SUMMER INTERNSHIP REPORT
ON
“SHORT TERM MARKET ANALYSIS UPON
DEMAND, SUPPLY CORRIDER AVAILABILTY OF LAST THREE
FINANCIAL YEAR”
UNDER THE GUIDANCE OF
Mr MANOJ RASTOGI, Associate Vice President, Power Sales
At
STERLITE ENERGY LIMITED
(SUBSIDIARY OF VEDANTA RESOURCES)
Submitted
By
Swagat Kumar Panigrahi
Regd no- 12NPTIF0072
Roll no-91
Batch 11th(2012-2014)
MBA power management
Affiliated to
ACKNOWLEDGEMENTS
I am having great pleasure to present this report titled “SHORT TERM MARKET ANALYSIS UPON
DEMAND, SUPPLY CORRIDER AVAILABILTY OF LAST THREE FINANCIAL YEAR”. I take this
opportunity to express my sincere thanks and gratitude to all who contributed to make this a success.
I thank my Project guide Mr. Manoj Rastogi, Associate vice president, Sterlite energy Limited, for giving
me the opportunity to work on such an insightful project.
I would like to extend my thank to Mr. Pulak Srivastav, Associate Manager who imparted me with his
valuable guidance during the internship period.
I would also thank Mr Kewal Hariram Kurmi ,Associate Manager for constantly guiding and solving all
my queries throughout this project.
Special thanks go to all the staff members of STERLITE ENERGY LTD Without their insights and
helpful thoughts, I would not have gained as much information as I have. Their help has sparked my interest
even more! Thanks!
I wish to express my deep sense of gratitude to my Internal Guide ,Miss Karishma verma (senior fellow) ,
NPTI for her able guidance and useful suggestions, which helped me in completing the project work, in
time. I also, thank Mr. S.K. Chaudhary, Principal Director (CAMPS), NPTI , Mrs. Manju Mam,
Director (MBA), NPTI, Mrs. Indu Maheshwari (Dy.Director) and Miss Farida Khan, Asst. Director,
NPTI for providing constant support and assistance whenever required.
DECLARATION
I, SWAGAT KUMAR PANIGRAHI, Reg. No12NPTIF0072. student of III semester M.B.A (Power
Management, 2012-2014 of the National Power Training Institute, Faridabad hereby declare that the
Summer Training Report entitled “SHORT TERM MARKET ANALYSIS UPON DEMAND, SUPPLY
CORRIDER AVAILABILTY OF LAST THREE FINANCIAL YEAR” is an original work and the same
has not been submitted to any other Institute for the award of any other degree.
A Seminar presentation of the Training Report was made on 30-08-2013 and the suggestions as approved
by the faculty were duly incorporated.
Date:
Place: Faridabad, Haryana
Project Guide
Signature of the
(Sterlite Energy Ltd)
candidate
Countersigned
Director/Principal of the Institute
EXECUTIVE SUMMARY
Power trading in India accounts for 9% of the net generation. Trading basically involves unscheduled
exchange, bilateral trading and trading through power exchange. Unscheduled exchange accounts for around
40-45% of the total power traded, followed by 40-43% bilateral trade and rest through power exchanges.
The proportion of unscheduled power exchange is expected to decline in coming years due to Power
Ministry continuous effort to maintain grid discipline. In bilateral trade there are sub-sections like short term
trading, medium and long term trading and cross border trading.
This Report comprises of an effort to study and analyse the Indian power market scenario and also power
market size and structure. In this report I have studied region wise demand and availability of power which
help to determine the power surplus region.
Through this study I analysed inter & intra-regional bilateral transaction that took place among five regions,
day ahead & weekly market analysis of power exchange & tried to identify prospective buyer for financial
year 2013-14 & that enables the firm to make its long and short term strategy in power sales.
Through the study I able to know quantity of power that was being traded in different regions of India and
also the rate and trading margin gained from the transaction.
TABLE OF CONTENTS
ACKNOWLEDGEMENT
DECLARATION
EXECUTIVE SUMMARY
LIST OF TABLES
1.INTRODUCTION
1.1 INDIAN POWER MARKET SCENARIO
1.2 POWER TRADING IN INDIA
1.3 OBJECTIVE OF THE PROJECT
1.4 SCOPE OF THE PROJECT
1.5 ABOUT THE ORGANISATION
2 LITERATURE REVIEW
2.1 POLICY REVIEW
3 SHORT TERM POWER MARKET IN INDIA
3.1 NEED FOR SHORT TERM POWER MARKET IN INDIA
3.1.1 DEVLOPMENT OF SHORT TERM MARKET IN INDIA
3.1.2 ELECTRICITY ACT 2003 AND ENABLING PROVISIONS ON POWER MARKET
3.2 POWER EXCHANGE MARKET
3.2.1 PROCEDURE FOR COLLECTIVE TRANSACTION.
3.2.2 PRODUCTS OF EXCHANGE MARKET
3.2.3
AREA
VOLUME
ANALYSIS
OF
IEX
FOR
FY
10-11,
FY
FY 12_13.
3.2.4 AREA PRICE ANALYSIS OF IEX FOR FY 10-11, FY 11-12 AND FY 12-13
11-12
AND
3.2.5 WEEKLY MARKET REVIEW OF IEX & PXIL FOR LAST THREE FINANCIAL YEAR
3.3 BILATERAL MARKET
3.3.1 LONG TERM OPEN ACCESS
3.3.2 MEDIUM TERM OPEN ACCESS
3.3.3 SHORT TERM OPEN ACCESS
3.3.4 PROCEDURE FOR SCHEDULING OF BILATERAL TRANSACTION
3.3.5 ANALYSIS OF LAST THREE FINANCIAL YEARS BILATERAL
TRANSACTION REGION WISE
4
RESULTS , CONCLUSIONS AND RECOMMENDATIONS
4.1
4.2
RESULTS
RECOMMENDATION
4.3
CONCLUSION
4.4
REFERENCES
INTRODUCTION
POWER MARKET SCENARIO
The electricity consumer has long been served by vertically integrated state electricity boards which had
inefficiency and inefficacy to an exuberant level. The reforms adopted by various states led to separation of
generation, transmission and distribution and their corporatization. However, the desired result of the
reform, that is low prices, reliable supply, fairly predictable bills and the opportunity to benefit from the
value added services can only be accrued in long term through a competitive and efficient market. But the
inherent properties that make electricity different from other commodity makes it difficult to develop an
efficient market that facilities all the above mentioned benefits to the consumer.
For India, having in place an efficient and developed power market is especially important because India is
on a fast track growth path and history has shown that power sector development has always been one of the
basic requirement for the development of a nation as a whole. However, it must be kept in mind that market
development and introducing competition are only the means and efficiency and consumer choice is the
ultimate goal.
India is already on its way to establishing a power market. This requires considerable and continuous effort
starting from continued strengthening of inter-regional power transmission links, open access to
transmission and later to distribution links, releasing the underutilized captive capacities, to the designing of
an effective market mechanism suited to India's needs. The institutional set-up of the Market could make a
significant difference to the final market price. In the short term, market rules should promote economic
efficiency, so that customer loads are served and reliability is maintained at the lowest possible cost. In the
long term, the market should produce prices that stimulate appropriate levels of investments in new
generation and transmission capacity.
In addition, the market rules should be such as to encourage broad participation and ensure fairness. Such a
process will reduce the need for government oversight because it will be to a large extent self-policing and it
will be difficult for individual participants to manipulate results in their favour. Of the two market
mechanisms evaluated, Pool day-ahead market, may produce lower prices than the bilateral model.
However, in the case of a power exchange with a small number of buyers and sellers, often there may be not
enough bids to provide an assurance that the price is competitive, thus creating the need for more market
participants. The short term power market is continuing its expansion and has reached the (10%) mark. The
percentage of short term transactions of electricity to total electricity generation was (9.81%) for the month
of march 2013. This augurs well for the implementation of open access and organized power market in the
country. The rest of the power is transacted through long term PPAs while the share of medium term
contracts is still insignificant. The share of PX based day ahead transaction has crossed 2% ((2.05%) of total
power generated in India). More than 600 direct consumers are buying from the power exchanges on a
regular basis. Of all the short term transactions of electricity, 49.51% transacted through bilateral followed
by 20.86% through UI and 29.62% through power exchanges. This growth is expected to continue over the
year and the biggest opportunity in short term market is presented by the uneven distribution of natural
resources. This makes few states like Chhattisgarh, Odisha and Himachal Pradesh surplus in power over the
next five years and states like Maharashtra, Tamil Nadu, Andhra Pradesh and Uttar Pradesh will continue to
struggle with a deficit situation. Moreover, an analysis of the load curves of different states shows that the
peak for the different states come at different times and this create surplus and deficit situation for states at
different times.
This presents an opportunity for arbitrage and can only be profitable if a efficient short term market is in
place. However, transmission remains a big concern, in percentage terms around 3.93% of electricity in IEX
and15.45% in PXIL could not be cleared due to congestion in state transmission grid. This congestion
problem also present us a unique opportunity opening the transmission sector for private players and coming
out of the notion of transmission being a natural monopoly.
As the market matures the risk hedging instrument can be introduced into the market. Things may start
rolling with the trading of transmission rights. It will hedge players from the issue of transmission
congestion as even if they cannot wheel their power on the line due to congestion, still they will be earning
something as the owner of transmission rights. They will be paid charges by whoever is using the
transmission line at that point of time. Subsequently a capacity market can also be developing to hedge the
risk of uncertainty in demand.
As the supply demand deficit ebbs, various derivative can be introduce that can be used to hedge risk more
appropriately and this will help increase liquidity in the market. With increasing liquidity and competition,
prices will come down. And the benefits of all these will be reaped by the ultimate consumers.
POWER TRADING IN INDIA
In India, while there is a huge section of consumers, who are power deprived, there are a lot of Captive
Power Plants (CPP‟s) that are under-utilized and a lot of merchant capacity also expected to be added in the
near future, there is a need to encourage the peaking power plants and bring the surplus captive power
generation in the grid.
The Electricity Act, 2003, mandated development of power markets by appropriate commissions through
enabling regulations. This paved the way for the new trends to emerge like Open Access and the one in
February, 2007, when the Central Electricity Regulatory Commission (CERC) issued guidelines for grant of
permission for setting up operation of power exchanges within an overall regulatory framework. The
emerging trends will help in proper flow of power from surplus regions to deficit regions and thus try to
bring about a balance in the power sector.
The National Electricity Policy, pronounced in February 2005, stipulated that enabling regulations for interand-intra-state trading, and also regulations on power exchange, shall be notified by the appropriate
Commissions within six months. On 6 February 2007, the 5
Central electricity Regulatory Commission (CERC) issued the guide lines for grant of permission for setting
up and operation of power exchanges within an overall regulatory frame work. Private entrepreneurship is
allowed to play its role. Promoters are required to develop their model power exchange and seek permission
from CERC before start of operation.
Open access & trading
The Electricity Act, 2003 which has come into force from 10th June, 2003 repeals the Indian Electricity Act,
1910; Electricity (Supply) Act, 1948; and Electricity Regulatory Commissions Act, 1998. In view of a
variety of factors, financial performance of the state Electricity Boards has deteriorated. The cross subsidies
have reached unsustainable levels. A few States in the country have gone in for reforms which involve
unbundling into separate Generation, Transmission and Distribution Companies. To address the ills of the
sector, the new Act provides for, amongst others, newer concepts like Power Trading and Open Access.
Open Access on Transmission and Distribution on payment of charges to the Utility will enable number of
players utilizing these capacities and transmit power from generation to the load centre. This will mean
utilization of existing infrastructure and easing of power shortage. Trading, now a licensed activity and
regulated will also help in innovative pricing which will lead to competition resulting in lowering of tariffs.
Definition of “open access” in electricity act 2003
“The non-discriminatory provision for the use of transmission lines or distribution system or 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”.
Issues
a) Freedom to buy/sell, and access to market
b) Adequacy of intervening transmission
c) Transmission/wheeling charges
d) Treatment of transmission losses
e) Energy accounting, scheduling, metering and UI Settlement.
The present level of inter-regional electricity exchange is still quite limited and the constraints for enhancing
the same are the relative lack of commercial awareness with SEBs, lack of proper market mechanism
(absence of tariff structure to promote merit-order operation and encourage trading of power), inadequate
transmission capacity, lack of statutory provisions for direct sale by IPPs/CPPs/ Licenses outside the State,
grid indiscipline and financial viability of State Utilities, among others.
‘inter‐State trading’ means purchase of electricity from one State for re‐sale in another State and includes
electricity imported from any other country for re‐sale within India or exported to any other country subject
to compliance with applicable laws and clearance by appropriate authorities.
‘intra‐State trading’ means purchase of electricity for re‐sale within the territory of the same State.
‘licensee’ means a person who has been granted licence for inter‐State trading under section 14 of the Act.
Provided that if any licensee undertakes intra‐State trading based on the licence for inter‐State trading
granted by the Commission, the licensee shall be regulated under these regulations for the purposes as
specified which shall be in addition to and not in derogation of any regulations on intra‐State trading
specified by the concerned State Commission.
“Provided that the applicant should have been authorized to undertake trading in electricity in accordance
with its constitutional/organizational documents such as the Main Objects in the Memorandum of
Association (in case of a company incorporated under the Companies Act, 1956) or the Partnership Deed (in
case of a partnership firm registered under the Indian Partnership Act, 1932) or the constitutional documents
of Limited Liability Partnerships under Limited Liability Partnership Act, 2008.
Considering the volume of inter‐State and intra‐State trading proposed to be undertaken by the applicant on
the basis of the inter‐State trading licence, the minimum net worth of the applicant on the date of
application, as per audited special balance sheet accompanying the application, shall not be less than the
amounts specified hereunder.
CATEGORY
OF
TRADING
Volume
of
WORTH (IN CRORE)
CATEGORY 1
NO LIMIT
50
CATEGORY 2
<1500 MUs
15
CATEGORY 3
<500 MUs
5
CATEGORY 4
<100 Mus
1
LIST OF TRADERS IN INDIA
List of Inter-State Trading Licensees
(As on 15.3.2013)
NO.
Net
proposed TO BE TRADED
LICENSEE
SL
electricity Minimum
TRADING LICENSEES
1
Tata Power Trading Company Ltd.
2
Adani Enterprises Ltd.
3
PTC India Limited
4
Reliance Energy Trading Ltd.
5
Vinergy International Private Ltd
6
NTPC Vidyut Vyapar Nigam Ltd.
7
National Energy Trading and Services Ltd.
8
MMTC Limited
9
DLF Power Limited
10
Jindal Steel & Power Limited
11
Sarda Energy & Minerals Ltd.
12
GMR Energy Limited
13
Karam Chand Thapar & Bros. (Coal Sales) Limited
14
Subhash Kabini Power Corporation
15
Special Blasts Ltd.
16
Maheshwary Ispat Limited
17
Instinct Infra & Power Ltd.
18
Essar Electric Power Development
19
Suryachakra Power Corporation
20
JSW Power Trading Company
21
BGR Energy Systems Limited
22
Malaxmi Energy Trading Private
23
Visa Power Limited
24
Pune Power Development Private
25
Patni Projects Pvt. Limited
26
Ispat Energy Limited
27
Greenko Energies Private Limited
28
Vandana Global Limited
29
Vandana Vidhyut Limited
30
Indrajit Power Technology Pvt. Ltd.
31
Adhunik Alloys & Power Ltd.
32
Indiabulls Power Trading Limited
33
Indiabulls Power generation Limited
34
Ambitious Power Trading Company
35
RPG Power Trading. Co. Ltd.
36
Basis Point Commodities Pvt. Ltd.
37
GMR Energy Trading Limited
38
Jain Energy Ltd.
39
Righill Electrics Limited
40
Shyam Indus Power Solutions Pvt.
41
Global Energy Private Limited
42
Knowledge Infrastructure Systems
43
Mittal Processors Private Limited
44
Godawari Power and Ispat Limited
45
Shree Cement Limited
46
PCM Power Trading Corporation
47
Abellon Clean Energy Limited,
48
Jay Polychem (India) Limited, New Delhi
49
Jaiprakash Associates Limited,
50
My Home Power Limited,
51
Customized Energy Solution India
52
BS TransComm Ltd., Hyderabad
53
Chromatic India Limited, Mumbai
54
Kandla Energy and Chemical
55
Marquis Energy Exchange Limited
56
DLF Energy Private Limited,
57
GEMAC Engineering Services Private Limited, Chennai
58
SN Power Markets Pvt. Ltd., Noida
59
Manikaran Power Limited, Kolkata
60
Greta Power Trading Limited
61
Arunachal Pradesh Power
62
Green Fields Power Services Private Limited, Visakhapatnam
63
HMM INFRA LIMITED, Chandigarh
1.2.1 Objective of the project
1. To study and analyse region wise demand and availability of Electricity to determine peak shortage
and total energy deficit.
2. To study and analyse the power market size and structure.
3. To identify the need and importance of an efficient short term power market.
4. To analyse Volume and Price of short term Power market
5. To identify states for investment opportunities through analysis of different market parameters
influencing the power market.
6. To understand the various risk associated with Short term power market for various stakeholders.
1.2.2 Scope of the project
Under the scope of the project it covers the participating entities in short term market and the CERC
regulation for the same.
The participating entities in short term market are-:
1. The various regulatory authorities.
2. Power exchanges.
3. Trading licensee.
4. Merchant generators
5. And states discoms.
1.3 About the Organisation
Vedanta Group/Vedanta Resources:Vedanta Resources plc is a global diversified metals and mining company headquartered in London,
United Kingdom. It is the largest mining and non-ferrous metals company in India and also has mining
operations in Australia and Zambia. Its main products are copper, zinc, aluminium, lead and iron ore.
History:-The Company was founded by Anil Agarwal in Mumbai in 1976. It was first listed on the
London Stock Exchange in 2003 when it raised $876 million through an Initial Public Offering.
Meanwhile in 2006 it acquired Sterlite Gold, a gold mining business. It raised an additional $2bn
through an ADR issue in 2007.In 2008 it bought certain of the assets of Asarco, a copper mining
business, out of Chapter 11 for $2.6bn. In December 2011 it also completed the US$8.67 billion
acquisition of Cairn's Indian unit heralding
its foray in the oil sector.
The Company has experienced significant growth in recent years through various expansion projects for
our copper, zinc, lead silver, aluminium, iron power and power businesses. Group Revenue for the fiscal
year ending 31 March 2011 was US$ 11.4 billion.
Vedanta has spent approximately two-third of our US$ 19 billion capital expenditure programme as of
30 September 2011.Vedanta is the world’s largest integrated Zinc Lead producer and among the top
producers of copper, iron ore and silver.
Operations:-
Area
Subsidiaries
Copper
Sterlite Industries (India) Ltd.: Sterlite is registered office headquartered
in Tuticorin, India. Sterlite has been a public listed company in India since
1988, and its equity shares are listed and traded on the NSE and the BSE,
and are also listed and traded on the NYSE in the form of ADSs. Vedanta
owns 53.9% of Sterlite and have management control of the company.
Konkola Copper Mines: Vedanta own 79.4% of KCM’s share capital and
have management control of the company. KCM’s other shareholder is
ZCCM Investment Holdings Plc. The Government of Zambia has a
controlling stake in ZCCM Investment Holdings Plc.
Copper Mines of Tasmania Pty Ltd.: CMT is headquartered in
Queenstown, Tasmania. Sterlite owns 100.0% of CMT and has management
control of the company.
Zinc
Hindustan Zinc Limited: HZL is headquartered in Udaipur in the State of
Rajasthan. HZL’s equity shares are listed and traded on the NSE and BSE.
Sterlite owns 64.9% of the share capital in HZL and has management
control. Sterlite has a call option to acquire the Government of India’s
remaining ownership interest.
Aluminium
Bharat Aluminium Company Ltd.: BALCO is headquartered at Korba in
the State of Chhattisgarh. Sterlite owns 51.0% of the share capital of
BALCO and has management control of the company. The Government of
India owns the remaining 49.0%. Sterlite exercised an option to acquire the
Government of India’s remaining ownership interest in BALCO in March
2004.
Vedanta Aluminium Ltd.: Vedanta Aluminium is headquartered in
Jharsuguda, State of Orissa. Vedanta owns 70.5% of the share capital of
Vedanta Aluminium and Sterlite owns the remaining 29.5% share capital of
Vedanta Aluminium. Vedanta Aluminium produces ingots, billets & wire
rods that are sold in the markets around the World. Vedanta Aluminium
Limited (VAL) has acquired 24.5% stake in L & T subsidiary
RaykalAluminium. Based on achieving certain milestones, VAL will fully
acquire RaykalAluminium in phases.
Madras Aluminium Company Ltd.: MALCO is headquartered in Mettur,
India. MALCO’s equity shares are listed and traded on the NSE and BSE.
They own 93.9% of MALCO’s share capital and have management control
of the company.
Sesa Goa Limited: Sesa Goa is headquartered in Panaji, India, and its
Iron ore
equity shares are listed and traded on the NSE and BSE. Vedanta owns
57.1% of Sesa and has management control of the company.
Commercial
power
generation
business
Sterlite Energy Limited: Sterlite Energy is headquartered in Mumbai.
Sterlite owns 100.0% of Sterlite Energy and has management control of the
company.
Values
Sterlite believe in fostering an entrepreneurial spirit throughout their
Entrepreneurship businesses and value the ability to foresee business opportunities
early in the cycle and act on them swiftly.
Sterlite believe to deliver industry-leading growth and generate
Growth
significant
value
for
shareholders.
Achieving excellence in all that we do is our way of life. Sterlite
Excellence
consistently deliver projects ahead of time at industry-leading costs of
construction and within budget.
Sterlite recognise that they must responsibly deliver on the promises
Trust
we make to earn that trust. They constantly strive to meet stakeholder
expectations and deliver ahead of expectations.
Sustainability
Sterlite believe that the principle of sustainability is a key component
of conducting business in a responsible manner and it is a primary
aim of Vedanta to operate as a good corporate citizen.
Sterlite Projects:1-Jharsuguda Project: -Sterlite Energy Ltd has taken a major initiative towards the advancement of the
power infrastructure in Orissa through its 4 x 600 MW coal-based independent power plant (IPP) in
Jharsuguda district. The IPP project envisages a total capital outlay of Rs. 8,200 crores. The power plant
entails a number of pioneering achievements in the Indian power sector. One of the largest coal handling
plants to handle 44,000 MT of coal per day, which is equivalent to 14 rakes of coal a day and a power
generation capacity to produce 57 million units/day. In addition to this, a Hybrid ESP with fabric filter is
being deployed for the first time in an Indian power plant. The plant also has a dual LP-flow steam turbine
and four 160 meters high natural draft cooling towers. Other important features of the plant include two 275
meters high multi-flue stacks and a high concentration slurry disposal (HCSD) system for dry ash and highly
concentrated slurry. The company has made extensive arrangements to source raw materials for the power
plant. The Hirakud Reservoir is being used as a water source and coal- the chief raw material, is being
derived from the IB Valley coalfield. Power would be supplied to consumers through the high-voltage
power lines.As a prime advocate of sustainable development, Sterlite Energy Ltd. Puts a premium on
environmentally friendly construction technology. The plant employs hybrid ESP and fabric filter which
maintains stack emission < 50 mg/m3 and HCSD system for ash disposal, which results in very low
consumption of water compared to wet slurry system. The Jharsuguda IPP would therefore be a zero effluent
discharge plant with stack emission.
For actualization of Vision for Global Benchmark Performance, the Company has tied up for Operation &
Maintenance of the station with Evonik Energy Services (India) Pvt. Ltd., a wholly owned subsidiary of
Evonik Energy Services GmbH, Germany having 70 years of experience in O&M of Coal fired thermal
Power Plants of big size.
Details of Jharsuguda IPP:Independent power plant, Jahrsuguda, Odisha
Capacity
2400 MW (4X600 MW)
Technology
Thermal Sub critical
EPC contractor
SEPCO III, China
O&M Contractor
Evonik Energy Services India Pvt Ltd
Estimated
Coal
Requirement
estimated project cost
Approx 12.49 MTA
INR 82,000 million
2-Talwandi Project:Talwandi Sabo Power Limited (TSPL) is implementing a state of the art coal based supercritical thermal
power plant in District Mansa, Punjab, India. This will be the first Supercritical unit and one of the largest
Greenfield power project in the State of Punjab. Power generated from this project shall be supplied to the
Punjab State Electricity Board.
TSPL will use energy efficient and cleaner supercritical technology for the electricity generation. Supercritical technology utilizes steam at temperature above the critical point of water. The technology generates
same amount of electricity using less coal. The project activity will thus reduce consumption of fossil fuel
(coal) as compared to the conventional sub critical technology thus making it an environmental friendly and
cost efficient technology.
CHAPTER 2
LITERATURE REVIEW
B jorganet al (2000) presented flexible electricity contracts (FECs) which require the buyer or the seller to
schedule its decision of a certain time interval, and the scheduling decision is composed of sequential
decision-making processes. Furthermore, the buyer can resell the electricity obtained from the FEC to spot
market; otherwise, the seller can choose between producing the energy and buying from the spot market.
Through this way, the traders of FEC can optimize their revenue. Since base-load power and peak-load
power bring different effects on power system operation and electricity generation, the value of them is
different. So base-load power and peak-load power should not have the same price. Therefore, the power
should be divided into several continuous blocks that are traded separately at respective prices.
Daniel S. Kirschen et al (2000) analyzed the effect that the market structure can have on the elasticity of the
demand for electricity. As electricity markets are liberalized, consumers become exposed to more volatile
electricity prices and may decide to modify the profile of their demand to reduce their electricity costs. He
advocated that elasticity can be taken into consideration when scheduling generation and setting the price of
electricity in a pool based electricity market. The customers’ reaction to changes in the price of electricity
depends on the time frame considered. The elasticity of the demand for electricity can be taken into
consideration when the price of electricity is set by a centralized, compulsory pool which schedules
generation on a half-hourly basis for a 24 hour period. Generation is scheduled using a unit commitment
program instead of an optimal power flow. The price computation is carried out according to the rules of the
Electricity Pool of England and Wales. Cutting back on electricity consumption involves at least one of the
following activities: reorganizing production, adjusting controls, using energy or intermediate product
storage systems, calling upon backup generation or substitute energy sources, cycling equipment. Since all
these options are relatively cumbersome, most consumers are unlikely to react to an increase in price until
this increase becomes significant. There is also a level beyond which load reductions become very difficult
if not impossible to implement. Furthermore, customers are much less likely to increase or reorganize their
production to increase their consumption of electricity in the case of a short-term price drop than they are to
react to a price increase.
Xian Zhang et al (2003) presented a a model for block flexible electricity contracts (BFEC) and focuses on
pricing the BFEC based on the principle of no-arbitrage[4]. Energy is traded in blocks according to its time
duration at different block prices, which is called block trading. The BFEC requires the buyer or the seller to
schedule its trading amount and the certain block of power at each time interval. The block trading needs to
divide the power into several blocks, the prices of each power block are obtained from market clearing price.
The inherent feature of electricity commodity makes the price of electricity fluctuates tempestuously, which
forces the participants to confront tremendous financial risk in spot power market. As an efficient risk-
managing tool, forward contract is introduced into power markets. A majority of power exchanges is
conducted through forward contracts in power markets; Therefore , forward contracts have attracted great
interest. The modeling and pricing are the primary contents of forward contracts. The FEC based on the
block trading method is called block flexible electricity contracts (BFECs), which requires the buyer or
seller to schedule its trading amount and the certain block of power at each time interval. The electricity
energy is divided into blocks with continuous time segments, because the effect of each block on the power
system and power market participants varies. It is generally accepted that the shorter lasting time block such
as1-h block power, which is usually used to balance the peak of load, contributes more to the security of
power system than the24-h block power does. Furthermore,
generating
the same quantity power, 1-h
block power will costs more than the 24-h block power due to the cost of unit’s startup and shutoff. So every
block has different value and cost compared with each other, and the price of the block should vary with its
value and cost. However, the former electricity contracts do not discover the difference of the power, all of
the power at the same time interval is settled by a uniform price.
Jinsu Lee et al (2009) showcased in her studies how to formulate a cross border power trading
system.[7]The West African Power Pool is currently developing the regional electricity market for its
member states .As the basic design for the cross-border power trading system for the West African Power
Pool, the step-by-step evolution, the baseline System and the Full scale System, is estimated. West Africa
region, despite its abundant energy resources, has an unequal geographical distribution of resources for
generating electric power. As a result only a third of across 14 Economic Community of West African States
(ECOWAS) countries has access to electricity. Power supply for household and industrial usage is vastly
different between each country and distinguished much from the overall regional demand. The West African
Power Pool (WAPP) was established by ECOWAS in order to address the issue of power supply deficiency
within the West African sub-region. It is expected that the market rules for WAPP regional electricity
market will be established by WAPP. If the market rule for WAPP regional electricity market is finalized,
the interchange scheduling and settlement will be reshaped by the market rule. Generally, in the electricity
market environment, the power trading will be based on bidding mechanism. Through the step-by-step
implementation of the WAPPICC System, the WAPP will achieve its vision to integrate the operation of the
national power systems into a unified, sustainable regional electricity trading.
2.1
POLICY REVIEW
Major policies and regulations affecting the trading scenario
Inception of Power Trading Corporation, 1999

Facilitator for market participant in finding counterparts.

Low volume relative to huge demand
Availability Based Tariff, 2002-03

Incentive for generator for efficient operations and central dispatching.

Grid security problems due to over drawl on high UI charges
Electricity Act, 2003

Identified trading as a distinct licensed activity.

Provided provision for open access

De-Licensing of Generation

Development of multi buyer & multi seller market in power

Introduced trading & competitive bidding for procurement of electricity
National Electricity Policy, 2005

Measures to promote competition aimed at consumer benefits

Promote competition for optimal pricing of power
Open Access Regulations, 2008

Impetus for bilateral trading.

Bilateral trading based on voluntary agreement of participants.

Lacked transparency in price discovery.

Transaction cost hindered smaller players from entering market

Separation of transmission ownership and system operation

Universal open access to transmission networks
Power exchange, 2008

The electricity prices in transparent manner.

Facilitating efficient trading among the player.

Easy access to new entrants is possible.

Clear signals for capacity addition.
National action plan on climate change, 2008

Promotion of renewable power market through power exchanges

Introduction of REC trading
Power market regulations, 2010

Providing a regulatory framework for competitive markets

Guidelines and prudential norms for setting up and operating power exchanges

Guidelines on listing contracts on power exchanges
CHAPTER 3
3. SHORT TERM POWER MARKET IN INDIA
Short term transactions of electricity in India are the contracts of less than one year period for electricity
transacted through Inter-state trading licensees and directly by the distribution licensees, power exchanges
(Indian Energy exchange (IEX) and Power Exchange India Ltd (PXIL), and unscheduled Interchange (UI).
Interstate trading licensees have been carrying out trading since 2004, when open access provision was
implemented. Power exchanges are in operation since 2008. The IEX and PXIL became operational in June
2008 and October 2008 respectively.
As of June 2011, there were 51 trading licensee and two power exchanges.
Since the starting of interstate trading, the volume of electricity traded has been continuously increasing. In
2010, the total volume traded in short term market was almost 6% of total electricity generated, excluding
UI based drawls. It has increased from a mere 3% when the power exchanges started their operation. More
than 50% of the short term transaction has been through bilateral trading for various reasons. The relatively
high impact of transmission congestion and volatility of prices in power exchanges are the main reason.
FIGURE 3.1 : ATTRIBUTES OF SHORT TERM MARKET
3.1.
NEED FOR SHORT TERM POWER MARKET IN INDIA
Seasonal demand due to agrarian economy
Demand in India, being an agrarian economy, is driven by various factors such as weather, temperature and
agriculture operations. Although these demands are cyclic in nature, the quantum of demand is still
determined by factors such as rainfall and temperature. So it will always be difficult to predict these
demands. In the year 2009, the electricity prices had a hit a level of Rs. 17 per unit in the month of August
due to below normal rain. The situation went to such drastic level mainly due to high demand and
inadequate supply. Such situation can be deterred in future by having a more liquid and efficient short term
market.
It acts as good price signal for investment
High prices in short term market signal the increasing demand situation. As such a free market can give
price signals for more investment. By analyzing the demand scenario, it can be concluded weather the
situation is more conducive of independent power plant (IPP) or merchant power plant (MPP). However,
they do have some risk associated with them. The high prices in the market may just be a temporary
phenomenon arising out of abnormal conditions such as abnormally high temperature or lack of rainfall.
Optimal Asset Utilization
In a diverse and large country like India, there is a significant difference in the peak hour of one region from
other region. Scenario where one region goes through instantaneous deficit other region is surplus is quite
common in India.
Bringing CPP into the market
India has a grid connected captive capacity of 31516.87 MW as on 31-03-12. This capacity is only used to
power the owner’s facilities. With so much deficit prevailing in Indian power sector it would only help if
idle capacities from these power plants are traded in the short term market. An efficient short term market
will always incentivizes the captive power plant to participate in power trading and earn revenue on their
idle capacity.
3.1.1. DEVLOPMENT SHORT TERM MARKET IN INDIA
India’s electricity has undergone the reform process and is still evolving. Although there were many agenda
for reform, one of the priorities was to facilitate nationwide electricity trading at a whole sale level and to
develop an efficient wholesale electricity market in India. The initial step in this direction was to encourage
wholesale trading between states.
To facilitate this, in 1999, Power Trading Corporation (PTC) was established in India on the government
initiatives. PTC acted as a broker helping market participants find counterparts.
So electricity trading in India started in the form of bilateral trading.
However, trading volume of PTC was small relatively to the huge demand. Also POWERGRID which was
responsible for system operation at national level was loosely coordinating the RLDCs. It meant that each
state had to carry out dispatching from its own generating plant. And as such the situation of one state being
power deficit and another power surplus during different times persisted. The deficit state resorted to load
shedding in order to match supply and demand. In order to streamline the system of scheduling and
dispatching, Availability based tariff was implemented. It would panelise generator and loads for
unscheduled interchanges. It also created incentive for a central dispatch schedule and trading of surplus
power, if any. It had a positive effect on generators which started operating more efficiently. But ABT in
itself does not balance supply and demand in real time and does not ensure a least cost dispatching. Utilities
started overdrawing power from grid to meet their demand even at high UI charges. It not only led to high
pooled power cost but also put the grid security at stake.
To take care of this, in Electricity Act 2003, electricity trading as a distinct activity was permitted on the
basis of licenses. Central electricity regulatory commission (CERC) was made responsible for granting
license, which would be valid for 25 years. The Act also provided guidelines for provision for open access
which made it convenient to procure power from short term market. This gave some freedom for new
players to engage in electricity trading through bilateral contracts.
It has been recognized in India as well as in developed power market; electricity trading through bilateral
contract is promoted based on voluntary agreement of market participants. Reliance on voluntary agreement
among the market participants, however, does not necessarily guarantee the evolution of an efficient power
market. Transaction costs associated with the bilateral contracts stops relatively smaller player to participate
in the market limiting competition. Also it results in lack of transparency in price discovery. So the need for
an organized power market to determine the electricity prices in transparent manner, thereby facilitating
efficient trading among the player was felt.
In July 2006, CERC took a giant leap forward in developing the electricity market in the country and floated
a discussion paper on “Developing a Common Platform for Electricity Trading”. In this paper learning from
different foreign markets such as Nord Pool, PJM, UK power market etc was considered and attempt was
made to visualize them in Indian conditions.
The benefits envisaged by the formation of power exchanges where:
 Trading is done in efficient, transparent & equitable manner.
 Existing resources are efficiently utilized & availability of power supply increases.
 Standardization of electricity as tradable products can be achieved.
 Easy access to new entrants is possible.
 Electricity is valued in terms of time of the day/season.
 There are clear signal of adding capacities.
 Business confidence in power sector grows.
On 27th June 2008, India’s first ever power exchange came into existence as the Indian Energy Exchange
Ltd. (IEX).
This development process can be shown in figure below
FIGURE 3.2
3.1.2
Development process of Indian Power Market
EA 2003 and enabling provisions on Power Market
Electricity Act 2003
i)
Intent and object of the EA 2003 is to develop power market through increased The competition,
more players and protect consumer interests.
ii)
Development of Power Market – EA 2003, Section 66, “The Appropriate
Commission shall endeavour to promote the development of power market…”, guided by the
National Electricity Policy
iii)
Suitable safeguards to prevent adverse effect on competition .
iv)
Recognized Trading as a distinct activity
v)
Definition under section (2) (47): “Purchase of electricity for resale thereof”
vi)
Adequate and progressive provisions governing open access both :
• to transmission networks (inter-state and intra-state) and
• to distribution networks
3.2
POWER EXCHANGE MARKET
Introduction:
On 6th February 2007, the CERC issued guidelines for grant of permission to set up power exchanges in
India. Financial Technologies (India) Ltd responded by proposing then tentatively named 'Indian Power
Exchange Ltd' and applied for permission to set it up and operate it within the parameters defined by CERC
and other relevant authorities. Based on the oral hearing on July 10, the CERC accorded its approval vide its
order dated 31st August, 2007. IEX thus moved from the conceptual level to firmer grounds. On 9th June
2008 CERC accorded approval to IEX to commence its operations and 27th June 2008 marked its presence
in the history of Indian Power Sector as Indian Energy Exchange Ltd (IEX), India’s first-ever power
exchange starts operating.
Power exchange india Ltd got permission to trade on August,31,2009 from CERC. Started off its operation
from September 15,2009
Collective Transaction Procedure for Scheduling
[As per CERC Open Access Regulations, 2008 (dated 25.01.2008) & subsequent
(Amendment) Regulations, 2009 (dated 20.5.2009)
INTRODUCTION

Regional Entity shall obtain a prior approval from the respective RLDCs/RPCs, by making an
application

State Utilities and intra-State Entities proposing to participate in trading through Power Exchange(s)
shall obtain “Standing Clearance”/ “No Objection Certificate” from the respective State Load
Despatch Centre.

The “Standing Clearance”/”No Objection Certificate” submitted by the State Utilities/intra-State
entity shall be reviewed on quarterly basis by the respective SLDCs. Even if there is no change in the
status, it shall be resubmitted by the respective State Utilities/intra-State Entity.

Each RLDC, on their website, shall display the list of Regional Entities of the Region. Similarly,
each SLDC, on their website, shall display the list of the intra-State Entities of their State.

All Entities participating in the Power Exchange(s) shall be identifiable with a Unique Code on the
basis of Bid Area, sub Bid Area.
(for STERILITE- W3SE1SEL0002)

All data between NLDC and Power Exchange(s) shall be exchanged electronically through a
dedicated communication channel.

Power Exchange(s) shall be responsible for Settlement of Energy Charges, Price Discovery and
Settlement arising due to Congestion, with its participants.
SCHEDULING

RLDCs shall schedule the Collective Transaction at the respective periphery of the Regional Entities.

RLDCs shall incorporate all buyers within a State (clubbed together as one group) and all sellers
within a State (clubbed together as another group), in the schedules of the Collective Transactions.

The individual transactions for State Utilities/intra-State Entities shall be
scheduled by the
respective SLDCs. Power Exchange(s) shall send the detailed breakup of each point of injection and
each point of drawl within the State to respective SLDCs by 18:00 Hrs. after receipt of acceptance
from NLDC. The details for Scheduling Request for Collective Transaction shall be submitted by
Power Exchange (s) to the respective SLDCs as per Format–PX-IV.
REAL TIME CONGESSION MANAGEMENT

In case of transmission constraint or threat to grid security, the scheduled transactions may be
curtailed in the manner as decided by the NLDC /RLDCs / SLDCs to relieve the transmission
constraint/ to improve grid security.

Collective Transaction through Power Exchange(s) would normally be curtailed subsequent to the
Short-Term Bilateral Transaction

In case of curtailment of a Transaction caused by transmission constraints / threat to grid security,
the Transmission Charges in respect of such Transaction shall be payable on pro-rata basis in
accordance with the finally Implemented Schedules. Operating Charges shall not be revised in case
of curtailment.
COMMERCIAL CONDITION

Following STOA charge shall apply for collective transaction through power exchange &shall be
paid to NLDC by power exchange.
1. Non-refundable fee of Rs. 5000/- payable along with each Application
2. Operating Charges @Rs.5000/- per day per Entity involved
Payments of Transmission Charges and Operating Charges shall be made by the Power
to
the NLDC, by next working day falling after the day on which its
Exchange(s)
Application was processed at
NLDC.
SCHEDULE TIMELINE

11.00 HR- The National Load Despatch Centre (NLDC) shall indicate to Power Exchange(s), the
list
of interfaces/control areas/ regional transmission systems on which unconstrained flows are
required

13.00HR- Power exchange(s) shall furnish by 13:00 Hrs., the interchange on various
interfaces/control areas/regional transmission systems as intimated by NLDC.

14.00HR- in case of congestion, NLDC shall inform the exchange(s) by 14:00 Hrs.
about the period of congestion and the available limit for scheduling of collective
transaction on respective interfaces/control areas/transmission systems

The Application for Scheduling of Collective Transaction shall be submitted by the Power
Exchange(s) by 15:00 Hrs. each day, to the NLDC

NLDC shall send the details (Scheduling Request of Collective Transaction) to different RLDCs by
16:00 Hrs. for final checking and accommodating them in their schedules. RLDCs shall confirm its
acceptance to NLDC by 17:00 Hrs.

After getting acceptance from the RLDCs, NLDC shall convey the acceptance of scheduling of
Collective Transaction to Power Exchange(s) by 17:30 Hrs.
PRODUCTS OF IEX:
Day Ahead Market:
On a daily basis the Exchange will offer a double side closed auction for delivery on the following day,
which is termed as day-ahead market. Price discovery would be through double side bidding and buyers and
suppliers shall pay/receive uniform price.
Day Ahead Market operations will be carried out in accordance with the ‘Procedure for scheduling of
collective transactions’ issued by the Central Transmission Utility (PGCIL), ‘CERC (Open Access in interState Transmission) Regulations, 2008’ ,its modifications issued from time to time and the Bye-Laws, Rules
and Business Rules of the Exchange.
Process of Closed-Bidding Auction:
Bid accumulation period(Bidding phase): During the auction sessions on each Trading Day, bids entered
by Members on the IEX Trading Platform are automatically stored in the Central Order Book without giving
rise to Contracts. During this phase, bids entered can be revised or cancelled. Bid accumulation period shall
start at 10.00 AM and will end at 12.00 Noon.
Auction Period: At the end of the bidding session, the IEX Trading Platform will seek to match bids for
each 15 minute time block. After the price determination phase is concluded, the Members, whose bids have
been partially or fully executed, will be provided all relevant trade information regarding each contract
traded on the IEX Trading Platform.
Price Determination Process (Provisional): All purchase bids and sale offers will be aggregated in the
unconstrained scenario. The aggregate supply and demand curves will be drawn on Price-Quantity axes. The
intersection point of the two curves will give Market Clearing Price (MCP) and Market Clearing Volume
(MCV) corresponding to price and quantity of the intersection point. Results from the process will be
preliminary results. Based on these results the Exchange will work out provisional obligation and
provisional power flow. Funds available in the settlement account of the Members shall be checked with the
Clearing Banks and also requisition for capacity allocation shall be sent to the NLDC. In case sufficient
funds are not available in the settlement account of the Member then his bid (s) will be deleted from further
evaluation procedure.
Price Determination Process (Final): Based on the transmission capacity reserved for the Exchange by the
NLDC on day ahead basis by 2.00 PM, fresh iteration shall be run at 2.30 PM and final Market Clearing
Price and Volume as well as Area Clearing Price and Volume shall be determined. These Area Clearing
Prices shall be used for settlement of the contracts.
Settlement:
On receipt of final results, obligations shall be sent to Banks for Pay In from buying Members at 2.30 PM
and will take confirmation of the same from the Bank. At 3.00 PM final results will be sent to NLDC /
SLDCs for incorporating in final schedules. Once a transaction is scheduled it shall be considered as deemed
deliver.
TERM AHED MARKET: This market segment will cover all electricity contracts except those mentioned
in the Day Ahead Market segment. This will cover market timeframes of intra-day, day-ahead contingency,
daily, weekly etc. as allowed by the Commission. The Term Ahead Market will operate in accordance with
the procedures issued by CTU for „Scheduling of Bilateral Transactions‟. All terms and conditions of the
contracts including trading sessions, matching rules, margin requirement and delivery procedure etc, will be
as per specific rules mentioned herein.
Contracts: The Exchange shall make the contracts as specified in this section available for trading as per
the trading calendar. These contracts will be traded in accordance with provisions of trading as specified in
the respective Contract Specification. The trade sessions, matching rules applied in each trade session for
concluding the contracts, risk management and settlement for such contracts will be as per specific contract
specifications provided herein. The delivery of such contracts will be in accordance with CERC (Open
Access in Inter-State Transmission) Regulations, 2008, as amended from time to time and relevant
procedures issued by CTU and by Open Access Regulations of concerned State. The Exchange holds the
right to modify all other parameters except those specified in regulation 7 of CERC (Power Market)
Regulation, 2010. These contracts will be further differentiated on time of day basis (Peak and Off-Peak
basis), day-of-the week basis (weekday, week-end and holiday). Following contracts shall be available for
trading in Term-Ahead Market:
Day-Ahead Contingency Contracts: The Exchange shall make the daily contracts available for trading
upto a period specified by CERC for delivery of electricity for defined blocks of hours of the day. The
Exchange will carry out trading in such contracts either through „Uniform Price Step Auction‟ or
„Continuous Trade‟ sessions or a combination of both depending on market feedback. The timeline for trade
matching sessions will be specified in Contract Specifications. They will be sent for scheduling in
accordance with CERC (Open Access in Inter-State Transmission) Regulation, 2008, as amended from time
to time and relevant procedures issued by CTU as specified in the contract specifications. The contracts may
contain provisions allowing quantity variation in delivery. The Exchange holds the right to modify
parameters as specified by CERC.
Weekly Contracts: The Exchange shall make the weekly contracts available for trading maximum up to a
period specified by CERC for delivery of electricity for defined blocks of hours on all defined week-days
and/or weekends of the week. The Exchange will carry out trading in such contracts through „Uniform Price
Step Auction‟ or „Continuous Trade‟ sessions or a combination of both as approved by CERC. The timeline
for trade matching sessions will be specified in Contract Specifications. They will be sent for scheduling in
accordance with CERC (Open Access in Inter-State Transmission) Regulation, 2008, as amended from time
to time and relevant procedures issued by CTU as specified in the contract specifications. The contracts may
contain provisions allowing quantity variation in delivery. The Exchange holds the right to modify
parameters as specified by CERC.
Daily Contracts: The Exchange shall make the daily contracts available for trading up to a period specified
by CERC for delivery of electricity for defined blocks of hours of the day. The Exchange will carry out
trading in such contracts either through „Uniform Price Step Auction‟ or „Continuous Trade‟ sessions or a
combination of both depending on market feedback. The timeline for trade matching sessions will be
specified in Contract Specifications. They will be sent for scheduling in accordance with CERC (Open
Access in Inter-State Transmission) Regulation, 2008, as amended from time to time and relevant
procedures issued by CTU as specified in the contract specifications. The contracts may contain provisions
allowing quantity variation in delivery.
Weekly Contracts: The Exchange shall make the weekly contracts available for trading maximum up to a
period specified by CERC for delivery of electricity for defined blocks of hours on all defined week-days
and/or weekends of the week. The Exchange will carry out trading in such contracts through „Uniform Price
Step Auction‟ or „Continuous Trade‟ sessions or a combination of both as approved by CERC. The timeline
for trade matching sessions will be specified in Contract Specifications. They will be sent for scheduling in
accordance with CERC (Open Access in Inter-State Transmission) Regulation, 2008, as amended from time
to time and relevant procedures issued by CTU as specified in the contract specifications. The contracts may
contain provisions allowing quantity variation in delivery. The Exchange holds the right to modify
parameters as specified by CERC.
EXCHANGE MARKET TIME LINE
Exchange
Timeline
Auction type
DAM
1000 Hrs-1200 Hrs
Both sided closed auction
WEEKLY
1200 Hrs till bids finalization
Both sided open auction
INTRA DAY
1200 Hrs till bids finalization
Both sided open auction
DAILY
1200 Hrs till bids finalization
Both sided open auction
DAC
1500 Hrs till bids finalization
Both sided open auction
Market
AREA VOLUME ANALYSIS OF FY10-11,FY11-12
Buy Mus
Sell Mus
Buy Mus Sell Mus %change in buys % Change in sales
SN
Region
FY 10-11
FY 11-12
1
E1
122.29
825.05
518.87
1214.62
324.31
47.22
2
E2
0.21
173.71
82.15
327.67
38982.20
88.63
3
W1
135.03
2504.33
567.67
1097.50
320.39
-56.18
4
W2
1970.32
2805.68
2690.60
3436.98
36.56
22.50
5
W3
5.47
1268.65
NA
NA
6
N1
3514.77
913.38
2227.13
2169.42
-36.64
137.52
7
N2
2957.50
2448.54
2383.63
2413.12
-19.40
-1.45
8
N3
1656.99
190.23
NA
NA
9
S1
460.98
1488.84
1266.64
1100.29
174.77
-26.10
10
S2
2827.25
23.08
2340.88
5.56
-17.20
-75.91
11
A1
23.64
234.98
8.83
232.92
-62.66
-0.87
12
A2
41.18
144.37
216.38
175.57
425.41
21.61
AREA VOLUME ANALYSIS OF FY11-12 & FY 12-13
Buy Mus
SN
Region
Sell Mus
FY 11-12
Buy Mus
Sell Mus
FY 12-13
%
%
Change
Change
(Buy)
(Sale)
1
E1
518.87
1214.62
442.59
1229.32
-14.70
1.21
2
E2
82.15
327.67
35.51
307.74
-56.77
-6.08
3
W1
567.67
1097.50
426.53
1432.09
-24.86
30.49
4
W2
2690.60
3436.98
6627.31
2936.00
146.31
-14.58
5
W3
5.47
1268.65
77.97
4316.51
1326.26
240.25
6
N1
2227.13
2169.42
1417.91
4372.79
-36.33
101.56
7
N2
2383.63
2413.12
5648.41
3646.38
136.97
51.11
8
N3
1656.99
190.23
2794.01
39.06
68.62
-79.47
9
S1
1266.64
1100.29
2034.86
3814.42
60.65
246.67
10
S2
2340.88
5.56
2474.07
0.66
5.69
-88.09
11
A1
8.83
232.92
82.44
171.30
833.87
-26.46
12
A2
216.38
175.57
313.22
108.54
44.76
-38.18
AREA PRICE ANALYSIS OF FY 10-11
14000
12000
10000
A1/A2 Price
8000
E1/E2 Price
6000
N1 /N2Price PRICE
4000
S1 Price PRICE
2000
S2 Price PRICE
0
W1/W2Price PRICE
AREA PRICE ANALYSIS FOR FY11-12
12000
10000
A1/A2 Price
8000
E1/E2 Price
6000
N1 /N2Price PRICE
4000
N3 Price PRICE
2000
S1 Price PRICE
0
S2 Price PRICE
W1/W2/W3 Price PRICE
AREA PRICE ANALYSIS FOR FY12-13
14000
12000
10000
8000
6000
4000
2000
0
A1/A2 PRICE(RS/MWH)
PRICE(Rs/MWH)
E1/E2 PRICE(RS/MWH)
PRICE(Rs/MWH)
N1/N2 PRICE(RS/MWH)
PRICE(Rs/MWH)
N3 PRICE(RS/MWH)
PRICE(Rs/MWH)
S1 PRICE(RS/MWH)
PRICE(Rs/MWH)
S2 PRICE(RS/MWH)
PRICE(Rs/MWH)
W1/W2/W3 PRICE(RS/MWH)
PRICE(Rs/MWH)
RESULTS
KEY FINDINGS

Total
volume traded by IEX for last three financial year is
2010-11
12.053 (BUs)
2011-12
13.965(BUs)
2012-13
22.374(BUs)
Average price in IEX for different region for last financial year is
3442/MWhr.

MCP & MCV for different delivery hours of 2013 are
UN_MCP(RS/MWHr)
UN MCV(MWHr)
Average (RTC)
2848.03
3760.09
Peak
3124.04
3633.17
Non Peak
2756.03
3802.4
Day
3196.4
3868.97
Night
2385.88
3715.28
Morning
2633.14
3838.37
Delivery Hours

Due to transmission constraint, prices in southern region are too high comparatively other region.
Average price of southern rose by 51% in 2012 as compared to 2011.
However, In 2013 average price has come down to 25% as compared to previous year.
Region
Average Price
2011
2012
2013
S1
5105
7731
5728
S2
5237
7744
6516
51.44%
-25.91%
percentage change
Long Term Market
Long term market serves as a major platform to procure and sell power to the utilities. As of now, the
available power procuring arrangements in the long term market are:
1. Traditional PPAs between genco and discom-Regulated: Until recently ,the long term market had a
single arrangement called the regulated PPA to procure and sell power.This PPA is a legal contract
between an electricity generator and a discom. Such agreements plays a key role in the financial
closure of generation projects .
2. Long/medium term PPAs between genco and traders and PSAs between trader and discom:
However, while analysing the upcoming/proposed capacities, there is slow transition from regulated
PPAs (genco discom) to bilateral contracts involving traders (genco
trader
discom/industrial
consumer/exchange). Traders such as PTC,Tata Power Trading and Reliance Trading had executed
many such LT-PPA with generators and their strategy is to be in open position in the market and sell
the contracted power in small quantities for shorter duration to different consumers at high price.
PTC leads in dealing long –term power and has entered into many MoUs/PPAs with generators to
procure long –term power.
3. Long /medium term PPAs between genco and discom i.e. competitive bidding: MoP has issued the
competitive bidding guidelines contemplated under Section 63 of the Act, titled “Guidelines for
Determination of Tariff by Bidding Process for Procurement of Power by Distribution Licensees”.
As per these guidelines, the discom can invite bids from prospective sellers both on long term and
medium term basis. As of now, the total capacity coming up through the competitive bidding regime
is to the tune of 30GW.Hence, competitive bidding is gaining momentum, and stakeholders’ generic
views on this are presented below:
From Buyer’s side: This new regime has helped them to discover competitive tariffs and has considerably
reduced the discom’s cost of power procurement. As procurement by more than one distribution utility is
permitted, it would further bring down the aggregate efforts taken by individual discoms in the state.
From Developer’s side: Both the private segment and public sector companies would have to forego the
profit margin as fixed in the regulated cost-plus structure. As some of risks are thoroughly minimised
through competitive regime, the established private players would not get much affected by this transition;
instead, could arrange cheaper finances for the project. As certain techno commercial competencies are
required to minimise the overall project cost and to arrive at lowest profitable tariff, the small players and
new entrant would find it hard to compete with the established players.
From Traders side: This regime has helped to earn an unregulated profit margin for the entire
transaction. As traders are allowed to participate in Case 1 bidding, they can also contract capacities from
one or more generators and, in turn, bid for supplying to discom.
Guidelines for Determination of Tariff by Bidding Process for Procurement of Power by Distribution
Licensees
Bidding Process
TWO STAGE PROCESS:
For long-term procurement under these guidelines, a two-stage process featuring separate Request for
Qualification (RFQ) and Request for Proposal (RFP) stages shall be adopted for the bid process under these
guidelines. The procurer may, at his option, adopt a single stage tender process for medium term
procurement, combining the RFP and RFQ processes. Procurer or authorized representative shall prepare bid
documents including the RFQ and RFP in line with these guidelines and standard bid documents.
The procurer shall publish a RFQ notice in at least two national newspapers, company website and
preferably in trade magazines also to accord it wide publicity. The bidding shall necessarily be by way of
International Competitive Bidding (ICB). For the purpose of issue of RFQ minimum conditions to be met by
the bidder shall be specified by the procurer in the RFQ notice.
Procurer shall provide only written interpretation of the tender document to any bidder / participant and the
same shall be made available to all other bidders. All parties shall rely solely on the written communication
and acceptances from the bidders.
Standard documentation to be provided by the procurer in the RFQ shall include,
(i) Definition of Procurer’s requirements, including:

Quantum of electricity proposed to be bought in MW. To provide flexibility to the bidders, this may
be specified as a range, within which bids would be accepted. Further, the procurer may also provide
the bidders the flexibility to bid for a part of the tendered quantity, subject to a given minimum
quantity.

The procurer may separately specify distinct base load requirements and peak load requirements
through the same bid process. Seasonal power requirements, if any, shall also be specified;

Term of contract proposed; (as far as possible, it is advisable to go for contract coinciding with life
of the project in case of long term procurement). The bidder shall be required to quote tariff life
project is estimated to be 15 years for gas/liquid fuel based projects, 25 years for coal based projects
structure for expected life of the project depending upon fuel proposed by him. The expected and 35
years for hydro projects.

Normative availability requirement to be met by seller (separately for peak and off-peak hours, if
necessary);

Definition of peak and off-peak hours;

Expected date of commencement of supply;

Point(s) where electricity is to be delivered;

Wherever applicable, the procurer may require construction milestones to be specified by the
bidders;

Financial requirements to be met by bidders including, minimum net-worth, revenues, etc with
necessary proof of the same, as outlined in the bid documents;
(ii) Model PPA proposed to be entered into with the seller of electricity. The PPA shall include necessary
details on:

Risk allocation between parties;

Technical requirements on minimum load conditions;

Assured offtake levels;

Force majeure clauses as per industry standards;

Lead times for scheduling of power;

Default conditions and cure thereof, and penalties;

Payment security proposed to be offered by the procurer.
(iii) Period of validity of offer of bidder;
(iv) Requirement of transfer of assets by the selected bidder (if any) to the procurer at the end of the term of
the PPA.
(v) Other technical, operational and safety criteria to be met by bidder, including the provisions of the
IEGC/State Grid Code, relevant orders of the Appropriate Commission (e.g – the ABT Order of the CERC),
emission norms, etc., as applicable.
(vi) The procurer may, at his option, require demonstration of financial commitments from lenders at the
time of submission of the bids. This would accelerate the process of financial closure and delivery of
electricity;
(vii) The procurer and the supplier may exercise exit option subject to the condition that the new player
satisfies all RFP conditions.
RFP shall be issued to all bidders who have qualified at the RFQ stage. In case the bidders seek any
deviations and procurer finds that deviations are reasonable, the procurer shall obtain approval of the
Appropriate Commission before agreeing to deviation. The clarification/revised-bidding document shall be
distributed to all who had sought the RFQ document informing about the deviations and clarifications.
Wherever revised bidding documents are issued, the procurer shall provide bidders at least two months after
issue of such documents for submission of bids.
Standard documentation to be provided by the procurer in the RFP shall include,
(i) Structure of tariff to be detailed by bidders;
(ii)
PPA
proposed
to
be
entered
with
the
selected
bidder.
The model PPA proposed in the RFQ stage may be amended based on the inputs received from the
interested parties, and shall be provided to all parties responding to the RFP. No further amendments shall
be carried out beyond the RFP stage;
(iii)
Payment
security
to
be
made
available
by
the
procurer.
The payment security indicated in the RFQ stage could be modified based on feedback received in the RFQ
stage. However no further amendment to payment security would be permissible beyond the RFP stage.
(iv) Bid evaluation methodology to be adopted by the procurer including the discount rates for
evaluating the bids.
The international market for the last 30 years for coal and 15 years for gas / LNG (as per CERC’s
notification in (vi) below) shall be used for escalating the energy charge quoted by the bidder. However this
shall not apply for cases where the bidder quotes firm energy charges for each of the years of proposed
supply, and in such case the energy charges proposed by the bidder shall be adopted for bid evaluation. The
rate for discounting
The bids shall be evaluated for the composite levellised tariffs combining the capacity and energy
components of the tariff quoted by the bidder. In case of assorted enquiry for procurement of base load, peak
load and seasonal power, the bid evaluation for each type of requirement shall be carried out separately. The
capacity component of tariffs may feature separate non-escalable (fixed) and escalable (indexed)
components. The index to be adopted for escalation of the escalable component shall be specified in the
RFP. For the purpose of bid evaluation, median escalation rate of the relevant fuel index in the combination
of fixed and variable charges for computing the levellised tariff shall be the prevailing rate for 10 year GoI
securities;
(v) The RFP shall provide the maximum period within which the selected bidder must commence supplies
after the PPA is entered into by the procurer with the selected bidder, subject to the obligations of the
procurer being met. This shall ordinarily not be less than four years from the date of signing of the PPA with
the selected bidder in case supply is called for long term procurement. The RFP shall also specify the
liquidated damages that would apply in event of delay in supplies.
(vi) Following shall be notified and updated by the CERC every six months for the purpose of bid
evaluation:
1.Applicable discount rate
2.Escalation rate for coal
3.Escalation rate for gas/LNG
4. Inflation rate to be applied to indexed capacity charge component.
Bid submission and evaluation

To ensure competitiveness, the minimum number of qualified bidders should be at least two other
than any affiliate company or companies of the procurer. If the number of qualified bidders
responding to the RFQ/RFP is less than two, and procurer still wants to continue with the bidding
process, the same may be done with the consent of the Appropriate Commission.

Formation of consortium by bidders shall be permitted. In such cases the consortium shall identify a
lead member and all correspondence for the bid process shall be done through the lead member. The
procurer may specify technical and financial criteria, and lock in requirements for the lead member
of the consortium, if required.

The procurer shall constitute a committee for evaluation of the bids with at least one member
external to the procurer’s organisation and affiliates. The external member shall have expertise in
financial matters / bid evaluation. The procurer shall reveal past associations with the external
member - directly or through its affiliates - that could create potential conflict of interest.

Eligible bidders shall be required to submit separate technical and price bids. Bidders shall also be
required to furnish necessary bid-guarantee along with the bids. Adequate and reasonable bidguarantee shall be called for to eliminate non-serious bids. The bids shall be opened in public and
representatives of bidders desiring to participate shall be allowed to remain present.

The technical bids shall be scored to ensure that the bids submitted meet minimum eligibility criteria
set out in the RFP documents on all technical evaluation parameters. Only the bids that meet all
elements of the minimum technical criteria set out in the RFP shall be considered for further
evaluation on the price bids.

The price bid shall be rejected if it contains any deviation from the tender conditions for submission
of price bids.

Wherever applicable, the price bid shall also specify the terminal value payable by the Procurer for
the transfer of assets by the selected bidder in accordance with the terms of the RFP.

The bidder may quote the price of electricity at the generating station bus-bar (net of auxiliaries), or
at the interface point with the State transmission network. For purposes of standardization in bid
evaluation, the tariffs shall be compared at the interface point of the generator/supplier with the
State transmission network. In case the bidder quotes his rate at the generating station bus-bar,
normative transmission charges for the regional/inter-regional network, if applicable, based on the
prevailing CERC orders shall be added to the price bid submitted. The charges for the State
transmission network shall be payable by the procurer, and shall not be a part of the evaluation
criteria.
The bidder, who has quoted lowest levellised tariff as per evaluation procedure, shall be considered for the
award. The evaluation committee shall have the right to reject all price bids if the rates quoted are not
aligned to the prevailing market prices.
Deviation from process defined in the guidelines
In case there is any deviation from these guidelines, the same shall be subject to approval by the
Appropriate Commission. The Appropriate Commission shall approve or require modification to the bid
documents within a reasonable time not exceeding 90 days.
Arbitration
The procurer will establish an Amicable Dispute Resolution (ADR) mechanism in accordance with the
provisions of the Indian Arbitration and Conciliation Act, 1996. The ADR shall be mandatory and timebound to minimize disputes regarding the bid process and the documentation thereof.
If the ADR fails to resolve the dispute, the same will be subject to jurisdiction of the appropriate Regulatory
Commission under the provisions of the Electricity Act 2003.
Time Table for Bid Process
A suggested time-table for the bid process is indicated below. The procurer may give extended time-frame
indicated herein based on the prevailing circumstances and such alterations shall not be construed to be
deviation from these guidelines.
Elapsed Time from Zero
Event
date
Publication of RFQ
Zero date
Submission of Responses of RFQ
60 days
Short listing based on responses and issuance
of RFP
90 days
Bid clarification, conferences etc
150 days
Final clarification and revision of RFP
180 days
Technical and price bid submission
360 days
Shortlisting of bidder and issue of LOI
390 days
Signing of Agreements
425 days

A suggested time-table for the Single stage bid process is indicated below. The procurer may give
extended time-frame indicated herein based on the prevailing circumstances and such alterations
shall not be construed to be deviation from these guidelines.
Elapsed Time from Zero
Event
date
Publication of RFP
Bid clarification, conferences etc. & revision
of RFP
Zero date
90 days
Technical and price bid submission
180 days
Short-listing of bidder and issue of LOI
210 days
Signing of Agreements
240 days
Contract award and conclusion

The PPA shall be signed with the selected bidder consequent to the selection process in accordance
with the terms and conditions as finalized in the bid document before the RFP stage.

Consequent to the signing of the PPA between the parties, the evaluation committee shall provide
appropriate certification on adherence to these guidelines and to the bid process established by the
procurer.

The procurer shall make evaluation of bid public by indicating terms of winning bid and anonymous
comparison of all other bids. The procurer shall also make public all contracts signed with the
successful bidders.

The final PPA along with the certification by the evaluation committee shall be forwarded to the
Appropriate Commission for adoption of tariffs in terms of Section 63 of the Act.
Medium term open access
MTOA(Medium Term Open Access) application for connectivity comes under The Regulation “Central
Electricity Regulatory Commission (Grant of Connectivity, Long-term Access and Medium-term Open
Access in inter-State Transmission and related matters) Regulations, 2009.” As per the CERC regulation a
Generating station of installed capacity 250 MW and above, including a captive generating plant of
exportable capacity of 250 MW and above or a bulk consumer in respect of grant of connectivity and a
generating station including a captive generating plant, a consumer, an Electricity Trader or a distribution
licensee, in respect of long-term access or medium-term open access , as the case may be. A “Bulk
consumer” who intends to avail supply of a minimum load of 100 MW from the Inter-State Transmission
System can apply for connectivity.
The medium term open access( MTOA) means the right to use the inter-State transmission system for a
period exceeding 3 months but not exceeding 3 years. The generating station including captive generating
plant or a bulk consumer, seeking connectivity to the inter-State transmission system cannot apply for longterm access or medium-term open access without applying for connectivity. Provided that a generating
station, including captive generating plant or a bulk consumer, seeking connectivity to the inter-State
transmission. The nodal agency to grant of connectivity, for medium term open access to the inter-State
transmission system shall be the Central Transmission Utility.
The application of connectivity should accompanied by a non-refundable application fee payable in the
name and in the manner to be laid down by the Central Transmission Utility in the detailed procedure.
APPLICATION FEE FOR MTOA
Application fee (Rs. in lakh)
S.N.
Quantum of Power to be injected/off
taken into/from ISTS
FOR CONNECTIVITY
Medium-term
Access
1
Up to 100 MW
2
1
2
More than 100MW up to 500 MW
3
2
More than 100MW and up to 500 MW
6
3
More than 1000 MW
9
4
3
4
Open
The application form shall be processed within 40 days by nodal agency for medium term open access.
Procedure for Grant of Connectivity:
The application for connectivity shall contain details such as, proposed
1-Geographical location of the applicant
2- Quantum of power to be interchanged that is the quantum of power to be injected in the case of a
generating station including a captive generating plant and quantum of power to be drawn in the case of a
bulk consumer
3- The inter-State transmission system and such other details as may be laid down by the Central
Transmission Utility in the detailed procedure.
Provided that in cases where once an application has been filed and thereafter there has been any material
change in the location of the applicant or change, by more than 100 MW in the quantum of power to be
interchanged with the inter-State transmission system, the applicant shall make a fresh application, which
shall be considered in accordance with these regulations. On receipt of the application, the nodal agency
shall, in consultation and through coordination with other agencies involved in inter-State transmission
system to be used, including State Transmission Utility, if the State network is likely to be used, process the
application and carry out the necessary interconnection study as specified in the Central Electricity
Authority (Technical Standards for Connectivity to the Grid) Regulations, 2007. While granting
connectivity, the nodal agency shall specify the name of the sub-station or pooling station or switchyard
where connectivity is to be granted. In case connectivity is to be granted by looping-in and looping-out of an
existing or proposed line, the nodal agency shall specify the point of connection and name of the line at
which connectivity is to be granted. The nodal agency shall indicate the broad design features of the
dedicated. The applicant and all Inter-State Transmission Licensees including the Central Transmission
Utility shall comply with the provisions of Central Electricity Authority (Technical Standards for
Connectivity to the Grid) Regulations, 2007. The applicant or inter-State transmission licensee, as the case
may be, shall sign a connection agreement with the Central Transmission Utility or inter-State transmission
licensee owning the sub-station or pooling station or switchyard or the transmission line as identified by the
nodal agency where connectivity is being granted Provided that in case connectivity of a generating station,
including captive generating plant or bulk consumer is granted to the inter-State transmission system of an
inter-State transmission licensee other than the Central Transmission Utility, a tripartite agreement as
provided in the Central Electricity Authority (Technical Standards for Connectivity to the Grid) Regulations,
2007 shall be signed between the applicant, the Central Transmission Utility and such inter-State
transmission licensee. The grant of connectivity shall not entitle an applicant to interchange any power with
the grid unless it obtains long-term access, medium-term open access or short-term open access.
A generating station, including captive generating plant which has been granted connectivity to the grid shall
be allowed to undertake testing including full load testing by injecting its infirm power into the grid before
being put into commercial operation, even before availing any type of open access, after obtaining
permission of the concerned Regional Load Despatch Centre, which
shall keep grid security in view while granting such permission. This infirm power from a generating station
or a unit thereof, other than those based on non-conventional energy sources, the tariff of which is
determined by the Commission, will be governed by the Central Electricity Regulatory Commission (Terms
and Conditions of Tariff) Regulations, 2009. The power
injected into the grid from other generating stations as a result of this testingshall also be charged at UI rates.
An applicant may be required by the Central Transmission Utility to construct a dedicated line to the point
of connection to enable connectivity to the grid Provided that a thermal generating station of 500 MW and
above and a hydro generating station of 250 MW and above, other than a captive generating plant, shall not
be required to construct a dedicated line to the point of connection and such stations shall be taken into
account for coordinated transmission planning by the Central Transmission Utility and Central Electricity
Authority.
Applications for long-term access or medium-term open access shall be processed on first-come-first-served
basis separately for each of the aforesaid types of access: Provided that applications received during a month
shall be construed to have arrived concurrently.
Application procedure for MTOA:
1) The application for grant of medium-term open access shall contain such details as may be laid down
under the detailed procedure and shall, in particular, include the point of injection into the grid, point of
drawl from the grid and the quantum of power for which medium-term open access has been applied for.
2) The start date of the medium-term open access shall not be earlier than 5 months and not later than 1 year
from the last day of the month in which application has been made.
3) On receipt of the application, the nodal agency shall, in consultation and through coordination with other
agencies involved in inter-State transmission system to be used, including State Transmission Utility, if the
State network is likely to be used, process the application and carry out the necessary system studies as
expeditiously as possible so as to ensure that the decision to grant or refuse medium-term open access.
4) On being satisfied that the requirements specified under clause (2) of regulation 9 are met, the nodal
agency shall grant medium-term open access for the period stated in the application. Provided that for
reasons to be stated in writing, the nodal agency may grant medium-term open access for a period less than
that sought for by the applicant; Provided further that the applicant shall sign an agreement for medium term
open access with the Central Transmission Utility in case medium-term open access is granted by the
Central Transmission Utility, in accordance with the provision as may be made in the detailed procedure.
While seeking medium-term open access to an inter-State transmission licensee, other than the Central
Transmission Utility, the applicant shall sign a tripartite medium term open access agreement with the
Central Transmission Utility and the inter-State transmission licensee. The medium–term open access
agreement shall contain the date of commencement and end of medium-term open access, the point of
injection of power into the grid and point of drawl from the grid, the details of dedicated transmission lines
required, if any, the bank guarantee required to be given by the applicant and other details in accordance
with the detailed procedure. Immediately after grant of medium-term open access, the nodal agency shall
inform the Regional Load Despatch Centres and the State Load Despatch Centres concerned so that they can
consider the same while processing requests for short- term open access received under Central Electricity
Regulatory Commission (Open Access in inter-State transmission) Regulations, 2008 as amended from time
to time.
5) Medium-term customer may arrange for execution of the dedicated transmission line at its own risk and
cost before the start date of the medium term open access.
6) On the expiry of period of the medium-term open access, the medium-term customer shall not be entitled
to any overriding preference for renewal of the term.
7) A medium-term customer may relinquish rights, fully or partly, by giving at least 30 days prior notice to
the nodal agency. Provided that the medium-term customer relinquishing its rights shall pay applicable
transmission charges for the period of relinquishment or 30 days which ever is lesser.
8) When for the reason of transmission constraints or in the interest of grid security, it becomes necessary to
curtail power flow on a transmission corridor, the transactions already scheduled may be curtailed by the
Regional Load Despatch Centre. Subject to provisions of the Grid Code and any other regulation specified
by the Commission, the short-term customer shall be curtailed first followed by the medium-term customers,
which shall be followed by the long term customers and amongst the customers of a particular category,
curtailment shall be carried out on pro rata basis.
9) The transmission charges for use of the inter-State transmission system shall be recovered from the longterm customers and the medium-term customers in accordance with terms and conditions of tariff specified
by the Commission from time to time. Provided that if the State network is also being used in the access as a
part of inter-State transmission system for the conveyance of electricity across the territory of an intervening
State as well as conveyance within the State which is incidental to such inter-State transmission of
electricity, recovery of charges for such State network and terms and conditions thereof shall be in
accordance with the regulation as may be specified by the Commission under section 36 of the Act for
intervening transmission facilities, if such charges and terms and conditions cannot be mutually agreed upon
by the licensees; Provided that any disagreement on transmission charges for such State network as specified
above, shall not be the sole reason for denying access and either party may approach the Commission for
determination of transmission charges for such State network.
10) Subject to the provisions of these regulations, the Central Transmission Utility shall submit the detailed
procedure to the Commission for approval within 60 days of notification of these regulations in the Official
Gazette. Provided that prior to submitting the detailed procedure to the Commission for approval, the
Central Transmission Utility shall make the same available to the public and invite comments by putting the
draft detailed procedure on its website and giving a period of one month to submit comments; Provided
further that while submitting the detailed procedure to the Commission, the Central Transmission Utility
shall submit a statement indicating as to which of the comments of stakeholders have not been accepted by it
along with reasons thereof. The detailed procedure submitted by the Central Transmission Utility shall, in
particular, include—
a)The proforma for the connection agreement.
b)The proforma for the long-term access.
Provided that the Transmission Service Agreement issued by the Central Government as part of standard bid
documents for competitive bidding for transmission in accordance with section 63 of the Act shall be a part
of this Agreement along with necessary changes; Provided further that in case transmission system
augmentation is undertaken through the process of competitive bidding in accordance with section 63 of the
Act, the Transmission Service Agreement enclosed as part of bid documents shall be used as a part of the
proforma agreement to be entered into between the applicant and the Central Transmission Utility for longterm access. The time line for phasing of construction/modification of the transmission elements by the
Central Transmission Utility/transmission licensee, as the case may be, and the coming up of generation
facilities or facilities of bulk consumer, as the case may be, so as to match the completion times of the two;
Provided that the time period for construction of the transmission elements shall be consistent with the
timeline for completion of projects. Aspects such as payment security mechanism and bank guarantee during
the period of construction and operation: Provided that the bank guarantee during construction phase shall
not exceed Rs. 5 lakh per MW of the total power to be transmitted by that applicant through inter-State
transmission system. Provisions for collection of the transmission charges for inter- State transmission
system from the long-term customers or medium-term customers, as the case may be, by the transmission
licensee or the Central Transmission Utility.
BILATERAL TRANSACTION
Procedure for Scheduling
As per CERC Open Access Regulations, 2008 (dated 25.01.2008) & subsequent (Amendment) Regulations,
2009 (dated 20.5.2009)
Submission of application
 Application for scheduling of Bilateral Transaction through Short-Term Open Access in the interState transmission system shall be made to the Regional Load Despatch Centre of the Region
where point of drawl of electricity is situated.
 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 Regional periphery where the
supplier is located, 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”].
 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.
 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 dispatch centre
 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.
Concurrence of regional load dispatch centre
 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
Despatch Centre(s). The concurrence of the Regional Load Despatch Centre shall be as per enclosed
format [FORMAT-III: “Request/Concurrence from RLDCs”].
 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.
 In case of denial of access, the RLDC concerned shall furnish reasons for the
same, in writing.
Procedure for ADVANCED SCHEDULING of bilateral transaction
 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.
 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>>”.
 An Application for inter-State scheduling during the fourth month shall be made up to the last day
of the first month.
 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.
 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.
 All the Applications received up to 17:30 Hrs on the last day as mentioned above shall be taken up
together for consideration.
 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.
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.
 In case of perceived congestion in transmission corridor, nodal RLDC on nex day (i.e. 2nd day after
the applicable last date for submission of Application) will inform the concerned 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”],
 In
case the nodal RLDC still anticipates Congestion, it may invite electronics bids for advance
scheduling on 4th day after applicable last date for submission of Application.
Time line for ADVANCED SCHEDULING
Procedure for scheduling bilateral transaction on “FIRST-COME-FIRST-SERVE” BASIS
 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. However, 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.
 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.
 Pro-rata scheduling acceptance shall be given in case scheduling requests of the Applicants is for
more than the margins available.
Procedure for scheduling bilateral transaction on DAY-AHEAD basis
 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.
 Applications for Day Ahead transactions shall be processed only after processing of the Collective
Transactions of the Power Exchange(s).
 Pro-rata scheduling acceptance shall be given in case scheduling requests of the
Applicants is for more than the margins available.
Procedure for scheduling bilateral transaction in a CONTIGENCY
 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.
 Nodal RLDC shall accept such Application only after 1500 hrs of the day immediately preceding the
day of scheduling.
 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.
 Pro-rata scheduling acceptance shall be given in case scheduling requests of the Applicants is for
more than the margins available.
Incorporation of BILATERAL TRANSACTION on daily basis
RLDCs shall incorporate the Bilateral Transactions in the Daily Schedules of the Regional Entities. The
concerned SLDCs shall also incorporate such inter-State transactions to / from the point of injection /
drawal in the Daily schedules issued by them.
 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
Revision of schedule
 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.
 The accepted schedules for Day-Ahead transactions and transactions in a Contingency shall not be
revised or cancelled.
 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 upto 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.
 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.
Terms of payment
All payments associated with Bilateral Transaction shall be made by the Applicant to the Nodal RLDC.
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 MWhr 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 no 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:
1. Regional Transmission systems involved
2. 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:
1. Each RLDC involved
BILATERAL MARKET ANALYSIS OF TOP FIVE TRADERS.
1) Tata Power Trading Company Ltd.
Following are the four major state purchasing power from Tata power trading company limited
during the period Jan-13 to May-13.
Volume of Price purchased and weighted average Purchase Price in INR/kWh offer by
the state.
The following graph shows the quantity of power purchased by the top four states and weighted average
price offer by them during the month Jan to Feb (2013).
600
551.334
Quantity of power purchased and price offer INR/kWh
500
409.657
400
300
MU Purchased
200
134.553
118.783
WT.Avg.Purchase price
100
3.648
3.710
3.880
3.740
0
West Bengal
Uttarakhand
Rajasthan
Dadar & Nagar
Haveli
Dadar& Nagar Haveli Purchase with highest price it offers INR 3.880/kWh followed by Rajasthan
Uttarakhand and West Bengal it offers INR 3.74/kWh,3.71/kWh and 3.65/kWh respectively.
2NTPC Vidyut Vyapar Nigam Ltd.
Following are the four major states, purchasing power from NTPC vidyut vyapar nigam ltd. during the
period Jan-13 to May-13.
Most of the major purchasing states are from southern region i.e. Tamil nadu, Kerala, Andhra Pradesh they
purchased 865.469, 357.822, 153.282 respectively.
1000
865.469
900
Quantity of power purchased and price offer
800
700
600
MU Purchased
500
400
357.822
Wt. Avg. Purchase Price
300
100
157.867
153.282
200
4.991
5.417
4.277
3.811
0
KERALA
AP
TN
WB
Andhra Pradesh purchased at Rs.5.417/kWh for 153.282MU whereas Kerala, Tamil Nadu and West Bengal
purchased at Rs.4.991/kWh,4.277/kWh and 3.811/kWh for 357.822, 865.469 and 157.867MU’s of Power
3)National Energy Trading and Service:Following are the five major states, purchasing power from National Energy Trading and Service
during the period Jan-13 to May-13.
From southern region i.e. Tamil Nadu, Andhra Pradesh purchased 11.09789 and 33.9504 MU
respectively and from Northern region Delhi, Punjab and U.P purchased 23.327015,12.128703 and
4.40937 MU’s respectively.
40
Quantity of power purchased and price offer INR/kWh
33.9504
35
30
23.327015
25
20
15
MU Purchased
12.128703
11.09789
10
5.43 4.40937
3.1
5.145
5
4.05
Weighted Avg. Purchase Price
3.93
0
Tamil
Nadu
Andhra
Pradesh
U.P.
Delhi
Punjab
Tamil Nadu, Andhra Pradesh, U.P, Delhi and Punjab purchased 11.09789, 33.9504, 4.4.0937,
23.327015, 12.128703 MU’s respectively at INR 5.145/kWh ,5.43/kWh, 3.1/kWh, 4.05/kWh,
3.93/kWh.
4)PTC India Limited.
Following are the five major states, purchasing power from PTC India ltd. during the period Jan-13
to May-13.
800.00
700.00
674.72
600.00
500.43
500.00
436.49
400.00
MU Purchased
323.62
Wt. avg Purchasing price
300.00
206.13221
200.00
100.00
5.31
3.26
4.94
3.78
3.83
0.00
Andhra
Pradesh
HIMACHAL
PRADESH
KERALA
RAJASTHAN UTTRAKHAND
Weighted avg .Purchase price at trading licensees
6
5.43
5.43
5
4.89
4.2
4.1
3.73
4
4.3
4.2
4.38
4.37
3.73
3.7
3
4.53
4.15
4.28
4.15
3.76
3.48
3.1
Tata trading
NVVNL
PTC
NETS
2
1
0
Jan-13
Feb-13
0
Mar-13
Apr-13
May-13
CORRIDOR ANALYSIS
Introduction:
The corridor analysis is very important for generating companies to sell power in Short term power market.
The corridor analysis give clear view about the total transfer capability (TTC),availability transfer capability
(ATC) for power evacuation for short term transaction and
transmission reliability margin (TRM).
‘Transfer Capability’ as the measure of the ability of interconnected electric systems to reliably move power
from one area to another over all transmission lines (or paths) between those areas under specified system
conditions. It is directional in nature and is highly dependent upon the generation, customer demand and
transmission system conditions assumed during the time period analysed.
Total Transfer Capability (TTC) : Total transfer capability is defined as the amount of electric power that
can be transferred over the interconnected transmission network in a reliable manner while meeting all of a
specific set of pre- and post-contingency system conditions.
Difference between transfer capability and transmission capacity:
Transfer Capability is different from ‘Transmission Capacity’, which usually refers to the thermal limit or
rating of a particular transmission element or component.
The capability to meet load (transfer capability) would however depend on several other factors such as
spatial distribution and diversity of generation/load, network configuration (radial or meshed), availability of
reactive compensation within that control area.
Thus, the individual transmission line capacities or ratings cannot be arithmetically added to determine the
transfer capability of a transmission path or interface.
Available Transfer Capability (ATC):
Available Transfer Capability (ATC) is a measure of the transfer capability remaining in the physical
transmission network for further commercial activity over and above already committed uses. It is derived
from the Total Transfer Capability (TTC) after discounting the reliability margins. Thus ATC = TTCReliability Margins.The reliability margins could be classified as Transmission Reliability Margin (TRM)
and Capacity Benefit Margin (CBM). These have been explained in the subsequent sections.
Assessment of transfer capability
Due to the complexity involved, the assessment of transfer capability from one area to another in an
interconnected system is carried out with the help of computer simulation studies. These studies are to be
carried out for a particular scenario or snapshot, which is based on certain assumptions and forecasts. The
factors, inter alia that are to be considered in these simulations are as below:
i. Planning criteria.
ii. Forecasted demand- peak/off peak/transitions/four cardinal points.
iii. Generation despatch based on maintenance schedule for thermal and forecasted hydro generation
during peak/off peak.
iv. System Configuration—new lines expected or existing lines under outage.
v. Base Schedule Transfers mainly intra regional transactions known in advance.
vi. Credible System contingencies.
Limits to Transfer Capability
The ability of interconnected transmission network to reliably transfer power may be limited by the physical
and electrical characteristics of the systems.
The limiting condition on some portions of the transmission network or flow gates can shift among thermal,
voltage and stability limits as the network operating conditions change over time. TTC would be minimum
of thermal limit, voltage Limit and stability Limit.
Reliability Margins
Calculations of future transfer capabilities must consider the inherent uncertainties in projecting such system
parameters over longer time periods. These include projections of system conditions, transmission system
topology, projected customer demand and its distribution, generation despatch, location of future generators,
future weather conditions, available transmission facilities and existing and future power transactions.
Margins in the form of Transmission Reliability Margin (TRM) and Capacity Benefit Margin (CBM)
must be kept aside to provide operating flexibility in real time.
Transmission Reliability Margin (TRM)
NERC document on Transmission Capability Margins and their use in ATC determination defines TRM as
the amount of transmission transfer capability necessary to provide a reasonable level of assurance that the
interconnected transmission network will be secure. TRM accounts for the inherent uncertainty in system
conditions and its associated effects on ATC calculations, and the need for operating flexibility to ensure
reliable system operation as system conditions change.
Capacity Benefit Margin (CBM):
As per the 1996 NERC document, Capacity Benefit Margin (CBM) is defined as that amount of
transmission transfer capability reserved by load serving entities to ensure access to generation from
interconnected systems to meet generation reliability requirements. CBM is a more locally applied margin
than TRM, which is more of a network margin. The (n-1) criteria is applied while evaluating the first
contingency transfer capability. However a considerable difference exists between what is a (n-1)
contingency in planning horizon and a (n-1) contingency in operating horizon.
- A tower collapse or ‘lightning strike’ on a D/C tower would result in simultaneous loss of two elements.
- Non-availability or outage or non-operation of bus bar protection at a substation would result tripping of all
the lines emanating from the substation at remote end in Zone-2.
- In a substation having breaker and a half switching scheme, outage of a combination of breakers could
result in tripping of multiple for a fault on one line.
- Tripping of both the poles of an HVDC bipole system.
Therefore all such practical considerations call for an even higher reliability margin with consequent further
reduction in ATC.
Consequences of not providing for a Reliability Margin in Indian context:
The consequences of scheduling the interregional links at the full TTC level without any margin are as
under:
1. Power shortages and compulsion to meet demand by most of the state utilities would result in more
load being connected in the Northern and Western grid. This would lead to a drop in frequency, as
there would not be commensurate increase in generation in Eastern region. The line loadings would
also increase above
the TTC levels and make the system insecure to even one element outage. A 1
Hz change in frequency could
result in inter regional line loading changes of the order of 1000
MW.
2.
Tight control at the interregional level (no UI) would be completely inconsistent with loose control at
the inter state level (no limit on UI) and a floating frequency regime).
3. There would be frequent curtailments in real time, which would affect all the RLDCs/SLDCs in the
country. The effect on a single transaction due to curtailment could be as low as 2 MW and the grid
operators would be busy in rescheduling and catering to this ‘private’ need of stakeholders at a time
when the larger ‘public’ issue of grid security is at stake. It also has the potential for creating disputes.
4. Unlike a safety net in the form of Under Frequency Relays (UFRs) available for low frequency, there
is no safety net in the form of System Protection Schemes (SPS) to take care of cascade trippings and
Under Voltage Relays to guard against voltage collapse. Thus reliability margins are absolutely
essential and are non-negotiable for providing a reliable transmission services to all transmission
system users under a broad range of potential system conditions. These margins are reserved by grid
operators and made available for use by all the transmission users in real time.
From corridor analysis found that there no reliable margin between western region to southern region and
eastern region to southern region. This shows the congestion of these network due power deficit and huge
demand in southern region. Also it shows that there is need for development high capacity transmission
corridor between ER and SR to transfer surplus power from ER region to power deficit SR region.
CHAPTER-4
CONCLUSION AND RECOMMENDATION
CONCLUSION
In India although the short term market has grown in recent years ,it continue to face some of the major
challenges in terms of achieving sustained growth and meeting the increasing high level of expectations
from the stakeholders. India is perhaps the only country to have a growing market in an overall deficit
condition. In such a scenario, the benefits of trading cannot be passed on the consumers. Besides, in a deficit
market, the participants face volume risk in addition to price risk. Hence the limited evacuation path, lack of
participation and overall shortage situation, it eventually leads to price spikes and further burdens the
consumers. So the short term prices are high.
When the short term market is not promoted, most of the capacities would be linked with long term market
PPAs. But at times long term power also costs more than short term power.
As of now the short term in India is only 10% and also the prices of the short term is coming down due to
the competition in the market with various trading licensees are getting involved into it.
Long term market in India contributes to 90% of the power market because of the fact that long term PPAs
are done at very low prices and buying power from the short term market will cost more to the consumers
since the prices in the short term are more than the long term market.
Buying electricity through exchange may not be suitable for the bulk consumers since it depends on the
prices on that day whether the bids will be cleared or not or to get the power they have to bid at high rates
which eventually will cost them more. Therefore a bulk purchaser will go for long term PPAs instead of the
short term market. Short term market have helped the power sector to go in different direction altogether.
Now the small players have also come into the picture and are helping the sector to meet the increasing
demand.
It has been estimated that in FY 15 the actual supply will meet the increasing demand.
The market modification in bidding time block from one hour to fifteen minutes in the day ahead markets
run on power exchanges will make the thing more complex form the traders point of view and will attract
more and more participants due to the flexibility in bidding and will also attract the participation of
renewable energy in Power exchange but by doing this market will lose its simplicity and intuitiveness.
The introduction of evening market is little better idea than the modification of the block bidding since by
introduction of evening market the participants will be able to bid in the evening shift and if they are not
able to bid or if their bids in the morning shift are not cleared than they can bid in the evening shift and it
will also not make the bidding error prone due to large amount of data to be entered.
So we can say that Indian Power Market is growing very rapidly and short term market have made the
market more competitive and attractive with the prices going down and more volumes are getting cleared
through exchange.
RECOMMENDATION
IDEAL BIDDING PROCEDURE & STRATEGY FOR BETTER NET SALE REALISATION
 KEY FACTORS TO BE TAKEN INTO CONSIDERATION WHILE PREPARATION OF
BIDDING SCHEDULE
1. Finalisation of minimum load after taking OPEN ACCESS Bilateral transactions in to consideration
 Deciding threshold load for next day after considering gap from bilateral schedule &
compatibility as well as availability from generator end.
 Placing at lower price to maintain the load flow & bridging gaps in schedules for safety
running of base load plant.
2. Filling in to blocks by analysing price Vs volume trends of last 7-10 days to maximise the chances of
getting maximum quantum scheduled in day ahead market.
3. UI trend analysis of last 7-10 days for placing bids at rate so as to get maximum benefit through UI
under injection/over injection depending upon frequency trend throughout the day.
4. Maximising Net Sale Realisation & bridging gaps in schedules by trading through IEX/PXIL.
References
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www.cea.nic.in
www.cercind.gov.in
www.powergridindia.com
www.nldc.in
www.nrpc.gov.in
www.vedantaaluminium.com
www.sldcorissa.org.in
www.erldc.org
www.srldc.org
www.nrldc.org
www.wrldc.org
Electricity Act 2003
National Tariff Policy
www.iexindia.com
www.ptcindia.com
www.eastrpc.org
www.westrpc.org
www.nrpc.gov.in
www.srpc.org