1. Sharing of Inter State Transmission Charges and Losses
Implementing Agency
National Load Despatch Centre

2. Contents Fundamental Principles Desirable Transmission Pricing Scheme
History/Evolution of Transmission Pricing in India
Methods of Sharing of Transmission Charges
Postage Stamp Methodology
Drivers for Change
Policy Mandate
PoC Methodology
Sharing Regulations & Amendments
Procedures
Sample Results

3. Distinctive Features of Transmission
Public Service
Sunk Investment
Natural Monopoly
Common Carrier
Vital Infrastructure and Regulated Business
Non-Divisible

4. Desirable Features of a Transmission Pricing Scheme
Promote efficient day-to-day operation of Bulk Power Market
Signal Locational advantages for investment in Generation & Demand
Signal need for Planning and Investment in Transmission System
Compensate Owners of existing Transmission Assets
Provide Incentive to Transmission Owners to enhance Availability
Equitable Sharing among Transmission System Users as per Utilization

5. Desirable Features of a Transmission Pricing Scheme…(2)
Prevent distortion in Merit-Order Dispatch of Generating Stations
Treatment of Transmission Losses
Charges known Upfront, retrospective adjustments to be avoided
Priority of Transmission System Usage among Users of different categories
Simple & Transparent
Politically Implementable

6. Historical Background
Stage I
Cost of Transmission clubbed with Generation Tariff
Implicit
Stage II
Apportioned on the basis of energy drawn
(Usage Based)
Stage III
Apportioned on the basis of MW entitlements
(Access Based)
Stage IV
Hybrid Methodology
(Point of Connection)
Upto 1991
2011 onwards

7. Development of Transmission System
GENERATION
GENCO
Unbundling
TRANSCO
TRANSMISSION
DISCO
DISTRIBUTION

8. Scenario in Recent Past
Multiple Utilities With Two Transmission Service Providers
UTILITY (U-1)
TRANSMISSION
SERVICE
PROVIDER
(TSP – 1)
Transmission Assets (T1A 1-n)
UTILITY (U-2)
UTILITY (U-3)
UTILITY (U-4)
TRANSMISSION
SERVICE
PROVIDER
(TSP – 2)
Transmission Assets (T2A 1-n)
UTILITY (U-n)
ONE REGIONAL GRID

9. Present Scenario: Increasing Complexities
REGIONAL GRID -1
TSP – 1
Transmission Assets (T1A 1-n)
U-2
U-1
U-4
U-3
U-n
TSP – 2
Transmission Assets (T2A 1-n)
TSP – m
Transmission Assets (TmA 1-n)
TSP – 3
Transmission Assets (T3A 1-n)
D-1
D-n
REGIONAL GRID -2
U-1
D-1
D-n
TSP – 1
Transmission Assets (T1A 1-n)
U-2
D-1
D-n
TSP – 2
Transmission Assets (T2A 1-n)
U-3
D-1
D-n
TSP – 3
Transmission Assets (T3A 1-n)
U-4
D-1
D-n
TSP – m
Transmission Assets (TmA 1-n)
U-n
D-1
D-n
Inter-Regional Interconnections

10. Future Scenario : More Complexities
TSPs in One Region Having Customers in Another Region Also
REGIONAL GRID -1
TSP – 1
Transmission Assets (T1A 1-n)
U-2
U-1
U-4
U-3
U-n
TSP – 2
Transmission Assets (T2A 1-n)
TSP – m
Transmission Assets (TmA 1-n)
TSP – 3
Transmission Assets (T3A 1-n)
D-1
D-n
REGIONAL GRID -2
U-1
D-1
D-n
TSP – 1
Transmission Assets (T1A 1-n)
U-2
D-1
D-n
TSP – 2
Transmission Assets (T2A 1-n)
U-3
D-1
D-n
TSP – 3
Transmission Assets (T3A 1-n)
U-4
D-1
D-n
TSP – m
Transmission Assets (TmA 1-n)
U-n
D-1
D-n
Inter-Regional Interconnections

11. Elegant Model TSP – 1 Transmission Assets (T1A 1-n) Region -1 TSP – 2
AGENCY
FOR
PLANNING
U-2
U-1
U-4
U-3
U-n
D-1
D-n
TSP – 1
Transmission Assets (T1A 1-n)
Region -1
TSP – 2
Transmission Assets (T2A 1-n)
AGENCY
FOR
COMPUTATION OF
TRANMSSION
CHARGES
TSP – 3
Transmission Assets (T3A 1-n)
U-2
U-1
U-4
U-3
U-n
D-1
D-n
AGENCY
FOR
BILLING
&
COLLECTION
Region -2
TSP – m
Transmission Assets (TmA 1-n)

12. Methods for Sharing of Transmission Charges
Postage Stamp Method
Contract Path Method
MW Mile Method
Distance Based
Power Flow Based
Average Participation
Marginal Participation Method
Zone to Zone Method
Locational Marginal Pricing

13. Sharing of Transmission charges - Postage Stamp Methodology
Regulation 33 of Terms and Conditions of Tariff
Regional postage stamp
Shared by beneficiaries in the same region as well as other regions
Generating companies – if beneficiary not identified
Medium term users
Pooling of all ISTS assets as on
Charges of new ATS
By respective beneficiaries if pooling not agreed
Part pooling / part by respective beneficiaries
Treatment of inter-regional link charges
Step down transformers and down-stream system after
By beneficiary directly served

14. Pre-PoC Scenario Regional Postage Stamp Method in Long Term Market
Contract Path Tariff in Short Term Bilateral Market
Point of Connection Tariff in Power Exchanges

15. Drivers for change in Pricing Framework
Synchronous integration of Regions- Meshed Grid
Increasing complexities in Transmission
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

16. Other Complexities Consensus in building transmission system
Creation of Sub-Pools (35 Sub Pools at present)
Non Scientific
Dispute Prone
60000 MW Generation coming in Pvt. Sector
Transmission Charge Sharing
High Capacity Corridors?
Biswanath Chariali – Agra HVDC Link ?
Benefits gained by Eastern Region as well
Addition of Inter Regional Capacity
60000 MW in 12th Plan
Future Share Allocations of generating stations?

17. Pools and Sub Pools Generator-I WR Pool Generator-III Load-I Load-II
IPP
Pool
WR States Pool
Load-I
Load-II
Generator-II
IPP Pool
UMPP Pool
WR States
NR States
Inappropriate Transmission Charge and Loss Sharing Mechanism leads to Sub-optimal Transmission Planning

18. Pancaking in Long Term Transactions (Without Sub Pool)
Generation Located in ER
Drawee Entity in NR
ER-NR Boundary
Sharing of Charges of Eastern Region Transmission System by other regions
Cross Subsidization

19. Pancaking in Long Term Transactions (With Sub Pool)
Mundra UMPP
Haryana
WR-NR Boundary
Sub Pool Boundary
Maharashtra
Transmission Charges:
Maharashtra : Sub pool Rate + WR Rate
Haryana : Sub pool Rate + WR Rate+ NR Rate

20. Pancaking in Short Term Transactions
Generation Located in NER
Drawee Entity in NR
NER-ER Boundary
ER-NR Boundary
8 p/unit
Transmission Rate : 24 p/unit

21. Pancaking in Losses Generation Located in NER Drawee Entity in NR
NER-ER Boundary
ER-NR Boundary 3%
4 % 5%
100 MW
97 MW
93.12 MW
88.46 MW

22. Policy Mandate Electricity Act 2003 Tariff Policy
National Electricity Policy
Tariff Policy

23. Policy Mandate – National Electricity Policy
Section “….Prior agreement with the beneficiaries would not be a pre-condition for network expansion…” Section “……..The tariff mechanism would be sensitive to distance, direction and related to quantum of flow….”

24. Policy Mandate – Tariff Policy
Section 7.1 : Transmission Pricing
Section 7.1.1
“The National Electricity Policy mandates that the national tariff framework implemented should be sensitive to distance, direction and related to quantum of power flow……”
Section 7.1.2
“Transmission charges, under this framework, can be determined on MW per circuit kilometer basis, zonal postage stamp basis, or some other pragmatic variant, the ultimate objective being to get the transmission system users to share the total transmission cost in proportion to their respective utilization of the transmission system……”
Contd…..

25. Regulatory Initiatives
Discussion Paper on Sharing of Charges and losses in Inter-State Transmission System (ISTS)
May Approach Paper on Formulating Pricing Methodology for Inter-State Transmission in India
Feb Draft Regulation on Sharing of Inter-State Transmission Charges and Losses
Jun Regulation on Sharing of Inter-State Transmission Charges and Losses

26. PoC Methodology in India
Point of Connection (PoC) Charges
Usage Based Methodology
Handling Transition
In Rs. per MW per month
Nodal / Zonal Charges
Separate Injection & Withdrawal Charges
To be made known upfront
To be applied on Medium Term and Short Term Trades
Based on Load Flow Studies
Hybrid of Average Participation and
Marginal Participation methods
To begin with 50% Uniform Charges and 50% PoC Charges
Gradual movement towards 100% PoC Charges
Three Slab Rates for initial years.

27. (Billing, Collection and Disbursement)
PoC Framework
IMPLEMENTING AGENCY
CTU
NETWORK
ISTS Licensees
(Billing, Collection and Disbursement)
YTC
PoC Tariff
(50%UC+50%PoC)
Injection/
Withdrawal
DICs
RPCs
LTA/MTOA
(Accounting)

28. Advantages of PoC Mechanism
National Integration
Fulfills Policy Mandate
Scientific and elegant way of handling complexities
Accommodates Multiple Transmission Licensee Regime
Necessary for large capacity corridors
Certainty in Transmission Rates
Market Friendly
Facilitates Competitive Bidding
No Pan caking of charges and losses

29. Distance Sensitivity Flow of electricity
Based on Laws of Physics
Independent of Contract Path
Electrical Distance is captured in PoC Mechanism
Conductor Impedance
Charges of Transmission Lines

30. Contract Path Farakka State Contract (%) Beneficaries Bihar 28.74
Jharkhand
9.82
Orissa
13.63
West Bengal
30.54
Sikkim
1.63
Andhra Pradesh
1.31
Tamilnadu
1.84
Kerala
0.79 UP
2.08
Haryana
0.69
Rajasthan
J&K
0.85
Delhi
1.39
Punjab
Assam
2.68
Meghalaya
0.65
Nagaland
0.70
Arunachal
0.36
Mizoram
0.21
Contract Path
Farakka
Beneficaries

31. Electrical Path Farakka Drawee Entities
State
Actual Consumption*
Bihar
32.40% UP
26.84%
West Bengal
11.15%
Orissa
8.91%
Haryana
8.34%
Uttrakhand
3.62%
Delhi
3.12%
Punjab
3.05%
Rajasthan
2.43%
Jharkhand
0.14%
Drawee Entities
* Based on the PoC Results for

32. Mapping from Financial Sector
Cournot’s Behaviour Fungible Commodity
Money may be deposited at any location
Withdrawal from nearest source of money
Similarly, contract may be with any generator, power flow by displacement

33. Direction Sensitivity
Chhattisgarh
Injection PoC Rate
(Rs per MW)
Withdrawal PoC Rate
(Rs per MW)
Separate PoC Rates for Withdrawal and Injection
Generation Hub
High Injection PoC Rate
Demand Met from Local Generation
Low Withdrawal PoC Rate

34. Mapping from Financial Sector
Deposit
Withdrawal
No Mutual adjustment even if the withdrawal and deposit quantum is same
Separate transaction charges for both

35. Quantum Sensitivity Access vs Usage Planning based on Access
Usage reflected in PoC Rates
Access is reflected in charges payable

36. CERC (Sharing of Transmission Charges & Losses) Regulations 2010
Notification of Regulations : 15th June 2010
Notification of First Amendment: 24th November 2011
Notification of Second Amendment: 28th March 2012
Applicable to:
Designated ISTS Customers
Inter State Transmission Licensees
NLDC, RLDC, SLDCs, and RPCs
Regulations came into force from 1st July 2011
For a period of 5 years unless reviewed or extended by the Commission

37. Data Collection and Load Flow Studies
Data Collection Regulation 7(1)(a)
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
IA to perform AC Load flow Regulation 7(1)(h)
Converged Load Flow results to be verified by Validation Committee Regulation 7(1)(i)
Single Scenario for year or further period as per Commission
Based on Average Energy Generation & Demand data published by CEA
Regulation 7(1)(o)
Load Flow Studies to be carried out by IA as & when YTC revised
YTC to be revised on a Six monthly Basis in First Full year and subsequently on Quarterly Basis

38. Flow Chart for Data Acquisition
STU/SEBs/ISTS Licensees
Designated ISTS Customers
Line wise YTC
Nodal Demand / Generation
Additional Medium Term Injection / Withdrawal
Network Parameters
Forecast
Injection / Withdrawal
Network Parameters
Implementing Agency
Approved Injection
Approved Withdrawal
Basic Network
Flow Chart for Data Acquisition

39. Validation Committee To validate Basic Network and Load Flow Results
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
Nominee from Commission to Chair the Committee

40. Annexure, Clause 2.3 Network Truncation
Upto 400 kV except NER, where it shall be reduced to 132 kV
Annexure, Clause 2.3
Power inflow from Lower voltage Level : Generation Node Annexure, Clause 2.3
Power outflow from Lower voltage Level : Demand Node Annexure, Clause 2.3
AC Load Flow on Truncated Network

41. Computation of PoC Charges and Losses
Yearly Transmission Charges for assets for each Voltage Level and Conductor configuration to be provided by respective ISTS Transmission Licensees
Total YTC to be apportioned for each Voltage Level & Conductor Configuration based on Ratio of Indicative Cost Levels furnished by CTU
Inputs for Computation of PoC Charges and Losses (Hybrid Method)
Truncated Network
Linewise Average Transmission Charges

42. Average Participation
Tracing of Power
Load Tracing
Generator Tracing
Average Participation is used for identification of slack buses of each load and generation bus

43. Marginal Participation
The charges are based on incremental utilization of network assessed through load flows
Marginal Participation is used for identification of usage of transmission system by each agent in the network based on the slack buses identified through average participation

44. Information flow chart
Approved Injection, Approved Drawal, Transmission losses of truncated network
Basic Network data
Load flow on complete network
Power System Model
Nodal Injection & withdrawal
Average Transmission Charge per ckt kilometer for a voltage level & conductor configuration
Total YTC, Circuit kms and Indicative Cost Level
Algorithm for average participation
Generation Zone Demand Zone PoC loss slab for scheduling
Point of Connection Loss
YTC assigned to each line
Slack bus
Algorithm for computing marginal participation
Point of Connection Transmission Charge
Generation Zone Demand Zone PoC Slab for billing
List of state lines used as ISTS

45. Zero Marginal Participation for HVDC Line
Treatment of HVDC
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

46. 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
Allocate HVDC line cost to the identified nodes

47. Zoning Annexure, Clause 2.2
Criteria for Zoning of nodes: Regulations7(1)(t)
Zones shall contain relevant nodes with Costs in the same range
Nodes within zones shall be combined in a manner that they are Geographically & electrically proximate; Demand zones within Geographical boundary of State
ISGS connected to 400kV Inter State Transmission System to be taken as separate zone
For Merchant Power Plant connected to 400kV ISTS, entire merchant Capacity + LTA to be considered for computing Injection PoC Rate
Demand zones : State Control Area
Zonal Charges : Weighted Average of Nodal Charges
Annexure, Clause 2.2
Revision of Zones in a financial year
Significant Changes in Power System
Prior approval from commission by IA
Regulations7(1)(t)(vi)

48. Slabs for PoC Charges and PoC Losses
50% recovery of transmission charges through Hybrid Methodology and 50% through Uniform Charge Sharing Mechanism
Regulation 7(1)(q)
Three Slab Rates for Injection & Demand PoC Charges for year upto ; to be rationalized in by Commission
Regulation 7(1)(l)
50% losses through Hybrid Method and 50% through Uniform Loss Allocation Mechanism
Regulation 7(1)(s)
Slabs for Transmission Losses in % for year or for period as per Commission Order

49. Regional Power Committee
Accounting Billing and Collection of Charges
Accounting of Charges : Monthly accounts in each region shall be prepared by respective RPC Regulation 10(1)
Regional Power Committee
Regional Transmission Accounts
(Next Working Day
of Issue of Regional Energy Account
for the previous Month)
Regional Transmission
Deviation Accounts
(15th Day
of Every Month

50. Accounting Billing and Collection of Charges
Central Transmission Utility (CTU) shall be responsible for
Raising the bills, collection and disbursement to ISTS licensees based on Accounts issued by RPC
Regulation 11(1)
Bill to be raised only on DIC’s
SEB/STU may recover such charges from DISCOMs, Generators and Bulk Consumers connected to the intra-state system.
Regulation 11(2)
The billing from CTU for ISTS charges for all DICs shall be :
In 3 parts on the basis of Rs/MW/Month and;
the fourth part for deviations would be on the basis of Rs/MW/Block
Regulation 11(3)(7)

51. Accounting Billing and Collection of Charges
Central Transmission Utility
Next Working Day of uploading of RTA for previous month
First Part
(Based on Approved Injection/Withdrawal and PoC Rate)
Second Part
(Recovery of Charges for Additional Medium Term Open Access)
Along with First Part
Biannually
(1st Day of September and March
Third Part
(Adjustments Based on
FERV,Interest, Rescheduling of Commissioning)
18th Day of a Month
Fourth Part
(Deviations)

52. Accounting Billing and Collection of Charges
Treatment of Deviations Regulation 11(7)
Deviation Calculation shall be carried out after considering Short Term Open Access
Charge to be Calculated on Block wise Deviation
Deviations by Generator shall not be charged to Long Term Customers
Deviation = Metered MW – (Approved Injection/Withdrawal)+ (Approved Additional Injection/Withdrawal)+ Approved Short Term Open Access

53. Accounting Billing and Collection of Charges
Generator
Treatment of Deviations
Net Injection
Net Drawl
Deviation upto than 20%
Deviation Greater than 20%
PoC Charge
1.25 times PoC Charge
1.25 times PoC Charge

54. Accounting Billing and Collection of Charges
Demand
Treatment of Deviations
Net Drawl
Net Injection
Deviation upto than 20%
Deviation Greater than 20%
1.25 times PoC Charge
PoC Charge
1.25 times PoC Charge

55. Accounting Billing and Collection of Charges
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

56. Commercial Agreements
Transmission Service Agreement :
Governs the provision of transmission services and charging for the same.
Regulation 13(1)
CTU shall publish the draft Model Transmission Service Agreement on its website and invite public comments on the same.
Regulation 13(2)
Signing of the Transmission Service agreement shall not be a pre-condition for construction of new network elements by the CTU and Transmission Licensees.
Regulation 13(7)

57. Commercial Agreements
Revenue Sharing Agreement
Regulation 13(9)
CTU shall enter into a separate RSA with other ISTS Transmission Licensees for disbursing monthly transmission charges among various transmission licensees.
Amendments of Contracts
Regulation 14
Realignment of all existing contracts within 60 days of notification of TSA

58. Information Procedures
Information by DICs and other constituents
Regulation 16(1)
Data to be submitted by DICs
YTC, Basic Network Details of ISTS, Deemed ISTS, Certified ISTS Lines
Demand or Injection Forecast for each season
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

59. Information Procedures
Information on Public Domain by IA
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

60. Implementation Arrangements
Implementing Agency : NLDC
Procedures to be prepared by IA
Procedure for Data Collection
Procedure for Loss Sharing
Procedure for Transmission Charge Computation
Regulation 18(2)(3)
Procedures to be Prepared by CTU
Billing, Collection and Disbursement Procedure
Expenses of IA to be included in YTC and approved by Commission Regulation 18(4)

61. Important Amendments
“Contract” replaced with “Access” in the definition of Approved Injection
“Transaction” word replaced with “ Access” in the definition of Approved Withdrawal
Exclusion of Overload capability from Approved Injection and Approved Withdrawal
YTC to be revised on six monthly basis i.e., on 1st April and 1st October in first year
Subsequently, revision on Quarterly basis i.e., 1st April, 1st July, 1st October and 1st December
Single Scenario based on average generation and demand data published by the Central Electricity Authority to be considered.

62. Important Amendments
Total YTC to be apportioned for each Voltage level and conductor configuration based on Ratio of Indicative cost levels furnished by CTU in the beginning of application period and approved by Commission.
Charges for LTA to target region without identified beneficiaries
Injection PoC and lowest of Demand PoC among all DICs in target region
Revenue collected against Bill for deviation from DICs in a synchronous grid to be reimbursed to DICs in same synchronously connected grid having LTA in following month

63. Important Amendments
Injection PoC and Demand PoC charges for STOA to target region to be adjusted against Injection PoC and Demand PoC Charges for LTA to target region without identified beneficiaries and not against LTA granted to any other target region without identified beneficiaries.
The charges of the HVDC back to back inter-regional links at Chandrapur and Gazuwaka shall be included in the YTC of the NEW grid and the SR grid in the ratio of 1:1 and charges for Talcher–Kolar HVDC bi-pole link shall be shared by DICs of SR only.”
Each state of NER as separate zone

64. Important Amendments Proviso for Slabs of PoC Rates and PoC Losses
Load flow studies for PoC Computation to commensurate with the periodicity of revision of YTC
Talcher – Kolar HVDC :
Entire YTC to be borne by SR DICs through Scaling Up
200 MW share of Odisha from Talcher – II
Charge at PoC Injection Rate of Talcher– I Station
Recognition of HVDC as National Assets
After synchronization of NEW & SR Grid, Cost of all HVDC systems to be borne by all DICs through Scaling Up.

65. Sample Results

66. Handling Bulk Data Buses 5227 Generating Stations 657 Generating Units
5227
Generating Stations
657
Generating Units
1257
Loads
3128
Branches
DC Lines 7
765 kV 10
400 kV
853
220 kV
3190
132 kV
5288
Total
9348
Transformers
2262

68. Long Term Allocation Matrix
Allocation Matrix ( all figures in MW)
North
East
West
South
North East
CHANDIGARH
DTL
HVPNL
HPSEB
PDD,J&K
PSEB
RRVPNL
UPPCL
UPCL
Railways
HVDC Rihand
HVDC Dadri
To North From
PUSAULI
BIHAR
JHARKHAND
DVC
ORISSA
WEST BENGAL
SIKKIM
To East From
GUVNL
MPPTCL
CSEB
MSEDCL
GOA
D&D
DNH
BHADRAWATI HVDC
VINDHYACHAL HVDC
MPAKVNL, Indore
Heavy Water Plant of DAE
To West From
APTRANSCO
KPTCL
KSEB
TNEB
PUDUCHERRY
NLC Mines
HVDC Gazuwaka
HVDC Talcher
HVDC Kolar
To South From
Arunachal Pradesh
Assam
Manipur
Meghalaya
Mizoram
Nagaland
Tripura
To North East From
Total LTA/ Allocation
180
3533
1459
706
1344
2410
1653
4583
633
100 1
16603
1667
499
161
1025
1195
145
4692
2358
2375
514
3252
308
213
544 2 12 17
9596
1738
1376
937
2331
339 90 93
6910
123
718
116
189 64 94 97
1402
SINGRAULI STPS
1845 16
156
228 22
247
277
796
102
14973
RIHAND I STPS
940 18
103 83 33 77
135 89
357 44
RIHAND0II STPS
127 76 31
128
330 39
UNCHAHAR I TPS
384 3 23 13 6 14 37
235 34
UNCHAHAR II TPS 47 30 11 32 68 35
139
UNCHAHAR III TPS
192 28 15 7 21
DADRI NCTPS I
764
688
DADRI NCTPS II
916
825 92
DADRI NCGPS
805 8 49 24 59
141 75
259
ANTA GPS
475 10 54 72
129
AURAIYA GPS
646 9 74 48 96
231
NAPS
387 45 58
142
RAPP B 42 88
143 71
RAPP C 53 41
SALAL
683
208 82
318
CHAMERA I HPS
535 62 80 5
184
CHAMERA II HPS
297
108
TANAKPUR HPS 38
BAIRASIUL HPS
178 25 40 19
URI HPS 61 36 85 55
DHAULIGANGA 56
NATHPA JHAKRI
1485 26
215
233
115
209
144
404
DULHASTI
386 52 98 65
TEHRI STAGE I
990 81
202
107
SEWA II HEP
119 4
From North to
3036
1334
684
1194
2178
1493
4168
607
Farakka
1489
106
1630
437
146
203
455
1265
4505
557 63
134
200
Kahalgaon I 46 70
237
309
474
Kahalgaon II
1403
147 78
112
787 29
150
132 69
138
372
Talcher
935
374 86
867
Rangeet
Teesta
504
104
121 66
Mejia DVC
366 27
137
183
DVC to Delhi
230
Hirakud GRIDCO
TALA
891
227
341
757
Chukha
333 99 51
Kurichhu 50
From East to
7025
497
124
151
160
415
838
252
125
KORBA STPS
1949
451
195
650
196
9039
VINDHYACHAL STPS I
1147
214
402
434
VINDHYACHAL STPS II
298
349
VINDHYACHAL STPS III
253
293 43
KAWAS
643 79
GANDHAR
644
232 57
SIPAT
148
KAKRAPAR APS
405
TARAPUR APS 1&2
294
TARAPUR APS 3&4
983
254
210
412
SSP
Pench
NSPCL Bhilai
170
From West to
2226
2122
484
3114
211
541
NTPC,RAMAGUNDAM I &II
187
652
371
511
6776
NTPC,RAMAGUNDAM III
468
164
NTPC ,TALCHER II
1870
394
346
393
1683
NEYVELLI LC TPS II0I
567
109
172
NEYVELLI LC TPS II0II
756
190
157
257
NEYVELLI LC TPS I EXP
380
101
NPC,MAPS
396
299
NPC ,KGS UNITS 1&2
122
NPC ,KGS UNITS 3
198 67
From South to
6963
2206
AGBPP, NEEPCO
282
159 20
1202
AGTPP, NEEPCO
Doyang, NEEPCO
Kopili, NEEPCO
Kopili 2, NEEPCO
Khandong, NEEPCO
Ranganadi, NEEPCO
401
174
Loktak, NHPC
From North East to
575
153

69. Sample Results- Slab PoC Rate (Rs/MW/Month)
Generation PoC
Demand PoC

70. Approved Slab Rates for NEW Grid
100000
110000
109968
85000
95000
94968
70000
80000
79968
July 11 – March 12
April 12 – Sep 12
Oct 12 – Apr13
All Figs in Rs/MW/Month

71. Approved Slab Rates for SR Grid
110000
89520
100000
95000
85000
74520
80000
59520
70000
July 11 – March 12
April 12 – Sep 12
Oct 12 – Apr13
All Figs in Rs/MW/Month

72. Slab rates for PoC Losses
Average Los + 0.3%
Average Loss
Average Loss - 0.3%

73. Thank You!

74. Sharing of Inter-State Transmission Losses

75. Introduction
Losses are physical phenomenon while transportation of electric energy from generation to load
Fixed losses
core or iron losses in transformers,
losses in shunt devices such as shunt reactors, shunt capacitors etc
SVC, part of losses in HVDC terminals and other FACTS devices
Generally depend on system voltage and thus constant.
Variable losses (I2R)
Copper losses in transformers, transmission lines
Depend on load current
Load current varies with quantum of load and thus variable
Resistance of lines and thus on line lengths
In transmission system variable losses >> fixed losses
Thus generally losses proportional to load and distance of transportation

76. Introduction Development of ISTS system Treatment of losses
: State systems connected with few inter-state lines,
: Development of Central Generators and their associated transmission system.
1991: POWER GRID came in existence and transfer of associated system to new company
Post 2k/2003: ISTS licensees
Treatment of losses
Individual line losses
Associated Transmission losses with individual generator
Pooled losses

77. Introduction Sharing of Transmission losses
: Based on drawal on individual lines on some mutual/collective understanding
: based on drawal or actual energy allocation from concerned generator.
1990: Regional Pooled losses with some exceptions in proportion to the energy drawal.
Post ABT: Estimated Regional Pooled losses in proportions to schedules from Grid.
In all above drawee utilities used to bear the losses
Inter-regional Transactions:
Regional (whether pooled or otherwise) losses and inter-regional link losses.
Inter-regional link losses merged with regional pool
Thus regional postage stamp for losses.

78. Introduction Other changes Sharing of losses for some state networks
In schedules….. SR
In actuals… NR
Operation of ‘POWER EXCHANGES’ in 2008
Based on point of connection (connection to which region)
Injector /drawee both have to bear losses
Wheeling region losses only if studies prove it.

79. New Regulation for sharing of losses
CERC Regulation on sharing of ISTS charges and losses
Regulation notified in in June 2010
NLDC has prepared procedure in compliance with Regulation 6(1)
Formation of Implementation committee and various meetings of Implementation committee
Validation Committee
Final approval of the commission for implementation
Implemented w.e.f 1st July 2011

80. International Practices Prevalent
Losses settlement
Paid
In kind
In Money
Settled
For each balancing period
on daily, weekly or yearly
Paid by
Only drawee
Both injector and drawee
In some adhoc ratio 50:50 or 45:55
Loss allocation factors may have two component
Fixed and variable(based on location, season, time of the day)
Paid based
on after the fact
on figures declared upfront

81. Issues in Recovery of Transmission Losses
System Operation Requirement
Losses are physical in nature and thus to be supplied in real time
Loss compensation shall be as actual losses in real time so that proper load generation balance is maintained.
Market Operation Requirement
Losses to be known in advance (as long as possible)
to plan for future scenario
to make bid/price strategy
Calculation of individual payout is easy.
Whole process is transparent
Allocation is fair
Overall requirement
Administration of losses is easy

82. Loss sharing Methods…explained in literature
Loss allocation is a complex issue.
To date no single loss allocation method has been universally accepted
Various commonly followed methods are  
Pro rata allocation
Proportional sharing
Marginal / Incremental loss allocation
Loss allocation methods using the admittance matrix
Each of the above mentioned method has its own advantages and limitations.

83. Procedure for sharing of losses based on June 2010 regulation of CERC
Procedure for Sharing of ISTS Losses
Prepared by NLDC in compliance with Regulation 6(1)
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 calculated for each zone.

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

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

86. PoC Loss Computation (2)
Output of System Studies
Loss Allocation Factor
MW Losses of each node
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 week

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

88. 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 %)

89. Regional Losses Based on Studies (As)
Weighted average Actual losses of a region
Actual Transmission losses (in MWh) in Regional ISTS, L = ∑Injection of Regional Entities G + ∑Interregional injection I) - (∑Regional Entity drawals +∑Inter- regional drawals)
Actual Percentage Regional losses, l = L*100/ (G+I)
This would be computed for each 15 min time block and then averaged for each week.

90. Application of Losses in Scheduling
Net PoC Loss = 50% Moderated PoC Loss + 50% Uniform Loss for last 1 year
Provision of 3 slabs : each injection / withdrawal zone to be placed in low / average / high slab
50% of previous week loss – average slab
Low slab 0.3% less, high slab 0.3% higher
Loss to be applied on each regional entity
Drawee Entity to bear full losses for :
Long Term Transactions
Injecting Entity and Drawee Entity to share losses for:
Short Term Transaction
Collective Transactions
Bilateral Transactions

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

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

93. Case III : Long Term Transactions Involving Wheeling Region
Zone
Moderated Loss (%) A 3 B 5 B
92.15 MW
97 MW A
97 MW
100 MW

94. Case IV : Intra-Regional Short Term Transactions
Zone
Moderated Loss (%) A 3 B 5
100 MW Contract B A
95 MW MW

95. Case V : Inter Regional Short Term Transactions
100 MW Contract
Zone
Moderated Loss (%) A 3 B 5 B
95 MW A
100 MW MW

96. Case VI : Short Term Transactions Involving Wheeling Region
100 MW Contract B
95 MW
100 MW A
100 MW MW

97. Thank You!