trans pricing npti 090811
TRANSCRIPT
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Sharing of Inter StateTransmission Charges
Eastern Regional Load Despatch Centre
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Contents
Historical Background
Overview of proposed framework
Important decisions of Implementation
Committee Important decisions of Validation Committee
Orders on removal of difficulties Progress of Implementation
Results of Computation of PoC Charges and
Losses for 2011-12
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Fundamental Principles
Objectives of Pricing system
Promote the efficient day-to-day operation of the bulkpower market;
Signal locational advantages for investment in
generation and demand; Signal the need for investment in the transmission
system;
Compensate the owners of existing transmissionassets;
Simple and transparent
Politically implementable
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Desirable Features of a
Transmission Pricing SchemeReasonable revenue to the transmission system
owners
Equitable sharing of the above payment between thetransmission 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 defectivetransmission pricing
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Desirable Features of a
Transmission Pricing Scheme
Ensures that planned development / augmentation ofthe transmission system, which is otherwisebeneficial, does not get inhibited
Appropriate commercial signal for optimal location ofnew generating stations and loads
Treatment of transmission losses whether handledseparately or as a part of transmission charges
Priority of transmission system usage between usersunder different categories
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Desirable Features of a
Transmission Pricing Scheme
Revenue of transmission system owner, in a vertically
unbundled scenario, should not depend on dispatchdecisions and actual power flows
To the extent possible, the users should know upfrontwhat charges they would have to pay, andretrospective adjustments should be avoided
Dispute-free implementation on a long-term basis
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Policy Mandate
Electricity Act 2003Electricity Act 2003
National Electricity PolicyNational Electricity Policy
Tariff PolicyTariff Policy
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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.
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Policy Mandate Tariff PolicySection 7.1 : Transmission Pricing
Section 7.1.1
The National Electricity Policy mandates that the national tariffframework implemented should be sensitive to distance, direction
and related to quantum of power flow
Section 7.1.2Transmission 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 inproportion to their respective utilization of the transmission
system
Contd..
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Historical Background
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Development of Transmission System
GENERATION
DISTRIBUTION
TRANSMISSION
GENCO
TRANSCO
DISCO
Unbundling
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Scenario in Recent Past
TRANSMISSION
SERVICEPROVIDER(TSP 1)
Transmission Assets (T1A 1-n)
UTILITY (U-2)
UTILITY (U-1)
UTILITY (U-4)
UTILITY (U-3)
UTILITY (U-n)
TRANSMISSIONSERVICE
PROVIDER(TSP 2)
Transmission Assets (T2A 1-n)
ONE REGIONAL GRID
Multiple Utilities With Two Transmission Service Providers
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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
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Elegant Model
TSP 1
Transmission 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
Region
-1
Region-2
AGENCYFOR
COMPUTATION
OFTRANMSSION
CHARGES
AGENCYFOR
BILLING&
COLLECTION
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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
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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
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Regulatory Initiatives
Discussion Paper on Sharing of Charges and losses inInter-State Transmission System (ISTS) (2007)
Approach Paper on Formulating Pricing Methodology forInter-State Transmission in India (May 2009)
Draft Regulation on Sharing of Inter-State TransmissionCharges and Losses (February 2010)
Regulation on Sharing of Inter-State TransmissionCharges and Losses (June 2010)
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New Methodology
In Rs. per MW per monthNodal / Zonal ChargesSeparate Injection & Withdrawal Charges
To be made known upfrontTo be applied on Medium Term and ShortTerm Trades
Based on Load Flow StudiesHybrid of Average Participation andMarginal Participation methods
To begin with 50% Uniform Charges and50% PoC ChargesGradual movement towards 100% PoCCharges
Three Slab Rates for initial years.
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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
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What is Power Tracing?:
DefinitionPower Tracing is a tool, applied Post-facto power flow snap-shot
that provides complete power audit information like:
Share of loads in Generation
Generators contribution in Loads
Loss allocation to generators and Loads
Decomposition of Transmission line flows into Generator and Load Components
on
Wh i i f P
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What are pre-requisites of Power
Tracing?
Power Flows over lines and,
Injections at generator and load busesand,
Network topology (single line diagram)
State Estimation Solution
Or
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Power Tracing: Two VersionsDownstream Algorithm
Upstream Algorithm
Generator SideStatements
Load Side
Statements
Each Generators contribution in Transmission Line flows
Each Generators contribution in Transmission Line losses
Net power sent to a particular load
Each Loads contribution in Transmission Line flows
Each Loads contribution in Transmission Line losses
Power received from a particular generator includinglosses
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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
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STU/SEBs/CTU
Implementing
Agency
NetworkParameters Line wise YTC
Designated
ISTS
Customers
Nodal
Demand /
Generation
Medium Term
Injection /
Withdrawal
Approved
InjectionApproved
WithdrawalBasic
Network
Network
Parameters
ForecastInjection /
Withdrawal
Flow Chart for Input Data Acquisition
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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
ApprovedNodal
Injection &
withdrawal
Truncation of basic
network, (creation of
virtual generators /
loads) load flow, &
Transmission losses of
truncated network
Load flow on
completenetwork
Algorithm
for averageparticipation
Algorithm forcomputingmarginal
participation
Generation Zone
Demand Zone
PoC for billing
Generation Zone
Demand Zone loss
for scheduling
List of state lines
used as ISTS
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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.
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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 foreach line/bus
Calculation of PoC Charges for each Node
Results obtained from WebNetUse Node wise PoC Charges
Injection charge
Withdrawal charge
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Sample Calculation
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Timelines for Submission of Information
Details 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 forworking days immediately after the dates indicated
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Determination of PoC Charges (4)
Philosophy for identification of coherentnodes for zoning
Zones to be geographically and electrically proximate Shall contain relevant nodes whose costs determined by
the hybrid method are within same range
State control areas to be separate demand zone exceptin the case of North Eastern States, which areconsidered as a single demand zone.
State control areas considered as generation zone
except NER states which are considered as a singlegeneration zone.
All thermal plants 1500 MW / hydro plants 500 MW
connected directly to ISTS or through pooling stations tobe considered as separate generation zone.
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Billing of Transmission Charges
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Central Transmission Utility (CTU) shall be responsiblefor
Raising the bills, collection and disbursement to ISTS licenseesbased on Accounts issued by RPC
Bill to be raised only on DICs
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 shallbe :
In 3 parts on the basis of Rs/MW/Month and;
the fourth part for deviations would be on the basis ofRs/MW/Block
Billing of Transmission Charges
Billing and Collection of Charges by CTU
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CentralTransmission
Utility
Central
TransmissionUtility
First Part(Based on Approved
Injection/Withdrawal and
PoC Charge)
Third Part(Adjustments Based on
FERV, Interest,
Rescheduling ofCommissioning)
Fourth Part(Deviations)
Second Part(Recovery of Charges forAdditional Medium Term
Open Access)
Afterissuanceof RTA
After
issuanceof RTA
Biannually(1st Day ofSeptember
and March
18th Day
of aMonth
Billing and Collection of Charges by CTU
Treatment of Deviations : Generator
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Generator
NetInjection
NetDrawl
1.25 timesPoC Charge
Deviation upto
than 20%
Deviation
Greaterthan 20%
PoC Charge1.25 times
PoC Charge
Treatment of Deviations : Generator
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Information on Public Domain Approved Basic Network Data and Assumptions, if any
Zonal or nodal transmission charges for the next financialyear differentiated by block of months;
Zonal or nodal transmission losses data;
Schedule of charges payable by each constituent for thefuture Application Period, after undertaking necessary
true-up of costs
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Implementation Related Issues Definition of Approved Injection
Approved Withdrawal Determination of YTC & Substation Cost
Apportionment
Multiple Scenarios for PoC computation and Basisof 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
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CERC Orders on Removal of
Difficulties
Definition of Approved Injection /
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Definition of Approved Injection /
Withdrawal Long Term Access (LTA) or PPA/ Contracts
LTA: Most Sacrosanct figure for transmission PPA/Contracts: used for scheduling purpose
Transmission is a sunk investment
Recovery as per approved Transmission Access
Entities availing long term transmission services :
liable to pay
Proper signal for transmission planning
Incentive for submitting correct transmission
requirement
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Progress of Implementation(2)
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CERC Order on Determination of PoC Rates andTransmission Losses in accordance with the SharingRegulations dated 29th June 2011
CERC Order on Approval of Procedure of DataCollection along with formats, Procedure forComputation of PoC Transmission Charges and
Procedure for Sharing of Losses under the SharingRegulations
Inputs on PoC Charges for each Regional Entityprovided to the Power Exchanges on 30th June 2011
PoC Charges and Losses for 2011-12 implementedw.e.f 1st July 2011
Weekly Loss Application
Provisional RTA
g p ( )
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Results of PoC Computation ofCharges and Losses
(2011-12)
Handling Bulk Data
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Handling ulk ata
Buses 4830
Generating Stations 557
Generating Units 1148
Loads 2672
Branches
DC Lines 7
765 kV 2
400 kV 622
220 kV 3034
132 kV 5130Total 8795
Transformers 2031
Yearly Transmission Charges
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y g
ISTS NEW Grid SR Grid Total
POWERGRID 6605.5 1593.7 8199.2
POWERLINKS 268.1-
268.1
RPTL 80.0 - 80.0
Jaypee
Powergrid 141.8 - 141.8
UPPTCL* 15.6-
15.6
RRVPNL* 1.8 - 1.8
PDD J&K* 10.1 - 10.1
GETCO* 5.7-
5.7
Mahatransco* 20.6 - 20.6
Total 7149 1594 8743
ISTS NEW Grid SR Grid Total
POWERGRID 6605.5 1593.7 8199.2
POWERLINKS 268.1-
268.1
RPTL 80.0 - 80.0
Jaypee
Powergrid 141.8 - 141.8
UPPTCL* 15.6-
15.6
RRVPNL* 1.8 - 1.8
PDD J&K* 10.1 - 10.1
GETCO* 5.7-
5.7
Mahatransco* 20.6 - 20.6
Total 7149 1594 8743
* RPC Certified Lines* RPC Certified Lines
All Figures in Rs Cr/AnnumAll Figures in Rs Cr/Annum
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Slab Rates : NEW Grid
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Rs/MW/Month
Slab Rates : SR Grid
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Rs/MW/Month
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COMPARISION OF POC CHARGESAND
PRE-POC TRANSMISSION CHARGES
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2.562.30
19.24 15.93
0.02
7.90
25.96
73.93
1.95
16.84 15.64
0.00
7.34
22.16
2.55
66.47
0.00
10.00
20.00
30.00
40.00
50.00
60.00
70.00
80.00
SIKKIM WEST
BENGAL
ORISSA POWERGRID
PUSAULI
JHARKHAND BIHAR DVC Sub -Total
POC TOTAL Pre-POC TOTAL
Rs.
inC
rore
Monthly Transmission charges of ER DICs
Regionwise comparison of PoC & existing monthly transmission charges
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301.13
197.12
130.46
73.93
25.94
309.90
191.66
138.03
66.47
22.52
0
50
100
150
200
250
300
350
NR WR SR ER NER
POC TOTAL
Pre-POC TOTAL
R
sinC
rore
PoC Losses
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Paid in Kind
Entities to be placed in the slabs based on the
moderated PoC Losses
Moderation to be done based on the average losses ofpast 52 weeks
On Regional Basis.
Slab Rates for PoC Losses
Average Loss + 0.3%
Average Loss
Average Loss 0.3%
Average Loss to be declared by RLDCs on weeklybasis.
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Thank You!