Southern Regional Power CommitteeCentral Electricity Authority

Plant Availability Factor of ISGS. Percentage of Allocated Capacity Share. Share of Beneficiaries in ISGS. Misdeclaration of Declared Capacity. Ratio of Fees of SRLDC to be Shared. Ratio in which Transmission Charges to be Shared. Energy Scheduled to the Beneficiaries from ISGS. Details of Scheduled Energy Wheeled to Other Region. Details of Short Term Open Access. Details of Short Term Open Access Through Power

Exchange. Details of Wheeling Charges. Availability Certification

Components of Tariff Thermal◦ Capacity Charge ( for recovery of AFC)◦ Energy Charge ( for recovery of primary fuel and limestone

cost) Hydro◦ Capacity Charge ( for recovery of AFC)◦ Energy Charge ( for recovery of AFC)

Transmission◦ Transmission Charge ( for recovery of AFC)

Annual Fixed Cost Component Return on Equity Interest on Loan Capital Depreciation Interest on working Capital O & M Expenses Cost of Secondary Fuel Special Allowance in lieu of R & M

PAF-: The Average of the Daily Declared Capacities for all the Days during that period expressed as a percentage of the Installed Capacity in MW reduced by the Normative Auxiliary Consumption.

PAFM/PAFY=10000* DC/(N*IC*(100-AUX) )% NAPAF ( Normative Annual Plant Availability Factor) for thermal around 85%

NAPAF ( Normative Annual Plant Availability Factor) for hydro around 85-90%

Transmission Charge for ISTS Transmission Charge ( inclusive of incentive) = AFC x (NDM/NDY) x ( TAFM/NATAF)

NATAF (Normative Annual Transmission System Availability Factor)

AC System 98%HVDC Bipole 92 %HVDC back to back Stations 95 %

Allocated Capacity Share – Gadgil Formula. Un Allocated Share (15%)

Weighted Average of Percentage Allocation Capacity Decides the Ratio in Which Fixed Capacity Charges

is to be share by Beneficiaries. It takes care of URS power also ( in line with CERC

Order dated 11/01/10 on petition No. 134/2009 of NTPC)

As per Regulation 6.4.18, 6.4.19 & 6.4.20 of IEGC , ISGS could be asked to demonstrate the DC .

Quantum of penalty 2 days fixed charges for first misdeclaration.

Penalty to increase in GP subsequently

Ratio in Which ULDC fees are shared is based on Weighted Average of Total Entitlement of a Beneficiaries with Different ISGS and LTOA

Postage Stamp Method- Based on Entitlement. Point of Connection Method- Based on Hybrid

Method ( from 1.7.2011)

Variable Charges of a Station Recovered through Scheduled Energy.

Concept of Un-Requisition Energy (URS Power). Concept of Unscheduled Interchange.

From Goa SR-Goa WR From ER-WR Via SR. Jeypore - Gajuwaka (ER) Bhadravati - Chandrapur (WR)

Short Term Open Access. Short Term Open Access through Power Exchange PXI & IEX.

ISGS Embedded in State Transmission network KGS & MAPS.

State Transmission network Connecting Different States.

Declared Capacity Requisition Schedule Drawl Losses Frequency Least count of 0.02 Hz Freq= 49+Code/50 UI De incentive UI Capped UI (4.03 Rs/kwh) Capping Under APM (4.03 Rs/kwh) Additional UI (49.5-49.2)(49.2-49)

Frequency Vector

0.00

100.00

200.00

300.00

400.00

500.00

600.00

700.00

800.00

900.00

1000.00

49.5

49.5

2-49.5

4

49.5

6-49.5

8

49.6

0-49.6

2

49.6

4-49.6

6

49.6

8-49.7

0

49.7

2-49.7

4

49.7

6-49.7

8

49.8

0-49.8

2

49.8

4-49.8

6

49.8

8-49.9

0

49.9

2-49.9

4

49.9

6-49.9

8

50.0

0-50.0

2

50.0

4-50.0

6

50.0

8-50.1

0

50.1

2-50.1

4

50.1

6-50.1

8>5

0.2

Frequency Range

Pai

se/k

wh

Normal

GS (APM)

Criteria for UI RatesFrequency Range Criteria

50 > =F < 50.2 Median value of energy charge of lignite/coal based station of NTPC and NLC

49.68 > =F < 49.70 Sufficient incentive to the generating station based on coal including imported coal to support the grid after meeting the fixed and variable charges

F < 49.5 Hz Highest of the average energy charges of Generating stations

UI Cap Rates Generating stations under APM UI Cap Rate 403 paise/kwh U/D Beneficiary and buyer - in excess of 10% of the schedule or 250 MW

whichever is less shall be 403 paise/kwh Injection by seller in excess of 120% of schedule ( subject to

105%/101% block/day limits of IC ) shall be 403 paise/kwh

Limits on UI Volume O/D by beneficiary/ buyer shall not exceed 12% of

scheduled drawal or 150 MW whichever is lower and 3 % on daily aggregate basis for all the time blocks when F < 49.7 Hz

Under Injection by GS/ seller shall not exceed 12% of scheduled drawal and 3 % on daily aggregate basis for all the time blocks when F < 49.7 Hz

Presently no rates are notified but can be notified by the Commission

UI 105%/101% Generating Stations (other than hydro) injection in

excess of 105% of DC in a time block or 101 % of average DC over a day shall not exceed UI charges corresponding to frequency ‘ below 50.2 Hz and not below 50.0 Hz’

Seller injection in excess of 105% of IC in a time block or 101 % of IC over a day shall not exceed UI charges corresponding to frequency ‘ below 50.2 Hz and not below 50.0 Hz’

Additional UI Frequency is less than 49.5 Hz and up to 49.2 Hz

Over Drawal = 40% of UI Rate 873 paise/kwh Under injection by seller = 20% of UI Rate 873

paise/kwh Under injection by GS = 20% of UI Rate 403 paise/kwh

Frequency is less than 49.2 Hz Over Drawal = 100% of UI Rate 873 paise/kwh Under injection by seller = 40% of UI Rate 873

paise/kwh Under injection by GS = 40% of UI Rate 403 paise/kwh

No Generators Involved. Penalty for injecting Reactive Energy at 103% of

Voltage Level and Incentive for Drawing . Penalty for drawing Reactive Energy at 97% of

Voltage level and Incentive for Injecting Reactive charges Ps 10.5/KVARH . Payment for Interstate Lines.

24

Reactive Power & Voltage Control (6.6) VAR Charges under Low Voltage

VAR Charges under High voltage

Beneficiary1

Voltage: < 97%

Pool Account

VAR charges

EHV grid

Beneficiary2

Q Q

Beneficiary1

Voltage: > 103%

Pool Account

VAR charges

EHV grid

Beneficiary2

Q Q

25

VAR charges between two beneficiaries on interconnecting line owned by them singly or jointly

Can agree mutually not to have any charges. Can mutually agree to adopt any payment rate / scheme.

Or can adopt rate specified by CERC. In case of disagreement, they have to adopt scheme

specified by CERC in Annexure -3 (given below)

Payment to be made if one is to pay and other is to receive and will be min(x1,x3)+min(x2,x4). IN SR it is min(x1+x2,x3+x4)

Payment will be between the two beneficiaries on one to one basis

State A State BX1

X2

X3

X4

V > 103%

V < 97 %

Congestion Account

If F > 50.0 Hz Congestion Charge for Under Drawal and for over injection

If F < 50.0 Hz Congestion Charge for Over Drawal and for under injection

Rate = Max UI –

UI rate at 50.0 HzRs . 5.45/Unit

Regional Transmission Account 50% based on PoC + 50% based on Uniform PoC Charges in Rs/MW/Month Injection and Withdrawal Charges Approved Withdrawal and Approved Injection LTA and MTOA STOA Charges in Rs/KWhr Generators with LTA – the charges to be borne by

beneficiaries

Regional Transmission Deviation Account

Charges in Rs/MW/Block Deviations upto 120% normal rate Beyond 120% Transmission rate at 125% Negative withdrawal/injection applicable

withdrawal and injection rates *1.25 Injection deviation (generators having LTA) upto

120% and RPC approved to be borne by LTA beneficiary

Mechanism of Renewable Regulatory Fund wef 01.01.2012Utilities involved for payment mechanism

Purchasing state, Host state, Wind Generators, RRF

Criteria's Contracted Price, UI rates of the purchasing state region, UI rates of the host state region, ( UI – Cap UI rate) for UD, Additional UI rate for OD, 30% deviations from schedule, 50% deviations from schedule, Intra State & Inter state

Utilities involved for implementation

NLDC, RLDC, SLDC & RPCCTU & STU for metering