Table 1 : Elements of fixed charges

Sl. No.

Item Rate Base Rate % Analysis / Critical Comments


Interest on Debt Notional 50% of cumulative gross capital cost less actual repayment of long term loans identified for the station i.e. notional outstanding loan Weighted Average Interest Rate of the loans of the stations. Actual book value of outstanding loan is different from the notional outstanding loan. Company had the freedom of optimizing debt equity structure.


Return on Equity Notional 50% of cumulative gross capital cost. Once loans are fully paid equity to be reduced to the extent of further depreciation As per Govt. Notification

10% (Up to 21.10.91)
12% (w.e.f. 21.10.91)
16% (w.e.f. 1.11.98)

Once the loan repayment is over the tariff will be high due to high cost of equity. The purpose of reduction of notional equity is apparently to reflect the reduced capiatl employed.


Depreciation Cost of different Category Of Assets in the Capitalised Project Cost. Rate of depreciation for each class of assets as notified by the Govt. Rate of depreciation has been revised from average 3.6% spread equally in straight line for economic life of the project to 5.4% in 1990 and 7.5% in 1992 reflecting lower notional economic life for thermal projects. The purpose of high depreciation is understood to provide for higher loan repayment obligation of IPP projects. Provision of advance against depreciation was also provided subsequently in hydro projects for similar purpose.


Operation & Maint. Expenses Current Capital Cost defined as the capital cost approved by the Authority in the year of fixation of tariff for a similar project. 2.5 % of the Projects Cost with escalation of 10%each year for the remaiming tariff period. Escalation formula and rate of 2.5% was to be reviewed after 5 years based on actual expenses. This was not done.
5 Interest on Working Capital 1. O&M Expenses for one month;
2. Fuel Expenses for one month’s generation;
3. Stock of fuel for reasonable period, actual or normative whichever is less; norms are :

a. Coal for 15 days for pit head projects, 1month for others
b. Secondary Fuel Oil 2 months

4. Cost of inventory of spares covering one years’ actual needs with adjustment of initial spares;
5. Receivables from SEBs for 2 months;

At average interest rates of debt and rate of return on equity as applicable for working capital margin capitalised in the project cost. At bank’s cash credit rates for the balance short term Working Capital While providing 2 months receivables as a part of working capital, a rebate of 2.5 % of the bill amount against LC payment and 1 % rebate for payment within 30 days were provided.


Sl. No

Elements of Fixed Cost

Rate Base

Rate %

Analysis / Critical Comments

6 Tax as expenses Total Company’s taxable profit. Tax Rate as prescribed in IT Act. Total Tax pro rated for each station on the basis of capacity. Tax allocation on pro rated installed capacity basis may not be prudent as a new plants may have no taxable profits in the initial years of operation. The tax allocation is important as the beneficiaries of every station are not same and tariffs from new plants are expected to be higher than tariffs from old plants.
7 Adjustments Additional capital cost due to addition of assets, Renovation & Modernization, transfer of assets and foreign exchange variation. Applicable rates of depreciation, ROE and Interest rate. This has necessitated retrospective adjustement of fixed charges.
8 Recovery of Fixed Charges Total fixed charges are computed as sum of the above components and are the total due of NTPC if generation level including deemed generation is 5500 Hrs to 6000Hrs. Allocation to each SEB to be done initially on the basis of pro rata energy drawal. Suitable penalty in vcase of overdrawal and need for observance of discipline and restraint with regards to drawals and mutual agreements at REB levels were also envisaged. Share of Total Fixed Cost TFCA = TFC x SEBA S SEB
Per Unit Fixed Cost
For NTPC it is a two part tariff where it recovered the entire fixed chrages TFC in RS Crs / Year at normative deemed PLF. However for a SEBS (? SEB ) and lesser the individual’s drawal, the less is one’s share of fixed cost.

*** please see below.


Fixed Charge allocation of Two – part tariff system based on actual energy drawals was perhaps appropriate for perpetual scarcity situations where it was not possible to make available the allotted MW capacity to the beneficiary. There is also no merit order problem during scarcity as all plants are dispatched. But this FC allocation formula did not help grid operation during surplus situation.

During off peak periods, it was expected that a profit maximizing SEB would back down its high variable cost stations and buy from NTPC thereby reducing per unit cost of NTPC power, as total drawal (S SEB ) will be higher. The savings in variable cost from backing down by SEBs would have neutralized any higher sgare of fixed cost due to NTPC. This would have been also in the interest of the overall national economy.

However perhaps the generation maximising SEB’s, preferred to reduce their drawal (SEBA) with their own peak surplus capacities, over – generated to offset their earlier purchases and to reduce their net share. ( Few States having less generating facilities and dependent on NTPC almost always ended up paying larger share of fixed charges.)

In the absence of a compulsory merit order scheduling and dispatch for all plants in the entire region, self-dispatch of the plants was resorted to. KPRC recommendation regarding vesting REBs with statuary powers for backing down of plants on merit order basis and non – fulfillment of such directives leading to financial and other penalties was not implemented. This lead to grid indiscipline and in efficiences especially in regions with surplus capacities.

Other recommendations pf KPRC such as TOD pricing which could have improved grid disciline and economic efficiency has also not been implemented.

Table 2 : Rationalized Payment of incentives / disincentives for achieving a higher level of deemed PLF ( Availablity )


Base Deemed PLF / Availablity


Analysis / Critical Comments

Incentives Plant Load Factor Thermal – (Coal) Hrs/KW/Year

Eastern region – 5500 Hrs

Other regions – 6000 Hrs

1 Paise/ Kwh on all energy generated beyond 68.49% Per 1% increase in Deemed PLF above 68.49% Although 1 Paise / kwh appeared a lower value, considering the deemed generation benefits and application of incentive for all generation above 68.5% gave a higher incentive rate at higher deemed PLFs.
Penalty / Disincentives Disincentive for operating Below Deemed PLF – 5500 for all regions

4500 for eastern region.

Prorata reduction from full fixed charges at 6... Hrs to 50 % of full fixed charges at 0 Hrs. However no fixed cost reduction up to 5500 Hrs. The disincentive machanism may not arise in practice as PLF for coal based CGS was more than the normative level.

Table 3 : Norms and Elements of Variable Charges

Sl. No.

Normative Parameters

Norm of calculation for Quantity of Fuel / Energy

Price Multiplier

Comments & Critical Analysis

1 Secondary Fuel Oil Consumption ( SFO) A normative SFO specified as 3.5 ml/Kwh after stabilized period 5 ml/Kwh during stabilization. For eastern region higher SFO consumption was allowed due to specific grid condition. Average actual price of the SFO in the month These normative parameters specified in KPRC report was an average figure and any plant operating closer to its Maximum Continous Rating was able to reduce its actual costs arising out of these parameters. In the absence of mandatory scheduling and dispatch instructions, generating companies resorted to overgeneration to maximize their profits.

Station Heat Rate, an important efficiency parameter for thermal power station, is a function of coal quality, plant loading condition, age etc.. This parameter was expected to be revised after 5 years tariff period but was not done.

2 Station Heat Rate determines Primary Fuel Consumption (Coal / Gas) Cost For coal stations :

SHR norms are
2600 Kcal/Kwh during stabilization

2500 Kcal/Kwh after stabilization

Actual average price of coal
3 Auxiliary Consumption (AC)
Notional Generation = Metered Energy Sent Out / (1-AC) %
The norm varies from 7.5% to 13% depending on the size of the units, cooling tower and boiler feed pump configuration and specific grid capability of eastern region Total Variable Cost (TVC) = Notional Generation x VC This norm has not been revised to reflect the actual condition so that there is true reflection of efficiency in generation tariff
4 Date of commercial operation Not exceeding six months from the date of synchronization   The normative time periods allowed for central generating companies have been changed for new projects being set up by generating companies.
5 Period of stabilization 1 Year from the adte of start of commercial operation  

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