Summer Internship Report
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SUMMER INTERNSHIP REPORT ASSESMENT OF INDIAN POWER MARKET PRE AND POST GRID FAILURE Under the guidance of Ms Sugandha Agrawal, Sr Fellow (Strategic Management),CAMPS,NPTI & Mr.V.K Agrawal, General Manager, NLDC AT National Load Dispatch Centre, New Delhi Submitted by PRAVAR BALLAL ROLL NO:60 MBA( POWER MANAGEMENT )
(Under the Ministry of Power, Govt. of India) Affiliated to
MAHARSHI DAYANAND UNIVERSITY, ROHTAK
1 2 DECLARATION I,PRAVAR BALLAL, Roll No-60, student of MBA-Power Management(2012-14) at National Power Training Institute, Faridabad hereby declare that the Summer Training Report entitled “ASSESSMENT OF INDIAN POWER MARKET PRE AND POST GRID FAILURE” is an original work and the same has not been submitted to any other Institute for the award of any degree
A Seminar presentation of the Training Report was made on ------and the suggestions as approved by the faculty were duly incorporated.
Presentation In-Charge Signature of the Candidate
(Faculty)
Countersigned
Director/Principal of the Institute
ACKNOWLEDGEMENT
I am thankful to Mr. V. K. Agrawal (GM,NLDC) for the support and help to carry out this project work successfully. Words would be too small to describe the brilliance and versatility of my project guide Mr. Kaushik Dey (Sr. Engineer, NLDC) for their able and consistent guidance, supervision, help and encouragement at each step of the work which motivated me through the project. I really feel lucky to be under such an able guiding force in the field of power sector who never got irritated even with the most minor & silliest doubts of mine.
I would like to extend my gratitude to Ms. Sugandha Agrawal, Sr. Fellow, NPTI (My Mentor ) for her continuous help and motivation during summer internship.
3 I am very much thankful to Mr. S.K.Choudhary (Principal Director, CAMPS, NPTI), Ms. Manju Mam (Director, NPTI), Ms. Indu Maheshwari (Deputy Director, NPTI) for providing me an opportunity to work with National Load Dispatch Centre & their precious help and support.
My sincere thanks to my Batch Mates & Seniors who are working with other reputed organization for the help they rendered at each stage of the project.
Pravar Ballal
EXECUTIVE SUMMARY
An analysis of short-term transactions of electricity in India has been made in this Report on Short-term Power Market for the year 2012-13. Here, “short-term transactions of electricity” refers to contracts of less than one year period for electricity transacted under bilateral transactions through Inter-State Trading Licensees (only inter-state part) and directly by the Distribution Licensees (also referred as Distribution Companies or DISCOMs), Power Exchanges (Indian Energy Exchange Ltd (IEX) and Power Exchange India Ltd (PXIL)), and Unscheduled Interchange (UI). The analysis includes (i) Yearly/monthly/daily trends in shortterm transactions of electricity; (ii) Time of the day variation in volume and price of electricity transacted through traders and power exchanges; (iii) Trading margin charged by trading licensees for bilateral transactions (iv) Analysis of open access consumers on power exchanges; (v) Major sellers and buyers of electricity through licensed traders and power exchanges; (vi) Effect of congestion on volume of electricity transacted through power exchanges; (vii) Tariffs of long-term sources of power for various distribution companies; and (viii) Analysis of Renewable Energy Certificates (RECs) transacted through power exchanges. Salient features of the report are listed below and are discussed in details in subsequent sections. 1. Of the total electricity procured in India in 2012-13, the short-term power market comprised 11 per cent. The balance 89 percent of generation was procured mainly by distribution companies through long-term contracts and short-term intra-state transactions. 2. In volume terms, the size of the short-term market in India was 98.94 billion kWh (units) in the year 2012-13. As compared to the volume of electricity transacted through short-term market in the year 2011-12 (94.51 billion units), this was about 5 percent
4 higher. Majority of this growth in volume of 4.43 billion units was accounted for by growth in transactions through power exchanges (181%), followed by bilateral transactions through the inter-state trading licensees (6%). The direct bilateral transactions between the DISCOMs and the transactions through UI declined by 19% and 68% respectively. A caveat, however, needs to be added; in case of traders only inter- state transactions have been considered. 3. Excluding UI and direct bilateral sale between the DISCOMs, the volume of electricity transacted was 59.66 billion units in 2012-13. This was about 16 percent higher than in 2011-12. Volume of electricity transacted through power exchanges witnessed a sharp increase of about 51% over 2011-12 volume. On the other hand, the increase in the volumeof electricity transacted through inter-state trading licensees was very low at 0.8%. In monetary terms, the size of this segment of the short-term market was `24272 crore in the 2 year 2012-13 , which was 18% more than in the year 2011-12. Of this, 8646 crore was the value of electricity transacted through power exchanges (56% more than `5553 crore done in 2011-12), and the balance of `15624 crore was the value of inter-state transaction of electricitythroughtradinglicensees(about4%more than`14979croredone in2011-12).
4. In absolute terms, the volume of UI in the year 2012-13 decreased by 11% over 2011- 12. The share of UI as a percentage of total volume of short-term transaction of electricity continued the downward trend of past years and was about 25% in 2012-13, down from 39%, 34% and 29% respectively in the years 2009-10, 2010-11 and 2011-12.
5. The share of direct bilateral transactions between DISCOMs as a percentage of total short term transaction volume declined to about 15% in the year 2012-13 (as compared to about 16% in the year 2011-12). In terms of volume, these direct bilateral transactions between DISCOMs also witnessed a decline of about 6% in 2012-13 as compared to 2011-12. 6. The weighted average price of electricity transacted through power exchanges was Rs3.67 per kWh and through trading licensees was `4.33 per kWh in 2012-13. The corresponding values for the year 2011-12 were `3.57 per kWh and `4.18 per kWh, respectively. In the year 2012-13, the weighted average price of electricity transacted through Day Ahead Market sub-segment of the power exchanges was `3.67/kWh and that through Term Ahead Market sub-segment was Rs3.91/kWh.
LIST OF FIGURES
5 LIST OF TABLES
ABBREVIATIONS Abbreviation Expanded Version ADHPL Allain Duhangan Hydro Power Limited ADHPL (GOHP) Allain Duhangan Hydro Power Limited (GOHP Share) APCPDCL Central Power Distribution Company of Andhra Pradesh APPCC Andhra Pradesh Power Coordination Committee AVVNL Ajmer Vidyut Vitaran Nigam Limited BALCO Bharat Aluminium Company Limited BESCOM Bangalore Electricity Supply Company Limited BRPL BSES Rajdhani Power Limited BSEB Bihar State Electricity Board BU Billion Units (Billion kWh) BYPL BSES Yamuna Power Limited CCGT Combined Cycle Gas Turbine CERC Central Electricity Regulatory Commission CGS Central Generating Stations CPP Captive Power Producer/Plant CSPTCL Chhattisgarh State Power Trading Company Limited CSPDCL Chhattisgarh State Power Distribution Company Limited DAM Day Ahead Market
6 DISCOMS Distribution Companies FGUTPP Firoz Gandhi Unchahar Thermal Power Project GoHP Government of Himachal Pradesh GPS Gas Power Station GUVNL Gujarat Urja Vikas Nigam Limited HEP Hydro Electric Project HHI Herfindahl-Hirschman Index HPSEB Himachal Pradesh State Electricity Board HSD High Speed Diesel IEX Indian Energy Exchange Limited ISGS Inter State Generating Station JKHCL Jaypee Karcham Hydro Corporation Limited
TABLE OF CONTENTS
Contents
7 CHAPTER-1
INTRODUCTION
1.1 OVERVIEW In India, the total installed capacity of 211 GW is in excess of 35% of the total peak demand in the country which was close to 135 GW for the year 2012-13. Whereas the peak demand actually met was only to the extent of 123 GW, thereby leading to an ‘Unserved Demand’ of 12GW. Evidently, the issue is not with the availability of adequate generation capacity but with the non-availability of generation capacity due to the prevailing fuel shortage and then followed by non-utilization due to inadequacy in evacuation system and inability of the cash strapped Discoms to purchase power to serve the needs of the consumers.
8 Analysis of the Day-Ahead Market at IEX shows the same phenomenon where the total monthly sell bids received were 3887 MUs, higher than the total buy bids of 3271 MUs in the market indicating an over-supply situation. As a result the prices of electricity discovered at IEX came down substantially. The prices discovered on the exchange in the recent months are lower than the prices that prevailed earlier this year as well as the prices of last summer. The unconstrained price has come down from Rs3.42 per unit in May’12 to Rs2.73 in May’13. Similarly the area price showed downward trend as compared to the same month last year.
As compared to the last month the unconstrained price fell down by 15% from 3.16 per unit in April’13. The area prices were also lower than the values in the previous month. Even the constrained region of south experienced lower prices this month, with average area price falling from Rs8.41 per unit in April’13 to Rs6.47 per unit in May’13, a drop of 23%
While no Discoms are utilizing cheaper power from the exchange as an alternate to load shedding, many industries are utilizing the exchange as an alternate to costly power through diesel generator sets. In the month of May, the average participation at IEX in the day-ahead electricity market was 1297, higher from 1244 in the month of April’13, whereas the maximum participation of 1394 was observed on May 24 which was the hottest day of the year, with the average daily traded volume hovered around 80.6 MUs in May’13
There was also a substantial decrease in the congested volume in May’13 as compared to the previous month primarily due to more wind generations in Tamil Nadu which relieved the shortage in the state. The volume lost due to congestion in May’13 was close to 362.8 MUs whereas in April’13 the same touched 521.4 MUs, a drop of 30%
9 1.2 OBJECTIVE
A well-functioning electricity market requires an effective market monitoring process. The main focus of this study is to be a part of market monitoring process and to closely look after well-functioning of electricity market. Here, “short- term transaction of electricity” refers to the contrast of less than one year period, for electricity transacted (inter-state & intra-state) through Inter-state Trading Licensees and directly by the Distribution Licensees, power Exchanges (Indian Energy Exchange Ltd (IEX) and Power Exchange India Ltd (PXIL), and Unscheduled Interchange (UI). The main objective behind commissioning this study were to: i. To observe the trends in volume and price of the short-termtransactions of electricity. ii. To analyze competition among the market players iii. To analyze effect of congestion on volume and price of Renewable Energy Certificates (RECs) transacted through power exchanges. iv. To disclose/sisseminate all relevant market information.
1.3 SCOPE OF WORK
10 In the succeeding FY 2012-13 Power exchange has successfully overtaken the power market business, initially the large portion of business was done through Unscheduled Interchange (UI). But in recent trend it has overtaken by Power Exchange. The study will help us to understand the entire process as to how the market players have switched to Power Exchange from UI for short term transactions, and to see the changing trend in volume and price in short-term transaction of electricity.
1.4ORGANIZATIONAL PROFILE
National Load Dispatch Centre (NLDC) has been constituted as per Ministry of Power(MOP) notification; New Delhi dated 2nd March 2005 and is the apex body to ensure integrated operation of the national power system. On 25th February, 2009 the National Load Dispatch Center (NLDC) was inaugurated. Now these Regional Load Dispatch Centers (RLDCs) and National Load Dispatch Center (NLDC) is a separate Organization named POSOCO (Power System Operation Corporation). POSOCO is fully owned subsidiaries of POWERGRID. There are 5 RLDCs and 33 SLDCs under NLDC
Mission A ‘mission critical activity’ for uninterrupted, secure, reliable and quality power supply in the country A ‘relentless pursuit’ for optimization of precious power generating resources under minimization of inherent system losses
11 A ‘facilitator’ for an efficient electricity market A ‘vehicle’ far equitable and fair use of the transmission infrastructure in the country A ‘vital link’ between the administrators, planners & regulators on one end and physical system on the other end.
Functions of National Load Dispatch Centre Supervision over Regional Load Dispatch Centers. Scheduling and dispatching of electricity over the inter regional links in accordance with grid standards specified by the authority and grid code specified by Central Commission in coordination with Regional Load Dispatch Centers. Coordination with Regional Load Dispatch Centers for achieving maximum economy and efficiency in the operation of National Grid. Monitoring of operations and grid security of the National Grid. Supervision and control over the inter-regional links as may be required for ensuring stability of the power system under its control. Coordination with Regional Power Committees for regional outage schedule in the national perspective to ensure optimal utilization of power resources. Coordination with Regional Load Dispatch Centers for the energy accounting of inter-regional exchange of power. Coordination for restoration of synchronous operation of national grid Regional Load Dispatch Centers. Coordination for trans-national exchange of power. Providing Operational feedback for national grid planning to the Authority and Central Transmission Utility. Levy and collection of such fee and charges from the generating companies or licensees involved in the power system, as may be specified by the Central Commission.
12 Dissemination of information relating to operation of transmission system in accordance with direct or regulations issued by Central Government from time to time.
CHAPTER-2
LETERATURE SURVEY, LEGAL POLICIES AND RESEARCH METHODOLOGY
2.1 LITERATURE SURVEY In this Project certain concept related to “Real Time Power System Operation are presented. These concepts are derived from extensive study of the practical power system operation of Indian Electricity system and various regulations stipulated by Central Electricity Authority of India.
In the late 1990’s, there was acute shortage in electricity before deregulation has taken place in India. For most of the time the Indian Regional grid used to operate at precariously low frequency at 48 Hz, voltage at 300KV (400KV) and around. This led to severe insecurity in the grid operation. This instability in operation of power system triggered grid contingencies very frequently, resulting in system separation and grid disturbances. This insecure and unstable grid operation caused immense financial loss to
13 the industry and the inefficient operation of the electrical equipment led to increased electrical losses also. In addition, with multiple blackouts in Indian Power systems, electrical sector experienced energy crisis along with serious financial problems. During this period, all electric power utilities throughout India were operated with an organizational model i.e. vertically integrated model. The electrical utility as a controlling authority operated model. The Electrical utility as a controlling authority operated the generation.
2.2 LEGAL POLICIES
2.2.1Real Time Power System Operation and Control
During this period there were wide fluctuations in the frequency and voltage in Indian power systems due to shortage of power as indicated above. The new tariff mechanism known as Availability Based Tariff (ABT) was implemented in regional grids so as to impose the grid discipline. It came into existence for regional grids of India from the year 2003 onwards. The author identified complex issues and variety of critical situations extending the new tariff mechanism to the inner layers of the state sector and implications of the power system operations in a Real-time environment under ABT mechanism. These electric utilities introduced privatization in their sectors to improve efficiency. During 21st century many electrical utilities and power network companies have been forced to change their ways of doing business from vertically integrated mechanism to open market system. The Open Access was introduced in Indian electrical environment with help of 2003 Electricity ACT.
2.2.2Cooperative Game Theory
14 The Game theory is divided in to two branches. One is non-cooperative and other is cooperative Game theory. These two branches mainly differ in modeling interdependence among the players. The non-cooperative game is generally termed as procedural game theory whereas the cooperative game theory is termed as combinatorial game theory. The first one specifies various actions that are available to the players while second one describes the outcomes that when the players come together in different combinations. This would indicate an important analytical distinction between them. The cooperative Game theory (CGT) is widely applied to allocate transmission costs, wheeling charges and losses to the players of electricity markets. The CGT is also used for analyzing the economic effect of interconnected power system .
2.2.3Transmission costs allocation
Two solution concepts of nucleolus and the Shapley value of the cooperative game theory are introduced in [28] for determining Wheeling charges allocation. In this case, everyone has to share the incurred costs by the wheeler company in order to accommodate all the transactions with adequate quality, reliability, and security levels. An approach for congestion cost allocation in pool electricity markets, based on the Cooperative Game Theory. The implementation of two well-known solution methods, nucleolus and the Shapley value to a bilateral transaction electricity market as well as in a pool market is discussed in this paper. A general game theoretic model for the RTN evaluation is presented, and the solution procedure is discussed in this paper. The strategic behavior of market agents in the spot market is modeled according to a Supply Function Equilibrium approach. The impact of transmission capacity expansion on market participants’ strategic behavior is studied in this paper.
15 A transmission trunk system is defined as a unique and common system constituted by electrical lines and substations that are economically efficient and necessary to allow the development of an electrical market and the supply of demand in the respective electrical system at a minimum cost and in an efficient manner. The principles of cooperation and interaction between agents that are the base for the cooperative games theory, the Shapley value approach is used in [35]. A scheme for the allocation of the transmission network expansion costs among market participants based on cooperative game theory is presented in [36]. The allocation takes into account the physical and economic impacts of the new transmission assets in this paper. The payments made by each participant are calculated using the Shapley value formula .They are based on the increase in social welfare brought about by the new assets and the pre-investment surpluses of the players. They influence the different market participants on the expansion decision. All firms have incentives to support the expansion through provision of reimbursements. An open access transmission method is based on the Nash bargaining game for power flow analysis in which each transaction and its optimal price are determined to optimize the interests of individual parties of power system.
2.2.4Frequency Control Models
The power system modeling suitable to market structures must ensure controllable generation for regulating both frequency (by controlling the output of the active power) and voltage (by controlling the output of reactive power). Several control scenarios based on robust and optimal approaches have been proposed for the AGC system in deregulated power systems. A new load flow method considering governor characteristics of generators andvoltage, frequency characteristics of loads are presented at [93]. The method of power-flow analysis considering frequency as an additional variable depicts the actual control phenomena in power systems The load frequency control in a deregulated electricity market designed for Poolco-based transactions,
16 bilateraltransactions, and a combination of these two utilizing an integral controller is presented in [95] and [96]. A method to find the optimum parameter of this type of controller for a two-area system of identical rating has been proposed and the concept of “DISCO participation matrix” (DPM) that helps the visualization and implementation of the contracts is proposed in [96].
2.3 METHODOLOGY
With the broad objective of analyzing the power market scenario pre and post grid failure, various data have been collected from different sources revealing the market operation in FY 2012-13. The main concern is been given to the short term transaction of electricity and hence data have been collected regarding Volume, Price, Percentage growth in revenue, Congestion and Voltage profile. Revealing from this data the conclusion has been drawn regarding the improvement of the grid post Grid Failure and further DEVIATION SETTELMENT MECHANISM has been discussed
17 CHAPTER-3
SHORT-TERM POWER MARKET IN INDIA, 2012-13
An analysis of the short-term transactions of electricity in India has been done in this Report on Short-term Power Market3 for the year 2011-12. Here, “short-term transactions of electricity” refers to contracts of less than one year period, for electricity transacted under bilateral transactions through Inter-State Trading Licensees (only inter- state part) and directly by the Distribution Licensees (also referred as Distribution Companies or DISCOMs), Power Exchanges (Indian Energy Exchange Ltd (IEX) and Power Exchange India Ltd (PXIL)), and Unscheduled Interchange (UI). The analysis includes (i) Yearly/monthly/daily trends in short-term transactions of electricity; (ii) Time of the day variation in volume and price of electricity transacted through traders and power exchanges; (iii) Trading margin charged by trading licensees for bilateral transactions (iv) Analysis of open access consumers on power exchanges; (v) Major sellers and buyers of electricity through licensed traders and power exchanges; (vi) Effect
18 of congestion on volume of electricity transacted through power exchanges; and (vii) Tariffs of long-term sources of power for various distribution companies.
3.1 Yearly Trends in Short-term Transactions of Electricity (2008-09 to 2011-12)
The analysis on yearly trends in short-term transactions includes the electricity transacted through the following segments: trading licensees (inter-state part only) under bilateral transactions or “bilateraltrader” segment , power exchange segment with transactions in both, Day Ahead and Term AheadMarkets, UI segment and direct transactions of electricity between DISCOMs.
Inter-state trading licensees have been undertaking trading in electricity since 2004and the power exchanges started operating since 2008. The two power exchanges, IEX and PXIL started their operations in June 2008 and October 2008 respectively. As of March 2012, there were 41 inter-state trading licensees and twopower exchanges.
3.1.1Total Short-term Transactions of Electricity with respect to Total Electricity Generation
Total volume of short-term transactions of electricity increased from 65.90 billion kWh (BU) in 2009-10 to 98.94 BU in 2012-13. The annual growth in volume was 24% from
19 2009-10 to 2010-11 and 16% from 2010-11 to 2011-12 and 5% from 2011-12 to 2012- 13. Total volume of short-term transactions of electricity as percentage of total electricity generation has increased from 9% in 2009-10 to 11% in 2012-13 (Table-1).
Table 1:Total Volume of Short-term Transactions of Electricity with respect to Total Electricity Generation Total volume of Short- term Total Volume of Transactions of Short-term Electricity as Transactions of Total Electricity % of Total Electricity Year Electricity (BU) Generation (BU) Generation 2009-10 65.9 764.03 9% 2010-11 81.56 809.45 10% 2011-12 94.51 874.17 11% 2012-13 98.94 907.49 11% Source: NLDC
The analysis of yearly trends in different segments of short-term transactions of electricity i.e. electricity transacted through traders and power exchanges, UI, directly between DISCOMs is dealt in the following sections.
20 3.1.2 Electricity Transacted through Trading Licensees and Power Exchanges
Table-2, Table-3, Figure-1 & Figure-2 show details of volume of electricity transacted through trading licensees under bilateral transactions and through power exchanges for the period from 2008-09 to 2011-12. The volume of electricity transacted through inter- statetrading licensees and power exchanges increased from 24.69 BU in 2008-09to 59.66 BU in2012-13. The share of electricity transacted through trading licensees and power exchanges(in volume terms) as a percentage of total short-term transactions of electricity has shown a moderate rise (from 51.45% in 2009-10 to 60.29% in 2012-13). The growth in volume forthis segment during the year 2012-13 as compared to 2011-12 was 8.28 BU in absolute terms and about 16.11 in percentage terms. Majority of this growth has come from the power exchange segment (7.48 BU). Looking at the individual sub-segment growth between the years 2011-12 and 2012-13, it is observed that the growth was 2.27% in bilateral trader segment and the growth was 48.86% in power exchange segment. Whereas between the year 2010-11 and 2011-12 the growth in bilateral was 29% whereas in power exchange it was only 15%.
Table 2:Total Volume of Short-term Transactions of Electricity with respect to Total Electricity Generation Year Electricity Electricity Total Transacted Transacted (BU) through through Trading IEX and
21 Licensees PXIL (BU) (BU) 2008-2009 21.92 2.77 24.69 2009-2010 26.72 7.19 33.91 2010-2011 27.7 15.52 43.22 2011-2012 35.84 15.54 51.38 2012-2013 36.64 23.02 59.66
Figure 1:Total Volume of Electricity Transacted through Trading Licensees and Power Exchange
Table 3:Electricity Transacted through Trading Licensees and Power Exchanges
Volume of Electricity Electricity Transacted Transacted through Total Short-term through traders and Traders and Power Transactions of PXs as % to Total Year Exchanges (BU) Electricity (BU) Volume of Short-term 2009-10 33.91 65.9 51.45% 2010-11 43.22 81.56 53.00% 2011-12 51.38 94.51 54.37% 2012-13 59.66 98.94 60.29%
Figure 2:Electricity Transacted through traders and PXs as % to Total Volume of Short-term
22 The price of electricity transacted through trading licensees and Power Exchanges is shown in Table-4 and Figure-3. The weighted average price of electricity transacted through trading licensees and power exchanges declined from `7.29/kWh and `7.49/kWh respectively in 2008-09 to Rs4.33/kWh and Rs3.57/kWh respectively in 2012-13. It is thus seen that the price of electricity in the short-term market in the year 2012-13 was on the lower side as compared to price prevalent in the previous four years. The decreasing trend in weighted average prices has had its effect on the market sizeof this segment in monetary terms (Table-5). Thus, although in physical terms (BU terms) the size of this segment increased only by about 16 % in the year 2012-13 compared to 19% increase in 2011-12, But in monetary terms the growth has been about 17% (or about Rs3546crore), which was only 10% (or about Rs1875crore) in 2011-12 . In fact, the bilateral trader sub- segment, though registering a low growth of about 2.22 % in physical terms as compared to 29% in 2011-12, also registered low growthin monetary terms of only about 2% (or about Rs881crore) as compared to13 % (or about `1711 crore) in 2011-12.The power exchange segment, though registered high growth of 48%in physical terms as compared to growth of 0.15% in 2011-12, also registered high growth of about 48% in monetary terms (or about Rs2665crore) as compared to growth of 3% (or about Rs164crore) in 2011-12.
Table 4:Electricity Transacted through traders and PXs as % to Total Volume of
23 Short-term
Price of Electricity transacted Price of Electricity transacted through Trading Licensees through Power Exchanges Year (`/kWh) (DAM+TAM) (`/kWh) 2008-09 7.29 7.49 2009-10 5.26 4.96 2010-11 4.79 3.47 2011-12 4.18 3.57 2012-13 4.33 3.57
Figure 3:Price of Electricity transacted through Trading Licensees and Power Exchange
Table 5:Electricity Transacted through traders and PXs as % to Total Volume of
24 Short-term Total Size Price of Price of Size of of the Electricity Electricity Power bilateral Electricity Transacte Size of Electricity Transacte Exchang trader + Transacte d bilateral Transacted d e Power d through through trader through through Market Exchange Trading Trading Market Power Power in Market Licensees Licensees in ` Exchanges Exchanges (Rs (Rs Year (BU) (Rs/kWh) Crore (BU) (Rs/kWh) Crore) Crore) 2009-10 26.62 5.26 14055 7.19 4.96 3563 17617 2010-11 27.70 4.79 13268 15.52 3.47 5389 18657 2011-12 35.84 4.18 14979 15.54 3.57 5553 20532 2012-13 36.63 4.33 15860 23.02 3.57 8218 24078
3.1.3 Electricity Transacted through UI
The volume and price of electricity transacted through UI is shown in Table-6 andFigure- 4. The volume and price of electricity transacted through UI in 2008-09 represents the period from August 2008 to March 2009. It can be observed from Table that the volume of electricity transacted through UI has increased from 25.81 BU in 2009-10 to 27.76 BU in 2011-12 but again decreased to 24.75 in 2012-13, and the volume of UI as percentage of total short-term volume has declined to a level of 25% in the year 2012-13 as compared to 39% in 2009-10. It can also be observed from the table that the average price of UI (New Grid and SR Grid) declined from Rs4.62/kWh in 2009-10 to Rs3.51/kWh in 2012-13.
25 Table 6:Volume and Price of Electricity Transacted through UI
Volume of UI as % Volume of UI Total Volume of of total volume of Price of UI Year (BU) Short-term (BU) Short-term (`/kWh) 2008-09 14.39 35.27 41% 6.7 2009-10 25.81 65.9 39% 4.62 2010-11 28.08 81.56 34% 3.91 2011-12 27.76 94.51 29% 4.09 2012-13 24.75 98.94 25% 3.51
Figure 4:Volume of electricity transacted through UI
Figure 5:Price of electricity transacted through UI
3.1.4 Electricity Transacted Directly Between DISCOMs
26 The volume of electricity transacted directly between DISCOMs is shown in Table-7and Figure-5. It can be observed from the table that the volume of electricity transacted directly between DISCOMs increased significantly from 6.19 BU in 2009-10 to 15.37 BU in 2011-12 but again decreased to 14.51BU in 2012-13. It can also be observed that, the share of electricity transacted directly between DISCOMs as percentage to total volume of short-term transaction of electricity had also increased from 9% to 16% between 2009-10 and 2011-12 but again decreased to 15% in 2012-13.
Table 7: Volume of Electricity Transacted Directly between DISCOMs
Volume of Electricity Transacted Directly Volume of Bilateral between DISCOMs Total Volume of Direct as % of total Year (BU) Short-term (BU) volume of Short-term 2008-09 3.31 35.27 9% 2009-10 6.19 65.9 9% 2010-11 10.25 81.56 13% 2011-12 15.37 94.51 16% 2012-13 14.51 98.94 15%
Figure 6:Volume of Electricity Transacted Directly between DISCOMs
27 3.2Monthly Trends in Short-term Transactions of Electricity (April 2012-March 2013)
During 2011-12, the share of the total short-term transactions in volume terms,including UI as a percentage of total electricity generation in the country was about 11 percent (Figure-7 and Table-8)
Figure 7:Share of Different Segments in Total Electricity
The share of different segments within the total short-term transaction for the year 2012-13 has been shown in the Figure-8 below.
Figure 8:Share of Different Segments in Short Term Transactions
3.2.1 Volume of Short-term Transactions of Electricity
During the FY2012-13, total electricity generation excluding generation from renewable and captive power plants in India was 907490.43 MUs (Table-8). Of the total electricity generation, 98940.45MUs (10.90%) were transacted through short-term, comprising of 51156.9MUs (5.63%) through Bilateral (through traders and term ahead contracts on Power Exchanges and directly between distribution companies), followed by 23024.42MUs (2.53%) through day ahead collective transactions on Power Exchanges (IEX and PXIL) and 24759.13MUs (2.72%) through UI (Table-8 & Figure-8). Of the total short-term transactions, Bilateral constitute 51.70% (37.03% through traders and
28 term-ahead contracts on Power Exchanges and 14.67% directly between distribution companies) followed by 23.27% through day ahead collective transactions on Power Exchanges and 25.02% through UI (Table-8& Figure-8). Daily volume of short- term transactions is shown in Table-8 & Figure-8. The percentage share of electricity traded by each trading licensee in the total volume of electricity traded by all trading licensees is provided. The trading licensees undertake electricity transactions through bilateral and through power exchanges. Here, the volume of electricity transacted by the trading licensees includes bilateral transactions and the transactions undertaken through power exchanges. There were 42 trading licensees as on 31.03.2013, of which only 20 have engaged in trading during March 2013. Top 5 trading licensees had a share of 79.79% in the total volume traded by all the licensees.
Herfindahl-Hirschman Index (HHI) has been used for measuring the competition among the trading licensees. Increase in the HHI generally indicates a decrease in competition and an increase of market power, whereas decrease indicates the opposite. The HHI above 0.15 indicates a moderate concentration of market power. The HHI computed for volume of electricity traded by trading licensees (inter-state & intra-state) was 0.1583 for the month of March 2013, which indicates that there was moderate concentration of market power. The volume of electricity transacted through IEX and PXIL in the day ahead market was 2259.65MUs and 64.70MUs respectively. The volume of total Buy bids and Sale bids was 3975.76MUs and 3721.00MUs respectively in IEX and 246.26MUs and 206.68MUs respectively in PXIL. The gap between the volume of buy bids and sale bids placed through power exchanges shows that there was more demand in IEX (1.07 times) and PXIL (1.19 times) when compared with the supply offered through these exchanges. The volume of electricity transacted through IEX and PXIL in the term-ahead market was 6.80MUs and 0.30MUs respectively.
29 Figure 9:Total volume of short term transaction of Electricity
Table 8:Total volume of short term transaction of Electricity T ot al el e ct Total Power Total short ri Bilateral Bilateral UI Bilateral Exchange term ci PERIOD through between TRANSACTION transactio transaction transaction ty Traders DIDCOMS S n (DAM+TAM) s g e n er at e d 74 APRIL'12 2384.7 1011 3395.69 1337 2576 7309 72 5
30 78 MAY'12 2416.6 1068.3 3484.82 1478 2737 7700 78 6 76 JUN'12 2946.6 1148.4 4095.05 1629 3638 9362 30 6 76 JULY'12 3766.4 1737.7 5504.12 1572 2900 9977 09 1 74 AUG'12 3855 1910.7 5765.7 1861 2076 9703 26 3 73 SEP'12 3072.2 1655.6 4727.76 1910 1662 8299 07 5 78 OCT'12 2433.5 901.7 3335.15 2301 1542 7178 31 1 72 NOV'12 3205.4 931.5 4136.86 2186 1475 7797 60 2 76 DEC'12 3369.5 1086.3 4455.79 2315 1480 8251 49 6 78 JAN'13 3547.3 1192.8 4740.11 2099 1503 8341 40 4 68 FEB'13 2680.6 949.9 3630.45 2012 1534 7177 45 9 79 MAR'13 2960.6 924.81 3885.4 2324 1637 7847 97 4 9E Total 36638 14519 51156.9 23024 24759 98940 +0 5 % share in total 10 4.0373 1.5999 5.637183 2.537 2.728 10.9 generatio 0 n % share 37.031 14.674 51.70474 23.27 25.02 100 in
31 Shortter m Volume As we can see from the above table as well as above graph the transaction through bilateral has kept varying within a defined limit and always been on the higher side. Whereas the transaction through power exchanges has started at very low volume of 1337 MUs in the starting of this fiscal year which nearly kept on increasing with the preceding months and crossed the UI consumption in month of August and ended in month of march at 2324 MU.
On the other side the total volume of electricity transacted through UI started at higher volume of 2576 MU which nearly kept on increasing upto month of july in which we faced GRID FAILURE. Looking towards undue advantage of UI low rates the UI rates were subsequently increased and thus the buyers started switching to power exchange rather than UI to buy electricity in short term market.
Hence total volume of electricity transacted through UI decreased after month of july which further kept on decreasing throughout the year and finally ended at the volume of 1637 MU at month of March’13
The volume of short-term transaction of electricity as percentage of total electricity generated varied between 9.16% and 13.11% during the period
32 Table 9:Volume of Short-term Transactions of Electricity as % of Total Electricity
Short-term transactions as % of total electricity Period generation APRIL'12 9.78% MAY'12 9.77% JUN'12 12.26% JULY'12 13.11% AUG'12 13.06% SEP'12 11.35% OCT'12 9.16% NOV'12 10.74% DEC'12 10.78% JAN'13 10.63% FEB'13 10.48% MAR'13 9.81%
There were 42 trading licensees as on 31.03.2013, of which only 20 have engaged in trading during March 2013. Top 5 trading licensees had a share of 79.79% in the total volume traded by all the licensees.
Herfindahl-Hirschman Index (HHI) has been used for measuring the competition among the trading licensees. Increase in the HHI generally indicates a decrease in competition and an increase of market power, whereas decrease indicates the opposite. The HHI above 0.15 indicates a moderate concentration of market power. The HHI
33 computed for volume of electricity traded by trading licensees (inter-state & intra-state) was 0.1583 for the month of March 2013, which indicates that there was moderate
Table 10:PERCENTAGE SHARE OF ELECTRICITY TRANSACTED BY TRADING LICENSEES IN 2012-13
% Share in total Volume transacted Herfindahl- Sr.N Name of the Trading by Trading Hirschman o Licensee Licensees Index
1 PTC India Ltd 28.86% 0.0833
Tata Power Trading 2 Company(P) Ltd. 15.98% 0.0255
JSW Power Trading 3 Company Ltd. 15.69% 0.0246
NTPC Vidyut Nigam 4 Ltd. 10.60% 0.0112
Reliance Energy 5 Trading (P) Ltd. 8.66% 0.0075
6 Adani Enterprise Ltd. 5.97% 0.0036
Knowledge Infrastructure 7 System (P) Ltd 3.27% 0.0011
Mittal Processor (P) 8 Ltd. 1.97% 0.0004
9 Shree ement td. 1.86% 0.0003
34 GMR Energy Trading 10 Ltd. 1.84% 0.0003
Instinct Infra & 11 Power Ltd. 1.07% 0.0001
National Energy Trading & Services 12 Ltd. 0.96% 0.0001
RPG Power Trading 13 Company Ltd. 0.89% 0.0001
Jaiprakash 14 Associates Ltd. 0.75% 0.0001
Manikaran Power 15 Ltd. 0.58% 0
Arunachal Pradesh Power Corporative 16 Ltd. 0.33% 0
Indrajit Power 17 Technology (P) Ltd. 0.32% 0 Pune Power Development Pvt 18 Ltd. 0.29% 0
Customized Energy Solution India Pvt 19 Ltd. 0.08% 0
Essar Electric Power Development Corp. 20 Ltd. 0.04% 0
35 TOTAL 100.00%
Figure 10:PERCENTAGE SHARE OF ELECTRICITY TRANSACTED BY TRADING LICENSEES IN 2012-13
Level of competition among the trading licensees (HHI based on volume of tradeundertaken by the licensees) is shown in Figure-10 for the period 2004-05 to 2011- 12. Number of inter-state trading licensees, who were undertaking trading bilaterally or through power exchanges, increased from 4 in 2004-05 to 17 in 2011-12. It can be observed from the figure that there is an inverse relationship between number of trading licensees and the HHI.
The concentration of market power declined from high concentration (HHI of 0.5512) in 2004-05 to moderate concentration (HHI of 0.1732) in 2011-12. The competition among the trading licensees resulted in increase in volume and decrease in prices in the short- term bilateral market (Table-5).
3.2.2 Price of Short-term Transactions of Electricity
The monthly trends in price of short-term transactions of electricity are shown in Table-11 and Figure-10 & 11. The price analysis is mainly based on the average price of UI and the weighted average price of other short-term transactions of electricity. The price of bilateral trader transactions represents the price of electricity transacted through
36 trading licensees. The trends in price of electricity transacted through trading licensees (bilateral trader transactions) were studied separately for total transactions as well as for the transactions undertaken Round the Clock (RTC), during Peak, and during Off-peak periods
Price of electricity transacted through Traders: Weighted average sale price has been computed for the electricity transacted through traders and it was Rs4.335/kWh. Weighted average sale price was also computed for the transactions during Round the Clock (RTC), Peak, and Off-Peak periods separately, and the sale prices were Rs4.305/kWh, Rs5.12/kWh and Rs4.655/kWh respectively. Minimum and Maximum sale prices were Rs2.44/kWh and Rs7.07/kWh respectively.
Price of electricity transacted Through Power Exchanges:Minimum, Maximum and Weighted Average Prices have been computed for the electricity transacted through IEX and PXIL separately. The Minimum, Maximum and Weighted Average prices were Rs0.35/kWh, Rs17.00/kWh and Rs3.67/kWh respectively in IEXand Rs1.31/kWh, Rs7.50/kWh and Rs3.47/kWh respectively in PXIL.
The price of electricity transacted through IEX and PXIL in the term-ahead market was Rs3.67/kWh and Rs3.47/kWh respectively.
Price of electricity transacted Through UI:All-India UI price has beencomputed for NEW Grid and SR Grid separately. The average UI price was Rs2.873/kWh in the NEW Grid and Rs4.16/kWh in the SR Grid. Minimum and Maximum UI prices were Rs0.00/kWh and Rs8.21/kWh respectively in the New Grid, and Rs0.00/kWh and Rs10.80/kWhrespectively in the SR Grid.
37 The prices of electricity transacted through trading licensees, power exchanges and UI and their comparison is shown in Table-11, Figure-10 & 11.
Figure 11:Comparison of price of bilateral, Power Exchange and UI Transactions in 2012-13
Table 11:Price of Short-term Transactions of Electricity (Rs/kWh), 2012-13
Power Bilateral through Traders Exchange UI NEW SR Period RTC Peak Offpeak Total IEX PXIL Grid Grid APRIL'12 4.35 5.78 4.95 4.4 3.19 4.71 2.81 5.16 MAY'12 4.26 6.13 4.79 4.3 3.6 3.89 4.26 4.92 JUN'12 4.11 4.91 4.17 4.11 4.11 4.1 5.55 5.29 JULY'12 4.02 5.81 4.69 4.03 4.51 4.54 6.13 5.09 AUG'12 4.22 4.89 4.3 4.22 3.89 3.53 2.16 4.12 SEP'12 4.37 5.69 4.26 4.37 2.98 2.34 1.45 3.69 OCT'12 4.43 5.73 4.85 4.41 4.03 3.76 2.29 3.91 NOV'12 4.39 4.35 4.58 4.43 3.62 2.89 1.87 3.3 DEC'12 4.25 4.77 4.67 4.39 3.9 3.08 2.33 3.33 JAN'13 4.38 4.34 5.09 4.42 3.65 3.66 2.31 2.94 FEB'13 4.42 4.48 4.89 4.46 2.9 2.42 1.53 3.83 MAR'13 4.46 4.49 4.63 4.48 3.68 2.76 1.79 4.33
It can be observed from the above figure that the price of electricity transactedthrough trading licensees was relatively low when compared with the price of electricity transacted through power exchanges and UI during the period April to July in 2012,
38 which gradually increased from month of August to March’13 and was constantly on the higher side as compared to UI and Power Exchange. The price of UI transactions were constantly increasing and was relatively higher as compared to Power Exchange and trading licensees until the month of July’12 after which there was a sharp step fall in UI prices and remained lower than Power Exchanges and Trading licensees. The price of electricity transacted through Power Exchange generally remained between the prices of UI transactions and Trading licensees, though there were many up and downs in the price of electricity transacted through Power Exchange throughout the year.
The trends in price of electricity transacted by trading licensees during RTC, Peak and Off-peak periods are shown in Figure-11. It can be observed from the figure that the price of electricity during peak period is high in all the months when compared with the price during RTC and off peak periods until month of Oct’12 after which it decreased and was approximately equal to RTC and off peak period throughout the year.
Figure 12:Price of Electricity Transacted through Traders during
39 3.3 Effect of Congestion on Volume of Electricity Transacted through Power Exchanges The volume of electricity transacted/sold through power exchange is sometimes constrained due to transmission congestion. The details of congestion in both power exchanges are shown in Table. During 2012-13, in IEX, the unconstrained cleared volume and the actual volume transacted were 26.14 billion KWh and 22.34 billion kWh respectively. This indicates that the actual transacted volume could have been 17% higher if there was no congestion in the system. During the same year, in PXIL, the unconstrained cleared volume and the actual volume transacted were 1.5 billion kWh and 0.678 billion kWh respectively. This indicates that the actual transacted volume could have been about 125% higher, if there was no congestion in the system. Congestion, consequent market splitting, and the resultant difference in market prices in different regions give rise to congestion charges. The congestion charges are being deposited in the Power System Development Fund, which was created pursuant to CEREC (Power System Development Fund) Regulations, 2010. Congestion in Power exchanges, besides affecting the volume, also resulted in formation of the fund.
Table 12:Price of Electricity Transacted through Traders during Details of Congestion APRIL MAY JUNE IEX PXIL IEX PXIL IEX PXIL Unconstrained Cleared Volume 1586.9 182.9 1445.2 1609.6 A (MUs) 6 5 1 124.29 9 124.14 Actual Cleared Volume and hence 1283.8 1388.3 1535.3 B scheduled (MUs) 6 53.32 9 89.69 4 94.03
40 Volume of electricity that could not be cleared and hence not scheduled because of 129.6 C congestion (MUs) (A-B) 303.1 3 56.82 34.6 74.35 30.11 Volume of electricity that could not be cleared as % to D Actual Cleared Volume 24% 243% 4.09% 38.58% 4.84% 32.02% Percentage of the time congestion occurred during the month (Number of hours congestion occurred/Total 100.00 E number of hours in the month) 100% 100% 99.97% % 76.67% 80.42%
Table-12:DETAILS OF CONGESTION IN POWER EXCHANGES, 2012-13 Details of Congestion JULY AUGUST SEPTEMBER
IEX PXIL IEX PXIL IEX PXIL Unconstrained Cleared Volume 1596.2 2001.3 2217.5 A (MUs) 8 79.29 4 87.33 8 84.31 Actual Cleared Volume and hence 1519.3 1821.0 1878.6 B scheduled (MUs) 2 52.93 2 39.93 9 30.92 Volume of electricity that could not be cleared and hence not scheduled because of C congestion (MUs) (A-B) 76.96 26.36 180.32 47.4 338.89 53.4 Volume of electricity that could not be cleared as % to 49.80 118.72 D Actual Cleared Volume 5.07% % 9.90% % 18.04% 172.71%
41 Table-12:DETAILS OF CONGESTION IN POWER EXCHANGES, 2012-13 Details of Congestion OCTOBER NOVEMEBER DECEMBER
IEX PXIL IEX PXIL IEX PXIL Unconstrained Cleared Volume 2452.0 2479.5 2633.3 A (MUs) 7 53.19 4 149.17 6 185 Actual Cleared Volume and hence 2119.0 2242.5 B scheduled (MUs) 2277.6 23.32 1 67.12 1 72.1 Volume of electricity that could not be cleared and hence not scheduled because of C congestion (MUs) (A-B) 174.47 29.87 360.53 82.05 390.85 112.9 Volume of electricity that could not be cleared as % to 128.08 122.25 D Actual Cleared Volume 7.66% % 17.01% % 17.43% 156.59%
Table-12:DETAILS OF CONGESTION IN POWER EXCHANGES, 2012-13 Details of Congestion JANUARY FEB MARCH
IEX PXIL IEX PXIL IEX PXIL Unconstrained Cleared Volume 2587.0 3020.3 A (MUs) 1 144.3 2513.75 147.5 9 167.64 Actual Cleared Volume and hence 2259.6 B scheduled (MUs) 2045.4 53.18 1975.42 36.97 5 64.7 Volume of electricity that could not be cleared and hence not scheduled because of C congestion (MUs) (A-B) 541.61 91.12 538.33 110.53 760.74 102.94 Volume of electricity that could not be cleared as % to 63.14 D Actual Cleared Volume 20.94% % 21.42% 74.93% 25.19% 61.41%
42 Table-12:DETAILS OF CONGESTION IN POWER EXCHANGE,2012-13
Details of Congestion AVERAGE
IEX PXIL
A Unconstrained Cleared Volume (MUs) 26143.18 1529.11
B Actual Cleared Volume and hence scheduled (MUs) 22346.21 678.21
Volume of electricity that could not be cleared and hence C not scheduled because of congestion (MUs) (A-B) 3796.97 850.9
Volume of electricity that could not be cleared as % to D Actual Cleared Volume 17% 125%
Figure 13:Details of congestion in Power Exchange 3.3.1Congestion management: Transmission congestion occurs when there is insufficient transmission capacity to simultaneously accommodate all requests for transmission service within a region. Where there is no congestion, there shall be no restriction of access to the interconnection and no specific procedure for access to transmission service.
43 Congestion can have a temporary or structural cause. Temporary bottlenecks occur relatively rarely and may be the result of outages for maintenance work, technical faults or particular market conditions. Structural bottlenecks are a result of the level of expansion of the grid and the localisation of generation and consumption within the grid. Structural bottlenecks tend to occur over longer periods of time or at regular intervals. It is often difficult to distinguish between the two types of congestion. It is, however, important to determine whether one is faced with temporary or structural congestion as to the best method of dealing with.
3.3.2PRINCIPLES OF CONGESTION MANAGEMENT: In principle, congestion can only be relieved physicallyby reducing generation or increasing consumption on the surplus side of the bottleneck and,conversely, by increasing generation or reducing consumption on the shortfall side. Dependingon which time phase one is in, different methods can be used for managing congestion. Thesemethods should be based on the following principles: 1. Economic efficiency and promotion of competition, 2. Maximizing of the amount of capacity available and the use made of it,
3. Transparency to network users on a non‐discriminatory basis,
4. Efficient System Operation
3.3.3CONGESTION MANAGEMENT METHODS: Congestion is relatively prevalent on interconnectionsbecause they were not built to facilitate the current large electricity flows between countries.
44 Originally, their main purpose was to allow exchanges between regions for the purpose of system stability. There are a variety of arrangements for congestion trade in use worldwide:
Non Market based methods • Access limitation • Priority List • Pro rata rationing • Counter trading and redispatching
Access Limitation: This congestion management tool which rations access totransmission capacity applies to DC interconnections with ownership that differs fromlinked networks. A few users may retain benefits from inter regional trade.
Priority List: Market players receive capacity in priority order until the ATC is fullyallocated. The priority criteria could be the chronological order and historic use ofcapacity
The method favors incumbents and long‐term trade because such contracts always have
priority over recent ones. Consequently, it leaves little opportunity for the short‐term
45 market. Allocation of a deliberately chosen fraction of the ATC for short‐term contracts can be an Improvement.
Pro rata rationing: This mechanism allocates capacity in proportion to requests if
theyexceed the announced ATC. The method is non‐discriminatory, transparent and easy toimplement compared to other mechanisms. However, it may very likely induceunwanted behavior such as gaming. Market players anticipating congestion
mayoverestimate their capacity needs and purchase accordingly. Anti‐gaming measures suchas the obligation to use the designated capacity appear to be a necessity if the method isto be of any use.
Counter Trading and re-dispatching: In this method the TSO plays most important rolein managing the congestion. This results in a planned electricity flow across thecongested line that exceeds its capacity. They need to enter the market to buy generationon one side and cancel generation on the other side.
Market based methods
46 • Explicit Auction • Implicit Auction
Explicit Auctioning: In an explicit auction, the TSO determines ex ante the ATC subjectto security analysis accepts bids from potential buyers and allocates the capacity to themarket players that most value it. There is a distinction between the trading oftransmission capacity and energy because they are traded separately. Each market playerbids for the ATC it wants to reserve. The bids are sorted, with the highest bids first, untilthe ATC is completely utilized.
The most common designs of explicit auctions are: 1. Uniform clearing price design, where all market players allocated transmission
capacity pays the clearing price or, alternatively, the pay‐as‐bid price design where all players allocated capacity pay the price they have bid. 2. Different products with varying frequency (year, month or day). 3. Often a joint coordinated mechanism between the PX involved.
Implicit Auctioning: The implicit auction considers energy bids in each organized market area.Based on submitted bids, demand and supply in market areas are matched. Arbitrageopportunities arise because of area price differences. As long as there is sufficient transmissioncapacity, demand and supply are matched and prices equalize (to the system price). However,when congestion occurs, the area prices differ and markets split. Each area has its own price:areas downstream of a congested interconnection will have a higher area price, while areasupstream will have a lower area price. In the process, energy and transmission capacity aretraded simultaneously. Interested parties bid across a
47 congested interconnect or into a powerpool. The market operator adds a surcharge to each bid that uses the interconnection. As a result,some of these bids are priced out of the market. The market operator sets the level of thissurcharge precisely so that just as many bids from across the interconnection are accepted as itscapacity allows.
1. Market Couplingwhere different power exchanges operate in each market area and a (shared) coupling system manages the capacity between them; and
2. Market Splitting, where a single power exchange operates across the connected
3.4 FREQUENCY PROFILE
There were great deviation from frequency in last FY 2011-12, maximum number of times the frequency remained below 49Hz and also above 50Hz due to this variation in frequency the grid was greatly disturbed and was one of the cause for the Grid Failure faced by most of the part of India for consecutive 2 days.
For further improvement of the grid Ministry Of Power has further narrowed the frequency band width i.e between 49.95Hz to 50.05Hz and also increased the UI rates looking towards this there was improvement in frequency profile in FY2012-13 as shown in (Table-13)
48 Table 13:Frequency profile in india in 2012-13
FRQUENCY PROFILE %Time MONTH <49.5 49.5-50.2 >50.2 April'12 2.38% 93.68% 3.94% May'12 10.82% 87.82% 1.36%
June'12 19.95% 78.66% 1.39% July'12 24.38% 73.59% 2.03% Aug'12 1.57% 89.72% 8.71% Sept'12 3.22% 84.09% 12.69% Oct'12 3.33% 90.39% 6.28% Nov'12 1.79% 85.83% 12.38% Dec'12 4.39 84.1 11.51 Jan'13 4.63 80.95 14.42 Feb'13 1.31 78.76 19.93 March'13 1.03 87.43 11.54
Figure 14:Frequency profile in India in 2012-13
As we can see from the graph for most of the time the frequency remained between 49.5 and 50.2, which remained fluctuating between 73% to 95% of time, hence this was a good sign for the stability of the grid.
49 Initially in the starting of the year the frequency profile below 49.5 Hz gradually kept on increasing and increased from 0% to 25% till month of July after which it gradually decreased and remained low throughout the year.
The frequency profile above 50.2Hz was very less percentage of time. Hence looking forward to frequency profile throughout the year it can be concluded that for maximum number of times the frequency was between the prescribed limit hence this was a healthy sign of stability of the grid.
CHAPTER-4
INITIATIVES TAKEN TOWARDS FURTHER IMPROVEMENT OF GRID
4.1 DEVIATION SETTELMENT MECHANISM
4.1.1. Objective The objective of these regulations is to maintain grid security and grid discipline as envisaged under the Grid Code through the commercial mechanism of Deviation Settlement by controlling the users of the grid in scheduling, dispatch, drawal and injection of electricity.
50 4.1.2. Scope These regulations shall be applicable to – (i) The generating stations and the beneficiaries, and (ii) Sellers and buyers involved in the transaction facilitated through short-term open access or medium-term open access or long-term access in inter-State transmission of electricity.
4.1.3. Charges for the Deviations: (1) The charges for the Deviations for all the time-blocks shall be payable for over drawal by the buyer or the beneficiary and under-injection by the generating station or the seller and receivable for under-drawal by the buyer or the beneficiary and over-injection by the generating station or the seller and shall be worked out on the average frequency of a time-block at the rates specified below as per the methodology specified in clause (2) Of this regulation: Average Frequency of the time block(Hz) Charges for Deviation Table 14:Charges for Deviation
Average Frequency of the Charges for time block(Hz) Deviation Belo Not w Below Paise/KWh 50.05 0 50.05 50.04 35.60 50.04 50.03 71.20 50.03 50.02 106.80 50.02 50.01 142.40 50.01 50.00 178.00 50.00 49.99 333.40 49.99 49.98 488.80
(Each 0.01 Hz step is equivalent to 35.60Paise/kWh in the 50.05-50.00 Hz frequency range, 155.40Paise/kWh in the below 50 Hz to 49.95 Hz frequency range) Provided that
51 the charges for the Deviation for the generating stations using coal or lignite or gas supplied under Administered Price Mechanism (APM) as fuel, when actual generation is higher or lower than the scheduled generation, shall not exceed the Cap Rate of 333.40Paise/kWh as per the methodology specified in clause (3) of this regulation:
Provided that the charges for the Deviation for the under drawls by the buyer and the over-injection by the seller shall not exceed the Cap Rate of 333.40Paise/kWh as per the methodology specified in clause (3) of this regulation: Provided also that the charges for the Deviation for the under drawls by the buyer or the beneficiaries in a time block in excess of 12% of the schedule or 150 MW whichever is less and in excess of 3% of the schedule over the day, shall be zero.
Provided also that the charges for the Deviation for the over-injection by the seller in a time block in excess of 12% of the schedule or 150 MW whichever is less and in excess of 3% of the schedule over a day shall be zero except in case of injection of infirm power which shall be governed by the clause (6) of this Regulation.
Provided also that the Charges for the Deviation for the under injection by the generating station “below 50.0 Hz” shall be the energy charge of the previous month if energy charge is higher than the charges for the Deviation corresponding to the grid frequency of the time block. In case of gas based generating stations the energy charge shall be considered for this purpose starting from the highest to lower for the respective fuels corresponding to the capacity scheduled on each fuel.
Note: Each generating station shall furnish the energy charges for the previous month to the respective Regional Power Committee (RPC) each month.
52 (2) The Charge for Deviation shall be determined in accordance with the following methodology: (a) The Charge for Deviation shall be zero at grid frequency of 50.05 Hz and above. (b) The Charge for Deviation corresponding to grid frequency interval of ‘below 50.01 Hz and not below 50.0 Hz’ shall be based on the median value of the average energy charge of coal/lignite based generating stations for any six months period preferably from July to December of previous year or from Jan to June for the year or any other six month period if deemed necessary and suitably adjusted upward to decide on the Deviation price vector. (c) The Deviation Price Vector shall accordingly, be in steps for a frequency interval of 0.01 Hz between 50.05 Hz and ‘below 50.01 Hz and not below 50.0 Hz’. (d) The Deviation Price Vector shall accordingly, be in steps for a frequency interval of 0.01 Hz between grid frequency interval of ‘below 50.01 Hz and not below 50.0 Hz’ and ‘below 49.95 Hz. (e) The Charge for Deviation at grid frequency "below 49.95 Hz" shall be based on the highest of the average energy charges of generating stations for any six months period preferably from July to December of previous year or from Jan to June for the year or any other six month period if deemed necessary and suitably adjusted upward to decide on the Deviation price vector.
(3) The Cap rate for the charges for the Deviation for the generating stations using coal or lignite or gas supplied under Administered Price Mechanism (APM) as the fuel shall be 7 the value close to the energy charges on imported coal on Deviation Price vector.
(4) The Cap rate for the charges for the Deviation for the under drawls by the buyer and the over-injection by the seller shall be the value close to the energy charges on imported coal on Deviation Price vector.
53 (5) The Charges for Deviation may be reviewed from time to time by the Commission and shall be re-notified accordingly.
(6) The infirm power injected into the grid by a generating unit of a generating station during the testing, prior to COD of the unit shall be paid at Charges for Deviation for infirm power injected into the grid, consequent to testing, for a period not exceeding 6 months or the extended time allowed by the Commission in the Central Electricity Regulatory Commission (Grant of Connectivity, Long-term Access and Medium-term Open Access and related matters) Regulations, 2009, as amended from time to time, subject to ceiling of Cap rates corresponding to the main fuel used for such generation as specified below:
Domestic coal/ Lignite/Hydro `1.78 / kWh sent out APM gas as fuel `2.82/ kWh sent out Imported Coal/RLNG `3.05 / kWh sent out Liquid Fuel `11.104 / kWh sent out
(7) Charges for Deviation of Inter-regional Exchange between the two asynchronously inter-connected Regions shall be computed by the respective Regional Power Committees, based on Charges for Deviation as per the frequency of the respective Region. The amount to be settled for the inter-regional exchanges shall be average of the Charges for Deviation computed for the two regions by way of such inter-change. 8
54 4.1.4. Declaration, scheduling and elimination of gaming (1) The provisions of the Grid Code and the Central Electricity Regulatory Commission (Open Access in inter-State Transmission) Regulations, 2008, as amended from time to time, shall be applicable for declaration of capacity, scheduling and elimination of gaming. (2) The generating station, as far as possible, shall generate electricity as per the day- ahead generation schedule finalized by the Regional Load Dispatch Centre in accordance with the Grid Code. Provided that the revision in generation schedule on the day of operation shall be permitted, in accordance with the procedure specified under the Grid Code and Central Electricity Regulatory Commission (Open Access in inter-State Transmission) Regulations, 2008, as the case may be. (3) The Commission, either suo motu or on a petition made by RLDC, or any affected party, may initiate proceedings against any generating company or seller on charges of gaming and if required, may order an inquiry in such manner as decided by the Commission. When the charge of gaming is established in the above inquiry, the Commission may, without prejudice to any other action under the Act or regulations there under, disallow any Charges for Deviation received by such generating company or the seller during the period of such gaming.”
4.1.5. Limits on Deviation volume and consequences of crossing limits
(1) The over-drawls / under drawls of electricity by any beneficiary or a buyer during a time block shall not exceed 12% of its scheduled drawal or 150 MW, whichever is lower, when frequency is ‘49.95’ Hz and above" and 3% on a daily aggregate basis for all the time blocks when the frequency is ‘‘49.95 Hz and above’.
55 Provided that any drawal of power by a generating station prior to COD of a unit for 9 the startup activities shall be exempted from the volume limit specified above.
Explanation: The limits specified in this clause shall apply to the sum total of over- drawal by all the intra-State entities in the State including the distribution companies and other intra-State buyers, and shall be applicable at the inter-State boundary of the respective State.
(2) The under-injection / over-injection of electricity by a generating station or a seller during a time-block shall not exceed 12% of the scheduled injection of such generating station or seller or 150 MW, whichever is lower, when frequency is ‘‘49.95 Hz and above’ and 3% on daily aggregate basis for all the time blocks when the frequency is ‘‘49.95 Hz and above’. Provided that any infirm injection of power by a generating station prior to COD of a unit during testing and commissioning activities shall be exempted from the volume limit specified above for a period not exceeding 6 months or the extended time allowed by the Commission in accordance with the Connectivity Regulations.
(3) In addition to Charges for Deviation as stipulated under Regulation 5 of these regulations, Additional Charge for Deviation shall be applicable for over-drawal/ under drawls as well as under-injection/ over-injection of electricity for each time block in excess of the volume limit specified in Clauses (1) and (2) of this regulation when grid frequency is ‘‘49.95 Hz and above” at the rates specified below in accordance with the methodology specified in clause 6 of this regulation: (i) For over drawls/under drawls of electricity by any beneficiary or a buyer in excess of 12% and up to 15% of the schedule or above 150 MW and up to 200 MW in a time block or in excess of 3% and up to 4% of the schedule over a day: equivalent to 20% of the Charge for Deviation corresponding to grid frequency of "below 49.95 Hz".
56 (ii) For over drawls/under drawls of electricity by any beneficiary or a buyer in excess 10 of 15 % and up to 20% of the schedule or above 200 MW and up to 250 MW in a time block or in excess of 4% and up to 5% of the schedule over a day: equivalent to 40% of the Charge for Deviation corresponding to grid frequency of "below 49.95 Hz". (iii) For over drawls/under drawls of electricity by any beneficiary or a buyer in excess of 20 % of the schedule or above 250 MW in a time block or in excess of 5% of the schedule over a day: equivalent to 100% of the Charge for Deviation corresponding to grid frequency of "below 49.95 Hz". (iv) For under injection/ over-injection in excess of 12% and up to 15% of the schedule or above 150 MW and up to 200 MW in a time block or in excess of 3% and up to 4% of the schedule over a day: equivalent to 20% of the Charge for Deviation corresponding to grid frequency of "below 49.95 Hz". (v) For under injection/over-injection in excess of 15 % and up to 20% of the schedule or above 200 MW and up to 250 MW in a time block or in excess of 4% and up to 5% of the schedule over a day: equivalent to 40% of the Charge for Deviation corresponding to grid frequency of "below 49.95 Hz". (vi)For under injection/over-injection in excess of 20 % of the schedule or above 250 MW in a time block or in excess of 5% of the schedule over a day: equivalent to 100% of the Charge for Deviation corresponding to grid frequency of "below 49.95 Hz". Provided further that Additional Charge for Deviation for under-injection/ over-injection of electricity, during the time-block in excess of the volume limit specified in (1) and (2) of this regulation when grid frequency is ‘‘49.95 Hz and above’, by the generating stations using coal or lignite or gas supplied under Administered Price Mechanism (APM) as the fuel shall be at the rates specified below in accordance with the methodology specified in clause 8 of this regulation: (i) For under injection in excess of 12% and up to 15% of the schedule or above 150 MW and up to 200 MW in a time block or in excess of 3% and up to 4% of the schedule over a day: equivalent to 20% of the Cap Rate for Deviations of Rs 333.40/kWh. 11 (ii) For under injection in excess of 15 % and up to 20% of the schedule or above 200
57 MW and up to 250 MW in a time block or in excess of 4% and up to 5% of the schedule over a day: equivalent to 40% of the Cap Rate for Deviations of Rs 333.40/kWh. (iii) For under injection in excess of 20 % of the schedule or above 250 MW in a time block or in excess of 5% of the schedule over a day: equivalent to 100% of the Cap Rate for Deviations of Rs 333.40/kWh. Provided that any drawal of power by a generating station prior to COD of a unit for the startup activities shall be exempted from the levy of additional Charges of Deviation. Provided also that any infirm injection of power by a generating station prior to COD of a unit during testing and commissioning activities shall be exempted from levy of additional charges for Deviation for a period not exceeding 6 months or the extended time as may be allowed by the Commission in accordance with the Connectivity Regulations.
(4) Methodologies for the computation of Charges for Deviation and Additional Charges for deviation for each regional entity for crossing the volume limits specified for the under drawal /over-injection and for overdrawal and under-injection in clause (3) of this regulation shall be as per Annexure-I and II respectively of these Regulations.
(5) In addition to Charges for Deviation as stipulated under Regulation 5 of these Regulations, Additional Charge for Deviation shall be applicable for over-drawal/ under drawls or under-injection/ over-injection of electricity for each time block when grid frequency is ‘‘below 49.95 Hz’ in accordance with the methodology specified in clause 7 of this regulation shall be equivalent to 100% of the Charge for Deviation of 1110.40Paise/kWh corresponding to the grid frequency of "below 49.95 Hz".
Provided further that Additional Charge for Deviation for under-injection of electricity, during the time-block when grid frequency is ‘‘below 49.95 Hz’, by the generating stations using coal or lignite or gas supplied under Administered Price Mechanism (APM) as the fuel in accordance with the methodology specified in clause 9 of 12 this
58 regulation shall be equivalent to 100% of the Cap Rate for Deviations of 333.40Paise/kWh.
Explanation: Additional Charges for Deviation shall not be applicable for net over drawls by a region as a whole from other regions. (6) The Additional Charge for Deviation for over-drawals / under-drawal and under- injection / over-injection of electricity for each time block when grid frequency is" 49.95 Hz and above" shall be as specified by the Commission as a percentage of the charges for the Deviation in grid frequency ‘below 49.95 Hz’ with due consideration to the behavior of the buyer and beneficiaries and sellers and the generating stations towards grid discipline:
Provided that the Commission may specify different rates for additional Charges for Deviation for over drawls/ under-drawal and under injections/ over-injection depending upon different % deviation from the schedule in excess of the volume limit specified in clause (1) and (2) of this Regulation.
(7) The additional Charge for Deviation for over-drawals and under-injection of electricity for each time block when grid frequency is “below 49.95 Hz” shall be as specified by the Commission as a percentage of the charges for the Deviation in grid frequency ‘below 49.95 Hz’ with due consideration to the behavior of the buyer and beneficiaries and sellers and the generating stations towards grid discipline: Provided that the Commission may specify different rates for additional Charges for Deviation for over drawls and under injections and for different ranges of frequencies ‘below 49.95 Hz’.
(8) The additional Charge for Deviation for under-injection of electricity during the time- block in excess of the volume limit specified in Clause (2) of this regulation when grid frequency is ‘49.95 Hz and above’, by the generating stations using coal or lignite or gas supplied under Administered Price Mechanism (APM) as the fuel shall be as specified by
59 13 the Commission as a percentage of the Cap Rate, with due consideration to the behavior of the generating stations towards grid discipline:
(9) The additional Charge for Deviation for under-injection of electricity during the time- block when grid frequency is ‘below 49.95 Hz’, by the generating stations using coal or lignite or gas supplied under Administered Price Mechanism (APM) as the fuel shall be as specified by the Commission as a percentage of the Cap Rate, with due consideration to the behavior of the generating stations towards grid discipline: Provided that the Commission may specify different rates for additional Charges for Deviation for under injections at different ranges of frequencies ‘below 49.95 Hz’.
(10) Payment of Charges for Deviation under Regulation 5 and the Additional Charges for Deviation under Clauses (3) and (4) of this regulation, shall be levied without prejudice to any action that may be considered appropriate by the Commission under Section 142 of the Act for contravention of the limits of over-drawal/ under drawal or under-generation/over-injection as specified in these regulations, for each time block.
(11) Each of the regional entity such as generating station, beneficiary, buyer or the seller shall have to make sign of their deviation from schedule changed, at least once, in every 6 time blocks. To illustrate, if a regional entity has positive deviation from schedule from 07.30hrs to 0.845hrs, then it must have negative deviation from schedule in the time block 08.45hrs to 09.00hrs.
(12) The charges for over-drawal/ under-injection and under-drawal/ over-injection of electricity shall be computed by the respective Regional Power Committee in accordance with the methodology used for preparation of ‘Regional Energy Accounts’.
(13) The Regional Load Despatch Centre shall prepare and publish on its website the records, on monthly basis, of the Deviation Accounts, specifying the quantum of over-
60 drawal/ under-generation and corresponding amount of charges for Deviation payable for each beneficiary or buyer and receivable for each generating station or seller 14 for all the time-blocks when grid frequency was "49.95 Hz and above" and "below 49.95" Hz separately.”
4.1.6. Compliance with instructions of Load Despatch Centre
Notwithstanding anything specified in these Regulations, the generating station, the seller, the beneficiary and the buyer shall strictly follow the instructions of the Regional Load Despatch Centre on generation and drawal in the interest of grid security and grid discipline.
4.1.7. Accounting of Charges for Deviation
(1) A statement of charges for Deviations including Additional Charges for Deviation levied under these regulations shall be prepared by the Secretariat of the respective Regional Power Committee on weekly basis based on the data provided by the concerned RLDC(s) and shall be issued to all constituents by Tuesday, for seven day period ending on the penultimate Sunday mid-night.
(2) All payments on account of Charges for Deviation including Additional Charges for Deviation levied under these regulations and interest, if any, received for late payment shall be credited to the funds called the “Regional Deviation Pool Account Fund”, which shall be maintained and operated by the concerned Regional Load Dispatch Centers in each region in accordance with provisions of these regulations.
61 Provided that the Commission may by order direct any other entity to operate and maintain the respective “Regional Deviation Pool Account Funds”:
Provided further that separate books of accounts shall be maintained for the principal component and interest component of Charges for Deviation and Additional Charges for Deviation by the Secretariat of the respective Regional Power Committee. 15
(3) All payments received in the “Regional Deviation Pool Account Fund” of each region shall be appropriated in the following sequence: (a) First towards any cost or expense or other charges incurred on recovery of Charges for deviation. (b) Next towards over dues or penal interest, if applicable. (c) Next towards normal interest. (d) Lastly, towards charges for deviation and additional charges for deviation.
Explanation: Any Additional Charge for Deviation collected from a regional entity shall be retained in the “Regional Deviation Pool Account Fund” of the concerned region where the regional entity is located.
4.1.8. Schedule of Payment of Charges for Deviation
(1) The payment of charges for Deviation shall have a high priority and the concerned constituent shall pay the indicated amounts within 10 (ten) days of the issue of statement of Charges for Deviation including Additional Charges for Deviation by the Secretariat of the respective Regional Power Committee into the “Regional Deviation Pool Account Fund” of the concerned region.
62 (2) If payments against the Charges for Deviation including Additional Charges for Deviation are delayed by more than two days, i.e., beyond twelve (12) days from the date of issue of the statement by the Secretariat of the respective Regional Power Committee, the defaulting constituent shall have to pay simple interest @ 0.04% for each day of delay.
(3) All payments to the entities entitled to receive any amount on account of charges for Deviation shall be made within 2 working days of receipt of the payments in the “Regional Deviation Pool Account Fund” of the concerned region. 16
Provided that in case of delay in the Payment of charges for Deviations into the respective Regional Deviation Pool Account Fund and interest there on if any, beyond 12 days from the date of issue of the Statement of charges for Deviations then the regional entities who have to receive payment for Deviation or interest thereon shall be paid from the balance available if any, in the Regional Deviation Pool Account Fund of the region. In case the balance available is not sufficient to meet the payment to the Regional Entities, then the payment from the Regional Deviation Pool Accounts Fund shall be made on pro rata basis from the balance available in the Fund. Provided further that the liability to pay interest for the delay in payments to the “ Regional Deviation Pool Account Fund” shall remain till interest is not paid; irrespective of the fact that constituents who have to receive payments have been paid from the “Regional Deviation Pool Account Fund” in part or full.
(4) All regional entities which had at any time during the previous financial year failed to make payment of Charges for Deviation including Additional Charges for Deviation within the time specified in these regulations shall be required to open a Letter of Credit (LC) equal to 110% of its average payable weekly liability for Deviations in the previous
63 financial year, in favour of the concerned RLDC within a fortnight from the date these Regulations come into force.
Provided that if any regional entity fails to make payment of Charges for Deviation including Additional Charges for Deviation by the time specified in these regulations during the current financial year, it shall be required to open a Letter of Credit equal to 110% of weekly outstanding liability in favour of respective Regional Load Despatch Centre within a fortnight from the due date of payment. Provided further that LC amount shall be increased to 110% of the payable weekly liability for Deviation in any week during the year, if it exceeds the previous LC amount by more than 50%.
Illustration: If the average payable weekly liability for Deviation of a regional entity during 17 2009-10 is Rs.20crore, the regional entity shall open LC for 22crore in 2010- 11. If the weekly payable liability during any week in 2010-11 is Rs35crore which is more than 50% of the previous financial year’s average payable weekly liability of Rs30Crore, the concerned regional entity shall increase the LC amount to Rs38.5Crore (1.1*Rs35.0) by adding Rs16.5Crore. (5) In case of failure to pay into the “Regional Deviation Pool Account Fund” within the specified time of 12 days from the date of issue of statement of charges for Deviations, the RLDC shall be entitled to encash the LC of the concerned constituent to the extent of the default and the concerned constituent shall recoup the LC amount within 3 days.
4.1.8. Application of fund collected through Deviations
The amount left in the Deviation Pool Account Fund after final settlement of claims of
64 Charges for Deviation of the generating stations and the beneficiaries shall be transferred to a separate fund as "Power Systems Development Fund" specified by the Commission and shall be utilized, for the purpose specified by the Commission.
4.1.9. Power to Relax. The Commission may by general or special order, for reasons to be recorded in writing, and after giving an opportunity of hearing to the parties likely to be affected by grant of relaxation, may relax any of the provisions of these regulations on its own motion or on an application made before it by an interested person.
4.1.10. Power to issue directions:- If any difficulty arises in giving effect to these regulations, the Commission may on its own motion or on an application filed by any affected party, issue such directions as may be considered necessary in furtherance of the objective and purpose of these
Table 15:OVER DRAWAL BY BENEFICIARY OR BUYER Additional Deviation Deviation In a Time Block Day Charges Total Deviation Charge Frequenc Charge Payable(+) y Payable(+) A B C D E F = D +E 49.95 upto 12% of schedule Normal SUM OF COLUMN D & 0 to AND or 150 MW whichever Deviation 0 E 3% ABOVE is low rate correspond >12% to >150MW >3% ing to 20% of charge 15% of to 200 to frequency for deviation schedul MW 4% corresponding to
65 below 49.95 = e 222.08
40% of charge >15% to >200MW >4% for deviation 20% of to 250 to corresponding to schedul MW 5% below 49.95 = e 444.16 100% of charge > 20% of for deviation schedul > 250MW > 5% corresponding to e below 49.95 = 1110.40 100% of charge for deviation <49.95 >0 >0 >0 1110 corresponding to # below 49.95 = 1110.40
Table 16:UNDER DRAWAL BY BENEFICIARY / OVER INJECTION BY APM GENERATING STATION/SELLER (EXCEPT INFIRM POWER) Additional Deviation Deviation In a Time Block Day Charges Total Deviation Charge Charge Recivable(-) Frequenc Payable(+) y A B C D E F = D + E
49.95 upto 12% of 0 to Normal 0 SUM OF COLUMN D & E AND schedule or 150 3% Deviation rate ABOVE MW whichever is corresponding low to frequency Ceiled to Rs
66 333.4
20% of >12% to charge for >150MW >3% 15% of deviation to 200 to 0 schedul corresponding MW 4% e to below 49.95 = 66.8 40% of charge for >15% to >200MW >4% deviation 20% of to 250 to 0 corresponding schedul MW 5% to below e 49.95 = 133.36 100% of charge for > 20% of > > deviation schedul 0 250MW 5% corresponding e to below 49.95 = 333.4 Normal upto 12% of Deviation rate schedule or 150 0 to corresponding 0 D + E MW whichever is 3% to frequency low Ceiled to Rs 333.4 <49.95 100% of charge for > 12% of schedule deviation or 150 MW >3% 0 # corresponding whichever is low to below 49.95 = 333.4
Table 17:UNDER INJECTION BY GENERATOR OR SELLER Additional Deviation Deviation In a Time Block Day Charges Total Deviation Charge Frequenc Charge Payable(+) y Payable(+) A B C D E F = D +E 49.95 upto 12% of 0 to Normal 0 SUM OF COLUMN D & E AND schedule or 150 3% Deviation rate ABOVE MW whichever is corresponding low to frequency Ceiled to Rs 333.4. The Deviation for
67 20% of charge for deviation corresponding to below 49.95 = 66.8 under- injection by a generating station “below 50.0 Hz” shall >12% to >150MW >3% be its energy 15% of to 200 to charge of the schedul MW 4% previous e month, if energy charge is higher than the charges for Deviation corresponding to the grid frequency of the time block. 40% of charge for >15% to >200MW >4% deviation 20% of to 250 to corresponding schedul MW 5% to below e 49.95 = 133.36 100% of charge for > 20% of > > deviation schedul 250MW 5% corresponding e to below 49.95 = 333.4 333.4 or its energy charge of the previous month, if 100% of energy charge for charge is 666.8 Or Greater if energy deviation <49.95 >0 >0 >0 higher than charge rate is higher than corresponding the charges 333.4 to below for Deviation 49.95 = 333.4 corresponding to the grid frequency of the time block.
68 Table 18:INFIRM POWER BY GENERATOR UNDER APM OR SELLER Deviation Additional Charges Deviation In a Time Block Day Payable(+) / Total Deviation Charge Frequenc Charge Recievable y Payable(+) (-) A B C D E F = D +E
Normal Deviation Charge subject to cap rate as below a) Domestic coal/ 49.95 Lignite/Hydro AND No deviation limit specified, `1.78 / kWh 0 ABOVE Allowed till 6 months or sent out SUM OF COLUMN D & E extended time allowed by b) APM gas CERC as fuel `2.82/ kWh sent out c) Imported Coal/RLNG `3.05 / kWh sent out d) Liquid Fuel `11.104 / kWh <49.95 sent out 0
IR Deviation Charge: Charges for Deviation of Inter-regional Exchange between the two asynchronously inter-connected Regions shall be computed by the respective Regional Power Committees, based on Charges for Deviation as per the frequency of the respective Region. The amount to be settled for the inter-regional exchanges shall be average of the Charges for Deviation computed for the two regions by way of such inter-change.
69 4.2 Ancillary Service
The grid disturbance episodes on 30 and 31 July, 2012 have drawn the attention of the policy makers to a very relevant issue of ensuring grid stability and reliability in the country. With the restructuring of the power sector, the responsibility of ensuring grid stability has been entrusted upon the system operators i.e. the Load Dispatch Centers at the state, regional and national levels.
For any power system to operate efficiently, two unique requirements which must be continuously and exactly satisfied in order to maintain overall system stability and reliability is to maintain a constant balance between generation and load and to adjust generation to manage power flows within the constraints of individual transmission facilities. Therefore, system operators need some resources to balance grid during contingencies at short notice. These resources are commonly known as ancillary services.
In cost-plus regulated regime, these resources can be built and operated under the instructions of system operators. However, in competitive, de-regulated regime, developing markets for such resources is a need.
A general classification of ancillary services is given below:
70 Presently, in the Indian context, it is envisioned that a Frequency Support Ancillary Service (FSAS) would help in improving the reliability of the operating system by harnessing the unutilized generation units with capabilities of ramping up in about 30 minutes. Currently, over 20,000 MW of bottled up generation is estimated to be present in the country and close to 1000 MW of capacity is left unutilized in the Day-Ahead Markets at exchanges. Such idle generationcapacity due to un-dispatched surpluses and the un-cleared bids in the day-ahead market at the two power exchanges operating in the country can be aggregated to create the Ancillary Market.
As such we need to create a market place to equip the system operator to aid in ensuring grid reliability by providing support services. The broad principles to govern the operations of such a market would entail:
1. Maintain grid frequency / voltage and other quality parameters within band as specified in Indian Electricity Grid Code (IEGC).
2. Encourage qualified resources to support system by participating in the market
71 3. Resource pricing should be market-based
The recent staff paper by Central Electricity Regulatory Commission (CERC) on April ’13 on Introduction of Ancillary Services in Indian Electricity Market’ touches upon the nuances and issues associated with the ancillary market design. Although the finer peculiarity of the operations ofsuch a market needs to be worked out, the overall market is perceived to operate through the exchanges approved by CERC. Once implemented, the ancillary services will serve as an ‘insurance’ product which would help in maintaining system reliability & security available directly to system operators at regional and national level.
4.2.1Frequency Support Ancillary Services (FSAS)
FSAS would be the service offered through bids by a generating station or any other authorized entity on behalf of the generating station to make itself available for despatch and get dispatched/ scheduled by the nodal agency to support the system frequency. Hence, the focus of introducing Frequency Support Ancillary Service (FSAS) would be to maintain the frequency within the band specified in the IEGC. FSAS, at present in the Indian context, aims to stabilize the grid frequency by maximizing unutilized generation and minimizing load shedding, under certain conditions, for ensuring grid safety and security. Gradually as this market grows and imbalances are better handled with improved system security and reliability, this market could phase out the UI Mechanism. It is however pertinent to mention that introduction of ancillary services may not automatically mean a good frequency profile.
72 Integration of renewable energy in the grid is one of the biggest thrust areas. The installed generation capacity of renewable generators is expected to grow manifold in the coming years. Considering the high variability and unpredictability of generation from renewable, the FSAS would serve to stabilize the frequency for increased integration of renewable sources into the grid. Frequency Support Ancillary Service (FSAS) can be used to complement the diurnal changes in renewable generation. FSAS can thus also be used as a mechanism to facilitate renewable integration by reducing the impact of their variation.
4.2.2 Voltage Control Ancillary Services (VCAS) & Black Start Ancillary Services (BSAS)
The Electricity Act 2003 entrusts the responsibility of transmission system planning on the CEA and the CTU. While the CEA forms perspective plans, the CTU fine tunes them over a shorter period in coordination with the CEA amongst others. While planning for the grid, the CEA and CTU, use system studies for ensuring a proper voltage profile at various points in the grid. However, the planning is done in anticipation of generators and loads coming up at various points in the grid. Due to variations between the anticipated and the actual for generation and load, the reactive power requirements change. The reactive power requirements also change as more and more elements get added to the grid. Since voltage is a local phenomenon and not a global phenomenon like frequency, the requirement of capacitor and/or reactor at a various nodes (sub-station or switchyard of generating station) may need to be changed. Therefore, we feel that the provision of reactive power, which may require a change in location, could be allowed under reactive power support ancillary services. There is already a commercial mechanism in the IEGC under Regulation 6.6 of the IEGC Regulations, w.r.t. voltage reference at the interchange point, which incentivizes maintaining a proper voltage profile at all interchange points between control areas in the grid. However, in case it is observed by the system operator
73 that there is a critically low voltage in the grid at one or more such interconnection points persisting during a season, the system operator may requisition voltage support ancillary services from any service provider, who may bid the same through the power exchange. Given that mobile substations, installed in trailers, which allow flexibility for quick installation to restore supply, are gaining popularity, we feel that mobile reactors or capacitors would be a big advantage and also result in reduction in cost, since they could easily be moved from one sub-station to another, as per requirement. But to start with, the mobile reactive compensation would be provided by the government owned transmission companies only.
CONCLUSION
From the above report it can be concluded that the grid as well as short-term market transactions were relatively more reliable as well as stable in FY 2012-13 as compared to FY 2011-12. The volume of short term electricity transacted through UI has been successfully been reduced from 2576.06MUs in April’12 to 1637.26 MUs in March’13. The volume of electricity transacted through short-term transactions in Power Exchange has gradually been in increasing mode and has increased from 1337.18MUs in April’12 to 2324.35MUs in March’13. The volume transacted through Bilateral Transactions were continuously on higher side and kept fluctuating within a prescribed limit.
The total short–term transaction of electricity which were 9% of total electricity generated in 2009-10, has gradually increased to 11% of total generation in 2012-13. The total percentage increase in volume transacted through Power Exchange from FY2011-12 to FY2012-13 was 49% which was only 0.13% from FY2010-11 to FY2011- 12 and the percentage increase in total revenue generated through Power Exchange was also 49% from FY2011-12 to FY2012-13, which was only 3.04% from FY2010-11 to FY2011-12.
74 At the end of the report brief discussion on the DEVIATION SETTLEMENT MECHANISM has been done, which is currently recommended by CEREC as a tool to replace UI mechanism of charging for the deviation in actual transactions from the scheduled one. Also the Ancillary Services has been discussed as a tool to further support the Grid.
BIBLIOGRAPHY
[1] Central Electricity Regulatory Commission (CERC)(2012). Monthly report on Short- Term Power Market April’12-March’13 [2] Central Electricity Authority. Report on Congestion Management. [3] Power Exchange India Limited (PXIL). Congestion Management Methods. [4] India Energy Exchange (IEX). Congestion Management Operations. [5] Power System Operation Corporation Limited (POSOCO). Monthly Report On Operational Performance [6] India Energy Exchange (IEX). Bulletin News and Information issue of June ‘13 [7] Integrated Council on Large Electric System (CIGRE). The challenge of ensuring adequate generation capacity in the competitive market. [8] Central Electricity Regulatory Commission (CERC). Introduction to Ancillary Services [9] shodhganga.inflibnet.ac.in/jspui/bitstream/10603/.../11_chapter%202.pdf.Report on power market operations.
75 ANNEXURE – 1
Volume of Short Term Transactions (in MUs) for 2012-13 (till Dec'12) Through UI with Through Power Regional Through Bilateral Exchange Grid Export (Unde Import Name of r (Over Total S.No the State Sale Purchase Net Sale Purchase Net Drawl) Drawl) Net Net 42.9 233 872. 1 Punjab 1031 5330 4299 6 2382 9 378 1251 9 7511 24.8 107 981. 2 Haryana 836 2251 1415 7 1100 5 679 1661 6 3472 242. 271 3 Rajasthan 1766 756.6 -1009 7 2954 2 444 1724 1279 2982 - 191 - - 4 Delhi 1585 2205 620.5 1981 63.78 7 1707 77 1630 2927 Uttar 69.8 135 5 Pradesh 477.2 1906 1429 8 1422 2 586 3523 2937 5719 Uttarakhan 48.7 160. 548. 6 d 223.4 725.5 502.1 8 208.9 1 123 671.6 4 1211 7 Himachal 1587 599.2 -988 1750 41.07 - 315 274.5 -40.7 - Pradesh 170 2738
76 9 72.5 - - 8 J&K 2070 1070 -1000 8 11.52 61.1 465 420.8 -44.2 1105 Chandigar 50.2 - 9 h 14.64 152.5 137.9 9 11.88 38.4 86.9 51.77 -35.1 64.3 - 10 MP 1627 1861 233.8 1131 335.2 -796 969 512.4 -457 1018 Maharasht 321. 886. 50.8 11 ra 796.8 4166 3369 9 1208 3 893 944.2 1 4306 150 - - 12 Gujarat 4199 1587 -2613 1708 3212 4 1811 449.6 1361 2470 Chattisgar 716. - 13 h 1277 458.2 -818.5 4 27.49 -689 439 437.5 -1.41 1509 Daman 14 and Diu 0 105.7 105.7 0 0 0 73.7 32.08 -41.7 64 Dadra & Nagar 15 Havelli 0 568.4 568.4 0 0 0 141 55.13 -86.3 482 Andhra 469. 575. 233. 16 Pradesh 128.5 3915 3786 8 1045 7 270 503.9 8 4596 - 180 - 17 Karnataka 1802 146.5 -1655 1842 35.07 7 357 251.2 -105 3568 110 18 Kerala 0 1031 1031 0.97 1105 4 8.59 786.6 778 2913 100 19 Tamilnadu 0 1421 1421 0.26 1008 8 429 424.7 -3.97 2425 Pondicherr 20 y 0 0 0 0 0 0 239 9.29 -230 -230 West 500. 21 Bengal 1591 2677 1087 6 252.1 -249 614 530.8 -83 755 172. - 245. 22 Orissa 938 456.4 -481.6 8 89.97 82.8 253 498.4 2 -319 23.3 - 23 Bihar 76.94 1816 1740 6 0 23.4 558 156.4 -402 1314 46.8 24 Jharkhand 80.24 837 756.7 0 46.82 2 497 98.37 -399 405 145. 25 Sikkim 217.1 131.5 -85.52 6 0 -146 65.6 41.65 -23.9 -255 98.3 - 26 DVC 1812 163.3 -1648 180 11.73 -168 339 437.2 2 1718 Arunachal 19.9 27 Pradesh 358.2 54.51 -303.7 7 23.39 3.42 186 237.9 52 -248
77 52.3 111. 35.9 28 Assam 0 426 426 4 163.6 3 296 331.5 5 573 36.8 29 Manipur 0 37.54 37.54 0.02 36.91 9 264 211.9 -52.2 22.2 32.6 - 30 Meghalaya 51.42 49.85 -1.57 4 22.03 10.6 197 196.8 0.03 -12.2 23.1 - 31 Mizoram 0 15.13 15.13 9 3.51 19.7 158 161.7 4.11 -0.44 18.9 32 Nagaland 28.77 0 -28.77 1.31 6.73 5.42 176 194.8 4 -4.41 - 33 Tripura 13.42 40.46 27.04 11.8 1.98 9.82 205 178.3 -26.3 -9.06 37.9 - 26.4 34 Goa 0.82 54.61 53.79 9 3.64 34.4 115 141.4 7 45.9
ANNEXURE – 2
78 FRE QU Delhi ENC Y Additio Freque Time Time ncy Deviat Deviat nal Block Code ion ion Deviati Total Schedu Actual le Charg Charg on Deviat 12% UI es es Charge ion Devia devia RAT Reciva Payabl Payabl Charg tion tion E ble(-) e(+) e(+) e - 117.2 1 00:00- 977.20 934.28 00:15 45 49.9 42.91 6 1110 333.4 0 0 -333.4 - 116.0 142. 2 00:15- 967.32 934.22 00:30 51 50 33.10 8 4 142.4 0 0 -142.4 - 115.1 3 00:30- 959.23 915.21 00:45 52 50 44.02 1 35.6 35.6 0 0 -35.6 - 114.1 4 00:45- 950.88 895.47 01:00 46 49.9 55.41 1 1110 333.4 0 0 -333.4 - 113.6 5 01:00- 947.34 878.45 01:15 53 50.1 68.88 8 0 0 0 0 0 - 112.1 6 01:15- 934.72 882.01 01:30 56 50.1 52.71 7 0 0 0 0 0 - 108.8 7 01:30- 906.83 875.75 01:45 59 50.2 31.08 2 0 0 0 0 0 - 8 01:45- 877.52 862.59 02:00 53 50.1 14.93 105.3 0 0 0 0 0 102.5 333. 9 02:00- 854.75 858.31 02:15 50 50 3.56 7 4 0 333.4 0 333.4 101.7 644. 10 02:15- 847.99 841.20 02:30 49 50 -6.79 6 2 333.4 0 0 -333.4 - 101.0 11 02:30- 842.35 822.49 02:45 46 49.9 19.86 8 1110 333.4 0 0 -333.4 92.53 644. 12 02:45- 771.10 821.20 03:00 49 50 50.10 2 2 0 644.2 0 644.2 89.68 142. 13 03:00- 747.38 813.47 03:15 51 50 66.09 6 4 0 142.4 0 142.4 88.80 14 03:15- 740.08 802.12 03:30 53 50.1 62.05 9 0 0 0 0 0 87.64 15 03:30- 730.34 796.32 03:45 56 50.1 65.98 1 0 0 0 0 0 86.76 16 03:45- 723.03 784.34 04:00 52 50 61.31 4 35.6 0 35.6 0 35.6 17 04:00- 50 50 705.72 775.01 69.29 84.68 333. 0 333.4 0 333.4
79 04:15 7 4 84.11 18 04:15- 700.95 770.82 04:30 54 50.1 69.87 4 0 0 0 0 0 82.39 333. 19 04:30- 686.59 758.49 04:45 50 50 71.90 1 4 0 333.4 0 333.4 82.39 20 04:45- 686.59 743.96 05:00 48 50 57.37 1 995 0 995 0 995 79.32 21 05:00- 661.03 730.47 05:15 46 49.9 69.44 4 1110 0 1110 1110 2220.8 79.54 333. 22 05:15- 662.91 721.98 05:30 50 50 59.08 9 4 0 333.4 0 333.4 79.54 23 05:30- 662.91 698.13 05:45 41 49.8 35.23 9 1110 0 1110 1110 2220.8 80.36 24 05:45- 669.67 681.74 06:00 46 49.9 12.07 1 1110 0 1110 1110 2220.8 79.94 25 06:00- 666.21 684.90 06:15 56 50.1 18.70 5 0 0 0 0 0 - 82.96 142. 26 06:15- 691.40 673.41 06:30 51 50 17.99 8 4 142.4 0 0 -142.4 - 87.14 333. 27 06:30- 726.20 669.50 06:45 50 50 56.69 3 4 333.4 0 0 -333.4 - 142. 28 06:45- 724.59 662.81 07:00 51 50 61.77 86.95 4 142 0 0 -142 - 87.27 644. 29 07:00- 727.27 662.61 07:15 49 50 64.66 2 2 333.4 0 0 -333.4 - 87.00 30 07:15- 725.06 657.95 07:30 45 49.9 67.10 7 1110 333.4 0 1110 777 - 86.04 31 07:30- 717.05 653.17 07:45 48 50 63.88 6 995 333.4 0 0 -333.4 - 84.02 32 07:45- 700.18 655.86 08:00 53 50.1 44.32 2 0 0 0 0 0 - 86.23 33 08:00- 718.66 649.15 08:15 48 50 69.51 9 995 333.4 0 0 -333.4 - 88.01 34 08:15- 733.48 636.90 08:30 39 49.8 96.57 7 1110 0 0 222.1 222.08 - 86.75 35 08:30- 722.96 635.42 08:45 34 49.7 87.54 5 1110 0 0 222.1 222.08 - 86.39 36 08:45- 719.92 651.92 09:00 44 49.9 68.00 1 1110 333.4 0 0 -333.4 - 85.27 37 09:00- 710.60 676.82 09:15 41 49.8 33.78 2 1110 333.4 0 0 -333.4 - 89.20 38 09:15- 743.36 709.76 09:30 40 49.8 33.60 3 1110 333.4 0 0 -333.4
80 - 90.21 39 09:30- 751.76 737.53 09:45 44 49.9 14.23 2 1110 333.4 0 0 -333.4 09:45- 40 747.92 766.27 10:00 54 50.1 18.35 89.75 0 0 0 0 0 - 95.00 41 10:00- 791.73 779.37 10:15 54 50.1 12.35 7 0 0 0 0 0 95.40 42 10:15- 795.06 791.92 10:30 52 50 -3.14 7 35.6 35.6 0 0 -35.6 95.19 43 10:30- 793.28 803.59 10:45 55 50.1 10.31 4 0 0 0 0 0 644. 44 10:45- 803.75 819.60 11:00 49 50 15.85 96.45 2 0 644.2 0 644.2 96.73 45 11:00- 806.15 830.53 11:15 48 50 24.38 8 995 0 995 0 995 98.09 46 11:15- 817.50 833.14 11:30 43 49.9 15.65 9 1110 0 1110 1110 2220.8 98.78 142. 47 11:30- 823.18 820.72 11:45 51 50 -2.46 2 4 142.4 0 0 -142.4 98.37 142. 48 11:45- 819.78 829.75 12:00 51 50 9.97 3 4 0 142.4 0 142.4 12:00- 49 848.35 839.11 12:15 48 50 -9.24 101.8 995 333.4 0 0 -333.4 - 103.5 333. 50 12:15- 862.84 849.88 12:30 50 50 12.96 4 4 333.4 0 0 -333.4 103.1 51 12:30- 859.65 872.15 12:45 44 49.9 12.50 6 1110 0 1110 1110 2220.8 103.1 142. 52 12:45- 859.91 870.65 13:00 51 50 10.74 9 4 0 142.4 0 142.4 101.0 53 13:00- 842.42 856.47 13:15 60 50.2 14.05 9 0 0 0 0 0 100.5 54 13:15- 837.78 847.11 13:30 47 49.9 9.33 3 1110 0 1110 1110 2220.8 13:30- 55 839.14 872.75 13:45 45 49.9 33.61 100.7 1110 0 1110 1110 2220.8 102.9 56 13:45- 858.13 903.34 14:00 52 50 45.22 8 35.6 0 35.6 0 35.6 111.1 57 14:00- 926.50 928.71 14:15 57 50.1 2.21 8 0 0 0 0 0 112.6 58 14:15- 938.95 959.33 14:30 46 49.9 20.38 7 1110 0 1110 1110 2220.8 113.8 333. 59 14:30- 948.93 969.72 14:45 50 50 20.79 7 4 0 333.4 0 333.4 114.3 142. 60 14:45- 952.96 996.20 15:00 51 50 43.24 5 4 0 142.4 0 142.4
81 1024.2 115.9 61 15:00- 966.20 15:15 54 50.1 5 58.05 4 0 0 0 0 0 1019.9 1028.5 122.3 62 15:15- 15:30 57 50.1 3 6 8.63 9 0 0 0 0 0 1021.5 1018.4 122.5 63 15:30- 15:45 55 50.1 5 9 -3.06 9 0 0 0 0 0 1022.0 1021.6 122.6 64 15:45- 16:00 60 50.2 0 8 -0.32 4 0 0 0 0 0 1010.5 115.4 65 16:00- 961.77 16:15 64 50.3 8 48.80 1 0 0 0 0 0 1016.4 114.1 142. 66 16:15- 951.45 16:30 51 50 1 64.96 7 4 0 142.4 0 142.4 16:30- 1020.3 67 945.84 16:45 52 50 6 74.52 113.5 35.6 0 35.6 0 35.6 1002.1 113.0 68 16:45- 942.44 17:00 54 50.1 8 59.74 9 0 0 0 0 0 109.8 69 17:00- 915.42 977.12 17:15 61 50.2 61.70 5 0 0 0 0 0 109.3 70 17:15- 911.23 940.41 17:30 54 50.1 29.18 5 0 0 0 0 0 107.3 71 17:30- 894.53 905.27 17:45 53 50.1 10.74 4 0 0 0 0 0 - 105.3 72 17:45- 877.63 863.76 18:00 53 50.1 13.87 2 0 0 0 0 0 - 102.8 73 18:00- 856.81 843.49 18:15 60 50.2 13.32 2 0 0 0 0 0 - 103.4 74 18:15- 862.12 823.53 18:30 56 50.1 38.59 5 0 0 0 0 0 - 102.9 75 18:30- 858.18 795.95 18:45 52 50 62.23 8 35.6 35.6 0 0 -35.6 - 102.8 76 18:45- 856.99 793.66 19:00 53 50.1 63.33 4 0 0 0 0 0 - 102.9 77 19:00- 857.93 775.34 19:15 55 50.1 82.58 5 0 0 0 0 0 - 102.6 78 19:15- 855.33 772.82 19:30 45 49.9 82.52 4 1110 0 1110 1110 2220.8 - 104.0 79 19:30- 867.30 778.93 19:45 48 50 88.37 8 995 0 995 0 995 - 106.3 644. 80 19:45- 886.17 795.00 20:00 49 50 91.16 4 2 333.4 0 0 -333.4 - 107.8 81 20:00- 898.96 810.30 20:15 48 50 88.66 7 995 333.4 0 0 -333.4 82 20:15- 50 50 913.78 810.90 - 109.6 333. 333.4 0 0 -333.4 20:30
82 102.8 7 5 4 - 107.0 83 20:30- 891.81 806.44 20:45 47 49.9 85.37 2 1110 0 1110 1110 2220.8 - 107.8 84 20:45- 898.48 805.29 21:00 53 50.1 93.19 2 0 0 0 0 0 - 108.8 85 21:00- 906.97 810.82 21:15 58 50.2 96.15 4 0 0 0 0 0 - 107.4 142. 86 21:15- 895.35 816.87 21:30 51 50 78.48 4 4 142.4 0 0 -142.4 - 108.2 644. 87 21:30- 901.81 832.44 21:45 49 50 69.37 2 2 333.4 0 0 -333.4 - 108.0 88 21:45- 900.55 855.62 22:00 55 50.1 44.93 7 0 0 0 0 0 - 89 22:00- 905.02 862.85 22:15 48 50 42.17 108.6 995 333.4 0 0 -333.4 - 110.8 90 22:15- 923.58 878.19 22:30 52 50 45.39 3 35.6 35.6 0 0 -35.6 - 114.8 91 22:30- 957.35 889.19 22:45 52 50 68.16 8 35.6 35.6 0 0 -35.6 - 115.5 92 22:45- 962.88 894.78 23:00 60 50.2 68.09 5 0 0 0 0 0 - 115.9 142. 93 23:00- 966.07 896.86 23:15 51 50 69.21 3 4 142.4 0 0 -142.4 - 114.4 94 23:15- 953.69 892.20 23:30 48 50 61.49 4 995 333.4 0 0 -333.4 - 114.4 95 23s:30- 953.96 887.88 23:45 53 50.1 66.08 8 0 0 0 0 0 - 114.1 96 23:45- 951.41 883.30 24:00 55 50.1 68.11 7 0 0 0 0 0 - 80879 79498 1381. 9705. 50 00 5 333.4 0 0 -333.4 234.25
83 Singrauli Devia Addition tion Devia al Time Frequen Charg tion Deviatio Time Schedul Block cy Code Actual e 12% es Charg n freq of UI Reciv es Charge Total uenc Devia sched RAT able(- Paya Payable( Deviatio y tion ule E ) ble(+) +) n Charge 00:00- 1 45 483.75 485.09 00:15 49.9 1.34 58.05 1110 333 0 0 -333.4 00:15- 2 51 483.75 486.29 00:30 50 2.54 58.05 142 142 0 0 -142.4 00:30- 3 52 483.75 483.78 00:45 50 0.03 58.05 35.6 35.6 0 0 -35.6 00:45- 4 46 483.75 485.53 01:00 49.9 1.78 58.05 1110 333 0 0 -333.4 01:00- 5 53 483.75 483.02 01:15 50.1 -0.73 58.05 0 0 132 0 132 01:15- 6 56 483.75 487.53 01:30 50.1 3.78 58.05 0 0 0 0 0 01:30- 7 59 483.75 482.58 01:45 50.2 -1.17 58.05 0 0 0 0 0 01:45- 8 53 483.75 481.02 02:00 50.1 -2.73 58.05 0 0 0 0 0 02:00- 9 50 483.75 486.18 02:15 50 2.43 58.05 333 333 0 0 -333.4 02:15- 10 49 483.75 485.64 02:30 50 1.89 58.05 644 333 0 0 -333.4 02:30- 11 46 483.75 484.11 02:45 49.9 0.36 58.05 1110 333 0 0 -333.4 02:45- 12 49 483.75 483.64 03:00 50 -0.11 58.05 644 0 333.4 0 333.4
84 03:00- 13 51 483.75 484.98 03:15 50 1.23 58.05 142 142 0 0 -142.4 03:15- 14 53 483.75 485.56 03:30 50.1 1.81 58.05 0 0 0 0 0 03:30- 15 56 483.75 486.36 03:45 50.1 2.61 58.05 0 0 0 0 0 03:45- 16 52 483.75 483.96 04:00 50 0.21 58.05 35.6 35.6 0 0 -35.6 04:00- 17 50 483.75 484.07 04:15 50 0.32 58.05 333 333 0 0 -333.4 04:15- 18 54 483.75 482.65 04:30 50.1 -1.10 58.05 0 0 0 0 0 04:30- 19 50 483.75 483.38 04:45 50 -0.37 58.05 333 0 333.4 0 333.4 04:45- 20 48 483.75 481.42 05:00 50 -2.33 58.05 995 0 333.4 0 333.4 05:00- 21 46 483.75 484.91 05:15 49.9 1.16 58.05 1110 333 0 0 -333.4 05:15- 22 50 483.75 484.29 05:30 50 0.54 58.05 333 333 0 0 -333.4 05:30- 23 41 483.75 485.71 05:45 49.8 1.96 58.05 1110 333 0 0 -333.4 05:45- 24 46 483.75 486.98 06:00 49.9 3.23 58.05 1110 333 0 0 -333.4 06:00- 25 56 483.75 486.84 06:15 50.1 3.09 58.05 0 0 0 0 0 06:15- 26 51 483.75 487.38 06:30 50 3.63 58.05 142 142 0 0 -142.4 06:30- 27 50 483.75 488.55 06:45 50 4.80 58.05 333 333 0 0 -333.4 06:45- 28 51 483.75 487.75 07:00 50 4.00 58.05 142 142 0 0 -142.4 07:00- 29 49 483.75 489.31 07:15 50 5.56 58.05 644 333 0 0 -333.4 07:15- 30 45 483.75 486.36 07:30 49.9 2.61 58.05 1110 333 0 0 -333.4 07:30- 31 48 483.75 484.11 07:45 50 0.36 58.05 995 333 0 0 -333.4 07:45- 32 53 483.75 485.24 08:00 50.1 1.49 58.05 0 0 0 0 0 08:00- 33 48 483.75 484.18 08:15 50 0.43 58.05 995 333 0 0 -333.4 08:15- 34 39 483.75 485.31 08:30 49.8 1.56 58.05 1110 333 0 0 -333.4 08:30- 35 34 483.75 484.44 08:45 49.7 0.69 58.05 1110 333 0 0 -333.4 08:45- 36 44 483.75 484.36 09:00 49.9 0.61 58.05 1110 333 0 0 -333.4 09:00- 37 41 483.75 486.11 09:15 49.8 2.36 58.05 1110 333 0 0 -333.4 09:15- 38 40 483.75 483.20 09:30 49.8 -0.55 58.05 1110 0 333.4 333 666.8 09:30- 39 44 483.75 482.47 09:45 49.9 -1.28 58.05 1110 0 333.4 333 666.8
85 09:45- 40 54 483.75 479.05 10:00 50.1 -4.70 58.05 0 0 0 0 0 10:00- 41 54 483.75 480.47 10:15 50.1 -3.28 58.05 0 0 0 0 0 10:15- 42 52 483.75 479.49 10:30 50 -4.26 58.05 35.6 0 35.6 0 35.6 10:30- 43 55 483.75 475.71 10:45 50.1 -8.04 58.05 0 0 0 0 0 10:45- 44 49 483.75 474.95 11:00 50 -8.80 58.05 644 0 333.4 0 333.4 - 45 11:00- 48 483.75 467.09 11:15 50 16.66 58.05 995 0 333.4 0 333.4 - 46 11:15- 43 483.75 351.82 131.9 11:30 49.9 3 58.05 1110 0 333.4 333 666.8 - 47 11:30- 51 483.75 352.98 130.7 11:45 50 7 58.05 142 0 142.4 142 284.8 11:45- 48 51 355.00 353.96 12:00 50 -1.04 42.6 142 0 142.4 0 142.4 12:00- 49 48 355.00 355.09 12:15 50 0.09 42.6 995 333 0 0 -333.4 12:15- 50 50 355.00 354.62 12:30 50 -0.38 42.6 333 0 333.4 0 333.4 12:30- 51 44 355.00 355.60 12:45 49.9 0.60 42.6 1110 333 0 0 -333.4 12:45- 52 51 355.00 354.55 13:00 50 -0.45 42.6 142 0 142.4 0 142.4 13:00- 53 60 355.00 353.20 13:15 50.2 -1.80 42.6 0 0 0 0 0 13:15- 54 47 355.00 353.64 13:30 49.9 -1.36 42.6 1110 0 333.4 0 333.4 13:30- 55 45 355.00 360.36 13:45 49.9 5.36 42.6 1110 333 0 0 -333.4 13:45- 56 52 367.50 381.35 14:00 50 13.85 44.1 35.6 35.6 0 0 -35.6 14:00- 57 57 380.00 380.51 14:15 50.1 0.51 45.6 0 0 0 0 0 14:15- 58 46 392.50 404.25 14:30 49.9 11.75 47.1 1110 333 0 0 -333.4 14:30- 59 50 392.50 417.45 14:45 50 24.95 47.1 333 333 0 0 -333.4 14:45- 60 51 405.00 427.78 15:00 50 22.78 48.6 142 142 0 0 -142.4 15:00- 61 54 415.00 431.20 15:15 50.1 16.20 49.8 0 0 0 0 0 15:15- 62 57 430.00 432.07 15:30 50.1 2.07 51.6 0 0 0 0 0 - 63 15:30- 55 442.50 350.65 15:45 50.1 91.85 53.1 0 0 0 333 333.4 64 15:45- 60 50.2 442.50 342.65 - 53.1 0 0 0 333 333.4 16:00
86 99.85 - 65 16:00- 64 455.00 348.44 106.5 16:15 50.3 6 54.6 0 0 0 333 333.4 16:15- 66 51 355.00 355.67 16:30 50 0.67 42.6 142 142 0 0 -142.4 16:30- 67 52 355.00 355.93 16:45 50 0.93 42.6 35.6 35.6 0 0 -35.6 16:45- 68 54 355.00 356.91 17:00 50.1 1.91 42.6 0 0 0 0 0 17:00- 69 61 355.00 357.24 17:15 50.2 2.24 42.6 0 0 0 0 0 17:15- 70 54 355.00 355.85 17:30 50.1 0.85 42.6 0 0 0 0 0 17:30- 71 53 355.00 356.55 17:45 50.1 1.55 42.6 0 0 0 0 0 17:45- 72 53 355.00 355.05 18:00 50.1 0.05 42.6 0 0 0 0 0 18:00- 73 60 355.00 354.80 18:15 50.2 -0.20 42.6 0 0 0 0 0 18:15- 74 56 355.00 354.44 18:30 50.1 -0.56 42.6 0 0 0 0 0 18:30- 75 52 355.00 354.04 18:45 50 -0.96 42.6 35.6 0 35.6 0 35.6 18:45- 76 53 355.00 352.33 19:00 50.1 -2.67 42.6 0 0 0 0 0 19:00- 77 55 355.00 352.04 19:15 50.1 -2.96 42.6 0 0 0 0 0 19:15- 78 45 355.00 355.24 19:30 49.9 0.24 42.6 1110 333 0 0 -333.4 19:30- 79 48 355.00 351.56 19:45 50 -3.44 42.6 995 0 333.4 0 333.4 19:45- 80 49 355.00 351.13 20:00 50 -3.87 42.6 644 0 333.4 0 333.4 20:00- 81 48 355.00 354.40 20:15 50 -0.60 42.6 995 0 333.4 0 333.4 20:15- 82 50 355.00 354.87 20:30 50 -0.13 42.6 333 0 333.4 0 333.4 20:30- 83 47 355.00 355.71 20:45 49.9 0.71 42.6 1110 333 0 0 -333.4 20:45- 84 53 355.00 355.20 21:00 50.1 0.20 42.6 0 0 0 0 0 21:00- 85 58 355.00 353.56 21:15 50.2 -1.44 42.6 0 0 0 0 0 21:15- 86 51 355.00 354.29 21:30 50 -0.71 42.6 142 0 142.4 0 142.4 21:30- 87 49 355.00 355.09 21:45 50 0.09 42.6 644 333 0 0 -333.4 21:45- 88 55 355.00 355.93 22:00 50.1 0.93 42.6 0 0 0 0 0 22:00- 89 48 355.00 358.15 22:15 50 3.15 42.6 995 333 0 0 -333.4 22:15- 90 52 367.50 378.73 22:30 50 11.23 44.1 35.6 35.6 0 0 -35.6
87 - 91 22:30- 52 380.00 367.89 22:45 50 12.11 45.6 35.6 0 35.6 0 35.6 - 92 22:45- 60 392.50 349.35 23:00 50.2 43.15 47.1 0 0 0 0 0 - 93 23:00- 51 405.00 353.42 23:15 50 51.58 48.6 142 0 142.4 142 284.8 23:15- 94 48 355.00 357.78 23:30 50 2.78 42.6 995 333 0 0 -333.4 23:30- 95 53 355.00 357.31 23:45 50.1 2.31 42.6 0 42.6 0 0 -42.6 23:45- 96 55 355.00 359.49 24:00 50.1 4.49 42.6 0 0 0 0 0
ANEXXURE-3
Herfindahl-Hirschman Index (HHI) Calculation Formula for computing the HHI is as under: N HHI = Σ si 2 i =1 where si is the market share of firm i in the market, and N is the number of firms. The Herfindahl-Hirschman Index (HHI) ranges from 1 / N to one, where N is the number of firms in the market. Equivalently, if percents are used as whole numbers, as in 75 instead of 0.75, the index can range up to 1002 or 10,000.
88 · A HHI index below 0.01 (or 100) indicates a highly competitive index. · A HHI index below 0.15 (or 1,500) indicates an unconcentrated index. · A HHI index between 0.15 to 0.25 (or 1,500 to 2,500) indicates moderate concentration. · A HHI index above 0.25 (above 2,500) indicates high concentration. There is also a normalised Herfindahl index. Whereas the Herfindahl index ranges from 1/N to one, the normalized Herfindahl index ranges from 0 to 1.
89