Sharing of Inter State Transmission Charges

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


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


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 – 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

Future Scenario : More Complexities

REGIONAL GRID -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

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

Elegant Model





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!

Documents

Sharing of Inter State Transmission Charges