3. EVOLUTION OF TRANSMISSION PRICINGEVOLUTION OF TRANSMISSION PRICING
03/22/15 3
âą (Usage &
Distance/Direction
sensitivity based)
4. PARADIGM CHANGE: EA-2003 AND NEP
âș EA-2003: Facilitate competitive markets
âș Generation de-licensed
âș Non-discriminatory open access
âș Efficient, coordinated and economical development of ISTS:
Responsibility of CTU
âș National Electricity Policy
âș Section 5.3.2 and 5.3.5
âș Prior agreement with beneficiaries not a pre-condition for ISTS
development
âș CTU/STU should undertake network expansion after
identifying the requirements in consultation with stakeholders
and taking up the execution after due regulatory approvals.
âș Transmission tariff to be made sensitive distance, direction
and quantum of flow
âș CERC has released the Grant of Regulatory Approval for
execution of Inter-State Transmission Scheme to CTU
regulations Dtd.31/05/10
5. 5 03/22/15
TARIFF POLICY ON TRANSMISSION PRICING
âșSection 7.1 (2), (3) & (4) and Section 7.2
âșSensitive to distance, direction and quantum
âșSharing in proportion to utilization
âșFacilitate planned development/augmentation
âșDiscourage non-optimal investment
âșPrior agreement not pre-condition
âșApportionment of losses- distance and direction
sensitive
6. 6 03/22/15 POWERGRID
NEED FOR CHANGE IN PRICING FRAMEWORK
âșSynchronous integration of Regions- Meshed Grid
âșChanges caused by law and policy
âșOpen Access and Competitive Power Markets
âșPricing Inefficiencies, Market Playersâ concern
âșNational Grid / Trans-regional ISGS
âșChanging Network utilization
âșAgreement of beneficiaries a challenge
âșAb-initio identification beneficiaries difficult
7. 03/22/15 à€°à€Ÿà€·à„à€Ż à€à€Ÿà€° à€Șà„à€·à€Ł à€à„ à€Š 7
Changing Structure of Indian Power Sector
and development of Electricity Markets
10. 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 â 1 to n)
11. 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 â 1 to n)
UTILITY (U-4)
UTILITY (U-3)
UTILITY (U-n)
12. ONE REGIONAL GRID
MULTIPLE UTILITIES WITH
TWO TRANSMISSION SERVICE PROVIDERS
TRANSMISSION
SERVICE
PROVIDER
(TSP â 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 â 2)
Transmission Assets (T2A 1-n)
19. 19 03/22/15 POWERGRID
ALLOCATIVE EFFICIENCY - OBJECTIVES
âșSimplicity
âșNon-discriminatory/Equitable
âșPredictable
âșStrong signal for efficiency, location and
expansion
âșEase of regulation and administration
âșDispute free Implementation
âșMinimize Cross Subsidies
âșTransparency of Procedures
âșContinuity â Smooth transition from existing
practice
21. Paradigm
âșRolled in Paradigm
âș Postage stamp
âș Contract Path Method
âș MW-Mile
âș Distance based
âș Power flow based (several variant such as MM, DFM, ZCF)
âș Incremental Transmission Pricing Paradigm
âș Long/Short Run Incremental/Marginal
âșComposite embedded / incremental transmission Pricing
Paradigm
22. 22 03/22/15 POWERGRID
Comparison of different methods in Transmission
Pricing Paradigm
âș Postage Stamp Method â
++ Simple, familiar, most widely used in developing
market
-- insensitive to distance & direction
âș Zonal Postage Stamp Method
++ sensitive to distance and direction
-- complex, difficult to implement, load flow condition
varies with dispatch scenario
âș Contract Path Methodology
++ Sensitive to distance
-- provides wrong economic signal, based on
fictitious path, power flow on parallel path is ignored
23. âșDistance Based MW-Mile Methodology
++ Simple, sensitive to distance
-- based on physical distance, not on actual power flow
âșPower 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
âșPoint 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
26. DEFINITIONS
âș Designated ISTS Customers (âDICâs) ï 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
âș Implementing Agency (IA)ï 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
âș Approved Injectionï 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;
27. DEFINITIONS
âș Approved Additional Medium Term Injection ï 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
âș Approved Short Term Injectionï The injection, as per the
STOA approved by RLDC /RLDC & including PX
âș Similarly we have Approved Withdrawal (simultaenous
withdrawal), Approved additional MT withdrawal & Approved
ST withdrawal
âș Deemed Inter State Transmission System (Deemed ISTS) ï
Transmission system which has regulatory approval of the
Commission as being used for interstate transmission of
power and qualified as ISTS
âș Point of Connection (PoC) transmission charges ï Nodal /
zonal charges determined using the POC method
28. DEFINITIONS
âșYearly Transmission Charge (YTC)ï 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
âșUniform Charge ï 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)
29. SCOPE OF THE REGULATIONS
âșPower Stations / Generating Stations that are
regional entities as defined in the Indian Electricity
Grid Code (IEGC)
âșSEBs/ 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)
âșAny bulk consumer directly connected with the ISTS
âșAny designated entity representing a physically
connected entity as per clauses above
âșRegional Entityï Those who are in the RLDC
control area and whose metering and energy
accounting is done at the regional level
30. PRINCIPAL/MECHANISM FOR SHARING OF ISTS
CHARGES AND LOSSES
âșPRINCIPLES:
âșLoad Flow Based Method
âșPoint of Connection Charging Method
âșMECHANISM
âșPoC Charges and Losses in advance
âșBased on Technical and Commercial Information
provided by DICs, ISTS Transmission Licensees,
NLDC, RLDCs and SLDCs
âșCharges for LTA/MTOA : Rs/MW/Month
âșCharges for STOA : Rs/MW/Hour
31. PROCESS FOR DETERMINATION OF POC
CHARGES & LOSSES
âș Data Collection Regulation 7(1)
âș DICs, Transmission Licensees to submit Basic Network
Data
âș Network Data for Load Flow Analysis Regulation 7(1)(b)
âș Electrical Plant or line upto 132 kV
âș Generators connected at 110 kV
âș Inflow from lower levels ï generation at that node
âș Outflow towards lower levels ï Load at that node
âș Dedicated Transmission Lines Regulation 7(1)(c)
âș Owned and Operated by ISTSâŠâŠâŠ. Included in Basic
Network
âș Owned and Operated by GeneratorâŠ.Excluded
32. Data Collection (1)
âș As per the Regulation and Data Collection Procedure
âș All concerned entities to submit
âș Details of Network Elements
âș Generation and Load at various nodes
âș Yearly Transmission Charges
âș Forecast Injection / Withdrawal
âș Additional Medium Term Withdrawal / Injection
âș By 10th
of every month by every DIC
âș RPC to send list of certified non-ISTS lines to IA
âș IA to send the lists to CERC for approval
âș YTC of Certified non-ISTS lines to be approved from appropriate
commission
33. INFORMATION PROCEDURES
âșData to be submitted by DICs
âșYTC, Basic Network Details of ISTS, Deemed ISTS,
Certified ISTS Lines
âșDemand or Injection Forecast for each season
âșOn or Before the end of fourth week of November
âșData to be submitted by CTU, Owners of Deemed
ISTS and DICs
âșEntire Network Data for first year of
Implementation
âșDates and data of commissioning of any new
transmission asset for subsequent years
34. INFORMATION PROCEDURES
âșInjection and Withdrawal forecast for different
blocks of months (Peak and Other than Peak):
Regulation 16(4)
âș April to JuneâŠâŠâŠâŠâŠâŠâŠâŠâŠâŠâŠ (May 15)
âș July to SeptemberâŠâŠâŠâŠâŠâŠâŠâŠ. (August 31)
âș October to NovemberâŠâŠâŠâŠâŠâŠâŠ (October 30)
âș December to FebruaryâŠâŠâŠâŠâŠâŠ.. (January 15)
âș MarchâŠâŠâŠâŠâŠâŠâŠâŠâŠâŠâŠâŠâŠâŠ (March 15)
âșIn case any of the above fall on a Weekend/Public
Holiday, the data shall be submitted for working
days immediately after the dates indicated.
03/22/15 à€°à€Ÿà€·à„à€Ż à€à€Ÿà€° à€Șà„à€·à€Ł à€à„ à€Š 34
35. 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
36. âș Nodal Generation / Demand Regulation 7(1)(d) / (e)
âș Based on Forecast provided by DICs
âș Forecast should be based on Long Term and Medium Term
Contracts
âș Forecast Generation to be vetted by IA based on Historic
Generation / Demand.
âș Changes in Generation /Demand to be Communicated to DICs
âș In case of conflict validation committee to take final decision
âș IA to perform AC Load flow Regulation 7(1)(h)
âș To obtain LGB & for achieving convergence adjustments may be
required to be made on vetted generation/demand
âș Converged Load Flow results to be verified by Validation
Committee Regulation 7(1)(i)
37. VALIDATION COMMITTEE
âșNominee from Commission to Chair the Committee
Regulation 7(1)(g)
âșValidation Committee Comprises two officials each
from:
âș Implementing Agency
âș National Load Despatch Centre
âș Regional Power Committee
âș Central Transmission Utility
âș Central Electricity Authority
âș Central Electricity Regulatory Commission
03/22/15 à€°à€Ÿà€·à„à€Ż à€à€Ÿà€° à€Șà„à€·à€Ł à€à„ à€Š 37
38. NETWORK TRUNCATION
âșNetwork Truncation by IA Regulation 7(1)(k)
âș Upto 400 kV except NER, where it shall be reduced to 132 kV
Annexure I, Clause 2.3
âșPower inflow from Lower voltage Level : Generation
Node Annexure I, Clause 2.3
âșPower outflow from Lower voltage Level : Demand
Node Annexure I, Clause 2.3
âșAC Load Flow on Truncated Network
Annexure I, Clause 2.3
39. COMPUTATION OF POC CHARGES (1)
âș Average YTC per circuit km(for each voltage level & conductor
configuration) shall be used for computation of charges
Regulation 7(1)(l)
âș e.g. 400 KVD/C twin Moose, 400 kV Quad Moose, 400 kV Quad
Bersimis etc.,
âș YTC of substations to be apportioned in line
Regulation 7(1)(m)
âș 2/3 to higher voltage lines
âș 1/3 to lower voltage lines
âș Apportionment among lines on the basis of length in ckt. kms
âș PoC Charges to be computed for 5 blocks of month for peak
and other the peak conditions
40. COMPUTATION OF POC CHARGES (2)
âș Representative Blocks of Months Regulation 7(1)(o)
âș April to June
âș July to September
âș October to November
âș December to February
âș March
âș Peak Hours : 8hrs Regulation 7(1)(o)
âș Other the Peak Hours :16 Hrs
âș Average YTC to be apportioned to peak and other than peak
based on the no. of hours constituting these periods
Regulation 7(1)(p)
âș 50% recovery through Hybrid Methodology and 50% through
Uniform Charge Sharing Mechanism(for first two years )
Regulation 7(1)(q)
41. COMPUTATION OF POC LOSSES
âșLoss Allocation Factor to be computed for each
season using Hybrid Methodology
Regulation 7(1)(r)
âș50% losses through Hybrid Method and 50% through
Uniform Loss Allocation Mechanism(for first two
years)
Regulation 7(1)
(s)
âșWeighted average of LAF for peak and other than
peak conditions shall be used
Regulation 7(1)
(s)
âșLoss Application as per the Procedure prepared by
NLDC
42. ZONING
âș Criteria for Zoning of nodes: Regulations7(1)(t)
âș Costs within the same range
âș Geographically and electrically proximate
âș Nodes with connectivity to Thermal Generators > 1500 MW or
Hydro Generators > 500 MW to be taken as separate zone.
âș Demand zones : Sate Control Area
âș Except NER states where entire region is to be taken as one
zone.
âș Zonal Charges : Weighted Average of Nodal Charges
Annexure I, Clause 2.2
âș Revision of Zones in a financial year
âș Significant Changes in Power System
âș Prior approval from commission Regulations7(1)(t)(vi)
âș Generating stations connected to ISTS network < 400KV would
be charged at zonal charges where physically located
âș No transmission charges/losses for solar projects (for the entire
useful life) commissioned within next 3 years.
43. SPECIFIC CHARGES
âș Charges thus determined to the extent of approved
injection/withdrawal for each DIC
âș 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
âș 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
44. SPECIFIC CHARGES
âș 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
âș Such additional charges would not be applicable in case::
âș Rescheduling of the planned maintenance program which is
beyond the control of the generator
âș Certified by RPC
âș 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
45. SPECIFIC CHARGES
âșEven if in case of injection / withdrawal < Approved
injection/withdrawal allocated transmission charges
to be fully paid
âșAfter 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
âșHowever, before COD, charges to be borne by
generators
âșThere would be no differentiation between POC
charges/losses for LT/MT/ST customers
46. IMPLEMENTING AGENCY (IA) (Chapter 8)
âșFor First Two Years Regulation 18(1)
âș NLDC shall be Implementing Agency
âșProcedures to be prepared by IA
âș Procedure for Data Collection
âș Procedure for Loss Sharing
âș Procedure for Transmission Charge Computation
âșExpenses of IA to be included in YTC and approved
by Commission Regulation 18(4)
47. TREATMENT OF HVDC Annexure I Clause 2.7
âșZero Marginal Participation for HVDC Line
âș HVDC line flow regulated by power order.
âșMP Method can not recover its cost directly.
âșHVDC line can be modeled as:
âș Load at sending end
âș Generator at receiving end
03/22/15 à€°à€Ÿà€·à„à€Ż à€à€Ÿà€° à€Șà„à€·à€Ł à€à„ à€Š 47
48. Indirect Method for HVDC Cost Allocation
âș Compute Transmission Charges for all load and generators
with all HVDC lines in service.
âș Disconnect HVDC line and again compute new transmission
charges for all loads and generators
âș Compute difference between nodal charges with or without
HVDC.
âș 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)]
âș In case benefit âve same to be collared to zero
âș Allocate HVDC line cost to the identified nodes.
49. Module on
Computation of PoC Transmission
Charges
National Load Despatch Centre
Power System Operation
Corporation
50. Process Chart for Computation of PoC Charges
Data Collection
Basic Network
Preparation
Load Flow Studies
Zoning
Network Reduction
PoC Charges &
Losses Computation
51. Data Collection (2)
âșNLDC to specify :
âș Nodes/group of nodes on which DICs would submit the
forecasted injection/withdrawal.
âșIA to specify :
âș Peak and other than Peak conditions for each representative
blocks for the next application period.
52. Approved Injection/ Withdrawal
âșApproval of Forecasted Injection/Withdrawal on the
basis of
âș Long Term and Existing Medium Term Contracts
âș Database of RLDC/NLDC
âșApproved Demand/Withdrawal to be notified on the
website of IA
âșAdjustments in forecasted Injection/withdrawal to
be intimated to concerned DIC.
53. Computation of AC Load Flows
âșSeprately for NEW and SR Grid
âșAdjustments for converging Load Flow
âș If Load > Generation
âș Pro-rata scaling down of Load
âș If Generation > Load
âș Pro-rata scaling down of Generation
âșValidation committee to validate
âș Converged Load Flow Results
âș Basic Network
âș Nodal Injection / Withdrawal
54. Network Reduction
ïź Reduction upto 400 kV (except NER where the
network will be reduced to 132 kV)
âșInjection from Lower Voltage : Generation
âșDrawal from Lower Voltage : Demand
Software
Reduced Network
Average YTC after
Truing up
PoC
Charges
and LAF
55. Computation of Charges
âș Annual Average YTC to be apportioned to peak and Other
than peak conditions
âșNet PoC Charge = 50% PoC Charge + 50% Uniform Charge
âș UC = Total ARR /(Approved injection +approved
Withdrawal)
âș Calculation of Uniform Charge on All India Basis
âș Scaling on Pro-rata basis to adjust over or under recovery
âș Treatment of Generators connected at 220 kV
âș Charged at PoC Charge of the zone
56. Zoning
âșAs per the regulations
âșFixed for an application period
âșZonal Charges / Zonal LAF
âș Weighted average of all nodes in the zone
âșTreatment of nodes feeding more than one zone
âș To be used in both zones
âș Pro-rata charges in both zones based on ratio of power flow.
57. Information to RPC
âșApproved Withdrawal/Injection (MW) for peak and
other than peak hours for each season
âșZonal Point of Connection Charge (Rs/MW/month)
for Generation and Demand Zones
âșApproved Additional Medium Term Withdrawal /
Injection (MW)
âșDetails of Short Term Open Access
As per format I and II of the Procedure
58. Information on Public Domain
âșApproved Basic Network Data and Assumptions, if
any
âșZonal or nodal transmission charges for the next
financial year differentiated by block of months;
âșZonal or nodal transmission losses data;
âșSchedule 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
59. 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
60. 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
62. INPUTS FOR MONTHLY TRANSMISSION
ACCOUNTS
âș Approved injection / withdrawal from IA
âș Zonal POCs from IA
âș Approved additional MT injection/withdrawal RLDC/NLDC
âș Approved ST injection/withdrawal from RLDC/NLDC
âș SEM data for deviation computations
âș RPCs to issue monthly transmission accounts(1st
working
day of the Month)
âș RPCs to issue monthly transmission deviation acounts(by
15th
of the Month)
âș CTU shall be responsible for raising the transmission bills,
collection and disbursement of transmission charges to
ISTS transmission licensees
âș Expenses incurred by CTU on account of this function shall
be reimbursed as part of YTC
63. Accounting Regulation 10
03/22/15 à€°à€Ÿà€·à„à€Ż à€à€Ÿà€° à€Șà„à€·à€Ł à€à„ à€Š 63
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
64. Billing (1) Regulation 11
âșResponsibility of Central Transmission Utility (CTU)
âș Based on Accounts issued by RPC
âșLong Term Customers shall be billed directly for:
âș Own Transmission Charges
âș Generator Transmission Charges in proportion to MW entitlement
after âCommercial Operationâ
âșGenerators shall be billed only for deviations.
âșBill to be raised only on DICâs
âș SEB/STU may recover such charges from DISCOMs, Generators
and Bulk Consumers.
03/22/15 à€°à€Ÿà€·à„à€Ż à€à€Ÿà€° à€Șà„à€·à€Ł à€à„ à€Š 64
65. Billing (2)
03/22/15 à€°à€Ÿà€·à„à€Ż à€à€Ÿà€° à€Șà„à€·à€Ł à€à„ à€Š 65
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
66. BILL PART-I
âș To be raised by 1st
working day of the month by CTU
âș Independent of Transmission accounts to be issued by RPCs
For Generators
[ (PoC Transmission Charge of generation zone in Rs / MW /
month for peak hours)Ă (Approved Injection for peak hours) ]
+
[ (PoC Transmission Charge of generation zone in Rs / MW /
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) ]
67. BILL PART-II
âș To be simultaneously raised alongwith BILL-PART-I
For Generators
[ (PoC Transmission Charge of generation zone in Rs / MW /
month for peak hours)Ă (Approved Additional MediumTerm
Injection for peak hours) ]
+
[ (PoC Transmission Charge of generation zone in Rs / MW /
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) ]
âș 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.)
68. BILL PART-IV (TREATMENT OF DEVIATIONS)
REGULATION 11(7)
âșDeviation calculations after considering additional
MT & Short Term Open Access for each time block
âșDeviation =
[Average MW injected/withdrawn]
-
[ (Approved injection/withdrawal+Approved additional
MT injection/withdrawal+ST injection/withdrawal) ]
âșCharge to be Calculated on Block wise Deviation
âșDeviations by Generator shall not be charged to
Long Term Customers
âșNo additional Charge for Deviations in case :
âș Rescheduling of Maintenance Schedule for reasons beyond
control of geenrator OR Certified by RPC
69. 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%
70. Treatment of Deviations âDemand 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%
71. BILL PART-IV (TREATMENT OF DEVIATIONS)
REGULATION 11(7)
âș Thus additional charges due to deviations =
1.25 x POC transmission charge for demand / withdrawal x
Deviations
In case a generator withdraws from grid::
âș 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::
âș Additional charges = 1.25 x POC transmission charge for the
generation zone x Average MW injected for the corresponding
blocks
âș Bill for deviations to be raised by CTU within 3 days of issue of
Transmission deviation accounts by RPC.
âș 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.)
72. BILL PART-III
âșThe 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
âșThe bill shall be used to adjust any variations in
interest rates, FERV, rescheduling of commissioning
of transmission assets, etc.
âșRecovery/Reimbursement would be on basis of
under-recovery/over-recovery, in proportion to
average approved injection/withdrawal over previous
six months
âșCTU to transfer the 3rd
part to respective ISTS
licensees for whom the adjustment is required
73. COLLECTION AND DISBURSEMENT
REGULATION 12
âș CTU to collect charges on behalf of ISTS service providers.
âș CTU to disburse in proportion to Monthly Transmission
Charges.
âș Payment and Disbursement shall be executed through
RTGS.
âș Delayed Payments shall result in pro-rata reduction in all
payouts
âș Payment Security as per detailed procedure prepared by
CTU
74. TRANSMISSION SERVICE AGREEMENT(TSA)
REGULATION 13
âș Existing BPTAs realigned ï TSA
âș TSA provides for all relevant matters regarding the POC losses/charges
mechanism(e.g.)::
âș Detailed Commercial/adminsitrative provisions
âș Metering, accouitnitng, billing, charges recovery provisions
âș Procedures for interconnection
âș Treatment in delay of line commissioning
âș Payment security mechanisms
âș default & consequences
âș Termination & Force majeure conditions
âș Draft TSA to be finalized by CTU and approved by CERC
âș Notified TSA would be the default transmission agreement and would
mandatorily apply to all DICs
âș Signing of TSA not a precondition for construction of new network
elements by CTU/licensees after approval by CERC
âș TSA may have certain aspects which could be modified from time to
time without rendering the TSA infructuous e.g. contracted capacity,
etc..
75. TRANSMISSION SERVICE AGREEMENT(TSA)
REGULATION 13
âșCTU to prepare revenue sharing agreement which is
to be approved by CERC for disbursal of monthly
transmission charges to various ISTS licnesees
âșThe 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
âșUsers 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
76. LIST OF PROCEDURES AS A PART
OFTRANSITION REGULATION 15
âș Commission would notify detailed procedures prepared by IA,
NLDC & CTU as a part of transition mechanism
âșProcedure for obtaining data ï IA
âșProcedure for computation of POC charges ï IA
âșProcedure for sharing of losses ï IA
âșProcedures for Billing and collection of charges by the CTU
on behalf of Transmission Licensees and redistribution ï
CTU
âșPayment and payment security related procedures ï CTU
77. Information on Public Domain Regulation 17
âșApproved Basic Network Data and Assumptions, if
any
âșZonal or nodal transmission charges for each block
of month
âșZonal or Nodal Transmission losses data
âșSchedule of Charges payable by each constituent
after undertaking necessary true up costs
âșUnderlying network information & base load flows
79. Introduction
âșHybrid Method : Based on Load Flow (Offline
Studies)
âșAverage participation for slack bus identification
âșMarginal Participation for usage identification
âșRecovery of Charges
âș 50% by Uniform Charge Method
âș 50% by PoC Charge Method
80. Importance of Data in Hybrid Methodology
âșInput to the Offline Line Model for Load Flow Studies
âș Network Parameters
âș Load and Generation Data ( MW & MVAr)
âșResults of offline line studies highly dependent
upon the input to the model
âșInconsistent data may not make solution Converged
âșMay lead to modifications in Approved Demand /
Injection
81. âșPoC Charge Calculation depends upon :
âș Converged and Reduced Network
âș Line wise YTC provided by Transmission Licensees
âșApproved Injection / Withdrawal
âșData to be submitted on or before 4th
Week of
November for next F.Y.
âșThe information may be sought by the IA at times
other than those if necessary
82. 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
83. How to Give Information to IA ?
âșIdentify a person(s) who will coordinate with
Implementing Agency
âșCommunicate the details of Identified Person to the
Designated Officer of IA.
âș Name
âș Designation
âș Company Name
âș Office Address
âș Contact Number : Official (Landline)
Mobile Number
âș Letter of Authorization
84. âșFormats would be available on the website of IA and
all RLDCs after getting permission from the
Commission
âș www.nldc.in
âș www.nldcindia.in
âșSubmission of data shall be only in electronic
spreadsheet formats (MS Excel).
âșFor all communication puposes
âș emailid of IA : implementingagency@powergridindia.com
âșWritten communication confirming submission of
data by e-mail.
85. Network Parameters
âșNetwork Data upto 132 kV except where generators
are connected to Grid at 110KV
âșInjection below 132 kV : Generation
âșWithdrawal below 132 kV : Load
âșAlso include states generation.
86. Type of Data
DICâs
Load &
Generation Data
Network Data
Forecast
Injection /
Withdrawal
YTC of each
ISTS Line
Transmission
Licensees
87. Category of Network Parameters
Network
Parameters
Switched
Shunt Data
Transformer
Data
DC Line
Data
AC Line
Data
Generator
Data
Bus
Data
88. Bus Data
âșBus Type
âșBus Name : Full Name of Substation
âșConductance
âș Real Component of Shunt admittance to ground
âș In MW at one per unit voltage
âș Should not include resistive impedance load
89. âșSusceptance
âș Reactive Component of Shunt admittance to ground
âș In Mvar at one per unit
âș Should not include reactive impedance load , line charging and
line connected shunts
Sign Convention
+ for Capacitor
- for Reactor
âșVoltage in kV
90. Generator Data
âșBus Name
âșGenerator Real Power Ouput
âș Ex Bus Output in MW
âșGenerator Reactive Power Output
âș Ex Bus Output in Mvar
âșMaximum and Minimum Generator Reactive Power
Output
âșIREG
âș Bus Name of remote type 1 bus whose voltage is to be regulated
by this plant
91. âșResistance and Reactance on MVA base
âșMVA Base
âș Total MVA base of the units represented by this machine
âșRT, XT
âș Step up Transformer Impedance in per unit on MVA Base
âșGTAP
âș Step up Transformer off-nominal turns ratio (in pu)
âșMaximum and Minimum Real Power Output
âșRMPCT
âș Percent of total Mvar required to hold the voltage at bus IREG
92. Load Data
âșBus Name
âșReal & Reactive Power Component
âș Constant MVA Load
âș Constant Current Load
âș Constant Admittance Load
93. AC Line Data
âșFrom Bus Name (I)
âșTo Bus Name (J)
âșCircuit Number
âș For D/C line one line will have 1 in this data and 2 for other line
âșBranch Resistance, Reactance and Charging
Susceptance
âș In pu on 100 MVA base
âșRate A
âș Operating limit considering the compensations and length of line
âș Minimum of Thermal, Voltage and Stability limits.
94. âșTransformer off-nominal tap ratio
âșTransformer phase shift angle
âș In degrees
âș Positive from untapped to tapped side and vice versa
âșComplex admittance of the line shunt at bus I (GI+j BI)
âșComplex admittance of the line shunt at bus J
(GJ+j BJ)
âșLine Length
95. DC Line Data (Line quantities and Control)
âșDC Line Number
âșControl Mode
âș 0 â Blocked
âș 1 â Power
âș 2 â Current
âșDC Line resistance in Ohms
âșCurrent or Power Demand
âș If Control mode is 1 then power, if 2 then current.
96. âșScheduled Compounded dc voltage in kV
âșMode Switch dc voltage
âș If inverter voltage falls below this value and control mode is 1
then it changes to 2.
âșCompounding Resistance
âșMetered end code
âș R for rectifier or I for inverter
âșMinimum Compounded dc voltage
97. DC Line Data (Rectifier & Inverter
âșRectifier converter bus name
âșNumber of bridges in series
âșNominal maximum rectifier firing angle
âșMinimum steady state rectifier firing angle
âșRectifier commutating transformer resistance &
reactance per bridge
98. âșRectifier primary base ac voltage
âșRectifier transformer ratio
âșRectifier tap setting
âșMaximum rectifier tap setting
âșMinimum rectifier tap setting
âșRectifier tap step
100. Transformer Data
âșFrom Bus
âșTo Bus
âșCircuit Number
âșResistance and Reactance in per unit
âșPhase shift angle
âșNominal Tap Ratio
101. âșControlled Bus Name
âșMaximum Voltage of Controlled Bus
âșMinimum Voltage of Controlled Bus
âșMax Turns Ratio
âșTurns Ratio Step Increment
102. Switched Shunt Data
âșBus Name
âșControl Mode
âș 0 â Fixed
âș 1 â Discrete
âș 2 â Continuous
âșDesired Voltage Upper & Lower Limit
âșNi : Number of steps for block I
âșBi : Admittance increment for each Ni steps in block
i
103. Forecast Nodal Injection / Withdrawal (1)
âș Two figure for each block of months
âș One for peak and other for offpeak
âș Five Representative Blocks
âș April to JuneâŠâŠâŠâŠâŠâŠâŠâŠâŠâŠâŠ (May 15)
âș July to SeptemberâŠâŠâŠâŠâŠâŠâŠâŠ. (August 31)
âș October to NovemberâŠâŠâŠâŠâŠâŠâŠ (October 30)
âș December to FebruaryâŠâŠâŠâŠâŠâŠ.. (January 15)
âș MarchâŠâŠâŠâŠâŠâŠâŠâŠâŠâŠâŠâŠâŠâŠ (March 15)
âș The data should be of the date mentioned against each block of month.
âș 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.
âș 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
âș Duration of peak hours for each block
âș Specified by NLDC
104. Forecast Nodal Injection / Withdrawal (2)
âșMW & MVAr Injection / Withdrawal at each node
âșForecast of MVAr on the basis of
âș Historic Injection /Withdrawal
âș Anticipated Change in Load pf
âșForecast of MW
âș On the basis of MW entitlements
âșForecast required for 5 blocks of month
âșFor Generators forecast should be equal to the rated
capacity
Forecast = max(G1) + max(G1) +âŠâŠâŠâŠâŠâŠ.
105. Commercial Data
âșLine wise YTC of each ISTS Line
âșBreakup of total YTC among different Voltage
Levels.
âșIn case of YTC not approved by SERC/CERC
âș Benchmark/Reference cost to be used.
âșYTC of substations to be apportioned in line
âș 2/3 to higher voltage lines
âș 1/3 to lower voltage lines
âș Apportionment among lines on the basis of length.
106. Certified Non-ISTS Lines
âșNon-ISTS lines certified by RPC as being used as
ISTS line will be included in the model.
âșTransmission Licensees to get them certified in
RPC.
âșLine wise YTC to be also certified by RPC and
approved by CERC.
âșSuch List to be provided to IA by Transmission
Licensee
âș Latest by Fourth week of November
107. Sharing of Inter-State Transmission
Losses
Based on PoC Losses
National Load Despatch Centre
Power System Operation Corporation
108. Introduction
âșThe procedure aims to keep computation:
âș Simple
âș Non-Recursive
âșLoss Application on Regional Basis
âș In line with existing practice
âș No Pan caking.
âșInjection and withdrawal loss would be calculated
for each zone.
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109. New Methodology
âș Point of Connection Losses
âș Independent of Contract Path
âș50% PoC losses + 50% Uniform Losses
âșUniform Loss component
âș Based on Regional Losses of last week
âșModeration of Losses
âș Based on Actual Regional Losses of last week and Losses
based on studies
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110. PoC Loss Computation (1)
âșComputation of changes in losses in the system due
to incremental injection / withdrawal at each node.
âșLoss Allocation Factor
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111. PoC Loss Computation (2)
âșOutput of System Studies
âș MW Losses of each node
âș Loss Allocation Factor
âș Weighted average losses (%) for each region
âșZonal Loss : Weighted Average of losses at each
node
âșModeration of Zonal Losses
âșOne PoC Loss for each entity per day
âș Weighted average of peak and other than peak
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112. Loss Sharing Mechanism
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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
113. Moderation of Losses (1)
âșNeed of Moderation
âș Difference in actual and study scenarios
âș Correct computation of injection and drawal schedule of various
utilities.
âș Scheduled losses to be closer to actual losses in the system so
that system mismatch is avoided.
âș Minimizing the mismatch between UI payable and receivable
âșModeration at regional Level
âșModeration Factor
= Actual Losses of previous week (Aact) ( In %)
------------------------------------------------------------------
Regional Losses based on Studies (As)(In %)
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114. âșRegional Losses Based on Studies (As)
âș Weighted average losses of a region
where A is Total MW losses of a region
âGNG = Total Injection in a region
âIIR = Inter Regional Exchange
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A*100 / (âGNG ±(âIIR )
115. Application of Losses in Scheduling
âșNet PoC Loss = 50% Moderated PoC Loss + 50%
Uniform Loss
âșNet PoC Loss to be applied on each regional entity
âșDrawee Entity to bear full losses for :
âș Long Term Transactions
âș Medium Term Transactions
âș Bilateral Transactions
âșInjecting Entity and Drawee Entity to share losses
for:03/22/15 à€°à€Ÿà€·à„à€Ż à€à€Ÿà€° à€Șà„à€·à€Ł à€à„ à€Š 115
116. Case I : Intra-Regional Transactions
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A
B
100 MW
92.15 MW
Zone Moderated
Loss (%)
A 3
B 5
117. Case II : Inter Regional Transactions
03/22/15 à€°à€Ÿà€·à„à€Ż à€à€Ÿà€° à€Șà„à€·à€Ł à€à„ à€Š 117
B
A
Zone Moderated
Loss (%)
A 3
B 5
100 MW
97 MW
92.15 MW
118. Case III : Transactions Involving Wheeling
Region
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B
A
100 MW
92.15 MW
97 MW
97 MW