Sharing of Inter State Transmission Charges National Load Despatch Centre Implementing Agency
Feb 12, 2016
Sharing of Inter State Transmission Charges
National Load Despatch Centre
Implementing Agency
Fundamental Principles
• Objectives of Pricing system– Promote the efficient day-to-day operation of the bulk
power market;– Signal locational advantages for investment in
generation and demand;– Signal the need for investment in the transmission
system;– Compensate the owners of existing transmission
assets;– Simple and transparent– Politically implementable
Desirable Features of a Transmission Pricing Scheme
Reasonable revenue to the transmission system owners
Equitable sharing of the above payment between the transmission system users, according to benefits derived
Inducement to transmission system owner to enhance the availability of the system
Ensuring that merit - order dispatch of generating stations does not get distorted due to defective transmission pricing
Desirable Features of a Transmission Pricing Scheme
Ensures that planned development / augmentation of the transmission system, which is otherwise beneficial, does not get inhibited
Appropriate commercial signal for optimal location of new generating stations and loads
Treatment of transmission losses – whether handled separately or as a part of transmission charges
Priority of transmission system usage between users under different categories
Desirable Features of a Transmission Pricing Scheme
Revenue of transmission system owner, in a vertically unbundled scenario, should not depend on dispatch decisions and actual power flows
To the extent possible, the users should know upfront what charges they would have to pay, and retrospective adjustments should be avoided
Dispute-free implementation on a long-term basis
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
Policy Mandate
Electricity Act 2003
National Electricity Policy
Tariff Policy
Policy Mandate– National Electricity Policy
Section 5.3.2“….Prior agreement with the beneficiaries would not be a pre-condition for network expansion…”
Section 5.3.5“……..The tariff mechanism would be sensitive to distance, direction and related to quantum of flow….”
Policy Mandate – Tariff PolicySection 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…..
Historical Background
Development of Transmission System
GENERATION
DISTRIBUTION
TRANSMISSION
GENCO
TRANSCO
DISCO
Unbundling
Scenario in Recent Past
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)
Transmission Assets (T2A 1-n)
ONE REGIONAL GRID
Multiple Utilities With Two Transmission Service Providers
Present Scenario: Increasing Complexities
REGIONAL GRID -1
TSP – 1Transmission Assets (T1A 1-n)
U-2
U-1
U-4
U-3
U-n
TSP – 2Transmission Assets (T2A 1-n)
TSP – mTransmission Assets (TmA 1-n)
TSP – 3Transmission Assets (T3A 1-n)
D-1 D-n
D-1 D-n
D-1 D-n
D-1 D-n
D-1 D-n
REGIONAL GRID -2
TSP – 1Transmission Assets (T1A 1-n)
U-2
U-1
U-4
U-3
U-n
TSP – 2Transmission Assets (T2A 1-n)
TSP – mTransmission Assets (TmA 1-n)
TSP – 3Transmission Assets (T3A 1-n)
D-1 D-n
D-1 D-n
D-1 D-n
D-1 D-n
D-1 D-n
Inter-Regional Interconnections
Future Scenario : More Complexities
REGIONAL GRID -1
TSP – 1Transmission Assets (T1A 1-n)
U-2
U-1
U-4
U-3
U-n
TSP – 2Transmission Assets (T2A 1-n)
TSP – mTransmission Assets (TmA 1-n)
TSP – 3Transmission Assets (T3A 1-n)
D-1 D-n
D-1 D-n
D-1 D-n
D-1 D-n
D-1 D-n
REGIONAL GRID -2
TSP – 1Transmission Assets (T1A 1-n)
U-2
U-1
U-4
U-3
U-n
TSP – 2Transmission Assets (T2A 1-n)
TSP – mTransmission Assets (TmA 1-n)
TSP – 3Transmission Assets (T3A 1-n)
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
Elegant Model
TSP – 1Transmission Assets (T1A 1-n)
TSP – 2Transmission Assets (T2A 1-n)
TSP – mTransmission Assets (TmA 1-n)
TSP – 3Transmission Assets (T3A 1-n)
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
AGENCYFOR
PLANNING
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
Reg
ion
-1
Reg
ion
-2
AGENCYFOR
COMPUTATION OF
TRANMSSIONCHARGES
AGENCYFOR
BILLING&
COLLECTION
Previous MethodRegional Postage Stamp Method in Long Term Market
Contract Path Tariff in Short Term Bilateral Market
Point of Connection Tariff in Power Exchanges
Sharing of Transmission charges - earlier 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 1.4.2008– 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 28.3.2008
• By beneficiary directly served
Illustration of earlier Methodology (1/2)
Gen. A Gen. B Gen. C Gen D
State A 100 100 200 -----
State B 200 50 100 50
State C 50 50 200
State D ----- 100 ----- -----
Region A
Gen D
State D ARR of Region A : 100 Cr
04/22/23 राष्ट्रीय भार पे्रषण कें द्र 18
Illustration of earlier Methodology (2/2)
Uniform Charges : Rs 0.083 Cr / MW
Total ARR ---------------------------------------------------------------------------------------
Demand (State A+ State B+ State C) +Export to Other Region
State Transmission Charge
State A 33 Cr
State B 33 Cr
State C 25 Cr
State D 08 Cr
04/22/23 राष्ट्रीय भार पे्रषण कें द्र 19
Drivers for change in pricing framework
• Pricing inefficiency in the emerging circumstances
• 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
Regulatory Initiatives
• Discussion Paper on Sharing of Charges and losses in Inter-State Transmission System (ISTS) (2007)
• Approach Paper on Formulating Pricing Methodology for Inter-State Transmission in India (May 2009)
• Draft Regulation on Sharing of Inter-State Transmission Charges and Losses (February 2010)
• Regulation on Sharing of Inter-State Transmission Charges and Losses (June 2010)
New Methodology•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.
New Framework
NETWORK
YTC
Injection/Withdrawal
LTA/MTOA
DICs
ISTS Licens
ees
PoC Tariff
(50%UC+50%PoC)
RPCs
(Billing, Collection and Disbursement)
(Accounting)
CTU
CERC Regulations on Sharing of Transmission Charges & Losses
• Notification of Regulations : 15th June 2010
• Applicable to:– Designated ISTS Customers– Inter State Transmission Licensees– NLDC, RLDC, SLDCs, and RPCs
• Regulations to come into force from 1.1.2011 – For a period of 5 years unless reviewed or extended by the
Commission
Hybrid Methodology• Hybrid of
– Average Participation– Marginal Participation
• Average Participation– Used to identify slack (responding) buses for
each node• Marginal Participation
– To compute the participation factor of each node on each line.
Average Participation• Tracing of Power
– Load Tracing– Generator Tracing
Marginal Participation
• Marginal Participation– The charges are based on incremental utilization of
network assessed through load flows.
Introduction to the PoC Charge Computation
• Algorithms/ Processes– AC Load flow and transmission losses– Slack bus determination- Average Participation method– Participation factor of a node- Marginal Participation method– Loss allocation factor of node- Marginal Participation method
• Input – Network data for modeling the power system– Nodal injection / Nodal withdrawal for a scenario– Yearly Transmission Charges to be apportioned
• Output– Point of Connection Charge- Demand Zone/ Generation Zone– Point of Connection Losses- Demand Zone/ Generation Zone
Inputs for PoC Charge Determination
ImplementingAgency
ISTS Licensees
1. Network Parameters2. Yearly Transmission
Charges3. DOCO of New Assets to
Commission
STU RPCs
1. Network Parameters2. DOCO of New Assets to
Commission3. Nodal Injection / Nodal
Withdrawal
1. List of non-ISTS lines which are being used as ISTS
STU/SEBs/CTU
Implementing Agency
Network Parameters Line wise YTC
Designated ISTS Customers
Nodal Demand / Generation
Medium Term Injection / Withdrawal
Approved Injection
Approved Withdrawal
Basic Network
Network Parameters
ForecastInjection / Withdrawal
Flow Chart for Input Data Acquisition
YTC assigned to each line
Slack bus
Point of Connection
Loss
Point of Connection
Transmission Charge
Power System Model
YTC of line + YTC of substation apportioned to
lines of a voltage level
Information flow chart
Average Transmission Charge per ckt kilometer for a voltage
level & conductor configuration
Basic Network data
Nodal Injection & withdrawal
Approved Injection, Approved Drawal,
Transmission losses of truncated network
Load flow on complete network
Algorithm for average
participation
Algorithm for computing marginal
participation
Generation Zone Demand Zone PoC for billing
Generation Zone Demand Zone loss
for scheduling
List of state lines used as ISTS
Timelines for Submission of InformationDetails of data submitted by DICs• Injection and Withdrawal forecast for different blocks of
months (Peak and Other than Peak):– April to June…………………………… (for May 15)– July to September……………………. (for August 31)– October to November………………… (for October 30)– December to February……………….. (for January 15)– March…………………………………… (for March 15)
• In case the dates appearing in brackets fall on a weekend/public holiday, the data shall be submitted for working days immediately after the dates indicated
Determination of PoC Charges (1)• Consultancy Assignment for Software
development– IIT, Mumbai & Power Anser Labs (PAL)
• Web based Software developed for calculation of PoC Charges– WebNetUse
• Software Approved by CERC
Determination of PoC Charges (2)• Compilation & checking of network data• Assumptions for missing data• Formulation of Base case for load flow studies
– Based upon the Network Data submitted by the DICs– All elements up to 132 kV included in the model
• Load Flow Studies on the Full Network• Truncation for the purpose of PoC Charge
Determination– Network truncation at 400 kV – Except NER, where it is done at 132 kV.
Determination of PoC Charges (3)• Inputs to the WebNetUse Software
– Truncated Network Data– YTC Details
• Load Flow Study by WebNetUse• Identification of Slack Bus• Calculation of Marginal Participation Factors for
each line/bus• Calculation of PoC Charges for each Node• Results obtained from WebNetUse
– Node wise PoC Charges• Injection charge• Withdrawal charge
Determination of PoC Charges (4)• Philosophy for identification of coherent
nodes for zoning– State control areas to be separate demand zone
except in the case of North Eastern States, which are considered as a single demand zone.
– State control areas considered as generation zone except NER states which are considered as a single generation zone.
– All ISGS of 1500 MW (thermal) / 500 MW (hydro) considered as separate generation zone.
Determination of PoC Charges (4)• Calculation of Zonal PoC Charges
– Weighted average of nodal PoC Charges– Separate Charge for
• Injection • Withdrawal
• Scaling of Charges– To ensure full recovery
• PoC Charges in Rs. / MW / Month
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
• 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.
Indirect Method for HVDC Cost Allocation
Regional Transmission Accounts
(1st Working Day of Every Month
for the previous Month)
Regional TransmissionDeviation Accounts
(15th Day of Every Month
for the previous Month)
Regional Power
Committee
Accounting of Charges : Monthly accounts in each region shall be prepared by respective RPC Regulation 10(1)
Accounting of Transmission Charges
• Central Transmission Utility (CTU) shall be responsible for – Raising the bills, collection and disbursement to ISTS licensees
based on Accounts issued by RPC
• 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.
• 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
Billing of Transmission Charges
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)
After issuance of RTA
After issuance of RTA
Biannually(1st Day of September and March
18th Day of a
Month
Billing and Collection of Charges by CTU
Generator
Net Injection
Net Drawl
1.25 times PoC Charge
Deviation upto
than 20%
Deviation Greater
than 20%
PoC Charge 1.25 times PoC Charge
Treatment of Deviations : Generator
Demand
Net Drawl
Net Injection
1.25 times PoC Charge
Deviation upto 20%
Deviation Greater
than 20%
PoC Charge 1.25 times PoC Charge
Treatment of Deviations : Generator
Long Term Allocation Matrix
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
Implementation Related Issues• Definition of
– Approved Injection – Approved Withdrawal
• Determination of YTC & Substation Cost Apportionment
• Multiple Scenarios for PoC computation and Basis of furnishing nodal generation and withdrawal data
• Collection and disbursement of STOA Charges– Avoidance of double charging
• Connectivity without Long Term Access• Treatment of HVDC Links
Data Quantum
Generating Stations
Generating Units
Loads Transformers
4830 No.s
557 No.s 1148 No.s
2672 No.s
DC Lines : 7 No.s765 kV : 2 No.s
400 kV : 622 No.s220 kV : 3034 No.s132 kV : 5130 No.s
2031 No.s
Thank You!