Economics of Power Generation

Power Generation Business in Electricity Sector

• Pre-NTPC Players– BBMB– Nuclear Power– Neyveli Lignite– Badarpur TPS

• Post NTPC– Amendment in Electricity Supply Act 1948, to include

Generation Business– Enabled new entities in Power Production, like NTPC,

NHPC, NPC and a host of IPPs

Evolution of Bulk Electricity Tariff in India

• Single Part Tariff: – Both Fixed Charges and Variable Charges realized in

one part as energy charge.• Existed before NTPC• Initially adopted for NTPC

– Causes Over / Under charging • Distorts Economic Dispatch (Merit Order Operation) • Resentment by customers• Under drawal accrues monetary benefit to beneficiaries:

Unhealthy competition to prevent / reduce drawals• Rogue customers use capacity at no cost by returning

energy when surplus– Need to change to avoid the above was felt.


• Conventional Two Part Tariff: – Fixed Charges and Variable Charges computed

separately • Fixed Charges compensate for the cost of capacity, including

investment cost• Variable Charges compensates for cost of energy

– Fixed Charges booked against Maximum Demand (or Contracted Demand) in Rs/kW

– Variable Charges realized against energy consumed, in Rs/KWh

– Provides the correct market perception.


• K P Rao Tariff (1992)– A pseudo Two Part Tariff

• Fixed Charges and Variable Charges computed separately • Both Fixed Charges and Variable Charges booked and realized in

one part against energy drawn during the billing period.

– Causes no Over / Under charging – Promotes incorrect market perception

• Continued to Distort Economic Dispatch • Resentment by customers• Under drawal accrues monetary benefit to beneficiaries: Unhealthy

competition to prevent / reduce drawals• Rogue customers use capacity at no cost by returning energy when

surplus

– Laid down fairly sound costing principles, still in vogue.


• ECC (Energy Control Consultants, Fairfax, USA) Report: – GoI appointed ECC to study and recommend Bulk Power and

Transmission Tariff for India as K P Rao tariff was soon resented by customers

• Report submitted in 1994; Accepted by GoI in 1995 • Implementation delayed till 2003, due to dispute on principles as well as

structure• NTF & RTF (National and Regional Task Forces) debated

implementation modalities of ECC recommendations – Several sub groups were formed, some recommendations of ECC were

modified and final implementation was agreed by 1998-99.• Electricity Regulatory Commissions formed in 1998; tariff setting

role transferred from Government of India to CERC– ABT order issued by CERC for ISGS, along with Inter-system exchange

Tariff in 1999; stipulated mock trial to begin– ABT finally implemented progressively from 2003


• ABT as Implemented (Generation) – A true two part tariff with supplementary adjustment for Net Exchange

deviations from schedule• Fixed cost recovered against Capacity made available; Full recovery at pre-

set EAF• Energy Charges recovered against requisitioned (scheduled, ex-bus) energy

at normatively computed rates– Actual Energy Generation (AG, measured ex-bus) would be different

from scheduled and the deviations positive or negative settled at a price linked to system sufficiency, in that time slice.

• Time slice of 15 minutes each in use• Average Frequency of operation in the time slice used as an index of system

sufficiency• Settlement through a pool account

– Promotes better market perception• Encourages Economy in Dispatch• Avoided cost of service by rogue beneficiary is prevented.


• ABT as Implemented (Beneficiary)– A true two part tariff with supplementary adjustment for Net Exchange

deviations from schedule• Fixed cost recovered from customers in proportion to capacity allocation • Energy Charges recovered against requisitioned (scheduled, ex-bus) energy

at normatively computed rates, on the respective drawal schedule– Actual Energy Generation (AG, measured ex-bus) would be different

from scheduled and the deviations positive or negative settled at a price linked to system sufficiency, in that time slice.

• Time slice of 15 minutes each in use• Average Frequency of operation in the time slice used as an index of system

sufficiency• Settlement through a UI pool account

– Promotes better market perception• Encourages Economy in Dispatch• Avoided cost of service by rogue beneficiary is prevented.

Power Pools / Market Mechanism

• Power Pools– What is a Power Pool? An Interconnected / Integrated Power

System where, the resources of the participating utilities are pooled and advantages are shared

• Regional Electricity Systems to operate as “Loose Power Pools”. In a loose Power Pool the individual Utility / Control Area dispatches its own sources: Ref: IEGC (Market Mechanism Option “C” of ECC report)

• “Tight Power Pools” are where the Pooled sources are centrally dispatched e.g. PJM in US (Market Mechanism Option “A” of ECC report

– With unbundling of State Utility (SEB), IEGC stipulates that each state would be treated as a notional Control Area (i.e. UI transactions will be settled at the States’ periphery

WHAT IS AVAILABILITY BASED TARIFF ?

IT STANDS FOR A RATIONAL TARIFF STRUCTURE FOR POWER SUPPLY

FROM GENERATING STATIONS

ON A CONTRACTED BASIS.

WHY WAS ABT NECESSARY?

1. PRIOR TO ABT,REGIONAL GRIDS OPERATED IN A UNDISCIPLINED AND HAPHAZARD MANNER. THERE WERE LARGE DEVIATIONS IN FREQUENCY.

2. 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


3. HIGH FREQUENCY IS A RESULT OF INSUFFICIENT BACKING DOWN OF GENERATION WHEN THE TOTAL CONSUMER LOAD HAS FALLEN DURING OFF-PEAK HOURS


4. 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.

5. IT WAS PROFITABLE TO GO ON GENERATING AT A HIGH LEVEL EVEN WHEN THE CONSUMER DEMAND HAD COME DOWN.

6. THE EARLIER TARIFF MECHANISMS ENCOURAGED GRID INDISCIPLINE.

COMPONENTS OF ABT

1. CAPACITY CHARGE2. ENERGY CHARGE3. UI CHARGE

4. INCENTIVE

5. TAXES & CESS

FIXED AND VARIABLE COSTS

VARIABLE COSTS ?

1. INTEREST ON LOAN.2. RETURN ON EQUITY3. DEPRECIATION4. O&M EXPENSES.5. INTEREST ON WORKING CAPITAL

COST

FIXED COSTS ?

VARIABLE COST IS FUEL COST i.e. COST OF GAS & NAPHTHA

PAYMENT OF FIXED COST

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 TO DAY BASIS.

THE ANNUAL AMOUNT PAYABLE DEPENDS ON THE AVERAGE AVAILABILTY OF THE

PLANT OVER THE YEAR.

PAYMENT OF FIXED COST

IN CASE AVAILABILITY IS LOWER THAN NORMATIVE THE GENERATING COMPANY

GETS A LOWER PAYMENT.

HENCE THE NAME ‘ AVAILABILITY TARIFF’THIS COMPONENT OF ABT IS TERMED AS

CAPACITY CHARGE

FULL PAYMENT OF FIXED CHARGES AT 80% OR ABOVENO PAYMENT OF FIXED CHARGES AT 0%.PRO- RATA PAYMENT FOR IN BETWEEN

VARIABLE CHARGES

IT COMPRISES OF THE VARIABLE COST i.e FUEL COST OF THE POWER PLANT FOR GENERATING ENERGY AS PER GIVEN SCHEDULE FOR THE DAY.

SECOND COMPONENT OF ABT AND IS ALSO CALLED AS ENERGY CHARGE.

ENERGY CHARGE IS BASED ON SCHEDULE GENERATION AND NOT ON ACTUAL GENERATION

VARIABLE COST?

VARIABLE COST IS DECIDED AND PAYABLE AS PER SCHEDULE.

TO TAKE CARE OF PRICE VARIATIONS IN FUEL WE HAVE FUEL PRICE ADJUSTMENT.

NORMS FOR VARIABLE COST ARE :-HEAT RATE OF 2075 KCAL/KWHAPC OF 3%.OPEN CYCLE HEAT RATE OF 3010 KCAL/KWHAPC OF 1%

BEF

UI CHARGE

IN CASE OF POSITIVE DEVIATIONS FROM SCHEDULE THAT IS GENERATION HIGHER THAN SCHEDULE

ENERGY CHARGE IS AS PER SCHEDULE

EXCESS GENERATION GETS PAID FOR AT A RATE DEPENDENT ON THE GRID FREQUENCY PREVAILING.

IF GRID FREQUENCY IS AT 50 HZ OR HIGHER THE RATES WOULD BE LOWER.

IF GRID FREQUENCY IS AT BELOW 50 HZ THE RATES WOULD BE HIGHER.

IN CASE OF UNDER GENERATION UI CHARGE WOULD BE NEGATIVE.

HOW DOES ABT WORK?

PROCESS STARTS:1. CENTRAL GENERATING STATIONS DECLARE

EXPECTED OUTPUT CAPABILITY IN 96 TIME BLOCKS OF 15 MINUTES DURATION EACH FOR THE NEXT DAY TO REGIONAL LOAD DESPATCH CENTRE.(RLDC)

2. RLDC BREAKS UP AND TABULATES AS PER BENEFICIARIES PLANT WISE SHARES AND CONVEYS ENTITLEMENTS TO STATE LOAD DESPATCH CENTRES.(SLDC)

HOW DOES ABT WORK?

3. SLDC CARRY OUT EXERCISE TO MEET THE LOAD OF THEIR CONSUMERS OVER THE DAY, FROM THEIR OWN GENERATING STATIONS ALONG WITH THEIR ENTITLEMENTS FROM CENTRAL GENERATING STATIONS. THEY ALSO TAKE INTO ACCOUNT IRRIGATION REQUIRMENTS AND LOAD SHEDDING.

4. SLDC CONVEYS TO RLDC THEIR SCHEDULE OF POWER DRAWL FROM THE CENTRAL GENERATING STATIONS.

HOW DOES ABT WORK?

5. RLDC AGGREGATES THE SCHEDULES BY SLDCs AND DETERMINES THE SCHEDULES FOR THE CENTRAL GENERATING STATIONS DULY INCORPORATING BILATERAL AGREEMENTS AND TRANSMISSION LOSSES.

6. RLDC CONVEYS THE SCHEDULE TO ALL CONCERNED AND BECOME THE OPERATIONAL AND COMMERCIAL DATUM.

HOW DOES ABT WORK?

7. IN CASE OF CONTINGENCY, CENTRAL GENERATING STATIONS CAN REVISE DECLARATION,BENEFICIARIES CAN REVISE REQUISITIONS AND SCHEDULES ARE REVISED ACCORDINGLY.

8. SCHEDULES ARE USED FOR DETERMINATION OF THE AMOUNT PAYABLE AS ENERGY CHARGES.

9. DEVIATIONS ARE MEASURED THROUGH SPECIAL METERING AND PRICED AS PER FREQUENCY.

DC AT ANTA

ABT ADDRESSES GRID INDISCIPLINE

1. ABT GIVES INCENTIVES FOR ENHANCING OUTPUT CAPABILITY OF POWER PLANTS,IT ENABLES MORE CONSUMER LOAD TO BE MET DURING PEAK HOURS.

2. BACKING DOWN DURING OFF-PEAK HOURS NO LONGER RESULTS IN FINANCIAL LOSS TO GENERATING STATIONS AND THE EARLIER INCENTIVE FOR NOT BACKING DOWN IS NEUTRALISED.

3. THE SHARES OF BENEFICIARIES IN THE CENTRAL GENERATING STATIONS ACQUIRE A MEANING,WHICH WAS PREVIOUSLY MISSING.

DOES ABT BENEFIT EVERYONE?

1. ABT HAS DRAMATICALLY STREAMLINED THE OPERATION OF REGIONAL GRIDS IN INDIA.

2. THROUGH THE SYSTEM AND PROCEDURE IN PLACE, CONSTITUENTS SCHEDULES GET DETERMINED AS PER THEIR SHARES IN CENTRAL STATION AND THEY CLEARLY KNOW THE IMPLICATIONS OF DEVIATING FROM THESE SCHEDULES.

3. GRID PARAMETERS i.e. VOLTAGE AND FREQUENCY HAVE IMPROVED AND EQUIPMENT DAMAGE CORRESPONDINGLY REDUCED.


4. DURING PEAK LOAD HOURS FREQUENCY CAN BE IMPROVED ONLY BY REDUCING DRAWLS,AND NECESSARY INCENTIVES ARE PROVIDED IN THE MECHANISM FOR THE SAME.

5. HIGH FREQUENCY IS BEING CHECKED BY ENCOURAGING REDUCTION IN GENERATION DURING OFF-PEAK HOURS.

6. BECAUSE OF CLEAR SEPARATION BETWEEN FIXED AND VARIABLE CHARGES,GENERATION ACCORDING TO MERIT ORDER IS ENCOURAGED AND PIT HEAD STATIONS DO NOT HAVE TO BACK DOWN NORMALLY.


7. MECHANISM IS ESTABLISHED FOR HARNESSING CAPTIVE AND CO-GENERATION AND FOR BILATERAL TRADING BETWEEN THE CONSTITUENTS.

8. ABT BY REWARDING PLANT AVAILABILITY ENABLES MORE CONSUMER LOAD TO BE CATERED AT ANY POINT OF TIME.

DAILY SCHEDULING PROCESS

1. SUPPOSE A 1000 MW CENTRAL COAL FIRED POWER STATION HAS THREE BENEFICIARIES-STATES-A,B,C.

2. THE BENEFICIARY-STATES-HAVE ALLOCATED SHARE OF 30,30 & 40% RESPECTIVELY.

3. STATION FORESEES A CAPABILTY TO DELIVER 900 MW (EX-BUS) NEXT DAY AND ADVISES THE SAME TO RLDC BY 0900 AM.


4. RLDC BREAKS UP THE CAPABILITY CONSTITUENT WISE AND ADVISES THE THREE SLDCS BY 10AM REGARDING ENTITLEMENTS OF 270,270 & 360 MW RESPECTIVELY.

5. SLDC RECEIVES AVAILABILTY STATUS FROM INTRA STATE STATIONS. CARRIES OUT EXERCISE TO MEET EXPECTED CUSTOMER DEMAND IN THE STATE FOR NEXT 24 HOURS AFTER COMPARING VARIABLE COSTS OF VARIOUS INTRA STATE POWER STATIONS WITH ENERGY CHARGE OF CENTRAL GENERATING STATIONS.


6. AFTER THE EXERCISE SLDCs WILL ISSUE DISPATCH SCHEDULE FOR THE INTRA –STATE STATIONS AND THEIR REQUISITION FROM CENTRAL STATIONS .

7. SUPPOSE STATES A & B FULLY REQUISITION THEIR SHARES FROM THE CENTRAL STATION UNDER CONSIDERATION (270 MW EACH WHILE STATE-C REQUISITIONS 360 MW DURING THE DAY TIME & 200 MW DURING NIGHT.


8. SUMMATION OF THREE REQUISITIONS WOULD PRODUCE FOR THE CENTRAL STATION TOTAL DISPATCH SCHEDULE OF 900 MW DURING DAY & 740 MW DURING NIGHT. RLDC ISSUES SCHEDULE BY 5 PM & EFFECTIVE MIDNIGHT.

9. STATES A,B & C SHALL PAY CAPACITY CHARGE CORRESPONDING TO PLANT AVAILABILITY OF

270,270&360 MW RESPECTIVELY. 10. GENERATING STATION WOULD GET CAPACITY CHARGE

CORRESPONDING TO 900 MW. ENERGY CHARGE PAYMENTS BY STATES WOULD BE FOR

270X24 MWH, 270X24 MWH & (200X24+160X16) MWH RESPECTIVELY AT THE RATE OF THE GENERATING STATION

DEVIATIONS FROM SCHEDULE?

THE ENERGY ACTUALLY SUPPLIED BY THE GENERATING STATION MAY DIFFER FROM SCHEDULE.

IF ACTUAL ENERGY SUPPLIED WERE HIGHER THAN SCHEDULE THE STATION WOULD BE ENTITLED TO RECEIVE A PAYMENT FOR THE EXCESS ENERGY AT A RATE DEPENDENT ON FREQUENCY AT THAT TIME.

IF ACTUAL ENERGY SUPPLIED WERE LOWER THAN SCHEDULE THE GENERATING STATION SHALL HAVE TO PAY BACK FOR THE ENERGY SHORTFALL AT THE SAME FREQUENCY LINKED RATE.

DEVIATIONS FROM SCHEDULE FOR STATES?

IF ENERGY DRAWN BY THE STATE IS IN EXCESS OF THE SCHEDULE IT HAS TO PAY FOR THE EXCESS ENERGY AT THE SAME FREQUENCY DEPENDENT RATE .THE HIGH UI RATE DURING LOW FREQUENCY WOULD INDUCE ALL STATES TO REDUCE DRAWL FROM THE GRID.

DURING LOW FREQUENCY IF A STATE DRAWS LESS POWER THAN SCHEDULED,IT PAYS FOR SCHEDULED ENERGY AT THE NORMAL RATE AND GETS PAID BACK FOR ENERGY NOT DRAWN AT A MUCH HIGHER UI RATE.

DEVIATIONS FROM SCHEDULE FOR STATES?

DURING HIGH FREQUENCY CONDITIONS, A STATE CAN DRAW EXTRA POWER AT A LOW RATE AND IS ENCOURAGED TO BACK DOWN ITS OWN COSTLIER GENERATING STATIONS.

AN UNDER DRAWL DURING HIGH FREQUENCY CONDITIONS MEANS THAT THE STATE PAYS FOR THE SCHEDULED POWER QUANTUM UNNECESSARILY. IT SHOULD EITHER REDUCE ITS SCHEDULE OR INCREASE ITS DRAWL.ALL UI PAYMENTS ARE MADE INTO AND FROM A REGIONAL UI POOL ACCOUNT,OPERATED BY THE CONCERNED RLDC.

TRADING OPPORTUNITIES WITHIN ABT?

IN CASE OF SCHEDULE LOWER THAN DC, OPTIONS AVAILABLE TO GENERATING STATION:-

1. BACK DOWN DURING OFF-PEAK HOURS. IN THIS CASE STATION GETS CAPACITY

CAHRGE AS PER DC DECLARED AND ENERGY CHARGE AS PER SCHEDULE

2. FIND A BUYER FOR THE OFF PEAK SURPLUS AND GENERATE POWER ADDING THE MW AGREED BY THIS BUYERTO AGGREGATE SCHEDULE FOR STATES A,B,&C.


AS THE STATION IS ALREADY BEING PAID CAPACITY CHARGE FOR 900 MW IT MAY NOT BE TOO PARTICULAR ABOUT FURTHER FIXED COST RECOVERY.

TRADING IS BENEFICIAL ON ACCOUNT OF :-1. IF ENERGY SALE RATE AGREED UPON IS

HIGHER THAN FUEL COST PER KWH.

2. TECHNICAL PROBLEMS ASSOCIATED WITH BACKING DOWN ARE REDUCED.

3. STATION EFFICIENCY IS IMPROVED.

4. STATION MAY LOOK FOR CUSTOMER PAYING HIGHEST RATE AND MAXIMIZE ITS PROFIT.


3. GENERATE UI: STATION MAY ACCEPT SCHEDULE GIVEN BY

RLDC BUT GENERTAE TO ITS FULL CAPACITY OF 900 MW EVEN DURING PEAK HOURS.

FOR OVERSUPPLY STATION GETS PAID UI FROM POOL ACCOUNT AS PER FREQUENCY LINKED RATE. IF FREQUENCY IS LOW THE STATION WOULD GAIN IF UI RATE IS HIGHER THAN FUEL COST PER KWH.

OPPORTUNITIES TO THE BENEFICIARY WITHIN ABT?

1. REQUISITION POWER ONLY AS PER ITS OWN REQUIREMENT AND DRAW POWER AS PER THE RESULTING SHEDULE.

2. REQUISITION FULL ENTITLEMENT FOR 24 HOURS ,FIND A BUYER FOR THE OFF-PEAK SURPLUS AND SCHEDULE A BILATERAL SALE.

3. REQUISITION FULL ENTITLEMENT FOR 24 HOURS, BUT DRAW POWER ONLY ACCORDING TO ITS ACTUAL REQUIREMENT. FOR THIS THE STATE WOULD GET UI PAYMENT. THE STATE HAS ONLY TO BE WATCHFULL THAT UI RATE REMAINS HIGHER THAN ENERGY CHARGE.

TARIFF POLICY 2009-14

Operating Norms Target Availability (NAPAF) for recovery of fixed

charges and incentive 85% for all stations except Talcher TPS,Badarpur TPS- 82%

Auxiliary Power Consumption 200 MW units: 9%; 500 MW units & above: 6.5%

o W/O CT: less 0.5%; with MDBFP: 2.5% extra Talcher TPS- 10.5%; Tanda TPS- 12%; Badarpur TPS- 9.5% CCGT: 3.0%; Open-cycle: 1.0%

Specific Oil Specific Oil 1 ml and 50% of saving w.r.t actual to be shared

with beneficiaries

Issues• Gas Station Availability has been made 85%.• ‘declared capacity’ or ‘DC' has been defined as the capability to

deliver ex-bus electricity in MW duly taking into account the availability of fuel or water, and subject to further qualification in the relevant regulation

• Earlier note that total DC will be sum of DC on gas and liquid fuel has been deleted

• Regulation also provides that in case of main fuel shortage, the generating company may propose to deliver a higher MW during peak-load hours by saving fuel during off-peak hours. The concerned Load Despatch Centre may then specify a pragmatic day-ahead schedule for the generating station to optimally utilize its MW and energy capability, in consultation with the beneficiaries. DC in such an event shall be taken to be equal to the maximum peak-hour ex-power plant MW schedule specified by the concerned Load Despatch Centre for that day – It may amount to peaking operation

• In case of NTPC APM,RLNG, Liquid fuel are all main fuel since these are being procured with prior consent of beneficiaries

• Need for creating storage capacity at Anta and Auraiya• Need for arranging coal for ER stations

Recovery of Fixed Charge -Incentive/ Disincentive

Fixed Charges (inclusive of incentive) payable on calendar month basis

– For stations > 10 years = (AFC x NDM / NDY) x (PAFM / NAPAF) – For stations <= 10 years = (AFC x NDM / NDY) x 0.5 (1.0 + PAFM / NAPAF)

• Even if plant availability for a particular month is nil, station will recover 50% of fixed charge

– Provided In case the plant availability factor achieved during a year < 70%, total fixed charge for the year shall be restricted to

AFC x (0.5 + 35/ NAPAF) x (PAFY /70)– In case of shortage of main fuel; the generator may propose to deliver a

higher MW during peak load hours by saving fuel during off peak hours. RLDC may then specify pragmatic day ahead schedule after consultation with beneficiaries.

– In all such cases, the maximum MW scheduled during peak hours shall be taken as the DC for the day.

Rate of incentive/ disincentve for stations > 10 years – same as capacity charge and for others half the capacity charge rate

Computation of Energy Charge• Computation of Energy charges (EC)

– EC covering primary fuel cost shall be payable for total ex-bus energy scheduled to be supplied to the beneficiary during the calendar month, at the specified energy charge rate.

– Energy charge rate (ECR) in Rs. per kWh on ex-power plant basis: • For coal or lignite fired based stations

ECR = (GHR – SFC x CVSF) x LPPF x 100 / {CVPF x (100 – AUX)}• ECR is arrived at after reducing GHR by heat from 1 ml secondary fuel• Sharing of actual secondary oil consumption will be as per formula below• (SFC x NAPAF x 24 x NDY x IC x 10 -ACsfoy) x LPSFy x 0.5• Need for re determination of ECR at the end of year based on actual

sharing• Actual secondary oil consumption should correspond to 85%

generation or actual generation• For gas or liquid fuel based stations

ECR = GHR x LPPF x 100 / {CVPF x (100 – AUX)}

– Landed Cost of Coal – • Price of coal corresponding to the grade and quality inclusive of

royalty, taxes and duties applicable & transportation cost• Considering normative transit and handling losses :• Pit head stations : 0.2% ; Non-Pit head stations : 0.8%

FUELS BEING USED

TYPE SOURCE

APM ONGC GAS FROM MUMBAI HIGH, UNDER GOI ADMINISTERED PRICE.

PMT JV OF ONGC+RELIANCE+BRITISH GAS, PRESENTLY UNDER GOI ADMINISTERED PRICE.

GAIL SPOT-RLNG

LIQUIFIED NATURAL GAS PURCHASED FROM SPOT MARKET BY GAIL.

GSPCL-RLNG LIQUIFIED NATURAL GAS PURCHASED FROM SPOT MARKET BY GSPCL.

NAPHTHA LIQUID FUEL PURCHASED FROM MAJOR OIL COMPANIES & GAIL

DAILY DC DECLARATION AT ANTA

DAILY DC DECLARATION STARTS WITH THE FOLLOWING ASSUMPTIONS:-

1. GAS ALLOCATION SHALL BE SAME AS YESTERDAY.2. AMBIENT TEMPERATURE SHALL BE SAME AS YESTERDAY.3. OTHER LOSSES SHALL BE SAME AS PREVIOUS DAY.4. GCV OF GAS SHALL BE SAME AS PREVIOUS DAY.

KNOWING THE GAS ALLOCATION AND AMBIENT TEMPERATURE, THE MAX EX-BUS CAPABILITY FOR THE NEXT DAY, BOTH ON GAS FUEL AND NAPHTHA FUEL SEPARATELY IS ESTIMATED FOR 96 TIME BLOCKS AND SENT TO RCC AT NCR-HQ FOR ONWARD TRANSMISSION TO RLDC AT 09:00 HRS.

FOR ANY CHANGE IN THE ASSUMED CONDITIONS, REVISIONS IN DC ARE SENT AS PER ABT.

BREAK EVEN FREQUENCY

BREAK EVEN FREQUENCY ON ANY FUEL IS THE FREQUENCY AT WHICH;VARIABLE CHARGE = UI CHARGE.

PRESENT BREAK EVEN FREQUENCY :NATURAL GAS :- HZNAPHTHA :- HZ

Economics of Power Generation

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