Availability Based Tariff
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10-01-2011, 03:15 PM
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Chapter-1 INTRODUCTION TO ABT
After independence in 1947 that the power sector got the required momentum and power generation was identified as a key area for development of India. 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. The installed capacity across the nation well exceeds 100,000 MW, a major share of which is derived from thermal sources (coal/lignite, gas, and 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.
With increasing energy demands 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 seminar and presentation is an attempt to introduce the significant clauses and implications of ABT in a concise manner.
Over two decades, the operation of power systems in India had been plagued with serious problems. A glaring symptom was the wide fluctuation of grid frequency – from below 48.0 Hz to above 52.0 Hz, on a daily basis. Because the grids still continued to operate, the seriousness of the situation was really not being appreciated generally, and such conditions were being allowed to continue. Utilities blamed each other for the prevailing anarchy but little was actually being done to tackle the root cause: the then prevailing faulty tariff structure for bulk power supply. Power from Central Government–owned generating stations was being supplied to the State Government-owned vertically integrated utilities as per simplistic, single-part, constant (Rupees per kWh) tariffs, which disregarded drawl pattern, deviation from schedules, system conditions (surplus/deficit), etc. On one hand, the State utilities were not being discouraged from overdrawing, even when generation was inadequate (during peak-load hours). On the other hand, both the Central generating companies and State utilities were being encouraged to go on generating, even when the consumer load had come down (during off-peak hours).
Chapter-2 AVAILABILITY BASED TARIFF
The term Availability Based Tariff, particularly in the Indian context, stands for a rational tariff structure for power supply from generating station, on a contracted basis.
Availability Based Tariff is the tariff structure ushered in as part of the market deregulation and unbundling by CERC (Central Electricity Regulatory Commission) of India. It is also used to indicate India’s recent power sector reforms in general.
2 Necessity of ABT
Prior to the introduction of Availability Based Tariff, the regional grids had been operating in a undisciplined and haphazard manner.
There were large deviations in frequency from rated 50Hz .Low frequency situation result when the total generation available in the grid is less than the total consumer load. These can be alleviated by curtailing consumer load or enhancing generation .High frequency is a result of insufficient of backing down of generation when the total consumer load has fallen during off-peak hours. The earlier mechanism did not provide any incentive for either backing down generation during off-peak hours or for reducing consumer load or 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 word s, the earlier tariff mechanism encouraged grid indiscipline
The ABT directly addresses these issues.
*By giving incentives for enhancing output capability of power plant ,it enables more consumer load to be met during peak load hours
* Backing down during off-peak hours no longer result in financial losses to generating
Station, and earlier incentive for not backing down is neutralized
* The shares of beneficiaries in central generating stations acquire a meaning, which was previous 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- drawl, they have to pay at 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 act as an incentives/compensation for them .
3 COMPONENTS OF ABT
Availability Based Tariff comprises of three components
1. Fixed cost
2. Variable cost
3. Unscheduled Interchange (UI)
1. Fixed cost
The fixed cost elements are interest on loan, return on equity, depreciation, operation and maintenance expenses, insurances, taxes and interest on working capital.
The payment of fixed cost to the generating stations is linked to the availability of the plant that is its capability to deliver MWs on a day-by-day basis.
Here, availability in relation to a thermal power plant for any period means the average of the daily average declared capacities for all the days during that period expressed as percentage of installed capacity of generating station minus normative auxiliary consumption in MW
Fixed charge is also known as capacity charge
The total amount payable to the generating station over a year towards a fixed cost depends upon 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 station gets higher payment. In case the average availability is lower, the payment also lowers.
Therefore the fixed cost is decided by capacity of plant or availability of plant in this tariff, hence name given Availability Based Tariff
Fixed charge or Capacity charge = a function of the Ex-bus MW availability of power plant for the day or (declared before the day start * beneficiaries % share)
2 Variable cost or energy charges
The variable cost comprises of fuel cost i.e. coal and oil in case of thermal plant and nuclear fuel in case of nuclear plants. In availability based Tariff mechanism, the fixed and variable cost components are treated separately
The second component of ABT is ‘energy charge’ which comprises of variable cost of the plant for generating energy as per given schedule of the day
It may specially noted that energy charges( at specified plant-specific rate) is not based on actual generation and plant output, but on schedule generation
Variable charge = MWH for the day as per ex-bus i.e. drawl schedule for the beneficiaries
Energy charges = (drawl finalized before the day start * energy charges rate)
In case there are deviations from the schedule(e/.g. if a power plant deliver 450 MW while it was scheduled to supply only 350 MW),the energy charge payment would be still be for the schedule generation (450 MW) and excess generation 100 MW would get paid for a rate dependent on the system condition prevailing at that time. If the grid has surplus power at the time and frequency is above 50.0 Hz ,the rate would be lower If excess generation
Take place at the time of generation shortage in the system, the payment for extra generation would be at a higher rate
3. Unscheduled Interchange(UI)
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.
Unscheduled Interchange is the sum of actual energy i.e. deviation from schedule interchange in a time bock
Unscheduled interchange = (interchange in a time block – scheduled energy interchange from the time block) * UI rate for the time block
ABT notification defines availability for any specific time-period as the ratio of the average send out capability (SOC) for all time blocks of the time-period to the rated SOC. Thus availability can be expressed using the formula:
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
Chapter-3 FEATURES AND SCHEDULING
1. Features of ABT
• ABT had no attempt to consider different cost separately like operational cot, depreciated cost concern with new tariff design proceeds
• Misleading of availability entails severe penalties
• It increases the minimum performance criterion for the earning of an incentive from 80 % PLF for all Thermal power stations,85% for hydro power stations and 77 % for nuclear power station and also subsequent year PLF should be improved
• It introduces severe financial penalties for grid indiscipline along with significant rewards for behavior, which enforces grid discipline for both generators and beneficiaries.
• It open up power marketing for surplus energy as power trading by beneficiaries and generators
• No payment for capacity charges for prolonged outages
• Announcement of unallocated capacity advanced in month so beneficiaries know their exact share in capacity
• It was first implemented in southern region from April 2004 specially to central power stations
• Implementation in a phased manner
• Generation and drawl schedules to be managed in 15 minute blocks (96 blocks per day)
• It provide 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
• Role of regional load dispatch centers (RLDC) in managing and coordinating the schedule and managing the schedule in the event of grid disturbances
• Methodology for calculating the capabilities for different types of power stations (such as hydro, thermal, nuclear) and for demonstrating the same
• Details on metering, accounting, billing and payment of energy charges under the ABT regime
• How disputes arising under ABT shall be resolved
2. Scheduling and Load Dispatching under ABT
To match the supply and demand on a daily basis at least one day in advance.
•Each day of 24 hours starting from 0.00 hour is being divided in to 96 time blocks of 15 minutes duration.
•Each generating station shall make advance declaration of the capacity available for generation in terms of MW delivery of ex-bus in each time block. The generator shall also ensure that, the capacity available during peak hours is not less than the capacity available during off-peak hours.
• The Scheduling as referred to above should be in accordance with the operating procedures in force.
•Based on the declaration of the generating station, the RLDC shall communicate to the beneficiary SEBs, their respective share of the available capacity.
• The beneficiaries give their requisition for power based on the generation schedules, The beneficiary shall prepare their schedules from the above, based on the internal generation availability, variable cost of generation of their own thermal stations, power purchase facility from other sources and the cost, system constraints and limitations etc.
•Based on the request from the beneficiaries as well as declaration from the generators, the RLDC shall prepare the generation schedules and drawl schedules from the CPS for each time blocks after taking into account the transmission constraints and other systems constraints if any.
•For transmission losses shall be apportioned among the beneficiaries in proportion of their drawls.
•In the case of any constraints, the RLDC have right to revise the schedule, which shall become effective from 4th time block.
•The generator and beneficiaries are also allowed to revise their schedule during a day, but such revisions shall be effective only from the 6th time block.
• For calculating the drawl schedule for beneficiaries, the transmission losses shall be apportioned in proportion to their drawls.
• RLDC is also entitled to revise (if need be), the schedules during the day in the interest of better system operation. These revised schedules shall become effective from the 4th time block counting the time of issue of revised schedule as the 1st time block.
• In the event of any grid disturbance, the schedules of both generation and drawl shall be deemed to have been revised to be equal to their actual generation/drawl. The grid disturbance and its duration shall be certified by RLDC.
• The schedules issued/revised by RLDC shall be effective from designated time block, irrespective of communication success or failure.
i) A generator generates more than the schedule, thereby increasing the frequency;
ii) A generator generates less than the schedule, thereby decreasing the frequency.
iii) A beneficiary overdraws power, thereby decreasing the frequency;
iv) A beneficiary under draws power, thereby increasing the frequency.
UI to be worked out for each 15 minutes time block. The charges shall be based
on the average frequency of the relevant time block.
Average Frequency of time block UI Rate (Paise/ KWh)
50.5 Hz and above 0.0
Below 50.5 Hz and up to 50.48 Hz 4.8
Below 49.4 Hz and 49.02 Hz 355.2
Below 49.02 Hz 360.0
Between 50.5 Hz and 49.02 Hz linear in 0.02 Hz step
(Rates subject to change through a separate notification from time to time)
Over declaration to increase fixed charges and rate of return under declaration to increase unscheduled interchange charges
Mechanisms to prevent gaming
Monitoring and enforcement of generation availability may be accomplished through auditing plant records 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.
Chapter-4 IMPACT OF ABT
Till the end of last century the power sector in India used to be a dull game. Central generation and transmission utilities and the monolithic SEB’s were the only players involved.
State monopoly translated into grid indiscipline. Thus the power plants generated at their peak capacity and got paid for it too!) even when load was low. And the SEB’s serviced all the loads even when sufficient power was not available in the grid. Low quality power was the order of the day.
CERC was set up in 1998 and an era of deregulation was ushered in. A system of incentives and disincentives for grid discipline called ABT was initiated. Several measures were taken to encourage investment and private participation in the power sector. Unbundling of the SEB’s were called for. All this resulted in a dynamic increase in the number of participants in the power sector.
Presently the Indian power sector contains central generation companies (NTPC, NHPC, NPC), state generation companies (GENCOs in various states), transmission companies (PGCL, TRANSCOs), distribution companies (DISCOMs), trading companies (PTC and several other playes) and private players (Tata power, Reliance, Torrent etc.). In addition, IPPs and CPPs participating in the grid for selling power or internal consumption add to the field. The RLDCs and SLDCs act as the coordinating agencies between
all these players. Rules of engagement are defined by the Electricity Act, IEGC (Indian Electricity Grid Code) and other notifications from CERC.
ABT introduces a tariff structure that will promote responsibility and accountability in power generation, transmission and consumption so that overall quality of power in India is improved
There are significant impacts on different players involved in generation, transmission and distribution of power
IMPACT ON GENCOS
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. 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 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 such as whether fuel of sufficient quality and quantity is being made available, are all the components of the system (say, the boiler, reheaters, super heaters, 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 incurs 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. This remains true irrespective of the algorithm employed by the forecasting solution (with the possible 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.
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AVAILABILITY BASED TARIFF (GENERATORS PERSPECTIVE)
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.
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.
Integrated grid operations require the normalisation of frequency across all five Regions. The alternative is to insulate each Regional Grid by Back to Back HVDC links. This is an expensive option. Normalisation of frequency requires proactive load management by beneficiaries and despatch discipline by generators. There is currently no formal system of financial
incentives to promote grid discipline. The ABT provides this mechanism.
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 .
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.
The ABT will induce corrections in the prevailing frequency to bring it within the permissible band 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.
The ABT will address this problem by inducing Grid discipline. Economic efficiency dictates that least cost power should be despatched in preference to more costly power (merit order despatch). This becomes difficult without a two part tariff for all stations. States tend to compare the total cost of central generators with the variable cost of their own stations, since for them the fixed costs of state level stations are sunk costs. This results in making central generation appear artificially more expensive than state level stations even though on variable cost basis the former may be cheaper. 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 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. 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.
The ABT will discourage such behaviour by pricing generation outside the schedule in relation to the prevailing frequency .
What Is ABT?
It is a performance-based tariff for the supply of electricity by generators owned and controlled by the central government
It is also a new system of scheduling and despatch, which requires both generators and beneficiaries to commit to day-ahead schedules.
It is a system of rewards and penalties seeking to enforce day ahead pre-committed schedules, though variations are permitted if notified One and one half hours in advance.
The order emphasises prompt payment of dues. Non-payment of prescribed charges will be liable for appropriate action under sections 44 and 45 of the ERC Act.
It has three parts:
1. 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.
Fixed charges excluding ROE is payable on
prorated basis for 0-30% availability.
Prorated ROE is payable from 30-70% availability.
Incentive is payable to generators for availability
beyond 70% (0.4% of equity for each percent increase in availability between 70-85%, 0.3% of equity for each percent rise beyond 85%.)
2. 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.
3. A charge for Unscheduled Interchange (UI charge): Variation between actual and scheduled generation shall be accounted for through UI charges.UI for Generation station shall be=(Actual Generation – Scheduled Generation).
UI shall be worked out for each 15-minute time block and charges for UI transactions shall be based on average frequency of the time block and following rates shall apply
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