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SUMMER INTERNSHIP REPORT

Scenario Analysis of Coal Based Thermal Power Plant under Case 1 and Case 2 Competitive Bidding Frameworks

Under the Guidance of

Mr. N. R. Haldar, Deputy Director, CAMPS, NPTI&

Mr. Nilay Dave, Joint General Manager, Essar Power LtdAt

Essar Power Limited, HaziraSubmitted By

AGAM KUMAR

Roll No.-1120812186

MBA (POWER MANAGEMENT)

(Under Ministry of Power, Gov. of India)

Affiliated to

MAHARSHI DAYANAND UNIVERSATY, ROHTK

AUGUST 2012

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CHAPTER 1

INTRODUCTION, PROBLEM STATEMENT, SCOPE & OBJECTIVES

1.1. INTRODUCTION

India is one of the fastest growing economies in the world and growth of power sector is the key to the economic development. Growth in production of electricity has led to its extensive use in all the sectors of economy in the successive five years plans. Over the years the installed capacity of Power Plants (Utilities) has increased to about 205340.26 MW (as on 30-06-2012) from a meager 1713 MW in 1950. Similarly, the electricity generation has increased from about 5.1 Billion kWh to 811 Billion kWh in 2010-11. The per capita consumption of electricity in the country also increased from 15 kWh in 1950 to about 814 kWh in 2011. Its power consumption is increasing at a very high rate due to fast industrialization, urbanization and population growth.

Figure1.1:Annual Energy Generation and Growth Rate during 2001-2011

Source: CEA

The per capita electricity consumption in India is 24% of the world’s average and 35% & 28% respectively that of China and Brazil. The Government of India has targeted to raise the availability of electricity to 1000 units per capita by 2012 in its National Electricity Policy (NEP).

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Figure1.2: per Capita Electricity Consumption in India

Source: CEA

However, there exist several challenges that need to be addressed to achieve the objectives of the

National Electricity Policy. One of challenge is to manage the resources to meet the demand.

India witnessed a peak power shortage of 10.3% and energy shortage of 8.5% during the year

2010-2011.

Figure1.3: Energy Deficit and Peak Deficit during 2010-2011

Source: CEA

The other important challenge is adequate and timely addition of capacity. During 11th plan, GOI had set target to add 78700 MW of additional capacity but it achieved only 41000 MW of revised target of 63000 MW.

Figure1.4: Percentage of Target Achieved in the previous plan period

Source: CEA

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(Deficit %)

(Deficit %)

Taking note of the above issues, the Electricity Act 2003 emphasized on competitive bidding framework to encourage private participation in generation segment. As per Section 63 of the Act, regulator has to adopt the tariff determined through competitive bidding according to the guidelines issued by the Government of India under the Competitive Bidding Guidelines, 2005.

The Competitive Bidding Guidelines (CBG) was issued in Jan 2005 to enhance transparency and fairness in procurement of power by utilities. Ever since the introduction of CBG about 42605 MW of capacity have been awarded under Case 1 and Case 2 bidding.

While an encouraging response from the developers has validated the utility of a transparent bid process based on standard documentation, several issues have emerged that need to be addressed. As a consequence of these issues beyond control of developers and investors, private sector interest is showing signs of fading. The CBG is also necessary because 50% - 60% of total capacity addition during 12th plan is to be done by the private sector and failure to address the issues seriously put at risk the capacity addition prospects in the country.

In order to analyze the competitive bidding framework, it is necessary to understand the key objectives of the framework, the bidding process and the governing policies laid down in the Competitive Bidding Guidelines (CBG).

1.2. PROBLEM STATEMENT

For the past few years both the Central Gov. and the State Governments have adopted the process of tariff based competitive bidding for allotting thermal power plants. But there are many problems associated with this process that are demoralizing the developers. These problems need urgent attention of the policy makers and the problems are:

Shortage of fuel(coal & gas); Changes in international laws; Environment and forest clearance; Land acquisition problem; Delay in placement of orders – mainly Civil Works and Balance of Plants(BOPs); Inadequate deployment of construction machinery; Contractual dispute between project developer and contractor and their sub vendors/ sub-

contractors; Shortage of skilled manpower for erection and commissioning; Inadequate infrastructure facilities like reliable construction power supply and constraints

in transportation of heavy equipment; Similar bid document for both gas and coal based power plants.

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1.3. OBJECTIVE OF THE STUDY

The objectives of this study are:

To analyze the present scenario of competitive bidding; Relevance of the bidding process and standard bid document (SBD) in present scenario; To analyze the tariff resulted through Case 1 & Case 2 competitive bidding frameworks; To find out the barriers in smooth implementation of the competitive bidding

frameworks; To suggest possible and feasible remedial solution of the problems; To find out various cost associated with tariff calculation through financial modeling.

1.4. SCOPE OF THE STUDY

The study analysis the growing demand of the power sector with special impetus on the mechanisms followed for the allotment of power plants. The project also takes into account the power plants allotted to either private players or public sector players after tariff based competitive bidding mechanism replaced the MOU based mechanism and the tariff resulted under the mechanism. Here financial modeling of 2*660 MW coal based power plant, based on supercritical technology has been done. The project also mentions several suggestions and recommendations that present a true roadmap for the future of the competitive bidding mechanism and the way forward.

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1.5. ORGANIZATIONAL PROFILE

1.5.1. ABOUT THE ORGANIZATION

The Essar Group is a global conglomerate and a leading player in the sectors of Steel, Energy (Oil & Gas and Power), Infrastructure (Ports, Projects & Concessions) and Services (Shipping, Telecom, Realty and Business Process Outsourcing). With operations in more than 25 countries across five continents, the group employs 75,000 people and has revenues of US$ 27 billion.

Essar began as a construction company in 1969 and diversified into manufacturing, services and retail. Over the last decade, it has grown through strategic global acquisitions and partnerships, or through Greenfield and Brownfield development projects, capturing new markets and discovering new raw material sources.

The Essar Group is widely regarded as a responsible and conscientious global employer. It has experience in managing businesses in different geographies with a culturally diverse workforce. The Group's people strategy is focused on promoting a learning culture that continually enhances the professional skills of its employees.

The combined assets of Essar Power and Essar Oil constitute Essar Energy.

1.5.2. VISION OF THE ORGANIZATION

“To be respected as global entrepreneur through the power of Positive Actions.”

People- Nurture our people with care.

Progress- Responsive with new opportunities

Power- Synergy through global presence

Passion- Winning spirit in everything we do

1.5.3. MISSION

Be responsive to Customer needs, deliver optimal solutions and value added services. To achieve excellence in project execution, quality, reliability, safety, and operational

efficiency. Ensure sustainable growth and professional excellence using state-of-the-art technology,

process driven approach, eco-friendly solutions and IT enabled tools. Foster a culture of mutual trust and employee empowerment to provide a conducive

atmosphere to work. Adhere to fair, transparent and ethical practices in interactions with all shareholders and

be a good corporate citizen. Be flexible and agile to continually adapt to changing business environment.

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To improve the lives of local community in all our projects. To be a partner in nation building and contribute towards the India’s economic growth.

1.5.4. PORTFOLIO OF BUSINESSES AND SERVICES:

Steel Business

Oil & Gas Business

Power Business

BPO & Telecom Services Business

Shipping Business

Port Business

Projects Business

1.5.5. ABOUT ESSAR POWER LIMITED

Essar Power is India’s leading power producers with a 14-year operating track record. The company has five operational power plants in India and one operational power plant in Algoma, Canada, with a total installed generation capacity of 2,800 MW. The company plans to have 4,510 MW of operating capacity by the end of March 2013 and 9,670 MW by the end of 2014.

1.5.6. ACHIEVEMENTS OF THE CONPANY

India’s 1st new generation, independent power plant in Hazira. Growing portfolio of gas, coal and liquid fuel-based power plants Owns about 800 million tons of coal reserves and resources in blocks spread across four

continents and One of the lowest cost power producers Expanding in the transmission sector; first private power company to get a transmission

license

1.5.7. PROJECTS UNDER CURRENT OPERATION

Essar Power & Bhander Power, Hazira, Gujarat- 515 MW & 500 MW Vadinar Power & Vadinar P1, Gujarat- 120 MW &380 MW Salaya 1, Gujarat- 1,200 MW Algoma Power Plant, Canada- 85 MW

1.5.8. PROJECTS UNDER CONSTRUCTION

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Mahan 1, MP- 1,200 MW Vadinar P2 & Hazira II, Gujarat- 510 MW & 270 MW Para dip & Navabharat I, Orissa- 120 MW & 1050 MW Tori I & II, Jharkhand- 1,200 MW & 600 MW Salaya II & III, Gujarat- 1,320 MW & 600 MW

1.5.9. BEYOND BUSINESS

Essar Foundation: Essar Foundation is leading CSR efforts across Essar business and locations in India. The thrust of the efforts is education, entrepreneurship, health and environment through institutional partnerships and employees volunteering programs.

Education: Community outreach initiatives, Essar International School, AVID’s school of continuous learning

Entrepreneurship: Tie-ups with premier educational institutions, Sponsoring entrepreneurship events, Knowledge sharing expert sessions.

Environment: HSE practice on par with global standard, Climate change initiatives, Model village concept.

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CHAPTER 2

LITERATURE REVIEW, POLICY AND RESEARCH METHODOLOGY

2.1. LITERATURE REVIEW

Richard P. Rozek et al (1989): A number of states as well as the Federal Energy Regulatory Commission have been considering whether traditional regulatory regimes in electricity and natural gas markets should be replaced with competitive bidding systems. This shift is designed to yield a more efficient allocation of energy resources within the existing legal framework The paper examines both the theoretical basis and empirical evidence on bidding processes in light of the characteristics of energy markets, especially electricity markets. It then discusses the extent to which one can draw policy conclusions about designing specific bidding processes for these markets. It concludes that given the underlying complexity of the products involved, the optimal system for procuring power should include a mix of bidding negotiation and utility construction. There exists the potential for gaming such as strategic bidding by participants (power suppliers and large consumers) in a deregulated power market, which is more an oligopoly than a laissez-faire market. Each participant can increase his or her own profit through strategic bidding but this has a negative effect on maximizing social welfare. A method to build bidding strategies for both power suppliers and large consumers in a pool co-type electricity market is presented in this paper. It is assumed that each supplier/large consumer bids a linear supply/demand function, and the system is dispatched to maximize social welfare. Each supplier/large consumer chooses the coefficients in the linear supply/demand function to maximize benefits, subject to expectations about how rival participants will bid. The problem is formulated as a stochastic optimization problem, and solved by a Monte Carlo approach. A numerical example with six suppliers and two large consumers serves to illustrate the essential features of the method.

Michael H. Rothkopf et al (1994): In analyzing bidding, modeling matters. The paper is critical analysis of the models available to aid competitive bidding decision making- bidding strategy and auction design-in real transactions. After an introductory overview, this paper describes the contexts in which auctions arise, reviews the mainstream theory of single, isolated auctions and discusses the important work involved in enrichment of this theory. In doing so, it indicates results that have been obtained and the sort of changes in analytical approach that are needed to tackle other critical enrichments, the paper summarizes briefly what is known about the direct use of models by bidders and auction designers. A general theme of this paper is that enriched models are needed to bring bidding theory closer to direct applicability in decision making. Bidding is important. The volume of economic transactions conducted by competitive bidding gives importance booth to study of auctions as part of basic research in economics and management science, and to the evaluation of the assistance bidding practitioners can get from the advances made in auction theory. Both concerns gain further importance from the role of competitive bidding as per archetypal formalization of competitive exchange. Those interested in the general topic of decision making in the face of both competition and uncertainty have found

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auction and bidding a fruitful area of study. Auctions have the added structure imposed by formal rules of exchange and price discrimination, and auction yield data. Hence, results for general economic models have been preceded by qualitatively similar results developed for the special case of auctions.

G. Strbac et al (1996): The paper discusses the importance of simultaneous plant production and demand reduction scheduling which is required for the establishment of a full electricity market where demand-side has opportunity to compete with generators, as is the case with the England & Wales Pool’s demand-side bidding (DSB) scheme. It also emphasizes that demand cannot be generally treated as negative generation because of the ability of demand to redistribute itself in response to price based load management activities. In that sense, an adequate scheduling methodology of available resources (from supp1) - and demand-sides) is needed to facilitate the new market. However, traditional formulations of the plant scheduling problem are not valid when load reduction is available, as gross demand is not known in advance. For that purpose a composite model for optimal generation and demand reduction scheduling is presented in the paper. It is shown that this model can be used for a comprehensive evaluation of possible scenarios or the implementation of demand-side bidding into the electricity market and the assessment of the influence of DSB on total production costs, system marginal price (SMP) profile, capacity element payments and benefit allocation between producers and consumers. In this paper a framework is developed for a comprehensive evaluation of possible scenarios for the implementation of DSB into the electricity market and the assessment of the influence of DSB on total production costs, SMP profile, capacity element payments and benefit allocation between producers and consumers. The proposed composite model is capable of dealing with supply and demand-side bidders simultaneously. For the practical implementation of the full market, a suitable philosophy has to be developed. The presence of large differences between SMP and load reduction marginal benefits has to be adequately addressed, requiring that both short-term and long-term implications should be investigated further.

Ahmuel s. oren et al (1997): The main thesis of this paper is that passive transmission rights such as transmission congestion contract (TCC) that are compensated ex-post base on nodal prices resulting from optimal dispatch by an Independent System Operator (ISO) will be presented by the strategic bidding of the generators. Thus, even when generation is competitive, rational expectation of congestion will induce implicit collusion enabling generators to raise the bid above marginal costs and capture the congestion rents, leaving the TCCs uncompensated. These conclusions are based on a Cornet model of competition across congested transmission links where an ISO dispatches generators optimally based on bid prices. We characterize the Cornet equilibrium in congested electricity networks with two and three nodes. We show that absent active transmission rights trading, the resulting equilibrium may be at an inefficient dispatch and congestion rents will be captured by the generators. We also demonstrate how active trading of transmission rights in parallel with a competitive energy market can prevent the price distortion and inefficient dispatch associated with passive transmission rights.

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George Gross et al (2000): This paper reports on the development of a comprehensive framework for the analysis and formulation of bids in competitive electricity markets. Competing entities submit offers of power and energy to meet the next day’s load. We use the England and Wales Power Pool as the basis for the development of a very general competitive power pool (CPP) framework. The framework provides the basis for solving the CPP dispatcher problem and for specifying the optimal bidding strategies. The CPP dispatcher selects the winning bids for the right to serve load each period of the scheduling horizon. The dispatcher must commit sufficient generation to meet the forecasted load and reserve requirements throughout the scheduling horizon. All the unique constraints under which electrical generators operate including start-up and shut-down time restrictions, reserve requirements and unit output limits must be taken into account. We develop an analytical formulation of the problem faced by a bidder in the CPP by specifying a strategy that maximizes his profits. The optimal bidding strategy is solved analytically for the case of perfect competition. The study in this work takes into account the principal sources of uncertainty—the load forecast and the actions of the other competitors. The formulation and solution methodology effectively exploit a Lagrangian relaxation based approach. We have conducted a wide range of numerical studies; a sample of numerical results is presented to illustrate the robustness and superiority of the analytically developed bidding strategies. This paper has reported the development of a competitive power pool (CPP) framework which incorporates the salient features of the England and Wales Power Pool (EWPP). We have applied the framework to formulate and determine the optimal bidding strategies of a bidder in the CPP under conditions of perfect competition. This paper’s results are noteworthy for the explicit inclusion and detailed representation of the various considerations and constraints associated with the generation for electrical power. We have developed a globally optimal bidding strategy: regardless of generation resources, costs and constraints, a generator maximizes profits by bidding to supply generation at cost and at maximum capacity. The increasing interest in the POOLCO concept (Bud raja and Woolf, 1994) makes this work highly topical. This paper has focused only on one aspect of CPP—the optimal bidding strategy problem for generators. The recent introduction of demand side bidding into the EWPP has introduced a problem which can be effectively solved using the CPP framework. There are several facets of the CPP that require additional work. For example, the optimal bidding strategy problem for buyers from the CPP may be formulated as a bid to optimize profits given resources, constraints and costs. The oligopoly situation in the EWPP generation markets (Green and Newbery, 1989) has thus far been resistant to analytic approaches. The construction of optimal bids by the method of this paper may provide little insight into the formulation of optimal bids under no perfect competitive conditions. Approaches based on other concepts such as game theoretic notions need to be explored. Another extension of this work is the study of the integration of financial instruments such as contracts and futures into the CPP. An area which requires considerable work is the incorporation of transmission constraints and pricing (Wu et al., 1994) into the CPP framework. There are some fundamental difficulties in the development of appropriate schemes for the economically efficient pricing of transmission services. Research into this area is currently underway.

Shangyou Hao et al (2000): This paper models bidding behaviors of suppliers in electricity auction markets under clearing pricing rule and with some simplified bidding assumptions. Optimal bidding strategy of suppliers is derived by solving a set of differential equations that

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specify the necessary conditions for bidders to maximize their expected payoffs. The derived result indicates that bidders have incentives to mark up their bids above their costs of production. The amount of markup depends on the probability of winning below and on the margin that are computed from the cost distribution of all suppliers, market demand, and the number of suppliers participating in the auction. Bidding behaviors under a simple auction market are modeled in this paper. Under clearing price rules, a generator winning the electricity auction on the margin will be paid at their bid price. Thus, to a generator on the margin, the auction is no different from first price auction. Before submitting a bid, a bidder would estimate the probability of being on the margin and how others would act. Bidders will select their bids above their costs to maximize their expected payoffs that are characterized by their profits from winning weighted by the probability of winning. The main results of the paper describe how generators would construct their bids under clearing pricing rule and conditions speculated in our model. The paper shows that bidders have no incentives to bid their true costs under the uniform pricing rule. Instead generators will likely mask their bids above their costs of production to hedge against the possibility of winning on the margin. Insights can be gained from this theoretic development even though the assumptions used in our model may not readily hold in most practical situations. It is difficult to develop a bidding strategy that takes into consideration many constraints and parameters. A practical strategy may need to consider ramping limits and hence couple the 24 hourly scheduling into one auction. Portfolio bidders may need to alter the strategy to maximize their expected payoff of their portfolios, not that of the individual generators. The actual number of bidders participating in the auctions and the exact demand are unlikely be known to bidders; information of bidder’s cost distribution are often out-dated even if available. Nevertheless, as a theoretic model, the bidding strategy developed will still serve as a valuable tool to guide the design and operations of the electricity markets and can reveal many salient characteristics of the clearing pricing mechanism and bidder behaviors.

Javier Contreras et al (2002): The new competitive framework that has been established in several electricity markets all over the world has changed the way that electric companies attain benefits. Under this new scenario, generation companies need to develop bidding models not only for the sake of achieving a feasible dispatch of their units, but also for maximizing their benefits. This paper presents a new bidding strategies model which considers the global policy of a company, but also specifies the bid of each generating unit. The proposed model produces a maximum price bid and an optimal bidding quantity by means of an iterative procedure using the generating company’s residual demand curve. It is based on an economic principle known as the cobweb theorem, frequently used to study stability in trading markets. A realistic case study from the Spanish daily electric market is presented to illustrate the methodology. A new bidding method for day-ahead electricity markets has been presented. It is based on the cobweb model, a simple dynamic model of cyclical demand and supply in which there is a time lag between the responses of producers to a change in price. The proposed methodology provides optimal price and quantity bids for a generating company, given the predicted (or actual) hourly residual demand curves, even if these curves cannot be expressed as functions. The cobweb model starts with an estimation of the hourly prices and produces a series of iterations of prices and residual demand slopes based on a first order approximation of the residual demand curve around a price. After a series of bounded iterations, the obtained solution is robust, since it does not depend on the starting point, but on the shape of the residual demand curve. The convergence of the method is based on a simple comparison between the bidding and residual demand slopes. Therefore, the

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knowledge or a good estimation of these demand curves is essential to obtain good results. The method has been successfully implemented to solve a realistic example of a generating company that bids in the Spanish day-ahead market. Future research will implement an equilibrium price model where small agents may modify their residual demand slopes simultaneously, according to several heuristic rules.

Javier Contreras et al (2002): The new competitive framework that has been established in several electricity markets all over the world has changed the way that electric companies attain benefits. Under this new scenario, generation companies need to develop bidding models not only for the sake of achieving a feasible dispatch of their units, but also for maximizing their benefits. This paper presents a new bidding strategies model which considers the global policy of a company, but also specifies the bid of each generating unit. The proposed model produces a maximum price bid and an optimal bidding quantity by means of an iterative procedure using the generating company’s residual demand curve. It is based on an economic principle known as the cobweb theorem, frequently used to study stability in trading markets. A realistic case study from the Spanish daily electric market is presented to illustrate the methodology. A new bidding method for day-ahead electricity markets has been presented. It is based on the cobweb model, a simple dynamic model of cyclical demand and supply in which there is a time lag between the responses of producers to a change in price. The proposed methodology provides optimal price and quantity bids for a generating company, given the predicted (or actual) hourly residual demand curves, even if these curves cannot be expressed as functions. The cobweb model starts with an estimation of the hourly prices and produces a series of iterations of prices and residual demand slopes based on a first order approximation of the residual demand curve around a price. After a series of bounded iterations, the obtained solution is robust, since it does not depend on the starting point, but on the shape of the residual demand curve. The convergence of the method is based on a simple comparison between the bidding and residual demand slopes. Therefore, the knowledge or a good estimation of these demand curves is essential to obtain good results. The method has been successfully implemented to solve a realistic example of a generating company that bids in the Spanish day-ahead market. Future research will implement an equilibrium price model where small agents may modify their residual demand slopes simultaneously, according to several heuristic rules.

D. Berleant et al (2003): Market based contracting introduces increased competition in the power industry, and creates a need for optimized bids and bidding strategies. To maximize the Expected Monetary Value (EMV) of a bid, generation companies (GENCOs) must strive to use models better than their competitors. Such models should account for factors such as buyers’ market power, market mechanisms, other competitors, substitutes, and equipment status. This paper explores bounds on the probability distribution describing the competitors’ bids. This weak probabilistic information is used to formulate a basic competitive bidding problem. In this environment, the bidder is expected to perform better provided they are informed about factors impacting the competitor’s bids. However, the acquisition of this kind of information involves costs that may exceed the expected benefit. Therefore, the bidder must decide whether or not to acquire information to alter the optimal bid. This paper explores use of Information Gap Decision Theory to quantify severe uncertainty. The value of additional information is compared under a more informative info-gap model where it determines the demand value of the information. HIS paper addresses a bidding problem faced by a generation company (GENCO)

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in a dynamically restructured electricity market. In this environment, GENCOs are exposed to risks and uncertainties. In real situations, intelligence about competitors is often uncertain and incomplete, so it is important to develop bidding models that can flexibly handle various kinds of partial information about competitors’ bids. Partial information includes but is not restricted to the dependency relationships among various relevant random variables, such as the bids put forth by a competitor. In the problem addressed in this paper, two GENCOs are competing to supply a fixed electricity demand. Using this imprecise information, we will attempt to quantify the uncertainty GENCO 1 faces and how to improve the situation by acquiring new information. This paper shows how Information Gap Decision Theory (IGDT) can serve as a decision support tool that assists in quantifying severe uncertainty when information is scarce and expensive. It can help decision makers to develop preferences, assess risks and opportunities, and seek information, given a minimum required level of reward. This minimum level of reward could be determined by incorporating risk management methodologies such as value at risk or profit at risk. Understanding how to balance the cost of new information with its benefits is an important next step.

Peter Cramton et al (2004): Profit-maximizing bidding in uniform price auction markets involves bidding above marginal cost. It therefore is not surprising that such behavior is observed in electricity markets. This incentive to bid above marginal cost is not the result of coordinated action among the bidders. Rather, each bidder is independently selecting its bid to maximize profits based on its estimate of the residual demand curve it faces. The supplier bids a price for its energy capacity to optimize its marginal tradeoff between higher prices and lower quantities. Price response from either demand or other suppliers prevents the supplier from raising its bid too much. Profit maximizing bidding should be expected and encouraged by regulators. It is precisely this profit maximizing behavior that guides the market toward long-run efficient outcomes. Profit-maximizing bidding in uniform price auction markets involves bidding above marginal cost. It therefore is not surprising that such behavior is observed in electricity markets. Common bidding behavior such as “hockey stick” bids easily is explained by suppliers determining their supply offers to maximize profits. This incentive to bid above marginal cost is not the result of coordinated action among the bidders. Rather, each bidder is independently selecting its bid to maximize profits based on its estimate of the residual demand curve it faces. Profit-maximizing bidding does not mean that “the sky’s the limit.” Typically, bidders are limited in how high they want to bid. As prices increase, generators become increasingly concerned that their capacity will not be selected—that someone else will step in front of them in the merit order. Only when (1) demand does not respond to price, and (2) the largest unhedged block of capacity is essential to meet demand can the bidder holding this largest block profitably name any price. In all other cases, the supplier bids a price for its energy capacity to optimize its marginal tradeoff between higher prices and lower quantities. Price response from either demand or other suppliers prevents the supplier from raising its bid too much. Profit maximizing bidding should be expected and encouraged by regulators. It is precisely this profit maximizing behavior that guides the market toward long run efficient outcomes.

B. J. Kirby et al (2006): Responsive load is the most underutilized reliability resource available to the power system. Loads are frequently barred from providing the highest value and most critical reliability services; regulation and spinning reserve. Advances in communications and control technology now make it possible for some loads to provide both of these services. The

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limited storage incorporated in some loads better matches their response capabilities to the fast reliability-service markets than to the hourly energy markets. Responsive loads are frequently significantly faster and more accurate than generators, increasing power system reliability. Incorporating fast load response into micro grids further extends the reliability response capabilities that can be offered to the interconnected power system. The paper discusses the desired reliability responses, why this matches some loads' capabilities, what the advantages are for the power system, implications for communications and monitoring requirements, and how this resource can be exploited. Encouraging responsive loads to provide regulation and spinning reserve is good for power system reliability, good for the responsive loads, and good for all power system customers. It is good for the power system because responsive loads can frequently supply faster, more accurate and more reliable response than generators. It is good for the responsive loads because regulation and spinning reserve are a better match to some loads inherent response capabilities than providing peak reduction or responding to energy markets. It also provides the loads with an additional income. It is good for all power system customers because it increases reliability and reduces costs. Reliability and market rules should be designed around power system physical requirements, not around the characteristics of the incumbent supply technology. Metrics should reward helpful behavior. Metering and communications systems should be designed with sufficient capability to accommodate ancillary service supply from loads. Supplying ancillary services is not exclusive of providing peak reduction or responding to energy markets. Many loads will want to optimize their responses to each as power system needs and market prices vary. This work was coordinated by the Consortium for Electric Reliability Technology Solutions for the U.S. Department of Energy, Office of Electricity Delivery and Energy Reliability. It is based upon research efforts concerning ancillary services and responsive load which has been supported for many years by Phil Overholt and the Department Of Energy.

Ali Hortac¸su et al (2008): We examine the bidding behavior of firms in the Texas electricity spot market, where bidders submit hourly supply schedules to sell power. We characterize an equilibrium model of bidding and use detailed firm-level data on bids and marginal costs to compare actual bidding behavior to theoretical benchmarks. Firms with large stakes in the market performed close to the theoretical benchmark of static profit maximization. However, smaller firms utilized excessively steep bid schedules significantly deviating from this benchmark. Further analysis suggests that payoff scale has an important effect on firms’ willingness and ability to participate in complex, strategic market environments. Many recent empirical analyses of oligopoly competition, including the analysis of bidding in auction markets, rely crucially on assumptions regarding the model of firm behavior. In a typical paper, a researcher has data on firms’ prices or bids and seeks to estimate the underlying costs of production or valuation of the auctioned object. By assuming that firms behave according to a particular strategic equilibrium model of profit maximization, the researcher can map firms’ observed pricing or bidding decisions into their unobserved costs or valuations. The inferences drawn from such approaches rely on the assumed strategic behavior. In most instances, testing the validity of a particular equilibrium model is left to the laboratory, where the researcher assigns costs/valuations to subjects and compares the subject behavior to the behavior predicted by the equilibrium model of competition. Outside of the laboratory, it is difficult to assess equilibrium models because data usually are not available on bidder costs/valuations.

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2.2. POLICIES AND REGULATIONS IN INDIA

2.2.1. THE ELECTRICITY ACT, 2003

Section 3 (National Electricity Policy and Plan) --- The Central Government shall, from time to time, prepare the National Electricity Policy and tariff policy, in consultation with the State Governments and the Authority for development of the power system based on optimal utilization of resources such as coal, natural gas, nuclear substances or materials, hydro and renewable sources of energy

Section 7 provides to establish, operate and maintain a generating company without obtaining a license subject to complying with Technical Standards.

Section 9 provides for Open Access to captive generators subject to availability of network for transportation.

Section 60 provides the Appropriate Commission to issue such directions to a licensee or generating company if they enter into any agreement or abuse their dominant position or enter into a combination, which is likely to cause an adverse effect on competition in electricity industry.

Section 63 stipulates that the Appropriate Commission shall adopt the tariff if such tariff is determined through bidding

Section 66 mandates the Appropriate Commission to endeavor to promote development of a market (including trading) in power.

Section 79(2) CERC to advise GoI on promoting competition.

2.2.2. NATIONAL ELECTRICITY POLICY, 2005

In compliance with section 3 of the Electricity Act 2003 the Central Government hereby notifies the National Electricity Policy.Section 3 (1) - the Electricity Act 2003 requires the Central Government to formulate, interalia, the National Electricity Policy in consultation with Central Electricity Authority (CEA) and State Governments. The provision is quoted below:

"The Central Government shall, from time to time, prepare the National Electricity Policy and tariff policy, in consultation with the State Governments and the Authority for development of the power system based on optimal utilization of resources such as coal, natural gas, nuclear substances or materials, hydro and renewable sources of energy".

Section 3 (3) -the Act enables the Central Government to review or revise the National Electricity Policy from time to time.

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The National Electricity Policy aims at laying guidelines for accelerated development of the power sector, providing supply of electricity to all areas and protecting interests of consumers and other stakeholders keeping in view availability of energy resources, technology available to exploit these resources, economics of generation using different resources, and energy security issues. The National Electricity Policy has been evolved in consultation with and taking into account views of the State Governments, Central Electricity Authority (CEA), Central Electricity Regulatory Commission (CERC) and other stakeholders.

The National Electricity Policy aims at achieving the following objectives: Access to Electricity - Available for all households in next five years Availability of Power - Demand to be fully met by 2012. Energy and peaking shortages

to be overcome and adequate spinning reserve to be available. Supply of Reliable and Quality Power of specified standards in an efficient manner and

at reasonable rates. Per capita availability of electricity to be increased to over 1000 units by 2012. Minimum lifeline consumption of 1 unit/household/day as a merit good by year 2012. Financial Turnaround and Commercial Viability of Electricity Sector. Protection of consumers’ interests.

Section 3(4) of the Act requires the Central Electricity Authority (CEA) to frame a National Electricity Plan once in five years and revise the same from time to time in accordance with the National Electricity Policy. Also, section 73 (a) provides that formulation of short-term and perspective plans for development of the electricity system and coordinating the activities of various planning agencies for the optimal utilization of resources to sub serve the interests of the national economy shall be one of the functions of the CEA. The Plan prepared by CEA and approved by the Central Government can be used by prospective generating companies, transmission utilities and transmission/distribution licensees as reference document.

Accordingly, the CEA shall prepare short-term and perspective plan. The National Electricity Plan would be for a short-term framework of five years while giving a 15 year perspective and would include:

Short-term and long term demand forecast for different regions; Suggested areas/locations for capacity additions in generation and transmission keeping

in view the economics of generation and transmission, losses in the system, load centre requirements, grid stability, security of supply, quality of power including voltage profile etc. and environmental considerations including rehabilitation and resettlement;

Integration of such possible locations with transmission system and development of national grid

2.2.3. NATIONAL TARIFF POLICY, 2006

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In compliance with section 3 of the Electricity Act 2003 the Central Government hereby notifies the Tariff policy in continuation of the National Electricity Policy (NEP) notified on 12th February 2005.

The National Electricity Policy has set the goal of adding new generation capacity of more than one lakh MW during the 10th and 11th Plan periods to have per capita availability of over 1000 units of electricity per year and to not only eliminate energy and peaking shortages but to also have a spinning reserve of 5% in the system. Development of the power sector has also to meet the challenge of providing access for electricity to all households in next five years. It is therefore essential to attract adequate investments in the power sector by providing appropriate return on investment as budgetary resources of the Central and State Governments are incapable of providing the requisite funds. It is equally necessary to ensure availability of electricity to different categories of consumers at reasonable rates for achieving the objectives of rapid economic development of the country and improvement in the living standards of the people.

Balancing the requirement of attracting adequate investments to the sector and that of ensuring reasonability of user charges for the consumers is the critical challenge for the regulatory process. Accelerated development of the power sector and its ability to attract necessary investments calls for, inter alia, consistent regulatory approach across the country. Consistency in approach becomes all the more necessary considering the large number of States and the diversities involved.

The tariff policy has been evolved in consultation with the State Governments and the Central Electricity Authority (CEA) and keeping in view the advice of the Central Electricity Regulatory Commission and suggestions of various stakeholders

The objectives of this tariff policy are to: Ensure availability of electricity to consumers at reasonable and competitive rates; Ensure financial viability of the sector and attract investments; Promote transparency, consistency and predictability in regulatory approaches across

jurisdictions and minimize perceptions of regulatory risks; Promote competition, efficiency in operations and improvement in quality of supply

2.2.4. CERC (Terms and Conditions for tariff) REGULATION, 2009-2014

Procedure for Tariff Determination and Computation of Capital Cost and Capital Structure

Tariff Determination:

Tariff in respect of a generating station may be determined for the whole of the generating station or a stage or unit or block of the generating station, and tariff for the transmission system may be determined for the whole of the transmission system or the transmission line or sub-station.

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For the purpose of determination of tariff, the capital cost of the project may be broken up into stages and distinct units or blocks, transmission lines and sub-systems forming part of the project.

Application for the determination of tariff:

The generating company may make an application for determination of tariff in accordance with Central Electricity Regulatory Commission (Procedure for making of application for determination of tariff, publication of the application and other related matters) Regulations, 2004, as amended from time to time or any statutory re-enactment thereof, in respect of the units of the generating stations completed or projected to be completed within six months from the date of application.

The generating company shall make an application as per Appendix Ito these regulations, for determination of tariff based on capital expenditure incurred duly certified by the auditors or projected to be incurred up to the date of commercial operation and additional capital expenditure incurred duly certified by the auditors or projected to be incurred during the tariff period of the generating station:

Provided further that application shall contain details of underlying assumptions for projected capital cost and additional capital expenditure, where applicable

Truing up of capital expenditure and tariff:

The Commission shall carry out truing up exercise along with the tariff petition filed for the next tariff period, with respect to the capital expenditure including additional capital expenditure incurred up to 31.3.2014, as admitted by the Commission after prudence check at the time ofTruing up. Provided that the generating company or the transmission licensee, as the case may be, may in its discretion make an application before the Commission one more time prior to 2013-14 for revision of tariff.

Capital Cost:

Capital cost for a project shall include the expenditure incurred or projected to be incurred, including interest during construction and financing charges, any gain or loss on account of foreign exchange risk variation during construction on the loan - (I) being equal to 70% of the funds deployed, in the event of the actual equity in excess of 30% of the funds deployed, by treating the excess equity as normative loan, or (ii) being equal to the actual amount of loan in the event of the actual equity less than 30% of the funds deployed, - up to the date of commercial operation of the project, as admitted by the Commission, after prudence checkThe capital cost admitted by the Commission after prudence check shall form the basis for determination of tariff.

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Initial Spares:

Initial spares shall be capitalised as a percentage of the original project cost, subject to following ceiling norms:

(I) Coal-based/lignite-fired thermal generating stations - 2.5%

(ii) Gas Turbine/Combined Cycle thermal generating stations - 4.0%

Debt-Equity Ratio:

For a project declared under commercial operation on or after 1.4.2009, if the equity actually deployed is more than 30% of the capital cost, equity in excess of 30% shall be treated as normative loan:

Provided that where equity actually deployed is less than 30% of the capital cost, the actual equity shall be considered for determination of tariff:

Provided further that the equity invested in foreign currency shall be designated in Indian rupees on the date of each investment

Components of Tariff:

The tariff for supply of electricity from a thermal generating station shall comprise two parts, namely, capacity charge (for recovery of annual fixed cost consisting of the components specified to in regulation 14) and energy charge (for recovery of primary fuel cost and limestone cost where applicable).

Annual Fixed Cost:

The annual fixed cost (AFC) of a generating station or a transmission system shall consist of the following components –

(a) Return on equity;

(b) Interest on loan capital;

(c) Depreciation;

(d) Interest on working capital;

(e) Operation and maintenance expenses;

(f) Cost of secondary fuel oil (for coal-based and lignite fired generating stations only)

Return on Equity:

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Return on equity shall be computed on pre-tax basis at the base rate of 15.5%

Provided that in case of projects commissioned on or after 1st April, 2009, an additional return of 0.5% shall be allowed if such projects are completed within the timeline specified in Appendix-II of the guidelines issued by the CERC.

Rate of return on equity shall be rounded off to three decimal points and be computed as per the formula given below:Rate of pre-tax return on equity = Base rate / (1-t) Where t is the applicable tax rate

Interest on Loan Capital:

The normative loan outstanding as on 1.4.2009 shall be worked out by deducting the cumulative repayment as admitted by the Commission up to 31.3.2009 from the gross normative loan.The repayment for the year of the tariff period 2009-14 shall be deemed to be equal to the depreciation allowed for that year.

Notwithstanding any moratorium period availed by the generating company repayment of loan shall be considered from the first year of commercial operation of the project and shall be equal to the annual depreciation allowed. The rate of interest shall be the weighted average rate of interest calculated on the basis of the actual loan portfolio at the beginning of each year applicable to the project. The interest on loan shall be calculated on the normative average loan of the year by applying the weighted average rate of interest.

The generating company shall make every effort to re-finance the loan as long as it results in net savings on interest and in that event the costs associated with such re-financing shall be borne by the beneficiaries and the net savings shall be shared between the beneficiaries and the generating company in the ratio of 2:1.

Depreciation:

The value base for the purpose of depreciation shall be the capital cost of the asset admitted by the Commission. The salvage value of the asset shall be considered as 10% and depreciation shall be allowed up to maximum of 90% of the capital cost of the asset. Depreciation shall be calculated annually based on Straight Line Method.Provided that, the remaining depreciable value as on 31st March of the year closing after a period of 12 years from date of commercial operation shall be spread over the balance useful life of the assets.Depreciation shall be chargeable from the first year of commercial operation.Interest on Working Capital:

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The working capital shall cover: Coal-based/lignite-fired thermal generating stations

(I) Cost of coal or lignite and limestone, if applicable, for 1½ months for pithead generating stations and two months for non-pit-head generating stations, for generation corresponding to the normative annual plant availability factor;

(ii) Cost of secondary fuel oil for two months for generation corresponding to the normative annual plant availability factor, and in case of use of more than one secondary fuel oil, cost of fuel oil stock for the main secondary fuel oil;

(iii) Maintenance spares @ 20% of operation and maintenance expenses;

(iv) Receivables equivalent to two months of capacity charges and energy charges for sale of electricity calculated on the normative annual plant availability factor, and

(v) Operation and maintenance expenses for one month.

Operation and Maintenance Expenses:Normative operation and maintenance expenses shall be as follows for coal based and lignite fired (including those based on CFBC technology) generating stations

Provided that the above norms shall be multiplied by the following factors for additional units in respective unit sizes for the units whose COD occurs on or after 1.4.2009 in the same station:

200/210/250 MW Additional 5th & 6th units 0.9, Additional 7th & more units 0.85


500 MW and above Additional 3rd & 4th units 0.9, Additional 5th & above units 0.85

In case of coal-based or lignite-fired thermal generating station a separate compensation allowance unit-wise shall be admissible to meet expenses on new assets of capital nature including in the nature of minor assets, in the following manner from the year following the year of completion of 10, 15, or 20 years of useful life:

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The operation and maintenance expenses for the year 2009-10 shall be escalated further at the rate of 5.72% per annum to arrive at permissible operation and maintenance expenses for the subsequent years of the tariff period.

Normative Annual Plant Availability Factor: - CERC guidelines after discussion with all stakeholders has fixed 85% normative annual plant availability factor for newer plant

Gross Station Heat Rate: Thermal Generating Station achieving COD on or after 1.4.2009:

Coal-based and lignite-fired Thermal Generating Stations = 1.065 X Design Heat Rate (kCal/kWh)

Where the Design Heat Rate of a unit means the unit heat rate guaranteed by the supplier at conditions of 100% MCR, zero percent make up, design coal and design cooling water temperature/back pressure.

Secondary Fuel Oil Consumption:

Coal-based generating stations: 1.0 ml/kWh

Auxiliary Energy Consumption:

Coal-based generating stations except certain plants mentioned in the CERC guidelines.

2.3. RESEARCH METHODOLOGY

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The literature survey was carried out by various published and unpublished reports on tariff based Competitive Bidding Mechanism. Works of various Government agencies were reviewed, reports based on risks profiles of generation utilities were consulted and articles concerning with recent development in power market were closely studied.

After surveying the works from various sources a list of advantages and potential risks factors in Competitive Bidding Mechanism has been prepared. These risks factors are thoroughly stated and possible risk mitigation strategies are suggested. Calculations were also done to assess the impact of these strategies on financial performance of the plant.

After careful investigation and analysis of data provided by JPL various parameters, such as project cost, interest rate was taken for calculations. Certain assumptions were also taken such as the price of short term power is assumed to be in range of INR 3.25 to INR 4.00 for next 25 years etc. Calculations for cost of generation for different situations is done by taking Tariff regulations 2009-14 issued by CERC as reference. Financial analysis of different strategies is also done on the basis of calculating NPV, IRR etc. The research methodology follows the following order:

Figure2.1: Flowchart of Research Methodology

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Search for data available in relevance to the assigned projectProper sorting and alignment of appropriate dataStudy and analysis of regulatory framework for Competitive Bidding MechanismComparative analysis of power plants allotted through Case 1 & Case 2 competitive biddingAnalyze thermal modal for tariff calculationPreparation of final report document

2.4. BARRIERS AND CONSTRAINTS IN BIDDING

The process of tariff based competitive bidding mechanism is a very sound and fair method for procurement of electricity. But smooth implementation this mechanism requires guidelines and government machinery that take care of concerns of all stakeholders. Following are the barriers and constraints in bidding mechanisms:

Problems in land acquisition to set up new power plants ; Uncertainty in supply of fuel; Single Standard Bid Document (SBD) for both coal-based and gas-based power plants; Excessive political interference; Information asymmetry between parties taking part in bidding process ; Lack of infrastructure to support smooth implementation of actions required to complete

bidding process on time ; Delay in pre-construction activities; Biased and unfair bidding process which decreases the enthusiasm of bidders ; Lack of communication between all parties before the start of and during the bidding

process ; Delay in completion of bidding processes; Co-existence of old and efficient plants consuming more coal but generating less

electricity; Delay in providing clearance for environment and forest department; Differences among various State Boards; No provision for revising tariff once set according to changing law and business

environment.

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CHAPTER 3

EVALUATION OF THE FRAMEWORK

3.1. OVERVIER

The Indian electricity sector has seen considerable changes in its policies and regulations over the years. While the Act of 1910 was the first legal framework to regulate electricity sector, the Electricity (Supply) Act of 1948 led to the formation of the State Electricity Boards (SEBs) and the Central Electricity Authority (CEA). The Act of 1948 empowered the SEBs to determine tariff. With the introduction of the Electricity Regulatory Commission Act, 1998 the Government distanced itself from tariff regulation. The Electricity Act, 2003 brought many changes. Introducing competition in all areas of electricity sector was the main objective of the Act. The earlier approach of Memorandum of Understanding (MOU) based capacity addition was analyzed and a new mechanism of competitive bidding was devised as per provisions of the Section 63 of the Act, 2003. Section 63 of the Act states that –

“Notwithstanding anything contained in section 62, the Appropriate Commission shall adopt the tariff if such tariff has been determined through transparent process of bidding in accordance with the guidelines issued by the Central Government.”

Later the National Electricity Policy and the National Tariff Policy advocated the new capacity addition through competitive bidding process. So the chronological order of the events is:

The Electricity Act, 2003 The competitive Bidding Guidelines, 2005 The National Electricity Policy, 2005 The National Tariff Policy, 2006

Figure3.1: Evaluation of the Competitive Bidding Framework.

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The Electricity Act 2003 provides an enabling framework to create a competitive and efficient power market. Some of the key provisions are as follows:

Section 7 provides to establish, operate and maintain a generating company without obtaining a license subject to complying with Technical Standards.

Section 9 provides for Open Access to captive generators subject to availability of network for transportation.

Section 60 provides the Appropriate Commission to issue such directions to a licensee or generating company if they enter into any agreement or abuse their dominant position or enter into a combination, which is likely to cause an adverse effect on competition in electricity industry.

Section 63stipulates that the Appropriate Commission shall adopt the tariff if such tariff is determined through bidding

Section 66mandates the Appropriate Commission to endeavor to promote development of a market (including trading) in power.

Sec 79(2) CERC to advise GoI on promoting competition

3.2. COMPETITIVE BIDDING OBJECTIVES AND SCOPES

The objectives of competitive bidding guidelines are-

1. Promote competitive procurement of electricity by distribution licensees;2. Facilitate transparency and fairness in procurement of electricity by licensees;3. Facilitate reduction of information asymmetries for various bidders;4. Protect consumer interests by facilitating competitive conditions in procurement of

electricity;5. Enhance standardization and reduce ambiguity and hence time for materialization of the

projects;6. Provides flexibilities to suppliers in internal operations while ensuring certainty on

availability of power and tariffs for buyers.

The scopes of the guidelines are:

The guidelines are applicable for procurement of power for:

1. Long-term: - 7 years and more;2. Medium-term: - up to 7 years but not less than 1 year.

The guidelines shall apply for procurement of base-load, peak-load and seasonal power requirement through competitive bidding, through the following mechanisms:

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I. Where location, technology, or fuel is not specified by the procurer (case 1);II. For hydro-power projects, load centre projects, or other location specific projects with

specific fuel allocation such as captive mines available, which the procurer intends to set up under tariff based competitive bidding process (Case 2).

Figure3.2: Bidding Mechanism – Case 1 and Case 2.

3.3. BIDDING PROCESS

The guidelines state a two-stage bidding process for long-term procurement of power:

I. Stage 1: Request for Qualification (RFQ);II. Stage 2: Request for Proposal (RFP).

Figure3.3: Bidding Process – Case 1 and Case 2.

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Bidding Mechanisms

Location/technology/fuel-not specified

Bidder responsible for clearances/approvals

Relevant for states having limited fuel resources

High risk for developers Low risk for the State

Land/fuel provided by the procurer Bidder responsible for

clearances/approvals Relevant for states having fuel

resources or coastal areas High risk for state and low risk for

the developers

Case 1

Case 2

For medium-term power procurement, the bidder can adopt a single stage bidding process, combining the RFQ and RFP processes. The bid documents should be in line with the guidelines and Standard Bid Documents (SBDs).The procurer shall publish a RFQ in at least two newspapers, company website and preferably in trade magazines also to accord it wide publicity. The bidding shall necessarily be by way of International Competitive Bidding (ICB).

3.4. TARIFF STRUCTURE

A multi-part tariff structure having separate charges for capacity and energy components should form the basis for bidding process. However, for medium-term procurement the procurer may permits bid on a single part basis, and this should be clearly mentioned in the RFQ/ RFP. In case of long-term procurement with specific fuel allocation (case 2), the procurer should invite bids on the basis of capacity charges and net quoted heat rate.

As per bidding guidelines, the bidder should try to keep tariff in Indian Rupees only and minimize the Foreign Exchange risk. Transmission cost shall be borne by the procurer. As far as possible, the bidder should quote the tariff in Indian Rupees only.

Integral to the Case 1 and Case 2 bid processes is the cost indexation mechanism that CERC is mandated to notify consequent to the role defined in the CBG. As per Clause 4.11 (ii) of the original CBG of 2005, it was envisaged the energy charge for captive coal mine based projects would an escalable component linked to inflation (relevant to mining operations). For imported coal / fuel based thermal power projects, under Clause 4.11 (iii) of the CBG, the energy charge would have the following three escalable sub-components:

Imported Fuel (Coal) component in USD / unit

Transportation of fuel (Coal – Ocean Freight) component in USD / unit

Inland fuel (Coal) Handling component in INR/unit

Subsequently CERC has also notified escalation rates applicable for domestic and imported coal and gas based projects.

Figure3.4: Components of Tariff.

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3.5. TIME TABLE FOR BIDDING PROCESS

A suggested time table for the bid process is indicated below. The procurer may give extended time frame indicated herein based on the prevailing circumstances and such alteration shall not be construed to be deviated from these guidelines.

Table3.1: Time Table for Bidding Process.

Events Elapsed time from Zero date

Publication of RFQ Zero date Submission of Responses of RFQ 60 days

Short listing based on responses and issuance of RFP 90 daysBid clarification, conference etc 150 daysFinal clarification and review of RFP 180 daysTechnical and price bid submission 360 daysShort listing of bidder and issue of LOI 390 daysSigning of Agreement 425 days

A suggested time-table for Single stage bid process is indicated below. The procurer may give extended time frame indicated herein based on the prevailing circumstances and such alteration shall not be construed to be deviated from these guidelines.

Table3.2: Time-Table for Single Stage Bid Process.

Event Elapsed Time from Zero date

Publication of RFP Zero date

Bid clarification, conference etc. & revision of RFP 90 days

Technical and price bid submission 180 days

Short listing of bidder and issue of LOI 210 days

Signing of Agreements 240 days

3.6. ARBITRATION

The procurer will establish an Amicable Dispute Resolution (ADR) mechanism in accordance with the provisions of the Indian Arbitration and Conciliation Act, 1996. The ADR shall be mandatory and time-bound to minimize disputes regarding the bid process and the documentation thereof.

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3.7. CONTRACT AWARD AND CONCLUSION

The PPA shall be signed with the selected bidder consequent to the selection process in accordance with the terms and conditions as finalized in the bid document before the RFP stage.

The procurer shall make evaluation of bid public by indicating terms of winning bid and anonymous comparison of all other bids. The procurer shall also make all contracts signed with the successful bidders. The final PPA along with the certification by the evaluation by the evaluation committee shall be forwarded to the Appropriate Commission for adoption of tariffs in terms of Section 63 of the Act.

3.8. CAPACITY CONTRACTED THROUGH COMPETITIVE BIDDING

Ever since the introduction of Competitive Bidding Framework in India, power projects with aggregate capacity of 42065 MW have been awarded with over 30 cases of case 1 and case 2 bids conducted successfully.

The framework has not only resulted in providing a strong platform for private sector participation in the power generation but has also resulted in considerably low tariff discoveries particularly in comparison to the traditional cost plus regime, that will ultimately benefit the consumers in terms of availability of cost effective power. Figure3.5 indicates the break-up of total capacity added under Case 1, Case 2 and through UMPPs.

Figure3.5: Capacity addition under various modes of competitive bidding

1320

6010

30444600

18413300

1200

4300

450

4000 4000 40004000

01000200030004000500060007000

MW

Case 1 Case 2 UMPP Total

Source: Forum of Regulators

Of the total capacity aggregate capacity added under Case 1 and Case 2 i.e. 42605 MW:

14224 (34%) is based on imported coal.

18521 MW (44%) is based on domestic coal.

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9320 MW (22%) is based on captive coal block.

The corresponding break-up for Case 1 and Case 2 are indicated in Table.

Table3.3: Fuel-wise break up of capacity added under Case 1 and Case 2

Description Domestic Coal Imported Coal Captive Coal Based

Case 1 6224 9601 ……..

Case 2 8000 8920 9320

Total 14224 18521 9320

State-wise break up for case 1 and case 2 project

Table3.4: State-wise break up for case 1 and case 2 project

Sl. NO. Name of the State No. of Case 1 Bids No. of Case 2 Bids

1. Andhra Pradesh 1 1

2. Chhattisgarh … 1

3. Utter Pradesh 4** 3

4. Madhya Pradesh 1 1

5. Gujarat 5* 1

6. Haryana 1 1

7. Punjab 1* 2

8. Maharashtra 3 …

9. Rajasthan 1 …

10. Bihar 1 …

11. Jharkhand … 1

12. Karnataka 1 ..

Total 19 11


*In Gujarat one of the bidding rounds in 2008 was cancelled. In Punjab, the bidding round initiated in 2009 was cancelled.

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** Includes a bidding round of Noida Power Ltd. that was subsequently cancelled

3.9. TARIFF ANALYSIS UNDER CASE 1 AND CASE 2 BIDDINGS

Tariffs under competitive bidding have been found to be lower than cost plus mechanism. Several reports including the statutory advice of the CERC regarding timeframe for tariff based competitive bidding bring out this fact. Table 2.1 depicts the tariff under Case 1 bids.

Table 3.5: Historical Tariff under Case 1 Bids

Sl. No.

Description Capacity

(MW)

Tariff (Rs/Kwh)

Year Host State State of Plant Location

Coal Source

1. Aryan Coal ( Dec 06)

200 2.25 2006 Gujarat Chhattisgarh Imported Coal

2. Adani Power( Dec 06)

1000 2.35 2006 Gujarat Gujarat Imported Coal

3. Essar(Dec 06) 1000 2.40 2006 Gujarat Gujarat Imported Coal

4. Adani Power (Nov 07)

1424 2.94 2007 Haryana Gujarat Domestic Coal

5. PTC-MGR (Nov 07)

300 2.88 2007 Haryana Orissa Domestic Coal

6. Lanco (Nov 07) 600 2.34 2007 MP Orissa …..

7. R-Power (Nov 07)

1241 2.45 2007 MP MP …..

8. Essar (Nov 07 ) 300 2.66 2007 MP MP …..

9. Adani Power (Feb 08)

1320 2.66 2008 Maharashtra Maharashtra Domestic Coal

10. Lanco (Feb 08) 680 2.70 2008 Maharashtra Maharashtra Domestic Coal

11. JSW Energy (Feb 08)


12. MGR-EMCO 200 2.88 2009 Maharashtra Chhattisgarh Domestic

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(Sept 09) Coal

13. India Bulls (Sept 09)


14. Adani Power (Sept 09)


15. KSK Energy( Jan 10)

1010 2.34 2010 Gujarat Maharashtra Domestic Coal

16. Shapoorji Palonji ( Jan 10)

800 2.80 2010 Gujarat Gujarat ….

17. Essar( Jan 10) 1000 2.80 2010 Gujarat Gujarat Imported Coal

18. Essar (Jan 10) 450 3.06 2010 Bihar ….. ….


As depicted above, in most of the cases the tariffs have been below Rs. 3.00 per unit.

A similar analysis of Case 2 bids indicates relatively lower tariffs than Case 1 bids. One of the reasons for this has also been low risk in Case 2 project than Case 1 project, wherein most of the facilitation is provided by the procurer. Within Case 2 bids, while UMPPs bidding have witnessed lower tariffs, most of the other projects have witnessed prices in the range of Rs. 2 to 3/kWh. Table 2.2 depicts the tariffs discovered under various Case 2 bids.

Table 3.6: Historical Tariff under Case 2 Bids

Sl.

No.

Description Capacity (MW)

State Coal Source

Bid Submission/ no. of Bidders

Final Bidder

Tariff (Rs./Kwh)

1. Anpara C 1000 UP Linkage Coal

May 2006 /3

Lanco 2.088

2. Sasan UMPP 4000 MP Captive Coal Block

Dec 2006 / 9

R-Power 1.196

3. Mundra 4000 Gujarat Imported Dec 2006 / Tata- 2.264

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UMPP Coal 6 Power

4. Krishnapatnam UMPP

4000 AP Imported Coal

Oct 2007 / 3

R- Power 2.33

5. Bhaiyathan TPP

1500 Chhattisgarh

Captive Coal Block

Jan 2008 / 10

Sunflag Iron & Steel Ltd + India Bulls

0.81

6. Jhajjar TPP 1320 Haryana Linkage Coal

March2008/ 3

CPL 2.996

7. Talwandi Sabo TPP

1980 Punjab Linkage Coal

June 2008 / 4

Sterlite 2.864

8. Karchana TPP 1320 UP Linkage Coal

Oct 2008 / 4

Jaiprakash

2.97

9. Tilaiya UMPP 4000 Jharkhand Captive Coal Block

Dec 2008 / 5

R- Power 1.77

10. Bara TPP 1980 UP Linkage Coal

Feb 2009 / 3

Jaiprakash

3.02

11. Nabha TPP 1320 Punjab Linkage Coal

Oct 2009 / 7

L&T 2.89


The levelised capacity charge for the twelve (12) Case 1 projects (about 10630 MW) has equivalent or embedded capital cost between Rs. 3.5 - 4.5 Crore/MW whereas capital cost of recent projects developed through the older i.e. cost plus route, is Rs. 4.5 - 5.9 Crore/MW which show the efficiency of tariff determined through bidding mechanism.

The analysis of variable charges (after being normalized to 2010-11 rates) shows that for most projects the variable cost over the 25 year PPA period falls between Rs 1.5-3.50 per unit and is less than Rs 2 per unit for the first 15 years of the PPA. As against this the current variable charges of many of the cost plus projects in states such as Maharashtra, Tamil Nadu and Rajasthan are well above Rs 2 per unit for the year 2010 itself.

3.10. VARIOUS ISSUES UNDER CASE 1 COMPETITIVE BIDDING FRAMEWORK

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3.10.1. PREVAILING ISSUES

1. Land: The Bidder should have acquired and have taken possession of at least 50% of the area of the land as indicated in the environmental clearance and also certify through an affidavit the total land acquired for the power station and that there are no pending claim(s)/litigation of any nature against/involving the Bidder vis-à-vis land and that the Bidder has absolute rights and authority to establish and run power plant on the land.A Bidder needs to meet the entire technical qualifying requirement listed above to qualify for the tender. This in turn means that the project developer needs to spend money upfront for acquiring 50% of the land when the financial closure of the project has not been achieved. Only bidder with deep pockets can meet the requirement. Another relevant issue here is that many developers plan a phased development of the project. However, they need to take environmental clearance for the entire planned capacity of the project. This implies that even if a bidder wishes to bid for the capacity being targeted in the first phase of the project or a part of the capacity being targeted in the first phase of the project, there may be a situation where he would need to show land acquisition for more than that phase. Therefore, it is suggested that the condition of land availability should be modified such that land acquisition is correlated with the phase of development of the project.

2. Environmental & Forest Clearance: The process of obtaining environmental clearance is time taking. Therefore, it is possible that at the time of bidding, the process of obtaining such clearance is in an initial or intermediate stage. While it is recognized that the process of public hearing and its outcome has a crucial bearing on the fate of the clearance, the condition of submitting the proposal for final environmental clearance approval is somewhat restrictive. Given that the process of bidding takes time to culminate, it is possible that the proposal for final environmental clearance may be submitted by the time of opening of the financial bid. Therefore, it is suggested that the condition of environmental and forest clearance should be modified such that the bidder is required to submit the requisite proposal, for the final environmental clearance approval by the time of opening of the financial bid. If at the time of opening of the financial bid, the bidder is not able to meet this requirement, the bid should be returned as unresponsive or disqualified.

3. Contract Performance Guarantee: The successful bidder is required to provide a Contract Performance Guarantee within thirty days of issue of Letter of Intent (LoI) by the Procurer. This Guarantee is determined on the basis of Rs. 30 lakhs/MW of the total Contracted Capacity. The first issue here is that the level of Guarantee may turn out to be very high (for 1000 MW, Rs. 300 Crores) and a bidder without deep pockets may be unable to furnish such guarantee prior to the financial closure of the project. Therefore, it is suggested that the level of the Contract

Performance Guarantee may be lowered. It may be argued that lowering the level of this guarantee may encourage non-serious bidders. To take care of such concerns, the

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termination cost of the PPA may be increased and kept at a very high level so that it prohibits non-serious bidders.

4. Application of Open Access: As per the SBD, in case the power plant is located within the Procurer State than the project bus-bar becomes the Delivery Point and it is the Procurer’s responsibility to co-ordinate with the State transmission network for evacuation of power. However, in case the power plant is located outside the State then it is the responsibility of the Bidder to obtain Open Access. In case the signatory of the power transmission agreement is an IPP/Trader than POWERGRID as payment security mechanism demands in addition to Letter of Credit 6 months billable amount as Bank Guarantee but if the same Open Access is obtained by the Procurer then only Letter of Credit suffices for POWERGRID. Thus the Bidder obtaining the Open Access increases the tariff for the Procurer which can be easily avoided.

Further, as per the SBD, the LC is provided to the Bidder only for the generation charges and not for the transmission charges. It only states that the transmission charges shall be reimbursed.

5. Escalation Rates (fuel, transportation, etc): On today’s base cost, escalation rate used for evaluation is applied to find the base cost for the 1st year of operation. This 1st year base tariff becomes the basis on which the escalation for making payment is applied. This means that if based on the present coal price the fuel charges works out to be Rs. 0.50 per kWh, and considering the present escalation rate for evaluation of bid as (say 5%), then the coal price for 1st year would be Re. 0.58 per kWh. This becomes the base price on which CERC escalation rates for payment will be applied for making payments. But in case the coal prices escalate by more than 5% during the 48 months of project commissioning then the Bidder has no protection under the present SBD. Therefore SBD may be amended to take care of actual escalation in coal price including freight escalation rate during the construction period of 48 months to arrive at 1st year base tariff.

3.10.2. EMERGING ISSUES

As discussed in previous sections, the Competitive Bidding Framework has resulted in considerably low tariff in comparison to the cost plus tariff determination, which is beneficial for the consumers in terms of low cost power. However, over the past five years the scenario has changed drastically due to the development of issues like acute coal shortage, legal/regulatory changes in coal exporting countries and changes in environment and forest laws in domestic country. All these developments have necessitated a relook in the bidding mechanisms. The emerging issues are:

1. Shortfall in Domestic Coal Capacity

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SBD conditions require that in case of plant based on domestic coal, bidder should have fuel tied up for total installed capacity for the term of the PPA. While this condition was possible until recently, the developments in the last 2-3 years have led to change in conditions that no longer permit the developers to have this certainty on the availability of the domestic coal.

Some of the key issues are as follows:

Coal India Limited (CIL)’s inability to meet commitment of domestic coal supply under Fuel Supply Agreement (FSA). Draft FSA for new plants assure only 50% of annual contracted quantity (ACQ) i.e. penalty is applicable only if less than 50% quantity of ACQ is delivered and that too mere 10% of base price. Due to demand supply gap of coal in India, the 50% of ACQ includes imported coal (Blended). If consumer opts for surrender of imported coal component, ACQ in FSA will be reduced by 50%, thus only 25% linkage is guaranteed.

12th plan envisages addition of 76.5 GW coal based capacity requiring approximately 344 million tonne (MT) of coal. Based on the current rate of production by the CIL (at the rate of 20 MTPA), ~100 million tonne would be available from the CIL for the XII plan period. Similarly, approximately 80 million tonne would be available from the captive coal blocks. Thus, the total deficit by end of XII plan period is likely to be 226 million tonne. There is no condition in the SBD or in the PPA that takes care of such issues caused due to shortage of coal from the linkages.

Figure3.6: Coal Demand, Growth, Domestic Supply& Import during FY 2010- FY2015

Source: KIR

2. Adverse Legal/Regulatory Changes resulting in change in the Imported Coal Prices

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Indian developers have been taking ownership positions in mining assets overseas to back their imported coal based projects with three important aims

a. To reduce the cost of power supplied and be competitive, b. To ensure supply availability, since the ocean trade market for coal is still

relatively small and c. To protect against volatility of fuel costs.

The consequence of such positions has been very competitively priced power supply offers and also relatively low coal market indexed component in the price bids in several instances. This has thus provided the country with relatively low cost supply prospects. In theory, if there are changes in market dynamics in ocean trade, the developer should be responsible for the impact of such changes.

Recently, Indonesia and Australia had changed their norms for the coal exports. The revised norms have increased the prices of the import of coal from these countries. Indonesia and Australia accounts for approx 55% of the nation’s coal imports.

INDONESIA has said it would not allow coal exporting companies to sell coal at prices below notified rates after September 23, 2011.

AUSTRALIA issued a draft mining law to impose levy on coal and iron ore projects. This is expected to be effective from July 2012. There is also possibility of introduction of Carbon Tax on Australian coal production. After implementation of these laws, Australian coal prices are expected to go up by US $ 20-25 / Tonne.

The above mentioned instances have exposed the vulnerability of the power projects based on imported coal due to legal/regulatory changes in coal exporting, which are beyond the control of coal producers. In order to meet the capacity requirement of India, it is essential to ensure that the power projects are economically viable and are protected from any undue/uncontrollable risk.

There can also be the other side of the story; various private players acquired international coal mines some years back when the coal price was low compared to the current scenario. For example Essar, Tata, Reliance acquired mines in Indonesia etc

Now, Looking at the rapid increase of the coal prices in the current scenario, there’s a possibility that the Pvt. Players might have analyzed the money they can make through Coal Trading rather than going for power generation through the acquired coal mines and may be they are finding ways to delay their ongoing power projects in India

Figure3.7: Demand Projection of Imported Coal till FY2015

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Source: KIR

Figure3.8: Coal Demand and Supply position in India during 2005-2010

Source: CEA

3. Environmental Issues:

The coal production has been seriously affected by the Ministry of Environment and Forest (MoEF) notification dealing with Comprehensive Environment Pollution Index (CEPI) and the “GO/NO-GO” policy.

The number of coal blocks allocated to different utilities and the geological reserves of the blocks are given in the table below.

Table 3.7: Details of Coal blocks Allocated to Power Sector

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Source: CEA

Out of 91 coal blocks only 16 blocks with a reserve of 1355 million tonne (MT) are operational. Mining plan has been approved for 26 blocks with reserve of 7787 million tonne (MT). The captive blocks have to be developed on priority basis to meet the capacity addition target for the 12th plan.

3.11. VARIOUS ISSUES UNDER CASE 2 COMPETITIVE BIDDING FRAMEWORKS

3.11.1. PREVAILING ISSUES

The responsibility of completion of project preparatory activities and various clearances is on the Bidders, but the Government may complete predevelopment activities like identification of water source, identification of land, preparation of pre-feasibility report ,tap-off point of gas pipeline, coal blocks etc. before bidding to expedite the bidding process. Respective Governments also help in getting clearances for land, environment, water and forest for UMPPs because of the scale of the operation. Thus the overall process in case 2 provides a lower risk profile for the bidder. This has also been reflected in the relatively lower tariffs discovered in Case 2 bids, when compared with the Case 1 bids.

Delay in completion of the pre-construction activities as per the stipulated timelines, results in continuation of the above activities beyond the date of signing of PPAs, thereby impacting the developers in terms of delay in project execution. Even though the above is partly accounted for in the provision of the PPA and the escalation/indexation mechanism notified by the CERC, this is against the objectives enshrined in the competitive bidding guidelines.

A larger issue faced by the Case 2 projects is on account of SYSTEMIC risks particularly those related to the fuel i.e.

- Shortfall in domestic coal availability;- Environmental issues involved in captive coal blocks; and - Change in law/regulations in the coal exporting countries (already elaborated in the

preceding section).

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At the time when Case 2 projects were awarded, 90% of the Annual Contracted Quantity (ACQ) was assured by the CIL, however, in the current scenario draft FSA for new plants assure only 50% of annual contracted quantity (ACQ) i.e. penalty is applicable only if less than 50% quantity of ACQ is delivered and that too mere 10% of base price. Contrary to this, the CERC regulations permit recovery of fixed charge only at 85% availability level. Thus, there appears to be a clear discord between the FSA and the regulatory framework of the power sector. The quoted tariffs at such low ACQ assurance are unsustainable.

It is difficult to visualize a situation where a developer is able to commit a plant availability of 85% as mandated by the CERC regulations, without corresponding firm allocation of coal under FSA. FSA below 85% ACQ is completely untenable. While acknowledging the fact that the Case 2 projects are largely protected from the major shift in the risk profile, however changes on account of emerging uncontrollable factors need to be incorporated to prevent defaults. The following section elaborates on the changes required in the Case 2 bidding framework.

3.11.2. SUGGESTED CHANGES FOR CAPACITY ADDITION UNDER CASE 2 BIDDING

Since delay in pre-construction activities result in delay of the project. So it is suggested that the letter of intent should be awarded only after the completion of pre-construction activities.

As suggested above, it is difficult to visualize a situation to commit plant availability for 85% as per CERC regulation without firm fuel allocation by CIL. So Fuel Supply Agreement (FSA) below 85% is completely untenable. Hence, it is suggested that either: (I) all FSA should mandatorily provide at least 85% firm coal allocation; or (ii) the full capacity charge recovery should be permitted at the level indexed to the ACQ assurance level.

As elaborated earlier, the current contractual framework under SBD doesn’t protect the Seller/Developer (in case of project based on imported coal) from coal price changes triggered by any “Change in Law” event in the coal exporting country. Such instances have exposed the vulnerability of the power projects based on imported coal due to legal/regulatory changes in coal exporting, which are beyond the control of coal producers. Hence, the SBD should include a change in law/regulation of exporting countries for imported coal based projects, for protecting the developers from their impact as it is beyond their control. In such cases, in the event of reduction in international prices of coal, the benefit of the same is passed on to power purchase.

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3.12. OTHER ISSUES IN THE COMPETITIVE BIDDING FRAMEWORK

Co-existence of cost plus (MOU) regime along with competitive bidding route

Rebidding based on baseless and unconvincing grounds: Re-bidding negatively affects the investor confidence and raises questions on fairness of bid process. It is suggested that if the tariff is determined by the process as laid down in the competitive bidding guidelines 2005 and regulators can find no flaw in the process, the same tariff should be adopted. Further, no tariff negotiations should be allowed after opening of financial bids.

Post Bidding Changes in Standard Bid Documents and Nature & Character of Project

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CHAPTER 4

INTRODUCTION TO FINANCIAL MODULING

4.1. OVERVIEW

Financial model is designed to represent in mathematical terms the relationships among the variables of a financial problem so that it can be used to answer “what if” questions or make projections. Some of the spreadsheet solutions that people create capture some of these relationships as well and, therefore, can answer “what if” questions to some extent. But because they are not primarily designed with these objectives in mind, they do not try to capture as many of these interdependencies as possible, and their Structures often make it cumbersome to answer “what if” questions or make projections with them.

4.2. STEPS IN CREATING A MODEL

Step 1: Define and Structure the Problem

The first step in creating a model is to define the problem properly. In real life, problems rarely come neatly defined and structured. Unless you take the time upfront to define and structure the problem and agree on them with the user, you may end up having to extensively change the model you first create. When you are asked to develop a model, you often have only a vague idea about the topic. As a finance person and a modeller, you are responsible for putting it all in more concrete terms before proceeding. Start by discussing with seniors and colleagues and define why the model is needed and what decisions, if any, will be made based on its output—that is, what questions the model is supposed to answer. Then establish how accurate or realistic the outputs need to be. As we know, all models have to capture the relationships among their variables, and discovering and quantifying these can take a lot of time.

Step 2: Define the Input and Output Variables of the Model

The second step is to define the input and output variables in accordance of the model. Make a list of all the inputs the model will need and decide who will provide them or where they will come from. This is a very crucial step. For example, if you are creating a model to do the business plan for your company, the inputs must come from the business managers. You cannot just guess sales growth rates, how much to spend on plants and equipment to support those sales growths, and so forth. You may not need the actual numbers upfront, but the list of inputs should be established based on your discussions with the managers of different departments so that you can make them independent variables in your model.

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Make a list of the tabular, graphical, and other outputs the model needs to create. To some extent, these should be driven by the decisions that will be made based on them.

Step 3: Decide Who Will Use the Model and How Often

After defining input and output variables, the next step is to decide the user. When you create models for others’ use, it involves much more work. You have to make sure that these people cannot enter data that do not make sense, they cannot accidentally damage parts of the model, and they can get the necessary outputs automatically and so forth. These are collectively called the user interface, and the more elegant, more easy to use, and more robust you want to make a model, the more work it is. You also have to plan for many of these features ahead of time.

How frequently a model will be used is another important issue. If a model is going to be used only once in a while, then it does not matter if it takes a long time to run or if it takes some extra work every time to create the outputs. A model that will be used frequently, however, should be designed differently.

Step 4: Understand the Financial and Mathematical Aspects of the Model

The fourth step is the clear understanding of the financial and mathematical aspects of the model. It is important to remember that the computer cannot do any thinking; you have to tell it exactly how all the calculations in the model will have to be done. In most situations, if you do not know how to do the calculations by hand, you are not going to be able to write the necessary formulas or instructions for the computer to do it. It is not a good practice to start building the model until you are confident of solving the problem by hand.

Step 5: Design the Model

The next step is to design the model. There are two aspects to designing a model. One is to sketch the steps that Excel will have to follow to solve the problem. For simple models, you may want to write down only the broad steps or perhaps even do it in your head. For more complex problems, however, you should work on paper and use a degree of detail that suits your level of experience and the complexity of the problem. The less experience you have, the more detailed the sketch should be. Once again, remember that this may seem like a waste of time, but ultimately it will save your time compared to plunging into your spreadsheet without such a sketch of the model. The other aspect of design is planning how the model will be laid out in Excel. Are you going to do the entire model in one spreadsheet or split it into several spreadsheets editing an Excel model is easy. So you do not have to decide every detail ahead of time, but you need to have an overall design in mind or on paper depending on the complexity of the problem and your level of experience. As discussed before, you also need to think about the kind of user interface you want to create and the reports you want the model to produce.

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Step 6: Create the Spreadsheets

After designing the model, the next step is to create the spreadsheet. This step needs a very good knowledge of Excel. Using the formulas in Excel sheet saves considerable time and makes it easy to modify at later stage.

Step 7: Test the Model

After creating the model in Excel sheet, the testing of model is done. No model works correctly the first time it is used; you have to find the problems (bugs) and fix them. The bugs that prevent the model from working at all or produce obviously wrong answers are generally easier to find and fix. For hidden bugs, you have to test the model extensively with a wide range of input variables.

There is no standard approach to testing and debugging a model. You almost always have to use your ingenuity to figure out what will be the best way to test and debug a particular model. Your ability to do so will improve with experience.

The better you understand a problem and a model, the easier it will be to debug it. If you understand how changes in certain independent variables affect the values of certain dependent variables, then you can change the values of the independent variables to see if the dependent variables are changing in the right direction and by the right orders of magnitude. This is one of the best tools, especially for debugging large models, and you should do a lot of testing using this approach. You can also use this approach to hunt down the sources of the problems: Starting from a value that looks wrong, backtrack through the values of the intermediate dependent variables to see where the problem may be originating. This approach may sound somewhat vague and abstract, but with experience you will find that you can locate and fix most bugs rapidly using this approach.

Checking a model’s output against hand-calculated answers is a common and effective approach to debugging. In some situations, doing hand calculations may not be practical, but you may be able to use Excel itself to do some side calculations to test individual parts of the model.

Step 8: Protect the Model

Once you have completed a model, and especially if you are going to give it to others to use, you should consider protecting it against accidental or unauthorized changes. In addition, you may also want to hide parts of the model so that others cannot see certain formulas, data, and so on. Excel provides several flexible tools that you can use to hide and protect parts or your entire model. A good strategy is to cluster and colour codes all the input cells of a model and protects and hides everything else in the workbook.

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Step 9: Document the Model

Documentation part is done after protecting the model. Documenting a model means putting in writing, diagrams, flowcharts, and so on, the information that someone else (or you yourself in the future) will need to figure out what it does, how it is structured, and what assumptions are built into it. One can then efficiently and effectively make changes to (update) the model if necessary.

For large systems (for example, the reservation systems for airlines), the amount of necessary documentation can be enormous; it is often put on CDs for easy access and use. Professional system development organizations have elaborate standards for documentation, because different pieces of large systems are developed by different people—many of whom may not be around for very long. Also, it is almost certain that the systems will have to be constantly updated.

Over time, anyone who creates models develops his own system of documentation. As long as you keep in mind the objectives I mentioned before, you have a lot of leeway to come up with your own system as well. Excel offer a number of features that let you easily do a lot of the documentation as you work on your model. You should take full advantage of them and do as much of your documentation as possible while creating the model.

This is important for two reasons. First, if you write your documentation when things are fresh in your mind, it will save you time later and you will be less likely to forget to document important things. Second, everyone hates (or learns to hate) documentation. It is no fun at all, especially if you try to do it all at once at the end of the project. If you do not work on the documentation until the end, chances are you will never do it. Then, if you have to use the model again a few months later or have to update it, you will end up spending hours or even days trying to figure out what you did. Do your documentation as you go along and finish it immediately after your model is done.

Step 10: Update the Model as Necessary

This is not a part of the initial model development, but almost all models require updating at some point, either because some things have changed or because you want to adapt it to do something else. This is where the documentation becomes useful. Depending on how much updating is involved, you may want to go through all of the above steps again. You should also thoroughly update the documentation and include in it the information on who updated it, when and why, and what changes were made.

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4.3. FINANCIAL MODELING OF A THERMAL POWER PLANT

4.3.1. CERC GUIDELINES 2009-2014 FOR TARIFF CALCULATION

Procedure for Tariff Determination and Computation of Capital Cost and Capital Structure

Tariff Determination:

Tariff in respect of a generating station may be determined for the whole of the generating station or a stage or unit or block of the generating station, and tariff for the transmission system may be determined for the whole of the transmission system or the transmission line or sub-station.

For the purpose of determination of tariff, the capital cost of the project may be broken up into stages and distinct units or blocks, transmission lines and sub-systems forming part of the project.

Application for the determination of tariff:

The generating company may make an application for determination of tariff in accordance with Central Electricity Regulatory Commission (Procedure for making of application for determination of tariff, publication of the application and other related matters) Regulations, 2004, as amended from time to time or any statutory re-enactment thereof, in respect of the units of the generating stations completed or projected to be completed within six months from the date of application.

The generating company shall make an application as per Appendix Ito these regulations, for determination of tariff based on capital expenditure incurred duly certified by the auditors or projected to be incurred up to the date of commercial operation and additional capital expenditure incurred duly certified by the auditors or projected to be incurred during the tariff period of the generating station:

Provided further that application shall contain details of underlying assumptions for projected capital cost and additional capital expenditure, where applicable

Truing up of capital expenditure and tariff:

The Commission shall carry out truing up exercise along with the tariff petition filed for the next tariff period, with respect to the capital expenditure including additional capital expenditure incurred up to 31.3.2014, as admitted by the Commission after prudence check at the time ofTruing up. Provided that the generating company or the transmission licensee, as the case may be, may in its discretion make an application before the Commission one more time prior to 2013-14 for revision of tariff.

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Capital Cost:

Capital cost for a project shall include the expenditure incurred or projected to be incurred, including interest during construction and financing charges, any gain or loss on account of foreign exchange risk variation during construction on the loan - (I) being equal to 70% of the funds deployed, in the event of the actual equity in excess of 30% of the funds deployed, by treating the excess equity as normative loan, or (ii) being equal to the actual amount of loan in the event of the actual equity less than 30% of the funds deployed, - up to the date of commercial operation of the project, as admitted by the Commission, after prudence checkThe capital cost admitted by the Commission after prudence check shall form the basis for determination of tariff:

Provided that in case of the thermal generating station prudence check of capital cost may be carried out based on the benchmark norms to be specified by the Commission from time to time

Provided further that in cases where benchmark norms have not been specified, prudence check may include scrutiny of the reasonableness of the capital expenditure, financing plan, interest during construction, use of efficient technology, cost over-run and time over-run, and such other matters as may be considered appropriate by the Commission for determination of tariff

Initial Spares:

Initial spares shall be capitalised as a percentage of the original project cost, subject to following ceiling norms:

(I) Coal-based/lignite-fired thermal generating stations - 2.5%

(ii) Gas Turbine/Combined Cycle thermal generating stations - 4.0%

Debt-Equity Ratio:

For a project declared under commercial operation on or after 1.4.2009, if the equity actually deployed is more than 30% of the capital cost, equity in excess of 30% shall be treated as normative loan:

Provided that where equity actually deployed is less than 30% of the capital cost, the actual equity shall be considered for determination of tariff:

Provided further that the equity invested in foreign currency shall be designated in Indian rupees on the date of each investment

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Components of Tariff:

The tariff for supply of electricity from a thermal generating station shall comprise two parts, namely, capacity charge (for recovery of annual fixed cost consisting of the components specified to in regulation 14) and energy charge (for recovery of primary fuel cost and limestone cost where applicable).

Annual Fixed Cost:

The annual fixed cost (AFC) of a generating station or a transmission system shall consist of the following components –

(a) Return on equity;

(b) Interest on loan capital;

(c) Depreciation;

(d) Interest on working capital;

(e) Operation and maintenance expenses;

(f) Cost of secondary fuel oil (for coal-based and lignite fired generating stations only)

Return on Equity:

Return on equity shall be computed on pre-tax basis at the base rate of 15.5%

Provided that in case of projects commissioned on or after 1st April, 2009, an additional return of 0.5% shall be allowed if such projects are completed within the timeline specified in Appendix-II of the guidelines issued by the CERC.

Provided further that the additional return of 0.5% shall not be admissible if the project is not completed within the timeline specified above for reasons whatsoever

Rate of return on equity shall be rounded off to three decimal points and be computed as per the formula given below:Rate of pre-tax return on equity = Base rate / (1-t) Where t is the applicable tax rate

Interest on Loan Capital:

The normative loan outstanding as on 1.4.2009 shall be worked out by deducting the cumulative repayment as admitted by the Commission up to 31.3.2009 from the gross normative loan.

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The repayment for the year of the tariff period 2009-14 shall be deemed to be equal to the depreciation allowed for that year

Notwithstanding any moratorium period availed by the generating company repayment of loan shall be considered from the first year of commercial operation of the project and shall be equal to the annual depreciation allowed

The rate of interest shall be the weighted average rate of interest calculated on the basis of the actual loan portfolio at the beginning of each year applicable to the project:

Provided that if there is no actual loan for a particular year but normative loan is still outstanding, the last available weighted average rate of interest shall be considered:

Provided further that if the generating station does not have actual loan, then the weighted average rate of interest of the generating company or the transmission licensee as a whole shall be considered

The interest on loan shall be calculated on the normative average loan of the year by applying the weighted average rate of interest.

The generating company shall make every effort to re-finance the loan as long as it results in net savings on interest and in that event the costs associated with such re-financing shall be borne by the beneficiaries and the net savings shall be shared between the beneficiaries and the generating company in the ratio of 2:1.

Depreciation:

The value base for the purpose of depreciation shall be the capital cost of the asset admitted by the Commission. The salvage value of the asset shall be considered as 10% and depreciation shall be allowed up to maximum of 90% of the capital cost of the asset.Depreciation shall be calculated annually based on Straight Line Method.

Provided that, the remaining depreciable value as on 31st March of the year closing after a period of 12 years from date of commercial operation shall be spread over the balance useful life of the assets.Depreciation shall be chargeable from the first year of commercial operation.

Interest on Working Capital:

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The working capital shall cover:(A) Coal-based/lignite-fired thermal generating stations:

(I) Cost of coal or lignite and limestone, if applicable, for 1½ months for pithead generating stations and two months for non-pit-head generating stations, for generation corresponding to the normative annual plant availability factor;

(ii) Cost of secondary fuel oil for two months for generation corresponding to the normative annual plant availability factor, and in case of use of more than one secondary fuel oil, cost of fuel oil stock for the main secondary fuel oil;

(iii) Maintenance spares @ 20% of operation and maintenance expenses;

(iv) Receivables equivalent to two months of capacity charges and energy charges for sale of electricity calculated on the normative annual plant availability factor, and

(v) Operation and maintenance expenses for one month.

(B) Open-cycle Gas Turbine/Combined Cycle thermal generating stations:

(I) Fuel cost for one month corresponding to the normative annual plant availability factor, duly taking into account mode of operation of the generating station on gas fuel and liquid fuel;

(ii) Liquid fuel stock for ½ month corresponding to the normative annual plant availability factor, and in case of use of more than one liquid fuel, cost of main liquid fuel;

(iii)Maintenance spares @ 30% of operation and maintenance;

(iv) Receivables equivalent to two months of capacity charge and energy charge for sale of electricity calculated on normative plant availability factor, duly taking into account mode of operation of the generating station on gas fuel and liquid fuel, and(v) Operation and maintenance expenses for one month.

Interest on working capital shall be payable on normative basis notwithstanding that the generating company has not taken loan for working capital from any outside agency.

Operation and Maintenance Expenses:Normative operation and maintenance expenses shall be as follows, namely:

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(a) Coal based and lignite fired (including those based on CFBC technology) generating stations

Provided that the above norms shall be multiplied by the following factors for additional units in respective unit sizes for the units whose COD occurs on or after 1.4.2009 in the same station:



500 MW and above Additional 3rd & 4th units 0.9, Additional 5th & above units 0.85

(b) Open Cycle Gas Turbine/Combined Cycle generating stations

In case of coal-based or lignite-fired thermal generating station a separate compensation allowance unit-wise shall be admissible to meet expenses on new assets of capital nature including in the nature of minor assets, in the following manner from the year following the year of completion of 10, 15, or 20 years of useful life:

Years of operation Compensation Allowance (Rs lakhs/MW/year)

0-10 Nil

11-15 0.15

16-20 0.35

21-25 0.65

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The operation and maintenance expenses for the year 2009-10 shall be escalated further at the rate of 5.72% per annum to arrive at permissible operation and maintenance expenses for the subsequent years of the tariff period.

Normative Annual Plant Availability Factor: - 85%

Gross Station Heat Rate: Thermal Generating Station achieving COD on or after 1.4.2009

(a) Coal-based and lignite-fired Thermal Generating Stations = 1.065 X Design Heat Rate (kCal/kWh)

Where the Design Heat Rate of a unit means the unit heat rate guaranteed by the supplier at conditions of 100% MCR, zero percent make up, design coal and design cooling water temperature/back pressure.

Provided that the design heat rate shall not exceed the following maximum design unit heat rates depending upon the pressure and temperature ratings of the units:

Provided further that in case pressure and temperature parameters of a unit are different from above ratings, the maximum design unit heat rate of the nearest class shall be taken

Provided also that where unit heat rate has not been guaranteed but turbine cycle heat rate and boiler efficiency are guaranteed separately by the same supplier or different suppliers, the unit design heat rate shall be arrived at by using guaranteed turbine cycle heat rate and boiler efficiency.

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(b) Gas-based / Liquid-based thermal generating unit(s)/ block(s)

= 1.05 X Design Heat Rate of the unit/block for Natural Gas and RLNG (KCal/kWh)

= 1.071 X Design Heat Rate of the unit/block for Liquid Fuel (kCal/kWh)

Where the Design Heat Rate of a unit shall mean the guaranteed heat rate for a unit at 100% MCR and at site ambient conditions; and the Design Heat Rate of a block shall mean the guaranteed heat rate for a block at 100% MCR, site ambient conditions, zero percent make up, design cooling water temperature/back pressure.

Secondary Fuel Oil Consumption:

Coal-based generating stations: 1.0 ml/kWh

Auxiliary Energy Consumption:

(a) Coal-based generating stations except

Provided further that for thermal generating stations with induced draft cooling towers, the norms shall be further increased by 0.5%

(c) Gas Turbine/Combined Cycle generating stations:

Combined cycle - 3.0%

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4.3.2. MECHANISM FOR FINANCIAL MODELING

Project Cost and IDC (Interest during Construction)

The project cost includes various expenses, which is divided into two categories, which consists of the following components.

Hard Cost:

This includes those cost which occurs due to tangible components of the project.

Land

Boiler and Turbine-Generator Package

Civil Works

BOP Mechanical

BOP Electrical

C & I Package

Initial Spares

Township and Colony

Start up Fuel

Soft Cost:

This cost includes those components which are intangible in nature

Preliminary Investigation & Site Development

Rehabilitation & Resettlement

Design & Engineering

Audit & Accounts

Operator's Training

Site Supervision

Interest During Construction (IDC)

Financing Charges (FC)

Assumption and Input Sheet:

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This sheet consists of two parts one is the financial assumptions and input the other is the technical assumptions and inputs.

The above two parts are further classified under two heads i.e. the regulatory assumptions and input and companies assumptions and inputs.

Fixed Cost Calculation:

There are five components of fixed cost calculation:

Interest on loan

Depreciation

O&M Expenses

Interest on Working Capital

Return on Equity

Note: For coal based one more components i.e. Secondary fuel oil is also considered

Variable Cost Calculation:

As per CERC Norms

Cash Flow Statement:

In financial accounting, a cash flow statement is a financial statement that shows a company's incoming and outgoing money during a time period (often monthly or quarterly).

The statement shows how changes in balance sheet and P & L accounts affected cash and cash equivalents, and breaks the analysis down according to operating, investing, and financing activities.

As an analytical tool the statement of cash flows is useful in determining the short-term viability of a company, particularly its ability to pay bills.

People and groups interested in cash flow statements include

Accounting personnel, who need to know whether the organization will be able to cover payroll and other immediate expenses and Potential lenders or creditors who want a clear picture of a company's ability to repay.

Profit & Loss Account:

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An Income Statement, also called a Profit and Loss Statement (P&L), is a financial statement for companies that indicates how net revenue (money received from the sale of products and services before expenses are taken out) is transformed into net income (the result after all revenues and expenses have been accounted for). The purpose of the income statement is to show managers and investors whether the company made or lost money during the period being reported.

Income statements should help investors and creditors determine the past performance of the enterprise; predict future performance; and assess the risk of achieving future cash flows. There are mainly following components of P&L Account Net Revenue - Inflows or other enhancements of assets of an entity or settlements of its liabilities during a period from delivering or producing goods, rendering services, or other activities that constitute the entity's ongoing major or central operations, usually presented as sales minus sales discount, returns, and allowances. Expenses - Outflows or other using-up of assets or incurrence of liabilities during a period from delivering or producing goods, rendering services, or carrying out other activities that constitute the entity's ongoing major or central operations. Here in this case the net revenue is obtained by selling the generated power then the coal cost, secondary fuel cost and the O & M Expenses are subtracted to get PBDIT i.e. profit before depreciation, interest and tax. Then the depreciation including the AAD is reduced from PBDIT it will give the value of PBIT i.e. profit before interest and tax. Again the interest value for working capital is calculated for 75% 0f the working capital and interest on loan is added up which together is subtracted from the PBIT, this will give PBT, i.e. profit before tax. Further the tax calculated from the tax sheet is subtracted from the PBT, to give the value of PAT.

Tax Calculation:

The tax is calculated here as per the income tax rules i.e. the corporate tax is not applicable for 10 years because of 10 year tax holiday to the generating plants, so Minimum Alternate Tax (MAT) is applied then after that period the corporate tax is applicable.

Minimum Alternate Tax (MAT) = 20.007%

Corporate Tax = 33.33%

4.3.3. FINANCIAL INDICATORS

4.3.3.1. Net Present Value (NPV)

Net present value (NPV) is a standard method for the financial appraisal of long-term projects. It is used for capital budgeting, and widely throughout in economics. It measures the excess or shortfall of cash flows, in present value (PV) terms, once financing charges are met.

By definition, NPV = Present value of net cash flows.

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Each cash inflow/outflow is discounted back to its PV and is summed.

NPV=∑ (t=1 to n) {C (t)/ (1+r) ^t}-C (o)

Where

t - The time of the cash flow

n - The total time of the project

r - The discount rate

C (t) - the net cash flow (the amount of cash) at time t

C (0) - the capital outlay at the beginning of the investment time (t = 0)

4.3.3.2. Discount Rate

Choosing an appropriate discount rate is crucial to the NPV calculation. A good practice of choosing the discount rate is to decide the rate which the capital needed for the project could return if invested in an alternative Venture.

Relationship between the NPV and the discount rate: For some professional investors, their investment funds are committed to target a specified rate of return. In such cases, that rate of return should be selected as the discount rate for the NPV calculation. In this way, a direct comparison can be made between the profitability of the project and the desired rate of return.

If NPV > 0, the investment would add value to the firm, so the project should be accepted.

If NPV < 0, the investment would decrease value of the firm, so the project should be rejected.

NPV = 0, the investment would neither add nor decrease value of the firm, so we should be indifferent in the decision whether to accept or reject the project. This project adds no monetary value to the firm.

4.3.3.3. Internal Rate of Return (IRR)

The internal rate of return (IRR) is a capital budgeting method used by firms to decide whether they should make long-term investments. The IRR is the annualized effective compounded return rate which can be earned on the invested capital, i.e. the yield on the investment.

A project is a good investment proposition if its IRR is greater than the rate of return that could be earned by alternative investments (e.g. investing in other projects, buying bonds, even putting the money in a bank account). Thus, the IRR should be compared to an alternative cost of capital including an appropriate risk premium.

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Mathematically the IRR is defined as any discount rate that results in a net present value of zero of a series of cash flows.

In general, if the IRR is greater than the project's cost of capital, or hurdle rate, the project will add value for the company. To find the internal rate of return, find the IRR that satisfies the following equation:

C (o) = ∑ (t=1 to n) C (t)/ (1+ IRR) ^t

Where

C (o) - Initial Investment

C (t) - the net cash flow (the amount of cash) at time t

N- Total time of the project in years

To understand internal rate of return, we must first know what is NPV or net present value. IRR is discounted rate of return derived based on the condition that net present value for an investment is 0. IRR is then compared to the company’s discounted rate of return. If IRR is higher than the company’s / projects discounted rate of returns, then the investment is deemed to be worthwhile for the company or investor. The investors themselves determine the discounted rate of return for the company. Discounted rate of return is derived based on a number of factors. One of them is the consideration of risk. If the investor is evaluating a more risky investment, he is likely to have a higher rate of return.

4.4. FINANCIAL MODELING OF 2*660 MW COAL BASED TPP

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Installed Capacity (IC): 2*660 MW

Contracted Capacity: 1000 MW

Auxiliary Consumption: 6% (for steam driven BFP)(Approximately Equals to 80 MW)

Surplus Capacity: 240MW (this spare power will be sold in Electricity Market. For determination of revenue, data of year 2011 have been taken form IEX.)

Basic Characteristics of the plant: It is coal based thermal power plant with supercritical technology (once through generator).

Supercritical Technology: The term supercritical refers to steam operating conditions being above the critical pressure of water (221.5 bar). The significance of the critical point is the difference between steam and water. Above the critical pressure there is no difference between steam and water (i.e. above 221.5 bar, water is fluid.).

In supercritical cycle, equipment is designed to operate above the critical pressure of water. Typically current supercritical units operate at 242 bar main-steam pressure, 565 degree C main-steam temperature and 593 degree C reheat-steam temperature.

Advantages of Supercritical Technology:1. Plant Efficiency (0.69% to 1.64%) improvement. With current supercritical parameter

42% of overall plant efficiency is achievable. 2. Fuel tolerance – more tolerant to change in coal quality3. About 4% reduction in coal consumption and hence ash production. Emission of CO2,

SOx, and NOx is also reduced. Improved heat rate results in 5% reduction in fuel consumption and hence 5% reductions in CO2 per MWh energy output. Typically for 800 MW supercritical unit the annual reduction in CO2 emission will be about 725000 tonnes of CO2 with respect to baseline emission norms established by CEA for 2008-2009.

4. Startup time improves.5. Load following capability improves.6. Efficiency gain of about 2% over sub-critical technology.

Station Heat Rate (SHR): According to CERC, the designed heat rate should not exceed the maximum designed unit rate for pressure 247 bar (kg/cm2) and SHT/RHT (C) of 565/593. The designed rate is

a) 2176Kcal/Kwh for sub-bituminous Indian coal (turbine driven BFP).b) 2300 Kcal/Kwh for sub-bituminous Indian coal (electricity driven BFP).

Station heat rate= [Specific coal consumption (kg/kwh) X G.C.V. of coal (Kcal/kg)] + [Specific oil consumption (ml/Kwh) X G.C.V. of oil (Kcal/lit)] Specific coal consumption =total coal consumption in a month (kg)/ Gross monthly Generation (Kwh) Specific oil consumption = total oil consumption in a month (lit)/ Gross monthly

Generation (Kwh)

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Fuel Requirement

a) Primary fuel: Coal block is approximately 100 kms away from the plant.Total coal requirement = 6.102 MMTPA

(Station heat rate= 2176 Kcal/Kwh with turbine driven BFP)Gross Calorific Value of coal = 3700 Kcal/kg.Cost of Coal (per tonne) = Rs. 630 (G.C.V between 3700 – 4000 kcal/kg)Total cost of Coal required annually = Rs. 3844.26 million

b) Secondary fuelSecondary fuel oil = Light Diesel Oil (LDO) and Heavy Fuel Oil (HFO).Secondary fuel requirement = 1 ml/kwh.Gross Calorific Value of oil = 10800.00 Kcal/lit.

Water RequirementTotal Water requirement = 50 MCM (annually)Total annual cost of water = Rs. 250 million (@ Rs.5/cubic meter) Water Source: Nearby River

Plant LocationDistance of water source: ~ 2 kms form the plantNearest railway station: 5 kms away.

Land Requirement: 1200 acres

Particulars Area (in acres)

Land for plant 345Ash disposal Area 337Green Belt 359Staff Township 59Miscellaneous (office, stores, other infrastructure) 100Total 1200

Cost of land: 5 lakhs/ acre

Total cost of land: 6000 lakhs

Total time required: 45 months for the first unit and additional 6 months for the nextUnit according to CERC guidelines

Financial modeling of the 2*660 MW TPP has been done in Excel and attached here.

CHAPTER 5

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RESULTS AND DISCUSSIONS

5.1. RESULTS

The Competitive Bidding Guidelines (CBG) was issued in Jan 2005 to enhance transparency and fairness in procurement of power by utilities. Ever since the introduction of CBG about 42605 MW of capacity have been awarded with 30 cases under Case 1 and Case 2 bidding conducted successfully.

The framework has not only resulted in providing a strong platform for private sector participation in the power generation but has also resulted in considerably low tariff discoveries particularly in comparison to the traditional cost plus regime, that will ultimately benefit the consumers in terms of availability of cost effective power.

Of the total capacity aggregate capacity added under Case 1 and Case 2 i.e. 42605 MW:

14224 (34%) is based on imported coal.

18521 MW (44%) is based on domestic coal.

9320 MW (22%) is based on captive coal block

Tariffs under competitive bidding have been found to be lower than cost plus mechanism. Several reports including the statutory advice of the CERC regarding timeframe for tariff based competitive bidding bring out this fact.

An analysis of Case 2 bids indicates relatively lower tariffs than Case 1 bids. One of the reasons for this has also been low risk in Case 2 project than Case 1 project, wherein most of the facilitation is provided by the procurer. Within Case 2 bids, while UMPPs bidding have witnessed lower tariffs, most of the other projects have witnessed prices in the range of Rs. 2 to 3/kWh.

The levelised capacity charge for the twelve (12) Case 1 projects (about 10630 MW) has equivalent or embedded capital cost between Rs. 3.5 - 4.5 Crore/MW whereas capital cost of recent projects developed through the older i.e. cost plus route, is Rs. 4.5 - 5.9 Crore/MW which show the efficiency of tariff determined through bidding mechanism.

The analysis of variable charges (after being normalized to 2010-11 rates) shows that for most projects the variable cost over the 25 year PPA period falls between Rs 1.5-3.50 per unit and is less than Rs 2 per unit for the first 15 years of the PPA. As against this the current variable charges of many of the cost plus projects in states such as Maharashtra, Tamil Nadu and Rajasthan are well above Rs 2 per unit for the year 2010 itself.

5.2. DISCUSSIONS AND RECOMMENDATIONS

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The process of procurement of power through competitive bidding took off smoothly after the introduction of CBG. With rapid capacity addition in progress, problems like shortage of fuel, lack of infrastructure, biased behavior of state governments, problems of getting clearances, information asymmetry etc surfaced. These problems not only decreased the enthusiasms of power sector players but also left many projects idle either because of lack of fuel, finance, land or clearances regarding environment and forests.

In order to avoid such difficulties, following measures are recommended:

1. Protection of Developer’s interest: The existing framework does not protect the interest of the developers (in case of project based on imported coal) from coal price changes by any “Change in Law” event in the coal exporting country. Such instances have exposed the vulnerability of the power projects based on imported coal due to legal/regulatory changes in coal exporting, which are beyond the control of coal producers. Hence, the SBD for Case 2 should include a change in law/regulation of exporting countries for imported coal based projects, for protecting the developers from their impact as it is beyond their control. In such cases, in the event of reduction in international prices of coal, the benefit of the same can be passed on to power purchasers.

2. Timely Completion of pre-construction Activities: Delay in the pre-construction activities from the Procurers end leads to delay in the project completion that impacts the developers, it is suggested that the Letter of Intent (LoI) for the project should be issued only when the pre-construction activities are completed. This is also in line with the provisions of the competitive bidding guidelines.

3. Free and Fair Bidding Process: Re-bidding negatively affects the investor confidence and raises questions on fairness of the bid process. It is suggested that if the tariff is determined by the process as laid down in the Competitive Bidding Guidelines 2005 and the regulators can find no flaw in the process, the same tariff should be adopted. Further, no tariff negotiations should be allowed after opening of financial bids.

4. Separate SBD for Gas-based Project: Current framework is unsuitable for gas based projects due to various differences discussed above, hence to ensure level playing field for gas based projects including recognizing the realities and market dynamics of the national and international gas sector there is need for a separate SBD for gas based projects.

5. Enhance Communication Between all Parties: Any change in the clauses of SBD or the nature and character of the project (size merchant sales etc) should be notified prior to the bidding process to ensure a level playing field for all bidders and discovery of most economical tariffs.

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6. Non availability of transmission network on account of delay due to the CTU/STU is beyond the control of the developer and hence the developer should not be penalized on account of such delays.

7. Timely Completion of Bidding Process: Delay in the bid process results in opportunity loss for the unsuccessful bidders who are unable to participate in other bids, as the capacity remains locked up. It is therefore suggested that all efforts should be made to complete the bid process in a timely manner. The Regulatory authorities should be empowered with the responsibility of ensuring this.

8. Coordination among State Boards: Coordination among State Boards can ensure availability of power from power-surplus state to power-deficit state. This will also help in mobilization of resources.

9. Gradual Decommissioning of Old and inefficient Units: Old and inefficient units (unit size less than 100 MW) need large amount of money for R & M to extend life and ensure availability. These plants also consume a lot of fuel. It would be better to decommission them and provide coal linkages to efficient plants.

10. Availability of Coal: Limited Availability of coal is a matter of great concern. Following activities can improve the situation: Use of domestic coal in judicious and most appropriate manner. Due to shortage of

domestic coal, import of coal may also be tied up. A policy decision may have to be taken to allocate coal blocks to super critical plants in future.

Acquisition of fuel assets abroad by power developers and other industries should be backed by the Government.

Development of specialized ports/jetties well equipped with modern coal handling systems.

Roads, Railways and other infrastructure should be improved to facilitate the transportation of coal, main plant and BOP equipments.

Implementation of express and dedicated freight Corridor for transportation of coal. Mining agency and the equipments & methods used for mining should be improved. Timely permission by MoEF for coal mining and Private sector participation in Coal

mining Setting of washeries for reduce burden on railways and to improve efficiency of

power stations.

CHAPTER 6

CONCLUSION AND WAY FORWARD

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6.1. CONCLUSION

The Case 1- Case 2 Bidding Framework should be made more flexible and compatible to the dynamic environment. Based on the assessment most of the plant through competitive bidding will face difficulties:

Plants based on imported coal will face pricing issues on account of change in law of mining in the host country (like in Indonesia and Australia). Total affected capacity is ~14224 MW.

Plants based on domestic coal will face issues related to coal availability and consequent pricing issues if they shift to alternate means to source coal. Total affected capacity is ~18521 MW.

In case of plants based on captive mines, there may be delay in commissioning due to issues related to environment clearances, however there are no pricing issues associated with such plants going forward.

Gas based plants will also face pricing issues and fuel shortages

6.2. FUTURE SCOPE OF WORK

The 12th five year plan aims to achieve 1, 00,000 MW of installed capacity over the next five years and the competitive bidding mechanism is going to play an important role. The smooth

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implementation of the framework will ensure optimum utilization of natural resources like land, minerals and water and will help in inclusive growth of our country.

The rural India where electricity is still not available, the Gov. can allot distributed source of generation through competitive bidding for generation and distribution of electricity.

Renewable sector has great potential and is also environment friendly. So, competitive bidding mechanism can be used to set up wind or solar power plants in those areas where either coal, gas or hydro can’t be set up.

The competitive bidding mechanism has resulted in lower tariff. This process has potential to decrease the cost of electricity and hence overall cost of goods and services. So it is beneficial not only for individuals but also for the overall health of the economy.

6.3. LIMITATIONS OF THE PROJECT

The project and study has the following limitations:

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All the records of tariff have been taken from the site of Forum of Regulators (FoR), Central Electricity Authority (CEA) and Central Electricity Regulatory Commission (CERC).

In this project, a complete analysis of competitive bidding has been done under both Case 1 and Case 2 mechanisms. But a financial modeling has been done for a 2*660 MW coal based thermal power plants based on supercritical technology. So the scope of the financial modeling is limited to a 2*660 MW coal based TPP.

All hard costs have been calculated according to the benchmark-cost prescribed by the CERC.

The financial ratios are highly subjected to project and factors affecting them. Also, the figures were calculated taking many assumptions which may not hold in reality.

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BIBLIOGRAPHY

[1] www.cea.nic.in/reports/powersystems/nep2012/generation_12.pdf

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[4] www.cea.nic.in

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[11] www.iexindia.com

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[13] http://cercind.gov.in/2012/orders/order_79_TT_2011.pdf

[14] http://powermin.nic.in/whats_new/competitive_guidelines.htm

[15] http://www.infraline.com/power/events/discussion/Ashok_Khurana_APP.pdf

[16]http://www.infraline.com/details/Case-I-Case-II-bidding-projects-Evaluating-Competitive-Regime-Mar-28-2011-New-Delhi-156016.htm

[17] http://cercind.gov.in/2009/February09/SOR-regulations-on-T&C-of-tariff-05022009.pdf

[18] http://ebookbrowse.com/sor-regulations-on-t-c-of-tariff-05022009-pdf-d25033956

[19]http://www.idfc.com/pdf/publications/Issues_with_Tariff_based_Competitive_Bidding_under_Case_I_route.pdf

[20]http://www.iitk.ac.in/ime/anoops/for10/pdf/17%20%20Rajat%20Mishra%20%20Competitve%20Building%20Guidelines%20and%20Recent%20Experiences.pdf

[21] http://www.tatapower.com/regulations/pdf/tpcd-apr-fy10.pdf

[22] http://www.infraline.com/power/setup/tatapower/tatapower.aspx

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[23] http://www.rel.co.in/pdf/RInfra-Generation-FY%2009-10andFY-10-11-petition.pdf

[24]http://www.cercind.gov.in/2010/November/Signed_Order_256-2010_RE_Tariff_FY_11-12.pdf

[25] http://www.powermin.nic.in/reports/pdf/Annual_Report_200809_English.pdf

[26] http://info.ornl.gov/sites/publications/files/Pub4856.pdf

[27]http://elmu.umm.ac.id/file.php/1/jurnal/Ja/Journal%2520Of%2520Economic%2520Dynamics%2520And%2520Control/Vol25.Issue3-4.March2001/1344.pdf

[28]http://economics.eller.arizona.edu/docs/Seminar_Papers/Paper_Archives/Sp10_puller_electricity_part1.pdf

[29] http://en.cnki.com.cn/Article_en/CJFDTOTAL-DLZD200301005.htm

[30] http://www.sciencedirect.com/science/article/pii/S0167718702000401

[31] http://econ.gsia.cmu.edu/ecommerce/joskow.pdf

[32] http://econ.gsia.cmu.edu/ecommerce/joskow.pdf

[33]http://automatica.dei.unipd.it/public/Schenato/PSC/2010_2011/gruppo5Smart_grid_market/Bibliografia%20Progetto%2010/12_Framework%20for%20the%20incorporation%20of%20demandside%20in%20a%20competitive%20electricity%20market%20(Strbac,%20Farmer,%20Cory).pdf

[34] http://www.nber.org/papers/w6269.pdf?new_window=1

[35] http://ualr.edu/jdberleant/papers/Mei_PMAPS04a.pdf

[36] https://iaee.org/documents/vol21(3).pdf

[37] http://www.springerlink.com/content/jrh04573360255ur/

[38] http://www.sciencedirect.com/science/article/pii/S0142061500000326

[39]http://ece.ut.ac.ir/Classpages/S87/ECE688/articles/A%20Study%20of%20Basic%20Bidding%20Strategy%20in%20Clearing%20Pricing%20Auctions.pdf

[40]http://drum.lib.umd.edu/bitstream/1903/7058/1/cramton-bidding-behavior-in-electricity-markets-hawaii.pdf

[41]http://ieeexplore.ieee.org/xpl/login.jsp?tp=&arnumber=237910&url=http%3A%2F%2Fieeexplore.ieee.org%2Fxpls%2Fabs_all.jsp%3Farnumber%3D237910

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[44] http://papers.ssrn.com/sol3/papers.cfm?abstract_id=337900

[45]http://www.jstor.org/discover/10.2307/2632805?uid=3738256&uid=2&uid=4&sid=21101183699237

[46] http://www.dakotarichter.com/papers/IEEE_GA_biddingStrategies.pdf

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ANNIXURE 1

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Timeline for Completion of Projects: Thermal projects: Cola/lignite Plants

Unit size- 200/210/250/300/330 MW and 125 CFBC technologies

a) 33 months for [first unit of] green field projects. Subsequent units at an interval of 4 months each.

b) 31 months for [first units of] extension projects. Subsequent units at an interval of 4 months each.

Unit size 250 MW CFBC technology



Unit size 500/600 MW



Unit size 660/800 MW



ANNEXURE 2

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BENCHMARK HARD COST IN Rs. Crore per MW with December 2011 Indices as Base

Unit size in MW

500 500 500 500 500 500 600 600

Number of Units

1 2 3 4 1 2 1 2

Type GF GF GF GF Ext Ext GF GF

Total Hard Coat ***

5.08 4.71 4.48 4.34 4.92 4.53 4.87 4.54

Unit size in MW

600 600 600 600 660 660 660 660

Number of Units

3 4 1 2 1 2 3 4

Type GF GF Ext Ext GF GF GF GF

Total Hard Coat ***

4.32 4.01 4.47 4.19 5.37 5.01 4.67 4.37

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Unit size in MW

660 660 800 800 800 800 800 800

Number of Units

1 2 1 2 3 4 1 2

Type Ext Ext GF GF GF GF Ext Ext

Total Hard Coat ***

4.95 4.67 4.96 4.79 4.59 4.44 4.63 4.44

***Total Hard cost with December 2011 as base for indices includes Steam Generator/ Boiler Island, Turbine Generator Island, Associated Auxiliaries, Transformers, Switchgears, Cables, Cable Facilities, Grounding and Lighting Packages, Control & Instrumentation, Initial Spares for BGT, Balance of Plant including cooling tower, water system, coal handling plant, ash handling plant, Fuel oil unloading & Storage, Miscellaneous Package, Switchyard, Chimney, Emergency DG Set. This does not include MGR, Railway siding, unloading equipment at jetty, and Rolling Stock, Locomotive, Transmission line till tie point.

GF- Green Field

Ext- Extension

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