Short term Power Purchase and Trading

Submitted by

Mohd KamilEnrollment Number – R590209021

Under the guidance of:

Mr. T.V.RAO

An Internship Report submitted in partial fulfillment of requirement for

Masters of Business Administration (Energy Trading)

August, 2010

University of Petroleum and Energy Studies

Dehradun, Uttrakhand

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ACKNOWLEDGEMENT

This is to acknowledge with sincere thanks for the assistance, guidance and support that I have

received during the Summer Training. I place on record my deep sense of gratitude to the

management of Power Management Institute (NTPC) for giving me an opportunity to pursue

my Summer Training. My very special regards to Mr. T.V.RAO for their constant advice and

support.

I also place on record my appreciation for the support provided by the other staff members.

Signature: Date:

……………………..

Mohd Kamil

R590209021

MBA in Energy Trading

University of Petroleum & Energy studies

Dehradun.

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BONAFIDE CERTIFICATE

This is to certify that Mr. Mohd Kamil, a student of University of Petroleum and Energy Studies,

Dehradun, pursuing MBA (Energy Trading), has successfully completed summer training at

Power Management Institute for the duration of 2 months in 2010. As part of his Curriculum,

the project report entitled, “Short term Power purchase and Trading” submitted by the student

to the undersigned is an authentic record of his original work which he has carried out under my

supervision and guidance.

I wish him all the best.

Date___________

Mr. T.V.RAO

AGM (HR)

Power Management Institute

Noida

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Executive Summary

India is and has always been a power deficit country. But since independence there has been

considerable growth in the power sector with the generation capacity being increased from 1362

MW in 1947 to 1,63,670 MW (Approx) today. The power supply position is characterized both

by shortages in meeting the demand during the peak hours and by shortages in the overall energy

supply. The peaking shortage is much more in every region and it is about 12% on all India basis.

The energy shortages on regional basis are varying in magnitude and overall shortage on all India

basis is about 7%.

But the demand is not uniform everywhere. Moreover there are regions where there is full-

fledged generation but very less consumption. For example, the state of Chhattisgarh has a lot of

generation capacity and at the same time the consumption is very less making it a power surplus

state. The country is divided into five different regions with each region having its own

peculiarity. There are various surplus and deficit regions in the country due to which the concept

of power trading comes into the picture. This is because of seasonal surplus in one state

coinciding with a deficit period in another. It helps a great deal in reducing the demand-supply

gap.

The implementation of the ABT mechanism has brought about considerable improvement in the

grid discipline with the UI charges acting as a penalty for a deviation from the schedule. It also

acts as revenue for the generators when there is under drawl by the buyers or an over injection by

the generating station. The UI charges are payable by the generating stations if there is over

drawl by the buyer/beneficiary or an under injection by the generating station. This way the

efficiency of the grid is ascertained.

The types of trading are categorized under long term, medium term or short term. The trading

through the exchanges are considered to be short term trading. Bilateral and banking agreements

also come under short term trading. Presently there are two power exchanges viz. IEX and PXI

operating in the country.

This report also highlights the various regulations affecting the short-term trading of power.

These are the regulations related to the Open Access, the procedures of scheduling various

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transactions etc. The Indian Power sector is highly regulated by the CERC and so it is imperative

that one should understand the various regulations related to it.

The objective of the study is to shed some light on the emerging power trading mechanism with

special reference to the short term power trading which is done through bilateral agreements,

banking agreements and the power exchanges.

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TABLE OF CONTENTS

Page no.

Chapter 1: Introduction…………………………………………………………..11

1.1: Overview of Power Sector………………………………………11

1.2: Global Overview…………………………………………………..12

1.3: Indian Power Sector Reforms………………………………….14

Chapter 2: The Concept of Trading………………………………………….17

3.1: Background…………………………………………………………17

3.2: Evolution of the Indian Power Market………………………….17

3.3: Indian power supply scenario……………………………………18

3.4: Why trading………………………………………………………..22

3.5: Current scenario of power trading……………………………..26

Chapter 3: Availability Based Tariff (ABT)………………………………...27

4.1: Components of ABT………………………………………………..27

4.2: Methods of sharing payments……………………………………..28

4.3: Working of the mechanism………………………………………..29

4.4: Importance of ABT…………………………………………………29

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Chapter 4: Types of Trading…………………………………………………....31

5.1: Long Term and Medium Term…………………………………31

5.2: Short Term…………………………………………………………32

Chapter 5: Types of Short Term Trading……………………………………34

6.1: Bilateral Agreements…………………………………………….34

6.2: Banking Agreements……………………………………………….35

6.3: Power Exchanges…………………………………………………36

Chapter 6: Indian Power Exchanges and their mechanisms……………….44

7.1: Indian Energy Exchange…………………………………………..44

7.2: Power Exchange of India Limited……………………………….46

7.3: Congestion management…………………………………………..49

Chapter 7: Open Access………………………………………………………….51

8.1: Meaning……………………………………………………………….51

8.2: Definition according to Electricity Act 2003…………………51

8.3: Impact of Open Access on DISCOMS ………………………....52

Chapter 8: Regulatory Role in trading………………………………………53

9.1: CERC Regulations for Short Term Open Access……………53

9.2: Procedure of Scheduling Bilateral Transactions………………………..63

9.4: Requirements of being an Electricity Trader……………………………...79

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Chapter 9: Findings and observations………………………………………………...82

10.1: Volume of Short Term Transactions of Electricity………………………82

10.2: Price of Short Term Transactions of Electricity…………………………84

10.3: Volume of Short Term Transactions State-wise………………………….88

Chapter 10: Conclusion…………………………………………………………………92

Bibliography

1. Ministry of Power

2. NTPC-VVN website

3. National Energy Map for India: Technology Vision 2030 by TERI, India

4. Regulations on connectivity and Short term Open access by CERC, India

5. Annual Report of Central Electricity Authority, India for 2007-2008

6. CERC Regulations on Unscheduled Interchange as on 1st April 2009

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Abbreviations

ABT – Availability Based Tariff

BU – Billion Units

BTU – British Thermal Units

CERC – Central Electricity Regulatory Commission

CGS – Central Generating Stations

CO2 – Carbon di-oxide

CPP – Captive Power Plant

CTU – Central Transmission Utility

DISCOM – Distribution Company

ER – Eastern Region

GDP – Gross Domestic Product

GENCO – Generation Company

GW – Gigawatt

GWh – Gigawatt hour

IEX – Indian Energy Exchange

IEO – International Energy Outlook

IPP – Independent Power Producers

Kwh – Kilowatt hour

LOI – Letter of Intent

MCP – Market Clearing Price

MU – Million Units

MW – Megawatt

MWh – Megawatt hour

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NLDC – National Load Dispatch Centre

NER – North-Eastern Region

NR – Northern Region

OECD – Organization for Economic Co-operation & Development

PX - Power exchange

PXIL – Power Exchange of India Limited

RLDC – Regional Load Dispatch Centre

RPC – Regional Power Committee

SEB – State Electricity Boards

SERC – State Electricity Regulatory Commission

SLDC – State Load Dispatch Centre

SR – Southern Region

ST – Short Term

STU – State Transmission Utility

T & D – Transmission & Distribution

TRANSCO – Transmission Company

UI – Unscheduled Interchange

WR – Western Region

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e

Chapter 1: Introduction

1.1. Overview of power sector

Accessibility, Availability and Acceptability are the three main objectives of the power sector. In

order to achieve these objectives the power sector has to be reliable both in terms of quality and

efficiency. The growth in this sector has been immense and the Indian economy continues to

surge ahead. The demand for power is never ending and in fact the demand has been increasing

over the years. It has become a growing concern for the people in the power sector to meet the

demands of the public.

Existing generation suffers from several recurrent problems. The international standards are way

too high as far as the efficiency and the availability of the coal power plants are concerned. Low

heat content and high-ash unwashed coal is used by the majority of the power plants. This results

in a high number of airborne pollutants per unit of power produced. Thereby polluting the

environment and increasing carbon emissions. In the context of fast-growing demand, large T&D

losses and poor pooling of loads at the national level exacerbate the lack of generating capacity.

India being the 11th largest manufacturers of energy worldwide makes its presence felt in the

energy sector with respect to its manufacturing strength and in terms of its usage. It is also the

worlds’ 6th largest consumers of energy. Although India has an extensive yearly energy output it

is a regular importer of energy because of the disparities in consumption.

Power is one of the few commodities which have always been in short supply in India. This is

one of the main reasons why India remains always hungry for power both in terms of peak and

off-peak power demand. There are various sources of power generation in India viz. thermal

power, hydropower or hydroelectricity, solar power, biogas energy, wind power etc. The

distribution of the power generated is undertaken by various distribution companies at its

respective state levels.

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1.2. Global Overview

Energy plays a vital role in the day to day activities of our lives. It plays a tremendous role in

supporting our convenience and living standards. Energy consumption is normally high in the

industrialized countries as compared to the developing countries. The United States of America

consumes around 26% of the world energy in total. The average annual growth rate of the world

electricity generation was 3.7% from 1971 to 2004 which was greater than the total primary

energy supply which grew at 2.1%. This increase was mainly because of more electrical

appliances, development of electrical heating in several developed countries and rural

electrification programmes in developing countries.

There is a fierce competition in the global energy markets due to de-regulation. Now electricity is

being produced a lower cost with many countries trying to reduce the impact power generation

has on the environment. 30% of the world’s energy is used by the developing countries

collectively but it is expected to rise to 95% with the projected population and economic growth

in those markets. Overall global consumption is expected to rise 50 % from 2005 to 2030.

The world net electricity generation is projected to rise from 17.3 trillion kilowatt hours in 2005

to 24.4 trillion kilowatt hours in 2015 and 33.3 kilowatt hours in 2030. The strongest growth in

demand is shown by the non OECD countries due to the expansion in their power grid for

supporting and maintaining the robust economic growth. There is an average increase of 4% per

year from 2005-2030 in the total electricity generation in the non OECD countries whereas in the

OECD countries the average increase is 1.3% per year for the electricity generation.

The coal and natural gas account for the largest increment for the projection period 2005-2030 as

far as the fuel component of electricity is concerned. The coal based generation appears to be

more economical considering the high prices of the oil and natural gas. But the coal power plants

can get restrictions from the various international agreements for cutting down of the greenhouse

gases. The electricity sector as such offers the most cost effective opportunities for reducing CO 2

emissions in many countries and its proving worth in real times also. A series of achievements

have been made when clean coal technology is considered. They have clinically tested and

proven, implementing these new technologies would not require expensive and large-scale

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changes in the power distribution infrastructure or in electricity-using equipment. An alternative

for reducing these emissions is to improve the efficiency of the equipment that uses electricity.

Electricity generation from nuclear power is projected to increase from about 2.6 trillion

Kilowatt hours in 2005 to 3.8 trillion Kilowatt hours in 2030 as there are rising concerns over

rising fuel prices for oil and natural gas, energy security and reduction of greenhouse gas

emission agreements support the development of new nuclear generation plants and older plants

have also citied high capacity utilization rates and there is also considerable uncertainty

associated with nuclear power plants. The various issues that slow down the development or

expansion of nuclear power plants include plant safety, radio-active waste disposal, wrong use of

the nuclear technology in making weapons of mass destruction, concerns of attacks because of

the increasing number of terrorist attacks all over the world and high capital & maintenance cost.

The IEO (2008) projection on nuclear electricity generation in 2025 is 31% higher than the IEO

(2003) projection that was pollution friendly five years ago.

In the IEO (2008) projection, the worlds installed capacity grows from 374 Giga watts in 2005 to

498 Giga watts in 2030. The decline in nuclear capacity projected only for OECD Europe, where

as countries like Germany and Belgium are planning to phase out their existing nuclear power

plants. There is strong growth projected in the Non-OECD Asian countries, where 68 Giga watts

of additional installed capacity is projected for Asia between 2005-2030, 45 Giga watts in China

and 17 Giga watts in India and outside Asia, the installed capacity is high in Russia and is

expected to have an additional 18 Giga watts.

High Oil and Natural Gas price pushing demand for generation RES and it’s also attractive for

environmental reason’s because of its pollution free nature. Worldwide consumption of

electricity from hydro power plants and other renewable sources have increased by 2.1% in the

IEO(2008) projections from 35 quadrillion BTU in 2005 to 59 quadrillion BTU in 2030

The per capita consumption of India is far behind when compared to the world average and very

less when compared to other countries. So there is a need to improve it and its only possible

through successfully implementing various initiatives taken by the government.

Though India has achieved many milestones in generation still the there is a wide gap between

demand and supply of power. This is the most important issue we must to be concerned with.

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1.3. Indian Power sector reforms

a) Electricity Act, 2003

After the implementation of the Electricity Act 2003, a new paradigm has been created for the

development of the power sector in the country. The monopoly created through the Electricity

(Supply) Act, 1948 of the State Electricity Boards has been abolished with the implementation of

this Act. It has created a new competitive framework for the development of the power sector in

the country with special focus on the interests of the consumers by independent Regulatory

Commissions. Almost all the barriers in the entire chain of the electricity supply business are

reduced or eliminated after the implementation of this Act.

It marks the culmination of the process beginning in the mid nineties of the states enacting their

own Reform Acts and the enactment of the Electricity Regulatory Commission Act of 1998

which brought into place the Central Electricity Regulatory Commission and authorized the

states to create SERC if they wished to do so.

The key features of this Act are discussed below:

To establish independent Regulatory Commissions in the States as well as the Centre

To free up thermal generation from the requirement of any prior clearances

Offering full freedom for setting up of captive power plants including group captive

power plants

To create an all India market and also allow Open Access in transmission

To encourage private investment in transmission through licensing by regulatory

commissions. There is also the full freedom for building dedicated transmission lines

Open access in distribution to be introduced in phases with consumers above 1 MW

getting the right of Open Access, latest by January 2009

To enable the provision for more than one distribution licensee in the same area.

Prescription of performance standards for distribution licensees and its enforcement by

Regulatory Commissions.

To establish a multi-year tariff framework for performance based regulation to incentivize

efficiency gains.

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To bid generation tariffs competitively so that it is accepted by the regulatory

commissions. The power purchase costs of the customers availing open access is to be

determined by the market.

An Appellate Tribunal is maintained for the quick disposal of appeals against decisions

of the State Regulatory Commissions or the CERC.

c) National Electricity Policy

The features of the policy are discussed below:

To provide access to Electricity and make it available for all households in the next five

years.

To meet the power demand fully by 2012 and to overcome the energy and peaking

shortages and also spinning reserve of 5% to be available at the national level.

To supply reliable and better quality power with specified standards at reasonable rates.

To increase the per capita availability of electricity to over 1000 units by 2012.

Minimum lifeline consumption of 1 unit/ household/ day as a merit good by year 2012.

To develop the hydro potential of the country fully.

Economics based choice of fuel for thermal generation and supply of electricity.

To develop the national grid of the country.

To extend the Availability Based Tariff (ABT) to the state level.

To introduce all India transmission tariff sensitive to distance and direction by the CERC.

d)Tariff Policy

The salient features of the National Tariff Policy are given below:

To accept the tariff of generation and transmission projects in private sector determined

through competitive bidding by the Regulatory Commission.

To reduce the amount of cross subsidy to around 20% of average tariff in the next five

years.

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To facilitate the open access in distribution and formulate clear policies on cross subsidy

surcharge.

The transmission tariff to be sensitive to distance and direction.

To implement the performance standards strictly.

To introduce time-bound multi-year tariff.

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Chapter 3: The concept of trading

3.1. BACKGROUND: Power trading inherently means a transaction where the price of power

is negotiable and options exist about whom to trade with and for what quantum. In India, power

trading is in an evolving stage and the volumes of exchange are not huge. All ultimate

consumers of electricity are largely served by their respective State Electricity Boards or their

successor entities, Power Departments, private licensees etc. and their relationship is primarily

that of captive customers versus monopoly suppliers. In India, the generators of electricity like

Central Generating Stations (CGSs), Independent Power Producers (IPPs) and State Electricity

Boards (SEBs) have all their capacities tied up. Each SEB has an allocated share in central

sector/ jointly owned projects and is expected to draw its share without much say about the

price. In other words, the suppliers of electricity have little choice about whom to sell the power

and the buyers have no choice about whom to purchase their power from.

The pricing used to be fixed by the Central and State Governments. However, it is now done by

the Regulatory Commissions at the Centre and also in the States wherever they are already

functional. Power generation/transmission is highly capital intensive and the Fixed Charge

component makes up a major part of tariff. The power demand in India is basically seasonal and

weather sensitive with India being a predominantly agrarian economy. There also exists a

substantial difference in the demand of power during different hours of the day with variations

during peak hours and off peak hours. Further, the geographical spread of India is very large and

different parts of the country face different types of climate and different types of loads.

States like Karnataka and Andhra Pradesh experience low power demand during the rainy

seasons and high in Delhi and Punjab. Whereas many of the States face high demand during

evening peak hours, cities like Mumbai face high demand during office hours. There is a

significant surplus in the Eastern Region round the clock, and even normally power deficit

states with very low agricultural loads like Delhi have surpluses at night. Such situations

indicate enough opportunities for trading of power. This would improve utilization of existing

capacities and reduce the average cost of power to power utilities and consumers.

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In view of high fixed charges, average tariff becomes sensitive to PLF. Trading of power from

surplus State Utilities to deficit ones, through marginal investment in removing grid constraints,

could help in deferring or reducing investment for additional generation capacity, in increasing

PLF and reducing average cost of energy. Over and above this, the Scheduled exchange of

power will increase and un-scheduled exchange will reduce bringing in grid discipline, a

familiar problem.

According to the Electricity Act 2003, trading is defined as “purchase of electricity for sale

thereof”. Trading is recognized as a distinct activity.

3.2. Evolution of the Indian Power market

The Indian power market has evolved over the years. The installed capacity for generation was

1362 MW in 1947 and the present capacity for generation in India is 1,63,670 MW. The actual

power supply position in 2009-10 according to the Ministry of Power are discussed below-

The energy requirement is 8,30,594 MW

The energy availability is 7,46,644 MU

The energy shortage is 83,950 MU (10.1%)

The peak demand is 1,19,166 MW

The peak met is 1,04,009 MW

The peak deficit is 15,157 MW (12.7%)

The peak power demand is growing at 7.85% (compounded annual growth rate) and energy

demand at 6%.

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3.3. Indian Power supply scenario

Fig 2. Energy Availability & Requirement

From the above diagram we can see that there is a considerable gap between the energy available

and the energy which is required. The total energy availability is 739 BU whereas the total

requirement of energy is 786 BU.

,

Fig 3. Peak Demand in GW

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The above figure highlights the actual demand prevailing in the country and the demand that is

being met. The actual demand in GW is 108 GW and the demand met is only 90 GW.

The installed capacity of the various regions of India is shown with the help of the following

table with the ownership sectors as well as the mode wise breakup viz. thermal, nuclear, hydro,

and renewable energy sources.

Table 1. All India installed capacity of power generation

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Fig 4. Regional capacity of generation

The figures shown in the above diagram have been revised in the table shown before with the

region-wise installed capacity. The total installed capacity of the northern region including all the

generation modes i.e. thermal, nuclear, hydro and renewable sources is around 38723 MW with

the major share of the thermal power plants being 22351 MW. Nuclear has a very small share of

1180 MW whereas hydro still has potential in the northern region with a generation capacity of

13425 MW. The renewable energy sources share is around 1766 MW. The Western region has a

total installed capacity of around 45965 MW with the major share being of the thermal power

plants again. The total installed capacity of the thermal power plants in the western region is

around 32653 MW, the nuclear capacity being 1840 MW, 7448 MW for the hydro plants and

around 4023 MW from the renewable sources. The total installed capacity of the Southern

Region is 40430 MW. The total thermal capacity in the Southern Region 21328 MW, nuclear is

around 1100 MW, hydro capacity is 10954 MW and there is a considerable share of the

renewable sources with 7047 MW. The total installed capacity in the eastern Region is around

20814 MW with 16653 MW thermal capacity, 3933 MW hydro capacity, 227 MW renewable

sources capacity with no generation capacity through nuclear. The total capacity of the North-

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Eastern Region is around 2255 MW with the major generation capacity being of hydro with 1116

MW, thermal being the next with 968 MW and also renewable sources contributing 171 MW. It

has no generation capacity through nuclear. The total installed capacity of the islands is taken

into consideration separately, the capacity being 76 MW with the major generation through

thermal stations. Combining all the regions of the country the total installed capacity of India

goes to around 148265 MW with the major share being that of thermal with 94025 MW 4120

MW of nuclear capacity, 36877 MW of hydro capacity and 13242 MW of renewable sources

capacity.

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3.4. Why trading?

Fig 5. Peculiarities of regional grids in India

India is divided into five different grids and every grid has its own peculiarity. Like, the northern

grid is a deficit region which has highly weather sensitive load. It has adverse weather conditions

with fog and dust storms. In the North eastern region the load is very low but it has high hydro

potential. In the eastern region there is low load but the reserves of coal is very high. It has pit

head base load plants. In the western region the load is basically industrial load and agricultural

load. In the southern region the load is very high and it is basically dependent on hydro potential.

Here, 40% of the load is agricultural load.

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Fig 6. Typical seasonal load curves for the Northern region

In the northern region the load during the summer seasons remains near the 22000 MW mark in

the wee hours of the morning. It reduces a little bit during the daytime but it again shoots up at

the evening time to around 24000 MW. In the winter season during midnight the load is around

19500 MW. It increases in the morning time and goes to around 22000 MW and again reduces

after 11 am. The main peak is reached during the evening time when the demand goes to around

23000 MW.

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Typical Seasonal Load Curves For240

00Southern Region

22000

SUMMER

20000

EVENINGPEAK

18000WINTER

16000

14000MONSOON

12000

100001 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 21 22 23 24

Fig 7. Typical seasonal load curves for the southern region

During the summer time the load is almost same throughout the day with the load increasing a

little bit in the evening time. It fluctuates round the 20000 MW mark but during the evening peak

it goes to around 23000 MW mark. The winter time witnesses a drastic change in the load curve

with the load increasing mostly from 7 o’clock in the morning and reaches the peak at the

evening time. At this time the load is around 21000 MW. During the monsoons the load falls

further down with the evening peak around 18500 MW.

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There is always the existence of shortages in meeting the peak as well as the overall demand.

Although there is an overall shortage, the inherent density in demand of various states and

regions in the country results in periods of seasonal surplus in one state or region coinciding with

periods of deficit in another region. This coexistence of overall shortages with complementary

geographical and temporal surplus-deficits provides substantial opportunities to improve the

economic efficiency and the security of supply through trading of power both within as well as

across regions. With the trading of power across the regions it has been possible to reduce the

demand and supply gap in various states of India.

There is also the need for the availability of adequate transmission capacity and inter regional

links for transfer of power from a surplus to a deficit entity and support. This way the full

benefits of trading can be realized.

Trading is also required for developing a fully fledged, efficient and competitive market

mechanism for power trading and also to facilitate the development of generation projects

including through private investment, both resulting in reliable, economic and quality power in

the long term.

It also helps in developing a power market for optimum utilization of energy. Optimum

utilization of existing resources is possible with the help of power trading.

It also aims to catalyze the development of power projects particularly environment friendly

hydro projects.

It also promotes the exchange of power with the neighboring countries.

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3.5. Power trading current scenario

Almost 97% of the supplies are locked up in the long term PPAs i.e the Power purchase

agreements.

The remaining 3% is constituted by the short term trading

Trading is always done between a surplus and a deficit region

Trading plays a vital role in the optimization of resources and also meeting the short term

peak demand

The trading basically takes place between two regions i.e inter-regional

The introduction of the open access regulations have facilitated the trading of power in an

orderly manner

All the energy agreements and transmission clearance should be arranged separately

The charges for open access are reasonable and easy to apply

The suppliers call for various bids from the buyers/traders

There is a tough competition between the traders to win the supply bids

If the buyer has entered into some contract with a trader for buying power he has no other

option but to buy from the trader having the supply contract.

There is a huge gap between the demand and the supply of power and due to this reason

the suppliers dominate.

The price of traded electricity keeps on fluctuating depending on various factors.

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Chapter 4: Availability Based Tariff

It is a generation tariff based on the premise of two part tariff structure (i.e. a fixed component

and a variable component) with the fixed component linked with the availability and the variable

component linked to the schedule generation. Availability based tariff can be viewed as a

commercial mechanism for improving the grid discipline and the frequency regime. It is a pricing

mechanism for electric power on the basis of frequency. It can also be considered as a

commercial mechanism for the Merit Order Operations. The ABT falls under electric market

mechanisms to charge and regulate power to achieve both short and long term network stability

as well as the incentives and the disincentives to market participants against deviations in

committed supplies as the case may be. ABT provides an efficient default market for trading and

encourages trading arrangements.

4.1. Components

Capacity charges: These are the charges payable by the beneficiary based on the

capacity allocated. They are also called the fixed charges. The payment of the capacity

charges based on the capacity available rather than the energy generated helps in the

avoidance of unwanted generation. It depends on the fixed component of generator like

Interest on loan, Return on Equity and Historical Cost. It is calculated based on the day

ahead availability declaration by generator.

Energy charges: These are the charges based on the scheduled energy. It depends on the

fuel cost.

Unscheduled Interchange (UI) charges: These are the charges levied for the deviation

from the schedules. The UI rate is considered as the default rate of trading. It is basically

dependent on the frequency which is an indicator of the demand and supply gap. It also

depends on the efficiency of the market. It encourages trading arrangements to hedge risk

of UI charges. In the decentralized scheduling system UI rate encourages the backing

down of the generation plants in the decreasing order of the variable cost given in the

Merit Order as the frequency goes up and vice versa when the frequency goes down.

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4.2. How do the beneficiaries share the payment?

Capacity Charges: It is the recovery of fixed charges based on the availability.

CAPACITY CHARGES = C.C. RATE * AVAILABILITY IN MW *

BENEFICIARY’S % ENTITLEMENT

Each beneficiary shall pay the capacity charges in proportion to its allocated percentage share in

the total capacity of the station as per the entitlement issued by State Load Dispatch Centre to the

respective generating station.

Energy Charges: It is the recovery of variable charges based on schedule generation in a time

block at a rate as fixed by the regulatory commission for the station and according to bilateral

agreement made by generating station and beneficiary.

ENERGY CHARGES = (BASE VC RATE + FPA) * BENEFICIARY’S SG

Each beneficiary shall pay the variable charges to respective generating station in proportion to

its drawl schedule based on the requisition of each beneficiary. The drawl scheduled will be

issued by State Load Dispatch Centre.

Unscheduled Interchange charges: It is the variation of actual generation with respect to

scheduled generation.

Unscheduled Interchange = Actual Generation – Scheduled Generation.

U.I. Charges = {Actual Energy Interchange in a time block -

Scheduled Interchange for the time block }

* Unscheduled Interchange rate for the time block.

Depending upon whether a utility is supporting or adversely affecting the Grid, UI Charges will

be receivable or payable which in turn called as a reward or penalty for the proactive action of

generator. Accordingly receivables and payables of each UI member will be calculated on

weekly basis.

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4.3. How does the mechanism work?

1. Generator declared the day ahead capability in the 96 time blocks for the possible

generation foresee and to be submit to SLDC.

2. Based on the allocation, declaration shall be break up for the respective beneficiary and

Entitlement will be issued to each beneficiary for all generating stations by SLDC.

3. All beneficiaries shall submit their requisition to SLDC for each generator in 96 time

block as per the demand forecast by them. It should not exceed their entitlement.

4. SLDC will compile the requisition received from each beneficiary and finalize the total

drawl schedule for each generator and prepared dispatch schedule.

5. Similarly, drawl schedule for each beneficiary shall be prepared as per their requisition

and bilateral.

6. Beneficiary shall also requisite for bilateral transaction through open access by reserving

corridor in advance to meet difference between demand forecast and entitlement . Same

shall be incorporated in the drawl schedule.

4.4. Why Availability Based Tariff is necessary?

1. Large deviations in frequency from the rated frequency 50.00 Hz reduced and grid

disciplined maintained due to ABT. The earlier mechanism does not provide any such

mechanism, incentive for optimum generation during peak hours and backing down

during low demand.

2. Each beneficiary takes part in ABT and they shall also manage their load by curtailing at

low frequency and adding demand during high frequency. At low frequency, beneficiary

may receive through UI mechanism. At high frequency, beneficiary may satisfy consumer

demand at low price through UI mechanism.

3. The generators optimize their generation at low frequency and receive payment through

UI mechanism and reduced generation at high frequency and saves fuel.

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4. Grid discipline maintained and system operation becomes safer.

ABT implementation dates

Western region - 1st July 2002

Northern region - 1st December 2002

Southern region - 1st January 2003

Eastern region - 1st April 2003

North-eastern region - 1st November 2003

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e

Chapter 5: Types of trading

5.1. Long Term and Medium Term

Long term and Medium term procurement of power is done through PPA’s where in Long term

PPA refers to agreements signed in for more than 7 years for the procurement of power and

medium term refers to agreements where the duration or validity of agreement is more than 1

year and not exceeding 7 years. These agreements are the central or core to the health of the

power sector, to be precise in those countries that have opted for single-buyer market structure.

The capital cost of the electricity generating plants often constitute a large share of the final cost

of power also referred to as the pass through mechanism i.e. at the end of the day it’s the buyer at

the end of the chain who has to bear the cost. In the case of thermal generation units fueled by

imported oil have faced problems due to the price fluctuation of the fuel because these fuels are

traded in international markets which are highly volatile and at certain situations like a war or

sudden demand shoot-up can lead to prices of these products to escalate to new heights there by

burdening the end user i.e. the consumers.

In cases where the risk allocation and sale price in PPA is one sided, then the bulk supply price

of power that results from the PPA may turn out to be very high and economically unstable. In

our country PPA’s are mostly entered between state/central/private generators as sellers and state

or central government undertaking wherein they are the purchaser, since the power sector of

India is highly regulated in most cases the sale price of the power was fixed by the governments

and on a long run it burdens the generation companies in private sector to supply the agreed

quantum at a fixed price due to the high construction cost incurred because the gestation period

of power plants can go into years if faced with unforeseen situation like policy changes caused

by new government at power i.e. political factors, cost of construction increasing due to

variations in global markets and increase in fuel cost due to volatility in global markets, these

issues can lead to losses borne by the seller if he sticks on with the agreement(private players)

whereas public sector generators losses would be borne by their respective states or the central

government.

The Enron fiasco can be classified under the above mentioned situation. Enron was world energy

giant they got permission to set up a thermal plant in Ratnagiri district of Maharashtra to meet

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the load demand of the state but once the plant was completed they could not stick with the

original agreement because their estimated cost of construction of the plant had gone up and the

price of fuel used for generation had also risen, putting the company a financially unsustainable

position if they had followed the agreement for selling power at the agreed prices. Now the plant

was taken over by GAIL and NTPC and it is floating its way out of losses.

PPA’s are a guarantee for the generating company to get back their cost fixed cost i.e. cost

involved in development and construction of the plant and also a guarantee for the fuel

agreement between the generator and the seller of the fuel from a seller’s perspective. From

buyers perspective it’s a guarantee to meet his load demand in the future once the plant is

operational and dedicated to commercial development. Central Electricity Authority (CEA) a

Statutory organization under the Ministry of Power, India con ducts an Electric Power Survey

(EPS) every 5 years to work out the load demand for all the states in the country based on

various factors, the latest survey was the 17th and its report’s were published in the year 2007.

With reference to the survey results, respective state governments get into Long-term PPA’s to

secure their load demand.

According to the tariff policy issued by Ministry of Power, the power purchase agreements

should ensure adequate and bankable security arrangements to the generating companies and in

case of persisting default from the purchaser in the form of letter of credit(LC), escrow of cash

flows etc then the generating company can sell of the generated power to other sellers.

5.2. Short term

Short Term trading is the trading done through bilateral agreements, banking agreements and

power exchanges. The short term trading accounts for about 3% of the total electricity

generation. It mainly helps in the reduction of the demand and supply gap by trading of power

among the surplus and the deficit regions. It is basically done on day-ahead basis but there are

also bilateral agreements which can be for a month. The bilateral agreements are useful for

buying or selling of power at a future date regardless of what the prevailing prices are at that

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time. They are merely between two parties i.e. a buyer and a seller and no other party is involved.

Banking agreements are also a kind of short term trading which is done between two parties but

it is non monetary. Here only a fixed amount of power is exchanged between the parties with a

promise to return it back at a particular date in the future. There can be various other conditions

in the agreement related to the quantity of power such as the quantity to be returned back may be

more than that was taken in the initial stage according to the conditions given by the lending

party.

Power exchange is the heart of short term trading. With the evolution of the power exchanges the

power scenario has drastically changed. They are a medium through which surplus regions can

sell power to the deficit regions. This has also increased the efficiency of the power system as a

whole as the power deficit states can easily quote the quantity needed to buy and vice versa for

the surplus states. They do not have to look for buyers/sellers as the case may be and consume a

lot of time. This has not only helped in increasing the efficiency but also in reducing the demand-

supply gap of power which is remarkable in the Indian context. The details about short term

trading are discussed in the following chapters.

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Chapter 6: Types of Short term trading

Short term trading includes the trading through:

Bilateral Agreements

Banking Agreements

Power exchanges

6.2. Bilateral Agreements

An agreement in which each of the parties involved in the contract makes a promise to each other

to buy/sell power on a particular date in the future. Bilateral Agreements are of two types viz.

Bilateral Import and Bilateral Export. These can be done on the basis of real time, day ahead and

on firm basis. The real time agreements are done on the same day, sometimes 11/2 hour before

the scheduling of power. This is because it takes only 11/2 hour to get the power scheduled

depending on the availability of the transmission capacity. The agreements on a day ahead basis

are done one day in advance. Whereas the agreements on a firm basis are those for which the

open access have been applied in advance.

In the case of a Bilateral export the consent has to be taken from the respective SLDC for the

sale/purchase of power. The quantum available for export is given to the traders and the traders

give the offers to the buyers and the sellers. The rates of the traded power are decided on

mutually agreed price. In this whole process the trader acts as a communicator between the

buyers and the sellers. The whole process is done verbally.

After this the trader sends the letter of intent (LOI) to both the buyer and the seller. After the

signing of the agreement by both the parties as per the agreed quantum and price, the open access

application is forwarded to both the buyer and the seller. The consent of both the parties is

required for the agreement to take place. The consent is then forwarded to the respective SLDC

for their approval. The approval from the respective SLDCs is followed by the open access

applications being forwarded to the traders by both the buyer and the seller. After this the trader

applies for the open access to the respective RLDCs. All the transactions are done through Fax. If

the transmission capacity is available in the network the power gets scheduled for the respective

time slots.

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The decisions as to at what rate the power should be bought or sold are mainly taken on the basis

of the prevailing UI rates. It also depends on the weather conditions.

The trader gets a maximum of 4 paise per unit. The wheeling charges are to be borne by the

buyer from the point of delivery by the seller.

An Example:

Power purchased from MSEB by NDPL the delivery point being the MSEB periphery. Then the

transmission charges which have to be paid will be through the link

MSEB – WR – NR – DTL

The charges to be paid are 5 + 5 + 3.5 = 13.50 paise/unit

Operating charges: Rs.2000 to be paid to the respective RLDC

Scheduling charges: Rupees 5000 to the respective SLDC

All the transmission charges, operating charges, scheduling charges are to be borne by the buyer

after the delivery point.

6.2. Banking Agreements

An agreement between two parties in which either of the parties agree to supply the power to the

other party for a specified period of time and as per the agreement the power is returned back by

the consuming party in the specified time period. These kind of agreements are also of two types

viz. day ahead banking and firm based banking.

For example:

If NDPL enters into a banking agreement with Rajasthan, the power supplied by NDPL in the

month of November, December, January (say 200 MUs) will be returned by Rajasthan in the

months of April, May and June.

Banking agreements are mainly useful when there is a seasonal disparity in the availability of

power. Now, Delhi is a power surplus State in the winter season and the winter season demand is

less as compared to the summer season. There is no profit in the case of an under drawl because

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the average UI rate is too less. In the summer season there is a huge shortfall to the tune of 250-

300 MW and nobody is willing to sell the power even at the rate of 10 Rupees/unit. The

frequency of the grid is worst during the summer season. The banking agreements are also useful

to keep the average power purchase cost down.

6.3. Power exchanges

Power exchange is a platform available for the purchase and sale of power in addition to the

bilateral agreements. It operates on a day-ahead basis, functions on all days including bank

holidays and Sundays.

Facts on Power Exchanges

Competitive wholesale spot trading arrangement that facilitate the selling and buying of

electricity.

It is an organized market that facilitates trade in standardized hourly and multi-hourly

contracts.

Develop marginal cost for its energy transaction – A price index

Power exchanges are ‘energy only market’ since they do not take into account any

technical aspects like transmission constraints or capacity payments.

Bids on an exchange only contain quantity and prices for a particular period.

An exchange is absolutely neutral towards the market because its

Rules apply to both sides of the transaction.

Power exchange is a voluntary market place

Competition in an electricity power exchange’s spot market occurs by generators,

distributors, traders and large consumers submitting bids for buying and selling

electricity.

Each sale bid specifies the quantity and the minimum price at which they are willing to

supply the energy.

Conversely, each buy bid specifies the desired quantity and the maximum price at which

they are willing to buy the energy.

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The power exchange matches supply and demand along with publishing a market-

clearing price.

Power exchanges have trading rules, which cover the setting of prices, delivery, clearing,

type of product, timing etc.

The role of a power exchange is to facilitate the trade of short-term products.

The key features of an exchange are discussed below-

Nation-wide, electronic Exchange for trading of Power

Exchange handles power trading and transmission clearance simultaneously

Transparent, neutral and efficient electronic platform

Trading on day-ahead contracts (all 24 hours)

Future extensions

Continuous Trading, Week-ahead, month and quarter ahead markets

How is it different from the present bilateral trading?

No separate booking of Transmission Corridor required

Participants comes to single platform and no direct access to each other

Buyers and sellers can participate directly

Trade Guarantee, Exchange guarantees payment to sellers

All confirmed trades to be scheduled & derivations to be settled through UI

B. Who can participate?

Inter-State Generating Stations (ISGSs)

Distribution Licenses

IPPs, connected on ISTS

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CPPs & IPPs

Open Access Customers

Electricity traders

State Generating Stations

Banks, Financial Institutions (as Clearing Members)

C. How to participate?

I. Become a member

Trading Member(TM)

Entitles the members to trade for themselves and / or on behalf of their constituents.

Trading cum Clearing Member (TCM)

Entitles the members to trade & clear, both for themselves and / or on behalf of their

constituents.

Professional Clearing Member (PCM)

Entitles the member to clear on behalf of the Trading Members.

II. Become a Constituent of a Member

Regulations by CERC

CERC is the regulator of Power Exchange – CERC issued guidelines for grant of permission to

set up power exchange in India and operate it within the parameters defined by CERC. Power

Exchange operates as per bye laws & business rules approved by CERC

Operationalisation of Exchanges in India

India Energy Exchange – 27th June 2008

Power Exchange India Ltd - 22nd October 2008

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Membership fees & associated charges of Power Exchange in India

Charges IEX PXI

1. Admission Fee (Non-refundable) 50.00 50.00

2. Annual Subscription 5.00 2.50

3. Processing Fee 0.10 0.05

4. Interest Free Security Deposit 25.00 40.00

(for self + 5 client)

5.Volume Based Transaction Charges 1 paise per Kwh 1 paise per Kwh

6. Margin Requirement In Cash Linked To CC

Limit

Table 2. Various charges of Power exchanges in India

Power Exchange Mechanism

Bid Call time in Power Exchanges from 10 am to 12 noon of the auction day

In a day ahead market (DAM), hourly electricity contracts (in MW) is traded

Bidders can put Single bid (for every hour) or Block bid (for night, day, peak, off-peak)

Minimum Bid Size – Quantum – 1 MW

Minimum Bid Price – 1 paise/Kwh

Margin Requirements – Member have to maintain Margins for putting the purchase bid in

form of :-

Interest free Security Deposit or

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Bank Guarantee or

Fixed Deposit in favour of Exchange or

Bank Credit limit – Working Capital/ credit limit with Clearing Bank

Transaction charges under Power Exchange -

- Open Access charges Payable to NLDC for Collective Transaction

b) Non-refundable fee of Rs. 5000/application.

c) Transmission Charges, for use of inter-State transmission system @ Rs.30/MWh for the

energy approved for transmission for each point of injection & drawl.

d) Operating Charges @ Rs.5000/day/entity involved.

Power Exchange Charges - 1 paise per kwh

Trading Margin for Client Member – 2.5 paise per kwh (charged by M/s AEL)

Transmission losses

- Regional Transmission losses - For Western Region – 5.5%

- State Transmission losses – For Gujarat – 4.92%

Clearing and Settlement System

Power Purchase Obligation – Member shall clear purchase obligation on T plus 1

day i.e. next day when the bid is executed

Sale Proceeds – Exchange shall release sale proceeds in T plus 2 days.

In case of bank holiday in between it will be extended to next working day

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Bid Areas

Fig 8. Bid Areas of India

The bid areas are divided into 10 different areas. The following diagram shows the various areas

where the bids are made.

N1- North Region- Jammu & Kashmir, Himachal Pradesh, Punjab, Chandigarh and Haryana

N2- North Region- Uttar Pradesh, Uttaranchal, Rajasthan, Delhi

E1- East Region- West Bengal, Sikkim, Bihar & Jharkhand

E2- East Region- Orissa

W1- West Region- Madhya Pradesh, Chhattisgarh

W2- West Region- Maharashtra, Gujarat, Goa, Daman and Diu-1,Daman and Diu-2,Dadar and

Nagar Haveli, North Goa

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S1- South Region- Andhra Pradesh, Karnataka, Pondicherry (Yanam), South Goa

S2- South Region- Tamil Nadu, Kerala, Pondicherry (Puducherry), Pondicherry (Karaikal),

Pondicherry (Mahe)

A1- North-East Region- Tripura, Meghalaya, Manipur, Mizoram, Nagaland

A2- North-East Region- Assam, Arunachal Pradesh

Trade Flow Timings

10 AM – 12 AM - Bidding Period (Participants to Place their Bid)

1 PM - PX to furnish unconstrained flow information to NLDC

2 PM - NLDC to inform PX about congestion, if any

3 PM - PX to submit application for scheduling to NLDC

4 PM - NLDC to send details of collective transaction to RLDC

5 PM - RLDCs to confirm acceptance to NLDC

5.30 PM - NLDC to convey acceptance for Scheduling PX

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Auctioned Day-Ahead Market

. Fig 9. Market Clearing Price graph

Market Clearing Price is the price which is found out in the exchanges by taking the total number

of buyers and the total number of sellers in a particular time slot. First, the total number of

buyers is taken into consideration i.e. the demand in the market, and the graph is drawn. After

that the graph for the total number of seller i.e. the supply is drawn. The intersection point of the

two graphs is called the market clearing price for that particular time slot. The area lying to the

left hand side of the market clearing price is the market clearing volume or the traded volume in

the market.

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Chapter 7: Indian power exchanges and their mechanisms

7.1. INDIAN ENERGY EXCHANGE

Section 66 of the Electricity Act 2003 made it mandatory for the development of Power markets

by appropriate commissions through enabling regulations. The Central Electricity Regulatory

Commission (CERC) issued guidelines for grant of permission for setting up and operation of

power exchange on 6th February 2007. This was done within an overall regulatory framework.

The Indian Energy Exchange (IEX), promoted by the Financial Technologies (India) Ltd. and

PTC India Ltd. is India’s first power exchange with an automated and online trading electricity

platform.

IEX being a demutualised exchange will enable efficient price discovery and price risk

management in the electricity market. The exchange has been developed as a market based

institution for providing price discovery and price risk management to the electricity generators,

distribution licensees, electricity traders, consumers and other stakeholders.

The broad features of the exchange are given below:

Nationwide, online and electronic platform

Voluntary participation

Neutral, unbiased and transparent

Offers day-ahead market

Exchange time line consistent with time line of load dispatch centers

The activities of the power exchanges will be carried put in accordance with the Central

Electricity Regulatory Commission (Open Access inter-state transmission) Regulations,

2008 dated 25.02.2008 as revised from time to time and the bye-laws, rules and

business rules of the exchange.

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MECHANISM used in IEX

A double sided closed auction mechanism is used in the current day ahead trading market. Both

the buyers and sellers shall pay/receive uniform price.

A separate interpolation auction procedure is used for the 24 hourly periods. The closed auction

method is a reliable method allowing both buy and sell bids to be submitted at the same time

without disclosing the identity of the buyer or the seller, price and quantity of bids. Both the

parties are under pressure to give in their best bids and true competition is ensured. It also

ensures that all parties receive the uniform price which is same or better than their price bids.

Market liquidity is also ensured by concentrating orders on each hourly market.

The transmission charges and losses are expected to be borne by the buyers and sellers in their

regional transmission system till the periphery of the transmission system. The operating charges

are also to be paid and a nominal transaction fee of 1 paise / kwh is also required to be paid.

After market closure, IEX calculates the MCP i.e. the Market Clearing Price on the basis of the

total number of buyers and the total number of sellers in the market and also the MCV i.e the

Market Clearing Volume on hourly basis and will forward the regional corridor required between

the inter regional links as well as the region wise traded quantity.

IEX is mainly responsible for the financial aspect of the transactions, NLDC/RLDC/SLDCs

ensure the electricity supplies and withdrawals correspond to the commitments contracted on the

exchange. It becomes obligatory for the participants to deliver or take delivery of the

corresponding net volume of electricity in the regional grid.

IEX validated transactions are deemed to be physically delivered. If the delivery commitment is

not fulfilled it becomes a liability for the participant to pay unscheduled interchange charges as

stipulated by the CERC to the RLDCs UI pool account or to SLDCs pool depending upon

whether it is a regional entity, embedded customer or else.

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7.2. Power Exchange India Limited

Power Exchange India Limited (PXIL) is a fully electronic, nation-wide exchange for trading

of electricity. It has been promoted by two of India's leading Exchanges, National Stock

Exchange of India Ltd (NSE) & National Commodities & Derivatives Exchange Ltd (NCDEX).

Power Finance Corporation, Gujarat Urja Vikas Nigam, JSW Energy, GMR Energy, Jindal Steel

& Power have taken equity stakes in this venture.

NSE is the largest stock Exchange in India and amongst the top 4 Stock Exchanges in the world

in terms of number of transactions. The standards set by NSE in terms of market practices,

products, technology & service standards have become industry benchmarks and are being

replicated by other market participants. NCDEX is the only commodity exchange in the country

promoted by national level institutions. The institutional promoters and shareholders of NCDEX

are prominent players in their respective fields and bring with them institutional building

experience, trust, nationwide reach, technology and risk management skills.

PXIL, like its promoters, will not just be building a Power Exchange, but would also be seeking

to play a thought leadership role in shaping India power markets in the years to come. PXIL aims

to provide transparent and fair price discovery mechanism which can signal massive potential

investments into the Indian Power Sector.

The initial products offered for trading are electricity contracts offered on a day-ahead basis with

voluntary participation. New products will be introduced after taking feedback from the market

& obtaining approval from CERC. PXIL has an independent Board of Directors and

professionals who manage the day-to-day operations. The Company is run on commercial

principles as an individual business entity, separated from the business of its shareholders.

PXIL received regulatory approval from Central Electricity Regulatory Authority (CERC) on

30th September 2008 to begin operations. After receiving the final nod from the National Load

Despatch Centre, the apex body of the country grid operator, PXIL has successfully started its

operations on 22nd October 2008.

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The last seven months have provided the Power Exchange India limited with the demand and

requirements of the Indian power market. Power Exchange India Limited has recently joined the

Association of Power exchanges which is a world body of the power exchange. It plays a key

role I the development and knowledge sharing of the best in class market practices. The members

of the Association of Power Exchanges are – Nordpool, EEX, PJM, NEMMCO, OMEL etc. it is

a major step in the development of the Indian power market.

Power exchange India Limited has proposed the idea for the development of intra state electricity

markets such that the buyers and sellers including the captives and the industrial consumers can

deal with one another in the exchange. The electricity surplus and the demand that is not met in

this intra state market would be cascaded such that it can be sold in the national market through

the power exchange on the next day. These intra state markets would play a key role in the

unlocking of captive capacity in the states and support the state utilities in their endeavor to

fulfill their universal service obligations

After about seven months of continued operations now the Power Exchange India Limited

believes that the power markets in India are ready to take the next step in their development

process through the introduction of the longer tenure products on PXIL. PXIL has developed a

new proprietary trading engine and the products can be traded using it. It would also utilize the

bilateral open access system. All these products are physical delivery based and would enable

market participants to procure and sell electricity through PXIL on week ahead, first, second and

third month ahead basis. Trading on the exchange would be now convenient and easy for all

participants with the structure of contracts being standardized and also standardized risk

management systems.

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Mechanism used in PXIL

The mechanism used in PXIL is also similar to that of IEX because the whole current day ahead

trading market uses a closed double sided bidding mechanism for a uniform price auction. This

bidding mechanism is very useful for obtaining a uniform hourly market clearing price for

smaller volumes and transactions in the day-ahead market. But it might have some issues for

much larger transactions which are expected for the longer tenure projects.

The revised inter-state bilateral open access regulations operate the electricity trading system

developed by PXIL. PXIL’s trading system uses an auction mechanism where the trading session

is divided into multiple sessions meant for sell, buy, trade-matching and price revision. These are

divided into 24 time slots in a day with each time slot of 1 hour. For each time slot a particular

price is bided and a particular quantum at that price is fixed for buy or sell. Suppose we are a

buyer and we put the bid price as Rs.4 per unit and the quantum as 100 MW then if the Market

Clearing Price for that particular time slot is less than Rs.4, say Rs.3 then we will get the quantity

of 100 MW. The case is reversed with the seller i.e. if the bid price is Rs.4 with a quantum of 100

MW and the market Clearing Price for that particular time slot is more than Rs.4 then the entire

100 MW will be cleared. The trades are matched through PXIL’s newly developed proprietary

trading engine.

PXIL believes that order matching systems for power trades are best evolved in keeping with the

peculiarities of the local market conditions. Hence PXIL has developed a trading engine software

through a consultative process with the market participants ranging from utilities to smaller

captives, as well as regulators so as to provide the Indian power market with the most suitable

product. The in-house development of the trading and matching system also provides PXIL with

the flexibility to accommodate changes in continuously evolving Indian power market.

The contract features of the traded products e.g. contract structure, penalty structures, risk and

margin system for longer tenure products have been kept in line with the present trading

transactions undertaken in the short term bilateral trading market.

The sanctity and the surety of the trades matched on the exchange are ensured by creating a risk

management mechanism in the form of adequate margins to cover the trades. Therefore the risk

management mechanisms take care of defaults in payments by buyers, defaults in supply by

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sellers, arbitrary termination of contract etc. the margins are collected in the form of an initial

margin after trade matching, daily margin of a pre-determined value during delivery and extra

ordinary margins to cover penalties of default. To provide the market participants with flexibility,

margin required can be built in the form of bank guarantee, bank limits, letter of credit, fixed

deposits and cash. Furthermore, care has been taken to ensure that the value of the margins is far

lower than that required in the short term bilateral transactions otherwise.

PXIL is of the opinion that by providing ease, transparency and certainty to market participants

these products would change the way power is traded in India and it would take the Indian power

market to the next stage of development.

7.3. Congestion Management

Congestion management is a very important phenomenon in the effective trading of power.

Transmission congestion occurs when there is not enough transmission capacity to

simultaneously accommodate all requests for transmission within a region. If in case the

congestion is not there then there shall be no restriction of access to the interconnection and no

specific procedure for access to transmission service.

The cause of congestion can either be temporary or structural. The occurrence of temporary

bottlenecks is relatively rare and maybe because of outages for maintenance work, technical

faults or particular market conditions. The structural bottlenecks are mainly a result of the level

of expansion of the grid and the localization of the generation and consumption within the grid.

These bottlenecks normally occur over longer periods of time or at regular intervals. But there is

very little difference between the two types of congestion. It is however important to determine

the kind of congestion faced with so as to employ the best method for dealing with it.

Principles of Congestion management

In principle the congestion can only be relieved physically by reducing generation or increasing

consumption on the surplus side of the bottleneck and conversely increasing the generation ot

reducing consumption on the shortfall side. Different methods are there for managing the

congestion depending on the various time phases of the day. These methods should be based on

the following principles –

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1. Economic efficiency and promotion of competition.

2. Maximizing of the amount of capacity available and its usage.

3. Transparency to the network users on a non discriminatory basis.

4. Efficient system operation

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e

Chapter 8: OPEN ACCESS

8.1. OPEN ACCESS AND TRADING:

The Electricity Act, 2003 has come into force from 10th June, 2003 and it repeals the Indian

Electricity Act, 1910; Electricity (Supply) Act, 1948 and Electricity Regulatory Commissions

Act, 1998. The performance of the state electricity boards have deteriorated over the years and

the cross subsidies have reached unsustainable levels. This is the reason why some of the states

in the country have gone in for reforms. This includes the unbundling of the state electricity

boards by creating separate Generation, Transmission and Distribution Companies. The

implementation of the Act has been one of the most important steps in the history of the power

sector. Due to this, newer concepts like power trading and open access have come into force.

The open access phenomenon helps the players to utilize the capacities and transmit power from

generation to the load centre. This will mean utilization of existing infrastructure and easing of

power shortage. Trading has now become a licensed activity and it also helps in the innovative

pricing leading to competition which in turn results in lowering of tariffs.

8.2. DEFINITION OF “OPEN ACCESS” IN THE EA’03:

The non-discriminatory provision for the use of transmission lines or distribution system or a

associated facilities with such lines or system by any licensee or consumer or a person engaged

in generation in accordance with the regulations specified by the Appropriate Commission”

A MORE GENERAL DEFINITION OF “OPEN ACCESS”: Open Access enables the non-

discriminatory sale/purchase of electric power between two parties using the system and not

blocking it on unreasonable grounds.

EXAMPLE: Suppose a company from Maharashtra wants to sell 100 MW to a Discom-A

in Andhra Pradesh.

Following steps need to be taken:

a) Discom-A and the company need to agree on terms and conditions of sale

b) The company needs to get the consent of MSEB i.e. Maharashtra State Electricity Board and

"no-objection" of MSERC i.e. Maharashtra State Electricity Regulatory Commission

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c) Discom-A to get the consent of APTransco i.e. the transmission company of Andhra Pradesh

and "no-objection" of APSERC i.e. Andhra Pradesh State Electricity Regulatory Commission

d) The SLDCs of both the states need to ascertain transmission adequacy, and agree to arrange

necessary metering, scheduling, energy accounting and UI settlement.

e) Both the regional load dispatch centers, here WRLDC and SRLDC to ascertain transmission

adequacy in their regional transmission systems.

f) All concerned to have a common understanding about treatment/sharing of transmission losses

and levy of transmission/ wheeling charges for the use of intra-State and inter-State systems.

8.3. IMPACT OF “OPEN ACCESS SYSTEM” ON DISCOM’S:

The Electricity Act 2003 has made it mandatory for the immediate implementation of the open

access. The implementation of the open access will serve the consumer interests but there is also

some contradicting views regarding the implications of the open access on the Discoms. The first

view being that the competition in the power generation will bring down the ultimate costs to the

consumers. Cost reduction is possible only by reducing the T&D losses, keeping under control

the operating costs and keeping the additional power purchase costs low. Given the facts that

power purchase costs keep increasing and the HT tariff has been mandated to be brought down

closer to the average costs (thereby reducing the cross-subsidy) according to a fixed time

schedule to be set by the regulator, the first group argues that taking up additional liability by

way of HT consumers at such high marginal costs of power purchase would be financially

imprudent for the electricity entities. The other view is that electricity entities have heavy

responsibility to meet the needs of agricultural consumers and small domestic consumers at a

lower rate than the average cost. Consumers who are currently the HT consumers and

commercial consumers paying a higher tariff are providing the means to do this. If such

consumers walk away from Grid supply subsidy from Government will have to increase. The

correct position would depend on the state-wise situation regarding relative tariff of the different

consumers, the possible rates of growth of category wise consumption and the potential for

purchasing additional power at low rates in the future.

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Chapter 9: Regulatory role in Trading

9.1. CERC Regulations for Short Term Open Access

Criteria for allowing short term open access

Short term open access can be given only if it can be accommodated by utilizing-

Inherent design margins

Margins available due to variation in power flows

Margins available due to in built spare transmission capacity created to cater to future

load growth

Allotment priority

The long term open access user gets the first preference, next is the medium term user and then

the short term user

If the capacity sought to be reserved by the open access users, at a given point of time is less than

the available capacity at that point of time, each short term open access user shall pay the

transmission or wheeling charges in accordance with regulation 14.

Procedure for short term open access user

1. First the application for access of transmission/distribution should be submitted to the SLDC.

2. The details such as capacity needed, inspection point, drawl point, duration of availing open

access, peak load, average load, and such other auxiliary information that may be specified

by the SLDC should be mentioned in the application.

3. A non refundable fee of Rs.5000 is payable to the SLDC along with the application in the

manner decided by the SLDC.

4. The reserved capacity should not be transferred by a short term open access user to any other

open access user.

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Non-Utilization of Reserved Transmission Capacity by Short-Term Open Access

User

If in case, a short term open access user is unable to utilize the full reserved capacity or a

substantial part of it then it must inform the concerned SLDC i.e the State Load Dispatch

Centre along with the reasons of its inability to utilize the full capacity. It is also required

that the reserved capacity must be surrendered.

The reserved capacity of a short term open access user may be reduced or even cancelled

by the concerned State Load Dispatch Centre if the user frequently under utilizes the

reserved capacity.

The short term open access user who surrenders the reserved capacity or whose reserved

capacity is reduced or cancelled under clause (ii), shall bear the transmission charges or

the wheeling charges and the scheduling and the system operation charge based on the

original reserved transmission capacity for seven days or the period of reservation

surrendered or reduced or cancelled, as the case may be, whichever period is shorter.

When a short term open access user surrenders a reserved capacity the capacity available

thereof under clause (i) or clause (ii) above, may be reserved for any other short term

open access user in accordance with these regulations.

Open Access Charges

The following Open Access Charges shall be payable by Open Access users. These charges will

be determined and notified by Commission from time to time through separate order. The

charges for open access shall consist of one or more of the following charges:

(i) Transmission / Distribution (Wheeling) charges

The charges for use of the system of the licensee for intra-state transmission or distribution

except intervening transmission facilities shall be regulated as under, namely:-

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1. The annual charges shall be determined by the Commission in accordance with the

terms and conditions of tariff notified by the Commission from time to time and after

deducting the adjustable revenue from the short-term users, these charges shall be shared

by the long-term users;

2. (a) The charges paid by the short term users shall be calculated by the following

method:

ST RATE = 0.25 x [TSC/ Av CAP]/ 365

Where:

ST RATE is the rate for short-term open access user in Rs per MW per day. "TSC" means

the Annual Transmission / Distribution Charges of the transmission or distribution

licensee for the previous financial year determined by the Commission. "Av CAP" means

the average capacity in MW served by the system. The capacity of the transmission

licensee in the previous financial year shall be the sum of the generating capacities

connected to the transmission system and contracted capacities of other transactions

handled by the system of the transmission licensee. The capacity of the distribution

licensee in the previous financial year shall be the sum of the distributed load for the

licensee. (b)The transmission charges payable by a short-term open access user in case of

un-congested transmission corridor shall be levied as under, namely:-

Up to 6 hours in a day in one block: 1/4th of ST RATE

More than 6 hours and up to 12 hours in a day in one block: ½ of ST RATE

More than 12 hours and up to 24 hours in a day in one block: equal to ST RATE

(c) Every licensee shall declare the rate in Rs/ MW per day which shall remain fixed for

a period of one year, provided further that, where reservation of capacity has been

done consequent to bidding in the manner specified in Regulation 6, the ST RATE

shall be taken as the floor price for bidding.

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3. 25% of the charges collected from the short-term open access user shall be retained by the

licensee and the balance 75% shall be adjusted towards reduction in the charges payable

by the long-term open access users.

4. The rates, charges and terms and conditions for providing the use of intervening

transmission facilities would be mutually decided by the licensees. Provided that any

dispute on the extent of surplus capacity available or disagreement on the rates, charges

and terms and conditions, shall be adjudicated upon by the Commission. However the

rates, charges and terms and conditions shall be fair and reasonable and may be allocated

in proportion to the use of such facilities.

(ii) Cross-Subsidy Surcharge

In addition to transmission charges and wheeling charges, a consumer availing open access to

the transmission system/distribution system shall pay a Cross-Subsidy Surcharge.

The Open Access users, except those availing open access facility to transfer power from

their captive generating plants to the destination of own use, shall pay the (cross-subsidy)

surcharge to the Distribution Licensee of their area, as determined by the Commission from

time to time under section 42 (2) of the Act.

The amount of surcharge shall be so calculated as to meet the current level of cross subsidy

from that category of consumers and shall be paid to the distribution licensee of area of

supply where the consumer is located.

Such surcharge and cross subsidies shall be progressively reduced and eliminated by the

Commission.

(iii) Additional Surcharge

(a) A consumer availing open access and receiving supply of electricity from a person other

than the distribution licensee of his area of supply shall pay to the distribution licensee an

additional surcharge, in addition to wheeling charges and surcharge, to meet the fixed

cost of such distribution licensee arising out of his obligation to supply as provided under

sub-section (4) of section 42 of the Act.

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(b) The distribution licensee whose consumer intends to avail open access shall submit to the

Commission within thirty days of receipt of application an account of fixed cost paid by

such open access user which the licensee is incurring towards his obligation to supply.

(c) The Commission shall scrutinize the statement of account submitted by the licensee and

obtain objections, if any, of the consumer and determine the amount of additional

surcharge payable by the consumer.

(d) The additional surcharge shall be levied for such period as the Commission may

determine but not normally exceeding one year.

(iv) Scheduling and System Operation Charges

(a) The scheduling and system operation charges payable to State Load Dispatch Centre by

long–term open access users shall be same as determined by the Commission under

Section 32 of the Act read with GERC (Levy and collection of fees and charges by

SLDC) Regulations, 2005.

(b) The scheduling and system operation charges of Rs.2000/-per day or part of the day shall

be paid by a short-term open access user to State Load Dispatch Centre

(c) The scheduling and system operation charges collected by the State Load Dispatch Centre

in accordance with clause (b) above shall be in addition to charges determined by the

Commission under Section 32 of the Act. These will be however adjusted in the

subsequent ARR of SLDC.

Explanation

Scheduling and system operation charges shall be payable by a supplier as well as his

consumer availing open access under these Regulations.

(v) Reactive Energy Charges

The payment for the reactive energy charges for the open access user shall be calculated

in accordance with the scheme applicable.

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(vi) Any other charges as may be specified by the Commission from time to time shall be

payable by the open access user.

UI Charges under Intra-State Availability Based Tariff (ABT)

The Commercial settlement of Unscheduled Interchange charges (UI charges) under Intra-State

ABT shall be done according to the Inter-State ABT being followed for Inter-State Transactions

with the following, additions/variation.

(i) A consumer opting for open access shall continue to be treated according to the rules

applicable to a normal consumer in the equivalent category of the Discom. Thus he will

be penalized for deviating from his scheduled drawl which may be detrimental to the grid

either by way of frequency or voltage of the grid. At the same time he will not be paid

any UI charges for changing his schedule even if it be helpful to the grid.

(ii) A generating station with a total capacity of generation upto 15 MW may operate

under UI regime and inject power (specially during peak load condition) when there is an

overall shortage and will be paid for such injection of generation into grid at the UI rate

as determined by SLDC.

(iii) Generating Stations with a total capacity above 15 MW shall be regulated as follows

according to CERC stipulations to avoid gaming:

(a) Any generation up to 105% of the declared capacity in any time block of 15 minutes and

aggregated averaging up to 101% of the average declared capacity over a day shall not be

construed as gaming, and the generator shall be entitled to UI charges for such excess

generation above the declared capacity scheduled generation (SG).

(b) For any generation beyond the prescribed limits, the State Load Dispatch Centre shall

investigate so as to ensure that there is no gaming, and if gaming is found by the State Load

Dispatch Centre, the corresponding UI charges due to the generating station on account of

such extra generation shall be reduced to zero and the amount shall be adjusted in UI account

of beneficiaries in the ratio of their capacity share in the generating station.

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Energy losses

The open access user shall bear average energy losses in the transmission and / or distribution

system proportionate to its drawl as specified by the Commission. The loss in the transmission

and / or distribution system shall be compensated by additional injection at the injection point(s).

Time-schedule for Processing Application

For grant of open access the following time schedule shall be adhered to by the respective nodal

agency for processing of the application as far as practicable:

1. Short-term Service

(for the period to be treated on First-come-first-served basis)

More than a week 2 days

Up to one week 3 days

Intimation regarding feasibility of access without system strengthening - thirty days Intimation of

results of studies for system strengthening with cost estimates and completion schedule –ninety

days

Curtailment Priority

When because of transmission or distribution capacity constraints or otherwise, it becomes

necessary to curtail the service of the open access users, the short-term open access users shall be

curtailed first followed by the long-term open access users:

Provided that within a category, all users shall have same curtailment priority and shall be

curtailed pro rata to the allotted capacity in the case of long term open access users and the

reserved capacity in the case of short-term open access users.

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Compliance of Grid Code

The open access user shall abide by the Grid Code and instructions given by State Transmission

Utility and State Load Dispatch Centre as applicable from time to time.

Collection and Disbursement of Charges

1. In case of open access to consumer, the concerned Distribution Licensee (or concerned

Transmission Licensee if the consumer is directly connected to its network), may invoice a

consumer in respect of the open access charges (such as Transmission Charges/Wheeling

Charges/Cross Subsidy Surcharge/ Additional Surcharge as the case may be) as set out in clause

14 of this Regulation and the open access user shall pay those charges, in accordance with the

procedures set out in the Bulk Capacity Agreement (Regulation: 10) between the licensees and

user.

Provided that the Distribution Licensee and Transmission Licensee(s) shall have appropriate

back-to-back arrangements in place in order to pass on Open Access Charges, pertaining to the

Licensees.

2. The scheduling and system operation charges in respect of open access shall be paid to the

State Load Dispatch Centre by the Open Access users.

3. The Unscheduled Interchange charges shall be paid in the manner as directed by the State

Load Dispatch Centre on weekly basis.

Phasing of Open Access

(i) Open access shall be allowed to consumers in the following phases subject to the

satisfaction of the conditions contained in the Act and in these Regulations:

PhaseLoad Level Time Frame

Load of 5MW andAfter Intra-State ABT is put in Place or 1st January, 20061

above whichever is later.

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Load of 1MW and2 2 years after introduction of 1 above above

(ii) Based on the experience of operation of open access in phase 1, the Commission may

revise the schedule for allowing open access in subsequent phases.

(iii) The Commission may allow open access to consumers with less than 1 MVA contract

demand at such time as it may consider feasible having regard to operational

constraints and other factors.

A person who has been allowed to use the transmission / distribution network on the date of

coming into force of these Regulations under the Captive Power policy of Government of

Gujarat shall pay charges applicable to Long Term Open Access User.

Information System

The State Load Dispatch Centre shall post following information on their websites in a separate

web-page titled “Open access information”:

(i) Floor rate in rupees per MW per day for the short-term open access users (ST_RATE)

(ii) A status report on the current short-term open access users indicating:-

(a) Name of open access user;

(b) Period of the access granted (start date and end date);

c) Point(s) of injection;

(d) Point(s) of drawl;

(e) Transmission / Distribution systems used (in terms of region and ownership);

(f) Reserved capacity; and

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(g) Applicable rate (Rs per MW per day).

Note

The status report shall be updated after every change in status.

(iii) Month-wise and year-wise report on past short-term open access users indicating:

(a) Name of the open access user;

(b) Period of the access granted (start date and end date);

(c) Point(s) of injection;

(d) Point(s) of drawl;

(e) Transmission / Distribution systems used;

(f) Reserved capacity;

(g) Applicable rate (Rs per MW per day); and

(h) Actual load factor.

Note

All previous reports shall also be available in the web-archives.

(iv) Information regarding usage of the links between various State licensees indicating:

(a) Time of updating;

(b) Name of the link;

(c) Total capacity of the link;

(d) Scheduled capacity use (giving open access user-wise break-up); and

(e) Current capacity of the link in use.

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e

Note

The information should be updated at least on hourly basis and wherever feasible on 15 minute

basis.

(v) The information regarding average energy losses for the previous 52 weeks,

provided that publication of web-based information system shall commence within 180 days.

Each transmission / distribution licensee shall make available the above information to the

SLDC.

All licensees shall declare current long-term open access using their system (including self-use

and use by unbundled entities which were previously integrated) with details thereof either on

their own websites or on the website of the State Load Dispatch Centre concerned, within 180

days.

Note

This list shall be updated as and when change in status takes place.

Communicating facility

The open access users shall meet the communication requirements as the nodal agency may

direct from time to time.

Redressal Mechanism

All disputes and complaints relating to open access shall be made to the State Load

Dispatch Centre, which may investigate and endeavour to resolve the grievance within 30

days, and

Where State Load Dispatch Center is unable to resolve a grievance, Grid Code Review

Committee constituted under Grid Code shall endeavour to resolve the grievance within

30 days, and

Where Grid Code Review Committee is unable to resolve the grievance in the time

period specified above, it shall be referred to the Commission.

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The responsibilities assigned to the State Load Dispatch Centers for formulation of

procedures, guidelines and application forms under these Regulations shall be

coordinated by the State Transmission Utility.

Powers to Remove Difficulties

If any difficulty arises in giving effect to any of the provisions of these Regulations, the

Commission may by general or special order, direct the State Transmission Utility, State Load

Dispatch Centre, licensees and the open access user, to take such action, as may appear to the

Commission to be necessary or expedient for the purpose of removing difficulties.

Operationalization of Open Access

Open Access will require implementation of the Intra-State Availability Based Tariff (ABT)

System. Installation of ABT compliant metering system, Discom-wise Area Load Dispatch

Centre and procedure for energy accounting and commercial settlement.

For oprationalisation of open access, the STU and SLDC shall furnish report on these matters to

the Commission not later than 30th November, 2005.

9.2. Procedure for Scheduling of Short-Term Open Access

(Bilateral Transaction as on 20.05.2009)

OUTLINE

1. This Procedure is in accordance with the various provisions of the “Central Electricity

Regulatory Commission (Open Access in inter-State Transmission) Regulations, 2008”, dated

25.01.2008, and subsequent amendments thereof hereinafter referred to as “the Regulations”.

2. The Procedures shall apply to the Applications made for scheduling of Bilateral Transactions

by availing of Short-Term Open Access for use of the transmission lines or associated facilities

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with such lines on the inter-State transmission system, received by the nodal RLDC on or after

15.06.2009.

3. All Applications received up to the date and time lines specified in “the Regulations” shall be

taken up together for consideration. For Applications Received before 15.06.2009, the short-term

open access charges shall be applicable as per CERC (Open Access inter-State Transmission)

Regulations, 2008. For Applications Received on or after 15.06.2009, the short-term open access

charges shall be applicable as per CERC (Open Access inter-State Transmission) (Amendment)

Regulations, 2009.

4. For the Applications (under Advance Scheduling/ First cum First Served basis) received till

17:30 Hrs of 14.06.2009, the short-term open access charges shall be as per the original CERC

(Open Access inter-State Transmission) Regulations, 2008. Similarly for Day-ahead scheduling,

the applications received till 15:00 HRs of 14.06.2009, the short-term open access charges shall

be as per the principal CERC (Open Access inter-State Transmission) Regulations, 2008. For

Applications (under “Contingency” category) received till 24:00 HRs of 14.06.2009, the short-

term open access charges shall be as per the principal CERC (Open Access inter-State

Transmission) Regulations, 2008.

For example:

An applicant “X” has submitted an Application on 13.06.2009 for Advance Scheduling of Short-

Term Open Access Bilateral Transaction for the month of August 2009 form 05.08.2009 to

25.08.2009. Another applicant “Y” has submitted an Application on 15.06.2009 for Advance

Scheduling of Short-Term Open Access Bilateral Transaction for the month of August 2009 form

01.08.2009 to 20.08.2009.The nodal RLDC shall consider both the Applications together. In case

of Applicant “X”, the short-term open access charges shall be as per CERC (Open Access inter-

State Transmission) Regulations, 2008 and in case of Applicant “Y”, as per the Amendment

Regulation, 2009.

6. No retrospective adjustments for short-term open access charges shall be made for the already

approved short-term open access bilateral transactions.

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SUBMISSION OF APPLICATION

1. An Application for scheduling of Bilateral Transaction through Short-Term Open Access in

the inter-State transmission system shall be made to the Regional Load Dispatch Centre of the

Region where point of drawl of electricity is situated.

2. The Application for scheduling of a Bilateral Transaction shall contain the details, such as

names and location of Supplier and Buyer, contracted power (MW) at the supplier interface,

point of injection, point of drawl, starting time block and date, ending time block and date, and

other information as per the enclosed format [FORMAT-I: “Application for Scheduling”].

3. An Application made for each Bilateral Transaction shall be accompanied by a non-refundable

fee as specified in the Regulations. Provided that the fee for Bilateral Transaction on the day of

the Application or on the day immediately following the day of the Application may be

deposited within three working days of submission of the Application.

4. A copy of the Application shall be endorsed by the applicant to the following:

a) Each RLDC involved in the transaction.

b) Each SLDC involved in the transaction.

CONCURRENCE OF STATE LOAD DESPATCH CENTRE

1. Wherever the proposed Bilateral Transaction has a State Utility or an intra-State Entity as a

Buyer or a Seller, concurrence of the concerned State Load Dispatch Centre shall be obtained in

advance and submitted along with the Application. The Concurrence of the concerned SLDCs

shall be submitted as per the enclosed format [FORMAT-II: “Concurrence from SLDC”].

2. Where “concurrence” or ‘no objection’ or “prior standing clearance”, as the case may be, is

deemed to have been granted by the concerned SLDC in accordance with clause 4 of the

Regulation 8, the applicant while making application for Scheduling of Bilateral Transactions

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shall submit to the nodal agency an affidavit, duly notarized, as per the enclosed format.

[FORMAT-II A: “AFFIDAVIT – regarding Deemed Concurrence from SLDC”]

3. Application(s) without the concurrence of concerned SLDCs will not be considered, except in

case of “Concurrence” or ‘No Objection’ or “Prior Standing Clearance”, as the case may be, is

deemed to have been granted by the concerned SLDC in accordance with the second proviso to

clause 4 of Regulation 8. In case of deemed concurrence, the Applicant must ensure that all the

requirements under Regulation 8 have been duly complied with and submit the Application for

scheduling of Bilateral Transactions along with the duly notarized affidavit as per FORMAT –

IIA. The Applicant shall serve a copy of the Affidavit along with the copy of the Application

being endorsed to the concerned SLDC.

CONCURRENCE OF REGIONAL LOAD DESPATCH CENTRE

1. Wherever the proposed Bilateral Transaction has a State Utility or an intra-State Entity as a

Buyer or a Seller in other region, the Nodal RLDC shall obtain concurrence of the concerned

Regional Load Dispatch Centre(s). The concurrence of the Regional Load Dispatch Centre shall

be as per enclosed format [FORMAT-III: “Request/Concurrence from RLDCs”].

2. RLDC shall first consider the Applications received by them, as nodal Agency, before giving

concurrence / indicating constraint, to other RLDCs, for the Applications received, by the later.

3. In case of denial of access, the RLDC concerned shall furnish reasons for the same, in writing.

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PROCEDURE FOR ADVANCE SCHEDULING OF BILATERAL

TRANSACTION

1. An Application for Advance Scheduling for a Bilateral Transaction may be submitted to the

nodal RLDC up to the fourth month, considering the month in which an Application is made

being the first month.

2. A separate Application shall be made for each month and for each transaction in a month in a

suitable cover marked “Application for Short-Term Open Access - Advance Scheduling for -

<<Month-Year’s name>>”.

3. (a) An Application for inter-State scheduling during the fourth month shall be made up to the

last day of the first month.

(b) An Application for inter-State scheduling during the third month shall be made up to the five

(5) days prior to the close of the first month.

(c) An Application for inter-State scheduling in the second month shall be made up to the ten

(10) days prior to the close of the first month.

4. All the Applications received up to 17:30 Hrs on the last day as mentioned above shall be

taken up together for consideration. Applications received after prescribed time shall not be

considered.

5. While processing the Applications, the Nodal RLDC shall seek the concurrence of each of the

other RLDCs involved in the transaction by 12:00 Hrs. on next day of the applicable last date for

submission of Application.

6. The other RLDCs shall give their concurrence/denial latest by 20:00 Hrs on the same day on

which request for concurrence is sent by the nodal RLDC.

7. In case of perceived congestion in transmission corridor, nodal RLDC on next day (i.e. 2nd

day after the applicable last date for submission of Application) will inform the concerned

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applicant(s) as per enclosed format [FORMAT-IV: “Congestion Information-Advance

Scheduling”] latest by 12:00 Hrs. By next day (i.e.; 3rd day after applicable last date for

submission of Application) latest by 11:00 Hrs, the Applicants must inform the nodal RLDC as

per enclosed format [FORMAT-V: “Request for Revision of Schedule- Due to Congestion”], the

reduced request for Scheduling during the period of Congestion or opt for Scheduling only for

the duration when no congestion is anticipated or opt for Scheduling through the alternate route.

In case of non-receipt of revised request in time, it shall be presumed that the Applicant is not

interested in revising it and nodal RLDC shall process the Application accordingly.

8. In case, the nodal RLDC still anticipates Congestion, it may invite electronic bids for advance

scheduling on 4th day after applicable last date for submission of Application.

9. The nodal RLDC shall convey its acceptance or otherwise to the Applicant in five days from

the last date of submission, as per enclosed format [FORMATVI: “Acceptance for Scheduling”].

In case, the nodal RLDC rejects an application ,it shall convey its reasons to the Applicant in

writing.

e-BIDDING PROCEDURE.

1. Bids shall be invited, from the concerned Applicants, for only such period during which

congestion is expected to occur and for the Regional transmission system or inter-Regional

corridor, whichever is expected to get over stressed.

2. The decision of the nodal RLDC in respect of an expected congestion shall be final and

binding.

3. Any Applicant intending to participate in bidding for Short-Term Open Access shall register

and obtain the “User ID” and initial “Password” in advance from the RLDC for its Authorized

User(s). The “Registered Users” will be issued a system generated “User ID” and initial

“Password’ by RLDC to enable them to submit their ‘Bid’ electronically. Upon receipt of the

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User Id and initial password, the User shall immediately change the password. It shall be the

responsibility of such Applicant to maintain its confidentiality/security and to prevent its misuse.

4. The Applicants shall submit their ‘Bid’ electronically through the web site of the CTU/

RLDCs. Only the Applicants, through their “Registered Users”, shall be entitled to submit a Bid.

5. The Bids shall be accepted up to the “bid closing time” as indicated on the website of

CTU/RLDCs, designated for e-bidding. Modification / amendment to a bid, once submitted,

including submission of a second or subsequent bid by an Applicant, shall not be entertained.

6. In case the Applicant does not participate in the e-bidding process, his Application shall be

considered as withdrawn.

7. Bidding process and the Approval of the Schedules of the bidders shall be as per following:

The bid price shall be in addition to the Transmission Charges for Bilateral Transactions

as specified in the Para 16 of the Regulations.

The Bidder shall quote price in terms of Rs./MWh in multiples of 10. The minimum price

a bidder may quote is Rs. 10/MWh.

Approval of Short-Term Open Access for Advance Scheduling will be accorded in the

decreasing order of price quoted.

In case of equal price quoted by two or more successful bidders, the approval for

scheduling shall be made pro-rata to the scheduling request sought by them.

The Applicant, which gets approval for scheduling less than the scheduling request

sought by him, shall pay the charges quoted by him. The Applicant getting approval for

scheduling equal to the scheduling request sought by him shall pay the charges quoted by

the last Applicant getting approval of its full scheduling request.

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PROCEDURE FOR SCHEDULING OF BILATERAL TRANSACTION

ON “FIRST-COME-FIRST-SERVED” BASIS

1. An Application shall be submitted to the nodal RLDC in a cover marked “Application for

scheduling on - First-come-first-served basis”.

2. Application received under the following categories shall be treated as “First-Come-First-

Served” application:-

i. Application received under “First Come First Served” category for Short-Term Open Access

shall be considered only when transactions are commencing and terminating in the same

calendar month.

ii. Application for scheduling a Bilateral Transaction which is commencing in the same month in

which Application is made, provided that such Application is received at least four (4) days in

advance from the date of commencement of the Bilateral Transaction. All such Application shall

be processed and decided within three days of their receipt.

iii. Application received during the last ten (10) days of the first month, for scheduling of

transactions in the second month. These Applications would be considered after completing the

process for Advance scheduling of Bilateral Transaction in the second month. Accordingly,

Applications received up to five (5) days prior to the end of the month shall be processed only

after completing the process for Advance Scheduling of Bilateral Transactions for the second

month.

3. All Applications received by the Nodal RLDC in a day up to 17:30 hrs shall be considered

together for processing and shall have same priority. Applications received by the nodal RLDC

after 17:30 hrs of a day shall be treated as having /been received on next day.

4. Pro-rata scheduling acceptance shall be given in case scheduling requests of the Applicants is

for more than the margins available.

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PROCEDURE FOR SCHEDULING OF DAY-AHEAD BILATERAL

TRANSACTION

1. Applications received within three days prior to the date of scheduling and up to 15:00 Hrs. of

the day immediately preceding the day of scheduling shall be treated as having been received

together for processing and shall have same priority.

2. Applications for Day Ahead transactions shall be processed only after processing of the

Collective Transactions of the Power Exchange(s).

3. Pro-rata scheduling acceptance shall be given in case scheduling requests of the Applicants is

for more than the margins available.

PROCEDURE FOR SCHEDULING OF BILATERAL TRANSACTION

IN A CONTINGENCY

1. In the event of a contingency, the buyer or in its behalf, a trader may locate, and the power

exchange may offer its platform to locate, a source of power to meet short-term contingency

requirement and make an Application to the Nodal RLDC.

2. Nodal RLDC shall accept such Application only after 1500 hrs of the day immediately

preceding the day of scheduling.

3. Nodal RLDC shall take steps to incorporate such Bilateral Transactions in Day Ahead

schedules/same -Day schedules, as the case may be. In case of Same Day, the transaction shall

be scheduled from the 6th time block, counting the block in which acceptance is accorded as the

first time block.

4. Pro-rata scheduling acceptance shall be given in case scheduling requests of the Applicants is

for more than the margins available.

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INCORPORATION OF BILATERAL TRANSACTIONS IN DAILY

SCHEDULES BY THE RLDCs

1. RLDCs shall incorporate the Bilateral Transactions (as per the acceptance accorded) in the

Daily Schedules of the Regional Entities. The concerned SLDCs shall also incorporate such

inter-State transactions to / from the point of injection / drawl in the Daily schedules issued by

them.

2. The average energy losses shall be applied, as estimated on weekly basis, by Regional Load

Dispatch Centre for regional transmission system and as displayed in their respective website.

For State transmission system, losses shall be applied as specified by the respective State Load

Dispatch Centre. The losses in the system shall be compensated by less drawl by the Drawee

Utility. The net drawl schedule for Buying Utility will be the drawl schedule minus the estimated

losses in the involved transmission system.

3. While finalizing the net drawl schedule / net injection schedule of Entities, each transaction

will have a resolution of 0.01 MW at each State/inter-Regional boundaries.

4. The ramp-up and ramp-down if required, in the Daily Schedules (issued by the RLDC) on

account of such transactions, shall commence at the time of commencement of the transaction

and shall end at the time of termination of the transaction respectively.

REVISION OF SCHEDULE

1. The Short-Term Open Access Schedules accepted by the Nodal RLDCs in case of “Advance

Scheduling” or “First-Cum-First Served basis” may be cancelled or revised downwards by the

Applicant by giving minimum two (2) days notice. The notice period shall be excluding the day

on which notice is served and the day from which revised schedules are to be implemented.

2. The accepted schedules for Day-Ahead transactions and transactions in a Contingency shall

not be revised or cancelled.

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3. The Applicant, who has requested for revision or cancellation of the accepted schedule as

above, shall pay the Transmission Charges and Operating Charges as per the originally accepted

schedule, if the period of revision or cancellation is up to two (2) days. If the period of revision

or cancellation exceeds two(2) days, the Transmission Charges and Operating Charges for the

period beyond two (2) days shall be payable as per the revised accepted schedule and for the first

two (2) days as per the original schedule.

For example: Say an Applicant has been scheduled for 10 days from 21st day of a month to 30th

day of a month for 100 MW on round the clock basis (i.e. for 2400 MWh per day). If this

Applicant, on or before 18th day of that month, submits request for revision of schedule to 50MW

on round the clock basis (i.e. 1200 MWh per day), the revised schedule will get implemented

from the beginning of the transactions (i.e. 21st day of the month). The Applicant shall pay the

Transmission Charges for 2400 MWh per day for the period from 21st to 22nd day of the month

whereas for the period from 23rd day to 30th day of the month, Transmission Charges shall be

payable for 1200MWh per day. However, if the Applicant requests for such revision on 20th day

of the month, his request will be implemented from 23rd day of the month. He shall pay

Transmission charges for 2400 MWh per day for 2 days i.e. from 23rd to 24th day of the month

and for the remaining period he shall pay the Transmission Charges based on 1200MWh per

day.

4. The margins becoming available as a result of such revision or cancellation shall be available

for scheduling to any other Applicant in accordance with relevant provisions of Regulations on

Open Access.

5. The short-term customers granted short-term open access prior to 15.06.2009 shall also be

eligible for Cancellation/downward revision of Schedule by giving two days notice and by

paying minimum two days transmission charges as per Regulation 15. The refund of

transmission charges shall be in accordance with the rate at which the transmission charges were

paid by the respective customer.

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CURTAILMENT IN CASE OF TRANSMISSION CONSTRAINTS

1. Bilateral Transactions shall be reduced or cancelled by the Regional Load Dispatch Centre, if

the Central Government allocates power from the Central Generating Station or Stations in a

Region to a person in another Region and such allocation, in the opinion of the Regional Load

Dispatch Centre, cannot otherwise be implemented due to Congestion in the inter-Regional

corridor. In the event of reduction or cancellation of already accepted schedules of Bilateral

Transactions, the Applicant shall be suitably intimated by the RLDC.

2. When because of transmission constraint or to maintain grid security as decided by RLDC, it

becomes necessary to curtail power flow on a transmission corridor, the transactions already

scheduled, would be curtailed in the manner, which in the opinion of RLDC, would relieve

transmission constraints/ enhance grid security. Subject to the provisions of the Grid Code, while

cancellation or curtailment of any transaction, among short-term, medium term and long-term

transactions, short-term transactions shall be cancelled or curtailed first, followed by medium

term and thereafter long-term transactions. Short-Term Open Access Bilateral Transactions

would be curtailed first followed by the Collective Transactions.

3. In case of transmission constraint or otherwise when Long Term Customer’s power from one

Region to another needs to be re-routed through the third Region, RLDC shall allow such re-

routing to the extent of the surplus margin available without curtailing the existing Long-Term,

Medium Term and Short- Term Open Access transactions.

4. In case of curtailment of the accepted schedules for any particular day for the reasons of

transmission constraints or due to allocation of power from Central Generating Station from one

Region to the person in other Region, the Transmission Charges for that day shall be payable on

pro-rata basis in accordance with the transactions finally scheduled. Provided that the Operating

Charges shall not be revised in case of curtailment.

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COMMERCIAL CONDITIONS FOR BILATERAL TRANSACTION

The following commercial conditions shall apply for the Bilateral Transaction:

TERMS OF PAYMENT

1. All payments associated with Bilateral Transaction shall be made by the Applicant to the

Nodal RLDC.

2. The Applicant shall make the following payment to the Nodal RLDC within three working

days from the date of acceptance of Bilateral Transactions. The charges for scheduling of

Bilateral Transactions will be worked out on the basis of total MWh approved at the point of

injection.

a) Application Fees (as per Para 7 of Regulation)

An Application made for each Bilateral Transaction shall be accompanied by a non-refundable

fee of Rupees five thousand (Rs.5000/-) only. Provided that the fee for Bilateral Transaction on

the day of the Application or on the day immediately following the day of the Application may

be deposited within three working days of submission of the Application.

b) Transmission charges (as per Regulation 16)

Full amount for the entire period of Bilateral Transaction, in respect of the following:

Regional Transmission systems involved

STU/SEB/transmission licensees involved

c) Operating charges (as per Regulation 17)

Operating Charges at the rate of Rs.2000/- per day or part of the day of each for the entire period

of Bilateral Transaction in respect of the following:

Each RLDC involved

Each SLDC involved

4. The Transmission charges for the use of the inter-State network shall be in Rs./MWh

depending upon the type of transaction and shall be payable by the short-term customer for the

energy approved at the point or points of injection. The rate for transmission charges shall be as

follows:

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Type of Transaction Transmission Charges (Total) Rs/MWh

(a) Bilateral, intra-regional 80

(b) Bilateral, between adjacent region 160

(c) Bilateral, wheeling through one or more region 240

4. The Transmission charges for the use of the State network shall be in Rs/MWh, as determined

by the respective State Commission and the same shall be intimated to RLDCs by concerned

STU. Provided that in case the State Commission has not determined the Transmission charges,

the charges for use of the respective State network shall be payable at the rate of Rs.80/MWh for

the energy approved.

5. In case a State utility is the Buyer/Seller, the Operating Charges and the Transmission Charges

shall not include the charges for that State network and the Operating Charges for that State Load

Dispatch Center. A certificate in this regard from the concerned STU(s)/SLDCs shall be

submitted by the Applicant.

6. All payments shall be remitted only by Bank draft/cheque drawn in favour of

“_________RLDC Short Term Open Access Account” payable at par at the location of the

Nodal RLDC or by electronic transfer. No outstation cheques will be accepted.

7. The transaction wise payment details shall be submitted as per enclosed format [FORMAT-

VII: “Details of Payment”].

DEFAULT IN PAYMENT OF SHORT-TERM OPEN ACCESS CHARGES

1. In case of default in payment of the Application fee or the charges specified under the

Regulations specified by CERC, the nodal RLDC, at its discretion may not schedule the

transaction or may cancel the scheduling of already scheduled transaction or may not entertain

any Application of such Applicant in future until such time the default is cured.

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2. The Applicant committing default in payment shall pay the simple interest at the rate of 0.04

% for each day of default from the Due Date of Payment.

3. In case a payment made by the Applicant through cheque has been dishonored, the Applicant

shall immediately pay the amount due by demand draft or electronic transfer and no further

cheque payment will be accepted from that Applicant for next three (3) months.

DISBURSAL OF PAYMENT

1. Nodal RLDC will reconcile the Short-Term Open Access Charges collected during the

previous month and disburse the Transmission Charges and Operating Charges within 7 working

days from the issuance of monthly Regional Energy Accounting by the respective Regional

Power Committees.

2. The Transmission Charges for use of State network and Operating Charges for SLDCs shall be

disbursed to the State Transmission Utility/SLDC concerned, after receiving the same from the

Applicants.

3. Transmission charges collected for use of the transmission system other than that of the State

network shall be disbursed by nodal RLDC to the RLDCs of the respective Region. The 25% of

the Transmission Charges collected for use of the transmission system other than the State

network shall be disbursed to CTU and balance 75% shall be disbursed to long-term customers

through the RLDC of the respective Region in accordance with Regulation 25.

4. In case of refunds arising due to curtailment/revision of transactions during the previous

month, the same shall also be disbursed to the concerned Applicants by 15th day of the current

month.

5. Nodal RLDC does not have any responsibility towards non-payment as well as dishonoring of

cheque(s) submitted by the Applicants. The amounts actually collected by RLDCs shall only be

disbursed.

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GENERAL CONDITIONS

1. The Entities which are making Application for the first time or intend to make, must submit

the “One- Time” information as per enclosed format. [FORMATVIII: “Registration Form] to the

concerned nodal RLDC. In case of any change in the existing information, the same shall be

intimated to the concerned nodal RLDC.

2. The Application for Bilateral Transactions can be submitted through Post/fax.

3. Any amendment/modification to an existing Application, except for reasons specifically

mentioned in the Procedure, shall be treated as a fresh Application.

4. The Nodal RLDC shall issue transaction-wise scheduling acceptance from:

I. The point of injection of a Seller to the injecting State’s periphery (control area boundary)

as confirmed by the concerned SLDC, and

II. From the periphery (control area boundary) of injecting State up to the periphery (control

area boundary) of the Drawee State as confirmed by the concerned RLDCs.

III. From the periphery (control area boundary) of the Drawee State to the point of drawl of

Buyer as confirmed by the concerned SLDC.

5. The Applications of the Applicants, who have not been accorded the Acceptance for

Scheduling of Bilateral Transactions, shall stand disposed off with suitable intimation to the

concerned Applicant(s).

6. All costs/expenses/charges associated with the Application, including Bank Draft, shall be

borne by the Applicant.

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7. An incomplete/vague Application, and an Application not found to be in conformity with

these Procedures and Regulations, shall be summarily rejected.

8. None of charges payable by Applicant(s) and/or any other Entities involved in the transaction

shall be adjusted by them against any other payments/charges.

9. The Applicant shall abide by the provisions of The Electricity Act, 2003, Indian Electricity

Grid Code and CERC Regulations, as amended from time to time.

10. The Applicant shall keep each of the SLDCs/ RLDCs indemnified at all times and shall

undertake to indemnify, defend and save the SLDCs/RLDCs from any and all damages, losses,

claims and actions including those relating to injury or death of any person or damage to

property, demands, suits, recoveries, costs and expenses, court costs, attorney fees, and all other

obligations by or to third parties, arising out of or resulting from the transactions.

9.4. Requirements of being an Electricity Trader

As per the CERC guidelines the following are the requirements of being an electricity trader-

Qualifications

1. Qualification of domicile

The applicant shall be a citizen of India, or a partnership firm registered under

the Partnership Act,1932 or a company incorporated under the Companies

Act, 1956 or an association or body of individuals who are citizens of India

whether incorporated or not or an artificial juridical person recognized under

the Indian Laws.

2. Technical Qualifications

The applicant shall have at least one full time professional having,

qualifications and experience in each of the following disciplines, namely-

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Discipline Qualifications and experience

a) Power system operations Degree in Engineering with at least 10

And commercial aspects years experience in the field.

of power transfer

b) Finance, Commerce and CA/ICWA/MBA(Finance) with at least

Accounts 5 years experience in the field

3. Capital adequacy and liquidity requirements

a) Considering the volume of inter-state trading proposed to be undertaken,

the net worth of the applicant for three years immediately preceding the

year in which the application is made or such lesser period during which

the applicant may have been incorporated, registered or formed and on the

date of special balance sheet accompanying the application, shall not be

less than the amounts specified hereunder.

b) The applicant shall have minimum current ratio of 1:1 and liquidity ratio

of 1:1 consistently for three years immediately preceding the year in which

the application is made or such lesser period as may be applicable, and on

the date of special balance sheet accompanying the application.

Disqualifications

The applicant shall not be qualified for grant of license if-

a) The applicant or any of his associates, or partners, or promoters, or Directors

is an un-discharged insolvent; or

b) The applicant or any of his associates, or partners, or promoters, or Directors

has been convinced of an offence involving moral turpitude, fraud, or any

economic offence during the year of making the application or three years

immediately preceding that year and a period of six months has not elapsed

since his release from imprisonment, if any, consequent to such conviction; or

c) An order cancelling the license of the applicant or any of his associates, or

partners, or promoters, or Directors has been passed by the Commission; or

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d) The applicant holds a license for transmission of electricity; or

e) The applicant or any of his associates, or partners, or promoters, or Directors

has in the past been-

i. Refused a license on the grounds which continue to remain valid; or

ii. Found guilty in any proceedings for non compliance of any of the

provisions of the act or the rules or the regulations made there under or

an order made by the Appropriate Commission, during the year of

making the application or five years immediately preceding that year;

or

iii. The applicant is not considered a fit and proper person for the grant of

license for any other reason to be recorded in writing. It is decide

based on the person’s reputation and character or his efficiency and

honesty or his competence or the financial integrity of the applicant.

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Chapter 10: Findings and Observations

A Market Monitoring Cell (MMC) was set up in CERC in August 2008. As advised

by the Steering Committee of MMC, MONTHLY REPORT ON SHORT-TERM

TRANSACTIONS OF ELECTRICITY is prepared. Here, the “short-term transactions of

electricity” includes the electricity transacted through Trading Licensees, Power Exchanges and

Unscheduled Interchange.

10.1. Volume of Short-term Transactions of Electricity

During the Month of March 2009, total electricity generation excluding generation from

renewable sources and captive power plants in India was 64841.89 MUs. Of the total electricity

generation, 4248.55 MUs (6.55%) transacted through short-term i.e. 1941.68 MUs (2.99%)

through Bilateral (through traders and direct between distribution companies), followed by

1878.26 MUs (2.90%) through Unscheduled Interchange (UI) and 428.61 MUs (0.66%) through

Power Exchanges (IEX and PXIL). Of the total short-term transactions, Bilateral constitute

45.70% (39.93% through traders and 5.77% direct between distribution companies) followed by

44.21% through UI and 10.09% through Power Exchanges. The percentage share of electricity

traded by each trading licensee in the total volume of electricity traded by all trading licensees is

provided in. Here the volume includes the volume traded by licensees through power exchanges

also. There are 41 trading licensees as on 31.3.2009, however only 12 licensees are undertaking

trading during March 2009. Top 5 trading licenses are having share of 85.65% in the total

volume traded by licensees. The volume of electricity transacted through IEX and PXIL was

377.17 MUs and 51.44 MUs respectively. The volume of total Buy bids and Sale bids was

719.68 MUs and 640.90 MUs respectively in IEX and 67.29 MUs and 82.04 MUs respectively in

PXIL. The gap between the volume of buy bids and sale bids placed through power exchange

shows that there was more demand (1.12 times) when compared with the supply offered through

IEX and it was less demand (0.82 times) when compared with the supply offered through PXIL.

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Table 3. Volume of Short Term Transactions of Electricity in India

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e

Volume of Short Term Transactions of Power in India

Table 4. Volume of Short term Transactions of Power in India in %

10.2. Price of Short-term Transactions of Electricity

(1) Price of electricity transacted through Traders: Weighted average sale price has been

computed for the electricity transacted through traders and it was Rs.7.43. The weighted average

sale price also computed for the transactions during Round the clock (RTC), Peak and Off-Peak

periods separately and the sale price was Rs.7.35, Rs.8.08 and Rs.7.53 respectively. Minimum

and Maximum sale price was Rs.2.44 and Rs.11.69 respectively.

(2) Price of electricity transacted Through Power Exchange: The Minimum,

Maximum and Weighted Average Price has been computed for the volume transacted through

IEX and PXIL separately. The Minimum, Maximum and Weighted Average Price was Rs.0.60,

Rs.13.10 and Rs.8.33 respectively in IEX and Rs.0.00, Rs.13.10 and Rs.8.54 respectively in

PXIL.

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Fig 10. Price of power transacted through PX

(3) Price of electricity transacted Through UI: All-India UI price has been computed for NEW

Grid and SR Grid separately. The average UI price was Rs.4.85 in the NEW Grid and Rs.8.20 in

the SR Grid. The power deficit is more in the Southern Region when compared with other

regions; therefore, the UI price was higher in the SR Grid when compared with the UI price in

the NEW Grid. Minimum and Maximum price of UI was Rs.0.24 and Rs.10.00 respectively in

the New Grid and Rs.0.00 and Rs.10.00 respectively in the SR Grid.

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Fig 11. Price of power transacted through UI

Fig 12. Price of short term transactions of electricity

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Table 5. Price of Short term Transactions of Electricity

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10.3. Volume of Short-term Transactions of Electricity (State-Wise)

Of the total bilateral transactions, top 5 states selling 68.78% of the volume are Jindal

Power Ltd, Chhattisgarh, Delhi, Punjab and Haryana and top 5 states purchasing 71.07% of

the volumes are Rajasthan, Madhya Pradesh, Tamil Nadu, Andhra Pradesh and Karnataka.

Of the total Power Exchange transactions, top 5 states selling 86.68% of the volumes are Gujarat,

Chhattisgarh, Delhi, Rajasthan and West Bengal and top 5 states purchasing 99.50% of the

volume are Andhra Pradesh, Tamil Nadu, Maharashtra, Rajasthan and Karnataka. Of the total UI

transactions, top 5 states exporting 53.58% of the volume are Chhattisgarh, Delhi, Madhya

Pradesh, Gujarat and West Bengal and top 5 states importing 48.92% of the volumes are

Haryana, Maharashtra, Uttar Pradesh, Andhra Pradesh and Tamil Nadu. State-wise total net

short-term transactions of electricity i.e. volume of net transactions through bilateral, power

exchange and UI was shown in Table-13. Top 5 states those selling electricity are Chhattisgarh,

Delhi, Jindal Power, Gujarat and West Bengal and top 5 states those purchasing electricity are

Andhra Pradesh, Tamil Nadu, Rajasthan, Madhya Pradesh and Karnataka.

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Table 6. Volume of Short Term Transactions of Electricity (State-wise)

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Percentage share of Electricity traded by trading licensees during March 2009

Table 7. Percentage share of Electricity traded by trading licensees during March2009

Key findings/Observations:

• The percentage of short-term transactions of electricity to total electricity generation was

6.55%.

• Of the total short-term transactions of electricity, 45.70% transacted through bilateral

(Through traders and directly by distribution companies) followed by 44.21% through UI and

10.09% through Power Exchanges.

• Top 5 trading licenses are having share of 85.65% in the total volume traded by licensees.

• The price of electricity transacted through trading licensees is comparable with the price of

electricity transacted through Power Exchanges and UI. The price range was between Rs.7.43 -

Rs.8.54 per KWh.

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• The gap between the volume of buy bids and sale bids placed through power exchange shows

that there was more demand (1.12 times) when compared with the supply offered through IEX

and it was less demand (0.82 times) when compared with the supply offered through PXIL.

• Top 5 states those selling electricity are Chhattisgarh, Delhi, Jindal Power, Gujarat and

West Bengal and top 5 states those purchasing electricity are Andhra Pradesh, Tamil Nadu,

Rajasthan, Madhya Pradesh and Karnataka.

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Chapter 11: Conclusion

Power trading in India reached new heights with the evolution of the power exchanges in 2008.

The trading of power has become more convenient with the help of these exchanges. The

implementation of the Electricity Act, 2003 has also played a major role in making this possible

as it makes the trading of power across regions a licensed activity. The trading of power was also

prevalent before the existence of the exchanges but the level of risk was more in those

agreements. The exchanges mitigate these risks and assure the traders of their returns. As far as

the bilateral agreements are concerned they are helpful for buying or selling power at a future

date regardless of what the price is at that particular time. This way the traders can mitigate the

risks as well.

Although there are a lot of benefits from short term power trading, there is still a long way to go.

There is no technical barrier as such in making the electricity market more flexible. Shortening of

the time between the clearing of the market and the delivery can also be looked into for quick

and efficient supply. Moreover, the procedure of bidding in IEX is a bit complex as compared to

PXI. The concept can be made simpler so that it is more user-friendly. The exchanges are also

coming up with term-ahead markets which can be a week ahead or month ahead. This is an

important step in the development of exchanges towards month ahead and week-ahead markets.

The exchanges can also take important lessons from international markets like those in Europe or

the NORD Pool etc. This is because the international markets had to face a lot of hindrances in

the initial stages and they successfully dealt with all these problems. All this will not only make

the power system of the country effective but will also improve the growth of the power sector in

the country.

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BIBLIOGRAPHY

1. Ministory of power india

2. CERC Regulations on Unscheduled Interchange as on 1st April 2009

3. 11th Planning Commission Report on Energy, India

5. National Energy Map for India: Technology Vision 2030 by TERI, India

6. Regulations on connectivity and Short term Open access by CERC, India

7. Annual Report of Central Electricity Authority, India for 2007-2008

8. ABC of ABT Primer on availability Tariff by Bhanu Bhushan

9. Guidelines for Determination of Tariff by Bidding Process for Procurement of Power by

Distribution Licensees ; issued by Government Of India

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