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Tariff Determination of Generating Stations
Controlled by Central Govt.
As per Section 62 of the Electricity Act, 2003, tariff for supply of
electricity by a generating company to a distribution licensee to be
determined by Appropriate Commission
As per Section 79, Central Electricity Regulatory Commission
(CERC) has the jurisdiction to regulate tariff for the generating
companies owned & controlled by the Central Government
CERC from time to time notifies the Regulations for determination
of tariff which specify the principles and methodology for working
out the tariff of generating companies under its jurisdiction.
CERC has notified the Tariff Regulation applicable from 1.4.2014 to
31.3.2019
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Tariff Framework in Electricity Act 2003
Commission
Section 62
(Tariff Determination)
Section 63
(Tariff Adoption)
Bulk TariffGencos
to Discoms
Transmission Tariff
Retail Tariff
Competitive Bidding
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CERC issues Tariff
Regulations
Guided by the Tariff
Policy issued by GOI
Contains Financial
and Operationalnorms
Framed after
Consultative
process through
public hearing
Petition filed bygenerator. Copy to
beneficiaries
Hosting petitionon website
Hearings
conducted by
CERC and
Tariff ordersissued
I - TariffRegulations
II - Petition byGenerator
III - Tariff Order
Prudence check
conducted by the
CERC
Oral hearings
conducted where
the stakeholders
can participate
Process of Tariff Determination
Posts entire petition on the
website
Publishes notice in 2 newspapers
so that consumers can perusethe tariff application and submit
their comments/
suggestions/objections to
Regulator
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Timelines of 2014-19 Tariff Regulations
Applicable from
01.04.2014
CERC issued order
for data. NTPC
submitted data.
(July 2013)
Final Regulations
issued on 21st
February 2014
Public Hearing
conducted on 15th-
16thJanuary
NTPCs comments on
Draft Regulations
submitted- 29th
January 2014
Draft Regulations
issued- 6thDec
2013
Approach paperissued by CERC,
comments
submitted (Aug 13)
Process for
formulation of
Regulations starts
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Tariff of Thermal Stations
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Tariff Basics
Cost-Plus Tariff
Two-part tariff
Capacity Charge (for recovery of annual fixed cost
components)
Energy Charge (for recovery of primary and
secondary fuel costs)
Incentive allowed separately
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Capital cost for tariff
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Capital Cost
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Capital Cost of the Station (Rs. Lakhs) (Cash Basis)
As on
31.03.2014
Date of
Last Order
As approved by
CERC
As per Final
True up Petition
TTPS 15.05.2014 100159.35 102633.18
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Capital Cost
Capital cost for tariff base for an existingstation-
Capital cost admitted by the Commission prior to
1.4.2014 duly trued up by excluding liability;
Add-Cap and De-cap for the respective year of tariff;only for the category of works listed in the Regulation
on projection basis (described in Add-cap slide)
expenditure on account of renovation and
modernisation after end of useful life (if SpecialAllowance is not claimed)
Capex on PAT on case to case basis will be allowed
(sharing of benefits due to PAT)
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Capital Cost
Capital Cost for tariff base for a new station-
All the expenditure incurred or projected to be
incurred till COD
IDC/ IEDC
Capitalized initial spares
Additional capitalisation/ de-capitalisation
Adjustment of revenue due to sale of infirm power
prior to COD
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Prudence check of Capital Cost for new stations
Capital Cost prudence check w.r.t benchmark normsspecified/ to be specified by Commission from time to
time.
CERC has already issued an order on Benchmarking
of capital cost for different unit size and unit
configurations.
12
Unit Size in
MW
No of
units
Total Hard cost
(Rs. Cr/ MW)
Unit Size in MW No of units Total Hard cost
(Rs. Cr/ MW)
500
(Greenfield)
1 to 4 5.08 -4.34 660
(Greenfield)
1 to 4 5.37-4.37
500
(Extension)
1 to 2 4.92-4.53 660
(Extension)
1 to 2 4.95-4.67
600
(Greenfield)
1 to 4 4.87-4.01 800
(Greenfield)
1 to 4 4.96-4.44
600
(Extension)
1 to 2 4.47-4.19 800
(Extension)
1 to 2 4.63-4.44
BENCHMARKS NORMS AS ON DECEMBER 2011
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IDC/ IEDC- in case of delay in projects
Additional IDC due to delay beyond Scheduled COD will
be allowed only after prudence check.
Additional IDC & IEDC will be allowed only for delay due
to uncontrollable factors such as: Force Majeure
Change in Law
If the delay is attributable to agencies or contractors, no
IDC/ IEDC will be allowed for the delay period. When time-over run is not allowed by CERC, the cost
escalation in that period may be excluded from
capitalization
IDC- Interest Durin g Cons truc t ion , IEDC- Incidental Expens es Durin g Cons truc t ion
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Controllable/ Uncontrollable factors
Controllable Factors Variations in capital expenditure on account of time and/or
cost over-runs on account of land acquisition issues;
Efficiency in the implementation of the project not involving
approved change in scope of such project, change in statutory
levies or force majeure events; and
Delay in execution of the project on account of contractor,
supplier or agency of the generating company or transmission
licensee.
Uncontrollable Factors
Force Majeure events
Change in Law
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Additional Capitalisation
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Cut Off Date
Date by which all works within the original scope of workare required to be completed.
means 31st March of the year closing after twoyears of the year of commercial operation of theproject, and in case the project is declared under
commercial operation in the last quarter of a year,the cut-off date shall be 31st March of the yearclosing after three years of the year of commercialoperation.
COD of Station Cut off Date
1.4.2014 to 31.12.2014 31.3.2017
1.1.2015 to 31.12.2015 31.3.2018
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Add cap allowed upto cut-off date
new stations
Following Capex projected to be incurred after COD andup to the Cut-Off Date is allowed:
Deferred liabilities
Works deferred for execution
Procurement of initial capital spares within the originalscope of work
Liabilities to meet award of arbitration or forcompliance of the order or decree of a court
On account of change in law or compliance of an
existing law CERC has asked for the details of works asset wise/
work wise to be submitted along with tariff application
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Initial spares
Initial spares as a % of the plant and machinery costupto cut-off date are as follows:
Coal-based/lignite-fired thermal stations - 4.00%
Gas Turbine/Combined Cycle thermal stations - 4.00%
Hydro generating stations - 4.00%
Transmission system - 3.5%~6.00%
Earlier Initial Spares allowable amount was linked to the
total Capital cost 2.5% for Coal stations 4.0% for Gas stations
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Add cap allowed beyond cut-off date-
existing stations
Liabilities to meet award of arbitration or for compliance of the
order or decree of a court
On account of change in law or compliance of an existing law
Deferred works relating to ash pond or ash handling system in
the original scope of work for coal stations.
Expenses on account of higher safety and security of the plantas directed by appropriate government
Discharge of liability on admitted works
Capex necessitated on account of modification in fuel receiving
system on account of non- materialisation of the fuel linkage Gas Stations: Capex necessary for efficient operation,
deterioration of assets, obsolescence of technology, up-
gradation of capacity for technical reason such as increased
fault level.
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Projected/ Actual Capex
Capital cost is determined based on the projected cost. If the projected cost is more than the actual capital
cost on yearly basis by more than 5%, the excess
tariff will refunded along with interest rate of 1.20
times the bank rate If the projected cost is less than the actual capital cost
on yearly basis by more than 5%, the shortfall in tariff
will recovered along with interest rate of 0.8 times the
bank rate
Tariff Petitions have been filed based on the projected
Capex given by the projects/ stations.
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Truing up
Truing up exercise based on actual CAPEX upto31.03.2019 to be done in 2019-20
Interim True up to be done in 2016-17
Difference between tariff allowed and revised after
Truing-up to be adjusted with simple interest at thebank rate as on 1st April of respective year in six equal
monthly installements.
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Issues in Additional Capitalisation
Add-Cap is allowed based on the projections
Regulations allow add-cap only on limited grounds
(Regulation 14 (3)), other Capital expenses are
expected to be financed through Compensation
Allowance
The projections should be backed by proper
justifications (documents, letters, statutory requirements,
guidelines, directives etc.)
Projection should be based on capitalisation and notcash expenses
Implication in case of failure to meet the projected capex
Interest liability
Credibility22
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Issues in Additional Capitalisation
Add-Cap allowed/ disallowed in 2009-14 PeriodMajor Items
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Allowed Items
Item Regulation Item Regulation
Ash Handling Related
Works. (Rs. 3.85 Crs)
Environment System
and Change of Law(Rs. 6.13 Crs)
Reg 9(2)(iii)
Reg 9(2)(ii)
R&M Ph-II works
(Rs 9.42 Crs)
R&M Ph-III works
(Rs. 105.79 Crs)
R&M of Switchyard
(Rs 29.17 Crs )
Reg(10)
Reg(10)
Reg(10)
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Issues in Additional Capitalisation
Add-Cap allowed/ disallowed in 2009-14 PeriodMajor Items
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Disallowed Items
Items Remarks
R&M Ph-IV(Rs. 32.11 Crs)
Disallowed Rs. 19.11 Crs pertaining to StageI Unitsand Items executed under O&M
Capital spares
(Rs 27.95 Crs)
Capital spares allowed earlier
Crossing the limit of 2.5% allowable as per Regs.
MBOA items(Rs. 3.83 Crs)
No provision in Regulations.
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Capacity Charge
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Capacity Charge
Based on the Annual Fixed Cost (AFC) Servicing of Capital Cost
1.Return on Equity
2.Interest on Loan Capital
3.Depreciation
Other Fixed Expenses4.Interest on Working Capital
5.Operation and Maintenance Expenses
6.Compensation Allowance (for units 10 ~ 25 years old)
7.Special Allowance (for units more than 25 years old)
Cost of Secondary Fuel Oil has been removed from AFC and made apart of the Energy Charge
Compensatory Allowance for coal based stations upto 25 years of lifeor Special Allowance in lieu of R&M beyond 25 years will not beconsidered for Working Capital
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Typical AFC Break up (%)
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Old
stations
New
Stations
Gas
Stations
ROE 35~38% 28~ 30% 35~37%
Interest on Loan 5% 20% 3%
O&M Cost 40~ 45% 20~25% 27%
Interest on
Working Capital
10% 8% 23%
Depreciation 5% 20% 10~12%
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AFC Break up
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Rs. Lakhs
ROE 10409.64
Interest on Loan 543.14
O&M Cost 18818.60Interest on Working Capital 2594.44
Depreciation 4564.42
Compensation Allowance -
Special Allowance -
TOTAL 37937.03
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Return on Equity (ROE)
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Return on Equity (ROE)
Equity Base of a Project: New projects: Based on Debt: Equity ratio of 70:30 for
new projects
Existing Projects: as already allowed by CERC prior to
31.3.2014Actual Debt in excess of 70% would be allowed
Actual Equity in excess of 30% will be treated as
normative loan
Basic rate of Return on Equity (ROE) will be 15.5% during
2014-19 Tariff Period.
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Return on Equity (ROE)
ROE for new projects allowed is 15.5%
Additional 0.5% ROE would be allowed subject to
completion of CoD from investment approval/Zero Date
within the defined timeline of CERC.
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Hydro Projects as per TEC
200/210/250/300/330 MW 33 months at 4 mths interval
500/600 MW 44 months at 6 mths interval
660/800 MW 52 months at 6 mths intervalGas Stations >100MW 30 mth at 4 mths interval
Extension Projects 2 months less than above time
period
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Return on Equity- treatment of tax
ROE of 15.5% is Base Rate of Return Tax to be paid by the generator
Mechanism of recovery of tax to be paid is through
grossing up of the Base Rate of Return
Actual effective tax rate to be used for grossing uppurpose.
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Example:
If estimated effective Income Tax rate is 25%, then Pre-Tax Grossedup ROE would be 15.5%/(1-25%) = 20.67%
Grossed up ROE will be trued up at the end of each financial yearbased on actual income tax paid
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Other elements of AFC
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Normative loan as on 1.4.2014 after considering the cumulative
repayment upto 31.3.2014
Repayment equal to depreciation irrespective of actual repayment
To be charged from 1styear of CoD irrespective of moratorium @
Actual Wt. Avg. Rate of interest at the beginning of each year
If there is no actual loan available in any particular year, last
available weighted average rate of interest shall be considered
If there is no actual loan, then weighted average rate of interest of
the company shall be considered Generator to attempt re-financing - Net Benefit of refinancing to be
shared in the ratio of 1 (Gen):2 (beneficiaries) ; Refinancing cost is
to be borne by the beneficiaries
Interest on Loan
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Interest on Working Capital
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Coal Based Stations
o Coal stock for 15 days for pit head stations, 30 days for non-pit
head stations
o Cost of coal for 30 days generation
o
Secondary fuel oil for 2 monthso Maintenance spares @ 20% of O&M
o Receivables for 2 months (capacity charge and energy charge)
o O&M expenses for 1 month
Cost of fuel based on Price & GCV of preceding 3 months of the1stmonth for which tariff is decided andno fuel escalation allowed
Rate of interest will be bank rate as on 1.4.2014 or 1stof April of the
year in which the station is declared under commercial operation
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Interest on Working Capital
Gas Based Stations
o Fuel expenses for 30 days
o Liquid fuel stock for 15 days
o Maintenance spares @ 30% of O&M
o Receivables for 2 months
o O&M expenses for 1 month
For Fuel expenses, Liquid fuel stock and receivables, mode of
operation is to be considered
Cost of fuel based on Price & GCV of preceding 3 months of the
1stmonth for which tariff is decided andno fuel escalation allowed
Rate of interest will be bank rate as on 1.4.2014 or 1stof April of the
year in which the station is declared under commercial operation
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Depreciable value 90% (except land);
Depreciable life:
Thermal - 25 years
Gas 25 years
Hydro - 35 years
Weighted Average % for the 12 years after commercial operation
and balance shall be spread over balance life
For existing stations the balance depreciable value as on 1.4.2014
shall be worked out by deducting the cumulative depreciation as
admitted by the Commission upto 31.3.2014 from the gross
depreciable value of the assets.
Depreciation
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Norm for O&M expenses in 2014-15 is as follows:
Coal Based stations
o 200 MW - 23.90 Lac/MW
o 500 MW - 16.00 Lac/MW
o 660 MW - 14.40 Lac/MW
o TTPS - 43.16 Lac/MW
o Tanda - 35.88 Lac/MWo BTPS (unit 1to3)- 35.88 Lac/MW
Gas Based stations: Rs 14.67 Lac/MW
Advanced F class machines Rs 26.55 Lac/ MW
Escalation in the O&M expenses - @ 6.35% thereafter
Water Charges (based on water consumption subject to prudence
check) and Capital spares (actual with justification and should not be
funded through SA/ CA) - shall be allowed separately
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O&M Expenses .. contd.
Additional units which will be commissioned after1.4.2014 in the same station
200/210/250 MW
90% of above for Unit 5 & 6
85% of above for 7thonwards
300/330/350 MW
90% of above for Unit 4 & 5
85% of above for 6thonwards
500 MW and above
90% of above for Unit 3 & 4
85% of above for 5thonwards
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Compensatory Allowance
CERC has provided following Compensatory Allowancefor meeting expenses on new assets of capital nature
in lieu of any additional Capex beyond Cut Off Date
Yrs of
Operation
Comp. Allowance (in Rs. Lac/MW/yr) for
coal stations only0 10 Nil
11 - 15 0.20
16 20 0.50
21 - 25 1.0
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No other additional capitalisation, other than the heads
provided in Regulation 14 (Add Cap) shall be allowed.
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Renovation and Modernisation
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Renovation and Modernisation
R&M provision can be availed by a station/ unit on aftercompletion of useful life.
CERC would do the prudence check based on the
estimated cost, extension of life, detailed justification etc.
New capital cost will be based of expenditure incurred
after deducting the accumulated depreciation from
original capital cost (Net Fixed Asset).
For Gas stations, renovation is allowed after completion
of 25 years and due to obsolescence of spares
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Special Allowance
Alternatively, the generating company may opt to avail
SpecialAllowance(SA). In such a case:
There will be no revision of capital cost
No relaxation in operating norms
Will be allowed for units after completing 25 years from COD
Will not be allowed to stations for which expenditure on R&Mhas been allowed earlier
Amount of Special Allowance Rs 7.5 Lakh/ MW/ year in
2014-15; thereafter escalated at 6.35% every year (5.72%
for 2009-14 period) For stations availing SA, the amount for 2014-15 will be
determined by escalating the amount allowed in 2013-14 by
6.35% (~Rs 6.64 Lakh/MW/Year)
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Energy Charge
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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.
Total Energy Charge payable in a month:
Energy Charge Rate x Scheduled Energy (ex-bus)
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Energy Charges
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Energy charge rate (ECR) in Rs. per kWh for coal based stations
ECR = {(GHR-SFC xCVSF)xLPPF/ CVPF + SFC x LPSFi} x100/{(100AUX)}
GHR normative station heat rate
SFC normative Sp oil consumption
AUX normative auxiliary energy consumption
CVSF Calorific value of oilLPPF Weighted average landed cost of Coal
LPSFi Weighted average landed price of secondary fuel
CVPF Weighted average GCV of coal as received
Landed Cost of Coal
Price of coal corresponding to the grade and quality inclusive ofroyalty, taxes and duties applicable & transportation cost
Considering normative transit and handling losses :
Pit head / non-pit head stations : 0.2%/ 0.8%, imported coal- 0.2%
Coal received through railways system: 0.8%
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Computation of Energy Charge Rate - Coal
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Energy charge rate (ECR) in Rs. per kWh for gas or liquid fuel
based stations
ECR = GHR x LPPF x 100 / {CVPF x (100 AUX)}
GHR normative station heat rateAUX normative auxiliary energy consumption
CVPF Weighted average GCV of primary fuel as received
LPPF Weighted average landed cost of primary fuel
Energy charge rate for a gas/liquid fuel based station shall be adjusted
for open cycle operation based on certification of Member Secretary of
respective Regional Power Committee for the open cycle operation
during the month.
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Computation of Energy Charge Rate - Gas
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The generating company shall provide to the beneficiaries
details of parameters of GCV and price of fuel i.e.
domestic coal, impo rted coal, e-auct ion coal, lignite,
natural gas, RLNG, liquid fuel etc.
The details of blending ratio of the imported coal,proportion of e-auction coal and the weighted average
GCV of the fuels as received shall also be provided
separately, along with the bills of the respective month
Copies of the bills and the above shall also be displayed
on the website of the generating company on monthly
basis for a period of three months.
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Other provisions
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Prior permission from beneficiaries not a pre-condition for use of
alternative source of fuel unless agreed specifically in the PPA.
The weighted average price of use of alternative source of fuel shall
not exceed 30% of base energy charges.
Prior consultation with beneficiary shall be made not later than three
days in advance in case the :
the energy charge rate exceeds the lower of
30% of base energy charge rate as approved by the
Commission for that year
20% of energy charge rate for the previous month
The Commission shall approve the base energy charge rate at thestart of the tariff period. The same for subsequent years shall be
computed by escalating at the escalation rates for payment
purposes, notified by the Commission under competitive bidding
guidelines.
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Other provisions
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Operating Norms
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Operating Norms
Target Availability (NAPAF) for recovery of fixed
charges83% (earlier 85%)
The above provision shall be reviewed based on actual
feedback after 3 years from 01.04.2014.
Incentive will be based on PLF (earlier incentive waslinked to Availability)
Normative Annual Plant Load Factor for incentive
85%
Rate of incentive 50 paise/ kwhr beyond ScheduleGeneration of 85%
In 2009-14- incentive was @ FC/kWhr for old stations
(>10 yrs old) and @ 50% of FC/kWhr for new stations.
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Heat Rate norm for existing Coal Stations
2009-14 2014-19 Difference
200/210/250 MW Sets 2500 2450 -50
500 MW Sets 2425 2375 -50
BTPS 2825 2750 -75
TTPS 2950 2850 -100
Tanda 2825 2750 -75
HR values in Kcal/kWhr
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Heat Rate norm for existing Gas Stations
Station Combined Cycle Open Cycle
2009-14 2014-19 Difference 2009-14 2014-19 Difference
Anta 2075 2075 No Change 3010 3010 No Change
Auraiya 2100 2100 No Change 3045 3045 No Change
Dadri Gas 2075 2000 (-75) 3010 3010 No Change
Faridabad 2000 1975 (-25) 2900 2900 No Change
Kawas 2075 2050 (-25) 3010 3010 No Change
Gandhar 2040 2040 No Change 2960 2960 No Change
Kayamkulam 2000 2000 No Change 2900 2900 No Change
HR values in Kcal/kWhr
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Heat Rate - New Stations
Pressure Rating (Kg/cm2) 150 170 170 247
SHT/RHT (0C) 535/535 537/537 537/565 565/593
Type of BFP Electrical Turbine Turbine TurbineMax Turbine Cycle Heat rate
(kCal/kWh)
1955 1950 1935 1850
Min.Boiler Efficiency
Sub-Bituminous Indian Coal 0.86 0.86 0.86 0.86
Bituminous Imported Coal 0.89 0.89 0.89 0.89Max Design Unit Heat rate
(kCal/kWh)
Sub-Bituminous Indian Coal 2273 2267 2250 2151
Bituminous Imported Coal 2197 2191 2174 2078
New coal based stations after 1.4.2014 4.5% margin over design Heat Rate
New gas based stations after 1.4.2014 5% margin over design Heat Rate
New liquid fuel stations after 1.4.2014 7.1% margin over design Heat Rate
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Norms for Auxiliary Energy Consumption
2009-14 2014-19 Difference
200 MW Series 8.5% 8.5% No Change
500 MW Series SDBFP 6.0%
EDBFP 8.5%
SDBFP 5.25%
EDBFP 7.75%
- 0.75%
For IDCT Additional 0.5% Additional 0.5% No Change
Gas Stations 3.0%/ 1.0% 2.5%/ 1.0% -0.5% for
Combined cycle
TTPS 10.5% 10.5% No Change
Tanda 12.0% 12.0% No Change
BTPS 9.5% 8.5% -1.0%For Air Cooled Condenser system additional APC of 0.5%/1.0% has been
allowed for direct/ indirect cooling respectively
CERC has excluded Colony consumption from Auxiliary Energy Consumption)
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Truing up
Controllable Parameters: Station Heat rate
Secondary Fuel Oil Consumption
Auxiliary Energy Consumption
Refinancing of Loans
Uncontrollable Parameters
Force Majeure
Change in Law Primary Fuel Cost
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Truing up
The financial gains on account of controllableparameters shall be shared.
Sharing will be done in the ratio of 60:40 between
generating stations and beneficiaries. (sharing on
refinancing of loan will be done in 2:1 ratio)
Sharing on monthly basis with annual reconciliation
Net Gain= (ECRNECRA) x Scheduled Generation
ECRNNormative Energy Charge Rate
ECRAActual Energy Charge Rate
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Commercial Operation Declaration
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COD of Thermal Station
2009-14 : Successful full load demonstration earlier to COD after
notice to Beneficiaries.
2014-19:
Trial Run : 72 hours successful running on continuous basis
at MCR or IC
7 days prior notice to beneficiaries before trial operation
Self Certification: to the effect meeting technical standards of CEA
Regulations, 2010 and GRID Code
RGMO , Communication System- linked to RoE
Certificate signed by CMD/CEO/ MD after approval of Board of
Directors in the specified format
CEA Tech. Standards for Construction of Elect. Plants & Elect.
Lines Regulation-2010; Reg 3(8) , 5, 7(1), 7(2), 7(3),7(4) & 8
To be submitted to RPC/ RLDC before COD
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Truing up on
Operational Parameters
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Other provisions
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FERV
Generator to attempt to hedge FERV
Cost of hedging as pass-through on normative loan on
year on year basis
To the extent loans are not hedged, FERV allowed as
pass-through, as an expense on year-to year basis
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Rebate/ Late payment surcharge
Rebate of 2% will be allowed for payments made within
2 days of presentation of bills
1% Rebate is to be paid for payments made within 30
days of presentation of bills
Late payment surcharge for a period beyond 60 days will
be at the rate of 1.5% per month.
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Sharing of CDM benefits
In the 1
st
year after COD- 100% of the gross proceedson account of CDM to be retained by the project
developer
In the 2ndyear, the share of the beneficiaries shall be
10%
This shall be progressively increased by 10% every year
till it reaches 50%
Thereafter the proceeds shall be shared equally between
generator and beneficiaries.
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Issues for discussion
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Operational aspects
Target Availability for recovery of FC- 83%. Strategies for allocation of coal:
In case of multi stage stations need to be devised.
After meeting the 83% DC level, more coal may be diverted to
efficient units (less ECR)
Limit of 20% of ECR from the previous month / 30% of
base need to be maintained so that need for consent of
beneficiaries does not arise. PAT clause can be used for capitalization of Capex for
successful and efficient operation.
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Operational aspects
Reporting of as received GCV of coal Reporting of Heat Rate/ APC/ Specific Oil to be shared
in the ratio of 60:40
O&M Cost - Capital spares and water charges spent on
actual basis is to be allowed.
RGMO/ FGMO provisions to be kept in service as the
same would lead to loss of ROE.
Target Availability for recovery of FC- 83%.
Separate feeder for colony consumption from grid.
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Operational aspects
Additional capitalization provisions: proper documentation and
justifications for claiming any additional capitalization underallowed provisions.
Reasons for deviation from projected capitalization also needs to
be maintained.
Projected Capitalization has to be realistic. In the 2009-14 Tariff
period, actual Capitalization was substantially less than projected
and consequently NTPC had to refund tariff along with interest @
12~14% p.a.
Additional Capitalization to be shown in the year when
Capitalization would take place & the asset shall be ready foruse.
Expenditure incurred from Special Allowance and Compensation
Allowance needs to be maintained properly so that the same can
be furnished as and when asked by the Commission.
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Project Construction aspects
IDC/IEDC in case of delay would be allowed only for
uncontrollable factors
Proper documentation, record keeping required for
justification in case of delay in project completion
particularly for the reasons if delay is beyond control
of NTPC or its contractors.
Expenditure for the delayed period is unlikely to be
allowed in the Capital Cost (example: Farakka-III)
Transmission Charges are also to be borne by Gencos
for the delayed period
APC will exclude Construction Power, to be tied up with
local Discoms
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P j t C t ti t D t ti
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Project Construction aspects-Documentation
Help/Assistance given to Contractor/ sub-contractor to arrest
delay
Force -majeure event of contractor / sub-contractor
Financial crisis of vendor / contractor
In the cases of delays or anticipated delays, the related
documents/ communications particularly attributable to actionsof governmental agencies/ Railways
Reasons beyond reasonable control of NTPC and its contractorsmust be collected and maintained ;
excessive rain/ flood,
geological surprises etc.
The actions identified for collection and maintaining suchdocuments may also be followed up/ monitored in PRTs.
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Project Construction aspects
Preparation for COD
Readiness of all the major systems including Balance of Plants,
Coal arrangement etc to ensure Trial run for a continuous period
of 72 hours at maximum continuous rating or installed capacity.
Notice to beneficiaries at least 7 days before Trial run.
Compliance to CEA Regulations (check list to be a part of CODnote)
Commissioning of RGMO/ FGMO before COD (1% to be
deducted if not complied)
Proper record keeping of less schedule during trial run period.
Process should start at least 45 ~60 days prior to the target dateof COD.
Certification of CMD for COD requires Board Approval
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Project Construction aspects
Prudence check of Capital Cost w.r.t. Benchmark cost-
Proper justifications are required for any deviations from
specified benchmark norms.
Capitalization before Cut-off date of project-
Completion of all works in original scope before cut-off
date
Procurement of Initial Spares of allowable amount before
cut-off date
Proper documentation required to justify extension of Cut-
off date as beyond the control of generator.
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ECR T d (P/K h)
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ECR Trend (P/Kwh)
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StationSep
'13
Oct
'13
Nov
'13
Dec
'13
Jan
'14
Feb
'14
Mar
'14
Apr
'14
May
'14
Jun
'14
Jul
'14
Aug
'14
TTPS 109 104 102 101 112 109 112 111 109 115 124 128
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Operating Parameters
Description Norm 2009-10 2010-11 2011-122012-13 2013-14
Heat Rate
(kcal/kwh)2850 2859 2851 2842 2823 2810
APC
(%)10.50 10.47 10.56 10.64 10.50 10.52
SOC
(ml/kwh)
0.5 0.63 0.52 0.44 0.38 0.40
DC
(%)83 90.27 93.58 91.88 95.72 94.56
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Force Majeure
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j
79
Force Majeurefor the purpose of these regulations means the event or
circumstance or combination of events or circumstances including those
stated below which partly or fully prevents the generating company ortransmission licensee to complete the project within the time specified in the
Investment Approval, and only if such events or circumstances are not within
the control the generating company or transmission licensee and could not
have been avoided, had the generating company or transmission licensee
taken reasonable care or complied with prudent utility practices:
a) Act of God including lightning, drought, fire and explosion, earthquake,
volcanic eruption, landslide, flood, cyclone, typhoon, tornado, geological
surprises, or exceptionally adverse weather conditions which are in excess
of the statistical measures for the last hundred years; or(b) Any act of war, invasion, armed conflict or act of foreign enemy, blockade,
embargo, revolution, riot, insurrection, terrorist or military action; or
(c) Industry wide strikes and labour disturbances having a nationwide impact
in India;
Change In Law
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gChange In Lawmeans occurrence of any of the following events:
(a) enactment, bringing into effect or promulgation of any new Indian law; or
(b) adoption, amendment, modification, repeal or re-enactment of any existing
Indian law; or
(c) change in interpretation or application of any Indian law by a competent
court, Tribunal or Indian Governmental Instrumentality which is the final
authority under law for such interpretation or application; or
(d) change by any competent statutory authority in any condition or covenant
of any consent or clearances or approval or licence available or obtained for the
project; or
(e) coming into force or change in any bilateral or multilateral agreement/
treaty between the Government of India and any other Sovereign Government
having implication for the generating station or the transmission system