||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
||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.
||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
||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.
||Interest on Working Capital
||1. O&M Expenses for
2. Fuel Expenses for one months 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 banks cash credit rates for the balance short term Working
||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.
Elements of Fixed Cost
Analysis / Critical Comments
||Tax as expenses
||Total Companys taxable
||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.
||Additional capital cost due to
addition of assets, Renovation & Modernization, transfer of assets and foreign
||Applicable rates of
depreciation, ROE and Interest rate.
||This has necessitated
retrospective adjustement of fixed charges.
||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 FCA=TFC / S SEB
|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 individuals drawal, the less is ones 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
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
However perhaps the generation
maximising SEBs, 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
Base Deemed PLF / Availablity
Analysis / Critical Comments
||Plant Load Factor Thermal
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
operating Below Deemed PLF 5500 for all regions
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.
Norm of calculation for Quantity of Fuel / Energy
Comments & Critical Analysis
||Secondary Fuel Oil Consumption
||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
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.
||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
||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
||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.
||Period of stabilization
||1 Year from the adte of start
of commercial operation