availability based tariff

AVAILABILITY BASED TARIFF

- Tariff structures - Two part tariff

- Concept of ABT - ABT structure- Expectations from OEMs/Utilities

Session outline

TARIFF STRUCTURES

The current tariff approach has gradually developed over the many decades…

Tariff Milestones

1910 1948 1975 1992 1998 2003

ES Act ES Act ES ActCentral Utilities 2 Part tariff

British India- agglomeration of provinces

Indian Union

Isolated Private LicenseesIsolated SEBs

RegionalSystem

Central Utilities Central Utilities, IPPs, CTU, SEBs

Early British Model State Govt Central Govt Regulator

CountryStatus

SectoralMakeup

InstitutionalStructure

The sectoral set up has evolved from monolithic inceptive SEBs and certain private licensees and is transiting to independent Generation, Transmission & Distribution…

State

Joint

Private

SEBs

DVC,

Licensees

Under MOP: NTPC, NEEPCOOther Ministries: NLC, Central

Transmission

State

CTU-Power GridCentral

STUs- SEBs

State STUs- SEBs

Private Licensees

Power Trading: PTC, NVVVNL Financing: PFC, REC

, IPPs

/State GenCos

, Pvt DisComs

/State DisComs

/State TransCos

Generation

Transmission

Transmission

Distribution

Generation

Distribution

Generation

Transmission

Transmission

Distribution

Generation

Distribution

• Cost of Debt• Cost of equity• Debt : Equity• Tax on returns• Additional capitalization• R&M capitalization• Capital costs basis• Working capital• O&M expenses• Depreciation• Operating norms• Target Availability• Utilization Incentive• Efficiency Incentive• Development Fund• Technology Compensations• Fuel Compensations

Fuel

Generators

TransmissionAgencies

DistributionAgencies

The norms for tariff determination need to comply to basics of economics along the full electricity value chain. …

Indian Tariff approach has developed as a response to industry evolution…

Cost of Supply

CapacityCharge

UI Charge Energy Charge

Cost of Supply

CapacityCharge

Energy Charge

Cost of Supply

Bundled Charges

Single Part Tariff Two Part Tariff Availability Based Tariff

1910

1992 2001

• Carry over of early isolated licensees utility centric electricity luxury era

• Practically all costs were pass on without any performance linkage

• First capacity utilization linkage came in 1975 with entry of central utilities @ 55%

• Response to excess capacity charge accruals on performance exceeding industry average

• First systematic effort to lay tariff determination principles

• Fixed charges pegged to 62.8% capacity utilization and incentive beyond 68%

• Regulators response to contemporary sectoral situation to enhance performance and instill grid discipline.

• Applicable only to Central utilities

• Concept and Systems for UI charges established

While the evolution has been logical there are a number of issues in the Indian Power Sector which the tariff approach need to consider in future

Tariff Structure - Two part tariffWorldly most accepted structureIt has inbuilt efficiencyCapacity charge component based upon the customer capacity utilization.Energy charge to cover the cost of energyIt encourage economic dispatch and the financing of generation resourcesIt improves the optimization of consumption patterns.

Two part tariffComponents of Fixed Charges

• Return on Equity– capital cost for tariff is the cost as approved by

CEA– Debt equity ratio 70:30 for investments

approved after March 1992– ROE - 16% allowed

• Interest on Loan capital– weighted average of the interest rate applicable

on the outstanding project loans

• Depreciation– Notified by the GoI– 7.84 % Coal based , 8.24% Gas based

• O&M ExpensesNormative– 2.5 % of the current capital cost– or 2% of current capital cost + Insurance total

not exceeding 3%



• Interest on working capital– Rate of interest is the current cash credit interest

charged by the bankers– Working capital Norms

• Two months receivables• spares for 1- year• Coal stock- 15days/1 month for pit-head/others• Oil Stock for 1 month• Fuel expenses and O& M expenses for 1 month

• Taxes on income



• Normative and based on operational performance

• The Norms– Plant Load factor

• 4500 Hours /kW/year during stabilisation period and 6000 hours/kW/year there after ( corresponds to a PLF of 68.49%)

Variable Charges

– Sp.Oil Consumption• 5 ml/ kwh for 1st year after commercial operation and

3.5 ml/kwh there after

– Heat Rate• 2600kcal/kwh for 1st year after commercial operation

and 2500kcal/kwh there after( 40kcal/kwh reduced for electrically driven BFPs)

Variable Charges

– Aux. Power consumption• For 200MW units - 9.5% for 1st year after commercial

operation and 9% there after (additional 0.5% with cooling towers)

• For 500MW units(steam driven BFPs) - 8.5 % for 1st year after commercial operation and 8.0 % there after(additional 0.5% with cooling towers)

• For 500MW units(elec. driven BFPs) - 9.5 % for 1st year after commercial operation and 9.0 % there after(additional 0.5% with cooling towers)

Variable Charges

• Norms for gas based power stations– Heat rate

• 3150 kcal/kwh for open cycle operation and 2100 kcal/kwh for combined cycle operation on GCV basis

– Aux. Power Consumption• 1% for open cycle and 3% for combined cycle

Variable Charges

• Variable cost calculated thus would be subject to fuel price adjustment

Variable Charges

Variable Charges

• Fuel price adjustment.

-On price variation of fuel.

-On quality variation of fuel.

FPA =

10*Hc/(100-AC)*{[Pcm/Kcm - Pcs/Kcs] +10*Ho/(100-AC) [Pom/Kom - Pos/Kos]}

Pcm / Pcs = Price of coal PSL/ Base tariff.

Kcm / Kcs = GCV of coal PSL/ Base tariff

Pom / Pos = Price of oil PSL/ Base tariff

Kom / Kos = GCV of oil PSL/ Base tariff

Tariff Structure - Two Part TariffTariff Structure - Two Part Tariff

Worldly most accepted structure Capacity charge component based upon the

customer capacity utilization. Energy charge to cover the cost of energy

THE GRID CONDITIONS PRIOR TO ABTTHE GRID CONDITIONS PRIOR TO ABTWide frequency variations causing serious damages at

generation & load ends.

Low frequency during peak hours, with frequency going down to 48.0 – 48.5 Hz.

High frequency during off peak hours, with frequency going up to 50.5 to 52.0 Hz.

Rapid changes in frequency – 1 Hz change in 5 to 10 minutes, for many times every day.

Very frequent grid disturbances, causing tripping of generating stations.

WHY THIS GRID INDISPLINE ?WHY THIS GRID INDISPLINE ?

The TWO PART tariff mechanism was not providing any incentive for either backing down the generation during off-peak hours or for reducing the consumer load by the beneficiaries and/or enhancing the generation during peak hours.

In fact, there was financial incentive in continuing with generation at higher level, even when, the load (consumer demand) had come down. This was due to the fact that incentives were linked with actual generation.

AVAILABILITY BASED TARIFF

BACKGROUND• Two Part Tariff had no mechanism to impose

- Grid discipline.

- Market Competition

- Breaking monopoly

• 1994 - M/s ECC engaged by GOI for

rationalisation.

• Formation of NTF and RTF

• M/s ECC report»Market Mechanism»Recommendation for ABT

Frequency Profile (Pre-ABT and Post ABT)

47

48

49

50

51

52

53

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Time

Fre

qu

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cy

(H

z)

Freq.: 23-Jun-2002 Freq.: 23-Jun-2003

400 Kv BUS Voltage profile - a Typical Day

340

350

360

370

380

390

400

410

420

Time (hh:mm)

APPLICABILITYAPPLICABILITY

ABT is applicable to:-

All central sector generating stations (whether

inter-state or intra-state) , viz, the power plants

of NTPC, NLC, NHPC, THDC etc.

All the beneficiaries, who draw power from

central sector generating stations, viz, SEBs,

Bulk Consumers having entitlements in CGS.

ABT IMPLEMENTATION STATUS IN INDIAABT IMPLEMENTATION STATUS IN INDIA WR – 01.07.02

NR – 01.12.02

SR – 01.01.03

ER – 01.04.03

NER – 01.11.03

CONCEPT

• Performance criteria shifted from PLF to Availability.

• Introducing the concept of Re-trading

• Introduction of Frequency linked component

• Introduction of Merit order despatch

Availability Tariff

Rational tariff structure for power supply from generating stations on a contracted basis.

The payment of fixed cost to the generating

company is linked to availability of the

plant.

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.

Hence the name ‘Availability Tariff ’

Primary objectives of ABT a) To encourage maximisation of generation

b) Deviate from the schedules and take advantage of the UI

mechanism.

c) Mandatory FGMO for all generating units.

d) Generators are expected to operate and maintain their

stations with high plant availability in a sustained

manner.

e) Positive deviation through the UI mechanism ensures

extra power for consumers and/or enhanced optimisation /

conservation of resources.

e) Natural Merit order

COMPONENTS OF ABTCOMPONENTS OF ABTAvailability Based Tariff Mechanism has following three components:

Capacity Charge for Sent Out Availability Energy Charge for Scheduled Generation / Drawl Unscheduled Interchange (UI) Charge:

The Variation from generation schedules, i.e., Actual Generation (AG) - Scheduled Generation (SG)

The Variation from drawal schedules, i.e., Actual Drawal (AD) - Scheduled Drawal (SD)

AVAILABILITY BASED TARIFF AVAILABILITY BASED TARIFF

The fixed cost elements relates to Capacity Charges are

Return on equity Interest on loan Depreciation including AAD O&M expenses Interest on working capital FERV on capital cost

VARIABLE COST ELEMENTS

Energy (variable) charges cover the fuel costs and are worked out on the basis of ex-bus energy scheduled to be sent out from the generating station as per the following formula;

Energy Charges (Rs.)=Rate of Energy Charges in Rs/kWh X Scheduled Energy (ex-

bus) in kWh corresponding to scheduled

generation.

The components of energy charges are Primary Fuel Cost, i.e., coal for thermal units. Secondary Fuel Cost , i.e., oil for thermal units.

UI MECHANISM

TOOL FOR INDUCING GRID DISCIPLINE ?

UI TARIFF BEING LINKED WITH FREQUENCY, SENDS

AN APPROPRIATE COMMERCIAL SIGNAL TO

GENERATORS & STATES DEPENDING UPON THE GRID

FREQUENCY ALLOWS THEM TO TAKE CORRECTIVE

ACTION AND BRING THE FREQUENCY NEAR THE

NOMINAL LEVEL.

FEATURESFEATURES OF ABTOF ABT

Capacity Charge and Energy Charge do not depend on PLF of the station and actual generation/drawal respectively.

No complications w.r.t deemed generation.

No year end commercial adjustments.

Perpetual Incentive for maximizing generation and reducing drawal during peak load conditions.

No incentive to over generate during off-peak conditions.

TERMINOLOGYAvailability : in relation to a thermal generating station for any period means the average of the daily average declared capacities (DCs) for all the days during that period expressed as a percentage of the installed capacity of the generating station minus normative auxiliary consumption in MW, and shall be computed in accordance with the following formula:

N

Availability = 10000 x Σ DCi / { N x IC x (100-AUXn) }%

i=1

where,

IC = Installed Capacity of the generating station in MW,

DCi = Average declared capacity for the ith day of the period in MW,

N = Number of days during the period, and

AUXn = Normative Auxiliary Energy Consumption as a percentage of gross generation;

TERMINOLOGY

Declared Capacity (DC): The capability of the generating station to deliver ex-bus electricity in MW declared by such generating station in relation to any period of the day or whole of the day, duly taking into account the availability of fuel

TERMINOLOGYPlant Load Factor(PLF): The total sent out energy corresponding to scheduled generation during the period, expressed as a percentage of sent out energy corresponding to installed capacity in that period and shall be computed in accordance with the following formula:

N

PLF = 10000 x Σ SGi / {N x IC x (100-AUXn) }%

i=1where,

IC = Installed Capacity of the generating station in MW,

SGi = Scheduled Generation in MW for the ith time block of the period,

N = Number of time blocks during the period, and

AUXn = Normative Auxiliary Energy Consumption as a percentage of gross

generation;

TERMINOLOGY

Unscheduled Interchange (UI) Charges:

• Variation between actual generation or actual drawal and scheduled generation or scheduled drawal shall be accounted for through Unscheduled Interchange (UI) Charges.

• UI for a generating station shall be equal to its actual generation minus its scheduled generation.

• UI for a beneficiary shall be equal to its total actual drawal minus its total scheduled drawal.

• UI shall be worked out for each 15 minute time block. Charges for all UI transactions shall be based on average frequency of the time block

• UI rates are frequency dependent and uniform throughout the country.

UI SHALL BE BASED ON THE AVERAGE FREQUENCY OF THE RELEVANT TIME BLOCK.

AVAILABILITY BASED TARIFF - UI

Unscheduled Interchange(UI) Charges : (contd..)

(i) Any generation up to 105% of the declared capacity in any time block of 15 minutes and averaging up to 101% of the average declared capacity over a day shall not be construed as gaming, and the generator shall be entitled to UI charges for such excess generation above the scheduled generation (SG).

(ii) For any generation beyond the prescribed limits, the Regional Load Dispatch Centre shall investigate so as to ensure that there is no gaming, and if gaming is found by the Regional Load Dispatch Centre, the corresponding UI charges due to the generating station on account of such extra generation shall be reduced to zero and the amount shall be credited adjusted towards in UI account of beneficiaries in the ratio of their capacity share in the generating station.

AVAILABILITY BASED TARIFF - UI if a power plant delivers 1934 MWs, while it was scheduled to

supply only 1800 MW, the energy charge payment would be for 1800 MW only, i.e., for scheduled generation only.

The excess generation, i.e., 134 MW in above example would be paid for at a certain rate known as Unscheduled Interchange (UI) Charge, which would depend upon the system conditions prevailing at that time.

If the grid has surplus power at a particular time and frequency is above 50.5 Hz, the energy rate (for extra power) would be nil. If the system frequency is between 50.5 – 49.8, the rate would be small, i.e., varying from 6 paise per unit to Rs. 2.10 per unit depending upon the system frequency. However, if the system frequency is between 49.8 – 49.0, the rate would be high, i.e., varying from Rs. 2.10 per unit to Rs. 5.70 per unit.

FGMO in ABT regime

• All generating units, which are synchronized with the grid, irrespective of their ownership, type and size, shall have their governors in normal operation at all times .

• If any generating unit of over fifty (50) MW size is required to be operated without its governor in normal operation,the RLDC shall be immediately advised about the reason and duration of such operation. All governors shall have a droop of between 3% and 6%.

FGMO in ABT regime

• No dead bands and/or time delays shall be deliberately introduced.

• The generating units operating at/ above 100% of their MCR shall be capable of (and shall not be prevented from) going at least up to 105% of their MCR when frequency falls suddenly.

• After an increase in generation as above, a generating unit may ramp back to the original level at a rate of about one percent (1%) per minute, in case continued operation at the increased level is not sustainable.

FGMO in ABT regime

• Any generating unit of over fifty (50) MW size (10 MW for NER) not complying with the above requirements, shall be kept in operation (synchronized with the Regional grid) only after obtaining the permission of RLDC. However, a constituent can make up the corresponding short fall in spinning reserve by maintaining an extra spinning reserve on the other generating units of the constituent.

FGMO in ABT regime• The recommended rate for changing the governor setting, i.e.,

supplementary control for increasing or decreasing the output (generation level) for all generating units, irrespective of their type and size, would be one (1.0) per cent per minute or as per manufacturer’s limits.

• If frequency falls below 49.5 Hz, all partly loaded generating units shall pick up additional load at a faster rate, according to their capability.

• All Regional constituents shall make all possible efforts to ensure that the grid frequency always remains within the 49.0 – 50.5 Hz band.

CAPACITY CHARGE

Related to ‘availability’ of the generating station and the percentage capacity allocated to the state.

‘Availability’ for this purpose means the readiness of the generating station to deliver ex-bus output expressed as a percentage of its rated ex-bus output capability.

ENERGY CHARGE

Energy charges shall be worked out on the basis of a paise per kwh rate on ex-bus energy scheduled to be sent out from the generating station as per the following formula

Energy charges = Rate x Scheduled Generation (ex-bus)

CGS-2 CGS-1 CGS-3

BULKCONSUMERS

SEB/SLDC 1 SEB/SLDC 2 SEB/SLDC 3

inter state IPPs

REGIONAL GRID RLDCControls

CONTROL AREA UNDER ABT FOR CONTROL AREA UNDER ABT FOR RLDCRLDC

CENTRAL GENERATION

STATETHERMAL

REGIONALGRID

STATEHYDRO

BULKCONSUMERS

DISCOM 1 DISCOM 2 DISCOM 3

STATE IPPs

CPP

STATE GRID SLDC

CONSUMERS CONSUMERS CONSUMERS

CONTROL AREA UNDER ABT FOR CONTROL AREA UNDER ABT FOR SLDCSLDC

Controls

Two PartTariff Availability Based Tariff

Based on K.P.Rao Committee Report

Based on E.C.C Report

Two Part Tariff

I. Fixed Charges

II. Variable Charges

Three Part Tariff

I. Capacity Charges

II. Energy Charges

III. U.I.Charges

Fixed charges recovery proportional to Drawal.It thus becomes single part tariff

Capacity charges recovery proportional to Entitlement / Allocation of Capacity Share

F.C. fully recovered at 62.78% PLF including deemed generation

C.C.fully recovered at T.A. of 80% as declared by the Generating Company.

TARIFF COMPARISON

Two Part Tariff Availability Based Tariff

The fuel risk is generally passed on to the beneficiaries.

The fuel risk is with NTPC.

The Rate of Return shall be 16%

The Rate of Return at 16% is protected.

Interest on Loan is at actuals & passed on to the beneficiaries.

Same to continue.

Depreciation shall be as under

Coal based = 7.84%

Gas based = 8.24%

To be charged from the beginning of the next financial year

Depreciation shall be as under

Coal based = 3.6%

Gas based = 6.0%

To be charged from the same financial year on pro rata basis.

TARIFF COMPARISON

Two Part Tariff Availability Based TariffThe O&M Charges are 2.5% of current capital cost escalated @10% per annum.

The base level od O&M shall be average of actual O&M expenses in the last five years (1995-96 to 1999-2000 )escalated twice @10% to bring it to 1999 – 2000 level.

Escalation in O&M cost to be provided on the basis of a weighted price index of CPI (40%) and WPI (60%).

Base O&M to be escalated at the rate of 6% per annum for the tariff period.

TARIFF COMPARISON

Two Part Tariff Availability Based TariffIn case actual escalation is within 20% of this, it shall be absorbed by the utility. Deviation beyond 20% will be adjusted for which petition will have to be filled.

All Tax on income including incentive is pass through.

Same shall continue.Tax on the other income streams accruing to the company shall not be pass through.

Tax Escrow account to be opened by each beneficiaries.

Tax to be billed on regional basis so that beneficiaries paying higher cost of new stations are also provided advantage of tax holiday.

TARIFF COMPARISON

Two Part Tariff Availability Based TariffInterest on working capital includes

Existing practice to continue.

TARIFF COMPARISON

a) Fuel cost for one month and fuel stock of 15 days for pit head stations & 30 days stock for non pit head stations calculated on normative PLF basis.b) 60 days stock of Secondary fuel oil calculated on normative PLF basis.c) Operation & Maintenance expenses (Cash) for one month.

Two Part Tariff Availability Based Tariff•d) Maintenance spares maximum of 1% of capital cost but not exceeding one years requirement less one fifth of initial spares already capitalised.

e) Receivables equivalent to two month’s average billing calculated on normative PLF basis.

Existing practice to continue.

TARIFF COMPARISON

Two Part Tariff Availability Based TariffNo provision of Development Surcharge.

The generating company shall be entitled to a development surcharge of 5% on every bill for fixed charges raised by it.

The D.C.shall not be payable for plants operating exclusively within a state.

Levy of Development Surcharge shall be subject to the following conditions:-

TARIFF COMPARISON


All Tax on income including incentive is pass through.

Same shall continue.Tax on the other income streams accruing to the company shall not be pass through.

Tax Escrow account to be opened by each beneficiaries.

Tax to be billed on regional basis so that beneficiaries paying higher cost of new stations are also provided advantage of tax holiday.

TARIFF COMPARISON


50% F.C. recoverable even at Zero PLF

Proportionate recovery of C.C for Availability between 0 to 80%

Could be increased to 85 % subsequently at any time if the experience dictates such a requirement

This, However could be considered for relief after due justification for plants having operational problem.

Gross Generation & Deemed Generation is Certified by REB

Availability is determined by REB based on declared capability for each time block.

Two Part Tariff Availability Based TariffFor Certification of Backing down, the capability to be determined by Unrestricted Generation during Peak Period.Backing down shall be the difference between capability and the actual generation.

No Provision for certification of Deemed Generation.

Variable Charges shall be paid on each unit of Actual Energy sent out from the station.

Energy Charges shall be paid on the Ex.Bus Schedule Energy.

Two Part Tariff A.B.T

Operating Norms

1. Heat Rate

Coal Based Station

Stabilisation : 2600 Kcal/Kwh

Subsequent Period : 2500 Kcal/Kwh

(40 Kcal/Kwh shall be deducted in 500 MW units for electrically driven BFP)

Gas / Liquid Based Station

Without Nox Control With Nox Control

Open Cycle 3150 Kcal/Kwh 3190 Kcal/Kwh

Combined Cycle 2100 Kcal/Kwh 2125 Kcal/Kwh

Existing to continue

Two Part Tariff A.B.T2. Auxiliary Power Consumption

Coal Based Station

WithC.T Without C.T

200 MW Series 9.5% 9.0%

500 MW Series

With TDBFP 8.0% 7.5%

With MDBFP 9.5% 9.0%

Gas / Liquid Based Station

Open Cycle 1.0%

Combined Cycle 3.0%

(During the stabilisation period, normative APC shall be reckoned at 0.5% over and above the figure specified above.)



3. Secondary fuel Oil Consumption

Stabilisation Period 5.0 ml/Kwh

Subsequent Period 3.5 ml/ Kwh

4. Stabilisation Period Stabiliation period commencing from the date of commercial operation shall be reckoned as follows :

Coal Based / Thermal Station 180 Days

Open cycle Gas & Naptha based station 90 Days

Combined cycle gas & Naptha based station 90 Days



5. Date of Commercial Operation The date of commercial operation operation of individual units shall be reckoned as follows :

Coal Based / Thermal Station Not exceeding 180 days from the date of synchronisation.

Gas / Liquid Based Station From the date of Synchronisation


Two Part Tariff Availability Based TariffIncentive is payable @ 1 Paisa / Kwh for every 1% increase in PLF (Including deemed generation) above 68.49 % .

Incentive is payable on PLF above 77%.Only the Schedule Generation shall be taken into account for PLF.

The incentive rate shall be 50% of Fixed Cost (P/Kwh) limited to 21.5 P/Kwh upto 90% PLF.Beyond 90% this rate will be reduced to half.

Incentive billing in the ratio of Fixed Charges billed.

Incentive billing in the ratio of Energy Scheduled by beneficiaries beyond target PLF.


No provision for Unscheduled Interchange Charges.

Unscheduled Interchange Charges shall be applicable on the difference between actual generation / drawal and the schedule generation / drawal.

U.I. Shall be worked out on each 15 minute time block.

U.I. Rate be based on the average frequency of the time block.


No provision for Unscheduled Interchange Charges.

The U.I. Rates are as under.•50.5 Hz and above = Zero•49.0Hz and below = 420 P/Kwh•Between 49.0Hz & 50.5 Hz the UI rate is linear in steps of 0.02 Hz which is 4.8 Paisa

NEW TARIFF POLICY FROM 01.04.04

About New Tariff

• Date of implementation - 01-04-2004

• Duration of tariff - 5 years

Present Tariff Vs New Tariff

Parameter Earlier Present

Target PLF for Incentive (Based on schedule Generation)

77% 80%

Present Tariff Vs New TariffParameter Earlier Present

Gross Station Heat Rate

During stabilization

- 200 /210MW

- 500 MW

2600

2600

2600

2550

Subsequent period

- 200 /210MW

- 500 MW

2500

2500

2500

2450

* Will leads to reduction in marginal contribution for 500 MW sets


Description Earlier Present

Secondary fuel oil consumption-Stabilization period (ml /kwh)- Subsequent period

5 ml

3.5

4.5 ml

2.0

•Norms may be reviewed after 2 years• Reduction in marginal contribution

Present Tariff Vs New TariffAPC

Unit size Earlier Present

(MW) With CT With out CT

With CT Without CT

200 9.5 9.0 9.0 8.5

500 with TDBFP

8.0 7.5 7.5 7.0

500 with MDBFP

9.5 9.0 9.0 8.5

* Will leads to less energy charges


• Stabilization period and relaxed norms applicable during stabilization period shall cease to apply from 01-04-2006.



Ceiling norms for capitalized initial spares

Reasonable 2.5% of plant & equipment cost

Return of equity

Earlier Present

CGS -16%

IPP – 16%

14%

14% (if payment security mechanism similar to central power sector utilities is provided by Govt)

16% (if no payment security mechanism similar to central power sector utilities is provided by Govt)

O&M Expenses

Earlier Present

1. Average of actual O&M expense from 95-96 to 99-00 is considered as O&M

Expense of 97-98

2. Above average value is escalated twice at 10% per annum to arrive the base year O&M expense for 99-00

Year 200 500 MW

04-05 10.4 9.36

05-06 10.82 9.73

06-07 11.25 10.12

07-08 11.70 10.52

08-09 12.70 10.95

Rs. Lakh / MW

Interest on working capitalDescription Earlier Present

Secondary fuel oil corresponding to target availability

Two month One month

Rate of interest Cash –credit rate prevailing at the time of tariff filing

Short term prime lending rate of SBI as on 01-04-04

Landed cost of coal

Earlier Present

Actual landed cost Landed cost after considering the normative transit and handling losses

Pit head station – 0.3%

Non pit head station – 0.8%

Incentive

Earlier Present

Upto 90% SG PLF-50 % of fixed cost /kwh subject to ceiling of 21.5 paisa / kwh

Above 90% SG PLF

- 50% of above rate

25 paisa / kwh

* Incentive will now be more particularly for old stations like Singrauli

UI Rate


Max ( 49.02 Hz and below) 420 570 p

Min (50.5 Hz and above) 0.00 0.00

Between 49.02 to 50.48

Linear in 0.02 Hz step

5.6 8.00 p

Paisa/ Kwh

Rebate


Payment of Bill through LC 2.5% 2.0%

Scheduling Process

Day ahead

• By 10 AM, RLDC collects the plant-wise ex- Bus MW capability of ISGSs for the next day

• By 11 AM, RLDC advises SEBs, on a 15 minutes blockwise level, their entitled MW shares from each ISGSs’ availability

• By 3 PM, RLDC receives block-wise MW requisition from SLDCs and also the schedule of bilateral exchanges, if any

• By 5 PM, RLDC issues ‘despatch schedules’ for ISGSs and ‘net drawal schedules’ for SEBs, 15 minutes block-wise for the next day starting at midnight.

• Upto 10 PM SLDCs may inform any change of the above or bilateral exchanges to RLDC, if required by any new development during the day.

• At 11 PM Schedules are frozen for the next day. RLDC issues final drawal schedules to each State & Despatch schedule to each ISGS.

REVISIONREVISION OF SCHEDULES / REQUISITIONSOF SCHEDULES / REQUISITIONS

Revision of schedules are permitted due to contingency such as:-

Outage of generating unit.

Revised declaration of availability by CGS.

Outage of a transmission element.

Unforeseen load-crash.

REVISION OF SCHEDULES / REQUISITIONS

Revision takes effect from:- 4th Time Block in case of

Forced outage of a generating unit Transmission constraint Grid disturbance Suo Moto revision by RLDC, in the interest of grid stability

6th Time Block in case of Revision of declared availability by CGS Revision by beneficiaries due to unforeseen load-crash

Tripping of 500MW unit

Tripping of 500MW unit

Stopping of 500 MW unit

Stopping of 500 MW unit

SPECIAL ENERGY METERS (SEM)SPECIAL ENERGY METERS (SEM)To implement ABT, Special Energy Meters (SEM) have been provided at

the following locations

At generating stations - main & check meters on the outgoing feeders from the generator

SEM can record:-

Average frequency for each 15 minutes time block.

Average net energy transmitted for each 15 minutes time block.

Cumulative net energy transmitted.

SEMs Specification• Static type

• Composite meter

• Highest accuracy available in the power industry

• 3 Phase – 4 wire connections/measurement

• Direct measurement in whrs and varh on the CT/PT secondaries– 110 V Ph to Ph /63.51 V Ph – N– 1 amp or 5 amp– VA burden not more than 10 on any of the phases

• Works on real time clock

• No calibration required

• METERING AND ACCOUNTING:

– METERING INSTALLATION,TESTING,OPERATION -MAINTENANCE OF

METERS AND COLLECTION- TRASNSPORTATIONAND PROCESSING OF DATA REQUIRED FOR ACCOUNTING OF ENERGY CHARGES AND AVAILABILITY, FREQUENCY ON 15 MIN BLOCK SHALL BE PROVIDED BY PGCIL/RLDC.

– DATA PROCESSED SHALL BE SUPPLIED BY RLDC TO REB FOR REGIONAL ENERGY ACCOUNTING ON MONTHLY BASIS AND UI CHARGES FOR BILLING ON WEEKLY BASIS.

In case of a generating station, contracting to supply power only to the State in which it is located, the scheduling, metering and energy accounting shall be carried out by the respective State Load Despatch Centre.

NATURAL MERIT ORDERNATURAL MERIT ORDERNATURAL MERIT ORDERNATURAL MERIT ORDER

GAMING POSSIBILITIES

A GENERATOR MAY ALSO UNDER-DECLARE ITS CAPACITY TO EARN UNDESERVED UI CHARGES (UNDER DEFICIT CONDITIONS).

WITH DECLARED AVAILABILITY AS THE KEY FACTOR FOR REIMBURSEMENT OF FIXED CHARGES AND RATE OF RETURN, A GENERATOR MAY OVER-DECLARE ITS CAPACITY (IN SURPLUS CONDITIONS).

THEREFORE, THERE IS A NEED FOR VERIFICATION OF VERACITY OF THE AVAILABILE CAPACITY AS DECLARED BY THE GENERATOR.

IMPORTANT ISSUES INVOLVED ARE :- WHO CAN CALL FOR DEMONSTRATION.- PROCEDURE FOR TESTING THE DECLARED CAPACITY.- CONSEQUENCES OF NON-DEMONSTRATION.

• Generating Company may be required to demonstrate DC as and when asked by RLDC

• Failing which the capacity charges due to the generator shall be reduced as a measure of penalty.

• For repeated mis declaration the penalty shall be multiplied in Geometric progression

• Operating log books shall be available to REB/RPC for the review

Further benefits expected

UI mechanism For the intra-State stations

• State stations would respond to grid conditions • Higher power availability during peak-load hours• Reduced load shedding

How to bridge Demand - supply gap Harnessing the existing captive and co-generation

power into the grid and pay as per the frequency-linked UI rate.

The State would financially gain with respect to regional grid at the prevailing UI rate.

UI is a very versatile mechanism. It can even be applied for non-conventional generation (solar, bio-mass, wind, mini-hydel) to gainfully harness the capacity, which may not come into the grid otherwise.

OPTIMUM UTILIZATION OF

INTRA - STATE RESOURCES

Actual net drawal exceeds the net drawal schedule the State has to pay UI charges.

• This liability can be reduced by restricting the overdrawal, particularly when frequency is below normal.

• This in turn requires maximization of output from all intra-State stations, which means that there is a pressure on each State as well for perpetually enhancing the availability of all intra-State stations

In the absence of Availability Tariff for intra-State stations, these stations have no direct incentive acting on them for maximizing their availability.

IMPROVEMENTS BROUGHT BY ABTIMPROVEMENTS BROUGHT BY ABT

Quantum improvement in system parameters Grid frequency Voltage profile

Innovative methods in system operation Pump operation at Kadampurai Re-arrangement of electrical loads Optimal utilization of reservoirs Condenser mode operation of Idukki

Inter regional trading Win-win situation for both regions Opportunistic UI transaction

Expectations from OEM

• High Reliability

• Least equipment down time

• For High Availability of equipments : Maintenance of High Quality Standards while manufacturing , erection & Commissioning

• Adhering to the Free governor mode operation

Expectations from Generators & Grid Operators

• Ensuring Reliable power with high availability specifically during peak hours

• Demand side Management

MAJOR REGULATORY EVENTSMAJOR REGULATORY EVENTS

• ABT, Grid Code , FGMO In the past, frequent grid disturbances. No major grid

disturbances now With ABT improved grid discipline and better grid

security.• Tariff norms for 2001-04 and 2004-09.

Shift from cost plus to normative tariff to promote efficiency.

• Open access & power trading regulations Optimum utilisation of surplus capacities Development of market No. of Licensees in Trading Business - 17

• Depreciation and Return are the factors which promote investment in the sector,

constitute only 11% and should not be targeted for cost reduction.

8%

6%

7%

35%

6%

8%

5%

25%

100%

8%

6%

7%

35%

6%

8%

5%

25%

100%

Fuel O&M

Return & dep

O&M

AT&C Int. TotalDep. &Return

Intrest

------------------Generation--------------- -----------------T & D---------------

ELEMENTS OF COST OF POWERELEMENTS OF COST OF POWER

FIXED AND VARIABLE CHARGES FOR RAMAGUNDAM - PITHEAD (AT 80% PLF)

0

20

40

60

80

100

120

140

'03-

04

'02-

03

'01-

02

00-0

1

99-0

0

98-9

9

97-9

8

96-9

7

95-9

6

94-9

5

93-9

4

92-9

3

YEAR

PA

ISE

/Kw

h

Fixed Charges Variable Charges

Cost plus system though inevitable in the absence of an established market, has certain deficiencies…

Discourages Efficiencies

Micro Management

•Financials•Technological•Operating

•Detailed scrutiny of technology•Technology/Equipment vetting•Time consuming process

Not tuned to dynamic structure

•Enhanced participation of private sector players•Faster approvals (tariff etc.)

Any structure modification need to consciously take into account the constraints to include necessary enablers

Generation Regulated on cost plus basis

Transmission Regulated on cost plus basis

Distribution Regulated on cost plus basis

Generation Un-Regulated

Transmission Regulated on cost plus basis

Distribution Regulated price cap

Cost plus system though inevitable in the absence of an established market, has certain deficiencies…

Present System Target System

Target System will take some time to evolve

An interim structure needs to be established which also takes care of specific sectoral issues

The interim structure need to enable capacity buildup & release, incentivize productivity and compensate systemic deficiencies…

Interim Tariff Structure

Regulated on Normative Basis• Determination of normative costs• Normative financing plan• Normative O&M costs• Normative Operating Parameter• Judiciously established enablers

• Institute Technology Development Fund• Time of the day bias in the tariff chain• O&M charges towards maximizing reliability• Incentives for top range efficiency bracket• Enable advanced technologies induction• Catalyze R&M and life extension• Catalyze candidate energy sources • Traditional project cost appraisal on norms• Advanced technology projects on active scrutiny• Chronic Fuel uncertainties to be compensated

Following enablers need to be suitably included in the new tariff framework to provide a proactive instrument:

Necessary institutional arrangements, monitoring and control systems will need to be developed to enable and maintain systemic effectiveness

DEVELOPMENT OF MARKETDEVELOPMENT OF MARKET• Competition and market mechanism – to being in efficiency and

reduction in cost of supply.

• Actions required –

– Open access in distribution

– Intra-state ABT

– Trading under deficit conditions – need of more power for sale in market

• Merchant capacities

• Plant after useful life at the disposal of investor for sale of power in the market at a tariff of 50-60 P/kWh - to enable R&M

• Transmission constraints resulting in bottling up of generation, high cost power is being scheduled whereas pit-head stations remaining unrequisitioned – Transmission priority for low cost power

• Release of part capacities of existing stations for sale in market.

• Intra-state ABT• Power exchange• Reforms in Distribution for reduction in AT&C

losses Retail tariff rationalisation Open Access in Distribution IT in distribution Competition in retail supply

With the above only power at RIGHT price is possible

SuggestionsSuggestions

Thank You

availability based tariff

Documents

tariff tariff structures

tariff concept

current tariff approach

indian tariff approach

capacity utilization

equitycapital cost

cost of energyit

customer capacity utilization