1.1.4.2.2 Simple Cycle Operation

The Gross Heat Rate of the Unit(s) in simple cycle mode of operation using Natural Gas/LNG as fuel at standard reference conditions as per the latest version of ISO-2314 shall be the relevant value as per following table:

Table : Gross Heat Rate for different loading of Unit(s)

Categorisation based on ISO based rating of Combustion Turbine (in Simple cycle mode with Natural Gas/LNG as fuel)

Gross Heat Rate in kCal/kWh at loading of
  100% 80% 60%
1. 50 MW and less 2800 2950 3175
2. More than 50 MW and less than 200 MW 2600 2750 2975
3. 200 MW and above 2400 2550 2775


Notes :

1. In case of Unit(s) using Naphtha/NGL as fuel, the above specified Gross Heat Rate figures shall be multiplied by a factor of 1.01.
2. In case of Unit(s) using conventional combustor (other than dry low NOx) and water injection for NOx control, Gross Heat Rate shall be increased as under :

Fuel Natural Gas/LNG Naphtha /NGL
NOx Emission Level 50 ppm 100 ppm
Max. heat rate degradation, In kCal/kWh, with Water injection 70 50

In case NOx emission levels stipulated in Environmental Clearance are different from the above values, the heat rate degradation applicable shall be changed in proportion of the ratio of above stated NOx levels to the NOx levels stipulated in Environmental Clearance.

If dry low NOx combustors are used in conjunction with water injection, corresponding adjustment in heat rate shall be mutually agreed based on manufacturer's guarantees.

3) For the purpose of determination of Gross Heat Rate for the Settlement Period, average loading of the Unit during the Settlement Period shall be taken as the loading of the Unit.

4) Gross Heat Rate for any loading between any two above specified adjacent loadings shall be interpolated on pro-rata basis.

1.1.4.3 Diesel Generating Station

The Gross Heat Rate of the Diesel Generating Unit at standard reference conditions as per the latest version of ISO - 3046 shall be (a) the following values or (b) guaranteed heat rate corresponding to MCR, whichever is less :

Type of D.G. Engine Gross Heat Rate in kCal/kWh

i. Medium speed 4 - stroke

2000

ii. Low speed 2 - stroke

1900

Note : The Gross heat rate indicated above shall remain applicable for various loading conditions of the station. Generally, the heat rate of DG unit does not vary significantly between 70% and 100%. In case, station load comes down to 70% or less, some D.G. unit(s) can be shut down maintaining higher loading of the working DG sets.

1.1.5 AUXILIARY ENERGY CONSUMPTION

1.1.5.1 Steam Power Station

The Auxiliary Energy Consumption of the Generating Stations at the Rated Capacity with electric motor driven Boiler Feed Pumps (BFPs) shall not exceed the following values :

Type of Steam Generator/Fuel

Auxiliary Energy consumption in percentage

  with once-through water cooling with closed cycle cooling using wet cooling tower
Conventional Steam Generator    
(i) Domestic run of mine coal/Lignite 8.5 9.0
(ii) Domestic beneficiated coal 8.0 8.5
(iii) Imported beneficiated coal/ Petroleum coke/ Vacuum residue 7.5 8.0
(iv) Corex gas 6.5 7.0

Note : The Auxiliary Energy Consumption of Generating Stations with Steam Turbine driven boiler feed pumps shall be reduced by 1.5 percent.

1.1.5.1.1 Post Combustion Desulphurisation System

The following values shall be added to auxiliary power consumption as specified at para 1.1.5.1 for Conventional Steam Generator with flue Gas Desulphurisation System :

Process Maximum Additional Auxiliary Energy Consumption (%)
Wet Limestone Process 1.5
Spray Dryer Process 1.0

2. In- Combustion Desulphurisation System :

The Auxiliary Energy Consumption of the Generating Station with Circulating Fluidised Bed Combustion Steam Generators at the Rated Capacity with electric motor driven Bioler Feed Pumps (BFPs) shall not exceed the following values.

  with once through water cooling with closed cycle cooling using wet cooling tower
a) High Sulphur coals
(Sulphur content greater than 1%)
10.5% 11.0%
b) Domestic coal washery rejects 10.5% 11.0%

c) Imported beneficiated coal/ Petroleum coke/ Vacuum residue

9.5% 10.0%

1.1.5.1.3 Part Load Operation

The Auxiliary Energy Consumption at part load operation of the Generating Station shall be calculated by multiplying the above specified figures by the following multiplying factors :

DPLF Multiplying Factor
100% 1.00
80% 1.08
60% 1.20
50% 1.30

Note : For sample calculation of coal and secondary oil consumption refer Annexure C.

1.1.5.2 CCCT Generating Station

1.1.5.2.1 Combined Cycle Operation

The Auxiliary Energy Consumption (in percentage) of CCCT Generating Station shall not exceed the following values :

Fuel Auxiliary Energy Consumption (%)
  With once-through water cooling system Using wet cooling tower system
i. Natural Gas/LNG    
a. Without water/steam injection 2.50 2.75
b. with water/steam injection 2.60 2.85
ii. Naphtha/NGL (with water/steam injection) 2.75 3.00

1.1.5.2.2 Simple Cycle Operation

The Auxiliary Energy Consumption (in percentage) of Unit(s) operating in simple cycle mode shall not exceed the following values :

Fuel Auxiliary Energy Consumption (%)
i. Natural Gas/LNG :  
a) without water injection 1.25
b) with water injection 1.35
ii. Naphtha/NGL (with water injection) 1.50

Notes :

1. In case of dual fuel operation, the AEC shall be determined in proportion to the heat input of the fuels used

2. For sample calculation of Fuel consumption for CCCT plant refer Annexure C

1.1.5.3 Diesel Generating Station

The Auxiliary Energy Consumption of Generating Stations shall not exceed the following values:

Type of D.G. Engine

Auxiliary Energy consumption in percentage

  with radiator cooling using wet cooling tower
a) Medium speed 4-stroke 4.5 4.0
b) Low speed 2- stroke 3.5 3.0

1.1.6 SPECIFIC SECONDARY FUEL OIL CONSUMPTION

1.1.6.1 Steam Power Station

The Specific Secondary Fuel Oil Consumption for the purpose of start up-shut down and flame stabilisation shall not exceed the following values:

Type of Fuel Specific Secondary Fuel Oil Consumption in ml/gross kWh
a) All type of coals, Petroleum coke and Vacuum residue 1.0
b) Lignite 3.0

Note : While calculating the consumption of primary fuel, the heat credit for the secondary fuel consumption at the above specified rate shall be given.

1.1.7 SPECIFIC REAGENT CONSUMPTION

1.1.7.1 In-combustion Desulphurisation System

Specific Reagent Consumption, for Steam Generator Turbine Generating station with Circulating Fluidised Bed Combustion (CFBC) type Steam-Generator shall be a) guaranteed Specific Reagent Consumption or b) the value determined by the following formula, whichever is less :

Fuel Reagent Specific Reagent Consumption
kg/kg of fuel consumption
High Sulphur
Coal/Lignite
Limestone 6.25
----- X S
  P
Petcoke/Vacuum Residue Limestone 7.8
----- X S
  P

Where, S is percentage sulphur content in primary fuel

P is percentage purity of reagent

1.1.7.2 Post-combustion Desulphurisation System

Specific Reagent Consumption for Steam Power Stations with Flue Gas Desulphurization Sytem shall be a) guaranteed Specific Reagent Consumption or b) the value determined by the following formula, whichever is less:

Process Reagent Sulphur Dioxide Removal
Efficiency
Specific Reagent Consumption
kg/kg of fuel consumption
Wet Limestone Process Limestone 90% and more 3.28
----- x S
  P
Spray Dryer Absorber
Process
Lime 70% & more but less than 80%

2.19
----- x S
  P

    80% & more but less than 90% 2.45
----- x S
  P
    90% and more

2.8
----- x S
  P

Where, S is percentage sulphur content in the fuel.

P is percentage purity of reagent.

1.1.8 LUBRICATING OIL CONSUMPTION

1.1.8.1 Diesel Generating Station

Lubricating Oil Consumption shall not exceed the following values :

Type of D.G. Engine Lubricating Oil (incl. cylinder oil) Consumption in g/kWh (gross)
a) Medium speed 4-stroke 1.0
b) Low speed 2-stroke 1.2

1.1.9 'Commercial Operation Date' or 'COD'

1.1.9.1 Seam Power Station

Commercial Operation Date' or 'COD' - In relation to a Unit, date by which the Maximum Continuos Rating (MCR) or acceptable Installed Capacity is demonstrated by a Performance Acceptance Test as per international codes, after successful trial operation including stabilisation. The COD of the Generating Station shall be reckoned from the COD of the last unit.

Explanation:

For energy generated upto COD of the Unit, fuel charges shall be payable to the Generating Companies as per actuals.

1.1.9.2 Combined Cycle Combustion Turbine (CCCT) Generating Station

‘Commercial Operation Date' or 'COD' - In relation to a Unit or Block, date on which Maximum Continuos Rating (MCR) or acceptable Installed Capacity is demonstrated by Performance Acceptance Test as per latest versions of ISO -2314/ASME PTC-22 for Combustion Turbine and ASME PTC-6 for Steam Turbine after successful trial operation including stabilisation. The COD of the Generating Station shall be reckoned from the COD of the last Block.

Explanation:

1. Till COD of a Unit, fuel charges shall be payable to Generating company as per actuals. On declaration of COD of the Unit, fuel charges shall be determined as per operation norms for simple cycle operation.

2. As and when the steam turbine generator is synchronised with the grid, the fuel charges for the Block shall be payable to the Generating company as per actuals till COD of the Block. After COD of the Block, the fuel charges shall be determined as per operation norms for combined cycle operation.

3. Till COD of the Generating Station, the fixed charges shall be payable corresponding to the capital cost of unit(s)/ Block(s) in Commercial Operation.

1.1.9.3 Diesel Engine Generating Station

‘Commercial Operation Date' or 'COD' - In relation to a Unit, date on which the Maximum Continuous Rating (MCR) or acceptable Installed Capacity is demonstrated by a Performance Acceptance Test as per latest versions of ISO -3046 for Diesel Engine and IS : 4722, IS : 5422 & IS : 7132 and IEC-34 for Generator after successful trial operation including stablisation. The COD of the Generating Station shall be reckoned from the COD of the last Unit.

Explanation: For energy generated upto COD of the Unit, fuel charges shall be payable to the Generating Company as per actuals.

1.2 FINANCIAL PARAMETERS

1.2.1 Capital Expenditure

The capital expenditure of the project shall be financed as per the approved financial package set out in the techno-economic clearance of the Authority. The project cost shall include capitalised initial spares. The approved project cost shall be the cost which has been specified in the techno-economic clearance of the Authority.

The actual capital expenditure incurred on completion of the project shall be the criterion for the fixation of tariff. Where the actual expenditure exceeds the approved project cost the excesses as approved by the Authority shall be deemed to be included in the approved project cost for the purpose of determining the tariff:

Provided that such excess expenditure is not attributable to the Generating Company or its suppliers or contractors.

Provided further that where a Power Purchase Agreement entered between the Generating Company and the Board provides ceiling on capital expenditure, the capital expenditure shall not exceed such ceiling.

Provided also that in case of multi-unit project, the percentage of capital cost as specified by the Authority in its techno-economic clearance shall be considered for fixation of tariff, on commercial operation of the progressive units but in case of delay in commissioning of the second or subsequent units from the scheduled date, the project cost, for the period of delay, shall be retrospectively considered for the tariff purpose in the ratio of proportionate allocation of units.

Provided further that if the capital cost of the project increases, in comparison to the cost approved in the techno-economic clearance, on account of foreign exchange variation or change of law or any other reason not attributable to the Generating Company or its suppliers or contractors and approved by the Competent Government, the project developer may approach the Authority with the recommendation of the Competent Government, not more than once in a financial year, for the mid-term review of the Capital Cost.

Provided further that the Authority may, for special reasons to be specified by the project developer, allow the mid term review of Capital Cost more than once in a financial year.

1.2.2 Fixed Charges

The annual fixed charges shall be computed on the following basis:

1.2.2.1 Interest on loan capital shall be computed on the outstanding loans, including the schedule of repayment, as per the financial package approved by the Authority.

Note: (1) In case a generating company takes land on lease, the leasing charges as determined by the Central Government or the State Government or any statutory body, as the case may be considered as a pass through item in the tariff in lieu of interest liability of the notional cost of the land.

(2) Extra rupee liability towards interest payment and loan repayment actually incurred, in the relevant year shall be admissible, provided it directly arises out of foreign exchange rate variation and is not attributable to Generating Company or its suppliers or contractors.

1.2.2.2 The rates of depreciation shall be applicable as notified by Central government, from time to time.

1.2.2.3 Operation and Maintenance (O&M) Expenses :

1.2.2.3.1 Steam Power Stations

The annual Operation and Maintenance (O&M) expenses after the commercial Operation Date of the last Unit shall be determined as per the following formula :

C (O&M)n = 0.025 x CC (0.7 WPn/WP1 + 0.3 CPn/CP1)

Where,

C (O&M)n is the annual Operation & Maintenance expenses in crores of Rupees for the nth year of operation

CC is the actual capital expenditure in crores of Rupees as provided in clause 1.2.1

WPn is the wholesale price index during the nth year, and

CPn is the consumer price index during the nth year.

Note (1) Upto the Commercial Operation Date of the last Unit, the O&M Expenses for Units(s) in commercial operation shall be allowed in proportion to the allocation of the capital cost to the respective Unit as set out in the techno-economic clearance of the CEA or clearance of the competent authority approved by the State Government or the Power Purchase Agreement, as the case may be.

(2) No escalation in O&M Expenses shall be allowed upto one year from the COD of the last Unit of the Generating Station.

1.2.2.3.2 Combined Cycle Combustion Turbine (CCCT) Station

The annual Operation and Maintenance (O&M) expenses after the Commercial Operation Date (COD) of the last Block shall be determined as per the following formula:

C (O&M)n = 0.025*CC* (0.7 WPn/WP1 + 0.3 CPn/CP1)

Where, C(O&M)n is the annual Operation & Maintenance expenses in crores of Rupees for the nth year,

CC is the actual capital expenditure crores of Rupees as provided in Clause 1.2.1

WPn is the wholesale price index during the nth year, and

CPn is the consumer price index during the nth year.

Note : (1) Upto the Commercial Operation Date of the last Block, the O&M Expenses for Units/Blocks in commercial operation shall be allowed in proportion to the allocation of the capital cost to the respective Units/Blocks as set out in the techno-economic clearance of the CEA or clearance of the competent authority approved by the State Government.

(2) No escalation in O&M Expenses shall be allowed upto one year form the COD of the Generating Station.

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