Trans Pricing NPTI 090811

7/28/2019 Trans Pricing NPTI 090811

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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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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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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)


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 mTransmission Assets (TmA 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


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

Inter-Regional Interconnections

TSPs in One Region Having Customers in Another Region Also


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Elegant Model

TSP 1





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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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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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!

Documents

Trans Pricing NPTI 090811