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Regional Energy Accounting, Disputes Mechanism and

Resolutions

-R M Rangarajan & Asit Singh.-Executive Engineer,-SRPC, Bangalore

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WHAT IS Regional Energy Account (REA) ?

• “ REA is Statement of Allocation, Availability,Energy Scheduled/ injected and drawn which forms the basis for payment/ receipt among the constituents”

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Requirement of REA

• To be FAIR and EQUITABLE• To RECOVER DUES at the EARLIEST • TRANSPERANCY• Dispute Resolution• Reconciliation

RPCs have been entrusted with the responsibility of preparing REA

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Scope of REA

Regional Energy Account

ISGS Other Regions

BeneficiariesTraders

CTU

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Commercial Settlements

• Fixed/Capacity Charges• Variable/Energy Charges• Wheeling Charges• Ratio(s) in which above to be shared by

the beneficiaries.• Any other charges as been specified by

the competent authority from time to time like UI,Incentive, Transmission Charges etc.

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Fixed Cost Elements

• Interest on Loan• Return on Equity ( Presently 14% From 01.04.2009 -15.5%

and additional 0.5% if projects are completed within time frame)• Depreciation• O&M (cost of maintaining fuel, spares,

receivables, personnel etc.)

O & M for Thermal

Year 200/210/250 MW

300/330/350 MW

500 MW 600 MW and above

2009-10 18.20 16.00 13.00 11.70

2010-11 19.24 16.92 13.74 12.37

2011-12 20.34 17.88 14.53 13.08

2012-13 21.51 18.91 15.36 13.82

2013-14 22.74 19.99 16.24 14.62

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Rs. In lakh/MW

Hydro Normalised O& M for 2003-04 to 2007-08 escalated at 5.17 %

O & M for Transmission System

SS 2009-10 2010-11 2011-12 2012-12 2013-14

765 kV 73.36 77.56 81.99 86.68 91.64

400 kV 52.40 55.40 58.57 61.92 65.46

220 kV 36.68 38.78 41.00 43.34 45.82

132 kV & < 26.20 27.70 29.28 30.96 32.73

HVDC Stations

HVDC B2B Rs. Lakh/ 500 MW

443.00 468.00 495.00 523.00 553.00

Rihand-Dardri (Rs. Lakh)

1450.00 1533.00 1621.00 1713.00 1811.011

Talcher-Kolar (Rs. Lakh)

1699.00 1796.00 1899.00 2008.00 2122.00

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Rs. In lakh/bay

O & M for Transmission System

TL 2009-10 2010-11 2011-12 2012-12 2013-14

AC and HVDC lines

S/C ( Bundled conductor)

0.537 .568 .600 .635 .671

S/C( Twin or Triple conductor)

0.358 0.378 0.400 0.423 0.447

S/C( Single conductor)

0.179 0.189 0.200 0.212 0.224

D/C (Bundled Conductor

0.940 0.994 1.051 1.111 1.174

D/C ( Twin & Triple Conductor)

0.627 0.663 0.701 0.741 0.783

D/C ( Single) 0.269 0.284 0.301 0.318 0.336

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Rs. In lakh/km

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Fixed Cost Elements

• Cost of secondary fuel( for coal-based and lignite fired

generating stations only – From 01.04.2009)• Insurance, Taxes, etc. ( Not there from 01.04.2009)

• Special allowance in lieu of R&M or separate compensation allowance

(Independent of Energy produced)

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Variable Cost Elements

• Primary Fuel Cost (Coal)

(depends on Energy produced)

• Secondary Fuel (oil) ( In FC from 01.04.2009)

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PRE-REQUISITES

• Notify Two part tariff

• Signing of BPSA/PPA/BPTA

• Payment security mechanism (BG,LC, ESCROW etc.)

• Suitable Metering

• Scheduling mechanism

• Tele-metering/SCADA

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Pre ABT REA

• Fixed and variable charges merged to make single rate in paisa/KWhr

• Charges to be paid by beneficiaries on the basis of energy drawal

• No weightage to Entitlement/schedule of various beneficiaries in a particular generator (Typically in SR)

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PRE ABT TARIFF MECHANISM - ProblemsAll inter-utility exchanges based on single flat paise/kWHThis rate neither change with time of the day i.e; peak/off-peak or system conditions(generation surplus or deficit)Do not discourage MW overdrawals by SEBs.They could avoid this by proper load management, run their own higher cost generator DGs,GTs durng contingenciesDo not induce power plant operator to back down generation during off-peak hoursNo financial compensation to any party for over stressing its power plants for assisting during contingenciesSEBs view this composite figure only and compare with their own generating stations for their dispatch decisionsISGS(pit head plant)with lower incremental costs used to back down before backing down their own costlier load center generatorsThis leads to perpetual operational and commercial disputes in the operation of region grid

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Availability Based TariffAvailability Based Tariff

• With a view to promote overall economic operation of the power sector and to achieve improvement in operational parameter GOI felt that the existing tariff structure in power sector needs to be rationalized. Accordingly GOI proposed, for sale of electricity by generating companies to the beneficiaries, a three part tariff structure in viz. Capacity charge, Energy charge, Unscheduled interchanges (UI)

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AVAILABILITY BASED TARIFF(ABT)(a) CAPACITY CHARGE(b) ENERGY CHARGE(c) ADJUSTMENT FOR DEVIATIONS

(UI CHARGE)

(a) = a function of Ex-bus MW availability of power plant for the day declared before the day starts x SEB’s % share

.(b) = MWh for the day as per ex=bus drawl schedule for the SEB

finalized before the day starts x Energy charge rate

(c) =Σ(Actual energy interchange in a 15 min time block – scheduled energy interchange for the time block) x UI rate for the time block.

TOTAL PAYMENT = (a) + (b)± ( c)

Advantages of ABT• Improved frequency and voltage ?• Economic despatch ?• Autonomy to the utility ?• Incentive for high plant availability,but no incentive to

over generation during off-peak hours• Technically and commercially right ?• Immediate solution for IPPs and Captives ??• True free market ; market forces decide the pool price ?• Pool price known on-line ?• Total transparency ; No regulator required ?• Simple practicable ; Meters already developed and

installed

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Flow chart of Accounting Procedure

Data from RLDC(on every Thursday for the

previous week)

Preparation of Energy Accounts by RPCs

Weekly UI and VARAccounts

(issued on every Tuesday)

Monthly REA(Issued during

1st week of month)

GOI/CERC orders/notifications

Board Decisions

Preparation of Generation ScheduleAnd drawal Schedule

Disputes Mechanism and Resolution

Hydro Generating Station Inter State Transmission

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Preparing final schedule

12 1 2 3 4 5 6 7 8 9 10 11 12 1 2 3 4 5 6 7 8 9 10 11 12 1noon

ISGS

SLDC

Despatch schedule

net Drawal

schedule

revision

revisionstation-wise MW/MWH capability

station-wise W/MWH entitlement

required Drawal

schedule

AM PM

RLDC

Despatch schedule starts

Drawalschedule starts

finalDespatch schedule

final Drawal

schedule

BACKBACK

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Data Required for Preparing these accounts – to be furnished by RLDC

• Declared Capability (DC) and Dispatch/generation Schedule (GS) – Annexure 1A

• Entitlement of various beneficiaries – Annexure 1B• Requisition by various beneficiaries – Annexure 1C• Any bilateral Trading under STOAC – Bilateral Files• Wheeling to/from other regions – • Processed Meter (SEM) data – 15 min block wise

actual injection/drawal at various locations and reactive drawal/injection for a day –

SEM FilesBACKBACK

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Weekly Account Contains

• Unscheduled Interchange (UI) charges

• Reactive energy charges

BACKBACK

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Monthly REA Contains

(a) Availability % for Capacity Charge recovery(b) Energy Scheduled for Energy Charges(c) Energy scheduled beyond target PLF for Incentive(d) Ratio for sharing of monthly Transmission Charge

s of CTU(e) Ratio for sharing of monthly RLDC fees and O&M

charges(f) Wheeling Charges for ISGS Power wheeled on sta

te owned inter state lines.(g) Energy Exchanged with other Regions(h) Energy scheduled under STOA

BACKBACK

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Unscheduled Interchange (UI) charges

• For Generators

- UI = Actual Generation – Generation Schedule

• For Beneficiaries

- UI = Actual Drawal – Ex-Periphery drawal Schedule

• For Other Regions

- UI = Actual Metered energy – Net Schedule at Interregional Periphery

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For the day: 0000 hrs. to 2400 hrs. Central Generating Stations

1 2 3

Ex-Bus Declared Capability x1 x2 x3(Forecast) ____ ____ ___

SEB-A’s share a1 a2 a3SEB-B’s share b1 b2 b3SEB-C’s share c1 c2 c3

For a particular 15 minute time block

SEB-A’s requisition a’1 a’2 a’3SEB-B’s requisition b’1 b’2 b’3SEB-C’s requisition c’1 c’2 c’3

___ ___ ___CGS’s schedule x1’ x2’ x3’

MW

Sample UI Calculation

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Issues involved in UI Accounting• If During the day of operation any constituent feels that

its schedule needs to be changed due to load crash/ tripping of generators etc. it can do so but revised schedule will be effective from 6th time block.

• UI is to be suspended during grid disturbance / transmission bottle neck

• No UI for non commercial units and other stations not covered under ABT (Typically Nuclear stations)

• Any generation up to 105% of the declared capacity in any time block and averaging up to 101% of the average DC over a day is allowed. If generation goes beyond this limit, RLDC will investigate and if gaming is found UI charges due to such extra generation shall be reduced to zero and the amount shall be adjusted in UI account of beneficiaries in ratio of their capacity share in that generating station

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Special Note for Gas Turbine Generating Station

• For the Gas turbine generating station or a combined cycle generating station if the average frequency for any time block, is 49.02<f<49.52Hz and Schedule generation is more than 98.5% of the declared capacity, the scheduled energy shall be deemed to have been reduced to 98.5% of the DC, and if average frequency for any time block, is below 49.02Hz and Scheduled generation is more than 96.5% of DC, the scheduled generation shall be deemed to have been reduced to 96.5% of the DC

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For the day: 0000 hrs. to 2400 hrs. Central Generating Stations

1 2 3

Ex-Bus Declared Capability x1 x2 x3(Forecast) ____ ____ ___

SEB-A’s share a1 a2 a3SEB-B’s share b1 b2 b3SEB-C’s share c1 c2 c3

For a particular 15 minute time block

SEB-A’s requisition a’1 a’2’ a’3SEB-B’s requisition b’1 b’2’ b’3SEB-C’s requisition c’1 c’2’ c’3

___ ___ ___CGS’s schedule x1’ x2’’ x3’

MW

Revised Schedules

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Actual (metered) injection of CGS-1 in the time block = X1 MWh.

Excess injection = (X1 – x1’ ) MWh.

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Amount payable to CGS-1 for this =(X1-x1’) X UI rate for the block.

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SEB-A’s scheduled drawl for time block = a’1+a’2’+a’3 = a’ MW (ex-ISGS Bus)

SEB-A’s NET drawal schedule = (a’ – Notional Transm. Loss) MW

= (a’ – Notional Transm. Loss) = A’ MWH

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Actual (metered) net drawal of SEB-A during time block = A MWH

Excess drawal by SEB-A = (A-A’) MWh.

Amount payable by SEB-A for this = (A-A’) * UI rate for the block.

All above payments for deviations from schedules to be routed through a pool A/C operated by RLDC

SAMPLE UI ACCOUNT STATEMENT

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Variations in actual generation/drawal and scheduled generation /drawal are accounted through UI. This is a frequency linked charge which is worked out for each 15 minute time block.

Charges for all UI transaction, based on average frequency have following rate of paise per KWh from

Unscheduled Interchanges (UI)

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UI rate in effect UI rate (Paise per KWh)

Average Frequency of time block50.5 Hz. and above 0At 49.82 Hz 280Between 50.5 Hz and 49.80 Hz 8 P/ 0.02 HzAt 49.80 Hz 298Between 49.80 Hz and 49.00 Hz 18 P/ 0.02 HzAt 49.00 Hz and less then 1000

ISG Stations capped at 406 P

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1000 18 P/Unit/0.02Hz280

049 49.8 50.5

8 P

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Energy transactions of UI from/to Pool

Over Gen. By ISGS-1

Under drawl by SEB-A

UI import/Export from IR-1

Under gen. By ISGS-2

No one to one correspondence

System frequency UI

RateRegional Pool

Over drawl by SEB-BUI Import/Export to IR-2

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Operation of Pool

Separate Pool a/cs operated by RLDCs on behalf of RPCs for UI, IRE and Reactive charges

Regional Pool

Payable by ISGS-2

Payable by SEB-BPayable/Receivable by IR-2

Receivable by ISGS-1Receivable by SEB-A Payable/ Receivable

by IR-1No one to one correspondence

No cross adjustments allowed between the constituents

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IRE Account

• UI Calculated for Inter Regional Exchange are calculated at different frequency rate so net payable will not be same as net receivable by other region.the difference will go to IRE Account Normally the flow of power will be from higher frequency to lower frequency so there will mostly be surplus in IRE account . This will be shared by the two region on 50:50 basis and will be adjusted towards transmission charges.

BACKBACK

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REACTIVE ENERGY CHARGE :

PAYABLE FOR :

1. VAR DRAWALS AT VOLTAGES BELOW 97%2. VAR INJECTION AT VOLTAGES ABOVE 103%

RECEIVABLE FOR:

1. VAR INJECTION AT VOLTAGES BELOW 97%2. VAR DRAWAL AT VOLTAGES ABOVE 103%

APPLIED FOR VAR EXCHANGES BETWEEN :

A) BENEFICIARY SYSTEM AND ISTS- THROUGH A POOL ACCOUNT

B) TWO BENEFICIARY SYSTEMS ON INTER-STATE TIES- BY THEMSELVES

Basic Rate : 5 paise/kvArh ( for the year 2006-09 ) 0.25 Paisa ESCALATION PER YEAR

SAMPLE VAR ACCOUNT STATEMENT

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Issues in Reactive Energy charges

• Deficit in pool (SR & ER)-due to continuous High voltages in SR

• Surplus in Pool (NR &WR)

Utilization of Accruals

Disputes in payments between Beneficiaries for Reactive charges in Inter-state Lines

BACKBACK

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Capacity charge

• Capacity charge is based on Annual Fixed Charge and will be related to Availability of generating station. Availability means the readiness of the generating station to deliver ex-bus output expressed as a percentage of its rated ex-bus output capability.

• Target Avb. For Fixed charges recovery ( Notified by CERC Around 85 % from 01.04.2009 )

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Calculation Of Availability

% Availability =i=1

N

DCi/ {NxICx(100-Auxn) }%10000

Where DCi = Average Declared Capacity for i th day of the period in MW N = Total no. of days during the period Auxn = Normative Auxiliary Consumption as % of gross Gen.

IC= installed capacity in MW

% Availability forms the basis for calculations

Capacity Charges for Thermal

• Inclusive of Incentive

• GS < 10 years of COD

= AFC x ( NDM/NDY) x ( 0.5 +0.5 x (PAFM/NAPAF) (in Rupees)

• GS > 10 years of COD

= AFC x ( NDM/NDY) x (PAFM/NAPAF) (in Rupees)AFC = Annual FC

NAPAF= Normative Annual Plant Availability Factor

NDM= Number of days in a month

NDY= Number of days in a year

PAFM= PAF achieved for the month

PAFY= PAF acheived for the year

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Monthly Capacity charges receivable by an ISGS: (Not there from 01.04.2009)1 st Month = (1xACC1)/122 nd Month = (2xACC2-1ACC1)/12….….12 th month = (12xACC12-11ACC11)/12where ACC1,ACC2…….ACC12 = Annual capacity charges corresponding to the cum. Availability up to the corresponding month.

Monthly Capacity charges payable by a beneficiary :1 st Month = (1xACC1xWB1)/122 nd Month = (2xACC2xWB2-1ACC1xWB1)/12….….12 th month = (12xACC12xWB12-11xACC11xWB11)/12where WB1,WB2…..WB12 = Weighted average % share up to the corresponding month.

BACKBACKExtract from SR REA

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Energy charge:Energy charge is related to the scheduled ex-bus energy to be sent out from the generating station and will be worked out on the basis of paise per KWh.

The Energy Charges Payable by beneficiary to the ISGS = Variable Charge of ISGS X

Ex – Power Plant Schedule

The Energy Charges Receivable by ISGS from beneficiaries = Variable Charge of ISGS X

Despatch schedule of ISGS

BACKBACKExtract from SR REA

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• From 01.04.2009 Incentive recovered in Fixed charges

• Flat rate of 25ps/u

• For ex-bus Schedule Energy in Excess of ex-bus energy corresponding to Target PLF

Incentive for ISGS

PLF = 10000

i=1

N

SGi/ {NxICx(100-Auxn) }%

BACKBACK

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Ratio for sharing of monthly Transmission Charges of CTU

• Monthly Weighted average entitlement % from all ISGS in the region and other regions

BACKBACK

Extract from REA

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Ratio for sharing of monthly RLDC fees and O&M charges

• Monthly Weighted average entitlement % from all ISGS in the region

BACKBACK

Extract from REA

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Wheeling Charges for ISGS Power wheeled on state owned inter state lines.

BACKBACK

Extract from REA

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Energy Exchanged with other Regions• As furnished by RLDC

BACKBACK

Extract from REA

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HYDRO POWER GENERATING STATIONS

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CAPACITY INDEX

Daily Capacity Index = Declared Capacity(MW)

Maximum Available Capacity(MW)

Monthly Capacity Index

= (Average of Daily Capacity Index)

Capacity Charges from 01.04.2009 for Hydro

• Capacity Charges ( inclusive of incentive) = AFC x 0.5 x NDM/ NDY x (PAFM/NAPAF) 9 (in Rupees)

AFC = Annual Fixed Cost specified for the year

NDM – No of days in the month

NDY - No of days in the year

PAFM – Plant A F achieved during the month

NAPAF – Normative PAF

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• PAFM=10000 *

• AUX – Normative Aux. Cons.

• DCi - Declared Capacity for the ith day of the month (atleast 3 hours) certified by nodal LDC

• IC - Installed Capacity in MW

• N - No of days in a month

PAFM for HYDRO

i=1

N

DCi/ {NxICx(100-Aux) }%

BACKBACK

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NORMATIVE CAPACITY INDEX FOR RECOVERY OF FULL CAPACITY

CHARGES• During 1st Year of Commercial Operation

Run-of-river 85%

Storage Type 80%

• After 1st Year of Commercial Operation

Run-of-river 90%

Storage Type 85%

From 01.04.2009 Norms are revised

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COMPUTATION OF ANNUAL CHARGES

• TWO PART TARIFF– Annual Capacity Charge based on

Capacity Index

– Primary Energy Charge based on Scheduled Energy

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PRIMARY ENERGY RATE

• Minimum Variable charge of Central Sector thermal power station

• If Primary Energy Charge > Annual Fixed Charges, then

Primary Energy Rate

= Annual Fixed Charges

Saleable Primary EnergySecondary Energy Rate=Primary Energy Rate

Energy Charges for Hydro from 01.04.2009

• EC=(Engy chg rate (ECR) in Rs/KWH *Sch. Engy)*(100-FEHS)/100

ECR = AFC*0.5*10/(DE*(100-AUX)*(100-FEHS)

DE - Annual Design Energy in MU

FEHS – Free Energy for Home State

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INCENTIVE

= 0.65 x Annual Fixed Charges (CIA-CIN)/100

CIA = Capacity Index Achieved

CIN = Normative Capacity Index

From 01.04.2009 incentive included in the Capacity Charges

BACKBACK

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INTER STATE TRANSMISSION

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TARGET AVAILABILTY• Target Availability for recovery of full

transmission charges

AC system 98%

DC system 95%

(HVDC Bi-pole links and HVDC back- back stations)

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TARGET AVAILABILTY From 01.04.2009

• Normative Annual Transmission System Availability Factor (NATAF)

AC system 98%

HVDC Bi Pole 92%

HVDC B2B 95%

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SHARING OF CHARGES FOR INTRAREGIONAL ASSETS

n

= Tci -TRSC x CL

i=1 12 SCLTCi = Annual Transmission charge for ith project

TRSC=Total recovery from Open Access

CL=Allotted transmission capacity to a customer

SCL=Sum of all the allotted transmission capacities

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SHARING OF CHARGES FOR INERREGIONAL ASSETS

= 0.5x TCj -RSCj x CL

12 SCLTCj = Annual Transmission charge for jth

interregional assetRSCj=Total recovery from Open Access CL=Allotted transmission capacity to a customerSCL=Sum of all the allotted transmission

capacities

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INCENTIVE

= Equity x (Annual Availability-Target Availability)/100

BACKBACK

Monthly Transmission Charges from 01.04.2009

• =AFC*(NDM/NDY)*(TAFM/NATAF)

• AFC – Annual F C specified for the year

• NATAF – Normative Annual Tr. AF in %

• NDM – No of days in the month

• NDY - No of days in the year

• TAFM – Tr. Sys Avblty Factor achieved for the month

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Sharing of Tr. Charges from 01.04.2009

• By all regional beneficiaries in proportion to their entitlement

• By the beneficiaries of other region in proportion to their entitlement

• Generating Companies if ATS not developed

• Medium term users

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Sharing of Inter Regional Link Charges from 01.04.2009

• ER – NR by NR beneficiaries

• ER-WR by WR beneficiearies

• ER-SR by SR beneficiaries

• NR-WR and WR-SR 50:50

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New Regulations from 01.04.2009

• ATS not to be pooled would shared by the concerned beneficiaries

• 400/220 KV step down ICTs and down stream systems by the beneficiary only(DOC after 28.03.2008)

• For MW Benificiary not identified Tr. Charges to be borne by the concerned gen station.

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Disputes Mechanism and Resolutions

• All Accounts to remain open for 20 days for verification.• Any Deviation to be bought to the notice to RPC

Secretariat.• RPC Secretariat will verify the data and take corrective

action if required and issue the revised account.• If it is found that account is as per the data furnished by

RLDC. RPC Secretariat may ask the aggrieved Party to verify the correctness of the data with RLDC.

• If RLDC finds data needs to be changed, such changes will be intimated to RPC and then RPC will issue the revised account based on the revised data.

• If aggrieved Party is still not satisfied it may take up the issue with CERC for its decision.

Rebate and Late Payment Surcharges

• 2% Rebate for payment of bills through LC

• 1% Rebate for payment made within one month

• Late Payment 1.25% per month for delayed payment beyond a period of 60 days

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