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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
4.2.3.2.Aggregate Demand and Supply: Case 2 36
4.2.3.3.Market Clearing: Case 2 37
4.2.3.4.Generation Volume Allotment: Case 2 38
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
4.2.4.2.Aggregate Demand and Supply: Case 3 41
4.2.4.3.Market Clearing: Case 3 42
4.2.4.4.Generation Volume Allotment: Case 3 43
4.2.5. Double Side Bidding: Case 4 44
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4.2.5.1.Double Side Bids: Case 4 44
4.2.5.2.Aggregate Demand and Supply: Case 4 45
4.2.5.3.Market Clearing: Case 4 46
4.2.5.4.Generation Volume Allotment: Case 4 47
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 4.6 Case 2: Demand-Supply Bids 35
Table 4.7 Case 2: Aggregate Demand & Supply 36
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 4.11 Case 3: Demand-Supply Bids 40
Table 4.12 Case 3: Aggregate Demand & Supply 41
Table 4.13 Case 3: Generation Volume Allotment 43
Table 4.14 Case 4: Demand-Supply Bids 44
Table 4.15 Case 4: Aggregate Demand & Supply 45
Table 4.16 Case 4: Generation Volume Allotment 47
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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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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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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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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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
Rs/KWh Demand Bids Supply Bids Company
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
S. No. Rs/KWh Aggregate Demand Aggregate 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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4.2.3.3 Market Clearing: Case 2
The aggregate demand and supply curves intersect at a value 7.3 on the X-axis.
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
Aggregate Demand Aggregate Supply
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4.2.3.4 Generation Volume Allotment: Case 2
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
Case 3 : Demand - Supply Bids
Rs/KWh Demand Bids Supply Bids Company
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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4.2.4.2 Aggregate Demand and Supply: Case 3
Table 4.11 shows the aggregate demand and supply for case 3.
Table 4.12
Case 3 : Aggregate Demand & Supply
S. No. Rs/KWh Aggregate Demand Aggregate Supply
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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4.2.4.3 Market Clearing: Case 3
Fig 4.3 shows the market clearing for Case 3
Fig 4.3 Market Clearing : Case 3
0
500
1000
1500
2000
2500
3000
3500
4000
1 2 3 4 5 6 7 8 9 10
MWh
Aggregate Demand Aggregate Supply
The aggregate demand and supply curves intersect at a value 7.5 on the X-axis.
Conversion Factor:
MCP = 2 + (Value X axis 2) * 0.25
MCP = Rs 3.375
Market Clearing Volume
MCV = 2600 MWh
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4.2.4.4 Generation Volume Allotment: Case 3
The generation volume allotment for case 3 is shown in the table 4.12
Table 4.13
Case 3: Generation Volume Allotment
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
Case 4 : Demand - Supply Bids
Rs/KWh Demand Bids Supply Bids Company
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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4.2.5.2 Aggregate Demand and Supply: Case 4
The aggregate demand and supply are shown in table 4.13.
Table 4.15
Case 4 : Aggregate Demand & Supply
S. No. Rs/KWh Aggregate Demand Aggregate Supply
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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4.2.5.3 Market Clearing: Case 4
The market clearing is shown in the fig. 4.4.
Fig 4.4 Market Clearing : Case 4
0
500
1000
1500
2000
2500
3000
3500
4000
1 2 3 4 5 6 7 8 9 10
MWh
Aggregate Demand Aggregate Supply
The aggregate demand and supply curves intersect at a value 6.4 on the X-axis.
Conversion Factor:
MCP = 2 + (Value X axis 2) * 0.25
MCP = Rs 3.10
Market Clearing Volume
MCV = 2350 MWh
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4.2.5.4 Generation Volume Allotment: Case 4
The volumes allotted to different generators are shown in the table 4.15.
Table 4.16
Case 3: Generation Volume Allotment
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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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