An Assessment of Price Discovery Mechanism for Power

8/8/2019 An Assessment of Price Discovery Mechanism for Power

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EXECUTIVE SUMMARY

With the enactment of the Electricity Act, 2003 the transaction involving purchase and

sale of electricity has been recognized as a distinct licensed activity. This has been

termed as trading and defined in section 2(71) of the Act as purchase of electricity for

resale thereof. The Regulatory Commissions have been given the powers to grant

trading license.

It has been mentioned in EA 2003 that the price of traded electricity should be

determined competitively. In order to increase the trading volume and provide a

common platform for power trading, CERC has taken an important step by planning to

create a power exchange.

For any power exchange the most important and critical part is its price discovery

mechanism. The efficiency and transparency of operation depends upon the price

discovery mechanism. The price discovery mechanism involves two major aspects:

1) Bidding methodology

2) Pricing philosophy

The bidding can be done in two ways:

Supply Side Bidding

Double Side Bidding

In supply side bidding, the price bids are submitted by only the suppliers. There are no

demand side price bids. From the bids submitted, aggregate demand and supply curves

are drawn and the point of intersection of the supply and demand curves gives the


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market clearing price (MCP). The process is called as market clearing. The volume

corresponding to the MCP is the market clearing volume.

In case of double side biding the difference is that the consumers also submit the price

bids. The market clearing price is same as above.

The pricing for the suppliers can be done in two ways:

Uniform Pricing

Discriminatory Pricing

In uniform pricing all the suppliers are paid by the MCP while in discriminatory pricing

the suppliers are paid by the price they submitted in the bids.There can be four options for pricing mechanism:

1) Supply Side Bidding with Uniform Pricing

2) Double Side Bidding with Uniform pricing

3) Supply Side Biding with Discriminatory Pricing

4) Double Side Biding with Discriminatory Bidding

Each mechanism has its advantage and disadvantage. In the report the analysis for each

option is shown through four cases.

The first chapter gives the introduction of the project. Second chapter gives a view of

markets operating around the world. Third chapter compares the Indian electricity

market with the world electricity markets operation. Last two chapters show the analysis

through four cases.

The analysis tries to compare the methodologies and suggest the appropriate pricing

methodology for power trading in India.


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TABLE OF CONTENTS

CHAPTER PAGE NO.

EXECUTIVE SUMMARY iii

LIST OF TABLES viii

LIST OF FIGURES ix

1. INTRODUCTION

1.1. Overview 1

1.2. Electricity Act 2003 & Trading of Electricity 11.3. Existing power Supply and Trading Scenario 2

1.4. Open Access 3

1.5. Prices of Traded Electricity 5

1.6. Transmission System 6

1.7. Purpose of the Study 7

1.7.1. Objectives 7

1.7.2. Scope 8

2. WORLD ELECTRICITY MARKETS

2.1. Introduction 9

2.2. Nord Pool 11

2.3. PJM 15

2.4. Californian Experience 20

3. INDIAN ELECTRIICTY MARKET VIS--VIS WORLD

ELECTRICITY MARKETS

3.1. Introduction 22

3.2. Open Electrical Energy Markets 22

3.2.1. Bilateral Trading 23


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3.2.1.1.Long Term Contracts 23

3.2.1.2.Trading Over the Counter 23

3.2.1.3.Electronic Trading 24

3.2.2. Electricity Pools 24

3.3. Availability Based Tariff (ABT) in India 25

3.4. Comparison of Installed Capacity 27

4. ANALYZING BIDDING AND PRICING METHODOLOGIES FOR

POWER TRADING IN INDIA

4.1. Introduction 28

4.2. Supply Side Bidding Vs Double Side Bidding 29

4.2.1. Assumptions 294.2.1.1.Bid Volume 29

4.2.1.2.Distribution of Bid Volume 30

4.2.2. Supply Side Bidding: Case 1 31

4.2.2.1.Supply Bids: Case 1 31

4.2.2.2.Aggregate Demand and Supply: Case 1 32

4.2.2.3.Market Clearing: Case 1 33

4.2.2.4.Generation Volume Allotment: Case 1 34

4.2.3. Supply Side Bidding: Case 2 35

4.2.3.1.Supply Bids: Case 2 35




4.2.3.5.Result: Supply Side Bidding 38

4.2.4. Double Side Bidding: Case 3 39

4.2.4.1.Double Side Bids: Case 3 40




4.2.5. Double Side Bidding: Case 4 44


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4.2.5.1.Double Side Bids: Case 4 44




4.2.5.5.Result: Double Side Bidding 48

4.2.6. Result: Supply Side Vs Double Side Bidding 49

4.3. Uniform Pricing Vs Discriminatory Pricing 50

4.3.1. Uniform Pricing 50

4.3.2. Discriminatory Pricing 51

4.3.3. Result: Uniform Vs Discriminatory Pricing 52

5. SELECTING A PRICE DISCOVERY MECHANISM FOR POWERTRADING IN INDIA

5.1. Price Discovery Mechanisms 53

5.2. Option 1: Supply Side Bidding with Uniform Pricing 54

5.3. Option 2: Supply Side Bidding with Discriminatory Pricing 55

5.4. Option 3: Double Side Bidding with Uniform Pricing 56

5.5. Option 4: Double Side Bidding with Discriminatory Pricing 57

5.6. Result and Conclusion: Viable Option for India 58

APPENDIX I: FUNCTIONAL DIAGRAM OF PX PROPOSED BY CERC 59

APPENDIX II: ORGANIZATION OF PROPOSED PX 60

REFERENCES


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LIST OF TABLES

TABLE PAGE NO.

Table 1.1 Planned interregional transmission capacity 7

Table 4.1 Generation Statistics 30

Table 4.2 Bid Volume 30

Table 4.3 Case 1: Demand-Supply Bids 31

Table 4.4 Case 1: Aggregate Demand & Supply 32

Table 4.5 Case 1: Generation Volume Allotment 34



Table 4.8 Case 2: Generation Volume Allotment 38Table 4.9 Supply Side Bidding: Market Clearing 38

Table 4.10 Supply Side Bidding: Generation Allotment 39







Table 4.17 Double Side Bidding: Market Clearing 48

Table 4.18 Double Side Bidding: Generation Allotment 48

Table 4.19 Supply Side Vs Double Side Bidding 49

Table 4.20 Uniform Pricing: Revenue of Generators 50

Table 4.21 Discriminatory Pricing: Revenue of generators 51

Table 4.22 Result: Uniform Vs Discriminatory Pricing 52

Table 5.1 Option 1: Supply Side Bidding with Uniform Pricing 54

Table 5.2 Option 2: Supply Side Bidding with Discriminatory Pricing 55

Table 5.3 Option 3: Double Side Bidding with Uniform Pricing 56

Table 5.4 Option 4: Double Side Bidding with Discriminatory Pricing 57

Table 5.5 Viable Option for India 58


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LIST OF FIGURES

FIGURE PAGE NO.

Fig. 1.1 Increase in traded volume of electricity 3

Fig 1.2 Price trend of traded electricity 6

Fig 4.1 Market Clearing: Case 1 33

Fig 4.2 Market Clearing: Case 2 37

Fig 4.3 Market Clearing Case 3 42

Fig 4.4 Market Clearing Case 4 46


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CHAPTER 1: INTRODUCTION

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1 INTRODUCTION

1.1 Overview

The electricity sector in India is undergoing fundamental transformation of its

institutional structure particularly after the enactment of Electricity Act, 2003. Vertically

integrated SEBs are giving way to unbundled institutions that are conducive to

competition.

The objective for creating competitive electricity market is to unleash market forces to

improve efficiencies, stimulate technical innovations and promote investments. Creation

of electricity market can bring economic benefits for consumers and societies in the long

run.

1.2 Electricity Act 2003 & Trading of Electricity

Prior to the Electricity Act, 2003, the electricity industry recognized generation,

transmission and supply as the three principal activities, and the legal provisions were

also woven around these concepts. Bulk purchase and sale, although a regular

phenomenon between State Electricity Boards and/or licensees was construed as part of

the activity of supply of electricity.

It is only with the enactment of the Electricity Act, 2003 that the transaction involving

purchase and sale of electricity has been recognized as a distinct licensed activity. This

has been termed as trading and defined in section 2(71) of the Act as purchase of

electricity for resale thereof. The Regulatory Commissions have been given the

powers to grant trading license.


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Recognition of trading as a separate activity is in sync with the overall framework of

encouraging competition in all segments of the electricity industry. The entry barriers

have been sought to be removed and the State Electricity Boards have been mandated to

be reorganized within a definite time frame. This is expected to result in multiplicity of

players in generation, transmission and distribution, a sine qua non for competition. In

such a scenario, traders are expected to add value by facilitating the transfer of surplus

power available in one region to the regions experiencing deficit of supply.

1.3 Existing Power Supply and Trading Scenario

Bulk electric power supply in India is mainly tied in long-term contracts. The bulk

suppliers are mostly the central or state owned generating stations, as also a few IPPs.

Previously the bulk buyers were generally the SEBs, which are in the process of being

unbundled. The power allocations from various generating stations are being assigned to

Discoms as part of the unbundling process mandated by the Electricity Act, 2003. The

Appropriate Commission regulates the price of bulk supply of a generating station todistribution utilities on the basis of its Terms and Conditions of Tariff or as per the PPA.

Thus, most of the existing bulk supply is locked up in long terms contracts having

station wise tariff, usually in two-parts viz. capacity charge and energy charge.


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Fig 1.1 Traded Volume

1617

4178

1102911847

14188

0

2000

4000

6000

8000

10000

12000

14000

16000

FY 02 FY 03 FY 04 FY 05 FY 06

MU

Series1

The SEBs/Discoms who have the obligation to provide electricity to their consumers

mainly rely on supplies from these long-term contracts. However, it is neither feasible

nor economical to meet short term, seasonal or peaking demand through long-term

contracts. Be it a deficit scenario or otherwise, power trading is essential for meeting the

short terms demand at an optimum cost. Similarly, power trading is essential for

distribution utilities for selling short-term surpluses in order to optimize the cost of

procurement. A few captive generating plants participate in trading in order to optimize

their operating cost and in the process, supply electricity to the grid.

1.4 Open Access

The Open Access Regulations and Inter-State Trading Regulations of the Central

Commission have facilitated power trading in an organized manner. Today, it is possible

to trade electricity between any two points in India through inter-State Open Access on

advance reservation basis, on current reservation basis, on day ahead basis and even on

Fig 1.1 Increase in traded volume of electricitySource: Power Trading Corporation website


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real time basis. Transmission charges for trading are applied on Rs./MW/Day basis. For

reservation of less than 12 hours, part day charges are applied as per rules. Open Access

charges are transaction specific depending on the regions/transmission systems involved

between point of injection and point of drawl. At present, power is mostly being traded

between power surplus distribution utilities in Eastern Region (ER) and Northeastern

Region (NER) on one-hand and deficit utilities in Northern Region (NR) and Western

Region (WR) on the other.

Annual volume of electricity traded through open access route is of the order of 12-13

BU constituting about two percent of the total energy availability. In terms of power, the

magnitude of all India short-term bilateral trade is in the range of 1000 to 1500 MW

compared to installed capacity of 1,24,827 MW. According to CEA estimates the all

India peaking shortage during 2005-06 was 11,463 MW (12.3%). The availability of

power for trading peaks during monsoon and bottoms out during winter. Gridco,

WBSEB, DVC, Tripura Electricity Department, HP Government, Malana Hydro Power

Station, Jindal Tract etc. are among the notable suppliers.

The bilateral trading going on at present is mostly between SEBs/Discoms. It is either

through a trader as a counter party or direct. Some of the trading is taking place on barter

basis. The power trading agreements are mostly inter-state or inter-regional, requiring

Open Access through the CTU network. The Open Access Regulations have been

amended to suit the needs of the trade. The Open Access charges are reasonable and

simple to apply, and not a single payment dispute or default has been reported to the

Central Commission so far. However, power trading agreement and Open Access

approvals cannot be concluded separately.


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A couple of years ago, in the initial phase of power trading, the price was settled through

mutual negotiations. Now days, the sellers invite bids to which traders generally

respond. The trader with highest bid price is selected, who in turn sells this power to a

needy buyer after adding his trading margin. In a shortage scenario, when the buyers

invite bids, only such traders can respond who have already won a supply bid. In this

manner, the buyer is left with little choice but to buy at a price already committed by the

trader to a seller.

1.5 Prices of Traded Electricity

The term electricity market in the Indian context usually refers to this kind of bilateral

trading where the price is based on the value attached by the buyer to electricity as a

commodity and his willingness or capacity to pay that price.

Prices of electricity in the bilateral market have shown consistent upward trend as

depicted in the graph below. It is indicative of increasing shortages and reducing

elasticity of demand as result of economic development and growing population. The

buying utilities are not satisfied with the way bilateral trading is going on, and they

strongly feel that something should be done to arrest the trend of rising prices in the

electricity market. Some of the buyers utilities feel that the sale prices should be

capped.


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1.6 Transmission System

There is adequate inter-state transmission system for wheeling power contracted on

long-term basis. The magnitude of traded power is low and the available spare capacity

of the inter-state and inter-regional transmission corridors is able to cater to the need of

trading most of the time. Transmission congestion occurs occasionally, mostly on the ER

NR link. With the commissioning of Tala Transmission Project in 2006, the ER-NR

capacity would increase substantially. However, constraints may be experienced on the

ER-WR and ER-NR links.

Fig 1.2 Price trend of traded electricitySource: CERC website


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Corridor Transmission capacity

At the end of 10th plan

(end of 2006 07 )

MW

Transmission capacity

At the end of 11th plan

MW

ER-SR 3600 3600

ER-NR 5000 8500

ER-WR 2800 8500

ER-NER 1250 2250

NR-WR 2100 7600

WR-SR 1700 2700NER-NR - 4000

TOTAL 16, 450 37, 150

Table 1.1 Planned interregional transmission capacity

Source: Central Electricity Authority website

1.7 Purpose of the Study

For any power trading market the most critical part is the price discovery mechanism

followed to determine the price at which the trading takes place.

The purpose of the study is to analyze the price discovery mechanisms followed in the

world electricity markets and find the suitability of the same in the Indian perspective.

1.7.1 Objectives

To study and compare the world electricity markets to Indian electricity market


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To analyze the applicability of different price discovery mechanisms for power

trading in India

To suggest a suitable price discovery mechanism for power trading in India

1.7.2 Scope

The scope of the study is limited to short term trading through power exchange as

envisaged in the Electricity Act 2003.


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CHAPTER 2: WORLD ELECRTICITY MARKETS

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2 WORLD ELECTRICITY MARKETS

2.1 INTRODUCTION

Long term PPAs or Forward Contracts provide price security to buyers as well as

suppliers. In order to cater to the demand variations, it is also necessary for distribution

utilities to look for short-term contracts. Short-term arrangements could be of few

months to few hours. Open Access facilitates short-term contracts by providing the

transmission path. Traders chip in with their matchmaking skills and ability to secure

payments.

In short-term contracts, the price of electricity tends to reflect the economic price for

time of the day or time of season. Handling and dispatching large number of short term

contracts of varying durations is a challenging task for the system operators who have to

all the time maintain the demand-supply balance in order to ensure grid stability.

Under such circumstances, a situation evolves when it becomes desirable to organize the

trading of electricity through a market operator. Apart from devising ways and means of

organizing the electricity trade, the market operator has to enter into institutional

arrangements with the system operator for facilitating physical flow of electricity from

the suppliers to the buyers, and on the other hand with a clearing house for facilitating

cash flow from the buyers to the suppliers. If the market operator organizes the

generation and sale of the entire electricity of one area, it is usually referred to as a pool.

If the market operator caters only to voluntary trade, it is said to be a Power Exchange.

(PX) The impact of PX on market is gradual. PX volume grows as supplies increase and

buyers develop confidence in PX. Slowly, long term PPAs give way to day ahead trades


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through PX. In a centrally dispatched power pool, the market operator is responsible for

matching the supply with the demand of various participants. In some markets, each

participant is responsible to balance his demand with requisite supply and has to

commercially settle all real time deviations from the given schedules as per the agreed

pricing scheme. This is known as self dispatched market. In this sense, we have self-

dispatched system under the ABT regime, and deviations from schedules are settled as

per UI pricing mechanism.

In centrally dispatched markets, only generators/suppliers are asked to bid and the stack

of supplies is selected to the extent required to meet the forecast demand. The buyers are

not required to participate, as the underlying philosophy is that forecast demand has to

be met as far as possible.

In distributed markets, there is a clear separation between the market operator and the

system operator, and suppliers as well as buyers are asked to participate in bidding. This

enables the buyers to calibrate their demand according to their price sensitivity and

under take demand side managements in the process. Each buyer gets quoted quantity at

the corresponding price quoted by him.

In all organized markets, the bids are sought in pairs of quantity and price. In double

sided bidding, it is possible for a participant to dispose as a buyer or a supplier

depending on the clearing price. For example, a utility may offer to buy 100MW at a

price below Rs 3.00 per unit, but if the clearing price is in excess of Rs 5.00 per unit it

may be viable to start its own costly generation and sell a part there from, say 50 MW, to

the Power Exchange. Eventually, if the clearing price is below Rs. 3.00 per unit, the


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utility would be supplied 100 MW, and in case the clearing price is Rs 5.00 per unit the

utility would be dispatched for 50 MW as a supplier.

The first serious attempt to form a liberalized electricity market was launched in Chile in

1982. Markets were launched in England and Wales in 1990. Nordic market, now known

as Nord Pool, was started in 1991. Electricity markets started operating in Australia and

New Zealand in 1994 and 1996, respectively. In North America, several markets were

started in the late 1990s, such as PJM, New England, New York and California markets.

Spain and Netherlands opened their electricity markets in 1998.

2.2 Nord Pool

The electricity reforms were initiated in Norway in 1991. Nordic power exchange was

established as an independent company in 1993. It established price quotation on a day-

ahead basis and it established the worlds first exchange-based trade with futures

contracts in 1993.

Swedish electricity market unbundled in 1996. Thereafter, a common electricity

exchange for Norway and Sweden was established under the name of Nord Pool.

Finland also completed the electricity reforms by 1996. Two private electricity

exchanges were established in Finland in 1995 and they merged into one entity in 1996.

However, even the merged exchange did not have sufficient liquidity.

In 1998, Finland effectively entered into Nordic Market. Denmark joined Nord Pool

subsequently. Nord Pool was reorganized in 2002. It is still owned by the Transmission

System operators (TSO) of Norway and Sweden. Nord Pool provides freedom of choice

to the large consumers. Close cooperation between the system operation and market


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operation is the key feature of Nord Pool. The day-ahead spot market orgainsed through

Nord Pool is the cornerstone of the Nordic Electricity market. Demand bids and supply

offers must be submitted to Nord Pool by 12:00 noon for the following day. Marginal

bids and offers that determine the balance between supply and demand sets the price for

the entire market. Considerations regarding fixed cost are not taken into account in the

market clearing but market players have various opportunities to submit block-bids.

Block-bids enable generators to make a bid conditional for block of hours instead of

only one.

Nordic TSOs give Nord Pool PX a monopoly to use all available transmission capacity

that interconnects the defined areas or zones in the Nordic market. Currently there are

three zones in Norway, but they can change in case of frequent congestions in other

places. Sweden and Finland constitute one zone and Denmark has two zones. All

network companies are responsible for assessing and purchasing electricity resulting

from grid losses. Hence, grid losses are reflected in the zonal prices through normal

demand bids in the spot market. Nord Pool also calculates a system price assuming that

there are no constraints in the entire Nordic transmission system. This is purely a

reference used in the financial market and do not necessarily exact prices in the various

market zones.

Initially, some interconnection capacity was reserved for long-term contracts. The last of

these reservations was removed in 2000. The transmission capacity made available to

Nord Pool, as announced during the morning before day-ahead bids, is guaranteed by the

TSOs. This implies that the transmission right is firm. In real time, the TSOs have to

modify dispatches in order to overcome any transmission constraints. They have to do so


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at their own cost. Conversely, available transmission capacity is also a source to collect

congestion rents, which is used by the TSOs for various purposes and finally to reduce

transmission tariffs. The hourly Nord Pool schedules are binding in the sense that market

players are financially responsible for their fulfillment. All market players with a

physical footprint in terms of generation, load or trade after the scheduling deadline are

required to register as balance-responsible market players. They must sign the contract

with the TSOs in the zone in which they want physical footprint, through this contract

they become physically responsible for deviations and are bound to follow the specified

rules and formats for communication with that TSO.

After submitting schedules to the respective TSO, the framework for handling

imbalances deviates somewhat from country to country. Nordic TSOs operate balancing

market in which they buy and sell electricity to balance the system according to the merit

order of bids submitted by the market players to TSOs. Prices for real-time are

determined by the marginal bid, as is the case in the day-ahead spot market. Individual

imbalances that, by chance (such as underdrawal), are actually helping the system are

treated differently in different Nordic countries. In Norway, the imbalances that help the

system by chance are also rewarded with the same price and are, thereby, treated equally

with the market players that were actively called on in the purchase of balancing power.

This pricing principle is referred as the single-price system and is cost neutral. Market

players that caused the imbalance pay to those that alleviated the imbalance.

In Sweden, Finland and Denmark, the balance-responsible market players that helped the

system by chance are not rewarded. Their imbalances are settled with the day-ahead spot

price, which always gives an equal or poorer remuneration than the price settled in the


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purchase of balancing power. Otherwise, there would be an incentive to make arbitrage

between the two markets. Thus, balance-responsible market players that caused the

imbalance pay the settled regulating price to the TSO and the TSO passes this price on to

those that were actively called on. In reality, they are settling imbalances of those that

helped the system by chance at a less favourable price. This pricing principle is referred

to as the dual-pricing system and is not cost neutral. In fact, it generates surplus for the

system operator. Imbalances are settled at the cleared regulating prices, usually one or

two weeks after the day of operation. Local network companies collect hourly interval

meter readings on a daily basis. These are matched with schedules to calculate individualimbalances. All Nordic countries have implemented the system for load profiling for the

smallest consumers, primarily to avoid the need to have them install remotely read

interval meters.

Nord Pool PX has a market share of 43% of the physical Nordic demand; the remaining

57% is traded bi-laterally. This could be thought of as bilateral physical trade but, in

realty, it mainly reflects that several generators also have retail arms, and therefore,

demand and generation are matched directly within the company. Nord Pool also

operates a trading platform for financial derivatives as well as clearing house for bi-

lateral contracts. Nord Pool offers futures contracts for one to nine days ahead and for

one to six weeks ahead in time. These futures contracts are settled daily. All these

futures and forward contracts use the daily average system price as reference. There are

also contracts to hedge zonal price differences, either one quarter or one year ahead.

In 2004, total installed capacity in Nordic market was about 91000 MW including

47000 MW Hydro (mostly storage type), 23000 MW Thermal capacity (mostly coal


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based) and about 12000 MW Nuclear generating capacity. The inter-connector capacity

between Norway and Sweden is 3620 MW over nine different AC lines. Sweden and

Finland are interconnected with 2230 MW over five AC lines. Sweden and Denmark

east are interconnected with 1810 MW over four AC under marine cables. Sweden and

Denmark west are interconnected with 670 MW DC cables. Norway and Sweden are

interconnected with 1000 MW sub-sea DC connection. Norway and Finland are

interconnected with single 100 W AC line. Nordic market in turn is also interconnected

with neighbouring markets of Germany, Poland and Russia.

The four largest generating companies in the Nordic market are Vattenfall, Fortum,

Statkraft and E. ON Sweden. Vattenfall has a market share of 19% in terms of output.

Vattenfall is owned by the Swedish State. The other large generating company, Fortum

had market share of 16% in 2001 and it is 60% owned by the State of Finland. No other

company held more than 4% of the market in 2001. In Norway, 160 companies are

engaged in electricity generation; the 15 largest had 88% market share of Norway. In

Sweden, 15 large generators have market share of 94% of the domestic generation. In

Finland, 15 large companies have a market share of 95%. In Norway, there are about

100 retail companies; in Sweden and Denmark, the corresponding number is 80.

2.3 PJM

The Pennsylvania New Jersey Maryland interconnection (PJM) has been a pool that

enables co-ordination of trade between the three founding utilities since 1927. Prior to

1978, the United States electricity industry was run by vertically integrated utilities, in

most cases privately owned. These companies were regulated by the state public utilities


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commissions (PUCs). On the federal level, the Federal Energy Regulatory Commission

(FERC) has authority only over wholesale trade issues. In 1978, environmental friendly

small generators were allowed access to the grid through contracts corresponding to

avoided costs. A number of independent power producers (IPPs) came up primarily in

those States where the vertically integrated utilities were encouraged to auction least cost

contracts to IPPs to obtain the needed power. The Energy Act of 1992 gave the FERC

authority to order open access for wholesale trade between utilities and across state

borders. PJM started to transform itself into an independent, neutral organization in

1993. The FERC Order 888 on Open Access was issued in 1996 calling for functionalunbundling of transmission system operation from power trading.

Transmission utilities under FERC jurisdiction had to provide nondiscriminatory open

access to third parties on a comparable basis on the same terms & conditions as

applicable for self-use of the utilities. In 1999, FERC issued order 2000, which

encourages the merger of ISOs (Independent System Operator) into Regional

Transmission Organization (RTO). In Sept. 2001, FERC made several proposals to

encourage standardization of market design and push for the formation of RTOs. FERC

issued a White Paper in April 2003 with a refined version of Standard Market Design.

However, the proposal did not materialize due to resistance by the States and was

withdrawn in 2005. The Energy Act of 2005 gives FERC more authority in the matters

of system security and in the approval process of new transmission infrastructure and to

monitor and enforce competitive behavior in wholesale market. The Energy Act, 2005

indicates that the development towards competitive and open electricity market should

be supported, but not forced on all States.


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PJM became a fully organized market in 1997, and was approved by the FERC as the

first ISO in the country to be in compliance with Order 888. PJM is responsible for safe

and reliable operation of the unified transmission system and for the management of a

competitive wholesale electricity market across the control areas of its members. PJM

was given full RTO status in 2002.

The first years of PJM operation were used to establish and develop the market. The

initial day-ahead spot market was based on a single market-clearing price for the entire

region. High costs for congestion management and poor operational flexibility in the

utilization of the system due to security restriction called for a stronger locational

reflection of real costs. One year later, Locational Marginal Pricing (LMP) was

introduced. In 1999, a daily capacity market was introduced and in June 2002 the day-

ahead market was extended by the real time market, also based on LMP and competitive

bidding. In December 2000, a market for spinning reserves was added. With the

implementation of LMP principles in 1999, there appeared a need to offer hedging of

price differences between nodes. In April 1999, PJM introduced an auction of allocated

financial transmission rights (FTRs), which gave market participants the opportunity to

hedge the risk. In May 2003, the FTRs were replaced with auction revenue rights

(ARRs). The PJM market operation area has been extended to include West Virginia,

Ohio, North Carolina etc.

All generators defined as a capacity resource in PJM system are obliged to submit an

offer into the day-ahead PJM market. The bus that connects a generator to the grid is

specified when registering. Offers can include incremental prices, specifying different

prices at different generation volumes. They can also specify minimum run times and


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start-up costs to ensure that unit commitments are incorporated into the market-clearing

price. Market participants are allowed to self schedule. On the generator side this is

accounted for by indicating that a specific share of a generation unit must run regardless

of the price. An offer specifying that a unit must run is basically just a schedule that

commits the generator financially. Retailers and consumers must submit bids to the day-

ahead spot market. They can do it by bidding prices and volumes, if they intend to

respond to the price by decreasing demand, or they can do it without specifying any

price.

Reliability and transmission system security considerations are taken into account in the

total market clearing. A marginal pricing principle is used. Each generator is paid market

clearing price in its specific node. All loads are charged the market-clearing price in their

specific nodes. In 2004, 26% of the load was cleared in PJM day-ahead market. The

remainder was generation offer submitted as must run, meaning it was self-scheduled.

Most of the States in PJM have ordered retail access for all consumers.

In 2004, the demand peaked at 78,000 MW. Assessed peak demand after the extensions

in 2005 is 1,30,000 MW and the energy demand was of the order of 700 TWH. The total

population area was about 51 million across 13 states. The total load was served by

installed capacity of 1,44,000 MW in 2004 including 41.5% coal fired, 28.4% Natural

Gas fired, 19% Nuclear, 7% oil and 3.7 Hydro Electric. By the end of 2003, American

Electric Power Company was the largest generation company in PJM, owning 17% of

the total installed capacity and generating 22% of the output. Exelon was second with

13% of installed capacity and 23% of the total generation. Public Service Enterprise

Group (PSEG) had 9% of installed capacity and 6% of energy generation.


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PJM Interconnection is a limited liability, non-profit company, governed by a board of

managers. Members of the board of managers must have no personal affiliation or

ongoing professional relationship with or any financial stake in any PJM market

participant. Users of PJM join as members and are represented with a vote in the

members committee. The members committee elects a board of managers and provides

advice to this board by proposing and voting on changes in market rules; it also has

authority to make specific recommendations. There are other committees and user

groups for resolution of issues through discussion and negotiation. Market rules and

market design issues are often developed through these governing structures.

There is a specific unit within PJM to oversee the functioning of the market; the Market

Monitoring Unit (MMU). The MMU is an independent group that assesses the state of

competition in each of PJM markets, identifies specific market issues and recommends

potential enhancements to improve competitiveness and market efficiency. In particular,

the MMU is responsible for monitoring the compliance of members with PJM market

rules and for evaluating PJM policies to ensure those rules remain consistent with the

operation of competitive market. The MMU issues an annual report on the state of the

market. State regulators, together with a federal regulator, oversee compliance of state

and federal legislation. States have public utility commissions (PUCs) and the Federal

Energy Regulatory Commission (FERC), which is an independent agency within the

Department of Energy, regulates on those areas in which federal legislation gives it

authority. PUCs regulate intra-state utility business, such as generation and distribution.

The FERC regulates interstate energy transactions, including wholesale power

transactions on transmission lines.


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2.4 Californian Experience

California experienced energy crisis during spring 2000 until spring 2001 that led to sky

rocketing natural gas and electricity whole sale prices which culminated in the massive

regional energy shortage. While demand grew by 5500 MW between 1996 and 1999, the

generating capacity increased by 672 MW over the same period. On top of it, retail

prices were fixed and there was no reason for retail customers to moderate their

consumption. The situation was compounded by poor hydro conditions and abnormally

hot weather leading to high air conditioning load. Further, some old plants could not

operate because they did not have emission credits. In addition, import from

neighbouring States became problematic due to increase in local demand in the

respective States. Moreover, the period saw large increase in natural gas prices, which

was the fuel of choice for peaking power plants. The crisis culminated into rotational

load shedding. Market design flaws also played part in the California crisis and they are

relevant for our discussion on power exchange. The following flaws have been ascribed:

Freeze on retail prices

Restriction placed on long term contracts

Faulty design of day ahead and balancing markets

The California market was organized through a power exchange (CalPX) and an

independent system operator (CAISO). The power exchange ran a day-ahead market

using one-sided bidding for each hour with a marginal clearing price system. The power

exchange was mandatory for the demand and supply for investor-owned-utilities. The

power exchange handled 85% of the volume of day-ahead transactions. Investor-owned-


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utilities were forced to divest much of their fossil-fuel based power plants and not

permitted to sign multi-year contracts to buy part or all of the output from the plants they

had just sold. Due to this prohibition, the distribution companies were required to buy

almost all the power they needed from the power exchange and on real time market run

by CAISO. Companies other than the investor-owned-utilities were, however, allowed to

form their own markets, called the scheduling coordinators.

Some of the traders took advantage of flaws in the California market design to maximize

their profits. The strategies used were:

i. Arbitrage between Real-time and Day-ahead markets by buying power from the

PX, exporting it to a party in neighboring countries, and importing it back to sell

the energy to the ISO market where no price caps are in place.

ii. Scheduling transactions on a transmission line already out or full and receiving

payment for being rejected.

iii. Artificially creating congestion and getting paid for relieving it.

iv. Arbitrage between transmission pricing system by simultaneously scheduling a

transaction from A to B and from B to A.

v. Arbitrage between location by buying in California day-ahead and selling outside

California when prices outside California exceed the price cap of the day-ahead

market.


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CHAPTER 3: INDIAN ELECTRICITY MARKET VIS--VIS WORLD ELECTRICITY MARKETS

- 22 -

3 INDIAN ELECTRICITY MARKET VIS--VIS WORLDELECTRICITY MARKETS

3.1 Introduction

It is currently not economical to store large quantities of electrical energy; this energy

must be produced at pretty much the same time as it is consumed. Trade in electrical

energy, therefore, always refers to a certain amount of megawatt-hours to be delivered

over a specified period of time.

The length of this period of time is typically set at an hour, half an hour or quarter of an

hour depending on the country or region where the market is located. Since electrical

energy delivered during one period is not the same commodity as electrical energy

delivered during another period, the price will usually be different for each period.

Demand, however, does not change neatly at the beginning of each period. Some

adjustments in production must therefore be made on a much shorter basis to keep the

system in balance.

3.2 Open Electrical Energy Markets

The electricity markets in different countries broadly operate in following two ways:

1) Bilateral trading

Long term contracts

Trading over the counter

Electronic trading

2) Electricity pools


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Day ahead market

Balancing market (spot market)

3.2.1 Bilateral Trading

As its name implies, bilateral trading involves only two parties; a buyer and a seller.

Participants thus enter into contracts without involvement, interference or facilitation

from a third party. The essential characteristic of bilateral trading is that the price of each

transaction is set independently by the parties involved. There is thus no official price.

Depending on the amount of time available and the quantities to be traded, buyers and

sellers will resort to different forms of bilateral trading:

3.2.1.1 Long Term Contracts

The terms of such contracts are flexible since they are negotiated privately to meet the

needs and objectives of both parties. They usually involve the sale of large amount of

power over long periods of time. The large transaction costs associated with the

negotiation of such contracts make them worthwhile only when the parties want to buy

or sell large amounts of energy.

3.2.1.2 Trading Over the Counter

These transactions involve smaller amounts of energy to be delivered according to a

standard profile, that is, a standardized definition of how much energy should be

delivered during different periods of the day and week. This form of trading has much

lower transaction costs and is used by producers and consumers to refine their position

as delivery time approaches.


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3.2.1.3 Electronic Trading

Participants can enter offers to buy energy and bids to sell energy directly in a

computerized marketplace. All market participants can observe the quantities and price

submitted but do not know the identity of the party that submitted each bid or offer.

When a party enters a new bid, the software that runs the exchange, checks to see if there

is a matching offer for the period of delivery of the bid. If it finds an offer whose price is

greater than or equal to the price of the bid, a deal is automatically struck and the price

and quantity are displayed for all participants to see. If no match is found, the new bid is

added to the list of outstanding bids and will remain there until a matching offer is made

or the bid is withdrawn or it lapses because the market closes for that period. This form

of trading is extremely fast and cheap. A flurry of trading activity often takes place in the

minutes and seconds before the closing of the market as generators and retailers fine-

tune their position ahead of the delivery period.

3.2.2 Electricity Pools

Since electrical energy is pooled as it flows from generators to the loads, it was felt that

trading might well be done in a centralized manner and involve all producers and

consumers. Competitive pools were thus created. Pools are a very unusual form of

commodity trading but they have established roots in the operation of large power

systems.

Rather than relying on repeated interactions between suppliers and consumers to reach

the market equilibrium, a pool provides a mechanism for determining this equilibrium in

a systematic manner.


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3.3 Availability Based Tariff (ABT) in India

If we compare the Indian electricity market with the open electricity markets mentioned

above, the similarity can be drawn with the operation of market under ABT. This can be

explained as follows:

In ABT the Central Generating Stations (CGS) serve the beneficiary states

through long term contracts called PPAs. These long term contracts are bilateral

contracts between the CGS and the states. So, this can be equated to the long term

contracts under bilateral trading.

The generators have to declare the availability of capacity on day-ahead basis for

15 minute time blocks. This is similar to the day-ahead market under pool

operation. The declared availability can be compared with the bid submitted on

day-ahead basis.

Under pool operation the balancing is done on real time basis. The imbalances are

liquidated at the spot prices. In ABT also the imbalances are liquidated at the UI

charges. UI charges are also like the spot price prevailing at a particular

frequency.

Looking at the difference in operation of market under ABT, it lies in the pricing

methodology. In ABT the prices are not being determined in competitive manner. The

dispatch is done based on the merit order but the prices are regulated and almost fixed

through contractual arrangements.


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Thus, considering the operation under ABT, it can be said that it is neither completely

similar to a bilateral trading arrangement nor completely similar to the pool operation. It

is a mix of both. This can be shown by the shaded portions below:

However, the prices are not determined competitively. Also, all these markets are

subjected to technical constraints.

Bilateral Trading

Long Term Contracts

Trading Over the Counter

Electronic Trading

Power Pool

Day ahead market

Balancing market


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3.4 Comparison of Installed Capacity

Total = 128180 MW

India - Installed Capacity

Thermal

66%

Hydro

26%Nuclear

3%

Renewable

5%

PJM - Installed Capacity

Thermal

76%

Hydro

4% Nuclear19%

Renewable

1%

Total = 162143 MW

Nord Pool - Installed Capacity

Thermal

31%

Hydro

52%Nuclear

13%

Renewable

4%

Total = 92641 MW


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CHAPTER 4: ANALYZING BIDDING & PRICING METHODOLOGIES FOR POWER TRADING IN INDIA

- 28 -

4 ANALYZING BIDDING & PRICING METHODOLOGIESFOR POWER TRADING IN INDIA

4.1 INTRODUCTION

Now days, it has become a practice to call for bids for one hour time blocks. Most of the

markets, these days, are organized in two parts, i.e., a day-ahead market and real time

market. Day-ahead market is also called the spot market. In India, at the inter-state level,

all supplies and dispatches are organized by RLDCs on day-ahead basis considering

requisitions from central generating stations and requests for bilateral trade through

Open Access.

In a competitive market, it is the competition which forces suppliers to submit bids based

on marginal costs. In a Power Exchange design, the most critical issue requiring close

examination is its price discovery mechanism. Normally, in double-sided bidding, the

market-clearing price is the intersection of the aggregated demand and supply curves,

i.e., the price at which supply is equal to the demand. In the uniform pricing model,

which is adopted in most electricity markets, all the suppliers are paid based one clearing

price. At very low prices, demand may be very high but very little supply may be

available as no supplier will be willing to supply electricity at a price lower than its

marginal cost.

However, as one moves towards higher prices and surpasses marginal cost of suppliers,more and more supply will be available. At the same time, demand will also tend to

reduce at higher prices. Thus, at a particular price, demand and supply will match and

this price becomes the market-clearing price and corresponding volume will become


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clearing volume. Thus, the price offered by the last supplier (marginal supplier) sets the

price for all suppliers in the uniform pricing model. Its criticism is that such marginal

pricing enhances the possibility of gaming by dominant players, and has the potential to

create windfall profits. In the absence of perfect competition, suppliers may not be

compelled to submit bids close to their marginal costs. Alternatively, the suppliers can

be paid the amount they initially bid. This type of pricing is referred to as pay-as-bid or

discriminatory pricing. Its criticism is that suppliers/generator will be more bothered

about the marginal cost of their competitors than their own.

4.2 SUPPLY SIDE BIDDING VS DOUBLE SIDE BIDDING

In supply side bidding only the suppliers submit the price bids and the consumers do not

submit any price bids. The market clearing price is determined based on the highest price

bid at which the aggregate supply matches the forecasted demand.

In double side biding the bids are submitted by both the suppliers and the buyers and the

price is determined by the interaction of the aggregate supply and demand curves.

4.2.1 Assumptions

4.2.1.1 Bid Volume

Currently about 14000 MU are traded in India. The projected availability of supply for

trading after one year of the power exchange is in place is assumed to be twice at about

30000 MU.

Average bid volume / year = 30000 MU

Time block for bidding = 1 hr


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Average bid volume / 1 hr = 3425 MWh

4.2.1.2 Distribution of Bid Volume

The table below shows the generation per month by different generators in India:

Table 4.1 Generation Statistics

Source MU / month %

STATE 27 48.2

CGS (Except NTPC) 6 10.7

NTPC 17 30.4

PRIVATE 6 10.7

TOTAL 56 100

Now the second assumption is that each source contributes in the same proportion to the

bid volume also. Considering this the bid volume distribution is shown in table 4.2.

Table 4.2 Bid Volume

Source MU / hr

NTPC 1027

PRIVATE 411

CENTRAL 342

STATE 1644

TOTAL 3425


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4.2.2 Supply Side Bidding: Case 1

In supply side bidding the bids are submitted by only the suppliers. There are no demand

bids. A demand of 2800 MWh is considered on a particular day for a particular bid

block.

4.2.2.1 Supply Bids: Case 1

The supply bids are shown in the table 4.3.

Table 4.3

Case 1: Demand - Supply Bids

Rs/KWh Demand Bids Supply Bids Company

MWh MWh

2 - 0 -

2.25 - 300 NTPC

2.5 - 400 A

2.75 - 450 B

3 - 500 C

3.25 - 550 D

3.5 - 800 NTPC

3.75 - 300 E

4 - 100 F

In the table the shaded bids for supply are submitted by NTPC. A, B, C, D, E, F are other

six companies which could be traders also which have submitted the bids. NTPC has two


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bids; one of 300 MWh at Rs 2.25 and second at Rs 3.5 of 800 MWh. Both these bids are

independent of each other.

4.2.2.2 Aggregate Demand and Supply: Case 1

The bids are arranged in increasing order and the volume at a particular price is equal to

the bid volume at that price plus all the volumes at lower prices. In this way the

aggregate supply is 3400 MWh at a price of Rs 4 / KWh.

The demand remains at 2800 MWh at all the prices.

Table 4.4

Case 1: Aggregate Demand & Supply

S. No. Rs/KWh Aggregate Demand Aggregate Supply

MWh

1 2 2800 0

2 2.25 2800 300

3 2.5 2800 700

4 2.75 2800 1150

5 3 2800 1650

6 3.25 2800 2200

7 3.5 2800 3000

8 3.75 2800 3300

9 4 2800 3400


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4.2.2.3 Market Clearing: Case 1

The aggregate demand and supply curves are drawn and the intersection of these curves

gives the Market Clearing Price (MCP) also known as the System Marginal Price

(SMP). The corresponding market clearing volume is 2800 MWh.

The aggregate demand and supply curves intersect at a value 7.8 on the X-axis.

Conversion Factor:

MCP = 2 + (Value X axis 2) * 0.25

MCP = Rs 3.45

Fig 4.1 Market Clearing : Case 1

0

500

1000

1500

2000

25003000

3500

4000

1 2 3 4 5 6 7 8 9 10

MWh

Aggregate Demand Aggregate Supply


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4.2.2.4 Generation Volume Allotment: Case 1

Once the MCP is found out the volume is allotted to the generators in the merit order.

The generation volume allotment is shown in the table 4.5.

Table 4.5

Case 1: Generation Volume Allotment

CompanyAllotment

(MWh)

NTPC 900

A 400

B 450

C 500

D 550

E 0

F 0

Total 2800


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4.2.3 Supply Side Bidding: Case 2

In case 2 the bid volume submitted by NTPC at prices Rs 2.25 & Rs 3.5 are

interchanged. The supply and demand curves are plotted again to get the MCP.

4.2.3.1 Supply Bids: Case 2

The supply bids are shown in the table 4.6.

Table 4.6

Case 2 : Demand - Supply Bids


MWh MWh

2 - 0 -

2.25 - 800 NTPC

2.5 - 400 A

2.75 - 450 B

3 - 500 C

3.25 - 550 D

3.5 - 300 NTPC

3.75 - 300 E

4 - 100 F


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4.2.3.2 Aggregate Demand & supply: Case 2

The aggregate demand and supply curves are drawn as below:

Table 4.7

Case 2 : Aggregate Demand & Supply


MWh

1 2 2800 0

2 2.25 2800 800

3 2.5 2800 1200

4 2.75 2800 1650

5 3 2800 2150

6 3.25 2800 2700

7 3.5 2800 3000

8 3.75 2800 3300

9 4 2800 3400


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Conversion Factor:

MCP = 2 + (Value X axis 2) * 0.25

MCP = Rs 3.32

Fig 4.2: Market Clearing : Case 2

0

500

1000

1500

2000

2500

3000

3500

4000

1 2 3 4 5 6 7 8 9 10

MWh



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The volume is allotted for the time slot as shown in table 4.8.

Table 4.8Case 2: Generation Volume Allotment

CompanyAllotment

(MWh)

NTPC 900

A 400

B 450

C 500

D 550

E 0

F 0

Total 2800

4.2.3.5 Result: Supply Side Bidding

Considering the cases 1 & 2 the result for the study are as follows:

Table 4.9

Supply Side Bidding: Market Clearing

Volume (MWh) MCP (Rs/KWh)

Case 1 2800 3.45

Case 2 2800 3.325

Change 0 0.125

%Change 0.0 3.6


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Table 4.10

Generation Allotment

(MWh)

Company Case 1 Case 2 Change

NTPC 900 900 0

A 400 400 0

B 450 450 0

C 500 500 0

D 550 550 0

E 0 0 0

F 0 0 0

Total 2800 2800 0

Thus considering the cases for supply side bidding, the only change is in the MCP. The

MCP changes by 3.6 %. There is also no change in the generation volume allotment for

the different generators from case 1 to case 2.

4.2.4 Double Side Bidding: Case 3

In double side bidding the procedure is same as for supply side bidding. However the

difference is that the consumers also submit the price bids along with the suppliers. An

aggregate supply curve is drawn for the suppliers and an aggregate demand curve is also

drawn for the demands.


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The intersection of both these curves will give the MCP for the block. In the analysis for

double side bidding also two cases are considered. In both these cases the demand bids

are not changed but the supply bids are changed as for cases for supply side bidding.

4.2.4.1 Double Side Bids: Case 3

The double side bids for Case 3 are shown in the table 4.10.

Table 4.11



MWh MWh

2 550 0 -

2.25 500 300 NTPC

2.5 450 400 A

2.75 400 450 B

3 350 500 C

3.25 250 550 D

3.5 200 800 NTPC

3.75 100 300 E

4 50 100 F


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Table 4.11 shows the aggregate demand and supply for case 3.

Table 4.12



MWh

1 2 550 0

2 2.25 1050 300

3 2.5 1500 700

4 2.75 1900 1150

5 3 2250 1650

6 3.25 2500 2200

7 3.5 2700 3000

8 3.75 2800 3300

9 4 2850 3400

The table shows that the aggregate supply is less than the aggregate demand upto a price

of 3.25 and it exceeds the aggregate demand at a price 3.5. So, the equilibrium is

achieved at a price in between.

This equilibrium is found by plotting the curves for aggregate demand and supply. This

is determined in the market clearing.


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Fig 4.3 shows the market clearing for Case 3


0

500

1000

1500

2000

2500

3000

3500

4000

1 2 3 4 5 6 7 8 9 10

MWh



Conversion Factor:

MCP = 2 + (Value X axis 2) * 0.25

MCP = Rs 3.375

Market Clearing Volume

MCV = 2600 MWh


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The generation volume allotment for case 3 is shown in the table 4.12

Table 4.13


CompanyAllotment

(MWh)

NTPC 700

A 400

B 450

C 500

D 550

E 0

F 0

Total 2600


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4.2.5 Double Side Bidding: Case 4

Similar to the cases for supply side bidding, in case 4 the bids of NTPC are swapped.

The demand side bids remain unchanged.

4.2.5.1 Double Side Bids: Case 4

Table 4.14



MWh MWh

2 550 0 -

2.25 500 800 NTPC

2.5 450 400 A

2.75 400 450 B

3 350 500 C

3.25 250 550 D

3.5 200 300 NTPC

3.75 100 300 E

4 50 100 F


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The aggregate demand and supply are shown in table 4.13.

Table 4.15



MWh

1 2 550 0

2 2.25 1050 800

3 2.5 1500 1200

4 2.75 1900 1650

5 3 2250 2150

6 3.25 2500 2700

7 3.5 2700 3000

8 3.75 2800 3300

9 4 2850 3400


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The market clearing is shown in the fig. 4.4.


0

500

1000

1500

2000

2500

3000

3500

4000

1 2 3 4 5 6 7 8 9 10

MWh



Conversion Factor:

MCP = 2 + (Value X axis 2) * 0.25

MCP = Rs 3.10

Market Clearing Volume

MCV = 2350 MWh


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The volumes allotted to different generators are shown in the table 4.15.

Table 4.16


CompanyAllotment

(MWh)

NTPC 800

A 400

B 450

C 500

D 200

E 0

F 0

Total 2350


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4.2.5.5 Result: Double Side Bidding

Considering Cases 3 & 4, the results of the study are as follows:

Table 4.17

Double Side Bidding: Market Clearing

Volume (MWh) MCP (Rs/KWh)

Case 3 2600 3.375

Case 4 2300 3.1

Change 300 0.275

%Change 9.6 8.1

Table 4.18

Generation Allotment

(MWh)

Company Case 3 Case 4 Change % Change

NTPC 700 800 100 14.3

A 400 400 0 0.0

B 450 450 0 0.0

C 500 500 0 0.0

D 550 200 -350 -63.6

E 0 0 0 0.0

F 0 0 0 0.0

Total 2600 2350 -250 -9.6


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4.2.6 Result: Supply Side Vs Double Side Bidding

Table 4.18 shows the change in market clearing volume and price for supply side and

double side bidding.

Table 4.19

Supply Side Vs Double Side Bidding

Market Clearing

Volume MCP

Change % Change Change % Change

Supply SideBidding

0 0% 0.125 3.60%

Double SideBidding

300 9.60% 0.275 8.10%

It can be inferred from the table that the market clearing volume as well as the

market clearing price are more sensitive to the change in bids by a single large

company in case of double side bidding as compared to the single side bidding.

Also, in case of supply side bidding the market clearing volume will never be

less than the demand, unless the aggregate supply at the highest price is less than

the aggregate demand. So, normally the whole of the demand is met.

On the other hand, in case of double side bidding the demand is not met fully.


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4.3 Uniform Pricing Vs Discriminatory Pricing

The second main feature in the pricing mechanism is the price at which the bidders are

paid. In case of uniform pricing, all the bidders are paid by the MCP irrespective of the

price at which the bids were submitted. The revenues earned by each generator are

simply MCP multiplied by the energy traded. On the other hand, in case of

discriminatory pricing the price is paid according to the bid amount by the generator. In

this case the revenue to each generator is the product of the bid price and the energy

traded.

4.3.1 Uniform Pricing

Considering the cases discussed earlier, the revenue for each generator is shown in the

table 4.19.

Table 4.20

Uniform Pricing: Revenue of Generators

Revenue (Thousand Rs)

Company Case 1 Case 2 Case 3 Case 4

NTPC 3105 2992.5 2362.5 2480

A 1380 1330 1350 1240

B 1552.5 1496.25 1518.75 1395

C 1725 1662.5 1687.5 1550

D 1897.5 1828.75 1856.25 620

E 0 0 0 0

F 0 0 0 0


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Total 9660 9310 8775 7285

Thus in each case the revenues earned are dependent on the MCP. Also, the average

price per unit paid is equal to the MCP.

4.3.2 Discriminatory Pricing

The revenue earned by the generators in case of discriminatory pricing is shown in the

table 4.20.

Table 4.21

Discriminatory Pricing: Revenue of Generators

Revenue (Thousand Rs)

Company Case 1 Case 2 Case 3 Case 4

NTPC 2775 2150 2075 1800

A 1000 1000 1000 1000

B 1237.5 1237.5 1237.5 1237.5

C 1500 1500 1500 1500

D 1787.5 1787.5 1787.5 650

E 0 0 0 0

F 0 0 0 0

Total 8300 7675 7600 6187.5


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In discriminatory pricing the revenue earned by each generator is dependent on the price

quoted by the generator, MCP and the volume allotted to that generator. This is so

because the volume allotted to the generator depends upon the MCP.

4.3.3 Result: Uniform Vs Discriminatory Pricing

Table 4.21 shows the comparison between the two pricings.

Table 4.22

Result: Uniform Vs Discriminatory Pricing

Traded Volume

(MWh)

Total Price Paid

(Thousand Rs)

Price Per Unit

(Rs/KWh)

Uniform

Pricing

Discriminatory

Pricing

Uniform

Pricing

Discriminatory

Pricing

Case 1 2800 9660 8300 3.45 2.96

Case 2 2800 9310 7675 3.33 2.74

Case 3 2600 8775 7600 3.38 2.92

Case 4 2350 7285 6187 3.10 2.63

Comparing the price per unit. It shows that the price per unit in case of

discriminatory pricing is less than the price per unit for uniform pricing.


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Thus if the MCP is same in case of both form of pricing, the discriminatory

pricing will always give a lower price per unit.


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CHAPTER 5: SELECTING A PRICE DISCOVERY MECHANISM FOR POWER TRADING IN INDIA

- 54 -

5 SELECTING A PRICE DISCOVERY MECHANISM FORPOWER TRADING IN INDIA

5.1 Price Discovery Mechanisms

Bidding methodology and pricing methodology are the two major parts of the price

discovery mechanisms.

The bidding can be in two ways:

Supply Side Bidding

Double Side Bidding

Pricing can be done in following two ways:

Uniform Pricing

Discriminatory Pricing

Considering the two forms of bidding and two forms of pricing which can be followed,

we can have following options for the price discovery mechanism:

1. Option 1: Supply Side Bidding with Uniform Pricing

2. Option 2: Supply Side Bidding with Discriminatory Pricing

3. Option 3: Double Side Bidding with Uniform Pricing

4. Option 4: Double Side Bidding with Discriminatory Pricing


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Further, the suitability of each option will be analyzed. Each option has certain

advantages and disadvantages. Based on the relative strengths and weaknesses a suitable

option will be proposed along with the measures to remove the weakness in the option.

5.2 Option 1: Supply Side Bidding with Uniform Pricing

The results for this option are shown in the table 5.1.

Table 5.1

Option 1: Supply Side Bidding with Uniform Pricing

TradedVolume(MWh)

MCP(Rs/KWh)

Total PricePaid

(ThousandRs)

Price PerUnit

(Rs/KWh)

Case 1 2800 3.45 9660 3.45

Case 2 2800 3.325 9310 3.325

Change 0 0.125 350 0.125

% Change 0% 3.62% 3.62% 3.62%

The table shows that the traded volume in not affected by a single bidder at all.

The change in MCP is also not very sensitive to the change in bids by a single

bidder. Therefore we can say that because of supply side bidding the market

clearing is not affected by much.

However, MCP is higher. This is so because the demand is considered to be

present at every price. Here the generators know demand and also get a uniform


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price. Chances are that the generators will try to increase the MCP by colluding

together.

Since every generator is paid by the MCP, a number of generators can form a

cartel to increase the MCP which in turn increases the revenue.

5.3 Option 2: Supply Side Bidding with Discriminatory Pricing

The results for option 2 are shown in the table 5.2.

Table 5.2

Option 2: Supply Side Bidding with Discriminatory PricingTradedVolume(MWh)

MCP(Rs/KWh)

Total PricePaid

(ThousandRs)

Price PerUnit

(Rs/KWh)

Case 1 2800 3.45 8300 2.96

Case 2 2800 3.325 7675 2.74

Change 0 0.125 625 0.22

% Change 0% 3.62% 7.53% 7.53%

In this case the generators are paid by the bid price. The advantage here is that

the average price per unit is lesser than the MCP. This is thus more suitable when

a large number of players are present in the supplier side. The competition will

make all of them bid at a competitive price.

However if one player is large enough to influence the market then the bid price

might be higher.


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5.4 Option 3: Double Side Bidding with Uniform Pricing

The result for option 3 is shown ion table 5.3.

Table 5.3

Option 3: Double Side Bidding with Uniform Pricing

TradedVolume(MWh)

MCP(Rs/KWh)

Total PricePaid

(ThousandRs)

Price PerUnit

(Rs/KWh)

Case 3 2600 3.375 8775 3.375

Case 4 2350 3.1 7285 3.1

Change 250 0.275 1490 0.275

%Change

10% 8.15% 16.98% 8.15%

In double side bidding the MCP is determined competitively and is lesser than as

compared to options & 2. however the volume decreases. Also a single bidder is

not very important as the main aim is to classify for the volume allotment andthus the bid would reflect marginal cost of generation.

The price is uniformly paid to all the generators. This may not be good for small

generators as the cost of generation is higher for small generators and they have

the risk of getting no allotment at all as they might not classify for that.


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5.5 Option 4: Double Side Bidding with Discriminatory Pricing

Table 5.4 shows the result for option 4.

Table 5.4

Option 4: Double Side Bidding with Discriminatory Pricing

TradedVolume(MWh)

MCP(Rs/KWh)

Total PricePaid

(ThousandRs)

Price PerUnit

(Rs/KWh)

Case 3 2600 3.375 7600 2.92

Case 4 2350 3.1 6187 2.63

Change 250 0.275 1413 0.29

% Change 10% 8.15% 18.59% 9.93%

This option is good when the traded volume is very large. It is also better for

small generators as they get high returns for high risk.

The main disadvantage of this method is that every bidder is concerned about the

bid price of other bidders and tries to guess the MCP and bid accordingly. This

might make it difficult to get a bid close to the marginal cost.


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5.6 Result and Conclusion: Viable Option for India

Table 5.5

Viable Option for India

Pricing

Uniform Discriminatory

Supply Side

Whole demand is met. MCPless sensitive to a singlebidder. Generators cancollude to raise the MCP.

Average price is less than theMCP. Generators worriedabout the other bidders. Bidsmight not reflect the marginalcost.

Bidding

Double Side

Demand is not met fully.Generators might collude.Average price is equal toMCP.

Demand is not met fully. Goodfor small generators. Bestwhen large number of playersis present.

Considering the Indian scenario at present and for the start of trading through PX;

Option 1: Supply Side Bidding with Uniform Pricing can be viable to use:

Since in India a single company might hold a large proportion of traded volume;

the MCP will be less sensitive in case of option 1.

Also the demand is met fully in option 1. The generators are less worried about

the bids of other generators and thus the price will reflect the marginal cost of

generation. This would also help more and more participants to trade though the

PX to balance their positions.

The chances of abuse of colluding can be minimized by placing a bid cap and

through efficient and transparent market monitoring and operation.


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APPENDIX I

FUNCTIONAL DIAGRAM OF PX PROPOSED BY CERC


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APPENDIX II

ORGANIZATION OF PROPOSED POWER EXCHANGE

Documents

An Assessment of Price Discovery Mechanism for Power