Selling Options Fr Restricted Capacity For A Power Plant- Evaluation And Options

GSEG - Selling Options for Restricted Capacity Evaluation and Analysis

Sparshy Saxena PGP 08

Acknowledgement Ab initio, I would like to express my sincere appreciation to the college authortites, including my project mentor, Dr. Subrat Sahu, for their esteemed and valuable support. I would like to extend my heartfelt gratitude to the staff of Gujarat State Electricity Generation and Evonik for providing me with a congenial working atmosphere and extending the support as required by me. I would personally like to thank Mr. Hemant Gajjar, Mr. Vinay Kumar, Mr. Sameer Joshi, Mr. Shailesh Shivadasan and Mr. Baiju for their enthusiastic support. I owe an intellectual debt to Mr. Yogesh Patel, my Project mentor, Mr. Baiju, Mr. Gautam Patel, for their valuable guidance, Mr. Shashwat Srivastav, Indian Energy Exchange; and a few acquaintances from Adani Power Limited for their expertise on power trading.

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Objective The objective of the report is to study the various options available to GSEG for the sale of the restricted capacity. The report studies the options in light of factors like available trading capacity, profit margin and the available customer base.

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Executive Summary Gujarat State Electricity Generation has a combined cycle power plant based at Hazira with a capacity of 156 MW with expansion underway for ~350 MW. With the power being costlier, the plant suffers losses due to load restriction during low demand period. Outside of its PPA with GEB, based on a hypothetical proposal, the varied options that are available with GSEG to trade the extra capacity are the Bilateral trade and Power exchange. Bilateral trade involves market research, price volatility as per bargaining capacity and a chance of the power not being sold due to it being costlier and unexpectedly varying. Out of the two power exchanges operational in India, the Indian Energy Exchange (IEX) has an upper hand as compared to the Power Exchange India Limited (PXIL) in various aspects like the wider customer base, competitive trading prices, superior technology and varied future trading contracts. Thus, trading on IEX seems to be a profitable option for GSEG based on calculations taking the average availability of power for a particular day. However, considering the practical aspects like which time of the day power is available for sale, whether the demand in the grid exists, nomination acceptability within a short span of time and not a day ahead, including the fact that GUVNL themselves would trade the power during high demand periods, it may be relatively difficult to sell the power. Nevertheless, exploring the option of power sale and actually trying it can throw up the actual possibilities & difficulties and the experience gained can be useful in future.

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Contents The Power industry ............................................................................................................................... 10 Introduction ....................................................................................................................................... 10 Demand Management ........................................................................................................................ 11 Power Contracts ................................................................................................................................ 13 Long term ...................................................................................................................................... 13 Short term...................................................................................................................................... 13 Grid Management .............................................................................................................................. 24 Pricing of Power ................................................................................................................................ 27 Long term contracts and Bilateral trading ....................................................................................... 27 Pricing on the exchange ................................................................................................................. 30 Gujarat State Electricity Generation ....................................................................................................... 34 Company Description ........................................................................................................................ 34 Combined Cycle Power plant at Hazira .............................................................................................. 34 Production Data ................................................................................................................................. 37 Amount of losses incurred ................................................................................................................. 38 Nature of losses ................................................................................................................................. 38 Options and Evaluation ......................................................................................................................... 41 Short term market .............................................................................................................................. 41 Bilateral market – Power exchange : Relative Comparison ................................................................. 41 Power Exchange ................................................................................................................................ 42 Indian Energy Exchange ................................................................................................................ 42 Power Exchange India Limited ...................................................................................................... 42 Relative comparison between the exchanges ...................................................................................... 43 Market Share ..................................................................................................................................... 43 Membership Options ......................................................................................................................... 46 Contracts Offered .............................................................................................................................. 50 Technology Support .......................................................................................................................... 51 Costing Analysis ................................................................................................................................... 52 Comparative costs of other options .................................................................................................... 52 5|Selling Options for Restricted Capacity of GSEG

Effects on revenue ............................................................................................................................. 52 Monthly revenue................................................................................................................................ 54 Cost Benefit Analysis ........................................................................................................................ 56 Mix of selling options for GSEG........................................................................................................ 58 A Hypothetical Trading Proposal ................................................................................................... 58 Learnings and Conclusions .................................................................................................................... 61 Findings ............................................................................................................................................ 61 Recommendations ............................................................................................................................. 61 Action plan ........................................................................................................................................ 62 Contingencies .................................................................................................................................... 62 Exhibits ................................................................................................................................................. 63 Bibliography ......................................................................................................................................... 65

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TABLE 1 : MARKET TRADING VOLUMES OF THE LEADING EUROPEAN E XCHANGES ................................................... 17 TABLE 2 : FUEL COMPARISON ................................................................................................................................ 36 TABLE 3 : PRODUCTION AT FULL CAPACITY ............................................................................................................ 37 TABLE 4 : ACTUAL PRODUCTION DATA................................................................................................................... 37 TABLE 5 : FEE STRUCTURE FOR IEX ...................................................................................................................... 47 TABLE 6 : MEMBERSHIP OPTIONS FOR PXIL........................................................................................................... 48 TABLE 7 : MEMBERSHIP FEE FOR PXIL .................................................................................................................. 48 TABLE 8 : COMPARATIVE COSTS FOR POWER TRADE (IN RS./KWH) ......................................................................... 52 TABLE 9 : TRADING PRICES ON IEX (JUNE 2008-MAY 2009) ................................................................................... 53 TABLE 10 : LOAD RESTRICTION LOSS DATA ............................................................................................................ 53 TABLE 11 : MONTHLY PROFIT FOR THE PERIOD JUNE 2008 - MAY 2009 (@ RS. 2.9/KWH) ........................................ 54 TABLE 12 : MONTHLY PROFIT FOR THE PERIOD JUNE 2008 - MAY 2009 (@ RS. 5/KWH) ........................................... 55 TABLE 13: COST BENEFIT ANALYSIS FOR A FULL MEMBERSHIP OPTION .................................................................... 57 TABLE 14 : COST BENEFIT ANALYSIS FOR A LIGHT MEMBERSHIP OPTION .................................................................. 57 TABLE 15 : PRICES FOR THE UI INTERFACE FOR THE PERIOD OF AUGUST 2008 - MARCH 2009 .................................. 59 TABLE 16 : DAILY PROFIT FOR DECEMBER 11 (HYPOTHETICAL – EXCESS OF POWER) .............................................. 59 TABLE 17 : DAILY PROFIT FOR DECEMBER 11 (HYPOTHETICAL - DEFICIT OF POWER)................................................ 60

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FIGURE 1 : DIAGRAMMATIC REPRESENTATION OF THE DEMAND SETTLEMENT ......................................................... 12 FIGURE 2 : RELATIVE TRADING VOLUME ON NORD POOL ........................................................................................ 18 FIGURE 3 : GRID INFRASTRUCUTRE ........................................................................................................................ 25 FIGURE 4 : SELLING PRICE OF POWER ON THE E XCHANGE (JUNE 2008 – MAY 2009), IN RS./KWH............................. 31 FIGURE 5 : AVERAGE HOURLY MARKET CLEARING PRICE FOR APRIL 2009, TRADED ON IEX, IN RS./KWH ............... 31 FIGURE 6 : DETERMINATION OF EQUILIBRIUM PRICE .............................................................................................. 33 FIGURE 7 : TOTAL MONTHLY LOSS FOR THE PERIOD JUNE 2008 – MAY 2009, IN MWH ............................................. 38 FIGURE 8 :MONTHLY LOAD RESTRICTION LOSS DATA FOR THE PERIOD APRIL 2008 – MAY 2009, IN MWH ............... 39 FIGURE 9 : MONTHLY OPERATIONAL LOSSES FOR THE PERIOD APRIL 2008-MAY 2009, IN MWH .............................. 39 FIGURE 10 : RELATIVE MARKET SHARE OF THE TWO EXCHANGES ........................................................................... 44 FIGURE 11: MONTHLY SUMMARY OF ELECTRICITY TRADED ON EXCHANGES, IEX & PXIL ...................................... 44 FIGURE 12: DAILY AVERAGE TRADED HOURS (2008-2009) .................................................................................... 45 FIGURE 13 : MONTHLY AVERAGE TRADED HOURS (2008-2009) ............................................................................. 46 FIGURE 14 : IEX MEMBERSHIP .............................................................................................................................. 47 FIGURE 15 : MONTHLY PROFIT FOR THE PERIOD OF JUNE 2008- MAY 2009 @ RS. 2.9/UNIT ...................................... 55 FIGURE 16: MONTHLY PROFIT FOR THE PERIOD OF JUNE 2008- MAY 2009 @ RS. 5/UNIT .......................................... 56

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EXHIBIT 1 : AREA OF OPERATIONS OF THE LEADING EXCHANGES IN EUROPE ............................................................ 63 EXHIBIT 2 : DIAGRAMMATIC REPRESENTATION OF A COMBINED CYCLE POWER PLANT ............................................ 63 EXHIBIT 3 : RELATIVE COMPARISON OF FOUR FUEL ALTERNATIVES ......................................................................... 64 EXHIBIT 4 : HOURLY MCPS FOR THE MONTH OF DECEMBER, 2008 .......................................................................... 64

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The Power industry Introduction The power industry, on layman terms, is dissemination of electrical power, from the generators to the end consumers. The Indian power market is characterized by volatile relationship between the supply and demand of power as well as the virginity of the regulated environment. The electricity consumption by the end consumer is the guiding factor for evaluating the electricity demand for the future. At present, there is an approximate 8% energy shortage while peak power shortage is about 12%. GoI has plans to overcome the power shortage by building adequate generation capacity by the end of the 11 th plan. Based on the projections made in the 17th Electric Power survey, in 2011-2012, there is expected to be a demand of approximate 969 TWh at the power station bus bars, and a peak load requirement of approximate 153 GW. This means the energy demand will be higher by about 30%and the peak load by 35%. Based on the above statistics, a capacity addition of 46,500 MW has been tentatively fixed for Central Public Sector Undertakings under the Ministry of Power. At the state level, the SEBs/State utilities and private sector will add about 41,800 MW. For optimal development of the electricity energy in its totality, an integrated approach, including capacity addition through nuclear and non-conventional energy, has been adopted. The capacity addition targets of 6400 MW through nuclear power and 10,700 MW through nonconventional sources has been fixed for the period till 2012. The main aim of the players on the power market is meeting maximum consumer load, juggling between long-, medium- and short term agreements between business entities, and replacing costlier power with cheaper power. The tariffs of the industry are often market driven i.e. the prices are fixed based on the frequency meter and hence are susceptible to variability due to load generation balance. Some of the issues prevalent in the market are improper tariffs, as discussed above, and improper allocation of subsidies, beside the danger of the collapsing of the market. Regulators have been trying to establish an organized market structure by ensuring level playing field, competition and a proportionate number of buyer and sellers through legislative policies and regulations. In order to meet the deficit at the national/state levels, GoI liberalized the power sector in 1991 and encouraged private participation through the concept of IPPs, wherein the IPPs are required to supply their power to SEBs.

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As a further step in liberalization, the Electricity Act was implemented in 2003, which has provisions Open Access (Third Party Sale), empowering regulators and unbundling of SEBs into Gencos, Transcos and Discos. The Indian power market, both generation and trading, are novice as compared to the international power market wherein activities are carried on a very large scale since 10-15 years as compared to a time slot of about 5 years since the need for a ‘organised’ electricity market was recognized and steps were taken to bring the same into place.

Demand Management The need for electricity is variable and not scheduled as in terms of quantity. Hence the load balancing techniques form an important aspect of the ‘Inventory’ management system of the electricity supply. The industry experiences seasonal and irregular daily demand variations. The need for power increases during the peak hours of the day, 10 am to 5 pm, called peak power demand, and also during the seasons of summer, where in electricity is consumed in greater quantities. For this, the main aim of a consumer is to ensure the supply of the bare minimum amount for which the usage if confirmed and constant. The additional requirements of power have to be adjusted with additional arrangements. The constant need for power is sufficed through a long term power purchase agreement with a generating entity, both central and independent power producers (IPPs). The other variable demand is satisfied through medium and short term agreements, as the need may be. These variable contracts are negotiated either directly or through traders. However, there is another provision for unscheduled and inadvertent need, the UI (Unscheduled Interchange), like a spot market trading pertaining to overdrawing of electricity from the grid over one’s stipulated limit. The detailed further splitting up of the market is given as :

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EXCHANGES – DAY AHEAD MARKET (Intra-day, Day Ahead contingency, daily, weekly, monthly – upto 3 months {9%}

DEMAND VARIATIONS

DAILY UI BALANCING – REALTIME {43%}

SEASONAL Short term Trades – BILATERAL – (Direct, traders) : Day Ahead, FCFS, upto 3 months, Banking {48%}

BASE DEMAND – MANAGED THROUGH LONG TERM PPAs

Figure 1 : Diagrammatic representation of the Demand Settlement

Power systems have to make provisions for achieving a balance between real-time demand and supply. The grid frequency has to be maintained within an IEGC specified frequency band of 49.0 to 50.5 Hz. The utilities can deviate from their scheduled interchanges as long as the frequency remains with the floating frequency regime. As seen above, with the base demand is satisfied with PPAs, the short term variation are satisfied with contractual settlements and Unscheduled Interchange (UI) is used for real-time balancing.

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Power Contracts Long term Generally, for this, generators tie up with a discom for selling a larger chunk of their generated power. The quantity and the sale price are based on the terms of the PPA settled between the two entities. The PPA is arranged by the invitation of tenders. The generator floats out an open bid for the quantum of power that it generates. Discoms, those interested, file out tenders for the evacuation. The appropriate bid is then selected and the PPA is drafted out between the two entities. It is possible that the quantum of power to be purchased might not be fixed. It depends on the cost of generation of the generator. A Discom has PPAs with several generators. Power dispatch to the grid is done on the basis of the Merit Order Despatch. According to this rule, cheaper power is dispatched to the grid over costlier power. Discoms have to maintain a stipulated frequency of power that they put into the grid. Hence, they sort the power from among the generators that they have. As a result, the generator with costlier power might be asked to cut down on his generation processes. Hence, the plant does not operate at full capacity, leading to a decreased plant availability factor (PLF)1, leading to Backing down losses for the plant, in terms of MWhr that they produce.

Short term The demand for electricity is variable and to a certain extent, haphazard. The seasonal variations in trend can be predicted to a certain extent. The discoms tie up with the generators, through the PPA, for that amount of power for which they is an evident and permanent demand. Entities prefer going in for short term contracts for meeting the variations in demand and supply. Generators float bidding contracts and invite tenders from potential buyers. According to the generating capacity being offered, the potential customers file their bids and the appropriate bid is selected. The trading for temporary contract power in times of variable demand is divided in to two types of markets based on the transaction capacity and congestion to facilitate feasible meeting of demands; Spot market which includes Intra-day and Day-Ahead market and the Forward market which includes the Weekly and Monthly contracts.

1

Plant Availability is expressed as a ratio of the Operating hours + Standby Hours to the Total Year hours

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Apart from contracts, UI regulation is widely used to trade power to meet seasonal, short-term and peak demand. UI is a commercial as well as a disciplinary measure formulated to regulate the usage of additional power over base demand. UI allows overdrawing power from the grid at higher rates that are based on frequency of the power available at the dispatch centre and are generally associated with the Regional Load Dispatch Centers (RLDCs) for the different zones in the country. Some of the issues related to power trading in India are; 1) Procedurally difficult : Involves elaborate scheduling/dispatch procedures, co-ordinations with load dispatch centres, securing open-access. 2) Relatively closed-loop price discovery : wide fluctuations due to local factors, prices not having any underlying relationship to overall demand and supply, transmission scenario. Bilateral Trade Bilateral trade for power is a short term contract between two entities, for temporary settlement of demand variation. It can be carried out in two ways; 1. Direct trading 2. Through traders Direct trading forms 7% and through traders forms 41% of the total 48% share of bilateral trade in the market for short-term power trade. Bilateral trading takes place to settle the variations in demand. These variations are short-term in nature and beyond being settled through long term contracts. Hence, entities tie up for short terms to suffice their variable demand. Bilateral trading was limited within the state boundaries, prior 2003. However, after the enactments of the Electricity Act, 2003, open access came into picture and trans-state business came into play. The enactments gave the players enough authority to tap the market to search for players. Bilateral trading takes place through inviting tenders. The bidding can take place between public and private entities. In bilateral trading, the guidelines of either the Central Electricity Regulatory Commission (CERC) or the State Electricity Regulatory Commission (SERC) come into force for supervision of the deal. These guidelines come into play to ensure that foul play does not take place. But, these regulations only come into play when one of the entities involved is a state player. In case of two private players involved, the guidelines are not applicable.

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There is, however, an exception to this case. Incase the private buyer is the end consumer of that power, the guidelines are not applicable. But if the buyer intends to further put up the power for sale, which shall ultimately reach the customer, the guidelines are applicable to prevent unnecessary inflation of costs before reaching the customer. SERC guidelines are applicable when one is a state player (SERC is applicable from this state) and the other is a private player. CERC guidelines are applicable when more than one state player is involved. Generally, an entity desiring to go into bilateral trade would proceed in the following way : 1. The desired entity skims the probable market for power sale. 2. Hereafter, an open bid takes place where tenders are invited to fulfill the requirement by the buyer. 3. It is made sure that both, the buyer as well as the prospective sellers are in accordance with the guidelines of CERC or SERC, whichever applicable. 4. As per the requirement of the buyer and the deals offered by the sellers, the appropriate bid is selected. Taking the case of a generating company, A that has seasonal additional power during winters and a distribution company, B that needs power during the same time frame. These two entities enter into a bilateral trade, where the contract is shaped as per the basis of it being beneficial to both, including the cost of the traded electricity. This sale price might not be in compliance with the market rate or any other PPA that might be in possession with either of the companies, as it is subject to non-transparent negotiations. Trading in a bilateral market, involves the evaluation of the potential market for power and is extremely cost sensitive, which could be non-profit yielding contract for a generator who delivers costlier power.

Power Exchange On a general note, an Exchange is a platform on which buyers and sellers come together to trade. An Exchange is not the market but a ‘host’ to the market. In the same light, a Power Exchange is a platform on which power is traded. An exchange is effective in a market-driven economy where the prices are driven by the demand and supply. As opposed to non-market principles, it ensures a leveled playing field for players, ensuring anonymity preventing unfair trade.

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On an electronic Power Exchange, traders from a large geographical spread converge without their identities being revealed. In this case, the anonymity of the traders is maintained; hence market manipulation is thwarted and, in effect, a true market-driven power economy is enabled. It further, enables the market to be driven genuine forces of power and supply, and not by vested interest. In a contract negotiated over the exchange, the variable issues are Price, Time and Quantity, and all the other issues are standardized. Hence the negotiations take place over a general and standard platform for all the engaging entities. Some of the benefits of using the exchange for trading of power are as; Better price discovery of the traded electricity Less overheads (search cost) Payment security Better price signals Single check point on competitive prices (priority over bilateral contracts) Another trend seen with the power industry are the transmission and distribution losses, which amount to round 23% (estimated), in the Indian context. In the exchange, these losses are absorbed both by the buyer (draws lesser than its stipulated amount) and the seller (injects more power in the grid). International Power Exchanges There are successful operating exchanges around the world like Nordpool and Powernext which have a strong financial market equipped with adequate products and services for the market players, providing an efficient trading platform for business. Let us take a look at one of the successful international power exchanges in brief. Nordpool Exchange (Northern Europe) Nordpool is a major and one of the most liquid exchanges in Europe, operating between the Nordic countries of Sweden, Denmark, Norway and Finland. Nordpool Spot AS provides a market place for physical power through Day-ahead market, Elspot and an intra-day market, Elbas. Among the other European exchanges, Nordpool has the highest market share in terms of the volumes of power being traded.

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2006 (TWh)

2007 (TWh)

2008 (TWh)

Nordpool Spot

250

291

298

EEX

87

123

146

APX

19

21

25

PowerNext

30

44

52

Table 1 : Market trading volumes of the leading European Exchanges Source : Nordpool Spot AS company Presentation, 2009

The areas of operation of these exchanges are included as Exhibit 1. The exchange was established in 1993, with a view to quote power prices for the Norwegian power market. However, in 2002, with the splitting of the physical and financial markets, the Nord Pool Spot was devoted to handle the physical trading of power. The Nord Pool Spot AS operates in the physical markets based on the Nordic model of power exchanges. Apart from providing a transparent platform for trading, cutting down transaction costs and managing grid congestion, The Nordic model promotes inter-european co-operation through market coupling to Germany, Netherlands and other European countries. NordPool operates two types of physical markets based on the type of contracts ofered, Elspot and Elbas. Elspot is a day-ahead auction based market for trading of physical power. It covers countries of Norway, Sweden, Finland, Denmark and KONTEK area in Germany. About 70% of the total power consumption in the Nordic countries is traded on an Elspot market.

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Figure 2 : Relative trading volume on Nord Pool Source : Nordpool Spot AS company Presentation, 2009

Trading on the Elspot market gives a provision of hourly contracts and block bids for the entities trading on the exchange. In the hourly bid, the participant can select the range of price steps for the hourly requirements of power. The block bids are aggregated bids for several hours with a fixed price range and volume for the specified hours. Price calculations are done by evaluating the purchase and sale bids, and then reaching an equilibrium price, which shall be illustrated in the after sections. The Elspot trading varies the price calculations in relation to the bottlenecks present pertaining to the grid congestion. In case of no congestion, after the equilibrium price is decided, the whole region that is covered by the market, shows similar pricing of power, after checking the transmission capacities available. In case of congestion or bottlenecks present, according to the areas of concern, the prices are fluctuated, raised or lowered, in order to smoothen out the congestion by indirectly affecting demand. Thus, the region shows differentiated pricing.

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The Elbas trading market is a physical adjustment market, designed to cater to the immediate needs for power, for a time period shorter than 24 hours. It is an intra-day market with continuous trading of onehour contracts till one-hour prior to delivery. In India, however, the concept of a regulated power exchange has come in to play from the year 2003, which witnessed a change in the regulatory framework prevalent in the power market. Following are the regulatory changes that took place since the year 2003 : 2003 June

Enactment of Electricity Act ’03, development of an organized electricity market

2006 July

CERC issued a ‘Staff Paper on Development a Common Platform for Electricity Trading’, whereby, it recommends a spot (day-ahead) market for electricity trading, based on European model

2007 February

CERC issued ‘Guidelines for setting up of Power Exchange

2008 January

CERC Finalized new ‘Open Access Regulations for Inter State Transmission’ which includes guidelines for power exchange- based transactions

2008 June

Guidelines for scheduling of transactions on exchanges

2008 October

Finalization of operating instructions in a multi-exchange scenario

Operation The exchanges operate on a daily basis. The operation includes different phases as illustrated below. Time line of Exchange Operations Bid accumulation period (Bidding phase) During the auction sessions on each Trading Day, bids entered by Members on the IEX Trading Platform are automatically stored in the Central Order Book without giving rise to Contracts. During this phase, bids entered can be revised or cancelled. Bid accumulation period shall start at 10.00 AM and will end at 12.00 Noon.

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Auction period At the end of the bidding session, the exchange Trading Platform will seek to match bids for each hourly contract. After the price determination phase is concluded, the Members, whose bids have been partially or fully executed, will be provided all relevant trade information regarding each contract traded on the IEX Trading Platform. Price Determination Process (Provisional) All purchase bids and sale offers will be aggregated in the unconstrained scenario. The aggregate supply and demand curves will be drawn on Price-Quantity axes. The intersection point of the two curves will give Market Clearing Price (MCP) and Market Clearing Volume (MCV) corresponding to price and quantity of the intersection point. Results from the process will be preliminary results. Based on these results the Exchange will work out provisional obligation and provisional power flow. Funds available in the settlement account of the Members shall be checked with the Clearing Banks and also requisition for capacity allocation shall be sent to the NLDC. In case sufficient funds are not available in the settlement account of the Member then his bid (s) will be deleted from further evaluation procedure. Price Determination Process (Final) Based on the transmission capacity reserved for the Exchange by the NLDC on day ahead basis by 2.00 PM, fresh iteration shall be run at 2.30 PM and final Market Clearing Price and Volume as well as Area Clearing Price and Volume shall be determined. These Area Clearing Prices shall be used for settlement of the contracts. Settlement On receipt of final results, obligations shall be sent to Banks for Pay In from buying Members at 2.30 PM and will take confirmation of the same from the Bank. At 3.00 PM final results will be sent to NLDC / SLDCs for incorporating in final schedules. Once a transaction is scheduled it shall be considered as deemed delivery

.

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Delivery of power Delivery Point Delivery point for the purpose of contract, shall be reckoned as the periphery of Regional Transmission System in which the grid-connected exchange entity is located. The same shall be used for the purpose of payment of transmission charges in cash and transmission losses in kind. For example, delivery point for a state-embedded entity in Maharashtra shall be WR periphery. Day-ahead Scheduling of Exchange traded contracts The Exchange traded contracts will be aggregated for each region and State for each hour. This will also give net contractual flows between regions and/or bid areas. After the schedules are issued by NLDC/SLDCs, the delivery shall be deemed to have been completed. Transmission Capacity, Transmission Charges and Losses  Levy of transmission charges Following Transmission Charges shall be payable by the Members for the traded contracts: Transmission Charges for respective Regional Transmission System, as made applicable under the Central Electricity Regulatory Commission (Open Access in inter-State Transmission) Regulations, 2008. Transmission Charges for respective State Transmission Licensee, as decided by the concerned State Electricity Regulatory Commission. In absence of any direction or order from concerned SERC, in this respect, the provisions as stipulated in the Central Electricity Regulatory Commission (Open Access in inter-State Transmission) Regulations, 2008 shall be applicable. Socialized Scheduling and Operating Charges for trades on the Exchange. The Exchange shall pay such charges based on Central Electricity Regulatory Commission (Open Access in inter-State Transmission) Regulations, 2008 to NLDC and SLDCs. Such charges shall be socialized over all transactions within respective State(s) and Region(s). Any other charges as specified by CERC.  Transmission Losses: All grid connected exchange entities shall pay, in kind, the transmission losses from delivery point to its grid connection point. Transmission losses, for the Regional Transmission System, as decided by the NLDC for Collective transactions, shall be accounted for at the time of scheduling. Similarly, transmission losses for the State Transmission Licensees, as prescribed by the respective SERC, shall also be accounted for at the time of scheduling.

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Markets The operations on an exchange consists of different types of contracts, mainly consisting of a Day-ahead market (DAM). Further on, the contracts can be divided into a spot market (Intra-day and Day ahead) and Forward market (Weekly and Monthly contracts). DAM is a major tool of operation used by both the exchanges for trading. DAY-AHEAD MARKET Double-sided closed option (the traders are anonymous of the bids that are placed, both on the demand as well as the supply side) Hourly contracts (1-24 hours) No possibility of reversing or squaring off of contracts Hourly variation in price The different exchanges have slightly different specifications pertaining to the DAM. The exchanges provide facility to even trade the scrap capacity available with a seller. Special provisions Congestion management is an important factor and a special provision that is taken into concern with the exchange. Imbalance of power within the different regions can lead to congestion. This can delay the supply and transmission of power the following note details how the exchange tackles congestion by altering price. Let A and B be two areas, A being a surplus area and B being a deficit area. An equilibrium price, P0 , is reached by taking an unconstrained scenario for the sale and purchase bids, for both the areas.

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Area A + Area B

Having reached an equilibrium price, the areas with deficit and surplus are recognized in order to make price adjustments. Let us consider area A, which has surplus power. In this area, the prices are lowered. Lowering of prices shifts the equilibrium price point to the right, thereby increasing demand to Q 1 and reducing the quantity of sale bids for that area. Thus, the surplus area is eased out.

Area A

Similarly, area B has deficit power. Thus, price adjustment is done in such a way that the sale bids increase. The price is raised to P2 in the area B. raising the price shifts the equilibrium price to the left, decreasing the quantity of purchase bids to Q2 and increases sale. Thus, the deficit in the area is normalized.

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Area B

Congestion management is an important tool for power exchanges in order to ensure unconstrained flow through the grid.

Grid Management Transmission and grid management are the essential functions for smooth evacuation of power from generating stations to the consumers. Transmission function primarily consists of construction and maintenance of transmission infrastructure while the job of grid operator is to give operating instructions to the engineers in the field and ensure moment-to-moment power balance in the inter-connected power system. Grid management involves taking care of the overall reliability, security, economy and efficiency of the power system. Grid management is carried out a regional basis in India. The country is geographically divided in five regions, namely Northern, Eastern, Western, North-Eastern and Southern. All the states and the union territories fall under either of these regions. The first four of the grids operate in a synchronous mode, which implies that the power across these regions can flow seamlessly as per the relative load generation. The Southern region is interconnected with the rest of the India grid through asynchronous links. This implies that the quantum and direction of power flow between the Southern grid and rest of India grid can be manually controlled.

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Let us look at the hierarchy of the grid infrastructure.

Figure 3 : Grid Infrastrucutre

The Load Despatch Centres basically aim at optimum scheduling and dispatching of electricity within the region, in accordance with the contracts entered into with the licensees or the generating companies operating in the region and keeping accounts of the quantity of the electricity transmitted through the regional grid. Grid management functions can be segregated into different types; ex-ante, real time and post-facto; according to their nature of operations. The ex-ante functions are more in nature of planning for the day of operations. It involves estimating the future scenarios, evaluating options and making elaborate plans to meet the anticipated as well as unforeseen events. The real-time functions comprise of balancing the dynamically varying supply and demand of energy in the inter-connected system.

25 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

Regional Electricity Market The regional electricity in India is governed by frequency linked operation and commercial settlement mechanism known as Availability Based Tariff (ABT) and Unscheduled Interchange (UI). Unscheduled Interchange : The UI mechanism is often seen as a disciplinary as well as regulatory measure, in order to bring order to the grid, by maintaining the frequency within the permissible window. (Soonee, Narasimhan, & Pandey, 2006) Prior to the implementation of the ABT, the incentives were linked to the actual production and not availability. Hence, it led to the generators pumping in electricity, irrespective of the system frequency and they were paid incentives as per the amount put into the grid. It led to the increasing of operational costs for the generators. On the other hand, the utilities would draw from the grid with impunity, even in deficit and returned equivalent energy to the system during surplus conditions. UI mechanism encourages the utilities to conserve when in surplus so as to provide when in shortage and thus smoothen the frequency curve. The UI rate is a frequency-activated signal. Every utility reacts to this signal in real-time and adjusts its generation/demand and a new equilibrium is achieved. The decreasing marginal returns with every additional unit of deviation from the scheduled interchange acts as a counterweight, which forces the utility to seriously weigh the consequences of its actions. Thus, a collective action results in a Nash equilibrium, where the pay-off for every player is maximized. The UI rate at any frequency represents the marginal price of the costliest generator that is expected to be on the bar at that frequency that forces other players to optimize their exchanges with the grid in order to maximize their profits or minimize their costs. The UI rate, therefore, needs to be readjusted whenever the energy costs of generation in the country get revised, similar to ABT. ABT shall be covered under pricing of power. Open Access and Electricity Trading Open Access (OA) has been implemented in all the regions since May 6, 2004 in line with the open access regulations issued by CERC. The regulations aim at promoting non-discriminatory usage of the transmission system by customers after payment of appropriate charges. Open Access comes into play after the customer has accessed the stipulated limit.

26 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

Access can be granted under two categories : long term and short term. Long term access is granted for usage of 25 years or more while the short term access is for a maximum of three months at a stretch. As per the existing regulations, the long term users pay higher charges and have a higher priority over short term users. Under the short term category, the reservations can be made under the categories of Advance, First-Come-First Served, Day-ahead and Same day. Open access in transmission effectively introduces competition in the wholesale electricity market. Although the overall inter-state trade volume is currently only 3% to 5% of the country’s total energy consumption, it has had a multiplier effect on the entire power sector by promoting competition, efficiency and economy. (Pandey, 2007) The regional transmission system and the inter-regional links are being utilized to transport surplus hydro-generation in the north-eastern region and pithead generation in the eastern region to the energy deficit load centres in the northern, western and southern regions. The inter-regional exchanges have increased manifold after the introduction of open access. Almost all utilities in the grid have taken advantage of the open access provisions and transactions have taken place in all the possible directions in the country. The electricity trade has grown further after the commissioning of new generating stations and the establishment of an organized platform for trading in the form of a Power Exchange. The grid operator would continue to provide the interface between the physical system and the electricity market

Pricing of Power The pricing of power can be assessed in three different ways, depending on the type of contracts which are in concern. However, the mechanism through which power is priced is almost similar in both, longterm and the bilateral trading, except for the distinction of the terms and tenure of the contract. Long term contracts and Bilateral trading Pricing of power in long term contracts, or rather through PPAs and bilateral trading is generally negotiated between the two entities.

27 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

The pricing of power is very essential from the point of view of revenue earning from power sale. The cost of generation of power involves two aspects : 1) O&M costs and Fixed costs 2) Input fuel price Fixed costs cover the costs involved in the setting up of the plant, the infrastructure and the financial structuring opted for. They are : 1) Debt obligations 2) Interest charges 3) Lease and Hire rental charges 4) Capital cost and 5) Settling of exchange rate, if required. The Operations & Maintenance cost depends on the efficiency of a power plant to generate power. The various risk factors that can affect the O&M costs are : 1) Plant availability 2) Plant load factor2 3) Heat rate degradation3 4) Spares consumption and prices 5) Manpower turnover 6) Unscheduled/Scheduled maintenances 7) Logistics support 8) Daily operations The above factors can affect the O&M costs, and hence, need to be assessed as per their risk factors. The input cost of fuel is variable and depends on the type of power plant established. Over the various fuel inputs like coal (imported or domestic), Liquefied natural gas, Natural gas is a viable and cheaper option. (A relative comparison of the four viable fuels is included as Exhibit 5). However, the capital cost for a natural gas fired plant is relatively higher. The other renewable sources like hydel- or wind power plants also have a high cost devoted to capital assets and the technology used in generation. For a certain type of power plant, the fuel cost is fixed through a Fuel Supply Agreement (FSA). 2

Plant Load Factor is the ratio of the Average produced power to the output of the plant operating at full capacity. Heat rate is the efficiency level of a generator to use the input BTUs of heat fed to the feedwater to produce 1 KW of energy. 3

28 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

The sale price of power is fixed on a two-part tariff basis which involves two components : 1) Capacity charge 2) Energy charge The pricing is generally done on a cost-plus pricing basis which covers the targeted return. The capacity charge covers the fixed costs like O&M expenses and other capital costs. The energy charge covers the fuel costs. Hence, the fuel chosen plays an important role in the influencing the ability of power to avoid backing down losses. Backing down losses to a power plant are generally those losses which occur when a plant does not operate at optimum PLF. It can occur due to the following reasons : 1) Load restrictions due to costlier power. Like, a trader might have three to four generators on his list for power purchase. In order to maintain the transmission limit, the power dispatch depends on merit order dispatch. That is, cheaper power gets an evacuation preference over costlier power. Thus, the generator having costlier power is forced to generate power according to the requirement put forth by the evacuator. 2) Restrictions in gas supply from the supplier 3) Power losses due to the shutdown of machines, scheduled or for maintenance or on account of tripping.

Out of all these causes, load restriction occurs due to the plant generating costlier power. The other avoidable loss is due to the tripping of machines which can be eased out by maintaining a proper environment of the turbines. The other causes, to a certain extent, are outside the influential circle.

The most important aspect of grid maintenance is the load generation balance within the region it operates in. Regulations are devised in such a manner that generators get their profit and everyone are initiated to maintain the required frequency level in the grid. India plans to have an Integrated National Grid, to ensure least cost supply of power. It would mean an amalgamation of the five regional grids, which have varying operational parameters, which include frequency. Such an initiative would require normalization of the frequency across the grids with proactive load management. Another issue is the varying amount of surplus and deficit in the five grids. The north and the eastern grid have surplus power while the Southern and Western grid has a deficit. This leads to a decreased frequency operation, leading to long-term damages and a hidden cost that is borne by the customers.

29 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

Availability Based Tariff (ABT) is a recent, government initiated tariff system, which is a revision of the existing tariff design. ABT is a performance based tariff for the supply of electricity by generators owned and controlled by the central government. It is also a new system of scheduling and dispatch, which requires both generators and beneficiaries to commit to day-ahead schedules, and of rewards and penalties seeking to enforce day ahead pre-committed schedules, though variations are permitted if notified one and a half hours in advance. The order also emphasises prompt payment of dues.

ABT is a two-part tariff system, consisting of the following components : 1) A fixed Charge (FC) payable every month by each beneficiary to the generator for making capacity available for use. The FC is not the same for each beneficiary. It varies with the share of a beneficiary in the generator’s capacity. It also varies with the level of availability achieved by the generator. In case of gas fired and thermal plants, the FC has not been been defined by GOI notification. Hence, it comprises of loan interest, depreciation, O&M expenses, ROE, income tax and interest on WC. 2) An energy charge per kWH of energy supplied as per a pre-committed schedule of supply drawn upon a daily basis. 3) A charge for Unscheduled Interchange (UI charge) for the supply and consumption of energy in variation from the pre-committed daily schedule. This charge varies inversely with the system frequency prevailing at the time of supply/ consumption.

ABT attempts to promote financial incentives to promote grid discipline.

Pricing on the exchange There are certain factors that influence price of power that is bidden on the exchange. They are : 1) Season of sale : The demand of power undergoes seasonal variations. For example, the regularity or irregularity of the monsoon tends to vary the electricity demand. During intermittent, irregular or no showers, the demand goes up as the atmosphere does not cool down, and hence people tend to use cooling appliances discreetly.

30 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

Figure 4 : Selling price of power on the Exchange (June 2008 – May 2009), in Rs./KWh

2) Period of the day : The period of the day during which the power is sold also affects the price. The variation occurs due to the activity level associated with a particular hour.

Figure 5 : Average Hourly Market Clearing price for April 2009, traded on IEX, in Rs./KWh

During the peak hours of the day, office hours between 10 am to 4 pm or 5 pm, the consumption (Demand) is higher. With the supply being limited, the price of power goes up during this period.

31 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

3) Shutdowns : The Central Electricity Authority (CEA) receives yearly schedules of the power generation statistics from generators, including shutdowns for maintenance purposes. Thus, the area where a shutdown in power plants is observed shows a raise in demand in that area, with a decrease in supply. Hence, automatically, the price in that area goes up. The price is decided on the basis of the demand and supply of electricity by the bidders. The algorithm of price calculation is done on a hourly basis, in MWh. The whole process is described in detail below: Let us consider the portfolios of three bidders; A, B and C. These three bidders submit anonymous bids pertaining to the quantum of power they would purchase or sell at different prices of power (in units of Rs./KWh). The following table summarizes the nature of bids submitted online. Price

0

1

1.1

2

2.1

2.5

3

3.1

4

4.1

A, MW

20

20

20

20

20

20

20

0

0

0

B. MW

60

60

60

60

40

40

40

40

40

20

C, MW

40

20

0

0

-40

-60

-80

-80

-120

-120

Purchase

120

100

80

80

60

60

60

40

40

20

Sale

0

0

0

0

-40

-60

-80

-80

-120

-120

Net

120

100

80

80

20

0

-20

-40

-80

-100

Rs./kWh

An algorithm, or rather a demand-supply curve, is then plotted taking the total data registered for purchase and sale to help reach an equilibrium price. The equilibrium price is then and the corresponding data are then registered as the selling price for a particular market clearing volume data (MCV).

32 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

Price

4 Rs/kWh

Purchas e

Sale

3 2 MW

4 8 0 MW0

12 0

Figure 6 : Determination of Equilibrium Price

In the diagram above, portfolio A and B emerge as net buyers at the price of Rs 2.5 per kWh. Portfolio C sells 60 MW, out of which 20 MW is purchased by A and 40 MW by B. With bids accumulated on a country wide basis, congestion may happen. To manage that, market splitting has been proposed. For which, the country will be divided into five price zones, north, north east, east, south and west.

33 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

Gujarat State Electricity Generation Company Description Gujarat State Electricity Generation (GSEG) is engaged in the production of gas based electricity, from their power plant at Hazira. The company is a special purpose vehicle (SPV) floated by Gujarat state Petroleum Corporation (GSPC) with a view to covering the different verticals of the energy sector. GSEG has a power plant commissioned at Hazira which uses natural gas as a fuel for generation. Natural gas is a clean and economically cheap option, which allows GSEG to generate electricity at competitive costs. GSEG manages its electrical utility with the following initiatives : 1) Advanced power generation and management practices, and improve the efficiency of power supply to Gujarat Electricity Board 2) Operations at least-cost 3) Full compliance with the health, safety and environmental regulations of Gujarat 4) Excellent working conditions to optimise the skills and potential of the staff and managers involved.

GSEG has a present generation plant with a capacity of 156.1 MW at Hazira. The first phase of expansion is on way which would expand its capacity to360 MW. The company plans to further expand capacity by commissioning larger projects and expand its reach in the distribution vertical of the power sector.

Combined Cycle Power plant at Hazira The combined cycle power plant at Hazira in possession of Gujarat State Energy Generation has two components – the existing Plant of a capacity of 156 MW and the expansion plant with an additional capacity of ~350 MW. The plant comes under the Western Region Electricity Board (Installed Generation capacity of 8797 MW, for the year 2005 and a deficit of about 3500 MW). The major players operating on the western board are as follows : 1) State :

GEB

2) Central :

NTPC

3) IPPs :

AECo, GIPCL, Essar, GPEC, GSEG 34 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

The plant has a fixed Fuel supply agreement (FSA) and a Power purchase agreement (PPA), for its input and power evacuation, for both its components. The FSA is with GSPC- Niko for its natural gas supplied through GSPL cross-country pipelines, laid upto the existing plant, from its wells in Hazira for both the capacities. The plant has a fuel requirement of 0.42 MMTPA, wherein GSPC is able to supply about 80% of the total requirement, and the rest fuel requirement is completed through LNG. The power evacuation, for its present plant, is facilitated through PPA with Gujarat Electricity Board (GEB), wherein the plant is connected to the grid through two 220Kv switchyards. Plant configuration The plant is a combined cycle power plant. It utilizes natural gas as a fuel. Normal thermal plants have an efficiency of about 30% to 40%. In CCPP, the efficiency of generation rises to about 44%- 50%, with some of the latest plants having efficiencies in excess of 55%. The mechanism has a combination of a gas turbine generator (Brayton cycle) with turbine exhaust waste heat boilers and steam turbine generator (Rankine cycle). In a combined cycle operation, the exhaust gases from each gas turbine are ducted to a waste heat boiler, also called a Heat recovery system generator. The heat in these flu gases, ordinarily exhausted to the atmosphere, generates high pressure steam. This steam is piped to a steam turbine. Such a plant requires low maintenance fuels like natural gas and light distillate fuels, which are expensive. A diagrammatic representation of a combined cycle power plant is enclosed as Exhibit 2. The present plant has two operational gas turbines and one steam turbine. Present configuration : Generation capacity of 156.1 MW Year of operation : GT11 & GT12 since December 2001 STG – June 2002 Total operating hours : GT11 (32751), GT12 (27886), STG (29964.7)

35 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

Least cost option study – Relative comparison Conversion Coal Based Thermal Power Plant

CCPP (Regassified Natural gas)

Comparatively lesser efficient

More efficient

Operational efficiency of 38% with the best

Higher output & operational efficiency of 60% on

available fossil fuel

net calorific value basis

Higher requirement of cooling water with a

Steam turbine output of 50%, lesser requirement of

plant of similar capacity

cooling water

Environmental hazard of ash disposal

No environmental hazards, lesser gestation period

Based on coal, non- renewable fossil fuel

Based on clean fuels

Table 2 : Fuel Comparison

Fuel Source The present plant utilizes natural gas as a source of fuel, which is delivered by GSPC- Niko, as mentioned above. The choice of fuel depends on the following deciding factors : Cost of generation Flexibility in operations Location construction Infrastructure availability Environmental concerns There are various options for fuel inputs; coal, LNG and other sources like fuel oil. NG as a source, is cheaper and is environment friendly. This reduces the cost of generation for the company, allowing it to produce power at a cheaper rate. The statistics for the usage of NG is as under : Gas Source : GSPL Niko, hazira Quantity : 0.8 MCMD (33600 Nm3/hr for 2 GT) Total gas consumption : GT11 + GT12 = 0.78 MCMD The comparative analysis of the four fuels is given as Exhibit 3.

36 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

Production Data The present plant operates at an average PLF of 85%, with an installed capacity of 156.1 MW. Operating at a full capacity, the plant would produce, on a monthly basis ; Days in a Month

Generated Capacity (in MWh)

30

112392

31

116138.4

28 (February)

104889.2 Table 3 : Production at full capacity

However, due to Actual Commercial and Technical losses and that a CCPP power output depends on ambient conditions typically giving lower output during high ambient temperatures, the plant does not operate at full capacity. The following table gives a record of the production data from the period of June 2008 to May 2009. Month

Production Data (in MWh)

June 2008

101707.9

July 2008

69323.28

August 2008

56686.32

September 2008

58416.4

October 2008

83409.71

November 2008

107555.3

December 2008

106715.4

January 2009

101719.7

February 2009

96330.7

March 2009

108013.9

April 2009

111752

May 2009

114098.5 Table 4 : Actual production data

37 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

Amount of losses incurred The plant, as observed, operates at an average 85% PLF. Losses observed by the plant are mainly backing down losses. The following graph shows the total quantum of losses incurred by the plant.

Figure 7 : Total monthly loss for the period June 2008 – May 2009, in MWh

Nature of losses The plant highlights three possible types of losses, mainly backing down losses: 1) Load restriction : The power plant of GSEG uses a costlier fuel of natural gas for generation. However, fuel supply restrictions from the supplier leads to the usage of LNG to about 20%. Moreover, the capital costs of the plant, it being a combined cycle plant, are higher. Hence, the power produced by the plant lands up as being costly to GEB. As a result, the plant shows backing down losses due to load restriction. The following graph shows the loss amount due to load restriction.

38 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

Figure 8 :Monthly Load Restriction loss data for the period April 2008 – May 2009, in MWh

As the power is costlier to GEB and under the Merit Order Dispatch flow, the plant cuts down on its produced capacity, or rather slows the generation process, as ordered by GEB, influenced by the demand in the grid. This leads to the plant not functioning at optimal capacity, leading to losses. 2) Operational losses : These type of losses occur due to operational fallacies and failures. They include planned and unplanned shutdowns (machine and generator tripping), part load operation of certain turbines. The following graph enlists the total operational losses for the plant, including all the parameters and conditions.

Figure 9 : Monthly Operational losses for the period April 2008-May 2009, in MWh

39 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

As mentioned above, the operational losses can be broken down into three types : Forced Shutdown Planned shutdown Part load operation of the turbines Out of all the months, planned shutdown of the turbines for maintenance has taken place majorly on a large scale basis only in the month of April 2008, where it comprises of the entire volume of 20008.5 MW. In the other months, the losses comprise more of unscheduled maintenances, peaking in the months of August 2008 and September 2008, indicating operational inefficiencies in the working of the turbines. The power losses due to part load operation of the turbines are introduced from the month of December 2008. 3) Fuel Restriction Losses : This third type of losses have been described as occurring due to the insufficient availability of fuel from the supplier, thereby forcing reduction in generation. However, these losses are nil, in case of the plant. Out of the above losses, the generation losses due to load restriction can be utilized to generate extra revenue. The plant has surplus capacity which remains unutilised and hence, unsold. This extra capacity can be tapped and sold through a suitable platform to generate extra revenue for the company. The deal here is to find an optimum platform which would guarantee risk-free sale of the power, taking into account the generating cost and type of power which would be offered.

40 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

Options and Evaluation In the chapters above, we have seen that GSEG has a long term PPA with GEB which forms a constant source of power evacuation. In this agreement, the prices are negotiated and fixed at a certain price, with fixed terms. As also witnessed above, GSEG shows extra generated power capacity which remains unsold, and hence could be an added source of revenue. Looking at the variation in the power that would be up for sale, the market that would concern GSEG is the short term market.

Short term market Since the power that would be traded on the exchange is variable and not frequent, the power has to be traded in the short term market. As mentioned above, there are two options available for trading, bilateral and the power exchange.

Bilateral market – Power exchange : Relative Comparison Tapping a bilateral market, involves the evaluation of the player and the probable demand in the market. It also involves different aspects like; The generation cost, Efficiency level of the plant, The ability and the strength of a plant to negotiate and, to a little extent, The type of power plant involved. GSEG has a higher cost of power, and thereby, finding probable partners would be a little hassle, wherein the players cold have an access to cheaper power. Moreover, on the exchange, the company gets varied options in terms of players, where as through bilateral trade, the options are restricted to the bids that are received. Financial security is also provided by the exchange acting as an intermediary. Thus, the exchange is more feasible option as compared to bilateral trade.

41 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

Power Exchange The Indian power market has two different operational exchanges. They are ; 1) Indian Energy Exchange (IEX) 2) Power Exchange India Limited (PXIL)

Indian Energy Exchange Indian Energy Exchange (IEX) is India’s first, nation-wide, automated and online power exchange. IEX received its approval from the Central Electricity Regulatory Commission (CERC) on August 31, 2007 and commenced operations from June 27, 2008 (Srivastav, 2009). Financial Technologies (India) Ltd. (FTIL) and Power Trading Corporation India Ltd (PTC) a leading power trading company are the principal promoters of IEX. In recognition of the significance of IEX in the modernisation of the electricity market in India, a number of prominent players in the Indian electricity market have taken stakes in the Exchange. They include Infrastructure Development Finance Company (IDFC), Adani Enterprises, Reliance Energy, Lanco Infratech, Rural Electrification Corporation (REC) and Tata Power Company.

Power Exchange India Limited Power Exchange India Limited (PXIL) commenced operations from October 22, 2008. PXIL is promoted by National Stock Exchange (NSE) and the National Commodity and Derivatives Exchange (NCDEX). The entities that have a stake in the exchange are Power Finance Corporation Limited (PFC), Gujarat Urja Vikas Nigam Limited (GUVNL), JSW Energy, GMR Energy and Jindal Power Limited. The market system at PXIL offers a spot market and a realtime market, pertaining to the services offered. The exchange operates a day-ahead market, a 24 hour period sub-divided into hourly contracts. The software accepts simultaneous buy and sell bid portfolio. The bids remain anonymous and the bidder can have the flexibility of bidding for time blocks, even of an interval of 15 minutes with the Block-bid option. The finance between the participants is handled by the exchange which acts as an intermediary. The types of contracts offered are normal DAM type and block bids, restricted only to the sellers. The price calculation is similar to the equilibrium pricing. The pricing is the main tool that is used to manage congestion. As explained in the Nordpool type of pricing differentiation, the following steps are involved in the price calculation for congested areas; 42 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

1) Calculation of Market Clearing Price (MCP) for normal flow of power, without congestion. 2) Identification of areas of probable congestion, transmission bottlenecks 3) Identify surplus areas and deficit areas 4)

Increase price in deficit area (Supply increases and demand decreases)

5)

Decrease price in surplus area (Supply decreases and demand increases)

Pricing for the real time market is based on the frequency of the system. Of the metered generation registered, a part would be taken for the spot sale contract. The imbalance is put up for real time transactions. In the real time market, the pricing of power is based on frequency of the system. The amount of power in the system decides the price of the power to be supplied. The pricing includes penalties for over-drawal and under-supply of power and benefits for a reverse situation. All the other terms and specifications are similar to that of IEX.

Relative comparison between the exchanges Both the exchanges, IEX and PXIL, have almost the same terms and conditions and function on the same principle. H owever, the exchanges can be differentiated on the basis of the following points : 1) Market share and present position 2) Membership options 3) Contracts offered for trading 4) Technology support

Market Share IEX has commenced its operations earlier than PXIL. On the market position front, IEX has a comparative 92% share as compared to an 8% share of PXIL.

43 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

Figure 10 : Relative Market Share of the two Exchanges

The 92% pertains to a trading of 2142 MUs and the 8% to a 185 MU. As compared to PXIL, IEX has access to all the states of the country, 23 to be precise, and has a turnover of Rs. 2451 crores. The exchange has a wider customer base of participants interacting on the platform as compared to PXIL.

Figure 11: Monthly Summary of Electricity traded on Exchanges, IEX & PXIL

44 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

Over a period of 6 months, the relative share of PXIL has averaged between 2% to 19% of the total electricity traded via an exchange.

Figure 12: Daily Average Traded Hours (2008-2009)

The daily trading hours shows that the platform of IEX is utilized almost for the entire day (24 hours) for the past 7 months, except January 2009 where the figure fell to 19.9 hours. On the other hand, PXIL showed trading for about hours ranging from 25%-50% of the entire day length. This indicates that the client exposure and power traffic is higher on IEX than PXIL.

45 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

Figure 13 : Monthly Average Traded Hours (2008-2009)

Membership Options IEX and PXIL have drafted membership options almost on the same lines but have different ways of offering it. The membership costs have different fixed costs as per the type of membership opted for and the transaction costs, a source of income for the exchanges, varies accordingly. While considering both the exchanges, either one can trade electricity or be a clearing member as in terms of finance, or be both. The basic layout of the terminology of the memberships is given as; Trading Member : Entities that trade electricity on the exchange. (Generators, CPPs, IPPs) Clearing Member : Entities which handle the financial transactions of the traded power. (Lenders and banks) Professional Member : Entities that handle transactions on the behalf of other traders. They can either be professional traders or clearing members. Proprietary Member : Entities that handle transactions on their own behalf only, both trading and financial aspects.

46 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

Both the exchanges offer different combinations of memberships, with varying membership fee. Let us look at the individual exchanges. Indian Energy Exchange

Figure 14 : IEX Membership

The fee structure for a Proprietary and a Professional member is given as :

Table 5 : Fee Structure for IEX

The above structure has two options, with a varying transaction fee. The full payment option has a transaction fee of 1 paise/kWhr and the light payment option has a transaction fee of 2 paise/kWhr. 47 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

Beside the two options, the entity may choose to be a client at a fee of Rs.1 lakh. The proprietary members need to have a grid connectivity and a standing clearance from the State Load Despatch Centre (SLDCs).

Power Exchange India Limited The membership details are given as below: Type of Membership

Entitlement

Suitable for

Trading Member (TM)

Entitles the member to trade, both

Smaller captives, representatives of

for themselves and/or on the behalf

captives

of their clients Trading

and

Self-Clearing

Entitles the members to trade and

Member (TSCM)

clear for themselves only

Trading cum Clearing Member

Entitles the members to trade and

(TCM)

clear for both, themselves and/or on

Large captives and utilites

Traders/ Active utilites

behalf of their clients Professional

Clearing

Member

Entitles the members to clear on

Lenders/ Large banks

behalf of other TMs

(PCM)

Table 6 : Membership Options for PXIL

The fee structure of the above membership options are given as follows :

TM

TSCM

TCM

PCM

One Time Fee

5

10

10

0

Annual Fee

1

2.5

2.50

1

Interest-free security

10

25

40

50

Processing fee

0.05

0.05

0.05

0.05

Total

16.05

37.55

52.55

51.05

deposit

Table 7 : Membership fee for PXIL

The interest-free security deposit of Rs. 40 lakhs for a TCM is for a maximum of self+ 5 clients. For every additional client over this stipulated limit, a fee of Rs.2 lakhs has to be paid. PXIL has a variable transaction fee of 1 paisa/kWhr, applicable to all the membership options. 48 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

Considering GSEG, a power generator, with IEX, it could either become a Proprietary member or a Professional member, depending on the following factors : 1) Resources at disposal : Trading on the exchange requires expertise, from the viewpoint of adept manpower. The manpower, if available, can be utilised to tap the market of trading on behalf of clients by becoming a Professional member. This would lead to additional avenues opening up in terms of business and revenue. 2) Another factor is the availability of funds which can be dispensed towards selling the extra capacity. However, the fund factor depends on the quantum of the power that would be traded on the exchange. Incase the plant has huge quantity of power that it trades and for a long time duration, the full payment option seems viable as the transaction fee for the same is low. This would be feasible as the transaction cost is lowered as compared to the light payment option. However, if the voluminous trade ceases only to be seasonal, with nominal mundane trading, the light payment option would be feasible.

Considering PXIL, GSEG could opt for any option except for a Professional Clearing Member. IEX offers a more simplified membership option, which is relatively economical as compared to PXIL. Ideally, taken the expertise and the PPA of GSEG, the company does not have the adequate manpower to deal on the exchange. Moreover, the expansion phase of the plant to 360 MW is also underway. At such a juncture, extra funds would be needed towards the expansion phase. With the lack of manpower too, the undertaking of trading on behalf of other clients would not be optimally profitable. Hence, in these circumstances at hand, the viable option here would be the membership with IEX. The option of the full and light payment can be decided on the basis of the volume traded. The extra cost as compared to PXIL, at places, can be settled against the fact that IEX has an international based technology support and a wider customer base to interact with, coupled with a dense trade traffic.

49 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

Contracts Offered PXIL has an operational Day-ahead market for transactions and a real time market for balancing the variations. On the other hand, in addition to the DAM, IEX proposes to have a Term- Ahead market. TAM would offer contracts with features that are listed below : 1) Regional contracts 2) Concurrence with SLDCs 3) Product categories The different product categories available are; 1. Monthly contracts : Delivery Far Month (Contracts for delivery in the fourth month, counting the current month as the first), Delivery Middle Month (Contracts for delivery in the 3 rd month), Delivery Near Month (Contracts for delivery in the 2nd month) 2. Weekly contracts 3. Daily contracts These term-ahead contracts would be similar to bilateral contracts, but with certain enhancements. The term-ahead market would also cover regional contracts. IEX has received inprinciple approval from CERC for these TAMs. Further on, the exchange also proposes trading of the following environmental-friendly certificates : 1) Green Certificate Trading (REC) : Facilitate trading of renewable energy certificates, the trading would be in accordance with National Renewable Energy Law being prepared by GoI.

50 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

2)

White Certificates Trading : Facilitate trading in energy savings, blueprint by MoP under National Action Plan for Climate change.

Technology Support OMX Technology, Sweden, the technology provider to the world’s leading power exchange, NORDPOOL, has joined hands with Financial Technologies (India) Ltd to provide technology support to Indian Energy Exchange (IEX). OMX is a leading expert in the exchange industry. It owns exchanges in the Nordic and Baltic regions, and develops and provides technology and services to companies in the securities industry around the globe. In power trading, OMX is a pioneer, with four power exchanges in Europe currently using its technology. Financial Technologies is a leading technology enterprise specialising in providing technology for organized markets connected with multiple asset classes such as securities, commodities, debt, and foreign exchange. IEX is the seventh exchange with which Financial Technologies is sharing its systems management expertise in trading, clearing and settlement operations .

Thus, IEX has access to an established and sophisticated technology support as compared to PXIL. Based on the above factors, IEX proves to be a better trading platform as compared to PXIL.

51 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

Costing Analysis Comparative costs of other options GSEG has the following different options for evacuation of the restricted capacity; bilateral trade, power exchanges (IEX & PXIL) and UI. The following table gives the relative comparison costs of trading on the different platforms. Aug 08

Sept 08

Oct 08

Nov 08

Dec 08

Jan 09

Feb 09

Mar 09

Bilateral 6.78

7.17

7.78

7.98

7.89

7.23

6.58

7.34

IEX

7.68

8.46

7.56

6.14

6.42

5.62

6.42

7.57

7.22

6.58

5.86

4.42

6.24

6.32

5.33

4.89

4.99

4.89

4.85

7.50

PXIL UI

5.17

6.50

Table 8 : Comparative costs for power trade (in Rs./KWh)

As seen from the above table, from the two exchanges, IEX has higher trading prices as compared to PXIL. Prices on bilateral market are certainly higher, which could generate higher revenue. But, as mentioned in the above comparison between the exchange and bilateral market, the power being costlier and the market research renders it non-viable, coupled with the fact that it does not offer a wider exposure to customer base. Rates on the UI interface are low. Hence, it can be used to trade power during intervals when prices are low on the exchange. Thus, it reiterates the fact that the exchange is a much more viable option to trade.

Effects on revenue GSEG has a generation cost of approximately Rs. 2.25/unit to about Rs. 5/unit depending on the type of fuel used with highest being on RLNG. Out of the total generation cost, the variable expenses (cost of gas, transportation cost from the gas wells at Hazira, import of power from GEB and the O&M expenses) account for a range of 70-75% of the total cost. The company, in even in the case of not generating the restricted amount, will incur the fixed expenses (employee wages, interest and financial charges, depreciation) involved in the cost. The following table gives a list of the exchange trading prices from the period June 2008 to May 2009.

52 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

Month

Price (Rs./KWh)

Month

Price (Rs./KWh)

Jun-08

7.66

Dec-08

6.14

Jul-08

7.73

Jan-09

6.42

Aug-08

7.5

Feb-09

5.62

Sept-08

7.68

Mar-09

6.42

Oct-08

8.46

Apr-09

10.47

Nov-08

7.56

May-09

6.52

Table 9 : Trading prices on IEX (June 2008-May 2009)

The trading prices on the exchange differ as per the season of trade. The following table gives the total losses, load restriction losses, both in amount and as a percentage of the total backing down losses. Total Backing Down losses

Load Restriction Losses

(n MW)

(in MW)

As a percentage of total losses

10684.1

7769.5

7.639032956

46815.12

422

0.608742114

59452.08

774.98

1.367137609

53975.6

241.5

0.413411302

32728.69

2228.7

2.671991067

4836.66

3764.91

3.500439867

9423.05

6476.3

6.068761429

14418.68

11574.88

11.3791898

8568.5

7404.7

7.686749915

8124.5

6105.55

5.652559532

640

607.2

0.54334598

2039.9

2039.9

1.787841207

Table 10 : Load restriction loss data

As seen above, the load restriction losses range from a minimal percentage to around 11% of the total losses.

53 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

Monthly revenue Considering the above values of generation cost, the prevalent trading prices and the loss amounts, the following table gives a calculation of the marginal profit for GSEG, if it trades the extra capacity o the exchange. The generation cost varies as per the use of natural gas or R-LNG, from Rs. 2.9/kWh or Rs. 5/kWh. The profit is calculated taking both the instances in consideration. However, the margins would be very low in case of the cost being Rs. 5/kWh. Generation cost for GSEG : Rs. 2.9/unit Month

Jun-08 Jul-08 Aug-08 Sept-08 Oct-08 Nov-08 Dec-08 Jan-09 Feb-09 Mar-09 Apr-09 May-09

Loss Amount (MWh)

7769.5 422 774.98 241.5 2228.7 3764.91 6476.3 11574.88 7404.7 6105.55 607.2 2039.9

Trading price (Rs./kWh)

Actual Price (Rs./kWh)

Marginal revenue (Rs. In crores)

7.66

3.76

2.921332

7.73

3.83

0.161626

7.5

3.6

0.278993

7.68

3.78

0.091287

8.46

4.56

1.016287

7.56

3.66

1.377957

6.14

2.24

1.450691

6.42

2.52

2.91687

5.62

1.72

1.273608

6.42

2.52

1.538599

10.47

6.57

0.39893

6.52

2.62

0.534454

Table 11 : Monthly profit for the period June 2008 - May 2009 (@ Rs. 2.9/kWh)

The above actual trading price includes Re.1 towards miscellaneous charges like open access charges, wheeling charges. The following graph gives the trend of the marginal revenue that could be generated by GSEG.

54 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

Figure 15 : Monthly profit for the period of June 2008- May 2009 @ Rs. 2.9/unit

Generation cost for GSEG : Rs. 5/kWh Month

Jun-08 Jul-08 Aug-08 Sept-08 Oct-08 Nov-08 Dec-08 Jan-09 Feb-09 Mar-09 Apr-09 May-09

Loss Amount (MWh)

7769.5 422 774.98 241.5 2228.7 3764.91 6476.3 11574.88 7404.7 6105.55 607.2 2039.9

Trading price (Rs./kWh)

Actual Price (Rs./kWh)

Marginal revenue (Rs. In crores)

7.66

1.66

1.289737

7.73

1.73

0.073006

7.5

1.5

0.116247

7.68

1.68

0.040572

8.46

2.46

0.54826

7.56

1.56

0.587326

6.14

0.14

0.090668

6.42

0.42

0.486145

5.62

-0.38

-0.28138

6.42

0.42

0.256433

10.47

4.47

0.271418

6.52

0.52

0.106075

Table 12 : Monthly profit for the period June 2008 - May 2009 (@ Rs. 5/kWh)

55 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

Figure 16: Monthly profit for the period of June 2008- May 2009 @ Rs. 5/unit

The above calculations show that the trading is profitable only when the generation cost is above Rs. 5/unit. Under Rs. 5/unit, the trading shows negative profit. The high cost, as mentioned above, is attributed to the use of R-LNG.

Cost Benefit Analysis Let us consider the following assumptions and data to derive a cost benefit analysis for GSEG through trading on the exchange. The analysis has been done taking into account both the generation costs. Average available trading capacity : 4117.51 MW Minimum available trading capacity : 241.5 MW (Taken into consideration while calculation) Number of Days traded : 151 Number of hours traded : 12 Total MWHrs Traded : 437,598 MWHrs4 The following table gives the total profit calculation, assuming that GSEG takes up a membership with IEX on a full payment option.

4

Total MWhr traded = volume traded*Number of days traded*Number of hours traded

56 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

1.Generation Cost

Rs. 2.9/kWh

2. Average Trading Price

Rs. 5/kWh Rs. 7.34/kWh

3. Membership cost

0.65 crores

4. Transaction cost (@ 1 paise/kWh)

0.4376 crores

5. Total generation Cost

126.903 Crores

218.799 crores

6. Total Cost (3+5+4)

127.990 Crores

219.886 crores

7. Total Revenue

321.196 Crores

8. Total yearly profit (7-6)

193.206 crores

101.31 crores

Table 13: Cost benefit Analysis for a full membership option

The above cost benefit analysis is for a trading of an average of 241.5 MW, traded for 151 days in a year, subject to the capacity that is available to trade corresponding to the average of 4117.51 MW. 1.Generation Cost

Rs. 2.9/kWh

Rs. 5/kWh

2. Average Trading Price

Rs. 7.34/kWh

3. Membership cost

0.226 crores

4. Transaction cost (@ 2 paise/kWh)

0.875 crores

5. Total generation Cost

126.903 Crores

218.799 crores

6. Total Cost (3+5+4)

128.004 Crores

219.9 crores

7. Total Revenue

321.196 Crores

8. Total yearly profit (7-6)

193.192 crores

101.296 crores

Table 14 : Cost benefit analysis for a light membership option

The above calculation is for the light membership option. Thus, from the above analysis, it can be seen that trading the extra power on the exchange is a profitable option and yields a profit of about Rs. 190 crores with a generation cost of Rs. 2.9/unit and of 101 crores with a generation cost of Rs. 5/unit. The above calculations are, however, based on the average availability of power. In actual practice, the power availability during a particular time of the day should match with the grid demand during the same time slot.

Considering the practical aspects like which time of the day power is available for sale, whether the demand exists in the grid, nomination acceptability within a short span of time and not a day ahead, 57 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

including the fact that GUVNL themselves would trade the power during high demand periods, it may be relatively difficult to sell the power. Nevertheless, exploring the option of power sale and actually trying, it can throw up the actual possibilities and the experience gained can be useful in the future.

Mix of selling options for GSEG The above analysis gives the profitability of the power sale through the exchange. However, the exchange solely cannot be used as medium of trade as the company is not a merchant plat and has a PPA that evacuates power as per demand. As mentioned above, the market system prevalent on the exchange is the Day-ahead market. This would entail the company to commit a sale quantity a day prior to the actual sale. The loss that they incur due to load restriction is not known at that earlier date. Hence, it makes the commitment of a fixed quantity a problem. Hence, the company can adopt a mix of selling options, the exchange and the UI interface. A Hypothetical Trading Proposal Let us consider a hypothetical proposal for trading, based on historical data (taken of December month for the year 2008). The daily prices traded on for the month of December is enclosed as Exhibit 4. Let us consider that the company decides to trade on December 11. Thus, it applies for a bid on December 10, as per the provisions of the DAM. The issue here would be declaring the trading amount for the next day. At the end of every day, GSEG declares the availability for the next day, the amount that they would be producing. In case GEB wants the plant to cut down the capacity, it informs the plant 15 minutes in advance. During the trading window on the 10th, the average of the past days of the month, as in from December 1 to December 9, is calculated, 175.8 MW and put up for trading. As per the daily MCP and MCV on the 10th, the time slot for between 6 pm and 7 pm showed the highest MCP. The figure 16 shows the average MCP and MCV for the past Hence, the particular time slot is bid for the next day, i.e the 11th as well. After the equilibrium price is decided, the MCP for that particular block on the 11th comes down as Rs. 9.11/kWh. Further on, there can be two cases after this.

58 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

1) The actual spare production amounts to 266 MW. Thus, the plant has an excess of capacity over the traded amount. At the MCP of Rs. 9.11/kWh, the committed 175.8 MW is traded through the exchange. For the rest of the 90.2 MW, the UI can be used. Table 14 gives the prices on the UI interface for the period of August 2008 to March 2009.

Month

Price on UI

Effective price

(Rs./kWh)

(Rs./kWh)

Aug-08

5.17

1.92

Sept-08

6.50

3.25

Oct-08

6.32

3.07

Nov-08

5.33

2.08

Dec-08

4.89

1.64

Jan-09

4.99

1.74

Feb-09

4.89

1.64

Mar-09

4.85

1.6

Table 15 : Prices for the UI interface for the period of August 2008 - March 2009

Thus, the remaining capacity can be traded at a price of Rs. 4.89/kWh. The profit that they would earn on the day of December 11th is calculated as : Generation cost

Rs. 2.9/unit

Rs. 5/unit

Medium

Exchange

UI

Exchange

UI

MCP/Price

Rs. 9.11/unit

Rs. 4.89/unit

Rs. 9.11/unit

Rs. 4.89/unit

Quantity

175.8 MW

90.2 MW

175.8 MW

90.2 MW

Profit

0.0916

0.009

0.0547

-0.01

Total profit

Rs. 0.1006 crores

Rs. 0.0447 Crores

Table 16 : Daily profit for December 11 (Hypothetical – Excess of power)

59 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

2) The actual spare production amounts to 141.08 MW. This would mean a shortage of power by 34.72 MW as per the fixed amount. The rest amount can be drawn from the UI at the prevalent rate on the grid. Generation cost

Rs. 2.9/unit

Rs. 5/unit

Medium

Exchange

UI

Exchange

UI

MCP/Price

Rs. 9.11/unit

Rs. 4.89/unit

Rs. 9.11/unit

Rs. 4.89/unit

Quantity

Sell 141.08 MW

Buy 34.72 MW

Sell 141.08 MW

Buy 34.72 MW

Profit/Cost incurred

Rs. 0.0735 crore

Rs. 0.0169 crore

Rs. 0.0438 crore

Rs. 0.0169 crore

Total profit

Rs. 0.0566 Crores

Rs. 0269 Crores

Table 17 : Daily profit for December 11 (Hypothetical - deficit of power)

Hence, in light of the above two probable cases, the above two methods can be adopted in order to trade on the exchange. In case of a known deficit a day earlier, power can be purchased from the exchange when the rates are lower. Generally, trading prices are lower on the exchange during late hours of the night, 11 pm to 12 am, and wee hours of the morning, 12 am to 5 am. The rates hover around Rs. 2/kWh to Rs. 3/kWh. Power purchased can then again reinjected into the grid during peak hours when the rates are high, generally between office hours, to give a reasonable amount of trading margin.

It would require having a continuous tab on the prices on the exchange. So that they withdraw from the exchange when the prices are sufficiently lower and then sell it back to the exchange as and when required, or more aptly, when the prices are high.

60 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

Learnings and Conclusions Findings On the basis of the data collection and analysis; the following issues of findings come into view. 1) GSEG has costlier power as compared to many other from the pool of sellers to GEB. 2) As a result, the plant suffers load restriction losses to a higher extent of 11% of the total losses incurred. 3) Thus, with the plant not operating at optimum capacity, it leads to a loss of probable revenue for the plant. 4) Considering the company decides to trade on the exchange, with the power cost amounting to Rs. 5/kWh and Rs. 2.9/kWh and the trading price being near Rs. 7.433 (average), the profit per unit fluctuates between Rs. 2.433/kWh and Rs. 4.5333/kWh. Thus, this leads to a fluctuation of average monthly profit from Rs. 0.29 crores to Rs. 1.16 crores, taking the data of the past year, both loss and trading prices. Taking into account the fixed costs like the membership fee and the variable transaction costs, the yearly profit also fluctuates from Rs. 190 crores to Rs. 101 crores. This analysis is based on the availability of power on an average basis. 5) Considering the practical aspects like which time of the day power is available for sale, whether demand exists in the grid, nomination acceptability within a short span of time and not a day ahead , including the fact that GUVNL would themselves trade the power during high demand periods , it may be relatively difficult to sell the power. Nevertheless, exploring the option of power sale and actually trying, it can throw up the actual possibilities and difficulties and the experience gained can be useful in the future.

Recommendations On the basis of the surfacing of the above issues, the following recommendations are suitable : 1) Finding an alternate platform for the sale of the ingenerated power, via the exchange. 2) Depending on the demand of the power that is of concern, the full membership or the light membership might be opted for. 3) During the course of time, as the company gains experience in trading with the exchange, it can also extol the option of becoming a Client and trading on the behalf of other entities, adding to the source of revenue.

61 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

Action plan The following steps need to be undertaken in order to initiate trading with the exchange. 1) A detailed analysis of the time availability of power, the demand at that time and the price can be undertaken for further working out the possibility of power sale. 2) Depending on the quantum of power available to trade, in relation to the load restriction losses, compilation of the entire power, the ratio of the power that is to be traded, the number of hours for which trading has to take place, determining the time block during which the exchange prices are high enough and to generate maximum revenue as well as be feasible enough to ensure sale of type of power in hand. 3) Application to be enlisted in, taking into account the amount of power that the company intends to trade. 4) Provision of adequate manpower to facilitate trading on the exchange. A special requirement by the Exchange is the presence of the ABT meter and a standing clearance from the SLDC for trading, which needs to be acquired.

Contingencies The following problems could crop up in the action plan; 1) Lessening and blocking of the load restriction losses. The former discrepancy could lead to the locking in of the membership fee and stopping of funds from trading. However, the company would generate revenue from its sale to GEB for the concerned losses. Meanwhile, the company can choose to transfer or surrender their membership after a period of three years, in compliance with the terms of the exchange. The losses that would occur in the process would be, 1) Membership fee The other payments to the exchange are either adjusted or refundable. Even in the case of the lowest amount of power sold to GEB, 241.5 MW earning revenue of Rs. 60375, depending on the membership being full or light, the fee would be recovered within a period of 8 years to 3 years, respectively.

62 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

Exhibits

Exhibit 1 : Area of operations of the leading exchanges in Europe

Exhibit 2 : Diagrammatic representation of a Combined Cycle Power Plant

63 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G

Availability

Natural Gas

LNG

Depends on natural Gas finds

Depends on Development of LNG projects

Flexibility in operations High Infrastructure

High

Gas pipeline network available

Gas Linkage Committee Environmental options Cleaner fuel

No issues

Medium Construction Rank based on the cost 1 of generation

High 2

Regulatory

Cleaner fuel

Imported coal No problem

Domestic coal Abundant mine development A probable issue

Needs to be operated as a base load plant With few start and stops Close to port Close to railway line, For a captive jetty, Land and Abundant water Abundant water needed Imported under OGL Coal Linkage Committee Better than Ranks least Domestic coal High Low 3 4

Exhibit 3 : Relative comparison of four fuel alternatives

Exhibit 4 : Hourly MCPs for the month of December, 2008

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Bibliography Pandey, V. (2007, November). Electricity Grid Management in India - An Overview. 'Electrical India' Vol 47 No 11 . Soonee, S., Narasimhan, S., & Pandey, V. (2006). Significance of Unscheduled Interchange Mechanism in the Indian Elecricity Supply Industry. Department of Electrical Engineering, ITBHU . Srivastav, S. (2009, May). Facets of the working of the Power Exchanges. (S. Saxena, Interviewer)

65 | S e l l i n g O p t i o n s f o r R e s t r i c t e d C a p a c i t y o f G S E G