COMMERCIAL KNOWLEDGE

FOR
NON-COMMERCIAL EXECUTIVES
Presented by:
Kazi Md Hanif
Dy. Chief Engineer (M)
MPC, CMC, O&E Cell
KTPS, DVC, Koderma
Date: 19.01.2023
 CERC TARIFF REGULATIONS 2019-24
Key Provisions:
O Component of Tariff O Stations Older than 25 years

O Return on Equity O Special Allowance / R&M

O Tariff Application, True-up

O Interest on loan

O Depreciation

O Interest on Working Capital

O O&M Expenses

O Station Heat Rate

O Auxiliary Power Consumption

O Target Availability

O Incentive

O Sharing of Operational Gains

O Additional Capitalization
FORMATION OF CERC TARIFF REGULATIONS 2019-24

In Nov, 2017, CERC sought Draft Tariff Final Regulations

actual perf. data from Regulations issued on issued on 7th March,
CGS, IPP & CTU latest by 14th Dec 2018. Last 2019
31.12.2017 to kick-start date for submission of
the process of Tariff comments: 28.01.2019.
Regulations 2019-24.

Process for Applicable from

Regulations starts 01.04.2019

CERC issued Approach Public Hearing

paper for Regulations on conducted on 1st Feb,
24th May 2018. 2019 at Scope
Comments submitted by Complex, Delhi.
31.07.2018.

CGS: Central Generating Station, IPP: Independent Power Producer, CTU: Central
Transmission Utility
 PROCESS OF TARIFF DETERMINATION
1 2 3

Tariff Regulations Petition by Generator Tariff Order

O Guided by the Tariff O Petition filed by O Prudence check by the
Policy issued by GOI. generator with copy to CERC.
O Contains Financial and beneficiaries. O Hearings conducted by
Operational norms. O Hoisting petition on CERC.
O Framed after website so that consumers O Tariff Orders issued by
Consultative process can peruse the tariff CERC.
through public hearing. petition and submit their
comments/ suggestions
O Tariff Regulations issued
/objections to Regulator.
by CERC.
 METHOD OF RECOVERY OF TARIFF FOR DVC
CERC Tariff Regulation

Tariff Orders issued Firm

Beneficiaries
by CERC consumers

Tariff recovered from Beneficiaries Further Tariff Orders issued by

based on T.O. SERCs

Provisional Tariff for Firm

Recovery of FC: Based on DC Consumers fixed based on
Recovery of ECR: Based on SG
projected DC, SG

Final adjustment done in True-up Recovery based on actual

petition generation + CD Charge

Final adjustment done in True-

up petition
 COMPONENT OF TARIFF [REG:15 &16, PG:39]
Tariff

Fixed Charge Energy charge

Components: Components:
1. Return on equity 1. Cost of coal
2. Interest on loan capital 2. Cost of oil
3. Depreciation 3. Cost of limestone for FGD
4. Interest on working capital
5. O&M Expenses
6. Additional: Security charges & o Determined based on normative
Water charges HR, APC & SOC
o Landed price and GCV of coal & oil
as actual
Annual fixed charge is determined by o Normative consumption of lime
CERC based on Tariff Petition stones
1
RETURN ON EQUITY [REG:30&31, PG:60-62]
O Maximum Equity: 30% of the total capital cost

O Base rate of ROE , i.e. Post-tax ROE:

 Thermal: 15.5 %
 Hydro & Pumped storage: 16.5 %
O Pre-tax ROE = Base rate / (1 – Effective tax rate)

O Ramp rate requirements for thermal (w.e.f. 01.04.2020):

 Reduction of ROE @ 0.25 % for not achieving ramp rate of 1.0 % per min.
 Additional ROE @ 0.25 % for every incremental ramp rate of 1.0 % per min
achieved over and above the ramp rate of 1% per minute subject to ceiling of
1.0 %.
O Mandatory requirement of RGMO /FGMO, Data telemetry, Communication system up
to LDC, Protection system:
 Reduction in rate of ROE by 1.0 % for the period of deficiency as decided by
CERC based on report by RLDC.
2
INTEREST ON LOAN CAPITAL [REG:32 PG:63]

O Normative Loan i.e. Debt: 70 % of total project cost.

O Equity i.e. Company Investment: 30 % of total project cost.
O If the equity actually invested is more than 30% of the capital cost, equity in
excess of 30 % shall be treated as normative loan.
O If equity actually invested is less than 30% of the capital cost, actual equity shall
be considered for determination of tariff.
O Interest on Loan: The rate of interest shall be the weighted average rate of
interest calculated on the basis of the actual loan portfolio.
3
DEPRECIATION [REG: 33, PG:64]
O Depreciation allowed up to 90 % of capital cost. Salvage value is 10 %.
O Salvage value for IT equipment and software is NIL and 100 % value of the assets
shall be considered depreciable.
O Land other than the land held under lease and the land for reservoir in case of
hydro generating station shall not be a depreciable asset
O From recovery of depreciation repayment of principal of loan is done and rest
amount is to build up fund for new installation.
O Any depreciation disallowed on account of lower availability shall not be allowed to
be recovered at a later stage.
O In case of de-capitalization of assets cumulative depreciation recovered in tariff
shall be adjusted by the decapitalized asset during its useful services.
O Special provision for DVC for depreciation rate as stipulated by C&AG in terms of
Section-40 of the DVC Act, 1948.
4
INTEREST WORKING CAPITAL [REG:34(1)(A), PG:67]

O Working Capital: Working Capital is required by Generator f o r day to day

expenses for successful running of the units towards maintaining fuel stock,
employee expenses, O&M expenses, capital spares etc.

O Interest on working capital: Interest on Working Capital is allowed as part

of AFC@ SBI MCLR+350 basis points.
4 a COMPONENTS OF W.C. FOR THERMAL STATION
[REG:34(1) (A), PG-67]
1. Cost of coal and limestone towards stock for 10 days for pit-head and 20 days for
non-pit-head stations for generation corresponding to normative annual DC % or
maximum coal stock storage capacity, whichever is lower.
2. Advance payment for 30 days towards cost of coal and limestone for generation
corresponding to the normative annual DC %.
3. Cost of fuel oil for 2 months for generation corresponding to normative annual DC
%.
4. Maintenance spares @ 20% of O&M expenses including water charges and security
expenses.
5. Receivables equivalent to 45 days of capacity charge and energy charge for sale of
electricity calculated on the normative DC %.
6. O&M expenses, including water charges and security expenses, for one month.

Rate of interest: @ SBI MCLR+350 basis points (as on 1st April of each FY).
4 b COMPONENTS OF W.C. FOR HYDEL INCL. PUMP STORAGE HYDRO
STN, T&D SYSTEM [REG:34(1)(C), PG:68]

1. Maintenance spares @15% of O&M expenses including security expenses.

2. Receivables equivalent to 45 days of annual fixed cost.
3. O&M expenses, including water charges and security expenses for one month.
5 O&M EXPENSES FOR THERMAL STATION [REG:35, PG:70]
O Normative O&M Expenses (Rs. Lakh/MW) for thermal units in FY 19-20:
200/210/250 300/330/350 500 MW 600 MW 800 MW Series
MW Series MW Series Series Series and above
32.96 27.74 22.51 20.26 18.23
O Annual escalation: Thermal - 3.5 %.
O Additional units after first 4 units declared COD on or after 01.04.2019: O&M
expenses admissible 90 % of above norms.
O O&M expenses of station having unit size of less than 200 MW not covered above
shall be determined on case to case basis.
O Water Charges, Security Expenses and Capital Spares for thermal generating stations
shall be allowed separately after prudence check. Generator has to submit
assessment of security requirement & estimated expenses.
O O&M Expenses for FGD shall be 2 % of the admitted capital expenditure (excluding
IDC and IEDC) as on its date of operation. Annual escalation: 3.5 %. Provided that
income generated from sale of gypsum or other by-products shall be reduced from
O&M Expenses.
5 a
NORMATIVE O&M EXPENSES FOR THERMAL UNITS [REG:35, PG:70]

Units FY 19-20 FY 20-21 FY 21-22 FY 22-23 FY 23-24

MTPS U#1-6
32.96 34.12 35.31 36.56 37.84
[4x210+2x250]
MTPS U#7&8
22.51 23.30 24.12 24.97 25.84
[2x500]

BTPS-A [1x500] 22.51 23.30 24.12 24.97 25.84

CTPS U#7&8
32.96 34.12 35.31 36.56 37.84
[2x250]
DSTPS U#7&8
22.51 23.30 24.12 24.97 25.84
[2x500]
KTPS U#7&8
22.51 23.30 24.12 24.97 25.84
[2x500]
RTPS U#7&8
20.26 20.97 21.71 22.47 23.26
[2x600]
5 b O&M EXPENSES FOR HYDEL STATIONS
[REG:35, PG:73-74]

O Normative O&M Expenses (Rs. Cr.) of DVC Hydel Stations for FY 19-20:

MHS PHS THS

28.9240 21.9137 9.0017

O Annual escalation: 4.77 %.

O The Security Expenses and Capital Spares for hydro generating stations shall be
allowed separately after prudence check.
O Provided further that the generating station shall submit the assessment of the
security requirement and estimated expenses.
5 d O&M EXPENSES FOR T&D SYSTEM [REG:35(3)(A),PG:75-76]
Normative O&M Expenses includes for following three items:
A. Norms for Sub-station Bays.
B. Norms for Transformers.
C. Norms for Lines.
Normative O&M Expenses of T&D system FY 2019-20 are as follows:
A. Norms for Sub-station Bays (Rs. Lakh per bay)
765 KV 45.01
400 KV 32.15
220 KV 22.51
132 kV and below 16.08
B. Norms for Transformers (Rs Lakh per MVA)
765 KV 0.491
400 KV 0.358
220 KV 0.245
132 kV and below 0.245

O For GIS bays O&M expenses allowed 0.70 times of the normative value.
O Annual escalation: 3.5 %.
5 e
O&M EXPENSES FOR T&D SYSTEM [REG: 35(3)(A), PG:75]
Normative O&M Expenses of T&D system FY 2019-20 are as follows:

C. Norms for Lines Rs. Lakh / Km

Single Circuit (Bundled with six or more sub-conductors) 0.881

Single Circuit (Bundled conductor with four sub-conductors) 0.755
Single Circuit (Twin & Triple Conductor) 0.503

Single Circuit (Single Conductor) 0.252

Double Circuit (Bundled with four or more sub-conductors) 1.322
Double Circuit (Twin & Triple Conductor) 0.881

Double Circuit (Single Conductor) 0.377

Multi Circuit (Bundled with four or more sub-conductor) 2.319
Multi Circuit (Twin & Triple Conductor) 1.544

Annual escalation: 3.5 %.

 COMPENSATION FOR ASH UTILIZATION
[NOTIFICATION OF MOEF & CC DATED- 25.01.2016 FOLLOWED BY GAZETTE NOTIFICATION OF GOI
DATED- 27.01.2016]

O The cost of ash transportation within a radius of 100 Km shall be borne by power
plant for the following:
(i) For road construction projects.
(ii) For manufacturing of ash based products.
(iii) For use as soil conditioner in agriculture activity.
The cost of ash transportation beyond the radius of 100 Km and up to 300 Km for the
above activities shall be shared equally by the user and power plant.
O The cost of ash transportation within a radius of 300 Km shall be borne by power
plant for the following:
(i) Road construction projects under Pradhan Mantri Gramin Sadak Yojna.
(ii) Asset creation programmes of the Govt involving construction of buildings,
road, dams and embankments.
 CALCULATION OF FIXED CHARGE
For KTPS Ph-II (2x800 MW)
Amount (Rs.
Sl. No. Component
Cr.)
1 Interest on Loan @ 8.0 % on Quarterly Outstanding 666
2 Depreciation @ 7.0 % 859
3 Return on Equity @ 15.5 % 571
4 Interest on Working Capital @ 9.0 % [Calculated W.C. = Rs. 945 Cr.] 85.0
O&M Charges for main plant @ Rs. 22.42 Lakh/MW w.r.t. FY 2025-
5 (a) 359
26
5 (b) O&M Charges for FGD @ 2.0 % of capital cost of FGD 14.0
6 Security charges as actual subject to prudence check 20
7 Water charges as actual subject to prudence check 15
Annual Fixed Charges (Rs. Cr.) 2589
Normative Fixed Charge (Rs/kwh) 2.33

Total Project cost = Rs.12276 Cr., Debt :Equity = 70 : 30

Capital cost for FGD = Rs.700 Cr.
 FIXED CHARGE ALLOWED FOR KTPS
i.r.o. FY 2018-19 as per Last Tariff Order issued by CERC on 28.02.2017

Sl. No. Component Amount (Rs.Cr.)

1 Interest on loan 275.0

2 Depreciation 391.2
3 Return on Equity 150.5
4 Interest on working capital 88.2
5 O&M Expenses 208.1
6 Share of Common office expenses 1.4
7 Contribution for Sinking fund * 61.4
Total 1175.7

* Contribution towards sinking fund created for redemption of bond

Capital cost = Rs. 5541.3 Cr., Debt : Equity = 82.48 :17.52

 NORMATIVE FIXED CHARGE I.R.O. FY 2018-19
Installed Capacity Max. Allowable Fixed Charge for Normative Fixed
Station
(MW) FY 2018-19 (Rs. Cr. /Year) Charge (P/Kwh)

MTPS U#1-3 630 362 86

MTPS U#4 210 119 84

MTPS U#5-6 500 474 141

MTPS U#7-8 1000 1019 145

CTPS U#7-8 500 531 158

DSTPS U#1-2 1000 1104 157

KTPS U#1-2 1000 1176 168

RTPS U#1-2 1200 1396 166
BTPS-A 500 772 220

DVC Th. 6540 6952 153

 ENERGY CHARGE [REG: 37-40, PG:79-80]
O Energy Charge Rate is recovered on the basis of Normative Heat Rate, APC &
SOC.
O Landed cost of both Primary & Secondary Fuel is recovered based on actual.
O GCV considered “as received basis” & 85 kcal/kg margin is allowed on account of
storage at generating station.
O Transit & Handling Loss: 0.2 % for Pit head & 0.8 % for non-pit head stations.
O The generating company shall provide to the beneficiaries the details in respect of
GCV and price of fuel i.e. domestic coal, imported coal, e-auction coal, liquid fuel etc.
as per the Form-15.
O Additional details of the weighted av. GCV, blending ratio of the imported coal with
domestic coal, proportion of e-auction coal along with the bills of the respective
month shall be provided and the same will also be displayed on website.
O Measurement of GCV as received:
At the unloading point through collection, preparation and testing by Third party
sampling to be appointed by the generating companies as per guidelines of Central
Govt.
 NORMATIVE PARAMETERS [REG:49-59,PG:102-110]
SG (%) (For
Stations DC (%)
Incentives)
* APC (%) SOC (ml/kwh) HR (kcal/Kwh)
MTPS U#1-4
85 85 9.80 0.5 2430
[4x210]
MTPS U#5-6
85 85 9.80 0.5 2430
[2x250]
MTPS U#7&8
85 85 5.75 0.5 2374.1
[2x500]
BTPS-A [1x500] 85 85 5.75 0.5 2374.1
CTPS U#7&8
85 85 9.80 0.5 2369.17
[2x250]
DSTPS U#7&8
85 85 5.75 0.5 2374.1
[2x500]
KTPS U#7&8
85 85 5.75 0.5 2374.1
[2x500]
RTPS U#7&8
85 85 5.75 0.5 2350.17
[2x600]
DVC Thermal
85 85 6.89 0.50 2381
(6540 MW)
* Additional 1.0 % APC allowed for FGD.
 NORMATIVE STATION HEAT RATE [REG: 49(C), PG:104-107]
COD before 01.04.2009 Gross Station Heat Rate

210 / 250 MW 2430 kcal/kwh

500 MW (sub-critical) 2390 kcal/kwh

COD on or after 01.04.2009 Gross Station Heat Rate

1. Margin over Design Heat Rate: 5 %

250 MW 2. Maximum Turbine Heat Rate: 1955 kcal/kwh
3. Minimum Boiler Efficiency: 86 %

1. Margin over Design Heat Rate: 5 %

2. Maximum Turbine Heat Rate: 1950 kcal/kwh
500 / 600 MW 3. Minimum Boiler Efficiency: 86 %
(sub-critical)
KTPS: Design Turbine HR =1944.5
Design Boiler Efficiency = 83.23
Normative HR = (1944.5 /0.86) x 1.05 = 2374.1
 NORMATIVE AUXILIARY POWER CONSUMPTION [REG:5, 49(E),
PG:4,110]

Unit / Station APC

200 / 210 / 250 MW (With NDCT) 8.5 %
300 /500 MW & above - With TDBFP & NDCT 5.75 %
- With MDBFP & NDCT 8.00 %
Additional APC:
O Tube type coal mill 0.8 %
O IDCT 0.5 %
O FGD 1.0 %

Note:
O APC will include Transformer losses and consumption in switch
yard.
O APC for Sewage Treatment Plant and External CHP (Jetty & associated
infrastructure) to be considered separately.
O APC shall not include colony consumption, construction power and
consumption by integrated coal mine.
 LANDED COST OF COAL [REG: 38, PG:79]
Components for Landed cost of coal:
O Base price of coal corresponding to the grade and quality of fuel.

O Statutory charges as applicable.

O Washery charges.

O Transportation cost by rail or road or any other means.

O Loading, unloading and handling charges.

O Expenses towards 3rd party sampling.

 COMPUTATION OF ENERGY CHARGE [REG: 43, PG:88-89]

Parameters for calculation of energy charge:

O Landed cost of coal (LPPF in Rs./kg)
O GCV of coal (*CVPF in kcal/kg )
O Landed cost of oil (LPSF in Rs./ml)
O GCV of oil (CVSF in kcal/ml)
O Normative HR (nSHR in kcal/kwh)
O Normative SOC (nSOC in ml/kwh)
O Normative APC (nAPC in %)
* CVPF = “Weighted Av. GCV of coal as received” less 85 kcal/kg on account of variation
during storage.

Formula:
ECR = {(nSHR – nSOC x CVSF)/CVPF x LPPF + (nSOC x LPSF)} / (1- nAPC/100)
 TARGET AVAILABILITY [REG.42, PG:82, 86-87]
Financial Year
High Demand Season Low Demand Season
(3 months) (9 months)

Peak Hours Off-peak Hours (20 Peak Hours Off-peak Hours (20
(4 Hours) Hours) (4 Hours) Hours)

 85 % DC needs to be achieved on  85 % DC needs to be achieved on

cumulative basis for 3 months both in cumulative basis for 9 months both in
peak hours and off-peak hours. peak hours and off-peak hours.
 Any under achievement in DC in off-  Any under achievement in DC in off-
peak hrs. can be off-set by over peak hrs. can be off-set by over
achievement in peak hours, but vice achievement in peak hours, but vice
versa is not allowed. versa is not allowed.

O Concerned RLDCs shall declare high / low demand months at least 6 months in
advance.
O Peak hours to be declared by concerned RLDC at least 1 week in advance.
 METHOD OF RECOVERY
Month-wise from Beneficiary:

Total fixed charge based on Energy charge per unit

DC (Rs. Cr.) based on SG (Rs./kwh)

Fixed charge per unit Total energy charge (Rs.

(Rs./kwh) – Calculated value Cr.) - Calculated value

Month-wise from Firm Consumer:

O Recovery based on actual power supplied to the consumer as per provisional

tariff fixed by State Electricity Regulatory Commission (SERC).
 INCENTIVE [REG:42(6), PG:88]

O Applicable on achieving Normative Annual Plant Loading Factor (NAPLF) of 85

% on a cumulative basis within each Season (High Demand / Low Demand)
(w.e.f. 01.04.2020)

O Differential incentive rate for peak / off-peak hours (w.e.f. 01.04.2020)

 Incentive @65 paisa/kwh during Peak hours

 Incentive @50 paisa/kwh during off-peak hours.

 PARTIAL LOAD COMPENSATION MECHANISM
[CERC SUB-REG-6.3B (IEGC 4TH AMENDMENT), DTD-06.04.2016 ]

O IEGC 4th Amendment was introduced by CERC on 06.04.2016.

O Under these Regulations, Following compensation for Heat rate & APC was
provided:

Unit loading as % Increase in Heat Increase in Heat

Increase in
Sl. No. of Installed Rate (%) for Rate (%) for sub-
APC (%)
capacity supercritical units critical units

01. 85-100 Nil Nil Nil

02. 75-84.99 1.25 2.25 0.35

03. 65-74.99 2 4 0.65

04. 55-64.99 3 6 1.00

Copyright © 2016 Your Company All Rights Reserved.

 PARTIAL LOAD COMPENSATION MECHANISM
Where the SG falls below the technical minimum schedule, the concerned CGS or
ISGS shall have the option to go for reserve shut down and in such cases, start-up fuel
cost over and above seven (7) start / stop in a year shall be considered as
additional compensation based on following norms or actual, whichever is lower:

Oil compensation per start-up (KL)

Unit size
Hot Warm Cold
200 /210 / 250 MW 20 30 50
500 MW 30 50 90
660 MW 40 60 110

Each start-up due to reserve shut down shall be attributed to the beneficiaries who had
requisitioned below 55 % of their entitlement.
 SHARING OF NET GAIN [REG: 60, PG:123]
O Sharing of Net Gain on account of operational parameters (Station HR, APC & SOC)
shall be on annual basis between Generator and Beneficiaries in 50:50 ratio.

O Net Gain = (ECRn - ECRa) x Scheduled Generation.

ECRn = Normative Energy Charge Rate computed on the basis of normative

operational parameters.

ECRa = Actual Energy Charge Rate computed on the basis of actual operational
parameters.
 SHARING OF NON-TARIFF INCOME [REG: 62, PG :125]

The following non-tariff net income shall be shared between the Generator and
Beneficiaries in 50:50 ratio:
O Income from rent of land.

O Income from rent of buildings.

O Income from sale of scrap.

O Income from advertisements.

 REBATE & LATE PAYMENT SURCHARGE
[REG: 58-59, PG:121-122]

Rebate:
O 1.5 % within a period of 5 days of presentation of bills (*).
O 1.0 % after 5 days within 30 days.

Note:
(*) In case 5th day is holiday, immediate succeeding working day will be considered.

Late Payment Surcharge :

O Applicable beyond a period of 45 days from date of submission of bills @1.5
% per month.
CLASSIFICATION OF ADDITIONAL CAPITALIZATION [REG:25-27 & 29; PG:52-59]
1. Add-cap within the original scope and upto cut-off date for existing project
or a new project - Reg:24

2. Add-cap within the original scope and after cut-off date for existing project
or a new project - Reg:25(1).

3. Add-cap within the original scope and after cut-off date for replacement of
assets in existing project - Reg:25(2).

4. Add-cap beyond the original scope - Reg:26

5. Add-cap on account of R&M - Reg:27

6. Add-cap on account of Revised Emission Standards – Installation of FGD &

De-NOx Burners - Reg:29

Note:
O Cut-off date: Last day of calendar month after 36 months from COD of project.

O ‘Existing Project’ means achieved COD prior to 01.04.2019.

O ‘New Project’ means a project achieved COD on or after 01.04.2019.

1 ADD-CAP UNDER THE ORIGINAL SCOPE & UPTO CUT-OFF DATE [REG:
24 (1); PG:52]

Additional capital in respect of existing project or new project is allowed subject to

prudence check:

O Undischarged liabilities recognized to be payable at a future date.

O Works deferred for execution.
O Procurement of initial capital spares within the original scope of work.
O Liabilities to meet award of arbitration or for compliance of the directions of
any statutory authority or order of Court.
O Change in law or compliance of any existing law.
O Force Majeure events.
2 ADD-CAP UNDER THE ORIGINAL SCOPE & AFTER CUT-OFF DATE [REG:
25 (1); PG:53]

Additional capital in respect of existing project or new project is allowed subject to

prudence check:

O Liabilities to meet award of arbitration or for compliance of the directions of

any statutory authority, or order of Court.

O Change in law or compliance of any existing law.

O Deferred works relating to ash pond or ash handling system in the original
scope of work.

O Liability for works executed prior to the cut-off date.

O Force Majeure events.

O Liability for works admitted by CERC after cut-off date to the extent of
discharge of such liabilities by actual payments.

O Raising of ash dyke as a part of ash disposal system.

3 ADD-CAP I.R.O. REPLACEMENT OF ASSETS
[REG: 25 (2); PG:53-54]

Replacement of assets or equipment under the original scope after cut-off date is
allowed:
O In case useful life of equipment is less than useful life of plant and is fully
depreciated.

O On account of change in law.

O On account of Force Majeure events.

O On account of obsolescence of technology.

O The same has otherwise been allowed by the Commission.

4 ADD-CAP BEYOND THE ORIGINAL SCOPE [REG: 26; PG:54-55]
Additional Capitalization beyond the original scope may be allowed subject to prudence
check:
O Liabilities to meet award of arbitration or for compliance of directions of any
statutory authority, or order of Court.
O Change in law or compliance of any existing law.
O Force Majeure events.
O Need for higher security and safety of the plant as advised by Gov. or
statutory authorities responsible for national security.
O Deferred works relating to ash pond or ash handling system in addition to the
original.
O Usage of water from sewage treatment plant.
5 ADD-CAP ON ACCOUNT OF R&M [REG:27&42(2), PG:55-57,85]
O Generating company may undertake R&M of any unit after its normal service
life.
O Generating company intending to undertake R&M shall file a petition before
CERC for approval of the proposal with a detailed project report (DPR).
O Generating company shall be required to obtain the consent of the
beneficiaries for R&M and submit the same along with the petition.
O Approval may be granted after due consideration of reasonableness of the
proposed cost estimates, financing plan, schedule of completion, use of
efficient technology, cost-benefit analysis, expected life extension etc.
O Generating company shall be allowed to recover ‘O&M expenses’ and ‘Interest
on loan’ for shutdown due to R&M.
O After completion of R&M, the generating company shall file a petition for
determination of tariff.
O Generating company making the applications for renovation and
modernization (R&M) shall not be eligible for Special Allowance under
Regulation-28.
 SOME SALIENT POINTS REGARDING ADD-CAP
[REG:10(8),10(9),11,30; PG:34-35, 60]

O If actual add-cap expenditure incurred in a year falls short of allowed add-cap

by more than 10 %, Generator shall refund excess tariff recovered along with
interest at 1.2 times Bank rate as on 1st April of respective year.
If actual add-cap expenditure incurred in a year exceeds the allowed add-cap
by more than 10 %, Generator shall recover the shortfall in tariff along with
interest at Bank rate as on 1st April of respective years.
So projection of add-cap needs to be done on realistic basis so that difference
between actual and projections is within 10 %.
O In-principle approval is required for incurring expenditure on account of
change in law or force majeure, if it exceeds 10 % of admitted capital cost of
project or Rs.100 Cr, whichever is lower.
O ROE i.r.o. add-cap after cut-off date beyond the original scope excluding add-
cap due to Change in Law, shall be average rate of interest on loan.
 SPECIAL ALLOWANCE (SA) FOR THERMAL UNIT [REG:28,
PG:57-58]

O Generating company may opt to avail special allowance instead of availing R&M
after its useful life (25 years).
O Special allowance @9.5 Lakh/MW without escalation for the tariff period 2019-
24.
O SA to be transferred to a separate fund for utilization towards R&M activities, for
which a detailed methodology shall be issued separately.
O Expenditure incurred from special allowance shall be maintained separately by
the generating station and details of same shall be made available to the
Commission as and when directed.
O Such option shall not be available for a unit for which R&M has been undertaken
or unit which is in a depleted condition or operating under relaxed norms.
O SA will not be added to capital cost, but it will be included in the annual fixed
cost.
O The applicable operational norms shall not be relaxed.
 TRUE-UP PETITION [REG: 13; PG:35-36]
O The Commission shall carry out truing up exercise for the period 2019-24 along
with the tariff petition filed for the next tariff period 2024-29. Final true-up
petition has to be filed by 30.11.2024.
O Interim true-up allowed in 2021-22, if AFC increases by more than 20% over the
AFC determined for respective years.
O After true-up, if tariff recovered exceeds or falls short of tariff approved, generator
shall refund or recover the excess or shortfall along with simple interest at bank
rate as on 1st April of respective years in six equal monthly instalments.
KNOW YOUR ORGANIZATION
FROM COMMERCIAL &
FINANCIAL POINT OF VIEW
 DVC INFRASTRUCTURE
O Thermal (6 Stations): 6540 MW
Generation O Hydel (3 Stations): 147.2 MW
capacity O Solar: 3.82 MW
O Joint Venture (2 Stations): 1388 MW

O Sub-Station (48 nos.):

220 KV - 11 Nos., 132 KV - 24 Nos., 33 kV - 1 Nos., 33
Transmission & kV Receiving station-12 nos.
Distribution O Transmission Lines (8613 Ckms):
400 kV- 478 Ckms, 220 kV- 2957 Ckms, 132 kV- 3639
Ckms, 33 kV-1527 Ckms, 11 KV- 12 Ckms.

O Major Dams: 4 Dams (Tilaiya, Konar, Maithon,

Panchet).
Water Resources O Total length of canal system : 2494 km
O Total No. of Municipal & Industrial water Consumers:
162 (68 in WB & 90 in Jh)

Coal Mine O Tubed Coal Mine; Capacity: 6 MTPA

 DVC BENEFICIARIES
Capacity Station-wise
Station Unit Beneficiary Quantity (MW)
(MW) Quantity (MW)
CTPS (7&8) 500 U#7&8 Delhi DISCOM 300 300
U#5 WB 50
MTPS (5&6) 500 150
U#6 Delhi DISCOM 100
U#7&8 Haryana 100
U#7&8 TSL 100
MTPS (7&8) 1000 U#7 Delhi DISCOM 111.12 611.12
U#7&8 Karnataka 200
U#7&8 Kerala 100
U#1&2 Punjab 200
DSTPS 1000 U#1&2 MP 100 400
U#1&2 TSL 100
U#1&2 Haryana 100
KTPS 1000 U#1&2 Karnataka 250 950
U#1&2 JBVNL 600
U#1&2 Haryana 100
U#1&2 Punjab 300
RTPS 1200 U#1&2 Kerala 50 616
U#1&2 Rail 150
U#1&2 IPCL 16
BTPS-A 500 U#1 Punjab 200 200
Total (MW) 3227.12
 PLANT-WISE COAL LINKAGE (MMT)
PROJECT BCCL CCL ECL MCL OVERALL
MTPS U#1-6 (1340 MW) 4.200 0.900 0.500 5.600
BTPS-A (500 MW) 1.975 1.975
BTPS-B (210 MW) 0.267 0.733 1.000
CTPS U#3 (130 MW) 0.170 0.331 0.501
CTPS U#7 (250 MW) 1.030 1.030
DTPS (210 MW) 0.124 0.216 0.278 0.618
DSTPS (1000 MW) 1.756 0.556 1.413 3.725
KTPS (1000 MW) 1.759 2.238 0.300 4.297
RTPS (1200 MW) 2.040 1.591 0.732 4.363
Total (5840 MW) 10.315 7.898 2.704 2.191 23.109

BRIDGE LINKAGE (MMT)

MTPS (U#7&8) - 1000 2.178 1.157 3.335
CTPS (U#8) - 250 0.233 0.674 0.907
Total (1250 MW) 2.411 1.831 4.242

Total Linkage
12.726 9.729 2.704 2.191 27.351
(7090 MW)
 POSSIBLE GENERATION WITH AVAILABLE COAL

Available coal Materia- Normative HR GCV SCC Possible

PLF (%)
(MMT) lization (Kcal/Kwh) (kcal/kg) (Kg/kwh) Gen (MU)

3965 0.60 45550 79.51

27.35 100% 2381 3780 0.63 43425 75.80

3720 0.64 42736 74.59

3965 0.60 40995 71.56

24.62 90% 2381 3780 0.63 39082 68.22

3720 0.64 38462 67.14

Applicable PI:
(i) PI @ 10 % of base price for materialization 90 % to 95 %.
(ii) PI @ 20 % of base price for materialization 95 % to 100 %
(iii) PI @ 40 % of base price for materialization more than 100 %.
 GRADE OF COAL
Equivalent Washery
Grade of Coal GCV (Kcal/Kg)
Grade
G1 Exceeding 7000
G2 Range: 6700-7000
G3 Range: 6400-6700
G4 Range: 6100-6400
G5 Range: 5800-6100 W-III
G6 Range: 5500-5800
G7 Range: 5200-5500 W-IV
G8 Range: 4900-5200
G9 Range: 4600-4900 W-V
G10 Range: 4300-4600
G11 Range: 4000-4300 W-VI
G12 Range: 3700-4000
G13 Range: 3400-3700
G14 Range: 3100-3400
G15 Range: 2800-3100
G16 Range: 2500-2800
G17 Range: 2200-2500

Note: DVC FSA with coal companies: Normally G7 to G14

 INSTALLED CAPACITY VIS-À-VIS CUSTOMERS

Thermal: 6540 MW
Installed
Hydel: 147.2 MW Total: 6691.2 MW
capacity
Solar: 4 MW

Beneficiaries (11 Nos.)

PPA: 3227 MW

Firm consumers (300 Nos.)

Customer Contract demand: 3506 MVA Total: 7089 MW
(Eq. at bus level: 3540 MW)

Bangladesh: 300 MW
(Eq. at bus level: 322 MW)
 TARIFF VIS-A-VIS GENERATION COST
Tariff Generation Cost
Fixed charge: Fixed cost:
(a) Return on equity (a) Interest on loan capital
(b) Interest on loan capital (b) Depreciation
(c) Depreciation (c) Interest on working capital
(d) Interest on working capital (d) Operation and maintenance expenses
(e) Operation and maintenance expenses: (e) Additional: Security charges& Water charges
(f) Additional: Security charges & Water charges. (f) Ash evacuation cost
(g) Interest on short term loan, if any, due to
insufficient cash flow.

Energy charge: Energy cost:

(a) Coal cost (limited w.r.t. normative HR) (a) Coal cost (as actual)
(b) Oil cost (limited w.r.t. normative SOC) (b) Oil cost (as actual)
(c) Cost of limestone or other reagent, as (c) Cost of limestone or other reagent, as
applicable applicable (as actual)
Tariff = Fixed charge + Energy charge Gen. cost = Fixed cost + Energy cost
 FUTURE OF DVC IN VIEW OF THERMAL EXPANSION
FY 2023-24:
Capacity: 6540 MW
FGD Commissioned
Project cost: Rs.36262 Cr.
Fixed charge: Rs.7824 Cr.
ROE: Rs.1517 Cr.

FY 2029-30:
Capacity: 10260 MW
Project cost: Rs. 66504 Cr.
Fixed charge: Rs. 13297 Cr.
ROE: Rs. 2924 Cr.
FY 2022-23:
Total profitability including
Capacity: 6540 MW Hydel, T&D & Water = Rs.3269
Project cost: Rs.31762 Cr. Cr.
Fixed charge: Rs.6952 Cr.
ROE: Rs.1308 Cr.
1