Module1: Introduction

The power industry across the globe is experiencing a radical change in its business as well as in an operational model where, the vertically integrated utilities are being unbundled and opened up for competition with private players. This enables an end to the era of monopoly. Right from its inception, running the power system was supposed to be a task of esoteric quality. The electric power was then looked upon as a service. Control consisting of planning and operational tasks was administered by a single entity or utility. The vertical integration of all tasks gave rise to the term – vertically integrated utility. The arrangement of the earlier setup of the power sector was characterized by operation of a single utility generating, transmitting and distributing electrical energy in its area of operation. Thus, these utilities enjoyed monopoly in their area of operation. They were often termed as monopoly utilities. Why were earlier utilities the ‘monopolies'? The reason for monopoly can be traced right back to the early days when electricity was comparatively a new technology. The skeptical attitude of the government towards electricity led to investment by private players into the power sector, who in turn, demanded for the monopoly in their area of operation. This created a win-win situation for both- government and the electrical technology promoters. However, the government would not let the private players enjoy the monopoly and exploit the end consumer and hence introduced regulation in the business. Thus, the power industries of initial era became regulated monopoly utilities . The structure of a conventional vertically integrated utility is shown in Figure 1.1. As evident from the figure, there was only a single utility with whom the customer dealt with. Thus, only two entities existed in the power business: a monopolist utility and the customer.

Fig 1.1

What does ‘regulation’ mean? The regulations are generally imposed by the government or the government authority. These essentially represent a set of rules or framework that the government has imposed so as to run the system smoothly and with discipline, without undue advantage to any particular entity at the cost of end consumer. All practical power systems of earlier days used to be regulated by the government. This was obviously so. The old era power industries were vertically integrated utilities and enjoyed monopoly in their area of operation. Whenever a monopoly is sensed in any sector, it is natural for the government to step in and set up a framework of way of doing business, in order to protect end consumer interests. Some of the characteristics of monopoly utility are:

1. Single utility in one area of operation enjoying monopoly. 2. Regulated Framework: The utility should work under the business framework

setup by the government. 3. Universal Supply Obligation (USO): Utility should provide power to all those

customers who demand for it. 4. Regulated Costs: The return on the utility's investments is regulated by the

government.

In a nutshell, regulation is about checking the prices of the monopolist in the absence of private players and market forces.

Reasons for restructuring / deregulation of power industry The next obvious question is, “what is deregulation or restructuring of an industry?” From the name, one can sense discontinuation of the framework provided by the regulation. In other words, deregulation is about removing control over the prices with introduction of market players in the sector. However, this is not correct in a strict sense. An overnight change in the power business framework with provision of entry to competing suppliers and subjecting prices to market interaction, would not work successfully. There are certain conditions that create a conducive environment for the competition to work. These conditions need to be satisfied while deregulating or restructuring a system. Sometimes, the word ‘deregulation’ may sound a misnomer. ‘Deregulation’ does not mean that the rules won’t exist. The rules will still be there, however, a new framework would be created to operate the power industry. That is why the word ‘deregulation’ finds its substitutes like ‘re-regulation’, ‘reforms’, ‘restructuring’, etc. The commonly used word in Europe is ‘liberalization’ of power industry; ‘deregulation’ is a more popular phrase in US. If the power industries worked successfully with the regulated monopoly framework for over 100 years, what was the need for deregulating or changing the business framework of the system? There are many reasons that fuelled the concept of deregulation of the power industry. One major thought that prevailed during the early nineties raised questions about the performance of monopoly utilities. The takers of this thought advocated that monopoly status of the electric utilities did not provide any incentive for its efficient operation. In privately owned utilities, the costs incurred by the utility were directly imposed upon the consumers. In government linked public utilities, factors other than the economics, for example, treatment of all public utilities at par, overstaffing, etc. resulted in a sluggish performance of these utilities. The economists started promoting introduction of a competitive market for electrical energy as a means of benefit for the overall powerector. This argument was supported by the successful reform experiences of other sectors such as airlines, gas, telephone, etc. Another impetus for deregulation of power industry was provided by the change in power generation technology. In the earlier days, cost-effective power generation was possible only with the help of mammoth thermal (coal/nuclear) plants. However, during the mid eighties, the gas turbines started generating cost effective power with smaller plant size. It was then possible to build the power plants near the load centers and also, an opportunity was created for private players to generate power and sell the same to the existing utility. This technology change, supposed to have provided

acceleration to the concept of independent power producers, supported the concept of deregulation further. This technology change is supposed to have provided acceleration to the concept of independent power producers. This further supported concept of deregulation. This was specifically true where the financial losses were apparently high which was prevalent in some of the developing countries. It should be noted that these are the indicative or major reasons for introducing the concept of deregulation in power industry. There are many other reasons as well. One of the important reasons is the condition under which power systems were regulated, did not exist any more. There was no wind of skepticism about the electrical technology and all the initial investments in infrastructure were already paid back. Further, the deregulation aims at introducing competition at various levels of power industry. The competition is likely to bring down the cost of electricity. Then, the activities of the power industry would become customer centric. The competitive environment offers a good range of benefits for the customers as well as the private entities. It is claimed that some of the significant benefits of power industry deregulation would include:

1. Electricity price will go down: It is a common understanding that the competitive prices are lesser than the monopolist prices. The producer will try to sell the power at its marginal cost, in a perfectly competitive environment.

2. Choice for customers: The customer will have choice for its retailer. The retailers will compete not only on the price offered but also on the other facilities provided to the customers. These could include better plans, better reliability, better quality, etc.

3. Customer-centric service: The retailers would provide better service than what the monopolist would do.

4. Innovation: The regulatory process and lack of competition gave electric utilities no incentive to improve or to take risks on new ideas that might increase the customer value. Under deregulated environment, the electric utility will always try to innovate something for the betterment of service and in turn save costs and maximize the profit.

The deregulation of the industry has provided electrical energy with a new dimension where it is being considered as a commodity. The ‘commodity’ status given to electrical power has attracted entry of private players in the sector. The private players make the whole business challenging from the system operator’s point of view, as it now starts dealing with many players which are not under it’s direct control. This calls for introduction of fair and transparent set of rules for running the power business. The market design structure plays an important role in successful deregulation of power industry

Understanding the restructuring process The process of deregulation has taken different formats in different parts of the world. Also, the reasons for power sector to adopt the reforms vary from country to country. For the developed countries, introduction of competition to achieve social welfare was probably the most important reason. On the other hand, the developing countries mainly banked on the capacity addition through entry of private players. It is observed that neither, there is lone reson for driving deregulation of power industry nor is there a single objective of the same. The restructuring process starts with the unbundling of the originally vertically integrated utility. This essentially leads to separate the activities involved in an integrated power system leading to creation of functional partition amongst them. For example, the unbundling of power industry involves separating transmission activity from the generation activity. Further, distribution can be separated from transmission. Thus, these three mutually exclusive functions are created and there are separate entities or companies that control these functions. Then, the competition can be introduced in the generation activity by allowing other private participants in this segment. In contrast to the vertically integrated case where all the generation is owned by the same utility, there is a scope for private players to sell their generation at competitive prices. The generators owned by the earlier vertically integrated utility will then compete with these private generators. The transmission sector being a natural monopoly is most unlikely to have competing players in the sector. This is because for natural monopolies like transmission companies, the business becomes profitable only when output is large enough. Figure 1.2 shows the representative structure of deregulated power system. In contrast to the vertically integrated utility structure, it can be seen that there are many alternative paths along which the money flows. It is evident that there are many more other entities present, apart from the vertically integrated utility and the customers. It should be noted that there can be many more versions of deregulated structure.

Various Entities Involved in Deregulation: The introduction of deregulation has introduced several new entities in the electricity market place and has simultaneously redefined the scope of activities of many of the existing players. Variations exist across market structures over how each entity is particularly defined and over what role it plays in the system. However, on a broad level, the following entities can be identified:

1. Genco (Generating Company): Genco is an owner-operator of one or more generators that runs them and bids the power into the competitive marketplace. Genco sells energy at its sites in the same manner that a coal mining company might sell coal in bulk at its mine.

2. Transco (Transmission Company): Transco moves power in bulk quantities from where it is produced to where it is consumed. The Transco owns and maintains the transmission facilities, and may perform many of the management and engineering functions required to ensure the smooth running of the system. In some deregulated industries, the Transco owns and maintains the transmission lines under the monopoly, but does not operate them. That is done by Independent System Operator (ISO). The Transco is paid for the use of its lines.

3. Discom (Distribution Company): It is the owner-operator of the local power delivery system, which delivers power to individual businesses and homeowners. In some places, the local distribution function is combined with retail function, i.e. to buy wholesale electricity either through the spot market or through direct contracts with Gencos and supply electricity to the end use

customers. In many other cases, however, the Discom does not sell the power. It only owns and operates the local distribution system, and obtains its revenue by wheeling electric power through its network.

4. Resco (Retail Energy Service Company): It is the retailer of electric power. Many of these will be the retail departments of the former vertically integrated utilities. A Resco buys power from Gencos and sells it directly to the consumers. Resco does not own any electricity network physical assets.

5. Market Operator: Market operator provides a platform for the buyers and sellers to sell and buy the electricity. It runs a computer program that matches bids and offers of sellers and buyers. The market settlement process is the responsibility of the market operator. The market operator typically runs a day-ahead market. The near-real-time market, if any, is administered by the system operator.

6. System Operator (SO): The SO is an entity entrusted with the responsibility of ensuring the reliability and security of the entire system. It is an independent authority and does not participate in the electricity market trades. It usually does not own generating resources, except for some reserve capacity in certain cases. In order to maintain the system security and reliability, the SO procures various services such as supply of emergency reserves, or reactive power from other entities in the system. In some countries, SO also owns the transmission network. The SO in these systems is generally called as Transmission System Operator (TSO). In the case of a SO being completely neutral of every other activity except coordinate, control and monitor the system, it is generally called as Independent System Operator (ISO).

7. Customers: A customer is an entity, consuming electricity. In a completely deregulated market where retail sector is also open for competition, the end customer has several options for buying electricity. It may choose to buy electricity from the spot market by bidding for purchase, or may buy directly from a Genco or even from the local retailing service company. On the other hand, in the markets where competition exists only at the wholesale level, only the large customers have privilege of choosing their supplier.

Understanding the restructuring process

Electricity, as a commodity, can not be compared with any other commodity traded in the market. This is because it has some distinguishing characteristics of its own, which demand satisfaction of technical constraints before accomplishing the commercial trades. Two important features of electricity as a commodity are: need for real time balance and inability to wheel the commodity through desired path (in bulk). Hence, a set of principles laid down by standard micro-economic theory can not be mapped directly to the electricity commodity markets.

Tackling network congestion is one of the challenging issues of the de-regulated era. Transmission network provides the path through which transactions are made in a power market. But each transmission network has its own physical and operating limits like line flow limits, bus voltage magnitude limits and more. The power injection and withdrawal configuration should be such that no limit gets violated. If the network is operated beyond these limits, it may, even, result in the entire system blackout. Therefore, any arbitrary set of transactions can’t be organized on the power network. This has given rise to a new problem under the restructured power system environment, referred to as congestion management. There are many ways in which congestion is formally defined but to explain in simple words, when some components in a power network appear to be overloaded due to a trading arrangement, that particular arrangement is said to create congestion on the network. The purpose of congestion management is to make necessary corrections in order to relieve congestion. It can be easily appreciated that under the vertically integrated structure, network congestion, in fact, is not a challenging task. This is because all the resources in the system are under the direct control of the monopolist. Thus, this is the sole responsibility of the monopolist to maintain its transmission network. Provision of ancillary services is another tough task carried out by the system operator under the deregulated framework. Ancillary services are defined as all those activities on the interconnected grid that are necessary to support the transmission of power while maintaining reliable operation and ensuring the required degree of quality and safety. Under the deregulated power system environment, the system operator acquires a central coordination role and carries out the important responsibility of providing for system reliability and security. It manages system operations like scheduling and operating the transmission related services. The SO also has to ensure a required degree of quality and safety and provide corrective measures under contingent conditions. In this respect, certain services, such as scheduling and dispatch, frequency regulation, voltage control, generation reserves, etc. are required by the power system, apart from basic energy and power delivery services. Such services are commonly referred to as ancillary services. In deregulated power systems, transmission networks are available for third party access to allow power wheeling. In such an environment, the ancillary services are no longer treated as an integral part of the electric supply. They are unbundled and priced separately and system operators may have to purchase ancillary services from ancillary service providers. Then, there are certain issues like market design and market power which need regulatory intervention. Issues pertaining to market design revolve around choice made in the selection of dispatch philosophies, choice of various pricing schemes, choice between number of markets with multiple gate closures, etc., from various alternatives. The market architecture, which maps various markets on timeline, is also an important sub-topic of market design process.

Existence of market power shows the signs of deviation from the prefect competition. In general, market power is referred to as ability of market participants to profitably maintain the market price above or below the competitive level for a significant period of time. To tackle the situation, an indirect regulatory intervention in the form of market design rules is needed. Thus, as mentioned earlier, deregulation does not mean ceasing to have rules. It is the ‘restructuring’ of the power business framework. More rigorous treatment to these issues is given in further chapters.

Reasons and objectives of deregulation of various power systems across the world

Restructuring or deregulation is a broad term and can have different meanings in different countries. This is because the changes essential for betterment of power sector depend on the prevailing conditions in the power sector of respective countries. Further, the word – betterment can be looked upon subjectively. For example, well developed, industrialized countries can expect price to go down and these countries can treat the change in the prices as betterment. On the other hand, the developing countries need to make radical changes in the policy and regulation such that barrier to entry for private players is removed. The effective betterment can be looked upon from this perspective for developing countries. In this section we will see, in brief, the issues that led to restructuring of the power industry for following regions / countries: US , UK , Nordic Pool and developing countries. The US The US electric utilities, from the very beginning were privately owned and worked in a vertically integrated fashion. The developed countries like US had well functioning and efficient electricity systems. However for some systems, so long as consumers were concerned, they were not satisfied with the rising costs of electricity. For some other systems, utility management found that running the system was not viable due to low tariff. In some systems, pressure from smaller players to open up the business for competition played a major role. By and large, deregulation took place in developed countries by pressure to reduce costs while simultaneously increasing competitiveness in the market. Existence of market power shows the signs of deviation from the prefect competition. In general, market power is referred to as ability of market participants to profitably maintain the market price above or below the competitive level for a significant period of time. To tackle the situation, an the indirect regulatory intervention in the form of market design rules is needed. Thus, as mentioned earlier, deregulation does not mean

ceasing to have rules. It is the ‘restructuring’ of the power business framework. More rigorous treatment to these issues is given in further chapters. The UK The transformation of the British power sector proceeded along three paths in 1990. First, the traditional industry was unbundled both vertically and horizontally. High-voltage transmission assets were transferred to a new National Grid Company (NGC). Coal and oil fired units were divided among two companies National Power and PowerGen. Nuclear Electric retained control of all nuclear units. At the outset, National Power had 52 percent of total generating capacity, PowerGen had 33 percent, and Nuclear Power had the remaining 15 percent. The second set of changes involved ownership. Both National Power and PowerGen became private companies in 1991, whereas the difficulties associated with nuclear power resulted in continued government ownership of all nuclear units. Approximately 30 percent of shares in National Power and PowerGen were sold to the public,an equal amount to foreign and institutional investors. The remaining 40 percent was held by the government until 1995. The third set of changes sought to open the system to competition, wherever possible, while continuing necessary regulations. Vertical and horizontal restructuring of power generation was based on the assumption that generation had become workably competitive and would become increasingly so with new market entrants. A report on reform process was floated by the regulator in 2001 which stated that wholesale electricity prices had not fallen in line with reductions in generators’ input costs and that a lack of supply side pressure and demand side participation; and inflexible governance arrangements had prevented reform of the arrangements. The Nordic Pool The reforms in Nordic countries were inspired by the electricity market reforms in England and Wales in 1989, as well as by widely held beliefs that increased competition would raise power industry efficiency to the benefit of consumers. Norway was first amongst the Nordic countries to liberalize its electricity market in 1991, but without privatization. The Norwegian electricity sector remains almost entirely in public hands. Rather than implement national reforms, the other Nordic countries chose to reform by merging with the existing Norwegian market, Sweden joining the expanded Nordic pool in 1996, Finland in 1998 and Denmark in 1999. The Developing Countries The case of developing countries is different from that of other countries. In these countries, the electricity supply is treated as a social service rather than a market commodity. The ownership of the power sector in these countries is directly under the governments of respective countries. These state owned-controlled systems have led

to the promotion of inefficient practices over a period. The power sectors of these countries are marked by supply shortages. There has been an inability to add to the generating capacity. The subsidies and high transmission and distribution losses are the major concerns before these systems. Another consequence of state control over electric utilities was the high level of overstaffing. The inability to raise funds for capacity addition invited financial support from international financial institutions like World Bank. These institutions mandated opening of the power sector for private companies which were contracted under build, own, operate and transfer (BOOT) scheme.

ELECTRICITY VIS-A-VIS OTHER COMMODITIES

The classification of market models based on contractual agreements discussed in the previous section can be applied to most of the commodities that are traded in the market, if we assume a certain level of abstraction by presenting only the buyers and sellers. However, when it comes to ‘electricity' as a commodity, the same laws of economics or commercial trade arrangements may not hold good. This is because, electricity as a commodity bears different characteristics from other commodities, or rather, electricity is physically different from other commodities. This fact complicates the procedure of electricity trading. In other words, the trade is not as simple as an interaction between two entities: buyer and seller. The interdependencies of actions taken by various participants (primarily generators and loads), mandate somebody to takeover the control of real time activities. This somebody is the system operator, who makes sure that the whole system runs reliably and thus kept in synchronism. Thus, it is worthwhile to understand the distinguishing features of electricity as a commodity, which are presented next. Distinguishing Features of Electricity as a Commodity There are three basic distinguishing features of electricity. These are associated with electricity due to its physical nature. These three basic features effectively lead to one distinguishing feature of this commodity, the one that has commercial implications. Let us see these in details Real Time Demand Supply Balance Electricity can not be stored in bulk. Other commodities can be manufactured and kept in a warehouse until the demand for the same is sensed. A manufacturer of other commodities gets sufficient flexibility in planning the manufacturing activity and coordinating the dispatch. The same is not true for electricity. The demand for electricity needs to be satisfied on real time basis.

The parties involved in electricity trade perhaps would like to do it through forward contracts . These can be contracts for physical delivery or financial in nature. In many power markets, bulk trade of electricity (> 80%) is done through forward contracts. Forward contracts can be done years ahead. When a certain amount of electricity is bought in the forward contract, it is the estimate of the buyer, how much it is likely to consume during actual delivery time. However, in real time, the actual consumption may not match the predicted consumption that had been forecasted at the time of doing forward trade. This difference is called as imbalance. Knowledge about this imbalance is exposed only during real time operation or slightly before that. In this case, the system operator or some other market mechanism stands ready to make up the imbalances (either on positive or negative side). Due to storage limitation, the supply-demand matching decision needs to be done on a competitive basis by letting supply and demand interact with each other. The operator buys and sells these imbalances through some commercial mechanism. Due to this feature of electricity, an issue related to the speed of operation pitches in. The system operator, while making a provision for imbalances, has to take into consideration various network interdependencies. The system operator always has to communicate with the active participants to tell them which generators should increase their output and which ones should decrease it. This activity is called scheduling in advance and dispatch in real time. Since the system operator has to work with seconds to spare, a delivery system to make up for imbalances has to be in place. In real time, the only time available with system operator is what is allowed by the energy stored in rotating masses of huge interconnected grid. Thus, this exceptional feature of electricity leads to two issues related to power market design: Imbalances and Scheduling and Dispatch. The question is how these difficult tasks get reflected in the rules of marketplaces. Power Flows Obey Laws of Physics The electric power can not be told as to where and how it should travel, once the injection and take-off points are decided. The electric power flow over transmission lines obey laws of physics. Effectively, electric power can not be stopped from flowing on a transmission line that is already hitting its power carrying capacity. The system operator has to ensure that none of the lines get overloaded. To do this, only freedom left with it is the selection of pattern of nodal injections (either generation or load). Thus, any arbitrary set of forward contracts can not be scheduled by the system operator as this may lead to exceeding of limits of physical parameters of some of the power system elements. Allowing only the practically feasible set of transactions during scheduling and further making corrections while dispatching so as to keep line loadings within limits is usually termed as congestion management.

The concept of network congestion is shown by a simple lossless system in Figure 3.6. In this, generator A is a cheaper generator than generator B and hence, it gets a contract of satisfying the demand of load at bus 3 by generating 18 MW. The dispatch would be as shown in Figure 3.6(A). The power flow over all lines would be dictated by the reactance of parallel paths. In this case, let us assume that reactance of all three lines are same. Thus, two parallel paths are provided so as to transfer power of generator A to load at bus 3, with ratio of reactance 2:1. Obviously, the power will flow in opposite ratio on these paths. The flows are shown in Figure 3.6(A). However, if the physical properties of the line connecting nodes 1 and 2 state that it can carry only 3 MW, then the dispatch shown in Figure 3.6(A) left hand side is not practically feasible. To correct it, generator B is asked to generate 4.5 MW and generator A is asked to step down by 4.5 MW, leading to dispatch shown in Figure 3.6(B). This rearrangement of nodal injections is one of the means of congestion management, which is peculiar to electricity. We will discuss more about this in a separate module on congestion management.

Figure 3.6: Concept of network congestion

Generator Product Compatibility and Interactions To ensure reliable delivery of electricity, only generation by generators at injection points and take-off by loads at take-off points is not sufficient. The system operator must make arrangements for provision of allied services necessary to do this. These allied services are usually referred to as the ancillary services. Provision of reactive power, operating reserves are some of the commonly required ancillary services. Mostly, ancillary services are provided by generators. In this case, one is likely to witness the interdependencies involved in providing these services. In other words, the production of ancillary services is also dependent on production of energy. Then, the same generator is said to be providing two different products: energy and ancillary services.

This complicates the matter because the single generator can be simultaneously needed to produce multiple outputs, or to produce ancillary service rather than energy. This complication is shown in Figure 3.7, where, a generator's capacity is divided into various products. The defining question is how much of capacity should be allocated to each product? In centralized markets (explained later), the system operator does a joint optimization, taking into account various technical and commercial parameters of a generator to allocate it's full capacity to each of the products. module 6 is devoted to ancillary service management where these issues will be discussed more elaborately.

Figure 3.7: Generation capacity allocation to various products

Unusual Price Variation The combined effect of various peculiarities of electricity is that it has large temporal variation in its price. It is not prudent to run all generators throughout the day. Rather, the most economical generators can be run throughout the day. Effectively, the price of electricity will be low during low demand period. However, during peak demand situation, the costly generators are brought on-line and the price of electricity goes high. Thus, marginal cost of producing energy will vary throughout the day. Such rapid cyclic variations in the price of a commodity are unusual, and arise due to peculiarities associated with electricity, basically, the characteristic of matching supply and demand on real time basis. It should be noted that this peculiarity of electricity has arrived because of one of the basic physical properties associated with it. Effects of Peculiarity: Four Pillars of Market Design We have seen the characteristic features of electricity when compared with other commodities. How do these affect the trading activities of this commodity? For example, what if network congestion does not allow a set of transactions to be feasible? Should the generator sell its

generation capability in a single market that makes provision for energy as well as reserves, or should there be different markets for the same? Some subtle questions like these provide food for thought when designing criteria of markets are to be determined. Hunt in [1] has described the design issues arising out of characteristics of electricity as pillars of market design. These are:

Imbalance Scheduling and Dispatch Congestion Management Ancillary Services

Figure 3.8 shows four pillars of market design arising due to the basic characteristics of electricity.

Figure 3.8: Four Pillars of Market Design

The design of market revolves around the four pillars described above. It also depends on how and where these issues are accommodated in the whole process of market mechanism. Some of the pillars lead to creation of separate markets. Eventually, this gives rise to the issue of market architecture, which is nothing but arrangement and classification of these markets. Finally, these

markets can be integrated into one efficient market or there can be cascaded markets. The architectural aspects of market design are discussed next. MARKET MODELS BASED ON CONTRACTUAL ARRANGEMENTS As mentioned earlier, unbundling of the conventional vertically integrated power system creates groups of various commercial and technical activities. Since one of the major aims of deregulation is introduction of competition, it is worthwhile to explore every avenue where competition can be introduced. Eventually, competition provides a choice for entities to choose another entity or a group of entities to do a profitable transaction. In electricity parlance, either the load or an entity representing a group of loads gets a choice to select its energy provider, or there may exist some mechanism which would cater to the electrical energy needs of these loads at a competitive level. The former mechanism essentially requires bilateral involvement of the entities who wish to get into a power buy and sell contract. In this, the sellers and buyers mutually agree upon the terms and conditions, including the price and time of delivery. A repetitive bilateral interaction between buyers and sellers may lead to an equilibrium point where everyone is happy. Alternatively, a similar result would be obtained if a common exchange for the commodity is set up, where, buyers and sellers, instead of interacting with each other, communicate their expectations to this marketplace. This represents a simultaneous market clearing process and a common market price of electrical commodity. While moving from a vertically integrated structure to a competitive one, various policy and structural issues crop up. One of the important concerns is regarding the entity that should be allowed to take part in competitive activity. Similarly, issue of rearrangement of various elements of power system, when a new set of rules is introduced to buy and sell power, also needs to be addressed. It is obvious that the commercial arrangements and virtual boundaries between various functional entities can take many shapes and forms. Consequently, various models can be classified according to the levels at which the entities are given the choice of buying or selling electricity. Various trading models can be proposed based on the above discussion. The choice of choosing a model is a policy decision and is dominated by various prevailing conditions. They need to be accounted for before making structural changes. In [1], four basic models of industry structure are suggested. These are:

1. Monopoly model 2. Single buyer mode 3. Wholesale competition model 4. Retail competition model

Every model needs different amount of structural change and rearrangements of functions in the industry. These models are discussed next. Monopoly Model In this model, a single entity takes care of all the businesses such as generation, transmission and distribution of electric power to the end users. One of the versions of this model is shown in Figure 3.1(A). In this, a single utility integrates the generation, transmission and distribution of electricity. Usually (but not necessarily), in this kind of model, the monopoly lies with the Government. It is quite natural that this kind of model should have strict regulation in order to protect end consumers against monopoly. Most of the electric power systems followed this model prior to deregulation. Another version of the monopoly model is shown in Figure 3.1(B). In this model, generation and transmission are integrated and operated by a single utility and it sells the energy to local distribution companies, which themselves represent local monopolies.

Figure 3.1: Two different versions of monopoly model Single Buyer Model

In this model, as shown in Figure 3.2, there is competition in the wholesale sector, i.e., generation. Here, the single buyer agency buys power from Independent Power Producers (IPPs) in addition to its own generation. The power purchasing agency in turn sells it to state distribution utilities or distribution companies in the service area. All power generated by generating companies (Gencos) must be sold only to a purchasing agency and not to any other agency. Distribution companies (Discoms) are only able to purchase from the single buyer agency. They do not have a choice of choosing their power supplier. In this model, sales from power pool to retailers take place at a pre-set tariff price. The single buyer or the existing utility makes a long term contract with IPPs. A contract is necessary because, without it, a generator would be reluctant to invest large amounts of capital in a generating plant. The contracts are generally of life-of-plant type, indicating sale of all capacity of generating units for its lifetime. Figure 3.3 shows another version of this model, which has further evolved from the original single buyer model. In this model, the single buyer does not own any generation and buys all the power from IPPs. The distribution and retail activities are also disaggregated. This model has an advantage of introducing some competition between generators without the expense of setting up a competitive market. The tariff set by the purchasing agency must be regulated because it has monopoly over the Discos while monopsony over the IPPs. The single buyer model is looked upon as a way of attracting private participation in the generation sector, especially in the developing countries. In this model, transmission and distribution network can be owned and operated by State and Regional transmission utilities. Inter-state tie line should be sufficient to maintain a loose regional power pool. Merits and demerits of this model are as follows: Merits:

Private participation in power generation Introduction of some competition without expensive set up for a competitive market.

Figure 3.2: Single buyer model Demerits:

Long term contracts. Setting up a contract is problematic. No true competition. Price is not decided by demand-supply interaction. End consumers' price is regulated .

Wholesale Competition Model This model is one step closer towards competition. There is an organized market in which the generators can sell their energy at competitive rates. The market may be organized either by a separate entity or may be run by the system operator itself. There is not much choice for the end user. The end user is still affiliated to the Discom or retailer working in that geographical area of operation. The large customers or the bulk customers, so to say, are privileged to choose their energy provider. However, the definition of bulk customer is a subjective matter and changes from system to system.

Figure 3.3: Single buyer model with only IPPs This model, as shown in Figure 3.4, provides the choice of supplier to Discoms, along with competition in generation. Implementation of this model requires open access to the transmission network. Also, a wholesale spot market needs to be developed. Since this model permits open access to the transmission wires, it gives the IPPs to choose an alternative buyer. Discoms can purchase energy for their customers either from a wholesale market or through long term contracts with generators. The customers within a service area still have no choice of supplier. They will be served by a Discom in their area. With this model, the Discoms are under Universal Service Obligation (USO), as they have monopoly over the customers. They own and operate the distribution wires. The transmission network is owned and maintained either by government and/or private transmission companies. System operators manage the centrally accomplished task of operation and control.

Figure 3.4: Wholesale Competition Model The model provides a competitive environment for generators because the wholesale price is determined by the interaction between supply and demand. In contrast, the retail price of electrical energy remains regulated because the small consumers still do not have a choice for their supplier. The distribution companies are then exposed to vagaries of the wholesale price of the commodity. The merits and demerits of this model are as follows: Merits:

Choice of seller provided for Discoms and bulk consumers. The buyers and sellers can make forward contracts or buy from a wholesale marketplace. The price is decided by interaction between demand and supply. Hence, indicates truly

competitive price.

Demerits:

The end consumer still doesn't have a choice. It buys power from the affiliated Discom. Rates for end consumers are regulated rather than competitive. Discoms face competition at wholesale level, while their returns are regulated. Structural and institutional changes required at wholesale level.

Retail Competition Model

In this model, as shown in Figure 3.5, all customers have access to competing generators either directly or through their choice of retailer. This would have complete separation of both generation and retailing from the transport business at both transmission and distribution levels. Both, transmission and distribution wires provide open access in this model. There would also be free entry for retailers. In this model, retailing is a function that does not require the ownership of distribution wires, although, the owner of distribution wires can also compete as a retailer. This model is a multi-buyer, multi-seller model and the power pool in this model acts like an auctioneer. It behaves like a single transporter, moving power to facilitate bilateral trading and this is achieved through an integrated network of wires. In this pooling arrangement, there is a provision for bidding into a spot market to facilitate merit order dispatch. The pool matches the supply and demand and determines the spot price for each hour of the day. It collects money from purchasers and distributes it to producers. The advantage of this model over monopoly utilities is that competition is introduced in both wholesale and retail areas of the system. This model is supposed to be a truly deregulated power market model. The retail price is no longer regulated because small consumers can change their retailer for better price options. This model is economically efficient as the price is set by interaction of demand and supply. In wholesale competition model, with relatively few customers, all of them regulated Discoms, a spot market can be preferable but not essential. However, in retail competition model, spot markets become essential, since contractual arrangements between customers and producers are carried out over a network owned by a third party. In retail competition model, metering becomes a major problem. If the number of customers are increasing and metering capability for all the customers is not sufficient, it may create logistical problem and provoke disputes.

Figure 3.5: Retail Competition Model Merits:

Supposed to be 100% deregulated model. Every consumer has a choice of buying power. The price is decided by interaction of demand and supply. Hence, it is truly competitive

price. There is no regulation in energy pricing.

Demerits:

Need constitutional and structural changes at both, wholesale and retail level. Extremely complex settlement system due to large number of participants. Requirement of additional infrastructural support.

Comparison of Various Market Model A comparison between the four models discussed above is provided in Table 3.1. The attributes for comparison are chosen in such a manner that the difference between two truly competitive

models - wholesale competition and retail competition gets significance. It is then obvious that the monopoly and single buyer models will emerge to be similar models when compared on the chosen attributes.

Attribute Monopoly Single

Buyer

Wholesale

Competition

Retail

Competition

Degree of deregulation*

0 1 2 3

Number of buyers

1 1 Many Many

Number of

seller 1 Many Many Many

Choice

available No No

Discoms and

big customers

Everbody including

small consumers

Requirement

of spot market

No No

Preferable,

but not essential

Essential

Open access NA NA Transmission

network

Transmission as well as

distribution

network

Regulated

price to be paid by

Everbody Everbody Small

consumers None

MARKET ARCHITECTURE Stoft in [2] defines market architecture as a map of its component submarkets. This map includes the type of each market and the linkage between them. Where does this concept of multiple markets come

from? The answer can be traced back to various peculiarities associated with electricity. Four pillars of market design tend to cast the same electric energy into various products, which are characterized by separate individual markets. Moreover, there are various modes of energy contracts depending upon when energy trades are done. This again gives rise to market mechanisms based on timeline of trading.

The submarkets of a power market include the wholesale spot market, wholesale forward markets and markets for ancillary services. Somewhere in between is embedded the market for transmission capacity. This can be a separate market altogether or can be integrated with the energy market that takes place near real time. Similar is the case with ancillary service market. The best way to categorize alternative trading models is on the degree to which operational arrangements and commercial

arrangements for scheduling, imbalances, congestion and ancillary services are integrated with spot

markets. Two models are most common: integrated or centralized and decentralized.

In the rest of the module, we will give more stress on how various markets for energy and other products are organized. For the sake of understanding, we will not go into the intricacies involved in various modes of arrangement and levels of competition discussed in Section 3.2. We will just represent market by a set of sellers and buyers. For this, we do the abstraction of the market as shown in Figure 3.9, indicating sellers and buyers with some interaction facilitator. This abstraction gets rid of questions about ownership of transmission network, power exchange, distribution network, as well as doesn't

bother about whom the buyer represents or buys for its own. The relevant details about the same will be discussed at appropriate places. First, let us see how markets for energy are arranged.

Timeline for Various Energy Markets

There are many ways depending on the time of hand-shaking, where buyers and sellers can do the transaction. Figure 3.10 shows various modes of trading based on the time-line.

Following are the common modes in which the electric energy can be traded:

1. Bilateral contracts 2. Spot market

a. Day ahead markets (Power Exchange or through pool)

b. Real time market (through pool)

Figure 3.9: Abstraction of market concept

Trading for power delivered in any particular minute begins years in advance and continues until real

time, the actual time at which the power flows out of a generator and into a load. This is accomplished by a sequence of overlapping markets. The earliest amongst these are forward markets that trade non-standard, long term, bilateral contracts. This generally represents energy trading between buyers and

sellers directly for the mutually agreed price. This type of trading stops about one day prior to real time. At that point, the day-ahead market is held. The day-ahead market is often followed by a real-time market.

The term - spot market is used with different interpretations associated with it. According to definitions

in some of the systems, the spot market includes day-ahead and real-time market, while in others; it just includes the real-time market. Similarly, drawing line between spot and forward markets is not clear. According to one definition, all the markets before the real-time market can be classified as forward markets. This is because, in many forward markets, including day-ahead market, traders need not own a generator to sell power. If power is not delivered in real time, then the supplier must purchase replacement power at the real time rate and fulfill the contract. A customer who buys power in a forward market will receive either electricity delivered by the seller or a financial compensation. Any power that

is sold in the day-ahead market, but not delivered in real time, is deemed to be purchased in real time at the real time price of energy. The combination of day-ahead and real-time market is popularly known as multi-settlement market system in USA.

Another way to distinguish between forward and spot markets is by considering day-ahead and real-

time markets as spot markets, while all trades taking place before that are termed as forward or bilateral trades. This segregation emerges because both, the day-ahead as well as real-time markets provide a system price which holds for all the market trades done through it. On the other hand, in bilateral or forward trades, there is no single market price as such. In the rest of the module, we prefer to define the spot market as defined just above.

There is little doubt about what should be the nature of settlements based on timeline. Much ahead of real time, i.e., more than a week, month or years ahead, bilateral contracts provide the best manner of trading power. One is very unlikely to have bilateral contracts near real time. The reason is that the settlements of bilateral contracts take place very slowly. Near real time, it is prudent to have a centrally

organized market as the security and reliability issues can be tackled centrally rather than bilaterally. Even, the day-ahead market can be centrally organized. It can take the form of power exchange or the

pool. In other words, day-ahead market can be organized by a separate entity or it can be integrated with the system operator activities. If the latter is adopted, it is popularly known as a pool structure.

In general, real time transactions require central coordination, while week-ahead trades do not require the same. Somewhere in between are dividing lines that describe the system operator's diminishing role

in forward markets. Where to draw those lines is the central controversy of power market design. A larger role for the system operator implies a smaller role for private, profit making entities.

Bilateral/Forward Contracts

Bilateral trading generally involves two parties interacting with each other: a buyer and a seller. The characteristic of bilateral trades is that the price of a transaction is set independently by the parties involved. There is no market clearing price as such. Since, electricity can not be stored, it creates a wide

fluctuation in the spot price. Forward contracts provide generators and loads with a means of hedging their exposure to fluctuations in the spot price of electricity. The generators can negotiate a price for their output prior to the moment of producing it. Similarly, properly structured forward contracts provide

buyers with the ability to lock in a fixed price for a fixed quantity of electricity well in advance of delivery and consumption. Indeed, if a buyer's actual energy usage matches its forward market purchases, it can achieve a benefit of complete price certainty in the face of real time price volatility.

Figure 3.10: Seller buyer interaction based on timeline

Depending upon the quantity of power and time, the buyers and sellers resort to different forms of trading:

Long Term Contracts: This type of trade generally includes contract for a large amount of

power for a long time period. These types of contracts are negotiated privately and the terms and conditions are such that they suit both the parties involved in the transaction.

Trading Over The Counter: These transactions involve smaller amounts of energy to be

delivered. For example, the amount of energy to be delivered during different periods of the hour, day, etc. This type of trading has much lower transaction costs and is used by producers and consumers to refine their positions before real time.

Electronic Trading: In this, participants can enter offers to buy energy and bids to sell energy

directly in a computerized marketplace. The participants can observe the quantities and offers/ bids submitted by all participants, but do not know the party involved. The software in the exchange couples the matching offers. It checks whether for a newly entered bid, if there is matching offer whose price is greater than or equal to price of the bid. If no match is found, the bid is added to the list of outstanding bids until a new offer matches it. Otherwise, it lapses after

the market is closed. The same process is repeated after a new bid is entered. There is no market clearing price as such.

The Spot Market

As we have discussed in module 2, a market for any commodity provides an environment for buyers and sellers to interact and agree on transactions, generally, the quantity and price. These interactions progressively lead to an equilibrium point at which the price clears the market, that is, the supply is equal to demand. If electrical energy is to be traded according to a mechanism in which the buyers and sellers are free to interact individually, the equilibrium between the production and the consumption can

be set through repetitive interaction. In this scheme of attaining equilibrium, the consumers make an estimation of their consumption before entering into a contract. The generators schedule the production of their units to deliver at the agreed time the energy that they have agreed to sell. However, in practice, neither party can meet its contractual obligation with perfect accuracy because, for example, from a load's point of view, the actual demand of a group of customers is never exactly equal to the value

forecasted. Changes in weather and due to some other externalities, the day ahead or before real time estimation of load consumption can have deviation from that done few months or years back, while

doing the contract. Also, unforeseen problems may prevent generating units from delivering the contracted amount of energy.

It can be concluded that, while a large proportion of the electrical energy can be traded through an unmanaged open market in terms of forward contracts, such a market may not necessarily lead to an

equilibrium that replicates real time scenario. Thus, an intermediate stage is necessary, where a managed spot market can provide a mechanism for balancing load and generation. This market should supersede the open energy market as the time of delivery approaches. Its function is to match residual load and generation by adjusting the production of flexible generators and curtailing the demand of willing customers.

In many real life markets, more than 80% of the energy traded is through the forward or bilateral contracts. The rest is traded through the spot market. In a multi-settlement market (typically practiced

in some of the markets in USA), the spot market is sometimes made of two markets: Day Ahead (DA) market and a Real Time (RT) market. The DA market is run for each hour or half hour of the next day. The RT market is always run by a system operator, while the day-ahead market may or may not be run by the system operator. In both cases, the general principle of market clearing is the same. This and

other related issues are discussed next.

Spot Market Clearing

For the sake of understanding, let us assume that the market is run by an entity called Power Exchange (PX). The power exchange operates much like a stock exchange. The buyers and sellers enter their needs into the power exchange. For example, a buyer would say, “I need up to 20 MW between 1600 hours and1700 hours IST. I would pay INR 3.5/ kWhr”, whereas, the seller would enter his demand as, “I have 100 MW and would like to sell it at INR 4/ kWhr”.

When they transact with the power exchange, buyers and sellers are really talking to the marketplace and not the individual buyers and sellers. As in a stock exchange, the power exchange constantly updates and posts a market clearing price (MCP), which is the current price at which the transactions are being done. Note that when buyers and sellers communicate with the power exchange, they don‘t know whom they are dealing with. The general step by step process of settling this market is as follows:

1. Generating companies submit bids to supply a certain amount of electrical energy at a certain

price for the period under consideration. Usually, the period is an hour or half an hour. The bids are ranked in order of increasing price. From this, a curve that shows bid price as a function of

bid quantity is built, which is commonly known as supply curve. Supply curve is a plot with price

on y axis and quantity on x axis. 2. Similarly, demand curve is established by asking consumers to submit offers specifying quantity

and price and ranking these offers in decreasing order of price. If the load is willing to adjust its

consumption with price, the load is said to have demand elasticity. If the load is firm, the demand curve will take the form of a vertical line with x axis intersection indicating total cumulative firm demand.

3. The intersection of supply and demand curves represents the market equilibrium. At this point, the supply matches the demand. This price is known as Market Clearing Price (MCP) or System Marginal Price (SMP). All the bids submitted at a price lower than or equal to the market clearing price are accepted and the generators are scheduled for that much amount of power for that

particular time period under consideration. Similarly, all the offers submitted at a price greater than or equal to the market clearing price are accepted.

4. As for settlement, the generators are paid this MCP for every MWh they are scheduled for, while loads pay the MCP for every MWh they are cleared for.

Illustrative Example for PX Clearing

Suppose there is a central power exchange in which all players in the market send bids and offers. Table 3.2 shows the offers and bids supplied to the central power exchange for a particular hour of the next day, say 10:00 AM to 11:00 AM.

Once the buyers and sellers provide offers and bids, the power exchange forms an aggregate supply curve and aggregate demand curve. The curves are plotted on the coordinates of supply (and demand) and price as shown in the Figure 3.11. The point of intersection of the two curves determines the market-clearing price (MCP). At this point, the supply satisfies the demand.

From the intersection of supply and demand curves, the MCP would be set to 3200 INR/MWh and 450 MWh will be traded through the central power exchange. The MCP is the price of electric energy that is paid by consumers trading through the power exchange. The sellers are also paid at a price equal to the

MCP. MCP is the highest sell bid or lowest buy bid accepted in the auction. The generator ‘S2' is called the marginal generator as its bid sets the MCP.

Over and above the forward contracts, the participants trade the residuals through the power exchange. The objective of the power exchange clearing is to maximize the social welfare as explained in the earlier module. It is the sum of generator surplus and the load surplus.

Company Quantity

(MW) Price (INR)

Bids

S1 200 2400

S1 50 3000

S1 50 4000

S2 150 3200

S2 50 3400

S3 100 2600

S3 50 3600

offers

D1 50 2600

D1 100 4600

D2 50 2200

D2 150 4400

D3 50 2000

D3 200 5000

Table 3.2: Bids and offers in the power exchange

Discriminatory or Non-discriminatory Pricing?

There are few questions which are likely to remain unanswered regarding the settlement procedure adopted in the above market clearing process. One is likely to get surprised to see all of the generators

being paid the MCP, rather than at individual bid. Except the marginal generator, all other generators are willing to produce power for lesser price than the MCP. Then, why are they not paid their asking price? Paying them their asking price would have reduced the average price of electricity.

Paying generators as per their asking price is known as pay-as-bid scheme. The main reason why pay-

as-bid scheme is not adopted is that it would discourage generators from submitting bids that reflect

their marginal cost of production. Basically, the notion that the average price of electricity would decrease by adopting pay-as-bid scheme is based on the assumption that the generators would continue to bid in the same way as they do in the marginal pricing scheme. However, this is not true. All the generators would instead try to guess what the MCP is likely to be and would bid at that level to collect the maximum revenue. While doing so, some low cost generators would bid too high. Then, in the market clearing process, these generators would not get selected and be replaced by some other

generators that have higher marginal cost of production. The MCP would then be somewhat higher than it ought to be. Furthermore, this substitution is economically inefficient because optimal use is not made of the available resources. In addition, the generators are likely to increase their prices slightly to compensate themselves for additional risk of losing revenue because of uncertainty of MCP. An attempt to reduce the price of electricity would therefore result in a price increase.

On the other hand, in marginal pricing scheme, a seller is certain that it will be paid no less than its cost of production if he bids at marginal cost, and may be paid more. If a seller bids less than his marginal cost, it would lose money because his bid may set the MCP. If it bids more than its marginal cost, it may

bid more than other sellers and fail to be selected in the auction. If the seller's bid sets the MCP, then it would recover it's running cost and if the MCP is higher than it's marginal cost, then it would earn profit or contribution to fixed cost. It is worthwhile to know that the supply curve, being a derivative of

cost function, does not consider the fixed costs.

Figure 3.11: Calculation of market clearing price (multiple price by 200)

Simple Bids or Complex Bids?

In the illustrative example provided above, the generators submitted simple bids consisting of price-quantity pairs. In some system operator run markets, (typically known as centralized model, explained later), generators submit complex bids for each of their generating units. These bids are supposed to reflect the cost characteristics of the unit (including the marginal, start-up and no-load costs) as well as some technical parameters (minimum and maximum output, flexibility). Rather than simply stacking

the bids, the system operator then performs a central unit commitment that determines the production schedule and the prices for an entire day divided in periods of half an hour or an hour. For example, suppose a thermal generator with low marginal cost and high start up cost is shut down temporarily. In the centralized dispatch system, the generator submits a complex bid consisting of all details mentioned above. While doing a central unit commitment, the system operator will not only consider its marginal

cost, but will also take into account its start-up cost. On the other hand, if the market is not centrally

dispatched, only the marginal cost of the generator will be taken into account to decide its selection or exclusion.

The advantage of complex bids is that they allow the system operator to take account, the true characteristics of the generators and thus, potentially, do a more efficient job of minimizing the cost.

Setting the price becomes a disadvantage and requires a complex optimization problem to be solved.This leads to higher cost of computation & lower transparency.

Day-Ahead Market and Real Time Market

As mentioned earlier, imbalances arise due to deviation between the forward contracted amounts and the actual or near real time estimation of consumption. The spot markets are meant to provide a mechanism for handling these imbalances. However, the energy trading must stop at some point before real time to give the system operator to balance the system. How much time should elapse between this gate closure and real time is a hotly debated issue.

Large coal based thermal plants take more than an hour to start up. Such generators can not bid if the gate closure for spot market is lesser than one hour. Under these circumstances, it is beneficial to have two energy markets: a Day Ahead (DA) market in addition to Real Time (RT) market. A DA market, as its name implies, operates a day in advance of the RT market. A day-ahead market becomes beneficial as follows:

First, it can be beneficial if generators have high start up costs and start and stop each day. In a centralized dispatch model (explained later), the system operator integrates the start up costs of these

generators so as to come out with the start/stop decision in a longer term dispatch process. In other words, the time horizon for optimizing dispatch decisions is a day, not an hour or less.

Second, it can be beneficial if generators would otherwise be able to game the market to lift spot prices by withdrawing capacity at short notice - a form of market power. This form of market power is explained with the help of Figure 3.12. Figure 3.12(A) shows competitive MCP denoted as MCP1. Now suppose, if this generator company forms a coalition with Gen 7 and temporarily closes Gen 4 on the terms of sharing the profit with Gen 7. Now, Gen 7 becomes the marginal generator and sets the MCP (i.e., MCP2), which obviously is higher than the competitive MCP, as shown in Figure 3.12(B). If the system

operator needs to plan operations a few hours ahead of time and relies on generator promises of availability, then under such cases, withdrawing capacity of a generator just ahead of real time leads to calling of an expensive generation. The day-ahead contracts can remove the gaming incentive from generators because their prices are locked in day ahead, and they can't play the same game in the day ahead market because more alternatives are available day ahead than in real time.

The RT market provides volatile prices, in general. The DA market can promote demand response. If the DA price is high, the loads can choose not to buy, and they have a day to plan for alternative arrangements.

Figure 3.12: Change in MCP when capacity is withdrawn

MODELS FOR TRADING ARRANGEMENTS

As mentioned earlier, the decision about the market architecture is dominated by the factor - how

strongly the allied markets are integrated. The electrical energy takes different forms in different markets. In other words, same electrical energy is valued as different products in different markets. If the peculiarities associated with electricity would not have been there, then the four pillars of market design would have been absent and electricity as a commodity would have been treated at par with the other commodities. Then, the players in the market would only bid or play for price and quantity. However, due to peculiarities of electricity, apart from energy market (bilateral or spot), other markets also come into picture in which electricity, as a product, takes different forms. This fact strongly

influences the decision about the dispatch philosophies or in other words, the short-term trading arrangements.

The dispatch philosophies are based on the degree to which the operational and commercial arrangements for scheduling, imbalances, congestion and ancillary services are integrated with spot

markets. Depending upon how various markets associated with the four pillars are arranged, the market dispatch procedures take the form of cascaded markets or integrated markets. Broadly speaking, the integrated markets lead to economic efficiency at the cost of loss of transparency. On the other hand, cascaded markets though inefficient, provide transparency. Keeping this in mind, the dispatch philosophies or rather, the short-term trading arrangements can be classified into two broad categories:

1. Integrated or Centralized Dispatch 2. Decentralized Dispatch

As the name suggests, the integrated model is integrated with strong linkages between various aspects stated above. On the other hand, decentralized markets provide scattered efforts for various arrangements in a power market.

One of the essential differences between integrated and decentralized markets is whether or not the

system operator administers a spot market integrated with the pricing of energy imbalances, congestion management and ancillary services. The integrated model mandates the SO to run the spot market, integrated with imbalances, and the others. On the other hand, the decentralized model attempts to keep the spot market separate from the system operator, to be organized off-line by the traders.

Integrated or centralized markets are now being commonly employed in USA. In this, the system operator schedules forward contracts at the request of traders, but also takes bids from traders to modify scheduled contracts and to provide energy imbalances, congestion management and ancillary services. The system operator runs the spot market using large computer optimization program, and by doing so, the system operator minimizes the overall cost of these services.

The decentralized model was employed in earlier Californian market (now it has moved towards integrated model) and also in UK after adopting NETA3. In this model also, the system operator

schedules traders' contracts. However, the spot market is held separately and the decisions of the same are conveyed to the system operator. The system operator has to administer arrangements for imbalances. As far as possible, the traders run the spot market and manage congestion, while separate arrangements are set up for ancillary services. The decentralized model requires not only private

markets for regular energy to cater to imbalances of forward markets, but also markets for congestion energy and markets for ancillary services. As mentioned in [1], in a liquid and efficient market, all these separate products will be exchanged at the same price, time and place. However, the decentralized model does not ensure that the prices of all these different products converge. This may be looked upon as an inefficiency. The integrated model, on the other hand, integrates energy of imbalances,

congestion, reserves and spot sales together and sells at the spot price determined by the system

operator, achieving economical efficiency in the dispatch process.

In the following sections, we intend to provide more details on the concepts of centralized and decentralized markets, particularly comparing them on the following aspects:

1. Imbalance energy 2. Congestion Management 3. Ancillary Services

Integrated or Centralized Model

The schematic of centralized dispatch model is presented in Figure 3.13. As shown, the joint optimization of all markets is done by the system operator. It should be noted that the energy market refers to the

short term competitive market or the spot market, as defined in this module. As shown in the figure, the buyers and sellers provide their bids and offers to the system operator. The buyers in this model supply the complex bids. The system operator then performs the central unit commitment, taking into account the complex bids. The system operator accomplishes this by solving a complex optimization problem, typically known as Security Constrained Economic Dispatch, in USA market context. The outcome of this dispatch is the nodal prices, popularly known as Locational Marginal Prices (LMPs). If

the losses are neglected and the network constraints are non-binding, the outcome of this dispatch and that shown in Figure 3.11 carry the same meaning. In other words, all LMPs would come out to be the same which means nothing but common MCP to all. However, this market clearing is influenced and altered if the network capacities are congested and then the nodal LMPs would come out to be different. In other words, the network congestion is implicit to this type of market clearing.Some of the important features of this dispatch philosophy are discussed next.

Figure 3.13: Centralized Dispatch

Treatment of Imbalances

How contracts and imbalances are tackled in the integrated model? If the system operator does the central unit commitment using a complex optimization process, how are the forward contracts accommodated? These are a couple of questions which need further explanation.

In the integrated dispatch model, all differences between contract positions and actual production, consumption, regardless of cause, are traded at the market prices (spot prices) that come out of the system operator's central optimization process and the forward contracts in the integrated model remain financial in nature only. Whenever the traders make bilateral contracts in the integrated structure, it is not necessary for the system operator to know anything about the bilateral or forward contracts. This is because the system operator runs the least cost dispatch optimization program to come out with

locational spot prices and the settlements are done based on these locational spot prices (LMPs). The effect of central optimization for least cost dispatch is that every generator is scheduled by the system operator irrespective of its forward contract obligation. Thus, it may so happen that a generator has contractual obligation of 20 MW and the system operator in fact, may schedule this generator to produce

zero MW! The effect of getting into a forward contract is then left only as a risk hedging tool by locking

in to some earlier decided prices. We will see more of this in the module on risk hedging.

Sometimes due to operational constraints, the generation units are required to be scheduled, rather than shutting them down. In this case, the generators are said to do self scheduling. In other words, the system operator, while running its least cost optimization program, must schedule the MWs offered by this generator. This is also known as inflexible bidding. The system operator, while running its optimization program, shows this generator as a zero priced bid, so that it gets selected. Similarly, for load, it shows the self scheduled load as an infinitely priced offer.

What is the effect of offering either a flexible or inflexible bid on revenues to generators? Let us see the generator's perspective in case of flexible and inflexible bid submission in the spot market. Suppose, a generator has a bilateral contract for 100 MW and its marginal price is INR 3000/MW. Now, there are two choices for this generator.

1. Submit an inflexible bid. It can specify that, regardless of price, the system operator should

schedule this generator to inject 100 MW. 2. Submit a flexible bid. It can specify that anything up to its maximum capacity can be dispatched

by the system operator, as long as spot price exceeds its marginal price, i.e., INR 3000/ MW.

The first option essentially replicates the decentralized model. In this, the operator is meant to schedule the bilateral transactions physically. However, in case 2, if the spot price falls below INR 3000/MW, the generator will not be dispatched by the system operator, as per the least cost dispatch criteria. However, the requirement of load involved in the bilateral contract will still be satisfied. It is equivalent to meeting the generator's contract by purchasing electricity (i.e., imbalances) in the spot market at a lower rate than its running cost. Alternatively, if the spot price rises above INR 3000/MW, the system operator will dispatch all MWs of this generator. It is easy to conclude that in either of the circumstances, the

generator is better off being flexible than being inflexible. Indeed, in practice, in the integrated markets that are operating, much of the generation is offered as flexibly as its production characteristics allow.

When all market participants are flexible, willing to modify operations from their contracted levels if profitable, the system operator's dispatch is fully separate from forward contracts. The forward contracts

then become financial in nature only. The system operator will only know about a contract if the traders involved have chosen to be inflexible. In case of all generators opting for flexible bids, it is not relevant also for the system operator to know about the contract schedules.

Congestion Management

The process of congestion management is implicit to market operation of the integrated system. Congestion is solved as an integral part of the calculation of the least cost dispatch, where cost is defined by generator bids. The system operator uses the information regarding the bids and network condition to determine the most economical way to operate the system within the physical constraints using optimization software.

Pricing for congestion (i.e., the price charged for transporting electricity over scarce transmission) is also straightforward. Traders who schedule contracts across valuable transmission lines are charged for transmission usage which is equal to the energy price difference between the two ends of a transaction. As mentioned earlier, the energy price at each node is calculated by the system operator using central

optimization process. Congestion management and its pricing are thus integrated with energy pricing in the integrated model.

Ancillary Services

Though as good as 40 ancillary services can be listed, when it comes to classification of market models

based on ancillary services procurement, they essentially refer to the capacity of generators to provide reserve. The reserves are not a separate service from energy, they are options to buy energy if required. They should be priced as options to call energy in the spot market. However, complicating factor is that

the same generating unit can provide energy in the spot market, as well as can act as a reserve. Hence, the system operator's dilemma is about how much of it should be scheduled in the spot market and how much should be kept idle as a reserve.

In the integrated or centralized markets, depending on various technical criteria, the system operator

does a joint optimization of energy and reserve market so that optimum scheduling is done with minimum cost as well as appropriate amount is kept for reserve in the optimal fashion. More details on this issue are provided in the module on ancillary services management.

Decentralized Model

The decentralized and integrated models are most clearly distinguished by the different roles of forward/bilateral contracts in the procedures used to schedule and dispatch generation. While the

integrated model treats the contracts essentially as financial agreements, and dispatches generators to minimize overall costs, the decentralized model requires the system operator to schedule the system explicitly using the contracts. Thus, transaction is treated as a basic unit to be accommodated in real time system operations.

In all trading models, market participants can make and trade contracts in diverse markets separate from the system operator. The contracts could be one-to-one contracts or obtained through an organized trade. At some predetermined moment prior to real time operations, however, the system operator has to take over to deliver the contracts. The system operator is not intended to facilitate a spot market - he simply schedules trades that have been arranged elsewhere. While transferring transactions to the system operator for scheduling, the condition that the amount bought should be equal to sold should be satisfied. Each seller must have a buyer and each buyer a seller. The aim of decentralized model is to

leave as much of the trading as possible to the traders, whereas, in the integrated model, on the day

ahead and in real time, the system operator makes the trades by following instructions incorporated in the traders' bids.

The schematic of decentralized dispatch model is presented in Figure 3.14. As shown, the energy market

is not an integral part of system operator's activity and essentially depends on an external activity exclusive from the system operator.

Figure 3.14: De-centralized Dispatch

Treatment of Imbalances

The participants of various forward trades wish to balance their positions near real time. This is generally

accomplished through a spot market. This provides a common clearing price for imbalances, which is competitive in nature. If a decentralized system has market based imbalance prices, then that price becomes the price at which the system operator will buy or sell energy. The market based price of imbalances provides a reference price for forward contracts. When participants sign contracts, the contract prices are directly compared with the expected imbalances prices as imbalance provides direct substitute for contract energy. The spot market for the imbalance energy is generally run by a power exchange, where the participants submit simple price-quantity bids rather than complex bids.

Congestion Management

Congestion management in decentralized model can occur in one of the following ways:

1. Allocation of transmission rights on pro-rata basis 2. Allocation of transmission rights on first come first serve basis 3. Auction of available transmission capacity 4. Special case of zonal pricing with market splitting 5. Pro-rata curtailment in case of contingent situation

The first two approaches are not essentially the market based solutions. They don't reflect the willingness of a trader to pay for obtaining transmission rights. These methods do not take into account the network element interdependencies. On the other hand, the third option, i.e., of auctioning of capacity rights reflects traders' willingness to pay. The fourth option, i.e., special case of zonal pricing, separates markets across the transmission bottleneck and imposes a congestion fee for a bilateral

transaction taking place across the transmission bottleneck. The last approach, i.e., curtailment, is more

of congestion alleviation technique invoked in real time.

For all these methods, a different solution needs to be worked out to manage the congestion in real time. In the decentralized model, the system operator will only deviate from the final contract schedules in the dispatch if he needs to do so in order to maintain security, and may not make efficient trades

even if the traders ask him to since there is no bidding mechanism for them to do so. It should be noted that congestion management is not implicit with market clearing process. Transmission capacity allocation needs to be done explicitly.

Ancillary Services

Unlike in the centralized model, the system operator procures all types of ancillary services generally by making long term bilateral contracts with generator. It is obvious that this is not the best possible way of obtaining reserves, though it gets rid of complexities associated with joint optimization of energy

and reserves market and lack of transparency associated with it. There is a possibility that the reserves are procured on market basis. However, in decentralized system, it takes the form of cascaded markets.

In other words, after passing through forward contracts and spot market, the generators provide rest of their capacity to reserves markets, subject to technical compatibility, with the needs. This arrangement can take the other form in the sense, the generators get involved in long term contracts for reserves and after subtracting for forward energy contracts, the rest is offered in the spot market for balancing. There is no joint optimization as is done in the centralized dispatch market.

Comparison at a glance

The conclusion of the discussion on centralized dispatch and decentralized dispatch is provided in Table 3.3 by comparing the various aspects of two models.

ISO MODEL OR TSO MODEL

In section 3.2, we have seen how various trading arrangements take different forms depending on the

interaction between various entities of the market. In all the four models presented in section 3.2, the issue of ownership of transmission and distribution network is not discussed. The restructured power system models across the world can also be classified according to the ownership of transmission network. Rather, more clear distinction would be based on whether the system operator itself is owner of the transmission network or somebody else owns it. In ISO (Independent System Operator) model, the owner of transmission network is different from the system operator. In TSO (Transmission System Owner) model, system operator itself owns the infrastructural investments. This arrangement is seen in

most of the developing countries.

ISO Model

ISO model is practiced in those countries in which transmission companies are also providing the generation and distribution services in their area of operation. Further, in these countries, sufficient number of equal sized transmission companies exists in the market and it is not possible to club the system operation function with any of these companies for commercial reasons. Therefore, separation of ownership of the transmission assets from the system operation function is considered necessary to

avoid any preferential treatment for dispatching its own generation.

No Atrribute Centralized

Model Dcentralized

Model

1 Unit

Commitment Central Individual

2 Reserve

Reservw

market

integrated

with spot

market

Separate

reserve

market or

obtained

through long

term

contracts

3 Basis for

scheduling

Bids abd

offers of

participants

Individual

schedules

arising out

of bilateral

transactions

4 Imbalances

Integrated

with spot

market

Generally

through day-

ahead

market

5

Involvement

of system

operator in

day- ahead

market

Yes No

6 Congestion

Management Implicit Explicit

7

Significance

of forward

contracts

Risk hedging Physical

obligation

8 Example

SMD market

in USA like

PJM, ISO-

NE

NETA in

UK Nordic

pool

Table 3.3: Comparison between centralized and decentralized dispatch models

TSO Model

In TSO model, operation and ownership of the grid are integrated into a single entity which is responsible for development of transmission system and to provide non-discriminatory open access to all eligible market participants. It is also responsible for system operation functions. Neutrality is an important aspect of the TSO to ensure an efficient market. This model is prevalent in the whole of the Europe.