CERC_2014-19 Tariff Regulations

8/10/2019 CERC_2014-19 Tariff Regulations

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2

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

2

CERC Tariff Regulation 2014-19

Corporate Commercial Department


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3

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


Corporate Commercial Department3


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4

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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5

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

CERC Tariff Regulation 2014-19 15

C C iff l i 20 9


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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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CERC T iff R l i 2014 19


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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



CERC T iff R l ti 2014 19


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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.



CERC Tariff Regulation 2014 19


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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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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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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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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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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

C C a egu at o 0 9


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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

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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



500 MW and above



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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

42Corporate Commercial Department

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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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P j t C t ti t



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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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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)


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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O ti P t


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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


79/80

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


80/80

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

Documents

CERC_2014-19 Tariff Regulations