Erpc pres 100810

ERLDC
Power System Operation Corporation
SHARING OF ISTS
TRANSMISSION CHARGES
&
LOSSES

EVOLUTION OF TRANSMISSION PRICINGEVOLUTION OF TRANSMISSION PRICING
03/22/15 3
• (Usage &
Distance/Direction
sensitivity based)

PARADIGM CHANGE: EA-2003 AND NEP
► EA-2003: Facilitate competitive markets
► Generation de-licensed
► Non-discriminatory open access
► Efficient, coordinated and economical development of ISTS:
Responsibility of CTU
► National Electricity Policy
► Section 5.3.2 and 5.3.5
► Prior agreement with beneficiaries not a pre-condition for ISTS
development
► CTU/STU should undertake network expansion after
identifying the requirements in consultation with stakeholders
and taking up the execution after due regulatory approvals.
► Transmission tariff to be made sensitive distance, direction
and quantum of flow
► CERC has released the Grant of Regulatory Approval for
execution of Inter-State Transmission Scheme to CTU
regulations Dtd.31/05/10

5 03/22/15
TARIFF POLICY ON TRANSMISSION PRICING
►Section 7.1 (2), (3) & (4) and Section 7.2
►Sensitive to distance, direction and quantum
►Sharing in proportion to utilization
►Facilitate planned development/augmentation
►Discourage non-optimal investment
►Prior agreement not pre-condition
►Apportionment of losses- distance and direction
sensitive

6 03/22/15 POWERGRID
NEED FOR CHANGE IN PRICING FRAMEWORK
►Synchronous integration of Regions- Meshed Grid
►Changes caused by law and policy
►Open Access and Competitive Power Markets
►Pricing Inefficiencies, Market Players’ concern
►National Grid / Trans-regional ISGS
►Changing Network utilization
►Agreement of beneficiaries a challenge
►Ab-initio identification beneficiaries difficult

03/22/15 राषीय भार पेषण के द 7
Changing Structure of Indian Power Sector
and development of Electricity Markets

VERTICALLY INTEGRATED UTILITY
GENERATION
DISTRIBUTION
TRANSMISSION

TRANSMISSION
SERVICE
PROVIDER(TSP-1)
UTILITY(U-1)
ONE UTILITY (U-1) WITH
ONE TRANSMISSION SERVICE PROVIDER ( TSP-1 )
Transmission
Assets
(TA-1 to n)

ONE REGIONAL GRID
TWO UTILITIES WITH
ONE TRANSMISSION SERVICE PROVIDER (TSP-1)
TRANSMISSION
SERVICE
PROVIDER(TSP-1)
UTILITY (U-2)
UTILITY (U-1)
Transmission
Assets
(TA – 1 to n)

ONE REGIONAL GRID
MULTIPLE UTILITIES WITH
ONE TRANSMISSION SERVICE PROVIDER (TSP-1)
TRANSMISSION
SERVICE
PROVIDER(TSP-1)
UTILITY (U-2)
UTILITY (U-1)
Transmission
Assets
(TA – 1 to n)
UTILITY (U-4)
UTILITY (U-3)
UTILITY (U-n)

ONE REGIONAL GRID
TWO TRANSMISSION SERVICE PROVIDERS
TRANSMISSION
SERVICE
PROVIDER
(TSP – 1)
Transmission Assets (T1A 1-n)
UTILITY (U-2)
UTILITY (U-1)
UTILITY (U-4)
UTILITY (U-3)
UTILITY (U-n)
TRANSMISSION
SERVICE
PROVIDER
(TSP – 2)

ONE REGIONAL GRID
MULTIPLE TRANSMISSION SERVICE
PROVIDERS
TSP – 1
UTILITY (U-2)
UTILITY (U-1)
UTILITY (U-4)
UTILITY (U-3)
UTILITY (U-n)
TSP – 2
TSP – m
Transmission Assets (TmA 1-n)
TSP – 3

DISCOMS: COMPLEXITY INCREASED FURTHER
(D-1 TO D-N): DISCOMS PAY DIRECTLY TO TSPS
ONE REGIONAL GRID
TSP – 1
U-2
U-1
U-4
U-3
U-n
TSP – 2
TSP – m
TSP – 3
D-1 D-n
D-1 D-n
D-1 D-n
D-1 D-n
D-1 D-n

MULTIPLE REGIONS
REGIONAL GRID -1
TSP – 1
U-2
U-1
U-4
U-3
U-n
TSP – 2
TSP – m
TSP – 3
D-1 D-n
D-1 D-n
D-1 D-n
D-1 D-n
D-1 D-n
REGIONAL GRID -2
TSP – 1
U-2
U-1
U-4
U-3
U-n
TSP – 2
TSP – m
TSP – 3
D-1 D-n
D-1 D-n
D-1 D-n
D-1 D-n
D-1 D-n
Inter-Regional Interconnections

TSPS IN ONE REGION HAVING
CUSTOMERS IN ANOTHER REGION ALSO
REGIONAL GRID -1
TSP – 1
U-2
U-1
U-4
U-3
U-n
TSP – 2
TSP – m
TSP – 3
D-1 D-n
D-1 D-n
D-1 D-n
D-1 D-n
D-1 D-n
REGIONAL GRID -2
TSP – 1
U-2
U-1
U-4
U-3
U-n
TSP – 2
TSP – m
TSP – 3
D-1 D-n
D-1 D-n
D-1 D-n
D-1 D-n
D-1 D-n
Inter-Regional Interconnections

ALTERNATE FEASIBLE MODEL
TSP – 1
TSP – 2
TSP – m
TSP – 3
U-2
U-1
U-4
U-3
U-n
D-1 D-n
D-1 D-n
D-1 D-n
D-1 D-n
D-1 D-n
AGENCY
FOR
BILLING
&
COLLECTION
U-2
U-1
U-4
U-3
U-n
D-1 D-n
D-1 D-n
D-1 D-n
D-1 D-n
D-1 D-n
Region-1Region-2

18
FOCUS
►Economic/Regulatory Objective
►Operational Efficiency
► Minimisation of Present Operating Cost
►Dynamic Efficiency
► Long-term development of system
►Allocative Efficiency
► Equity and fairness in assigning costs

ALLOCATIVE EFFICIENCY - OBJECTIVES
►Simplicity
►Non-discriminatory/Equitable
►Predictable
►Strong signal for efficiency, location and
expansion
►Ease of regulation and administration
►Dispute free Implementation
►Minimize Cross Subsidies
►Transparency of Procedures
►Continuity – Smooth transition from existing
practice

Transmission Pricing Paradigms

Paradigm
►Rolled in Paradigm
► Postage stamp
► Contract Path Method
► MW-Mile
► Distance based
► Power flow based (several variant such as MM, DFM, ZCF)
► Incremental Transmission Pricing Paradigm
► Long/Short Run Incremental/Marginal
►Composite embedded / incremental transmission Pricing
Paradigm

Comparison of different methods in Transmission
Pricing Paradigm
► Postage Stamp Method –
++ Simple, familiar, most widely used in developing
market
-- insensitive to distance & direction
► Zonal Postage Stamp Method
++ sensitive to distance and direction
-- complex, difficult to implement, load flow condition
varies with dispatch scenario
► Contract Path Methodology
++ Sensitive to distance
-- provides wrong economic signal, based on
fictitious path, power flow on parallel path is ignored

►Distance Based MW-Mile Methodology
++ Simple, sensitive to distance
-- based on physical distance, not on actual power flow
►Power Flow Based MW- Methodology ( MM/
DFM/ZCF)/Power Tracing
++ sensitive to distance, takes planning and usage of network in
consideration
-- issue of net vs absolute power flow, absolute ignores directional
sensitiveness, varies with dispatch scenario
►Point tariff, Nodal Pricing or Locational Marginal Pricing
(LMP)
++Provides economic signals, suitable for developed/saturated
market
-- complex, not suitable for developing market,
losses forms the part of transmission pricing, based on MWh not
on MW.
COMPARISON OF DIFFERENT METHODS
IN TRANSMISSION PRICING PARADIGM

SHARING OF INTER-STATE
TRANSMISSION CHARGES AND
LOSSES
-REGULATIONS

DEFINITIONS
► Designated ISTS Customers (‘DIC’s)  Users of any
segments/elements of the ISTS and shall include all generators,
STUs, SEBs or load serving entities directly connected to the
ISTS including Bulk Consumer and any other entity/person
► Implementing Agency (IA) The agency designated by the
Commission to undertake the estimation of allocation of
transmission charges and transmission losses at various
nodes/zones for the Application Period along with other
functions
► Approved Injection Injection in MW vetted by IA for the DIC
for each representative block of months, peak and other than
peak scenarios at the ex-bus of the generator or any other
injection point of the Designated ISTS Customer into the ISTS,
and determined based on the generation data submitted by the
DIC incorporating total injection into the grid, considering the
long term and medium term contracts;

DEFINITIONS
► Approved Additional Medium Term Injection  means the
additional injection, as per the MTOA approved by CTU after
submission of data to NLDC by the DIC over and above the
Approved Injection for the DIC for each representative block of
months, peak and off-peak scenarios at the ex-bus of the
generator or any other injection point of the DIC into the ISTS
► Approved Short Term Injection The injection, as per the
STOA approved by RLDC /RLDC & including PX
► Similarly we have Approved Withdrawal (simultaenous
withdrawal), Approved additional MT withdrawal & Approved
ST withdrawal
► Deemed Inter State Transmission System (Deemed ISTS) 
Transmission system which has regulatory approval of the
Commission as being used for interstate transmission of
power and qualified as ISTS
► Point of Connection (PoC) transmission charges  Nodal /
zonal charges determined using the POC method

DEFINITIONS
►Yearly Transmission Charge (YTC) Annual
Transmission Charges for existing lines determined
by the Commission in accordance with the Terms
and Conditions of Tariff Regulations or adopted in
the case of tariff based competitive bidding in
accordance with the Transmission License
Regulations and for new lines based on
benchmarked capital costs
►Uniform Charge  Charged determined by dividing
the YTC of the ISTS Licensees by the sum of the
Approved Injection and Approved Withdrawal from
the grid(postage stamp charge)

SCOPE OF THE REGULATIONS
►Power Stations / Generating Stations that are
regional entities as defined in the Indian Electricity
Grid Code (IEGC)
►SEBs/ STUs connected with ISTS (on behalf of
distribution companies, generators and other bulk
customers connected to the transmission system
owned by the SEB/STU/intrastate transmission
licensee)
►Any bulk consumer directly connected with the ISTS
►Any designated entity representing a physically
connected entity as per clauses above
►Regional Entity Those who are in the RLDC
control area and whose metering and energy
accounting is done at the regional level

PRINCIPAL/MECHANISM FOR SHARING OF ISTS
CHARGES AND LOSSES
►PRINCIPLES:
►Load Flow Based Method
►Point of Connection Charging Method
►MECHANISM
►PoC Charges and Losses in advance
►Based on Technical and Commercial Information
provided by DICs, ISTS Transmission Licensees,
NLDC, RLDCs and SLDCs
►Charges for LTA/MTOA : Rs/MW/Month
►Charges for STOA : Rs/MW/Hour

PROCESS FOR DETERMINATION OF POC
CHARGES & LOSSES
► Data Collection Regulation 7(1)
► DICs, Transmission Licensees to submit Basic Network
Data
► Network Data for Load Flow Analysis Regulation 7(1)(b)
► Electrical Plant or line upto 132 kV
► Generators connected at 110 kV
► Inflow from lower levels  generation at that node
► Outflow towards lower levels  Load at that node
► Dedicated Transmission Lines Regulation 7(1)(c)
► Owned and Operated by ISTS………. Included in Basic
Network
► Owned and Operated by Generator….Excluded

Data Collection (1)
► As per the Regulation and Data Collection Procedure
► All concerned entities to submit
► Details of Network Elements
► Generation and Load at various nodes
► Yearly Transmission Charges
► Forecast Injection / Withdrawal
► Additional Medium Term Withdrawal / Injection
► By 10th
of every month by every DIC
► RPC to send list of certified non-ISTS lines to IA
► IA to send the lists to CERC for approval
► YTC of Certified non-ISTS lines to be approved from appropriate
commission

INFORMATION PROCEDURES
►Data to be submitted by DICs
►YTC, Basic Network Details of ISTS, Deemed ISTS,
Certified ISTS Lines
►Demand or Injection Forecast for each season
►On or Before the end of fourth week of November
►Data to be submitted by CTU, Owners of Deemed
ISTS and DICs
►Entire Network Data for first year of
Implementation
►Dates and data of commissioning of any new
transmission asset for subsequent years

INFORMATION PROCEDURES
►Injection and Withdrawal forecast for different
blocks of months (Peak and Other than Peak):
Regulation 16(4)
► April to June…………………………… (May 15)
► July to September……………………. (August 31)
► October to November………………… (October 30)
► December to February……………….. (January 15)
► March…………………………………… (March 15)
►In case any of the above fall on a Weekend/Public
Holiday, the data shall be submitted for working
days immediately after the dates indicated.

FLOW CHART FOR DATA ACQUISITION
STU/SEBs/CTU
Implementing
Agency
Network
Parameters Line wise YTC
Designated
ISTS
Customers
Nodal
Injection /
Withdrawal
Additional
Medium Term
Injection /
Withdrawal
Approved
Injection
Approved
Withdrawal
Basic
Network
Network
Parameters

► Nodal Generation / Demand Regulation 7(1)(d) / (e)
► Based on Forecast provided by DICs
► Forecast should be based on Long Term and Medium Term
Contracts
► Forecast Generation to be vetted by IA based on Historic
Generation / Demand.
► Changes in Generation /Demand to be Communicated to DICs
► In case of conflict validation committee to take final decision
► IA to perform AC Load flow Regulation 7(1)(h)
► To obtain LGB & for achieving convergence adjustments may be
required to be made on vetted generation/demand
► Converged Load Flow results to be verified by Validation
Committee Regulation 7(1)(i)

VALIDATION COMMITTEE
►Nominee from Commission to Chair the Committee
Regulation 7(1)(g)
►Validation Committee Comprises two officials each
from:
► Implementing Agency
► National Load Despatch Centre
► Regional Power Committee
► Central Transmission Utility
► Central Electricity Authority
► Central Electricity Regulatory Commission

NETWORK TRUNCATION
►Network Truncation by IA Regulation 7(1)(k)
► Upto 400 kV except NER, where it shall be reduced to 132 kV
Annexure I, Clause 2.3
►Power inflow from Lower voltage Level : Generation
Node Annexure I, Clause 2.3
►Power outflow from Lower voltage Level : Demand
Node Annexure I, Clause 2.3
►AC Load Flow on Truncated Network

COMPUTATION OF POC CHARGES (1)
► Average YTC per circuit km(for each voltage level & conductor
configuration) shall be used for computation of charges
Regulation 7(1)(l)
► e.g. 400 KVD/C twin Moose, 400 kV Quad Moose, 400 kV Quad
Bersimis etc.,
► YTC of substations to be apportioned in line
Regulation 7(1)(m)
► 2/3 to higher voltage lines
► 1/3 to lower voltage lines
► Apportionment among lines on the basis of length in ckt. kms
► PoC Charges to be computed for 5 blocks of month for peak
and other the peak conditions

COMPUTATION OF POC CHARGES (2)
► Representative Blocks of Months Regulation 7(1)(o)
► April to June
► July to September
► October to November
► December to February
► March
► Peak Hours : 8hrs Regulation 7(1)(o)
► Other the Peak Hours :16 Hrs
► Average YTC to be apportioned to peak and other than peak
based on the no. of hours constituting these periods
Regulation 7(1)(p)
► 50% recovery through Hybrid Methodology and 50% through
Uniform Charge Sharing Mechanism(for first two years )
Regulation 7(1)(q)

COMPUTATION OF POC LOSSES
►Loss Allocation Factor to be computed for each
season using Hybrid Methodology
Regulation 7(1)(r)
►50% losses through Hybrid Method and 50% through
Uniform Loss Allocation Mechanism(for first two
years)
Regulation 7(1)
(s)
►Weighted average of LAF for peak and other than
peak conditions shall be used
Regulation 7(1)
(s)
►Loss Application as per the Procedure prepared by
NLDC

ZONING
► Criteria for Zoning of nodes: Regulations7(1)(t)
► Costs within the same range
► Geographically and electrically proximate
► Nodes with connectivity to Thermal Generators > 1500 MW or
Hydro Generators > 500 MW to be taken as separate zone.
► Demand zones : Sate Control Area
► Except NER states where entire region is to be taken as one
zone.
► Zonal Charges : Weighted Average of Nodal Charges
► Revision of Zones in a financial year
► Significant Changes in Power System
► Prior approval from commission Regulations7(1)(t)(vi)
► Generating stations connected to ISTS network < 400KV would
be charged at zonal charges where physically located
► No transmission charges/losses for solar projects (for the entire
useful life) commissioned within next 3 years.

SPECIFIC CHARGES
► Charges thus determined to the extent of approved
injection/withdrawal for each DIC
► In the event of a Designated ISTS Customer failing to provide its
requisition for demand or injection for an Application Period,
the last demand or injection forecast supplied by the DIC and as
adjusted by the Implementing Agency for Load Flow Analysis
shall be deemed to be Approved Withdrawal or Approved
Injection
► In case the metered MWs (ex-bus) of a power station or the
aggregate demand of a Designated ISTS Customer exceeds, in
any time block,
(a) In case of generators: The Approved Injection + Approved
Additional Medium Term Injection + Approved Short Term
Injection or;
(b) In case of demand customers: The Approved Withdrawal +
Approved Additional Medium Term Withdrawal + Approved
Short Term Demand,
Additional charges would be applicable for deviation

SPECIFIC CHARGES
► For deviation > 20% in any time block, the DIC shall be
required to pay transmission charges for excess
generation @ 25% above the zonal POC charges
determined for zone where the Designated ISTS Customer
is physically located
► Such additional charges would not be applicable in case::
► Rescheduling of the planned maintenance program which is
beyond the control of the generator
► Certified by RPC
► Payment on account of additional charges for deviation by
the generator shall not be charged to its long term
customer and shall be payable by the generator

SPECIFIC CHARGES
►Even if in case of injection / withdrawal < Approved
injection/withdrawal allocated transmission charges
to be fully paid
►After declaration of COD of a generator, charges
payable by generators for LT supply shall be billed
directly to the LT customers based on capacity share
in the generating stations
►However, before COD, charges to be borne by
generators
►There would be no differentiation between POC
charges/losses for LT/MT/ST customers

IMPLEMENTING AGENCY (IA) (Chapter 8)
►For First Two Years Regulation 18(1)
► NLDC shall be Implementing Agency
►Procedures to be prepared by IA
► Procedure for Data Collection
► Procedure for Loss Sharing
► Procedure for Transmission Charge Computation
►Expenses of IA to be included in YTC and approved
by Commission Regulation 18(4)

TREATMENT OF HVDC Annexure I Clause 2.7
►Zero Marginal Participation for HVDC Line
► HVDC line flow regulated by power order.
►MP Method can not recover its cost directly.
►HVDC line can be modeled as:
► Load at sending end
► Generator at receiving end

Indirect Method for HVDC Cost Allocation
► Compute Transmission Charges for all load and generators
with all HVDC lines in service.
► Disconnect HVDC line and again compute new transmission
charges for all loads and generators
► Compute difference between nodal charges with or without
HVDC.
► Identify nodes which benefits with the presence of
HVDC[Benefit = (old cost i.e. base case with injection from
Talchar Kolar) minus (new usage cost i.e. with link
disconnected)]
► In case benefit –ve same to be collared to zero
► Allocate HVDC line cost to the identified nodes.

Module on
Computation of PoC Transmission
Charges
National Load Despatch Centre
Power System Operation
Corporation

Process Chart for Computation of PoC Charges
Data Collection
Basic Network
Preparation
Load Flow Studies
Zoning
Network Reduction
PoC Charges &
Losses Computation

Data Collection (2)
►NLDC to specify :
► Nodes/group of nodes on which DICs would submit the
forecasted injection/withdrawal.
►IA to specify :
► Peak and other than Peak conditions for each representative
blocks for the next application period.

Approved Injection/ Withdrawal
►Approval of Forecasted Injection/Withdrawal on the
basis of
► Long Term and Existing Medium Term Contracts
► Database of RLDC/NLDC
►Approved Demand/Withdrawal to be notified on the
website of IA
►Adjustments in forecasted Injection/withdrawal to
be intimated to concerned DIC.

Computation of AC Load Flows
►Seprately for NEW and SR Grid
►Adjustments for converging Load Flow
► If Load > Generation
► Pro-rata scaling down of Load
► If Generation > Load
► Pro-rata scaling down of Generation
►Validation committee to validate
► Converged Load Flow Results
► Basic Network
► Nodal Injection / Withdrawal

Network Reduction
 Reduction upto 400 kV (except NER where the
network will be reduced to 132 kV)
►Injection from Lower Voltage : Generation
►Drawal from Lower Voltage : Demand
Software
Reduced Network
Average YTC after
Truing up
PoC
Charges
and LAF

Computation of Charges
► Annual Average YTC to be apportioned to peak and Other
than peak conditions
►Net PoC Charge = 50% PoC Charge + 50% Uniform Charge
► UC = Total ARR /(Approved injection +approved
Withdrawal)
► Calculation of Uniform Charge on All India Basis
► Scaling on Pro-rata basis to adjust over or under recovery
► Treatment of Generators connected at 220 kV
► Charged at PoC Charge of the zone

Zoning
►As per the regulations
►Fixed for an application period
►Zonal Charges / Zonal LAF
► Weighted average of all nodes in the zone
►Treatment of nodes feeding more than one zone
► To be used in both zones
► Pro-rata charges in both zones based on ratio of power flow.

Information to RPC
►Approved Withdrawal/Injection (MW) for peak and
other than peak hours for each season
►Zonal Point of Connection Charge (Rs/MW/month)
for Generation and Demand Zones
►Approved Additional Medium Term Withdrawal /
Injection (MW)
►Details of Short Term Open Access
As per format I and II of the Procedure

Information on Public Domain
►Approved Basic Network Data and Assumptions, if
any
►Zonal or nodal transmission charges for the next
financial year differentiated by block of months;
►Zonal or nodal transmission losses data;
►Schedule of charges payable by each constituent for
the future Application Period, after undertaking
necessary true-up of costs
Username and Password to view critical data

Format I :Approved Withdrawal/Injection (MW)
& Zonal PoC Charge
Name of
the Zone
Approved Withdrawal
(MW)
Approved Injection
(MW)
Zonal
PoC
Charge
*
(Rs/MW
/Month)
Peak
Other
Than Peak Peak
Other
Than Peak
Season I
Season II
Season III
Season IV
Season V

Format II: Approved Additional Medium Term
Withdrawal/Injection
Name of DIC Duration
Approved
Additional Medium
Term Withdrawal
(MW)
Approved
Additional Medium
Term Injection
(MW)
From To Peak
Other Than
Peak Peak
Other Than
Peak

ACCOUNTING BILLING & COLLECTION
OF CHARGES(CHAPTER 5)

INPUTS FOR MONTHLY TRANSMISSION
ACCOUNTS
► Approved injection / withdrawal from IA
► Zonal POCs from IA
► Approved additional MT injection/withdrawal RLDC/NLDC
► Approved ST injection/withdrawal from RLDC/NLDC
► SEM data for deviation computations
► RPCs to issue monthly transmission accounts(1st
working
day of the Month)
► RPCs to issue monthly transmission deviation acounts(by
15th
of the Month)
► CTU shall be responsible for raising the transmission bills,
collection and disbursement of transmission charges to
ISTS transmission licensees
► Expenses incurred by CTU on account of this function shall
be reimbursed as part of YTC

Accounting Regulation 10
Regional Transmission
Accounts
(1st
Working Day
of Every Month
for the previous Month)
Regional Transmission
Deviation Accounts
(by 15th
Day
of Every Month
for the previous Month)
Regional
Power
Committee
Regional
Power
Committee

Billing (1) Regulation 11
►Responsibility of Central Transmission Utility (CTU)
► Based on Accounts issued by RPC
►Long Term Customers shall be billed directly for:
► Own Transmission Charges
► Generator Transmission Charges in proportion to MW entitlement
after “Commercial Operation”
►Generators shall be billed only for deviations.
►Bill to be raised only on DIC’s
► SEB/STU may recover such charges from DISCOMs, Generators
and Bulk Consumers.

Billing (2)
Central
Transmission
Utility
Central
Transmission
Utility
First Part
(Based on Approved
Injection/Withdrawal and
PoC Charge)
Third Part
(Adjustments Based on
FERV,Interest, Rescheduling
of Commissioning)
Fourth Part
(Deviations)
Second Part
(Recovery of Charges for
Additional Medium Term
Open Access)
1st
Day of
a Month
1st
Day of
a Month
Biannually
(1st
Day of
September
and March
18th
Day
of a
Month

BILL PART-I
► To be raised by 1st
working day of the month by CTU
► Independent of Transmission accounts to be issued by RPCs
For Generators
[ (PoC Transmission Charge of generation zone in Rs / MW /
month for peak hours)× (Approved Injection for peak hours) ]
+
month for off-peak hours) x (Approved Injection for off-peak
hours) ]
For Demand
[ (PoC Transmission Charge of demand zone in Rs / MW /
month for peak hours)x(Approved withdrawal for peak hours) ]
+
[ (PoC Transmission Charge of demand zone in Rs / MW /
month for off-peak hours) x (Approved withdrawal for off-peak
hours) ]

BILL PART-II
► To be simultaneously raised alongwith BILL-PART-I
For Generators
month for peak hours)× (Approved Additional MediumTerm
Injection for peak hours) ]
+
month for off-peak hours) x (Approved Additional MediumTerm
Injection for off-peak hours) ]
For Demand
[ (PoC Transmission Charge of demand zone in Rs / MW / month
for peak hours)x(Approved Additional MediumTerm withdrawal
for peak hours) ]
+
[ (PoC Transmission Charge of demand zone in Rs / MW / month
for off-peak hours) x (Approved Additional MediumTerm
withdrawal for off-peak hours) ]
► Revenue from Additional MTOA alongwith interest to be used
for truing up the YTC for next F.Y.(i.e would be adjusted in YTC
of the licensee for computation of POC for next F.Y.)

BILL PART-IV (TREATMENT OF DEVIATIONS)
REGULATION 11(7)
►Deviation calculations after considering additional
MT & Short Term Open Access for each time block
►Deviation =
[Average MW injected/withdrawn]
-
[ (Approved injection/withdrawal+Approved additional
MT injection/withdrawal+ST injection/withdrawal) ]
►Charge to be Calculated on Block wise Deviation
►Deviations by Generator shall not be charged to
Long Term Customers
►No additional Charge for Deviations in case :
► Rescheduling of Maintenance Schedule for reasons beyond
control of geenrator OR Certified by RPC

Treatment of Deviations -GENERATOR
Generator
Net
Injection Net Drawl
1.25 times PoC
Charge for the
average MW
withdrawal
Deviation
Less than
20%
Deviation
Greater
than 20%
PoC Charge
1.25 times PoC Charge
for the excess
deviation > 20%

Treatment of Deviations –Demand Customer
Demand
Net Drawl Net
Injection
1.25 times PoC
Charge for the
average MW
injected
Deviation
Less than
20%
Deviation
Greater
than 20%
PoC Charge
1.25 times PoC Charge
for the excess
deviation > 20%

BILL PART-IV (TREATMENT OF DEVIATIONS)
REGULATION 11(7)
► Thus additional charges due to deviations =
1.25 x POC transmission charge for demand / withdrawal x
Deviations
In case a generator withdraws from grid::
► Additional charges = 1.25 x POC transmission charge for the
demand zone x Average MW withdrawn for the corresponding
blocks
In case a withdrawing DIC becomes a net injector::
► Additional charges = 1.25 x POC transmission charge for the
generation zone x Average MW injected for the corresponding
blocks
► Bill for deviations to be raised by CTU within 3 days of issue of
Transmission deviation accounts by RPC.
► This part alongwith interest would be used for truing up the
YTC for next F.Y.(i.e would be adjusted in YTC of the licensee
for computation of POC for next F.Y.)

BILL PART-III
►The 3rd
Part of the Bill to be raised bi-annully by CTU
on the first working day of September & March for
the previous six months
►The bill shall be used to adjust any variations in
interest rates, FERV, rescheduling of commissioning
of transmission assets, etc.
►Recovery/Reimbursement would be on basis of
under-recovery/over-recovery, in proportion to
average approved injection/withdrawal over previous
six months
►CTU to transfer the 3rd
part to respective ISTS
licensees for whom the adjustment is required

COLLECTION AND DISBURSEMENT
REGULATION 12
► CTU to collect charges on behalf of ISTS service providers.
► CTU to disburse in proportion to Monthly Transmission
Charges.
► Payment and Disbursement shall be executed through
RTGS.
► Delayed Payments shall result in pro-rata reduction in all
payouts
► Payment Security as per detailed procedure prepared by
CTU

TRANSMISSION SERVICE AGREEMENT(TSA)
REGULATION 13
► Existing BPTAs realigned  TSA
► TSA provides for all relevant matters regarding the POC losses/charges
mechanism(e.g.)::
► Detailed Commercial/adminsitrative provisions
► Metering, accouitnitng, billing, charges recovery provisions
► Procedures for interconnection
► Treatment in delay of line commissioning
► Payment security mechanisms
► default & consequences
► Termination & Force majeure conditions
► Draft TSA to be finalized by CTU and approved by CERC
► Notified TSA would be the default transmission agreement and would
mandatorily apply to all DICs
► Signing of TSA not a precondition for construction of new network
elements by CTU/licensees after approval by CERC
► TSA may have certain aspects which could be modified from time to
time without rendering the TSA infructuous e.g. contracted capacity,
etc..

TRANSMISSION SERVICE AGREEMENT(TSA)
REGULATION 13
►CTU to prepare revenue sharing agreement which is
to be approved by CERC for disbursal of monthly
transmission charges to various ISTS licnesees
►The impact of any delayed payment/non-payment by
any DIC would be shared pro-rata in proportion of
YTC by all the ISTS transmission licensees including
CTU
►Users to ensure that existing contracts(e.g. BPTAs)
are realigned to these regulations within a period of
60 days from the date of notification of the TSA

LIST OF PROCEDURES AS A PART
OFTRANSITION REGULATION 15
► Commission would notify detailed procedures prepared by IA,
NLDC & CTU as a part of transition mechanism
►Procedure for obtaining data  IA
►Procedure for computation of POC charges  IA
►Procedure for sharing of losses  IA
►Procedures for Billing and collection of charges by the CTU
on behalf of Transmission Licensees and redistribution 
CTU
►Payment and payment security related procedures  CTU

Information on Public Domain Regulation 17
►Approved Basic Network Data and Assumptions, if
any
►Zonal or nodal transmission charges for each block
of month
►Zonal or Nodal Transmission losses data
►Schedule of Charges payable by each constituent
after undertaking necessary true up costs
►Underlying network information & base load flows

Module on
Information Submission
By DIC’s
Power System Operation
Corporation

Introduction
►Hybrid Method : Based on Load Flow (Offline
Studies)
►Average participation for slack bus identification
►Marginal Participation for usage identification
►Recovery of Charges
► 50% by Uniform Charge Method
► 50% by PoC Charge Method

Importance of Data in Hybrid Methodology
►Input to the Offline Line Model for Load Flow Studies
► Network Parameters
► Load and Generation Data ( MW & MVAr)
►Results of offline line studies highly dependent
upon the input to the model
►Inconsistent data may not make solution Converged
►May lead to modifications in Approved Demand /
Injection

►PoC Charge Calculation depends upon :
► Converged and Reduced Network
► Line wise YTC provided by Transmission Licensees
►Approved Injection / Withdrawal
►Data to be submitted on or before 4th
Week of
November for next F.Y.
►The information may be sought by the IA at times
other than those if necessary

Flow Chart
Load Flow Studies
Input
Output
Network Parameters
Load & Generation Data
Converged Network
Network
Reduction
Software for PoC
Charge & Loss
Computation
Reduced Network
Line wise YTC
PoC Charges
and LAF

How to Give Information to IA ?
►Identify a person(s) who will coordinate with
Implementing Agency
►Communicate the details of Identified Person to the
Designated Officer of IA.
► Name
► Designation
► Company Name
► Office Address
► Contact Number : Official (Landline)
Mobile Number
► Letter of Authorization

►Formats would be available on the website of IA and
all RLDCs after getting permission from the
Commission
► www.nldc.in
► www.nldcindia.in
►Submission of data shall be only in electronic
spreadsheet formats (MS Excel).
►For all communication puposes
► emailid of IA : implementingagency@powergridindia.com
►Written communication confirming submission of
data by e-mail.

Network Parameters
►Network Data upto 132 kV except where generators
are connected to Grid at 110KV
►Injection below 132 kV : Generation
►Withdrawal below 132 kV : Load
►Also include states generation.

Type of Data
DIC’s
Load &
Generation Data
Network Data
Forecast
Injection /
Withdrawal
YTC of each
ISTS Line
Transmission
Licensees

Category of Network Parameters
Network
Parameters
Switched
Shunt Data
Transformer
Data
DC Line
Data
AC Line
Data
Generator
Data
Bus
Data

Bus Data
►Bus Type
►Bus Name : Full Name of Substation
►Conductance
► Real Component of Shunt admittance to ground
► In MW at one per unit voltage
► Should not include resistive impedance load

►Susceptance
► Reactive Component of Shunt admittance to ground
► In Mvar at one per unit
► Should not include reactive impedance load , line charging and
line connected shunts
Sign Convention
+ for Capacitor
- for Reactor
►Voltage in kV

Generator Data
►Bus Name
►Generator Real Power Ouput
► Ex Bus Output in MW
►Generator Reactive Power Output
► Ex Bus Output in Mvar
►Maximum and Minimum Generator Reactive Power
Output
►IREG
► Bus Name of remote type 1 bus whose voltage is to be regulated
by this plant

►Resistance and Reactance on MVA base
►MVA Base
► Total MVA base of the units represented by this machine
►RT, XT
► Step up Transformer Impedance in per unit on MVA Base
►GTAP
► Step up Transformer off-nominal turns ratio (in pu)
►Maximum and Minimum Real Power Output
►RMPCT
► Percent of total Mvar required to hold the voltage at bus IREG

Load Data
►Bus Name
►Real & Reactive Power Component
► Constant MVA Load
► Constant Current Load
► Constant Admittance Load

AC Line Data
►From Bus Name (I)
►To Bus Name (J)
►Circuit Number
► For D/C line one line will have 1 in this data and 2 for other line
►Branch Resistance, Reactance and Charging
Susceptance
► In pu on 100 MVA base
►Rate A
► Operating limit considering the compensations and length of line
► Minimum of Thermal, Voltage and Stability limits.

►Transformer off-nominal tap ratio
►Transformer phase shift angle
► In degrees
► Positive from untapped to tapped side and vice versa
►Complex admittance of the line shunt at bus I (GI+j BI)
►Complex admittance of the line shunt at bus J
(GJ+j BJ)
►Line Length

DC Line Data (Line quantities and Control)
►DC Line Number
►Control Mode
► 0 – Blocked
► 1 – Power
► 2 – Current
►DC Line resistance in Ohms
►Current or Power Demand
► If Control mode is 1 then power, if 2 then current.

►Scheduled Compounded dc voltage in kV
►Mode Switch dc voltage
► If inverter voltage falls below this value and control mode is 1
then it changes to 2.
►Compounding Resistance
►Metered end code
► R for rectifier or I for inverter
►Minimum Compounded dc voltage

DC Line Data (Rectifier & Inverter
►Rectifier converter bus name
►Number of bridges in series
►Nominal maximum rectifier firing angle
►Minimum steady state rectifier firing angle
►Rectifier commutating transformer resistance &
reactance per bridge

►Rectifier primary base ac voltage
►Rectifier transformer ratio
►Rectifier tap setting
►Maximum rectifier tap setting
►Minimum rectifier tap setting
►Rectifier tap step

►Rectifier firing angle
►Tapped side “ from bus” name
►Untapped side “ to bus” name
►Commutating capacitor reactance

Transformer Data
►From Bus
►To Bus
►Circuit Number
►Resistance and Reactance in per unit
►Phase shift angle
►Nominal Tap Ratio

►Controlled Bus Name
►Maximum Voltage of Controlled Bus
►Minimum Voltage of Controlled Bus
►Max Turns Ratio
►Turns Ratio Step Increment

Switched Shunt Data
►Bus Name
►Control Mode
► 0 – Fixed
► 1 – Discrete
► 2 – Continuous
►Desired Voltage Upper & Lower Limit
►Ni : Number of steps for block I
►Bi : Admittance increment for each Ni steps in block
i

Forecast Nodal Injection / Withdrawal (1)
► Two figure for each block of months
► One for peak and other for offpeak
► Five Representative Blocks
► April to June…………………………… (May 15)
► July to September……………………. (August 31)
► October to November………………… (October 30)
► December to February……………….. (January 15)
► March…………………………………… (March 15)
► The data should be of the date mentioned against each block of month.
► In case any of the above fall on a Weekend/Public Holiday, the data
shall be submitted for working days immediately after the dates
indicated.
► In case large changes in POC are foreseen on account of network or
usage IA may undertake revised computations after petition from
Commission & directions from CERC
► Duration of peak hours for each block
► Specified by NLDC

Forecast Nodal Injection / Withdrawal (2)
►MW & MVAr Injection / Withdrawal at each node
►Forecast of MVAr on the basis of
► Historic Injection /Withdrawal
► Anticipated Change in Load pf
►Forecast of MW
► On the basis of MW entitlements
►Forecast required for 5 blocks of month
►For Generators forecast should be equal to the rated
capacity
Forecast = max(G1) + max(G1) +……………….

Commercial Data
►Line wise YTC of each ISTS Line
►Breakup of total YTC among different Voltage
Levels.
►In case of YTC not approved by SERC/CERC
► Benchmark/Reference cost to be used.
►YTC of substations to be apportioned in line
► 2/3 to higher voltage lines
► 1/3 to lower voltage lines
► Apportionment among lines on the basis of length.

Certified Non-ISTS Lines
►Non-ISTS lines certified by RPC as being used as
ISTS line will be included in the model.
►Transmission Licensees to get them certified in
RPC.
►Line wise YTC to be also certified by RPC and
approved by CERC.
►Such List to be provided to IA by Transmission
Licensee
► Latest by Fourth week of November

Sharing of Inter-State Transmission
Losses
Based on PoC Losses
Power System Operation Corporation

Introduction
►The procedure aims to keep computation:
► Simple
► Non-Recursive
►Loss Application on Regional Basis
► In line with existing practice
► No Pan caking.
►Injection and withdrawal loss would be calculated
for each zone.

New Methodology
► Point of Connection Losses
► Independent of Contract Path
►50% PoC losses + 50% Uniform Losses
►Uniform Loss component
► Based on Regional Losses of last week
►Moderation of Losses
► Based on Actual Regional Losses of last week and Losses
based on studies

PoC Loss Computation (1)
►Computation of changes in losses in the system due
to incremental injection / withdrawal at each node.
►Loss Allocation Factor

PoC Loss Computation (2)
►Output of System Studies
► MW Losses of each node
► Loss Allocation Factor
► Weighted average losses (%) for each region
►Zonal Loss : Weighted Average of losses at each
node
►Moderation of Zonal Losses
►One PoC Loss for each entity per day
► Weighted average of peak and other than peak

Loss Sharing Mechanism
Zonal Losses
as Computed
from Hybrid
Method
Calculation of
Previous week
Losses from
SEM Data
Total Losses
based on PoC
Software
Provided by
CERC
Total Losses
(50% PoC+50%UC)
Moderation Of PoC Losses

Moderation of Losses (1)
►Need of Moderation
► Difference in actual and study scenarios
► Correct computation of injection and drawal schedule of various
utilities.
► Scheduled losses to be closer to actual losses in the system so
that system mismatch is avoided.
► Minimizing the mismatch between UI payable and receivable
►Moderation at regional Level
►Moderation Factor
= Actual Losses of previous week (Aact) ( In %)
------------------------------------------------------------------
Regional Losses based on Studies (As)(In %)

►Regional Losses Based on Studies (As)
► Weighted average losses of a region
where A is Total MW losses of a region
∑GNG = Total Injection in a region
∑IIR = Inter Regional Exchange
A*100 / (∑GNG ±(∑IIR )

Application of Losses in Scheduling
►Net PoC Loss = 50% Moderated PoC Loss + 50%
Uniform Loss
►Net PoC Loss to be applied on each regional entity
►Drawee Entity to bear full losses for :
► Long Term Transactions
► Medium Term Transactions
► Bilateral Transactions
►Injecting Entity and Drawee Entity to share losses
for:03/22/15 राषीय भार पेषण के द 115

Case I : Intra-Regional Transactions
A
B
100 MW
92.15 MW
Zone Moderated
Loss (%)
A 3
B 5

Case II : Inter Regional Transactions
B
A
Zone Moderated
Loss (%)
A 3
B 5
100 MW
97 MW
92.15 MW

Case III : Transactions Involving Wheeling
Region
B
A
100 MW
92.15 MW
97 MW
97 MW

Erpc pres 100810

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