to be agreed as a pass through in the future tariff.


e) Up-gradation of SLDC:


In order to handle the increased volume of data under Intra-state ABT and also to perform the functions of monitoring and energy accounting, the state load dispatch centre needs to be up-graded suitably by providing necessary software, hardware, human resources and other infrastructure. This again involves additional investments and also have to be agreed as a pass through in the future tariff


f) Training and Familiarization:


Under intra-state ABT, energy accounting would be complex and requires computerization and trained human resource for efficient data management. For effective implementation of intra-state ABT, the staff of SLDC and the Licensee(s) need to be trained extensively. The staffs of SLDC have already gained experience in operating the inter-state ABT, but they have to be further trained on intra-state transactions.


Case of Tamilnadu in brief


Present Status in Tamil Nadu


TNEB have reported that presently in the SLDC scheme 34 numbers of generating stations and 49 numbers of grid stations have been covered with state-of-art communication and SCADA system. These are used for ABT based grid operation in the integrated operation of the southern grid. TNEB has also reported that additionally 8 numbers generating stations and 5 numbers grid stations are proposed to be linked with SLDC/SSLDC during the current year. All the new substations to be commissioned are also being provided with SCADA and proposed to be linked with SLDC. It has initiated action to provide ABT compliance meters in its generating stations and in grid feeders during the current year. It has also been reported that TNEB have already provided the state of art DCC-SCADA system for Chennai metro area covering 95 Substations and upgrade the existing DCC to accommodate additional 200 substations along with distribution management system (DMS) facility during the current year. TNEB is understood to have proposed to provide SCADA and communication facility to all substations, connecting them with circle level area control centre (ACC), which in turn, will facilitate open access, energy accounting and auditing. TNEB at present is a vertically integrated utility. With the present unbundled structure, the scope of implementing the ABT mechanism in Tamil Nadu may appear not to yield any major benefits to TNEB / consumers. In fact, it has also been pointed out during the discussions in a FOR Meeting on 10.11.2006 that unbundling is a necessary precedent condition for introduction of intra State ABT. However, even under an integrated set up, TNEB have to necessarily move towards establishment of profit centre concepts and under such a scenario, self discipline, proper accounting and optimum use of its energy resources will be automatic with intrastate ABT. In fact, this cannot be postponed indefinitely and we should not be lagging behind when the situation warrants such arrangements to be in place at the appropriate time. The intention of the Commission is that the TNEB should immediately start establishing the left over infra structure and other facilities with a time frame and to the extent possible.


 Proposed course of action


Taking into consideration, the necessity for introducing intra state ABT, the advantageous, the present status of required infra structure, emerging scenarios , along with the additional expenditure TNEB have to spend to establish the requirements, which, in turn will have to be allowed as a pass through in the future tariff, Commission have decided to invite the public opinion through this consultative paper, conduct a public hearing and issue a suo motu proceedings to TNEB to initiate a time bound program for establishing the infra structure and other requirements for introducing intra

State ABT at an appropriate period on a later date after these works are completed.




Self-regulating power market


Going by the commonly accepted definition of market, a power market would indicate an entity (or arrangement) where power generators will offer their distribution capacity or actual energy and interested consumers (such as distribution companies) would purchase them. The energy charges payable to the generators will depend on the demand-supply characteristics of the market. By the term “self-regulating” we imply that no external influence (such as directives from a regulating agency) shall be responsible for the power tariffs in the market and it will be determined purely on the demand-supply ratio. This is in contrast to the current scene in Indian (and most other) power sectors where government regulatory agencies are responsible for setting the rules of the game and the applicable tariffs. In fact, presently most of the generating companies and distribution companies are public sector units controlled by the government thereby curtailing the notion of a market system considerably.


However, the economics of a general market cannot be directly imported to the power sector due to the peculiarities of the commodity involved viz. electricity. For one, electricity cannot be stored for consumption and need to be generated synchronously with consumption and then transferred over conducting medium. This means that the production system needs to be ramped up and down closely in pursuit of the market demand. The implication is that your generation capacity needs to exceed the instantaneous maximum demand and your transmission bandwidth also needs to support the same. This “real time” nature makes demand forecasting a messy job as far

electricity is concerned. For example, you may be able to predict that X tons of wheat is required for the next month based on past consumption data and other relevant information. This prediction will be more or less accurate if you have got your statistics right. But it is not possible to predict exactly how many tons of wheat will be consumed on a particular day at a particular time. And in the case of wheat, it is not necessary to do so. But in a typical power market, you are required to predict the demand for each five minute interval (at least).


 Another differentiating fact for electricity is that it is not a stand alone commodity. Along with electric power other resources also need to be supplied such as reactive power, stand-by (spinning and non-spinning reserves) etc. which are commonly termed as ancillary services. In general practice terms for ancillary services are negotiated separately and in many instances actual power and ancillary services may be provided by different entities. This further complicates the process of modeling the electricity market.


A third crucial aspect is the consumer perception of electricity as a commodity. It requires extensive infrastructure to deliver electricity to a consumer. As a result, it is not possible for a consumer to choose from an array of vendors (for small-medium consumers, it is often not possible to have a choice of vendor at all). Further electricity is considered as a near-essential commodity for all and a must-have for critical institutions such as hospital. As a result of this subjecting electricity to a complete market oriented system susceptible to uncertainties of price and availability is a concern for most societies.


Due to the points enumerated above a completely free power market is yet to take shape (or even successfully conceived). What has been implemented in several advanced economies is a restricted power market. The restriction is implemented by means of a central coordinating agency (called an Independent System Operator – ISO) who regulates the market and ensures that the social objectives are met within the parameters of the system. Thus ensuring adequate and reliable supply of electricity to all consumers, preventing undue manipulation of the market by participating entities for profiteering etc. are the objectives of this entity. To facilitate the meeting of these objectives, in many cases all the transmission facilities are managed by this coordinating entity while it owns no generation or distribution mechanism. Selling and buying of power happens through bilateral agreements (between a generator-consumer pair) as well as in a power market. In may instances, the power market is run by the ISO while it may also be run by a separate independent agency. The ISO typically operates as a no-profit organization and is run by representatives from a regulating agency. All the stakeholders (such as generators and consumers) are also allowed representation in the ISO though mostly without decision making authority and only as recommending participants.


Implications of a power market


Thus it is quite easy to see that power markets are typically “engineered” markets and not “free” markets. Why then is it necessary to have such a market? Unfortunately, there is no unambiguous answer. Given the physics of power, perhaps the ideal system is a single generation-transmission-distribution-billing-collection agency. This unification of roles enables a lot of convenience in terms of managing unit commitment, merit order dispatch, congestion management, ancillary services etc. The problem is similar to one of the most debated issues faced by society viz. what is the best form of government? At a purely conceptual level it is quite tempting to accept a benevolent dictatorship or a Platonic educated-oligarchy as the best form. Why then is democracy preferred? For the simple reason that the conceptual level seldom translates into practice. A centralized system consisting chiefly of large generating capacities is posing environmental as well as reliability issues. And a monopoly nature inherent in such a

mechanism does not turn out to be fair to all participants and stakeholders. The availability and economics of such a vital commodity as power tend to be dictated by political or other nefarious considerations. And at a much more fundamental level, it is sometimes quite impossible for a central agency (especially a PSU with its inherent handicaps) to run a vast and complicated power system efficiently and transparently. Decentralization, thus, needs to be ushered in and thence the market approach.


Most power markets operate along three lines: long term (year ahead, month ahead, week ahead), mid term (day ahead, hour ahead) and short term (intra hour market). Participants in the market such as generators and distributors typically take part in all three markets to ensure purchase/ selling of their power in the most economical fashion. There is a non-profit ISO which coordinates the power system and ensures reliability by responsibly managing the transmission system. The power market may or may not be run by this ISO. Of the three, short term power market is the most significant. This because long and mid term power purchase quite often happens through bilateral agreements. In such cases the price and other terms are part of a private contract and may not be made public. Long term contracts may also be made available by the ISO in a transparent manner paving way for market dynamics. The short term arrangements are typically handled in a pure market fashion. Ancillary services are typically bought and arranged by the ISO which then charges all the participants in an equitable fashion for the same.


Power price is typically set in the market through supply side bids. This means that each power supplier (generator) will submit bids into the market indicating their prices and ramp rates. (For example, a generator may quote Rs.1300/- per MWh at an output rate less than 200MW, Rs.1600/- per MWh when the output is between 200MW and 420MW and Rs.2500/- when the generation capacity required is between 420MW and 500MW). Such bids will reflect the operating costs for the generator associated with different units. Demand side is typically not considered in determining the price of power in most markets. Market price of power is typically considered as the price paid against the highest successful bid. How each of the suppliers are paid for power supplied varies from market to market: in some, all will be paid the same price (which would be the market clearing price denoted above). In other markets, there may exist a pay-as-bid mechanism where different suppliers may get paid differently. Sometimes the long term and mid term power prices are set against the short term (or real time power price). Ancillary services (especially spinning and non-spinning reserves) may be priced against the real time prices.


Irrespective of the pricing model, it follows that price is normally set depending on applicable regulations of the market. And such regulations invariable allow the players to exploit loopholes gain undue benefit from the market. For example, a supplier of ancillary services has a lot of incentive to “fix” the real time price since he is going to get paid on the basis of that. Again where the real-time prices are fixed based on MCP (Market Clearing Price), suppliers can manipulate availability or demand to unethically bloat the MCP (this has actually happened in several markets). Where bilateral contract prices are also dependent on the real-time price, this incentive goes up much more. In pay-as-bid systems also such manipulations are possible by participants to gain undue advantage. In fact, in any of the four common auction methods (ascending bid auction, descending bid auction, highest price sealed price auction, Vickrey auction), given the restricted nature of power market, it is possible to manipulate the auction for participants to gain undue advantage. It is the crucial responsibility of the market coordinator to fine tune the market structure to discourage users from such manipulations. How successful such an attempt is what determines how efficient and beneficial the market is. And in most cases where power markets have failed, it was caused due to some unfair conduct by the participants exploiting vagueness or loopholes in the market regulations.

There are other implications to a power market as well. Along with power, trade will be encouraged in other commodities as well. One of the important components here can be emission rights. Environmental norms are becoming more stringent every day and power generation (especially in fossil-fired power plants) is a pollution-intensive exercise. Under such international contracts as the Kyoto protocol, capacity for different emissions can be traded. For example an entity (an organization, body or even a nation) that has the rights to emit 1000 tons of NOx per year can trade part or whole of this capacity to another entity for monetary or other considerations. Such trades are already underway in European markets. Another important result of a power market is that end customer expectation regarding quality and availability will go up than when it is managed by public sector organizations. This customer expectation will also prove beneficial to the industry by compelling participants to set higher benchmarks for themselves.


Successive milestones


Energy being an essential commodity, a power market based on demand-supply dynamics will fail to take off in the absence of surplus generation capacity. So having adequate generation capacity is going to be the first step in moving towards a market regime. It may not be possible to account for this surplus capacity from large centrally operated power plants alone. Captive power plants will play a crucial role in meeting this objective. Thus the next important step is the successful integration of captive power plants to the national grid. A lot of positive measures in this direction are already provided in the Electricity Act of 2003. However the transmission infrastructure available across the country as well as with our neighbors needs to be enhanced to ensure that there are no transmission bottlenecks in this integration. Further, a market with scope for multiple generators to participate will materialize only in the presence of redundant transmission capacity.


Next step is to provide adequate economic incentives for different players to participate in power trading. Again such measures are already allowed for in the ABT and Electricity act. This includes incentives captive generators as well as removing a lot of regulatory hurdles for private and cooperative bodies in setting up power generation facilities. Once these steps are covered, we can have an atmosphere conducive for a self-regulating power market.


From here, the crucial step is setting up the market itself. As our earlier discussion indicates, there is no perfect model available to import even when we do not take into account factors unique to India. A completely successful and satisfactory power market is yet to emerge anywhere across the world. So it will more be a question of learning from other’s mistakes. We will also need to adapt their good practices. The role of a central coordinating agency will be crucial in ensuring smooth operation of the market without failing any of the social and national objectives. One possibility is for the government to disinvest the generation capacity of PSUs and then for the PTC (Power Trading Corporation of India) with its Load Dispatch Centers to act as the central coordinating agency. This is however likely to raise a lot of opposition, not all of which will be invalid.




Thus after providing the conducive ambience for a power market, setting up of the actual market is going to be a major challenge. This challenge will first involve how to set the rules of the game and how to define the roles and responsibilities for the nodal coordinating agency. The onus is then on this agency to ensure the smooth operation of the market balancing the interests of different stakeholders. This agency will then also need to appropriately tone down its influence so that the market becomes more and more self-regulatory. The government (of India) will however need to divest all its generation facilities before setting up such a body to ensure that there is no conflict of interest in operating the market. If this is not done conclusively and transparently, it will

act as a major deterrent for many players in entering the market. As already mentioned such a disinvestment itself is going to be a major concern with opposition to be anticipated from multiple quarters. Compared to others, divesting nuclear power plants may cause additional worries taking into account environmental as well proliferation problems.


Another problem that needs to be solved is the disparity between different types of generators that take part in the market. ABT (as the first step in this direction) itself is faced with this problem and is not able to address it completely satisfactory. For a market scenario, in the absence of external regulations such disparities can seriously hamper the success of the market since different generation facilities (like hydro, thermal, nuclear, non-polluting) will be bound by vastly different physical constraints in participating in the market. Many of the other issues enumerated by ABT (such as adequate metering infrastructure) will also manifest themselves as serious hurdles in the progress to a self-regulating market.




Thus we conclude that the path from ABT to a self-regulating power market is an arduous one. What is called for is a lot of perseverance and professionalism. It is quite easy to run into a crisis situation in this journey, as has quite often happened in other markets. So it is very critical for the regulatory authorities to have a clear vision of the goal and the will to see the path to its logical conclusion. If technology (say, studies on super conductivity making it possible to bring down transmission losses to negligible levels in real life situations) emerges to seriously alter the physics of power generation-transmission-distribution, such a journey will be fraught with interesting consequences.




Issues 1:  Applicability of ABT to Nuclear Stations:

A.                 A question has arisen regarding the applicability of ABT to nuclear stations though owned by the Central Government.  The basis for the query is the provision contained in section 49 of the ERC Act which makes the provisions of this Act ineffective in so far as they are inconsistent with the Atomic Energy Act, 1962.  Thus though the commission has jurisdiction to regulate the tariff of centrally owned generating companies, since the Atomic Energy Act 1962 in section 22(b) states that the Central government shall have the authority of fix rates for and regulate supply of electricity from atomic power stations the Commission faces a constraint.  This constraint did not exist when it was the central government that was seized of the matter.

B.                 During the NTF proceeding the general consensus was to include the nuclear stations under the regime of ABT. However, in view of the special constraints involved in operation of nuclear stations, it was considered necessary to discuss the with NPC before taking a final division.  Subsequently after discussion with NPC it was decided to include nuclear stations under the regime of availability based tariff.

C.                In the proceedings before us, both on the grid code and on the ABT, NPC took an active part and filed replies to the proposals.  The jurisdiction of the commission has not been challenged in these proceedings.  We have also made special provisions for nuclear stations in our order on the grid code.  Under the ABT regime, NPC has expressed willingness to submit its stations to the regime subject to certain special considerations in view of the peculiar nature of their operations.  We are also of the view that in the interest of better grid discipline and merit order dispatch nuclear stations should also be included in the system.  In fact, even other entities like DVC and BBMB which do not fall within our jurisdiction though they are engaged in inter state transmission, would like to be covered by the ABT system.  The practical solution for this problem lies in making use of the alternative under section 22(b) of the Atomic Energy Act, 1962 which contemplates of the central government authorizing any authority established by the Government to do rate fixation and regulation of supply of supply of atomic stations.  As such, it is only required of the Central government through the department of Atomic Energy to authorize the commission in this regard.  We have already suggested to the Nuclear Power Corporation to initiate appropriate steps for the Government to authorize the Commission.

D.                We have also pointed out this inadequacy in the present legislation to GOI, under Section 60 of the ERC Act of 1998 vide letter No. L-7/7(1)/99-CERC dated September 21, 1999 which is pending with the Government.  In view of the above, the provisions of this order shall apply to atomic stations subject to the government’s response to these references.


Issues 2:  Do the Norms Need Revision?

A.                 A number of replies from the utilities indicate that the norms for determination of the fixed charges, variable charges and incentives need modification and cannot be accepted on the basis of existing norms.  On the one hand, NTPC has claimed additional payment for every startup and partial loading, as also an additional compensation for gas stations for making available the liquid fuel.  Some of the beneficiaries like KEB, AP TRANSCO, TNEB, DVC and RSEB have sought revision of the operational norms as well as in respect of ROE, debt equity ratio, incentives etc.

B.                 We are in agreement that the norms in respect of tariffs which were fixed as early as in 1992, need to be re-examined and revised.  We have already initiated the process through a consultation paper on bulk electricity tariffs which addresses these issues, among others.  We have also initiated certain studies by experts to help us in determining a rational basis for the revision of the norms.  This process is bound to take a few more months.  In the meanwhile, in the interest of grid discipline and merit order dispatch, we are convinced that the ABT merits implementation.  We are conscious of the implications of its introduction without revising the norms.  However, the time gap between the introduction of ABT and the evaluation of new norms may not be long.

C.                We understand that during the discussion in the task force meetings, it was advocated that the introduction of ABT should not adversely affect the revenues of the generating companies.  It was canvassed before us also that this so-called revenue neutrality should be maintained.  In fact on behalf of the Union of India, it was submitted before us that the guiding principle of revenue neutrality was kept in view while detailing on the tariff parameters of ABT for existing stations.  Accordingly, parameters such as return on equity, rate of depreciation, operation and maintenance charges, norms for fuel consumption and norms for consumption etc., have been taken to be the same as in the existing tariff.

On a perusal of the Minutes of the national task force, it is found that at its 9th meeting held on 25th March, 1998, there were some discussion to the effect that the intention behind the draft Notification is not to put the generating companies to loss in the process of implementing availability tariff.  This discussion was in the background of a 12% rate of return for NTPC at that point of time.  On behalf of the State Electricity Boards, protection was sought so that they should not be required to pay more.  As already stated by us, keeping in view the objective of the commissions to promote economy and efficiency, it may not be appropriate to proceed with a pre-determined conclusion that the existing revenues should be protected in the interests of revenue neutrality.  We have to take cognizance of the improvement in operations during the seven years since the norms were introduced in 1992.  At the same time, incentives for still further improvement in performance have to be thought of a balance to be kept between adequate return for the generator towards encouraging investment, and the possible exploitation of dominant position in generation.  As such, in reviewing the norms, we shall not proceed with apriority assumption, but approach the task in an unbiased fashion.  

D.                The commission is anxious to introduce the ABT system on account of its merits, without further loss of time.  As an immediate step, and in a broad sense, the present norms, etc. will continue to be used in the ABT system.   Within the short time available, the commission however, has considered some of the parameters which are dealt within this order.  The following are the topics that we shall leave untouched until our studies mentioned above are completed in some months:

      i)  Financial Structure

      ii)  Return on Equity and Income Tax Liability

      iii)  Method of Reckoning Incentives

      iv)  Depreciation

      v)   Operation & Maintenance Expenditures

      vi)  Station heat rate

      vii)  Auxiliary power consumption

      viii) Specific fuel oil consumption

      ix)   Admissibility of start up charges for thermal plants

The remaining topics listed below are dealt with in this Order:

a)     Target availability

b)     Criteria for Incentives

c)     Procedure for prevention of gaming

d)     Prolonged outages

e)     UI charges and frequency variation in different regions

f)       Settlement of UI account

g)     Treatment of unallocated capacities

Issue 3:  Rate of Return and Incentives

A.                 A number of beneficiary states have repeatedly questioned the increase in the ROE from 12% to 16% for existing stations.  No convincing justification has been advanced by generating companies in this regard excepting to state that public sector companies should be placed on par with the IPPs.  From the perusal of correspondence in the files made available to us, Cea appears to have taken a firm stand that the ROE and incentives should be considered as a total package and connot be isolated and dealt with separately.  In fact, the correspondence shows that CEA was not in favour of increasing the rate of return from 12% to 16% as it would add a burden of over Rs. 400 crores to the states.  When the take force was debating on the scheme  of incentives as a percentage of return on equity beyond target availability, the ROE under consideration was 12%.  However, without changing the scheme for incentives, the government of India raised the ROE from 12 to 16% which the beneficiary states considered as exorbitant and is a heavy burden on them.  We have come across in the NTF files a communication from the Ministry of Power to CEA enable it to generate adequate necessary resources for its capacity expansion programme during the 9th and 10th plans.  In another communication on record from the Government of India, Ministry of Power to TNEB it is stated:  This point has been reiterated along with a reference to the observations of the disinvestments commission to the effect that the tariff of NTPC is low due to poor rate of return.  Adjusting the Rate of Return in order to finance further expansion plans is a debatable issue.  Further, even admitting the same, the extent to which this can be factored-in is also debatable.

B.                 The system of incentives based on actual PLF + certification of backing down (called as Deemed PLF) came into vogue based on the recommendations of the KP Rao Committee.  The criterion of giving incentives to the generator, linked to PLF had a remarkable effect in improving the PLF of generating stations.  This remedy was essential at that time to augment the actual generation of existing capacities.  Over a period of time, however, it has been found that this system has become counter productive and costly in as much as incentive was payable even for backing down.  This is the cry from the Eastern Region and before more cries come from other quarters, it is better to remedy this situation.

C.                It is true that the ECC has discussed about both the disincentive and the incentive for better performance.  The disincentive is in the form of target availability for full reimbursement of fixed charges.  Any availability below the target availability would  result in reduced fixed charges.  The ECC did contemplate a basic incentive credit which is defined as that amount which replaces the BAC (Basic Availability Credit) in the capacity payment calculations after the target availability is attained.  The BIC is a smaller value than the BAC since it only provides for incremental cost of operation plus an incentive payment to the generators for operation beyond normal availability. (para 5.2.3 of the Report).  It is evident from this concept that the ECC meant payment of incentives for operations beyond normal availability after the target availability is attained for which a cost of operation is also involved.  Thus it appears that the ECC did not contemplate an incentive payment on mere availability.  However, the draft notification gives incentives on mere availability.

A generator cannot be rewarded for merely putting up a generating unit.  It is necessary for him to make it available for the beneficiaries to a reasonable extent so that the latter could draw upon that capacity.  Any shortfall in available capacity needs to be commercially punished with the denial of fixed cost.  Incentive however, stands on a different footing.  In regulated tariffs, it is necessary to keep a provision to reward better performance in order to promote efficiency and economy through cost reduction.  Such a reward linked to a demonstrably efficient performance level, should be as challenging as possible.  Mere availability does not reflect efficiency.  At the same time, in order to keep the machine available without break down, the disincentive of denial of fixed charges is adequate enough.  What is also required is that the available capacity should also be efficiently use.  For this purpose, the entrepreneur generator should demonstrate that his product is competitive enough both in terms of cost and reliability of service so that additional demand would get generated and he will be able to improve his plant load factor.  Any improvement in plant load factor (up to sustainable level) indicates efficient performance, for which reward in the form of incentive is appropriate.   Mere availability of the plant without demand cannot justify incentive payment.  This  conclusion is inevitable from studying the situation in the eastern region.

There though, the generator is available, due to lack of demand, he has to back down. In this process, the generator could claim incentive based on mere availability, which is patently unfair to the consumers who are already meeting the full fixed cost. The Commission considers that with the separation of fixed cost from the variable cost, the beneficiaries  are bound to view the cost advantage while making their scheduling. Combined with a little more aggressive marketing effort by the generators, it should  be possible to create demand for evacuation of power from surplus areas, which is otherwise bottled up. With this situation, the output and consequently the PLF generating units is bound to go up. Any incentive which is linked to PLF therefore would be an appropriate reward for cost control through better management of resources and better marketing efforts. There could be other and more effective ways which the Commission will be considering. But, for the present and in view of the foregoing argument,  the Commission considers it appropriate that any scheme of incentive should  be linked to actual performance, i.e., plant load factor instead of mere  availability.

D.                The draft notification contemplates reckoning of incentives as a percentage of equity linked to declare availability above the target availability. The incentive rate is also regressive, probably to avoid the temptation of extra earnings at the cost of proper maintenance of equipment. In fact the notification never uses the term “incentive”. The extra payment above target availability is included as part of capacity charges. This in other words means that the incentive will be chargeable as part of capacity charge on a monthly basis instead of being claimed at the year end separately. Many respondents have commented upon the adverse consequences of incentives merely based on availability. This has been very forcefully put across from the eastern region particularly because there is surplus power which is not in demand by the beneficiaries. The tow distinctive features of the  incentive scheme as per the draft notification are:

                    a)      The basis of determining the incentive; and

                    b)      The threshold eligibility limit for the incentive

E.                 Though we are clear about the criteria for incentives, as already discussed, the method of reckoning the incentive viz., as a percentage of the equity, is a matter which has to be deferred by the Commission since it has already initiated a study on cost of capital including whether the return should be on equity or on total investment. Further the impact on tariff between two comparable plants-one old and other new – with con trusting investment including debt/equity content has to be studies. Obviously, the newer plants would earn much higher incentive for no special performance.

            The Commission also finds considerable merit in the argument advanced by the CEA as evident from the files that the ROE and incentives should be considered together, as a reward to the entrepreneur, though reckoned separately for tariff purposes. As already stated, the Commission is convinced that this incentive should be linked to PLF so that it would really act as a catalyst for improved performance and cost reduction. Once our study on the cost of capital is completed, it would be possible to reach a firm conclusion regarding the justifiable ROE and incentives.

F.                 In fairness to all parties concerned, therefore, when both the issues regarding Return on Equity and method of reckoning incentives are yet to be looked into in detail, it is appropriate to maintain the status quo on both these issues till a final decision on the overall adequate return is arrived At. The Commission may also have to take a view on the effective date as and when the new norm regarding return is finalized As such the present ROE of 16% as well as the incentive scheme based on PLF should continue. However, the present incentive scheme provides for incentive at 1 paise per kWh for each percentage increase in PLF over 68.49% which is being revised. This is detailed in the next paragraph.

G.                In view of the discussion as above, the Commission would prefer to continue with the present incentive of 1 paise per kWh. This incentive should be linked to the actual generation achieved over and above the target level of generation. For this purpose, it is necessary to work out the targeted generation for each station based on the target availability and installed capacity.

Issues4: Capacity Charges and Target Availability

A.                 The Central generating stations which are mostly pit head thermal stations which are established in different regions order to cater to the power requirements of various state s in the regions. The investment has been made the Central Government and devolution of share of power to each state in the region has been determined on the lines of the Gadget formula for devolution of central assistance to the states. This had happened in the 1970’s.Over time, the tariffs of power from these stations have been based on commercial considerations. It is argued that the beneficiary states must bear the capacity charges of the stations in the region. As per the draft notification, the capacity charges consisting of fixed charges including rate of return is to be come by the beneficiary states in proportion to their percentage share in the capacity of the station. The notification also contains an annexure which stipulates payment of an extra percentage on equity, which is included in the definition of capacity charges and which is generally perceived in the industry as an incentive payment. The notification does not identify this as an incentive payment. This incentive payment portion of the capacity charges has been dealt with already by us in para 5.4. Hence presently we deal with the capacity charges other than incentive. These are the fixed charges and return on equity.

B.                 One of the essential features of the ABT is that the level for full reimbursement of fixed charges and ROE is the target availability of the generator to dispatch energy. This target availability is defined by ECC as “the equivalent availability factor (EAF) the unit us expected to attain on the average considering the units historical experience and the industry’s experience with similar equipment. Operation of the unit with good utility practice should be assumed”. (Para 5.2.3 of the Report).

There us considerable logic behind allowing capacity charges to be made payable in full, based on a target availability which is the average level a unit is expected to attain, so that below average performance is not rewarded with full fixed charges. The availability level for payment of full fixed charged is a departure from the existing criterion of payment at a PLF of 68.49%. Keeping in view the background that ventral generating stations were specifically designed to cater to a cluster of states, prescribing payment of fixed charges on availability subject to achieving a target is understandable and the substitution of PLF by availability is also more rational. Even though PLF along with deemed generation may be verifiable  (as they are record based), the proposed system is also fool proof since there is a system of checking of availability, as contained in the ABT. Testing of availability with consequent penal provisions for misdeclaration, further reinforces the system. In view of this, the disincentive in the form of commercial penalty for shorter availability can be considered as more appropriate and equally effective as the existing system for recovery of fixed charges.

C.                We also find from the minutes of the 7th meeting of NTF on 8th November, 1996, that there was concurrence of all concerned, both central generators as well as the beneficiary states on the adoption of availability based generation  tariff which incorporates this criteria for recovery and TNEB against capacity charges based on declared capacity instead of actual energy drawl, cannot be considered.

D.                Having accepted declared availability as basis for full recovery of fixed charges we have to consider the determination of target availability which is the minimum level to be  declared for full recovery of fixed charges. The garget availability as contained in the draft notification envisages a level of 70% in case of coal based and gas/naphtha based thermal power generating stations of NTPC and NEEPCO. As regards hydro-stations of NHPC and NEEPCO, a target availability of 85% has been contemplated.

These levels of target availability for thermal plants have not been justified. They cannot also be justified based on the recommendations of ECC or experience, which is required to be examined every 2 years. In this connection it has observed that “each generating unit shall have a target availability defined which shall be based on past operating experience unless new plant improvement projects indicate higher achievable values. This value should be re-examined every 2 years in order to reflect changes in generator operation and plant improvement projects. The study team expects that availability targets should generally be 85% or higher” (Executive Summary 2.0). It should be kept in mind that this  level was recommended by the study team in February 1994. Some of the beneficiary states  like Tamil Nadu and Rajasthan have strongly urged that the target availability should be at least 80%. RSEB has suggested that the target availability should be 85% instead of 70% as proposed in the draft notification. The administrative Staff College of India in its reply has stated that the availability factor of 70% as proposed in the draft suggested that the availability should be based on past performance of the plant or similar plant and for a thermal plant 80 to 85% would be reasonable. Similar comments have also been received from certain other beneficiary states. Though we granted a special opportunity to NTPC (which is also one of the respondents) to  file a counter affidavit, these contentions have not been refuted.

A perusal of the Annual Report of the Central Electricity Authority for the year 1998-99 shows that the average plant load factor of NTPC stations is 75.6% though All India average PLF is 64.6%. this  average of 75.6 when combined with the experience of deemed generation, would lead to an average availability of around 80 to 85%.

E.                 Minutes of the 7th meeting of the NTF are also worth considering. “the general consensus in RTF was that the norms for equivalent availability factor should be based on historical data of performance and industry experience with good utility practice for the past 4 years for existing plants”. The norms for determining equivalent availability factor should be reasonable and realistic so as to encourage better performance. “Performance of NTPC stations should not be compared with that of SEBs old station while determining target availability of NTPC units.

F.                 In the background of the above, the Commission called for data from NTPC, NLC and NHPC to understand the average availability of thermal and hydro plants for the past 5 years, which is as follows:-









69.28% to 90.17%

0.82% to 95.35%

74.45%to 91.01%

74.36% to 93.39%

78.30% to 95.28%

NLC: Availability






Stage I (630 MW)






Stage II (840 MW)










79.06% to 99.64%

82.09% to 96.21%

* The above availability factors do not include the following availability figures:









Kawas GPP: 48.91%

Feroz Ganxhi Unchahar TPP: 59.35%

Kawas GPP: 45.13%

Jhanor – Chandar GPP: 63.34%

Kawas GPP: 50.48%

Super TPP: Super 59.32%

Kahalgaon STPP: 58.38%

Talcher STPS: 66.50%






Chamera HEP: 56.20%

Salal HEP: 69.83%

Baira Siul HEP: 74.53%

Salal HEP: 74.42%

G.                These studies lead us to the conclusion that in case of thermal plants a target availability of 70% as provided in the draft notification cannot be justified. We could not find any justification in this regard from the records, excepting the only possible justification of revenue neutrality.  In our view, to compromise on the target availability to justify revenue neutrality is unfair to the beneficiary states.  We also considered the possibility of introducing station-wise target availability.  We could not accept this proposition since it may involve accepting existing inefficiencies of each unit and the target cannot therefore be an ideal in all cases.  As such we differ from the recommendation of ECC quoted earlier, that target availability for each station should be determined separately.  We are of the view that the target availability should operate as an ideal which should be normally achievable.

H.                We are conscious of the fact that there are some smaller units of thermal stations which were performing even below 80% and some of the hydroi-stations also which are performing below 80%.  It is necessary to pull these stations up to the proposed Target Availability.  The draft notification had created a comfortable feeling over the last two years that recovery of fixed charges was possible at 70% which the generators must period.  In the circumstances though we are convinced that the target availability should be 85% for full capacity charges recovery for thermal taking into account the sustained level achieved by thermal stations, it is appropriate to insist on a target availability of 80% .  it is fair and proper to afford a reasonable opportunity to low performing stations to improve.  It is felt that the time span of one year is adequate to enable all the thermal units to reach 85% availability.  Lignite stations are dealt with separately in the next paragraph.

I.                    Experience of operating lignite plants in India is limited only to Neyveli Lignite Corporation.  This fuel has a higher moisture content and in view of its spontaneous combustion, it is preferred to be used near the mine itself.  Transportation of this fuel over long distances is, therefore, avoided.  The lignite as obtained at Neyveli also contains marc site, which leads to slagging on the furnace.  This slagging formation sometimes leads to shut down of the boiler for its removal.  This process is stated to be taking around 5 to 6 days which includes cooling time manual breaking of the slag and its removal and bringing up the unit to its rated capacity. The quantum of marcasite also varies from seam to seam of lignite.  An effective method for separating marcasite in a cost effective manner is yet to be found out by NLC.  Another method of improving efficiency could be use of fluidized bed combustion.   However, the present boilers are not of a type to enable this.  The details furnished by NLC for their Stage –I and Stage –II projects has shown an availability factor ranging from 71.13 to 86.23 for power station-II, Stage-I (3x210 MW) and 72.54 to 86.74 for power station-II stage-II (4x210 MW).  The single part tariff agreed  to between NLC and beneficiaries has provided for payment of full fixed charge beyond 6150 hours (10.21% PLF) per annum of operation, which charge is also found to be high.  Taking into account the special features required to be provided for using lignite as fuel, we are of the opinion that conventional lignite fired power plants should have an availability of about 82% as compared to 85%, for conventional coal fired power plants.  NLC should be able to maintain the target availability level of 82% with proper handling of lignite to get rid of its impurities which cause slagging.

J.                  While going through the existing arrangements for charging the tariff in respect of NLC we found that the tariff is a single part-one without distinctly separating the fixed charges and variable charges.   This is the outcome of an agreement signed between the NLC and the beneficiary states.  In order to uniformly implement the ABT system in all stations, it is necessary to bifurcate and quantify the charges separately for capacity and energy.  This exercise was carried out based on the present tariff with data available in the agreement in respect of total charges and energy charges.  The difference between the total charges and the energy as per the agreement reflects the figure of fixed charges which could be quantified for the power station at 68.49% PLF by the commission staff with the assistance of NLC.  This has also been linked up with the data of fixed charges of power station as submitted by NLC in absolute figures.  Based on this data, the capacity charges per annum and variable charges per kWh for stage-II of NLC shall be reckoned accordingly.

K.                 As such, with effect from 1st April, 2000 the initial target availability shall be 80% in case of all thermal stations, 77% in case of lignite based stations and 85% in case of all bydro stations.  After one year, i.e. from April 1, 2001, the target availability will be 85% for thermal stations and 82% for lignite based stations.  The target availability for hydro stations for recovery of capacity charges was reduced in 199 from 90% to 85%, and shall remain unchanged for the year 2000-2001.  The target availability of hydro station for the further period would be announced by the Commission in due course.  The commission is hopeful that with in this period, the generators  will improve the performance of low performing units to reach the higher levels indicated earlier.  The immediate target is also an ideal for at least some stations who are below this level.  We are hopeful that in the background of actual performance of thermal stations it would be possible for these stations to reach the average target availability of 85% over this one year period.

The following is the summary of the targets now ordered:

Target availability for various types of plants (in percentages)

1st April 2000 to 31.3.2001

Thermal Coal/Gas






1st April 2001 onwards



To be notified by the commission

Issue 5:  Capacity Charges at Lower Levels of Availability

A.        Another incidental question, which has to be answered is with regard to the method of charging the capacity charges including ROE below the target availability levels.  Presently, there are different practices for different companies.  For instance, in case of NTPC at zero availability 50% of the capacity charges and ROE on pro rata basis are payable.  At levels from zero to 6 8.49% balance capacity charges including ROE are payable.  In case of NLC, as per agreement, charges are payable on pro rata basis from zero availability up to target level, which means that at zero availability to  target level, which means that at zero availability there is no capacity charge payable.  In case of NHPC,  the same practice as in NLC is adopted excepting in the case of two stations where an agreed rate prevails.  As regards NEEPCO the existing Tariff is a single part tariff for the energy delivered.  As per the draft notification, a distinction is made between fixed charges and ROE. Full fixed charges are reimbursed at availability of 30% and no fixed charges shall be payable at zero % availability.  Between zero and 30% pro rata fixed charges are payable taking 30% as equal to 100%.  Above 30% availability up to target availability (which is 70% as per the notification), pro rata ROE depending upon the actual declaration of availability is payable.  Many beneficiaries like KEB, AP TRANSCO, TNEB and DVC have stated that the availability of 30% is very low for reimbursement of full capacity charges.  Similarly,  ASCI has stared that the availability factor of 70% to recover full fixed charges is low.  ASEB has suggested pro rata payment of capacity charges below stipulated availability level.   In fact MPEB has suggested going back to the PLF basis for reimbursement of fixed charges as well.  NLC has suggested that in an integrated power and mine complex, fixed charges should cover even the cost of mining operations.

B.        As regards NLCs plea that the fixed charges of mining operations should also be considered, we have to state that mining operations do not fall within the regulatory jurisdiction of the commission.  In fact mining activities are being regulated by the Ministry of Coal.  The Commission cannot step in to regulate this activity. Hence it would only be possible to admit a transfer price for lignite for the purpose of tariff of power.  We have carefully considered all the other suggestions with regard to the levels for recovery of fixed charges and the ROE.  There has been practically no objection to zero fixed charges recovery for zero availability excepting that NTPC protested on the ground that this might deny a facility which was available to them so far.  We are convinced that the varying practices for charging capacity charges should end and there should be uniformity.

C         The payment of fixed charges at 0 through 30% availability has become a contentious issue.  Generating companies desired that this proposal should continue on the ground that they will be deprived of capacity charges in any such contingency, though none of them could submit facts and figures to show that any of their units were operating at these levels at any time.  The data on operations so far submitted do not indicate anything to this effect.  Even Nuclear Power Corporation, who raised the issue, could not provide any data indicating that their units were in this situation at any point of time.  In the circumstances, it is our conclusion that it is only a safety net which some of the generators would like to keep in contingency.  The decision regarding capacity charges at the two ends viz., zore level and at target level appears to be inevitable viz., that it shall be zero and 100% respectively.  The question remains as to what happens in the in-between stages.  The draft notification contemplates denial of ROE up to30% availability and pro rata ROE from 30% till the target level of availability.  We do not find any reason why the generator should be denied a return when he has made an investment.  The turn on equity should be seen as part of the capacity charges as it has been done all along and also as considered by the ECC.  This has been made specifically clear in para 5.2.2 of the Report while recounting the fixed cost  - one of the elements included therein is allowable return on equity.   This has also been the concept under the earlier KPRAO formula.  The ECC report also contemplates a pro rata payment of fixed cost by dividing the same by the total megawatts available i.e. a pro rata payment in relation to the level of availability.  We therefore, do not find any merit in deviation from the past practice of allowing fixed charges including therein the return on a pro rata basis uniformly for all levels between zero and target levels of availability.

The claim of NTPC that it was provided the facility of 50% fixed cost on zero availability and hence that should continue, cannot be sustained.  It is the their contention that in the draft notification, an alternate arrangement was provided in the form of a specific provision for prolonged outage.  It has also been found from data submitted that were no such prolonged outages in the past adversely affecting the availability of a station.  In multi unit stations, which is the general features, the station availability could still be maintained by operating other units.  Any prolonged outage is clearly an example, the  entire consequences of a cyclone may have to be borne by the consumers.

In the circumstance, we are not inclined to either consider payment of 50% fixed charges at zero availability or to make provision in the tariff for prolonged outages.  Thus, the full capacity charges including returns that may be due, will become payable at the target availability, level, while at lower levels the capacity charge recover, shall be pro rata.  At zero availability, no capacity charges shall be payable.

Issue 6: Treatment of Unallocated Share

A.        Another vexed question which has implications on sharing of capacity charges and which remains to be answered is the issue relating to allocation of central share to various parties or to any particular beneficiary state.  In this connection, the absence of specific distribution of unallocated power, the same shall be added to the allocated shares in the same proportion as the unallocated portion.  In the absence of specific distribution of unallocated power, the same shall be added to the allocated shares in the same  proportion as the allocated shares.   It is further contemplated that the beneficiaries may propose selling part of their allocated share to other states within/outside the region.  The beneficiaries may propose surrounding their shares or generating companies may enter into agreements with other states.  In such cases, depending upon the technical feasibility of power transfer and specific agreements entered into by the generating company with other states within/outside the region for such transfers the shares of beneficiaries may be reallocated for a specific period.  When such reallocations are done the capacity charges may be payable on the reallocated basis.   The beneficiary states will also have freedom for negotiating any transaction for utilization of their shares in which case though the liability for the beneficiary states will not charge, they may get an opportunity to trade.  Such bi-lateral arrangements can be facilitated also by the RLDC informing the beneficiaries about unutilized capacities.

B.     The draft notification while providing flexibility for shifting the burden of the  capacity charges also fastens the liability for capacity charges to the beneficiary states, who have the allocation.  With the expansion now taking place in the power sector, the liability for these capacity charges is being resisted by the beneficiary states.   It was also states.  It was also stated by some beneficiaries that allocation of 15%  is being done out of the installed capacity without taking the available  capacity into account.  It was suggested by some of the beneficiary states that unallocated share be allowed to be traded either through the RLDC or through the PTC.  The commission however, has to keep in view the historical fact that central thermal generating stations were established mostly at pit heads to facilitate catering to the states in each region.   It cannot at present ignore the specific commitments entered into between the CGS and the states constituting each region.  However, the possibility of entrusting the unallocated share to the power Trading Corporation thereby reducing the burden on the states as suggested by some of the beneficiaries could be considered by the government, with a clear guideline that if the allocation is not made the same could be traded.   In fact from the rejoinder filed by Union of India, it appears that the  Government is even willing to review the philosophy of capacity allocation.  In the view of the commission the concept allocation will have to ultimately go as.

                  a)     More capacities are added in all the regions

                  b)     The national grid facilitating inter regional flow is evolved

                  c)     The power trading corporation starts playing an active role

This may take some more time.  In the mean while, the facility of trading the allocated power would provide some flexibility subject to transmission facilities being available.  Taking these factors into account the commission considers the arrangement of fixed charge recovery in respect of unallocated power to be satisfactory and workable as obtaining today.

C.    From the replies submitted on this subject by GRIDCO, and TNEB, it transpires that the beneficiary states would not like to bear the capacity charges relating to the unallocated share it is contended that this cannot be charges to them without their prior consent or request.  The objection from the beneficiaries is that even though trading for the capacity entitlement is contemplated, the timing of the decision of the government o find makes all the difference as the opportunity for trading would be lost if the decision is delayed.  We find considerable weight in the argument and as such we recommend that the government may decide at least a month in advance with regard tot he allocation of the unallocated share based on availability so that trading of such capacity is facilitated and the burden on the SEBs is reduced.  Any decision on the allocation to the existing beneficiaries so long as it is taken in advance should be acceptable to them.  It is open to them there after to trade such capacity either within or outside the region.  The government may consider issuing a notification tot he effect that if no allocation of unallocated power is done by the end of the previous month the same may be taken as available for trading.  There after, the generator should be free to trade that power subject to frequency constraints, in case the government does not choose to entrust the unallocated share to power trading corporation as already suggested.

1.      While on the subject of trading, the commission anticipates an emerging situation of a surplus on account of the gap between the availability and scheduled generation.  This power could go unutilized as the capacity for this generation is blocked because the capacity charges are borne by the beneficiary states.  In order to economize operations, it would be appropriate to make use of this power on firm or non-firm basis with a suitable understanding between the beneficiary states and the generator.  It is therefore suggested that the generating company may initiate a dialogue with the beneficiary states for making use of this power for which the terms could be negotiated by the themselves.  Though, strictly speaking, this tariff also falls within the jurisdiction of the commission, due to the short term nature of this transaction the tariff could be freed to be negotiated for which a general exemption could be taken from the commission.  This would provide substantial additional revenue to the generator if he goes about aggressively marketing this surplus power.

 Issue 7: Gaming Possibilities

A.        With declared availability as the key factor for reimbursement of fixed charges and rate of return, the obvious question is about the over declaration of availability capacity.  There is also the possibility of under declaration which may facilitate earning undeserved UI charges.  In either case, this would amount to deliberate gaming which must be curbed.  This means the availability as declared should be subject to verification for its veracity.  This aspect has been dealt with by the ECC in para 5.2.7 of their report where it is said monitoring and enforcement of generation availability may be accomplished through auditing plant record and conducting  unannounced tests.  If a unit fails to reach the level of availability which was declared by the plant operator, the capacity charges should be reduced to cover the actual availability for that day.  The capacity charges should then stay reduced until a higher availability can be demonstrated.  If a unit fails in an availability test, severe penalty should be imposed, possibly retro-active for some period.

B.     The draft notification has dealt with this situation in para 7 under the head Demonstration of declared capacity.  This clause contemplates that a generator may be required to demonstrate the declared capability when asked to by the Member Secretary, REB of the region.  In case of failure to demonstrate, the capacity charges due to the generator shall be reduced as a measure of penalty. Similarly, if the declaration is observed to be on the lower side and the actual generation is more than the declared capacity then the UI charges due to the generator shall be credited to the UI account of beneficiaries in the ratio of their share in the capacity.

C.    Apprehensions were expressed regarding clause by various beneficiaries.  UPSEB has stated that the beneficiary should have a right to demand demonstration of declared capacity and also suggested periodical and surprise checks for declared capability.  Similar view was expressed by WBSEB.  DVC along with WBSEB suggested that in case of misdeclaration, capacity charges may be reduced for the preceding 30 days or from the date the availability was last demonstrated.  TNEB suggested a penalty of twice the capacity charge for misdeclaration apart from reserving the right to demand demonstration by any beneficiary. GRIDCO has stated that the procedure for testing and the quantum of penalty may be fixed once for all and should not be revised from time to time.  Similar view has been expressed by generators like NLC and NHPC.  Views have been expressed by NTPC and NHPC to provide for factors beyond the control of the generator in demonstrating the declared capacity.

1.      The need for demonstration and imposition of penalties has been accepted by all concerned in principle.  We have also looked at the relevant clauses of PPAs concluded with IPPs recently to see if there are any lessons from them.  The important issues on which we are required to rule related to - 

a)     Who can call for demonstration?

b)     Procedure for testing declared capacity?

c)     Exceptions if any for non-demonstration; and

d)     Consequences of non-demonstration.

2.      The plea of some of the beneficiaries for their individually and directly demanding demonstration is in our view, unworkable.  However, any beneficiary can, through the RLDC, call for demonstration in which case the RLDC shall immediately on such request, plan load  generation balance and after organizing consequential arrangements, call upon the generator to demonstrate.  It should h be ensured that demonstration is done within the shortest period commensurate with the ramping requirements of the machine.  RLDC may also reject repeated demands for such demonstrations, if in its option, repetition is not necessary and that it would only disturb normal grid operations.

3.      Regarding the procedure for testing declared capacity, the same has to be operated through the RLDC. We understand that it should be possible to issue instructions for demonstration from the control room of RLDC within a short time.  In additional, RLDCs shall prepare a standing procedure including a schedule for conducting tests in consultation with the REB concerned.  This shall be coordinated by the CTU.  The schedule of tests shall be such that stations, which have a potential for gaming will get tested at a periodicity to be determined by RLDC on a random basis.  RLDC shall maintain a record of all the tests carried out from time to time with full particulars.  In  drawing up the schedule, RLDC shall ensure that transmission network and other technical parameters are conductive for conducting the test.  Any corrective parameters in arriving at a final result of the test shall also be included in the standing procedure.

4.      The plea of some of the generators regarding allowance for factors not under the control of the generator has also been considered by us.  This of course depends upon the circumstances of each case.  The CTU, a statutory body, as the supervisor and controller of ISTS, can arrive at a final decision in this matter after the RLDC reports the findings of the test.  If any party is aggrieved by the decision of the CTU, an appeal can be made to the commission within 30 days. An additional responsibility on RLDC is to keep a close watch on any frequent revision of availability, which can be an act of gaming.  Such instances shall also be brought to the knowledge of CTU forthwith.

5.      The cost of testing shall be normally recoverably by RLDC charges from all beneficiaries.  When mis-declaration is established, the full cost of the test will be borne by the generator.  CTU shall submit to the commission within two months of this order the standing procedure including for determination of testing costs.

6.      We are in agreement that there should be deterrent penalties for non-demonstration of capacity.  In fact, ECC recommended retro active penalties.  This has also been suggested by DVC and WBSEB.  The Union of India in its rejoinder, has concurred with the views of beneficiaries on the procedure, demonstration and the need for penalty.  Keeping in view the financial implication of misdeclaration and as a deterrent for wrong declarations commensurate penalties have to be imposed.  We are also of the view that the servility of the view that the severity of the penalty  should be increased for subsequent wrong declarations.  The penalty has to have a relationship with the fixed charges for a day.  In case of misdeclaration the fixed charges have to be sacrificed.  As a measure of penalty, as suggested by TNEB, for misdeclaration for any number of blocks in a day, two days fixed charges shall be denied to the generator.  This can constitute the basic penalty for misdeclaration.  If this repeated for the second time, the penalty shall be double the basic penalty and shall be multiplied in the same geometrical progression for subsequent mis-declarations.  As regards under declaration, the penalty and the procedure for sharing the penalty as suggested in the draft notification shall be implemented.  In all these situations of mis-declaration the generator shall continue the operations as usual and shall not stop operation.

7.      It is also necessary to fix responsibility on specific individuals for wrong declarations.  For this purpose as in the case of occupier under the factories act, the officer in charge for declaration of capacity has to be identified and informed in writing in advance to the RLDC which shall incorporate the details in the records maintained by them.  In case of consistent misdeclration beyond five times in a year, apart from the penalties contemplated as above, action for non-compliance under section 45 of ERC Act could be contemplated.  A suitable clause in the relevant portion on standing procedures shall be inserted to this effect by the CTU.

Issue 8: Unscheduled Interchanges

A.        The ECC study team has elaborately dealt with the need for UI charges in order to stabilize the frequency in the regional grids and to minimize extreme deviations in the frequency.  A special task force constituted by the study team has observed that while inadvertent UI could be accepted and tolerated as a necessary feature of pooled operation, the deliberate UI should be discouraged.  Therefore, there appears to be a need to apply a mandatory pricing scheme to scheduled inter changes in India.  (Para 4.6.2).  the study team has stated that it is unaware of experience with pricing UI in the Western countries.  The study team believed that a comprehensive UI tariff which is based on bother  deviations from schedules and deviations from frequency is required to improve the Indian grid discipline and quality of supply.  Accordingly, the study team recommended that tariff for unscheduled inter change should be based on the principles of the grid control-linker UI Tariff with addition of a frequency sensitive component.

B.     The consensus of the task force constituted by the ECC study team was that the price of UI during power shortage conditions should be high enough to provide an economic signal to those pool members who are causing the problem other members of the pool who may be deprived of power should be suitably compensated for any financial losses.  The commercial mechanism should be reinforced by the enforcement f the provisions contained in the grid code, violation of which, will lead to penal consequences.  It has been observed that in India though the declared frequency is 50 Hz, there are instances of wide variations in the frequency in different regions with frequency going down as low as 48 Hz as well as going up as high as 53 Hz, which are not in the interest of any participant in the pool, permissible variation being 3% which means 48.50 Hz to 51.50 Hz.  This variation is with in the provisions of Indian Electricity Rules, 1956.  However, in order to ensure integrated grid operation of all the 5 Regional Grids, it is essential that the frequency hovers around 50 Hz.  This, in due course could lead to an All India grid facilitating transfer of bulk power between  states and the regions.  This would in turn lead to a balanced power supply position in the entire country and to an integrated national grid.

C.    The draft notification contemplates planning the generation drawal through a process of scheduling.  After considering the declaration by generators of this availability and requisitions from the beneficiaries.  RLDC is required to prepare the generation and drawal schedules in advance after taking into account the transmission losses.  This schedule is to be finalized each day for the following day starting from 00 hours separately for 96 time blocks of 15 minute each .  It is expected that the schedule of generation and drawal shall be observed by the respective parties with flexible granted to modify the schedules will advance notice and with exemption in appropriate cases like grid disturbance, transmission constraint, grid safety etc.  Any variation of the actual generation or drawal from the schedule shall be liable to a special UI charge payable / receivable by parties concerned.  This charges is reckoned with reference tot he frequency of the grid at which the deviation takes place.  It is possible that a deviation sometimes is favourable or unfavourable to grid operation.  Depending upon whether a utility is helping or adversely affecting the grid, UI changes will he receivable payable.  A proper metering arrangement needs to be provided so that deviation in each time block is clearly and shall be billed accordingly.

1.      Even though in National Task Force, all parties have agreed in principle to the sys tem of UI charges, apprehensions of generators were expressed before us both by generators on this system.  The apprehensions of the generators are on the following lines:

a)   NTPC has suggested a specified ramp rate to be considered for special changes in generation schedule during various time blocks.  It has also suggested that to achieve the objective of economy and efficiency, in the utilization of resources, regional merit order for all generators in the grid has to be ensured.  This of course has been already dealt with by NTF decisively.   It further suggested that revision of schedules in case of forced outages should be allowed without any provision for communication time gap.

b)    NLC suggested that revision of schedule should be allowed and accepted even if not communicated to RLDC due to inability, but if passed on through SEB, it should be accepted.  There was also a suggestion that exemption from the discipline of schedule which is permissible on grid disturbance should be available on certification by REB. NLC has further suggested that the time gap for revision by generators or beneficiaries should be  reduced from six time blocks to fur time blocks.  It is also stated that RLDC should not revise the schedule without consultation.

B.                 Number of objections were also received from beneficiaries when are  summarized below:

a)      The time block of 15 minutes should be revised to one hour (MPEB) and three hours (UPSEB)

b)      Operating procedure for generation schedule should be as per the decision of REB (WBSEB).

c)      Technical limitations contemplated in the UI Scheme to be decided by REB (WBSEB).

d)      Any revision in the event of forced outage of the unit should be allowed and the generating company should compensate SEBs for commitment already made (TNEB).

e)      In the Event of transmission constraints, UI charges should be paid by the transmission utility to the generator (TNEB, WBSEB).

f)        Time for normalization of grid following grid disturbances should be 15 minutes (TNEB) and grid disturbance should be defined (WBSEB); in the event of grid disturbance, availability should also be revised (UPSEB).

g)       Revised schedules should become effective only after successful communication from RLDC (NTPC, NPC, DVC, Gridco and WBSEB).

h)      Any defaulter generator, whose failure calls for post facto revision should pay for UI charges (WBSEB).

2.      Another major objection is that payment shave to be made for scheduled energy apart from paying UI charges, though actual energy drawn may be less.  This in our opinion is a baseless apprehension.  If there is self discipline and advance planning, such a fear of huge payment on account of scheduled drawl is unfounded.  Adequate opportunity is available for revising schedule within 1 ½ hours notice; the daily planning should also be done with or foresight.  This system of discipline should settle down over a period of time.  It should also be noted that in also be noted that in case of high frequency the beneficiary can get free power.  Thus the scheme is evenly balanced.  We have carefully considered all the above objections. These are being dealt with hereunder.

3.      The provisions regarding scheduling as contained in para 4 of the draft notification contemplate three situations for revision of schedules:-

i)    A forced outage of a unit of the generator in which case revision of schedule will be allowed effective from the 4th time block from the time of advice of outage.

ii)    Request for revision of declared capability by generator and revision of drawl schedule by beneficiaries in which case the revisions will be effective from the 6th time block from the request for revision.

iii)  Revision due to factors other than those attributable to the generators or beneficiaries viz.

a)   Bottlenecks in evacuation of power due to constraints or limitations etc.  in the transmission system in which case RLDC will revise the schedule to be effective from the 4th time block in which the bottleneck occurs.  In this case for the earlier three time blocks also the schedules will be deemed to have been revised to actual.  Bottleneck shall have to be certified by RLDC.

b)   In case of any disturbance the schedule of generation and drawls’ shall be deemed to have revised for all the time blocks affected by grid disturbance.  Certification of grid disturbance and its duration shall be done by RLDC.

c)   If any point of time RLDC observes need for revision of schedule for better system operation, it may do so and it shall be effective from the 4th time block.

It can be from the above that in case of situation © above, the factors are beyond the control of generator or beneficiary and as such responsibility is cast upon RLDC to certify.  However, RLDC shall adopt certain norms for the certification/revision which we shall deal with later.  In capacity charges as these are beyond the control of generators.

In case of forced outage of a unit at the request of the generator the declared capability not only affects the schedule of generation but also impairs the recovery of capacity charges.

It can be seen from the above that wherever a generator revises the schedule on his own, his declared capability also gets affected, resulting in impairment of recovery of capacity charges.  For beyond control  of the generator, if revision takes place, it is unfair to deny the declared capacity to him. 
As such, the claims of some of the beneficiaries for revision in this regard are unfair.  The time limits for communication for revision in the different situations is also fair keeping in view the circumstances for revision including any revision on account emergency reasons and the same is applicable irrespective of communication success.  In fact it should be possible with more familiarization of the system of the system to reduce the time gap for corrective action.  This appears to be the international experience.  Any unforeseen difficulties in the operation of the sys tem have to be sorted out as and when such situations may arise but the proposition otherwise appears to be fair to all parties concerned.  Further, the detailed scheduling as per the Grid Code shall be adopted in operation the UI system.

4.      Para 2 (iii) of the draft notification deals with the rates for UI charges based on the average frequency of reach time block.  The proposed rates at the two ends viz., 50.5 Hz and above on the one had and at 49 Hz on the other have been stated as .0 paise/KWh and 360 paise /kWh respectively.  Between 50.5Hz and 49.00 Hz adjustment of 4.8 paise/kWh for each 0.02 Hz change is proposed.  It is noted from the documents given to us that the rate was initially pegged at Rs. 6 / kWh which was subsequently revised in the draft sent by Cea to MOP as Rs. 4.5/ kWh based on the 9th NTF meeting.  This for arriving at the UI rate was however not found in the documents.  Since UI rate is proposed for over drawals/under generation during low frequency period and under drawal/over  generation during high envisages that UI rates should be separately notified from time to time which means that any revision in diesel prices could be incorporated and UI charges revised accordingly.

We however, do not consider, it necessary to provide a special ramp rate as claimed by NTPC since the time schedules provide for sufficient flexibility for the purpose.

Subsequent to the notification, there has been an increase of about 33% in the diesel prices.  Consequently a revision in the  charges is warranted.  The original proposal of 360 paise /kWh has been considered as the total cost of generation of power through diesel which incorporates in itself on our reckoning two elements viz., capacity charge of Rs. 1.60 / kWh and variable charge of Rs. 2 /kWh.  Applying the recent revision of diesel price, the variable charge goes up to Rs. 2.67 per kWh resulting in a total value of Rs. 4.27 kWh, which may be rounded off to Rs. 4.20/kWh at 49.00 Hz.  As such the charges are approved. The commission may review the charges as well as the corresponding frequency levels as and when necessary.

5.      Another point for consideration is whether charges for over drawl should be the same at 49 Hz and even below 49 Hz.  It should be noted that the declared frequency in India is 50 Hz.  An integrated power system should operate with a grid frequency hovering around 50 Hz.  In practice however, the frequency range in India has been 48.5Hz to 50.00 Hz.  This is not desirable for achieving interconnected/integrated operation of the grid.  With the additions to generation capacities it is hoped that there may not be a drop below 49 Hz.  Further the disincentive at 49.00 Hz is in itself a deterrent; and there is no need to make any provision for still lower levels of frequency at high rates.  In the circumstances, we consider that the charges as proposed in the draft notification subject to the revision on account of diesel prices is considered appropriate.  We are hopeful that with more self discipline contemplated by the scheme, frequency would be kept within permissible range.  In fact the attempt should be to further narrow down the range with more generating capacities coming up and redundancy created.

6.      We also considered the possibility of prescribing separate frequency limits for different regions.  This may involve deviating from statutory expedited and demand side management would be given more importance.  Besides, inter regional flow could be facilitated.  Hence we are not inclined to prescribe differential frequency limits.

7.      The operation of the UI mechanism is proposed to remain suspend during the period of transmission bottleneck grid disturbance etc., till the revised schedule becomes operative.  Apart from this, certain exemptions have been contemplated under para 5 of the Notification.  A special dispensation has been given for gas turbine/ combined cycle stations and for nuclear stations to provide correction in the schedule generation by the certain percentage where the frequency is below  49.02 Hz.  This special dispensation appears to have been considered based on the special nature of their operations.  Against this exemption, NPC  has sought a total revision of scheduled generation so as to be equal to actual generation even if the frequency variation is more than 2%.  The reason given by NPC viz to protect NPC from the liability of payment of UI is not convincing  and as such no further exemption is warranted.

The notification under para 5(b) also contemplates exemption from UI for hydro stations.  We do not find any justification for this exemption or denial of UI to hydro stations.  As such, the special exemption from UI for hydro stations needs to be deleted.  It is the Commission’s considered view that all the generators should conform to be UI discipline unless exceptional c circumstances warrant special treatment for which a case could be made before the commission separately.

8.      Some reservations have been expressed by beneficiaries on upsetting of schedules on the plea of grid disturbance which has not been precisely defined.  This will have its implications on capacity charges and incentives.  Sometimes, instances of gird disturbance may be internal to be beneficiary which cannot be the reason for suspending the UI.  A reference to grid disturbance should be attributable to the disturbance of the regional grid.  Even here some of the instances which have come to the notice commission are:

a)     When the regional grid splits into two big islands;

b)     When generation at central generating stations gets affected due to tripping of a  number of transmission lines without substantially affecting integration of the grid;

c)     Isolation of small parts from the grid or events within the control of beneficiaries affecting only the drawl pattern of the beneficiaries.

There may be several instance of grid disturbances.  Similarly transmission bottleneck is also a very wide are wherein it is possible to fix responsibilities on the party concerned at fault.  All this casts a great responsibility on RLDC while doing the certification certification therefore should not be granted in case RLDC considers that the situation has arisen out of any party’s fault.  The same should be reported to the CTU so that the latter can deal with the same appropriately.  This should take care of any gaming possibilities at the beneficiaries end with the objective of earning undue UI charges.  RLDC shall be vigilant against such practices.  In case any matter needs to be settled before the commission, subject to CBR , it shall be the responsibility of CTU to bring it up with notice to the other side.  It is also necessary for the CTU to announce in the course a detailed procedure to the followed for suspension of UI scheme on account of any grid disturbance or bottlenecks in transmission.  This procedure shall also cover recovery from grid disturbance in line with the grid code.  As and when the recovery takes place. RLDC shall notify all the constituents as well as outside the region, sufficiently in advance (at least 4 time blocks in advance) in order to resume the UI.  The role of REB was questioned by some parties.  Since the questions are not in conformity with the legal provisions, they cannot be accepted.  Regarding the claim for payment of UI charges by transmission utility, specific instances of dereliction on the part of transmission utilities can always be brought up.  The default on the part of a generator resulting in revision of schedule would have its own consequences on the generator.

9.      We have also considered the views of some of the beneficiaries to change the time block of 15 minutes.  We are convinced that a short time block of 15 minutes can be expended to ensure alertness on the part of the dispatcher to take quick corrective action for maintaining desirable system parameters. If the interval is larger, there may be a tendency to defer the action with possibilities of steep frequency excursions thereby inviting damages to the system.

10. We draw the attention of the CTU the following responsibilities viz.:

a).      To ensure proper recording of two way communication regarding revision of schedule;

b).      To minimize the time taken by RLDC for revision of schedule so that the impact of UI charges could charges could be kept to the minimum;

c).      To formulate a procedure for meeting contingencies both in the long run and in the short run (daily scheduling);

d).      To announce the procedures for temporary suspension and resumption of UI scheme.

The commission directs CTU to devise procedures in the above regard and inform all concerned within two months of this order.

Issue 9: Billing, Payment and Operation of Pool Accounts

A.        Para 9 of the draft notification deals with billing and payment of capacity charges.  This is proposed to be done on a monthly basis whereby each beneficiary shall pay capacity charges in proportion to the allocation.   The para also deals with the unallocated portion, which we have covered already.  It also deals with the method of charging and recovering on a cumulative basis the capacity charges, though basically it is monthly charge.  The recovery from the beneficiaries is proposed on a monthly  basis taking into account the weighted average percentage of allocated share of the beneficiary on a cumulative basis.  The year is taken to be the financial year so that no carry forward is taken to the next year.  This proposal appears to be fair and acceptable to all.

B.     Certain suggestion have been received during the proceedings on the subject, which are summarized below:

1. Monthly capacity charges for hydro stations should be withdrawn or the party getting the allocation should pay capacity charges (NHPC)

2. In determining the saleable energy  for hydro power, the free power to home state should be borne state (TNEB); should be borne by the generating company (EVC).

3. Either specific allocation of unallocated power should be withdrawn or the party getting the allocation should pay capacity charges (TNEB, DVC & Gridco)

4. Reallocation of shares should be with the consent of generating company (NLC).

5. Surrendering of shares may be permitted only long term basis (NTPC).


We have considered these objections.  As regards capacity charges for hydro stations, we consider that the present arrangement should be continued in the interest of simplicity of the system of charging.  Regarding free hydro power to the home state the existing arrangements based on agreement can not be wished away and the free element becomes part of the cost to be taken into account for tariff.  Regarding unallocated power,  the arrangement proposed in the draft notification is satisfactory.  As regards surrendering of shares we are in agreement with the suggestion of NTPC.  However, this matter relates to the government for its decision for reallocation of shares.  We have already covered these issues, regarding unallocated shares in this order.

C.   The third element viz. the UI charge, is proposed to be settled through a regional pool account to be operated by the member secretary of REB.  Detailed procedure in this regard was proposed to be laid down by the central electricity authority from time to time.  From the correspondence on files, it is found that Cea has proposed a broad outline of procedure for operation of the regional pool account by which:

a)     The billing for UI payable shall be done by REB to various parties;

b)     The parties shall pay the UI charges within 15 days of billing;

c)     Can delay in payment shall attract interest @ 2% per month;

d)     Any money received on account of UI to be distributed to the claimants pro-rata to their claim; and

e)     Any undue delay in payment will attract the extreme step of regulating the supply.

D.        The above proposed system of operation of pool account does not appear to be satisfactory.  The UI charge is not in the nature of penalty but is part of the tariff as contemplated in the notification.  As tariff, it constitutes the income/expenditure of the utilities concerned.  As such it will have to be included in the revenue accounts of the utilities in pursuance of the accrual system of accounting which is a statutory requirement and can not be kept unaccounted outside its books.  With the possibility of all the utilities ultimately becoming corporate bodies, this is a necessary accounting requirement.  Any outstanding UI charges at the end of each year has to be reflected in the balance sheet of the utilities concerned as asset or liability as the case may be.

The pool mechanism was contemplated perhaps on account of the difficulty in relating the receipt and payment on one to one basis, between the receiver and the giver of the UI.  Though the solution suggested appears to be simplistic it goes against the principles of accrual accounting particularly when it is recognized as part of the tariff to be received or paid.  Further a one-to-one identification cannot be totally avoided.  As more and more utilities join the pool, the accounting task would be stupendous.  ON a sample basis the UI calculated for Eastern Region for a typical day in March, 1999 worked out to Rs. 99.44 lakhs.  Thus the amount 8involved is substantial, unlike a penalty element, alone which may be small.

Any party, who is to receive a tariff has to raise a bill for the tariff.  If the bill for UI is raised by the REB the question is whether it would constitute the income of REB?  Similarly do any outstanding charges have to be shown as the assets of REB?  This however, is not the correct position.  REB is only carrying out the function of a clearing house.  In that case it would not appear as asset or liability of anyone REB should not take up the financial responsibility for managing the funds of the utilities unless it is specifically agreed to by all parties concerned.  In this connection, NTPC has suggested that since it would be the net receiver of UI it may be adjusted in the energy bills of NTPC instead of merging he same in the pool account.  Thus the proposed arrangement does not have the concurrence of NTPC.

By resorting to the system of pool account, the task of identifying the UI charges on a one-to-one basis is only postponed but not finally resolved.   Under the proposed arrangement any portion of UI as and when received is to be distributed pro rata to the outstanding of all parties.  Alternatively from the records, it should be possible to link up over drawals and under drawals on a regular basis.  This can be adjusted on every 48 hour basis from control room readings.   In this way composite scheme can be evolved by which at the end of the month the balance portion for distribution of the UI could be finalized by the REB.  The arrangement  has to be organized by the RLD in consultation with REB.  The net UI charges after these regular adjustments should be distributed, billed and paid at the end of each month.  This accounting system should be worked out by CTU in consultation with all the beneficiaries and could be put in position in the next three months time so that when the ABT is implemented the method of distribution is also finalized.  Based on the distribution of UI at the end of each month as advised by REB bills can be raised by the utilities including the generators against each party so that any outstanding can be pursued by the respective parties as a commercial debt rather than left to the REB to sort out.  The utility concerned can also initiate steps for recovering the dues as considered appropriate.  This would also enable reflection of a true and fair view of the income/expenditure and assets and liabilities of the various  utilities.  This will also enable the generators to justify their sales based on bills duty raised.  This system may also obviate any difficulty on account of sales tax or other levies which may be payable on tariffs of generating companies.  The setting out of a fool proof system was assigned by us to the CTU in the grid code order accordingly the CTU should in consultation with all concerned down the procedure for distributing the UI charges.

Issue 10:  Metering Arrangements and Programme of Implementation

.A.       A number of parties who deposed before us have stated that the ABT should be enforced only after proper metering, telemeter and associated hardware and software is commissioned.  It is stated by MPEB that, in the western region, the ABT cannot be implemented unless the special energy meters are installed.  It is also suggested that after the installation of the meters there should be some time allowed to conduct mock exercises.  It is also felt in some quarters that the joint meter reading would be a mammoth exercise which goes against the practicability of implementing ABT with 15 minute interval for UI charges.  We however understand that the metering system does not involved elaborate manual reading.

B.     We understand that the metering arrangements are primarily confined to the special energy meters which measure both energy flows and frequency over 15 minute time block to enable working of the UI charge.  It is understood from Powergrid that these meters have been procured and installed in consultation with all concerned.  According to the Union of India, meters are already in place in the southern region, Eastern Region and North-Eastern Region.  Meters in Northern and Western Regions are yet to be installed.  According to the Union of India in its region, Eastern Region and exercises may not serve much purpose.  However, it would be necessary to ensure that all the meters are in place and the procedure for collection, reading, decoding of data and software for accuracy are made operational.  Trial run for these should take place to trouble-shoot these procedures before actual implementation.

During the hearing NLC has expressed certain apprehensions about the metering arrangements.  However, it will not be possible for the commission to check the adequacy and reliability of the metering arrangements.   This will be the responsibility of the CTU.

C.    On a consideration of the above facts and submissions we find that the Southern and Eastern Region are in readiness for implementation of the ABT.  PGCIL has clarified that the meters for Northern Region are already ordered and the specifications for the meters for the Western Region are in the process of finalization.  As regards North-Eastern Region, though the meters are stated to be in position,  according to the ASEB, it is not possible to implanted ABT due to the presence of certain agreement for single part tariff.  Keeping all the above we consider that the CTU/Powergrid should take on hand the complete responsibility of installation, testing and trial run of the metering arrangements.  As regards North-Eastern Region it may not be possible in view of the special situation to implement ABT in the present from.  However, it is not clear as to how exactly the region would like to proceed in this matter.   Therefore, it is appropriate that NEPCO should come forward the a petition, with all concerned parties as respondents, on the programme for implementation of ABT.  This shall be done within a month from the date of receipt of a copy of this Order.

1.      In View of the special request of Powergrid/CTU to stagger the Implementation of ABT so that they will be able to make satisfactory arrangements before implementation the following schedule for implantation of ABT shall be followed:-   

Southern Region                 -           1-4-2000

Eastern Region                    -           1-6-2000

Northern Region                  -           1-8-2000

Western Region                   -           1-10-200

We understand from Powergrid/CTU that this schedule is practicable.

As already, stated as an interim arrangement after 1st April, 2000 till the introduction of ABT the PLF excluding deemed generation for calculation of incentives shall be 80% instead of the present including deemed generation in East, North and Western Regions for Thermal stations, 77% for lignite and 85% for hydro stations.


Issue 11:  Applicability of ABT to Hydro Stations

A.     None of the utilities represented before us have contested the applicability of the ABT to the Hydro sector.  However, questions have been raised regarding the manner of application to Hydro stations taking into account the special features of hydro operations as compared to other systems of generation.  For instance, ASEB has stated that there is duplication of elements considered for energy charge and capacity charges.  DVC  has stated that hydro units should also pay UI charges if actual generation is less than schedule generation in case of frequency below 49.5 Hz, though the draft notification exempts them from UI charges.  ASEB has objected to the payments for deemed scheduled generation on account of spillage of water.  RSEB has suggested a review of the formula for determining availability by eschewing any capacity not available for peaking.

B.     A number of suggestions have been received with regard to the valuation of secondary energy.  NHPC has questioned the valuation of secondary energy.  RESEB has suggested that the secondary energy relates for hydro stations should be les than the lowest variable cost on thermal power stations and proposed a rate of 15 to 20 paise per kWh.  DVC  has suggested that the energy charges for hydro stations should be limited to 30 paise per kWh which is equal to the UI rate at 50.2 Hz as per the UI scheme suggested by it. NHPC has also suggested modifications in the reckoning of sent out capacity for hydro stations for working out the availability.  According to it though total actual generation may be limited to Design Energy, any loss of generation due to reason not attributable to the generator should also be included for determining availability.

We have gathered from the minutes of the National Task Force that till their last meeting they could not come to any definite conclusions on the treatment to be given to hydro stations in the ABT system.  At the instance of NTF, CEA constituted a committee on Time of day metering and peak load Pricing, which was later reconstituted as committee on hydro tariff.  The committee finalized its report but the same could not be taken up by the NTF.  This committee had considered the recommendations of ECC in regard to tariff for hydro stations, apart from the proposals of BHPC.  The following are the major recommendations this committee, which we consider as relevant for our purposes:

1.  The hybrid tariff structure comprising of capacity charges and energy charges should be continued,  however, the method of bifurcating energy charges shall be on notional variable cost of thermal station.

2.       The following two alternative computations for bifurcating energy charges were recommended:

a)     Rate for primary energy for all hydro stations except for pumped storage stations to be take n as 90% of the lowest variable charges of the thermal power station of the concerned region.  Total energy charges may be computed on the basis of the rate and saleable energy of the project.  This is intended to facilitate merit order dispatch; or

b)     The rate for primary energy during peak and off-peak to be taken as 90% of the highest variable charges and 90% of the lowest variable charges of thermal stations of the region respectively.  After determining the quantum of peak energy, balance saleable energy should be taken as off-peak energy. Total energy charges shall be computed on the aforesaid rates and corresponding saleable energy figures.

3.       In case the energy charges exceed the total annual charges, 50% of the annual charges may be recovered as energy charges and in case of second alternative the rate for peak and off-peak energy may be reduced proportionately.

4.       The rate for primary energy may be computed for each project on the above lines and may be reviewed every year.

5.       The balance amount after deducting energy charges as referred to above may be recovered as capacity charges.  In case the actual availability happens to be lower than the target availability the capacity charges may get reduced on pro-rata basis.  The capacity charges may be recovered from the beneficiaries in proportion to their entitlement.

6.       In case of actual availability being higher than the target availability incentive will be payable.

7.       The parameters for target availability and rate of incentive for higher availability to be finalized separately.

·         We have considered the special treatment granted in the draft notification under para 3(b) and 6(b) with regard to hydro stations.  We have also considered the replies from various utilities as well as the recommendations as summarized already of the committee on hydro tariff constituted by the CEA.  We consider the committee’s recommendation to bifurcate the energy charges into peak and off-peak based on the highest and lowest variable cost of thermal power station of the concerned region respectively as sensible keeping in view the need for promotion of hydel generation as well as avoidance of backing down of hydro station when they are really required.    However, this has to wait till our detailed consideration of peak and off peak pricing of power.  A study on this subject is in progress.  We do not advocate the arbitrary splitting of the total cost into capacity charges and energy charges.  However, since a two part tariff is essential for ABT the procedure for bifurcation as suggested by the committee under alternative a as already referred to in para 5.12 (ii) should be implemented.  This would facilitate merit order dispatch for hydro stations.  The balance of total charges in any case would be recovered as capacity charges.

·         As regards determination of sent out capacity and availability which are covered in para 5(b) and 6(b), the following are our findings:     

1.      Since the hydro stations are willing to submit to the discipline of UI there is no need for a special treatment at extreme low or high frequencies.  Hence hydro station should also be subject to UI mechanism at all levels of frequency.   However in order to prevent undue earning of UI charges, the hydro stations shall be obliged to revise their scheduled generation in case of higher inflow of water.  In other words, in monsoon season on any sudden increase in flow of water the scheduled generation shall be deemed to have been revised and the hydro stations shall inform RLDC accordingly.

2.      it shall be ensured that by declaring capacity above designed energy and actually generating above designed energy a situation of more than 100% availability is not brought above which of course is presently covered by the notification.  It shall also ensured that the Declared Capacity does not exceed the Installed Capacity of the Plant.

3.      Regarding the pricing of secondary energy we are in agreement with the contentions NHPC that the same should be priced as primary energy.

4.      We are convinced that the proposal as contained in the draft notification read with this order shall ensure (a) full recovery of all costs and (b) provide scope for incentive on better performance as well as on secondary energy.

5.      The method or reckoning the incentive shall be based on the actual PLF and not on availability i.e. the same procedure as for thermal stations shall be adopted.

6.      Apart from the above  which are specific deviations from the draft notification, the rest of the features of the notification with regard  to hydro stations stand approved.   

                                                                          i.      There is no separate provision necessary fro tariff of pumped storage stations because the underlying idea tariff proposals is that the full cost would get recovered either in the form of energy charges or fixed charges.  With the bifurcation of variable charges by adopting the lowest available cost of thermal station in the region,  it is only necessary to add thereto the cost of pumping as part f the variable charges.  Hence a separate Tariff treatment is consider unnecessary.

                                                                        ii.      The objection of ASEV with regard to the bifurcation of cost into fixed and variable has been already taken into account.  Regard in the other objection of ASEB on compensation for water spillage, it has been adequately dealt with in notification as the underlying principle is that compensation has to be made upto the design energy.  However, the reason for this spillage have been restricted to low system demand or constraints in transmission system or any other reason not attributable to the generator which means the spillage is virtually a capacity charge.  As regards the objection of DVC on exemption of hydro units from UI charges, the same has been taken note of by us and hydro stations shall also be liable to pay UI charges.  We understand that it should be possible to schedule the generation even by run of the river station with the facility to revise the schedule within six time blocks.  Regarding the objection of capping the secondary energy, the same has been already taken care of in this order.




1.      Following improvements have been brought about in operation of regional grids by ABT:


(i) Grid frequency has dramatically improved from 48-52 Hz range to 49.0-50.5Hz range for most of the time.


(ii) A higher consumer demand is being met, due to built-in incentives to maximise generation in peak-load hours.


(iii) Generating stations are being operated according to real meritorder, on region-wide basis, through decentralized scheduling.


(iv) Hydro-electric generation is being harnessed more optimally than done previously.


(v) States’ share in Central generating stations have acquired a new meaning and grid discipline is encouraged.


(vi) Open access, wheeling of captive generation and power tradinghave been enabled by placing in position the mechanism (UI) forhandling deviations/mismatches.


(vii) States meet their occasional excess demand by over-drawing from the regional grid and paying applicable UI charges to the under-drawing States.


2.  The intra-State generating stations are not yet on ABT, due to which opportunities for further optimisation are being lost. For example, the intra-State stations (other than those owned by the still-bundled SEB) have no incentive presently to maximise their generation in peak-load hours and to back down during off-peak hours. They are also not induced to respond to grid contingencies. Scheduling disputes between generating stations and State LDCs could arise, particularly in case of IPPs. With the present focus on commercial aspects, it is very desirable that ABT is applied to all intra-State stations (except those embedded in vertically bundled licensees’ systems) as well, whether SEB-owned or otherwise, for optimised utilisation of intra-State resources.


3. Optimum utilisation of pumped storage capacity is another area of concern. The 4x100 MW Kadamparai scheme belonging to TNEB has been fully utilised since introduction of ABT in Southern Region. Water is pumped up in off-peak hours when UI rate is low, and power is generated during peak-load hours when UI rate is high. On the other hand, in the absence of intra-State ABT/UI in Maharashtra, a similar commercial signal is not available to Tata Power, and their 150 MW Bhira pumped storage scheme is still not being utilised optimally. Srisailam pumped storage scheme in Andhra Pradesh too has not received due priority, as APGenco has no UI.


4. The foregoing has been duly appreciated by the Central Government and the following has been stipulated in the National Electricity Policy notified on 12.2.2005:

5. The ABT regime introduced by CERC at the national level has had a positive impact. It has also enabled a credible settlement mechanism for intra-day power transfers from licensees with surpluses to licensees experiencing deficits. SERCs are advised to introduce the ABT regime at the State level within one year.”


6. As and when an SEB is unbundled and the State’s distribution system is divided into zones, it would be essential that each zone has a schedule for power that it is to receive through the State grid. The intra- State system would then look very much like the present regional system : a number of generating stations supplying power through a transmission grid to a number of beneficiaries, with scheduling, metering and energy accounting carried out by a load dispatch centre. It would only be logical to replicate the regional system (of shares/allocations, scheduling, metering, UI, etc), which is already tried and proven.


7. The UI liability of a State, after unbundling, would depend on judicious scheduling for the intra-State entities and their dynamic response. This can all be centralised at the State LDC adopting a disciplinarian approach, but it has the risk of being resisted and flouted. Highly reliable communication, SCADA, AGC etc would also be required, with associated cost and complications. A more pragmatic approach, therefore, would be to delegate the responsibilities to the intra-State entities for decentralised action, with UI mechanism providing the required frame work for keeping all entities on track. In other words, it would be desirable to apply UI on all intra-State entities which are

supposed to have a schedule.


8. While for a total compatibility with the system presently operating at the inter-State (regional) level, it would be desirable to adopt the same system in-toto for intra-State entities, it is recognized that there could be valid reasons, State-specific, to deviate from the regional mechanism. It is recommended that the concerned SERCs examine the following issues in detail, in association with the respective SEB/STU and pragmatically decide their approach.


9. Structure and components of ABT:

The present ABT for Central generating stations comprises of three (3) components : capacity charge, energy charge and UI. This structure is rational and appropriate for the conditions prevailing in India, and should straight-away be adopted for all intra-State generating stations. However, incentive may be linked to plant availability, instead of linking to PLF (as is presently done for Central Stations). Linking of incentive to PLF effectively converts the incentive into a supplementary energy charge, and distorts the merit order. Most Central stations being pithead (and, therefore, not being required to back down during off-peak hours), do not face a major problem on this account. On the other hand, many intra-State generating stations would be at load-centres and/or will be liquid fuel-based. They would have a high variable cost, would often be scheduled to back down during off-peak hours, and would, therefore, have a lower PLF. Linking of incentive to PLF in their case would be counter-productive and it would only be logical to link the incentive to plant availability. Para 144 and 145 of CERC order dated 29.3.2004 in petition no. 67/2003 may also be seen in this connection (copy enclosed). Certain issues have come up recently in ABT for Hydro stations, particularly in NER. It is suggested that SERCs may exercise caution while extending ABT to intra-State Hydro stations, or wait for resolution of these issues by CERC (for Central stations).


10. Norms and parameters for tariff:

Various norms and parameters in the present ABT for Central generating stations have been fixed by CERC primarily considering the past performance of NTPC and NHPC plants. It is possible that the performance level of the intra-State power plants, due to a variety of factors, may not match those of NTPC and NHPC. In such cases, it would be appropriate to adopt different norms and parameters, atleast for a transition period. CEA have also prescribed certain norms recently, and these too may be considered by SERCs.


11. Treatment of secondary oil consumption It has been a practice so far in India to treat secondary oil consumption as a component of energy charge. However, secondary oil is consumed only when a coal/lignite-fired unit has to back down below about 60% or has to be started up/shut down. During normal operation, secondary oil should not have to be fired at all. In other words, during normal operation (above 70% load), the variable cost of a generating unit would comprise of only the coal cost. In order to get the energy charge to reflect the unit’s correct variable cost (and thereby to give the unit a better merit-order position), it would be desirable to treat secondary oil consumption as a component of plant’s fixed cost, and recover it through capacity charge instead of energy charge. This is particularly important for load-centre stations which would be required to back-down during off-peak hours due to their comparatively higher variable cost, and may be considered by SERCs at an appropriate stage.


12. Relationship between capacity charge and plant availability is should be such that the incentive may be linked to plant availability. Once this is done, incentive can as well be merged with capacity charge. The relationship between capacity charge payment for the year and average plant availability can then have three possible shapes, that can be easily derived.


13. Time block for UI In the inter-State ABT, UI is determined for each 15-minute time block. This inherently requires 15-minute wise energy metering on all interchange points of each regional constituent. Similar special energy meters shall be required for all intra-State constituents if the same 15- minute time block is to be applied intra-State. As some States already have meters for 30-minute time-block, a question has been raised as to whether the intra-State time block can be of 30 minutes. The primary idea of UI is to price the deviations from schedules according to prevailing (i.e., real time) system conditions. The time block should, therefore, be as small as practicable, and a 5-minute time block would be still better, theoretically. 15-minute has been a satisfactory compromise, as regional grid operation over the last 2-3 years has shown. As such, we recommend that all States adopt a time block of 15 minutes only, which would also enable direct back-to-back accounting with regional UI. However, implementation of intra-State UI should not get delayed on this account alone. It is, therefore, suggested that following procedure may be adopted as an interim arrangement for determination of UI charges for those intra-State entities who are having 30 - minute meters on their periphery.

Energy actually drawn in a 30 - minute block = A


Scheduled energy for that block = B


UI energy for the 30 - minute block = (A-B)


Average frequency (regional) for first 15 minutes = C


Average frequency (regional) for second 15 minutes = D


UI rate corresponding to C = E


UI rate corresponding to D = F


UI charge for the intra-State entity, for the 30 - minutes block =(A-B)x (E+F)/2.


14. Maximum and minimum UI rates:

The minimum UI rate at regional level is zero, corresponding to the variable cost of overflowing hydro-electric stations. The same should be adopted for intra-State system as well, whether a State has intra- State hydro stations or not. Similarly, the maximum intra-State UI rate should basically be same as the ceiling regional UI rate, to enable back-to-back operation of regional and State UI pool accounts. For example, suppose a DISCOM overdraws by 10 MW from State grid, due to which the State overdraws 10 MW from the regional grid, while frequency is 49.0 Hz. The State shall have to pay to regional UI pool account for the overdrawal at the ceiling rate, which is Rs. 5.70 per kWh presently. This amount should in turn be paid by the defaulting DISCOM into the State UI pool account. UI rate for the DISCOM should also, therefore, be Rs. 5.70 per kWh. The present regional ceiling UI rate was specified by CERC when diesel price was about Rs. 22 per litre. Now that the diesel price is around Rs. 32 per litre, it may be necessary to increase the ceiling UI rate. This matter is, however, in CERC's jurisdiction, and it is being mentioned here only to apprise SERCs about the possibility of such an increase so that necessary provision is kept in the concerned intra- State regulations.


15. Threshold frequencies for UI rate:

In the present relationship between frequency and regional UI rate specified by CERC, the minimum UI rate (zero) is reached at 50.5Hz and the maximum (ceiling) UI rate is reached at 49.0Hz. The experience with such frequency thresholds has generally been satisfactory. In any case, the intra-State UI has to necessarily have the same frequency threshold as regional UI, for back-to-back operation of regional and State UI pool accounts.

16. Adjustment for intra-State transmission losses:

 It is assumed that transmission losses in intra-State grid are not affected by the deviations from schedules (UI) of the intra- State entities. While this simplifying assumption could be adopted to begin with, the impact of intra-State UI on transmission losses would have to be taken into account when one starts getting into the details.


For example, 10 MW overdrawal by a DISCOM may cause (depending on topology and power flow scenario) an increase in intra-State transmission loss by 0.3 MW. Consequently, the resulting overdrawal of the State from regional grid would be 10.3 MW, and the full coverage of State’s UI liability would require that the UI rate applied to the DISCOM be 3% higher than the regional UI rate. The incremental transmission loss would, however, change with power flow pattern, requiring detailed studies/computations and may still be very subjective. It is, therefore, recommended that this particular aspect be deferred for some time, and for the present, intra-State UI

rate relationship with frequency be kept same as that at the regional level.


17. Entities to be covered in ABT In the first instance, intra-State ABT should be implemented for


i) all SEB/STU-owned generating stations above 10 MW

ii) all State Government-owned/State generating company- owned generating stations above 10 MW

iii) all IPPs, i.e. private/JV-owned and any other power stations above 10 MW, which are contracted to supply power to SEB/STU/State Govt/DISCOMs

iv) all DISCOMs, as and when SEBs are unbundled, and entities like NDMC, BEST.

v) distribution licensees who are supplied power from identified generating stations as per an allocation.


18. UI (not the full ABT) could be implemented for:


i) all entities availing “Open Access”

ii) all parties availing wheeling of captive generation

iii) all generating stations below 10 MW, (as a general guideline), which are connected to the State/DISCOM grid, including nonconventional

iv) Merchant power plants, pumped-storage plants,

v) all entities/consumers with captive/co-generation, particularly those with a possibility of feeding power back into the grid

vi) licensees with own generation, e.g. TPC, BSES, AEC, CESC. It is not desirable to implement ABT separately for the power plants of licensees, as long as the concerned licensee (such as TPC and BSES in Mumbai) continues as a vertically integrated utility. Covering the licensee under the UI mechanism (operating on its periphery) would suffice for inducing merit-order operation of embedded generation.


19. For implementation of ABT and UI mechanism within a State, the activity on the critical path would be installation of special energy meters on the periphery of all entities which are to be covered by ABT and UI. It is recommended that the meters already field-proven, and fully conforming to the specification used in case of Gujarat be ordered by the respective SEB/STU on priority. Other preparatory action can follow.


20. In conformity with section 166(4) of the Electricity Act, 2003, the SERCs may request the respective State Governments to constitute a Coordination Forum at the State level, which may also oversee the implementation of intra-State A.B.T., if so decided.


21. Implications of not implementing A.B.T. for Intra-State Stations:


As mentioned earlier, the A.B.T. as implemented for Central generating stations comprises of three components : (a) Capacity charge, (b) Energy charge, and (c) UI. Payment of capacity charge for reimbursement of the annual fixed cost is linked to average plant availability achieved over the year, which induces the plant owner to maximise its availability, without encouraging over-generation during off-peak hours. A power plant not on A.B.T. would either have a single-part tariff (i.e. a constant paise/kWh rate), or a two-part tariff (e.g. K.P. Rao formula). In case of single-part tariff, with a composite paise/kWh rate combining fixed and variable costs, the plant owner would have a perpetual incentive to maximise the generation, even during off-peak hours when his plant should in fact be backing down depending on its position in variable cost-based merit order. He would resist if the SLDC gives him a schedule with backing down in off-peak hours, and three possibilities would arise, as follows:

(a) SLDC issues a schedule with backing down by this station during off-peak hours, and the station generates energy according to the given schedule: The Station owner would suffer a revenue loss on account of energy not generated.

(b) SLDC issues a schedule with backing down by this station during off-peak hours, but the station does not back down: The station will earn extra profit, while the State would under-draw from the regional grid, and in the process suffer a loss (paying a higher rate to the station for the extra energy, and getting paid a lower rate for the same energy quantum from regional UI account).

(c) SLDC is forced by the station owner to give full schedule for the

station (ignoring merit-order), and consequently requisitions only

a part of State’s entitlement in Central stations during off-peak

hours; The State would again suffer a loss, and SLDC could be

blamed for scheduling costlier energy while forgoing cheaper

energy from Central stations. The result of the above would be a perpetual tussle between the SLDC and the generating station, and the ultimate result would be a loss for the State as a whole, one way or the other. The situation would somewhat improve in case the station is on K.P. Rao tariff (in which full fixed charges are paid even in case of backing down). However, the experience between 1992 and 2002 clearly shows that K.P. Rao tariff did not address all the problems and indisciplined behaviour by utilities

could not be curbed. In particular, there was nothing to discourage SEBs from overdrawing during peak-load hours and underdrawing during off-peak hours. There were perpetual commercial disputes as well. While most of the problems at the inter-State level have been addressed by implementation of A.B.T. for Central stations, similar problems would arise between intra-State entities if sufficient care is not taken while unbundling the SEBs. Specifically, the intra-State mechanism must have features which (a) encourage generation maximisation during peak-load hours, (b) encourage backing down of generation as per merit order during off-peak hours, (c) discourage DISCOMs from over-drawing during peak-load hours. A.B.T. would directly provide all these. If an SERC proposes to adopt a variant, it would have to see how the above features are incorporated in the proposed mechanism.


22. Implications of Adopting a Balancing Mechanism different from Regional UI:


Some States are contemplating balancing mechanisms differing from the concept of frequency-linked U.I. rate. The implications are explained below through an example. Suppose two States A and B have a thermal station each, both having a variable cost of 150 paise/kWh. Suppose both have been scheduled to generate at 90% of their available capability during off-peak hours on a certain day. Also suppose that State-A has adopted UI mechanism totally identical to the regional UI mechanism, but State-B has adopted a different balancing mechanism concept in which the price of  balancing power, instead of being a function of frequency, is calculated by the SLDC from time to time. Suppose it is 210 paise/kWh at a certain time, while frequency is 49.9 Hz and corresponding regional UI rate is 180 p/kWh. In State-A, the thermal station would see the frequency and ramp up its generation from 90% to 100% of available capability (say 500 MW), at an incremental expenditure of 150 paise/kWh. The 50 MW over-generation would result in 50 MW of underdrawal by State-A, for which it would receive UI charges @ 180 paise/kWh from regional UI pool account, which would get passed on to the thermal station. There would thus be a saving of 30 paise/kWh on 50 MW for the thermal station of State-A, which would work out to Rs.15000 per hour. Other utilities in

State-A would not have any financial impact on the above account. The situation in  State-B would be more complex. The thermal station may want to increase its generation, since it would get 210 paise/kWh against an incremental fuel expenditure of 150 paise/kWh. But this would result in a loss for State-B DISCOMs; they would pay 210paise/kWh to the thermal station for its extra generation, but would receive only 180 paise/kWh from regional UI pool account for the resulting underdrawal. Due to this anomaly, the SLDC of State-B may not permit the thermal station to increase its generation beyond the given schedule (90%), and the State as a whole would miss an

opportunity for some financial gain. In other words, generally speaking, State-B may not gain anything by adopting a balancing mechanism differing from regional UI.


There would be another issue to resolve. If a DISCOM in State-B overdraws, it would pay 210 paise/kWh into the State UI pool account for the energy overdrawn. The State would have to pay only 180 paise/kWh to the regional UI pool account for the consequent overdrawal from regional grid. What is to be done with the 30 paise/kWh differential ? And it could be negative as well ! These complications also can be avoided by extending the regional frequency-linked UI rate to all intra-State entities on back-to-back basis.



23. Revenue Balancing between DISCOMs:


Because of differing consumer mix, different DISCOMs in a State may have differing daily load curve, differing average consumer tariff and differing realisation percentage. If power is supplied to all DISCOMs at identical rates (as would normally be the case immediately after SEB unbundling), it could mean widely differing amounts for meeting their own expense. Some DISCOMs may have much bigger gaps than others (it being unlikely that any DISCOM would be able to meet all its obligations on its own). This situation may be further aggravated if DISCOMs have to as well pay UI charges on back-to-back basis, as has been recommended.


However, it needs being appreciated that revenue balancing between DISCOMs is necessary, whether UI charges apply on them or not. The prudent approach would be to treat all DISCOMs similarly, in respect of generation allocation, power supply tariff, UI charges, etc., to ensure that similar incentives apply for all. In particular, UI mechanism should not be distorted in any manner. Only then would each DISCOM be properly incentivised to take due care in its load forecasting, daily requisitioning, load management planning and load curtailment if grid situation so requires. All revenue balancing between DISCOMs may be achieved through diversion of Government subsidy to the DISCOMs which are relatively more negative. Allocation of intra-State generating station capacity between DISCOMs, as also allocation of the States’ entitlement in Central stations between DISCOMs, have to be done very judiciously. These should be on 24-hour basis only. In case it is found that a DISCOM has a surplus in peak-load hours as well, some of its allocation should be diverted to the needy DISCOMs, but only on a permanent, 24-hour basis, and by the authority which is responsible for original allocation.


However, no restrictions should be imposed on DISCOMs regarding trading of any off peak or occasional surplus, either on bilaterally contracted basis or as UI. Only in case of an allegation of sale of power by a DISCOM to earn money while its own consumers are being load-shed, should be SERC/ State Government look into the matter. At times of low frequency, a DISCOM may be justified in not supplying power to non-paying consumers, either to curtail its overdrawal (and UI liability) or to improve its finances (by earning some UI). SERCs could specify frequency thresholds for different consumer categories, above which they should not be shed.


24. Captive/Co-generation and non-conventional sources:


A.B.T. is basically meant for large power plants whose capacity is assigned to one or more beneficiaries on a 24 - hour, long-term basis. It presumes that the plant operator is able to declare the plant availability on day-ahead basis, and is then able to supply power as per the schedule advised by his beneficiaries. As such, A.B.T. is not an appropriate/practicable mechanism for captive/co-generation, or for non-conventional sources of energy (wind, solar, biomass, mini-hydel, etc.), which are mostly unpredictable regarding their power supply capability. For example, payment of capacity charge in A.B.T. is dependent on MW availability declaration. If a figure cannot be committed for the whole of the next day, capacity charge itself cannot be determined. Further, the actual generation could vary widely, from the given schedule (e.g. due to changes in wind speed), and a plant could run up huge UI liability. A.B.T. should therefore not be applied for such plants. They may continue on the single-part tariffs as presently specified by SERCs, or the entire power supplied by them into the grid may be treated as UI (and paid for by the concerned DISCOM at the frequency-linked UI rate). The logic for the latter is fairly simple. If a DISCOM receives one MW from a captive plant or wind farm, its drawal from the State grid would reduce by one MW. If it goes in underdrawal mode, it would receive UI payment for one MW, which it can pass on to the captive plant/wind farm, and remain financially immune.


25. UI for Open Access:


Open access, as contemplated in the Electricity Act, 2003, means supply of power by entity-A to entity-B through the electricity grid. Power injection by A may not be constant, and may differ from contracted amount, by a varying degree from time to time. Similarly, power drawal by B may also vary and differ from the contracted amount. For example, the contract between the two parties may stipulate that A has to inject 10 MW, and B has to draw 9.5 MW (after accounting for transmission loss in the electricity grid). The actual injection and drawal may however be 9.0 and 10.0 MW respectively. Commercial treatment of such a situation, which is dynamic, could be very complex. The matter, however, becomes fairly simple if it is stipulated that B has still to pay to A for 10 MW at contracted rate, A has to pay at the UI rate to UI pool account for one MW of undersupply, and B has to pay at the UI rate for 0.5 MW of over-drawal to the UI pool account. This has already been specified by CERC for inter- State open access, and the same approach should be stipulated by the SERCs for intra-State open access. This necessarily requires installation of special energy meters for all open access customers, for recording energy 15-minutes block wise.


26. A.B.T. is generally not suitable for end-consumers of SEBs/ DISCOMs.:


As and when they are allowed open access, they would have to pay charges for contracted energy as per tariff bilaterally agreed with their supplier, and the UI charges for deviations from contracted schedule. This has to be duly taken care of while extending open access to end consumers.


All the apprehensions regarding the new system not withstanding, ABT is still a welcome and necessary development. Next step is for the concerned authorities to ensure the necessary infrastructure to remove all the bottlenecks on the transmission side. Once this id done, the path should be clear to a completely market driven scenario with much better systems and infrastructure in place. The culminating point shall be an elaborate and efficient system with much more reliance on distributed power systems as well. This will iron out any monopoly tendencies in the system delivering maximum benefits to the consumers. This will also prove beneficial to the environment since “green power” norms are much more effectively implemented in a distributed and deregulated power scenario.


ABT notification defines availability for any specific time-period as the ratio of the average sendout capability (SOC) for all time blocks of the time-period to the rated SOC. Thus availability canbe expressed using the formula:




Avaliability =  å {SOC/(1- AUX/100)+ CL}*100/(h*IC)





IC        =Installed capacity of station in MW

SOCi = Send out capability in ith time block

N         = number of time blocks in the durations

AUX    =Normative auxiliary consumption for the plant as a percentage of gross consumption

H         =Number of hours in the duration

CL       =Gross MWH of capacity units kept closed on account of the generation scheduling order

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What is availability Tariff?

Why was Availability Tariff Necessary?

How does it benefit everyone?

How do the beneficiaries share the payments?

How does the mechanism work?

 What is Availability Tariff?

 The term Availability Tariff, particularly in the Indian context, stands for a rational tariff structure for power supply from generating stations, on a contracted basis.

 The power plants have fixed and variable costs:

I.                   The fixed cost elements are

a.       Interest on loan,

b.      Return on equity,

c.       Depreciation,

d.      O&M expenses,

e.       Insurance,

f.       Taxes and

g.      Interest on working capital.

II.                The variable cost comprises of the fuel cost, i.e., coal and oil in case of thermal plants and nuclear fuel in case of nuclear plants.

In the Availability Tariff mechanism: The fixed and variable cost components are treated separately. They are called as the Capacity Charge and the Energy Charge.

Capacity Charge: The payment of fixed cost to the generating company is linked to availability of the plant, that is, its capability to deliver MWs on a day-by-day basis. The total amount payable to the generating company over a year towards the fixed cost depends on the average availability (MW delivering capability) of the plant over the year. In case the average actually achieved over the year is higher than the specified norm for plant availability, the generating company gets a higher payment. In case the average availability achieved is lower, the payment is also lower. Hence the name ‘Availability Tariff’. This is the first component of Availability Tariff, and is termed ‘capacity charge’.

Energy Charge: The second component of Availability Tariff is the ‘energy charge’, which comprises of the variable cost (i.e., fuel cost) of the power plant for generating energy as per the given schedule for the day. It may specifically be noted that energy charge (at the specified plant-specific rate) is not based on actual generation and plant output, but on scheduled generation. In case there are deviations from the schedule (e.g., if a power plant delivers 600 MW while it was scheduled to supply only 500 MW), the energy charge payment would still be for the scheduled generation (500 MW), and the excess generation (100 MW) would get paid for at a rate dependent on the system conditions prevailing at the time. If the grid has surplus power at the time and frequency is above 50.0 cycles, the rate would be lower. If the excess generation takes place at the time of generation shortage in the system (in which condition the frequency would be below 50.0 cycles), the payment for extra generation would be at a higher rate.

To recapitulate, the Indian version of Availability Tariff comprises of three components:

a.       capacity charge, towards reimbursement of the fixed cost of the plant, linked to the plant's declared capacity to supply MWs,

b.      energy charge, to reimburse the fuel cost for scheduled generation, and

c.       a payment for deviations from schedule, at a rate dependent on system conditions. The last component would be negative (indicating a payment by the generator for the deviation) in case the power plant is delivering less power than scheduled.

v   Why was Availability Tariff necessary

Prior to the introduction of Availability Tariff, the regional grids had been operating in a very undisciplined and haphazard manner. There were large deviations in frequency from the rated frequency of 50.0 cycles per second (Hz). Low frequency situations result when the total generation available in the grid is less than the total consumer load. These can be curtailed by enhancing generation and/or curtailing consumer load. High frequency is a result of insufficient backing down of generation when the total consumer load has fallen during off-peak hours. The earlier tariff mechanisms 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. In fact, it was profitable to go on generating at a high level even when the consumer demand had come down. In other words, the earlier tariff mechanisms encouraged grid indiscipline.

The Availability Tariff directly addresses these issues.

I.                   Firstly, by giving incentives for enhancing output capability of power plants, it enables more consumer load to be met during peak load hours.

II.                Secondly, backing down during off-peak hours no longer results in financial loss to generating stations and the earlier incentive for not backing down is neutralized.

III.             Thirdly, the shares of beneficiaries in the Central generating stations acquire a meaning, which was previously missing. The beneficiaries now have well-defined entitlements, and are able to draw power up to the specified limits at normal rates of the respective power plants. In case of over-drawal, they have to pay at a higher rate during peak load hours, which discourages them from over-drawing further. This payment then goes to beneficiaries who received less energy than was scheduled, and acts as an incentive/compensation for them.

v   How does it benefit everyone

The mechanism has dramatically streamlined the operation of regional grids in India.

Firstly, through the system and procedure in place, constituents’ schedules get determined as per their shares in Central stations, and they clearly know the implications of deviating from these schedules. Any constituent which helps others by under-drawal from the regional grid in a deficit situation, gets compensated at a good price for the quantum of energy under-drawn.

Secondly, the grid parameters, i.e., frequency and voltage, have improved, and equipment damage correspondingly reduced. During peak load hours, the frequency can be improved only by reducing drawls, and necessary incentives are provided in the mechanism for the same. High frequency situation on the other hand, is being checked by encouraging reduction in generation during off-peak hours.

Thirdly, because of clear separation between fixed and variable charges, generation according to merit-order is encouraged and pithead stations do not have to back down normally. The overall generation cost accordingly comes down.

Fourthly, a mechanism is established for harnessing captive and co-generation and for bilateral trading between the constituents.

Lastly, Availability Tariff, by rewarding plant availability, enables more consumer load to be catered at any point of time.

v   How do the beneficiaries share the payments

The Central generating stations in different regions of the country have various States of the Region as their specified beneficiaries or bulk consumers. The latter have shares in these plants calculated according to Gadgil formula, and duly notified by the Ministry of Power. The beneficiaries have to pay the capacity charge for these plants in proportion to their share in the respective plants. This payment is dependent on the declared output capability of the plant for the day and the beneficiary's percentage share in that plant, and not on power / energy intended to be drawn or actually drawn by the beneficiary from the Central station.

The energy charge to be paid by a beneficiary to a Central station for a particular day would be the fuel cost for the energy scheduled to be supplied from the power plant to the beneficiary during the day. In addition, if a beneficiary draws more power from the regional grid than what is totally scheduled to be supplied to him from the various Central generating stations at a particular time, he has to pay for the excess drawal at a rate dependent on the system conditions, the rate being lower if the frequency is high, and being higher if the frequency is low.

v   How does the mechanism work

The process starts with the Central generating stations in the region declaring their expected output capability for the next day to the Regional Load Dispatch Centre (RLDC). The RLDC breaks up and tabulates these output capability declarations as per the beneficiaries' plant-wise shares and conveys their entitlements to State Load Dispatch Centres (SLDCs). The latter then carry out an exercise to see how best they can meet the load of their consumers over the day, from their own generating stations, along with their entitlement in the Central stations. They also take into account the irrigation release requirements and load curtailment etc. that they propose in their respective areas. The SLDCs then convey to the RLDC their schedule of power drawal from the Central stations (limited to their entitlement for the day). The RLDC aggregates these requisitions and determines the dispatch schedules for the Central generating stations and the drawal schedules for the beneficiaries duly incorporating any bilateral agreements and adjusting for transmission losses. These schedules are then issued by the RLDC to all concerned and become the operational as well as commercial datum. However, in case of contingencies, Central stations can prospectively revise the output capability declaration, beneficiaries can prospectively revise requisitions, and the schedules are correspondingly revised by RLDC.

     While the schedules so finalized become the operational datum, and the regional constituents are expected to regulate their generation and consumer load in a way that the actual generation and drawls generally follow these schedules, deviations are allowed as long as they do not endanger the system security. The schedules are also used for determination of the amounts payable as energy charges, as described earlier. Deviations from schedules are determined in 15-minute time blocks through special metering, and these deviations are priced depending on frequency. As long as the actual generation/drawal is equal to the given schedule, payment on account of the third component of Availability Tariff is zero. In case of under-drawal, a beneficiary is paid back to that extent according to the frequency dependent rate specified for deviations from schedule.  

v   Why was Availability Tariff necessary

Prior to the introduction of Availability Tariff, the regional grids had been operating in a very undisciplined and haphazard manner. There were large deviations in frequency from the rated frequency of 50.0 cycles per second (Hz). Low frequency situations result when the total generation available in the grid is less than the total consumer load. These can be curtailed by enhancing generation and/or curtailing consumer load. High frequency is a result of insufficient backing down of generation when the total consumer load has fallen during off-peak hours. The earlier tariff mechanisms 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. In fact, it was profitable to go on generating at a high level even when the consumer demand had come down. In other words, the earlier tariff mechanisms encouraged grid indiscipline.

The Availability Tariff directly addresses these issues. Firstly, by giving incentives for enhancing output capability of power plants, it enables more consumer load to be met during peak load hours. Secondly, backing down during off-peak hours no longer results in financial loss to generating stations, and the earlier incentive for not backing down is neutralized. Thirdly, the shares of beneficiaries in the Central generating stations acquire a meaning, which was previously missing. The beneficiaries now have well-defined entitlements, and are able to draw power up to the specified limits at normal rates of the respective power plants. In case of over-drawal, they have to pay at a higher rate during peak load hours, which discourages them from over-drawing further. This payment then goes to beneficiaries who received less energy than was scheduled, and acts as an incentive/compensation for them.

v   How does it benefit everyone

The mechanism has dramatically streamlined the operation of regional grids in India. Firstly, through the system and procedure in place, constituents’ schedules get determined as per their shares in Central stations, and they clearly know the implications of deviating from these schedules. Any constituent which helps others by under-drawal from the regional grid in a deficit situation, gets compensated at a good price for the quantum of energy under-drawn. Secondly, the grid parameters, i.e., frequency and voltage, have improved, and equipment damage correspondingly reduced. During peak load hours, the frequency can be improved only by reducing drawls, and necessary incentives are provided in the mechanism for the same. High frequency situation on the other hand, is being checked by encouraging reduction in generation during off-peak hours. Thirdly, because of clear separation between fixed and variable charges, generation according to merit-order is encouraged and pithead stations do not have to back down normally. The overall generation cost accordingly comes down. Fourthly, a mechanism is established for harnessing captive and co-generation and for bilateral trading between the constituents. Lastly, Availability Tariff, by rewarding plant availability, enables more consumer load to be catered at any point of time.


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