power sector financing project report
TRANSCRIPT
ACKOWLEDGEMENT
It is with a sense of gratitude, I acknowledge the efforts of entire hosts of well‐
wishers who have in some way or other contributed in their own special ways to the success
and completion of this project.
First of all, I express my sage sense of gratitude and indebtedness staff of NTPC‐SAIL
Power Company (P) Ltd (NSPCL), Bhilai from the bottom of my heart, for their immense
actions, support, and faith.
I sincerely thank my project guide Shri J.R Sikidar, Sr.Manager (F&A), NSPCL
Corporate Center, New Delhi for his valuable suggestions, motivation and encouragement
through out this project. Also, I also express my sincere thankfulness to NSPCL Finance &
accounting team, HR–Training and Development cell for extending their timely support.
.
B. SatyaGopi
MP‐072453801
Contents
Page no.
Acknowledgements i
Certificate of originality ii
Proforma for approval of project proposal iii
Executive summary & Synopsis vi
1.0 Introduction 1
2.0 Power Sector ‐ Emerging Scenario 3
2.1 Power Industry structure in India 4
3.0 Role of NTPC/NSPCL (A Jv of NTPC & SAIL) in Indian Power sector 7
4.0 Power sector & issues
4.1 Generation 11
4.2 Transmission 12
4.3 Distribution 13
4.4 Demand Supply Position 14
4.5 Financing Requirements 15
5.0 Power Project Life Cycle 17
5.1 Project Finance 17
5.2 Operational Agreements 18
5.3 Project Development 19
6.0 Project Economics 22
6.1 Fuels Supply 22
6.2 Capital costs 23
6.3 Wholesale Tariff Structure 24
7.0 Power Project Financing 26
7.1 Types and Sources of Finance 26
7.2 Trends in Power Sector Financing 31
7.3 Major Financiers in Power Sector 31
8.0 Budgeting in Power Plants; 32
8.1 Types of budget heads in power plant; 32
9.0 Capital Budgeting for dummy Power project; 36
9.1 Projections for a 500MW unit. 37
9.2 Projections for a 2x250MW unit 46
10.0 Conclusions & Recommendations 52
References/Bibliography
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1.0 Introduction
Power is the critical infrastructure for the growth of economy. Acceleration in the growth of
economy will depends upon a financially & commercially viable power sector that is able to attract
fresh investments. Even though India ranks 5th in the world in terms of total installed capacity; it is
one of the lowest in terms of per capita consumption of power. India has continuously experienced
shortages in energy and peak power requirements.
According to the Central Electricity Authority's ("CEA") monthly review of the power sector
("CEA Monthly Review") published in April 2012, the total energy deficit and peak power deficit for
March 2012 was approximately 8.5% and 10.1%, respectively. Along it, the Indian Power sector is
among the least efficient in the world in terms of output units of electricity per unit of fuel
(coal/gas/oil). Even if we compare India with other developing nations like China and Korea, India is
far behind in terms of generation efficiency.
As per the recent statement given to a question in Rajya Sabha on 07/05/2012 by Minister
of State for Power Shri K.C. Venugopal , “As per the 18th Electric Power Survey Report, Peak
Demand of 1,99,540 MW and Energy Requirement of 13,54,874 BU has been estimated at the end
of Twelfth Five Year Plan i.e. 2016‐17. At the end of 11th Five year Plan i.e. 2011‐12 the country
was facing Peak Shortage of 13815 MW (10.6 %) & Energy Shortage of 79313 MU (8.5 %).”
The Working Group on Power constituted by the Planning Commission to formulate the
12th Five Year Plan for the Power sector has submitted its report to the Planning Commission. As
per the report of this Working Group, capacity addition requirement during the 12th Plan is
75,785MW on all India basis. The Sector‐wise and fuel‐wise break up of 12th Plan capacity
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addition programme as per the report of the Working Group on Power is as under: (In MW)
Hydro Thermal Nuclear Total
Central 5632 11426 2800 19858
State 1456 12340 0 13796
Private 2116 40015 0 42131
Total 9204 63781 2800 75785
Source: Press information Bureau Dtd. 07/05/2012
The target for new capacity additions has created a platform for approximately 150 billion
USD of investments across different segment of the generation sector. Although, the system is still
in a transitory phase, deepening reforms and a new policy framework have to create an optimistic
outlook.
Therefore, there are following goals of this project
A brief Study of Power sector & Power Industry structure in India
Identifying the demand & supply gaps in Generation.
Role of NTPC/NSPCL (A Jv of NTPC & SAIL) in Indian Power sector.
Identifying various steps involved & study of Project life cycle of a power project.
Study of various sources of power project financing & Investment patterns.
Study of various costs involved, long term Capital Requirement & capital budgeting for the
Power Generation by taking a 500MW & 250MW model power projects.
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2.0 Power Sector Scenario & Industry Structure.
India has a total installed capacity of 200 GW as on April 2012. Even though India has been
the 5th largest producer of Electricity in the world, it continuously facing acute shortages during the
peak hours. The following table shows the preceding years Demand & deficit of Electricity.
Years Peak Deficit % Energy Deficit %
2000‐01 13 7.8 Actual Power demandSupply Position 2001‐02 11.8 7.5 Requirement Availability Surplus/deficit (+/‐) 2002‐03 12.2 8.8
Fiscal year (MU) (MU) (MU)
2003‐04 11.2 7.1 2005 591373 548115 ‐43258 ‐7.3 2004‐05 11.7 7.3 2006 631544 578819 ‐52725 ‐8.3 2005‐06 12.3 8.4 2007 690587 624495 ‐66092 ‐9.6 2006‐07 13.3 9.6 2008 737052 664660 ‐72392 ‐9.8 2007‐08 16.6 9.8 2009 777039 691038 ‐86001 ‐11.1 2008‐09 11 11.1 2010 830594 746644 ‐83950 ‐10.1 2009‐10 12.7 10.1 2011 861591 788355 ‐73236 ‐8.5 2010‐11 9.8 8.5 2012 933741 837374 ‐96367 ‐10.3 2011‐12 12.9 10.3
MU denotes Million Unit Source: CEA Reports
Considering the importance of development of power sector for the overall growth of
economy, planning commission has given due importance in the previous & current five year plans.
Indian Government has set ambitious target to achieve “Power to all “as per national electricity
plan. To revamp the Power Sector, Government of India have taken, number of path breaking
initiatives in the recent past, both in terms of policy pronouncements and programmes, ranging
from bringing increasing efficiency in generation segment through introduction of super critical
technology, penetration of commercial energy in the rural areas and consolidation of electricity
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delivery systems Indian Government has brought various structural changes to achieve the target
through Indian Electricity Act 2003.
Indian Electricity Act 2003;
The restructuring of power systems across the globe started with the redesigning of its
power markets. In India, electricity reforms started with the re‐evaluation of Indian Electricity Act‐
1910 and the Electricity Supply Act‐1948, which led to the Electricity Act, 2003. Indian Electricity
Act 2003 is the biggest mile stone in the history of Indian Power sector. The Electricity Act 2003 has
been brought about to facilitate private sector participation in Indian Power Sector and to help
cash strapped SEBs to meet electricity demand. The Electricity Act‐ 2003 envisages competition in
electricity market, protection of consumer’s interests and provision of power for all. The Act
recommends the provision for National Electricity Policy, rural electrification, open access in
transmission, phased open access in distribution, mandatory SERCs, license free generation and
distribution, power trading, mandatory metering, and stringent penalties for theft of electricity.
One more welcome step the Indian electricity market has seen is the implementation of
Availability Based Tariff (ABT) which brought about the effective day‐ahead scheduling and
frequency sensitive charges for the deviation from the schedule for efficient real‐time balancing.
2.1 Industry Structure
Public sector institutions continue to play the dominant role in the electricity supply and
delivery chain in India, primarily through central and state level government owned utilities. The
following figure depicts the interactions between the various players in the Indian power market.
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The Ministry of Power (MoP) is the Central government institution responsible for overseeing
India’s electricity industry. Several authorities and agencies operate under the MoP, among them
the Central Electricity Authority (CEA), assists the MoP on technical and economic issues.
Figure 2.2: Indian Power Market Institutional/Operational Framework
The Central Electricity Regulatory Commission (CERC) is an independent statutory body with
quasi‐judicial powers. The CERC has a mandate to regulate interstate tariff related matters, advise
the central government on formulation of the national tariff policy and promote competition and
efficiency in the electricity sector. The CERC regulates Central government owned utilities both in
generation and transmission. The State Electricity Regulatory Commissions (SERCs) have
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jurisdiction over state utilities in generation, transmission and distribution. Independent Power
Producers (IPPs) are regulated by CERC / SERC depending on whether they sell power to one or
more states. Regional Load Dispatch Centers (RLDCs) are responsible for managing the central
transmission system, whereas State Load Dispatch Center (SLDCs) manages the intra‐state and
some inter‐state systems. Central generating stations are contracted to state utilities and are
dispatched by RLDCs. State owned generating stations sell power to their own state distribution
licensee and are dispatched by SLDCs. Distribution licensees can also buy power from mega power
projects, IPP, traders and through the power exchange. The central government, through public
companies, owns and operates one‐third of total generation capacity and interstate transmission
lines. At the state level, SEBs own and operate most of the remaining two‐thirds of the generation
capacity, as well as the majority of intrastate transmission and distribution systems.
To promote power trading in a free power market, Central Electricity Regulatory
Commission (CERC) approved the setting up of Indian Energy Exchange (IEX) which is the first
power exchange in India. IEX has been modeled based on the experience of one of the most
successful international power exchanges, “Nordpool”. The exchange has been developed as
market based institution for providing price discovery and price risk management to the electricity
generators, distribution licensees, electricity traders, consumers and other stakeholders.
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3.0 Role of NTPC/NSPCL (A Jv of NTPC & SAIL) in Indian Power sector.
NTPC Limited (formerly known as National Thermal Power Generation Limited), India's largest
power company, was set up in 1975 with a vision “A world class integrated power major,
powering India’s growth with increasing global presence" to accelerate power development in
India. It has emerged as an “Integrated Power Major”, with a significant presence in the entire
value chain of power generation business. NTPC is a Government owned entity with 89.5% of its
paid‐up capital contributed by the Government and the balance of 10.5% being held with foreign
institutional investors, financial institutions, banks, and the general public. NTPC is awarded with
“MAHARATNA” PSU status by Government of India. NTPC is primarily involved in constructing and
operating power stations. It is among the world’s largest and most efficient power generation
companies. NTPC has installed capacity of 37514 MW as on April 2012. It has
16 coal based power stations (29,195 MW),
7 gas based power stations (3,955 MW) and
7 power stations in Joint Ventures (4,364 MW).
The company has power generating facilities in all major regions of the country. It plans to be a
75,000 MW company by 2017. NTPC is pursuing expansion of its business activities into
hydroelectric generation, coal mining, gas exploration, and participation in the liquefied natural gas
value chain, which supplements and supports its core power generation activities.
NSPCL is a Joint venture of two Maharatna companies “NTPC & SAIL” was incorporated on
7th March 2011, with 50:50 equity participation of both promoter companies. Primarily it was
started to own, operate and maintain the captive power plants of Steel Authority of India Ltd (SAIL)
at Rourkela, Durgapur and Bhilai. The company has been on the growth path since then.
8
Initially it started with an installed capacity of 314MW combined of all three power plants
supplying captive power to respective SAIL Units. Going in expansion mode, it added further
capacity of 500MW (2X250) at Bhilai in the year 2009, taking the total capacity to 814 MW. Now it
supply power not only to SAIL, but beyond the captive mode it also supplies power to Chhattisgarh
Dadra Nagar Haveli, Daman & Diu
Expansion project of Bhilai funded by Rural Electrification Corporation (REC) ‐1285Cr, Union
bank 444Cr and IDBI ‐200Cr as a debt.
The company is poised for further capacity addition to the tune of 1725 MW as per latest
corporate plan besides it is in the process of finalized it long term corporate plan to chart out its
ambitious growth path up to 2022 with a view to emerge as significant contributor to country’s
economic development.
Salient Features of NSPCL:
• The Net Worth of the Company is steadily increasing over the past 5 years.
• During the past 5 years (FY06 to FY10), the Net worth has increased from Rs389 Cr to Rs1135
Cr. In the year FY07, out of Rs. 868 Cr of Net Worth, Rs. 781 Cr is Share Capital and Rs. 87 Cr is
Reserves & Surplus. During this year the promoters had infused equity of Rs. 450 Cr for Bhilai
Expansion Power Project (2 x 250 MW).
• As on March 31, 2010, out of the total Share Capital of Rs. 951.50 Cr, Rs. 117.30 Cr of equity is
towards existing plants at Durgapur and Rourkela, Rs. 33.20 Cr pertains to existing plant (CPP‐
II) of Bhilai and the balance Rs. 800 Cr of equity is towards Bhilai Expansion Power Project (2 x
250 MW).
• The operational performance of NSPCL has improved consistently from FY02 to FY10. This is
owing to the renovation & modernization initiative taken by NSPCL and better operational
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management. NSPCL, Bhilai PP‐ IIs are old plants with dated technology. However, with
renovation & modernization initiatives taken by NSPCL the plants are running at high
operational parameters.
• There was a significant improvement in Durgapur and Bhilai plant in terms of units generated,
PLF and availability factor.
• Outages, auxiliary power consumption, specific oil consumption and heat rate have
significantly decreased from the time of take over to FY10 for all the three Units.
• The PLF of the plant till September2010 is 89.91% as against the Normative Annual Plant
Availability Factor of 85% as per the tariff order.
• The Gross Station Heat Rate for the Plant is 2399Kcal/kWh which is lower than Gross Station
Heat Rate as per the CERC Regulations.
• The Secondary fuel oil consumption for the plant is close to half as against CERC order.
• The Auxiliary Consumption for the Plant is less than auxiliary consumption prescribed in the
CERC Regulations for tariff computation.
• The return on equity is as per the CERC Regulations.
Opportunity Areas for NSPCL going forward
• Aggressive growth plans of SAIL which would need 4600 MW of captive requirement by 2020
• SAIL’s vision of entering the thermal power business as part of their Lakshya2020 initiative
through NSPCL.
• Huge demand for power generation capacity in India
• Taking over the PP1 plants of SAIL
• Taking over and turning around of DVC plants in Bokaro.
• Potential amendment of clause on minimum 51% power consumption by the promoter of the
captive power plant.
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• Leveraging existing land bank of SAIL for projects, which would result in lower gestation
periods Constructing and operating Captive power plants for other bulk consumers/ industrial
clusters / groups
• Supply through open access
−Supply to other SAIL plants through CTU
−Supply to Bulk and other industrial consumers
• Venturing into Power trading
• Entry into managed distribution (Eg: SAIL townships)
• Offering O&M and other consultancy services
• Investing in Renewable energy
• Investment for ash utilization
Key Threats and Challenges
• Heavy dependence on a single consumer (SAIL).
• Rapidly evolving technology
• Fuel Security
• Dependence on NTPC for manpower and technical know‐how
• Availability of skilled manpower in the market
• Gradual phasing out of cross‐subsidy (which would lead to convergence of IPP & CPP)
• Likely cheaper power from UMPPs and super critical power plants may be a threat in a
competitive market scenario.
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4.0 Power sector & issues
4.1 Generation
The current installed capacity is approximately 200 GW with coal being the primary fuel
source. Despite significant recent additions, there is a significant stock of aging plants that have
poor performances. The sector also suffers from, fuel shortages, inadequate transmission
evacuation system, regulatory uncertainty and payment security concerns. Concerns about the
sector paved the path for reforms. Of this the central and state sector accounted for approximately
89% [MOP, 2012]. The statistics point to high perception of risk lack of enthusiasm on part of the
private sector with regard to power generation in India.
In the Central Sector, National Thermal Power Corporation (NTPC) is a player of global scale. The
State Electricity Boards also operate generation facilities to serve their demand. Private Sector
comprises of many players like Tata Power Company, Reliance Energy, GVK, GMR etc. Despite
reforms introducing private participation in the early 1990s, India’s electricity sector has remained
dominated by the state owned entities and has been unable to attract adequate private
investments. Electricity Act 2003 introduced another wave of liberation aimed at create a legal and
structural framework for a competitive market.
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To maintain the projected economic growth, India needs to add 75 GW of new capacity by
2017. The growth in capacity must be matched with efforts to i) optimize utilization of unevenly
distributed fuel resources with proper evacuation system; ii) diversify fuel sources with cheaper
and cleaner fuel from huge hydro and other renewable energy; iii) build raw material and
infrastructural support; iv) adopt new generation technologies; and v) renovate and modernize
program of existing plants.
The total funds requirement for the generation segment during the 12th Plan has been
estimated to be approximately `1372580 Cr, of which central sector requirement is 49%. However,
lack of financing and higher interest rates are likely to impede funds mobilization. But at the same
time interest from foreign investors and the renewed interest of multilateral agencies in the
electricity sector has been strong. There has been resurgence of international interest in the Indian
power sector.
4.2 Transmission
Transmission plan in India has always been generation based. It is therefore not going to
help because there are bound to be imbalances. Even today, CTU and STU’s are very conservative
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in agreeing to create more than the desired transmission capacity and freely allowing
interconnectivity. Investments in the Transmission sector have been therefore been inadequate
due to the heavy emphasis on generation capacity. In most states, the existing distribution network
has been formed by expanding and connecting smaller and disjointed networks. Consequently,
there are several deficiencies in the Transmission system, such as high losses and low reliability.
The major player in this sector is the government owned Power Grid Corporation of India. The
total transmission system in India at 765/HVDC/400/230/220 kV corresponding to 1,32,329 Mega
Watts (MW) of installed generation capacity at the end of March 2007 was 198,089 circuit
kilometers of transmission lines, 251,439 MVA of AC substation and 8,200 MW of HVDC substation
capacity.
4.3 Distribution
India’s distribution sector has traditionally been a leaking bucket with the holes deliberately
crafted and the leaks carefully collected as economic rents by various stakeholders that control the
system. The logical thing to do would be to fix the bucket rather than to persistently emphasize
shortages of power and forever make exaggerated estimates of future demands for power. Most
initiatives in the power sector (IPPs and mega power projects) are nothing but ways of pouring
more water into the bucket so that the consistency and quantity of leaks are assured. The
Distribution arm of the Power Sector had been the domain of the SEBs for a very long time which
gave rise to financial problems due to lack of collection of dues. The SEB’s financial difficulties led
to problems in the upstream for power generation. To alleviate this situation Distribution
Companies are beginning to be privatized in some states, most notable among them being Delhi.
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Reliance Energy and Tata Power Company were the first private sector players to make a foray into
power distribution in the country.
4.4 Demand Supply Position
The steady increase in electricity demand is attributed to the country’s rapid economic
growth. Over and above India’s visible electricity demand growth, there is significant latent
demand that remains under‐represented. The following table shows the preceding years Demand
& deficit of Electricity.
Years Peak Deficit % Energy Deficit %
2000‐01 13 7.8 Actual Power demandSupply Position 2001‐02 11.8 7.5 Requirement Availability Surplus/deficit (+/‐) 2002‐03 12.2 8.8
Fiscal year (MU) (MU) (MU)
2003‐04 11.2 7.1 2005 591373 548115 ‐43258 ‐7.3 2004‐05 11.7 7.3 2006 631544 578819 ‐52725 ‐8.3 2005‐06 12.3 8.4 2007 690587 624495 ‐66092 ‐9.6 2006‐07 13.3 9.6 2008 737052 664660 ‐72392 ‐9.8 2007‐08 16.6 9.8 2009 777039 691038 ‐86001 ‐11.1 2008‐09 11 11.1 2010 830594 746644 ‐83950 ‐10.1 2009‐10 12.7 10.1 2011 861591 788355 ‐73236 ‐8.5 2010‐11 9.8 8.5 2012 933741 837374 ‐96367 ‐10.3 2011‐12 12.9 10.3
MU denotes Million Unit Source: CEA Reports
The demand projections have discounted the Places where electricity cables have not
reached yet and industries that would come up if supply of electricity is guaranteed. Shortage is
likely to be a major driver for new capacity development in future. Energy demand deficits have
increased from 7 percent to 10 percent in the past five years, indicating that a high latent demand
for electricity exists in India. This latent demand increases the potential for demand to grow even in
periods of slow economic growth.
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As the figure below shows, India has constantly been plagued with a demand supply gap in the
Power sector. Such a gap is a major hindrance to the growth of a developing economy like India.
4.5 Financing Requirements
The Working Group on Power has estimated that Rs. 1372580 Cr will be required by the
Power sector to meet the target of 75785 MW capacity additions and development of related
transmission and distribution infrastructure by the end of XII plan (FY 2012 ‐ FY 2017).
Overall Investment Requirement in 12th plan (2012‐2017)
Particulars Fund Requirement in Cr
1 Generation 638600 2 R&M 31887 3 Captive 65000 4 Renewable Energy sources 135100 5 Transmission 180000 6 Distribution 306235 7 R&D 4168 8 DSM &EE 7482 9 HRD 4108 Total Fund Requirement 1372580
Source: Planning Commission of India
The question of generating this huge amount of funds therefore assumes prime importance.
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The planned additions in all the three sectors will be missed if significant steps are not taken to
ensure a more congenial environment in the sector to bring in more investments. The investment
in generation, transmission, distribution and rural electrification should ideally be in the ratio of
4:2:1:1. This implies for each rupee invested in generation a similar investment is required in
Transmission & Distribution (T&D). Nevertheless, in practice actual investment in T&D so far has
been 30 percent. As a result there is a severe gap in transmission capacity at state levels. The ratio
for Central and State sectors has gradually improved over the various plan periods, but the Private
Sector remains a gaping hole. The private investment in T&D segment has not been enough and
needs to be roped in for balanced distribution of power across the regions.
While this could well be the investment needed, the absorption capacity, availability of financial
resources and the viability of utilities are likely to act as constraints in realizing these investment
projections. Hence the question of generating this huge amount of funds therefore assumes prime
importance. Significant steps to ensure a congenial environment in the sector for bringing in more
investments have to be taken up as lack of financing and higher interest rates are likely to impede
funds mobilization. But at the same time interest from foreign investors and the renewed interest
of multilateral agencies in the electricity sector has been strong. There has been a resurgence of
international interest in Indian Power Sector.
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5.0 Power Project Life Cycle
A typical Power Project Structure is a web of contracts. The Power Plant Promoters setup a
project company via the Special Purpose Vehicle (SPV) route i.e. the project company is a distinct
legal entity. The Company enters into two sets of agreements‐ Project Finance and Operational.
Table 3.1: Power Project Structure in India
5.1 Project Finance
A Power Plant is financed via the Project Finance route. Project finance is usually defined as
limited or non‐recourse financing of a new project through the establishment of a
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separately incorporated vehicle company. As of now Indian power sector is permitting debt: equity
ratio of 70:30. Project financing will be arranged from different finance institutions & markets in
terms of debt & equity.
5.2 Operational Agreements
EPC Contract:
The Company then enters into an agreement with an Engineering, Procurement and
Construction (EPC) contractor for setting up the physical facility for the Power Plant.
Fuel Supply Agreement:
The Company also enters into a long term Fuel Supply Agreement (FSA) to ensure fuel availability.
As the paper explains later, fuel is the most important component in ensuring the viability of the
project.
Power Purchase Agreements:
Off take of the Power generated by the plant is guaranteed by a Power Purchase Agreement (PPA)
with a TRANSCO. Some power may be utilized for merchant sales to industrial houses.
Government Clearances:
The Company also has to get the requisite clearances for the government with regard to property
rights, permits and environmental concerns. List of Major clearances required as follows;
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5.3 Project Development
From a planning and financing perspective, there are essentially three stages of independent power
project (IPP) development: development, construction, and operation. The sources of funds, in
general, are different for each stage. The risks associated with the completion of each stage are
also different and hence, the cost of the capital is different.
5.3.1 Development Period
During the development stage, one cannot be certain that a "financeable" project will
result. The project must first be defined in terms of the buyer's needs, the site, the fuel availability
and the permitting requirements. Then the feasibility work is done. This generally consists of
engineering, cost estimation and environmental work, as well as the development of preliminary
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project proformas. The developer must then obtain contracts, secure the site, and complete the
permitting for the plant. The contract that sets the direction for the rest of a project's development
is the power purchase agreement. It is during the development period that the greatest "value" is
being created because efficient planning and engineering capability decide on the viability of the
project and also the tariff competitiveness of the power produced is decided by the engineering
excellence of the plant. The source of funds generally used during this period is equity. The
developer and owner of the project provide these funds. The sources of financing for independent
power projects are scarce because the risks of development are high. Until the project reaches
financial closing for construction, there are a multitude of risks that could reduce the value of the
project to zero. These risks include:
Permitting risk
Political opposition to the project
Inability to secure fuel and fuel transportation under long‐term contract
Inability to obtain a financeable power purchase agreement, either because the power price
is too low or the terms are not acceptable
Regulatory disapprovals and Change in law
5.3.2 Construction Period
A project enters the construction stage when it has met all the requirements necessary to put
together a non‐recourse project financing. This means that all of the contracts are negotiated and
signed, the permits are granted, and the technology and equipment are selected. There
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is limited to no recourse to the developer if there is a problem. This is the nature of non‐recourse
project finance. The majority of the construction funds are through debt. The period of greatest
risk for them is just before the plant is completed, because they have almost their entire loan
outstanding and the plant is still not producing revenues. The Project Cost also includes provision
for Interest during construction and a margin for working capital finance both of which are
capitalized.
5.3.3 Operating Period
The primary financial management issue throughout the project life cycle is to minimize the
financial and operating costs of the project. Once a project reaches commercial operation, a
developer/owner has many options in terms of additional financing. For example, institutional
buyers such as insurance companies and pension funds, as well as the public markets (which do not
take construction risk), can now participate. The project now has real operating and financial data
that can be used to assess the plant's performance and financial expectations. The key is planning
and constant attention to the project finance debt market
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6.0 Project Economics
The cost of power generation varies, depending on the type of fuel used. The choice of fuel for a
power plant is influenced by a number of factors such as the relative cost of generation,
availability, transportation constraints, and environmental hurdles. The capital costs of power
plants also vary significantly, based on the source of energy, infrastructure, plant size, technology
and equipment and interest during construction (IDC).
6.1 Fuels Supply
As pointed out earlier, power plants with the lowest variable costs (Coal) should be employed to
meet the base demand, while those with a higher variable cost (Gas) should be employed to meet
the peaking demand. This will result in a minimum overall variable cost of power.
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Cost:
The delivered price of any fuel can vary significantly depending on the source of supply (imported
or indigenous) and the distance of the plant from the source of supply. Power plants located near
coal mines (pit‐head plants) are able to generate power at a fairly lower rate than plants that need
to transport coal over long distances.
Supply:
An interruption in the fuel supply can lower the plant’s PLF, resulting in a higher overall cost of
power. Given the fuel supply constraints faced by existing power plants, banks and financial
institutions insist on a regular fuel supply arrangement (FSA) before funding private sector power
projects, especially those proposed to be funded on a non‐recourse basis. As a result, private
power producers want to have legally enforceable fuel supply agreements with fuel suppliers and
fuel transporters where the power producer would pay a premium on the price of the fuel, to
ensure its adequate and regular supply and would also guarantee a minimum off take of fuel from
the fuel supplier.
6.2 Capital costs;
Power projects are highly capital‐intensive and have a gestation period of 4‐6 years. The fixed
component of the power tariff is linked to the capital cost of the project. Hence, the capital cost of
a power project is a very important determinant of the total cost of generation. The capital costs of
power plants also vary significantly, based on the source of energy, infrastructure, plant size,
technology and equipment and interest during construction (IDC). Hence, it is not possible to set
standard benchmark costs for power plants. However, the capital costs of most projects in the
private sector are assumed as shown in the table above
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6.3 Wholesale Tariff Structure
The term Availability Tariff ‐‐ in the Indian context ‐‐ stands for a rational tariff structure for
power supply from generating stations on a contracted basis. In the Availability Tariff mechanism,
the fixed and variable cost components are treated separately. The payment of fixed cost to the
generating company is linked to availability of the plant, that is, its capability to deliver MWs on a
day‐by‐day basis. The total amount payable to the generating company over a year towards the
fixed cost depends on the average availability (MW delivering capability) of the plant over the year.
In case the average actually achieved over the year is higher than the specified norm for plant
availability, the generating company gets a higher payment. In case the average availability
achieved is lower, the payment is also lower. Hence the name ‘Availability Tariff (ABT)’. This is the
first component of Availability Tariff, and is termed ‘capacity charge’.
The second component of Availability Tariff is the ‘energy charge’, which comprises of the
variable cost (i.e., fuel cost) of the power plant for generating energy as per the given schedule for
the day. It may specifically be noted that energy charge (at the specified plant‐specific rate) is not
based on actual generation and plant output, but on scheduled generation. In case there are
deviations from the schedule (e.g., if a power plant delivers 600 MW while it was scheduled to
supply only 500 MW), the energy charge payment would still be for the scheduled generation (500
MW), and the excess generation (100 MW) would be remunerated at a rate dependent on the
system conditions prevailing at the time. If the grid has surplus power at the time and frequency is
above 50.0 cycles, the rate would be lower. If the excess generation takes place at the time of
generation shortage in the system (in which condition the frequency would be below 50.0 cycles),
the payment for extra generation would be at a higher rate. Likewise, if a state / customer draws
25
more power from the regional grid than what is totally scheduled to be supplied to him from the
various CGSs at a particular time, it has to pay for the excess drawl at a rate dependent on the
system conditions, the rate being lower if the frequency is high, and being higher if the frequency is
low. The deviation from schedule is technically termed as Unscheduled Interchange (UI) in
Availability Tariff terminology. Figure 1.13 illustrates how and when the UI mechanism works.
The payment due to the generation company by the buyer in any year is computed as
follows: Total payment due = Fixed charges + variable charges + UI charges, where
Fixed charges comprise:
• Interest on long‐term debt
• Depreciation
• O&M expenses (including insurance expenses)
• Return on equity
• Incentive return on equity
• Interest on working capital
• Taxes
Variable charges comprise:
• Cost of primary fuel
• Cost of secondary fuel
UI charges comprise:
• Cost of secondary fuel
26
7.0 Power Project Financing
The Indian economy is poised for higher economic growth in the years to come. This will
require large investment in the infrastructure sectors including the power sector. As per the 12th
plan ` 1372580Cr required for the addition of 75GW capacity. During the 1990s, up to 80% of
power sector funding came from the public sector, followed by the private sector (10–15%) and
official development assistance (5–10%). Increasingly, both the central and state governments are
facing the need to meet competing budgeting requirement from other social sectors such as health
and primary education. The need for enhanced fiscal discipline and macroeconomic stability is also
placing a limit on borrowing capacity of the government both at central and state level.
7.1 Types and Sources of Finance
7.1.1 Debt
Given the capital‐intensive nature of power projects, mobilization of long‐term debt becomes
critical to the development of power projects. Project finance debt is generally secured by projects
assets such that after paying operating expenses, debt and debt service is paid from cash flows.
Debt typically constitutes up to 70% of the power project costs in India. The type of debt used in
power projects finance structures has been varied. The following are some of the sources of debt
available to power projects developers:
Government:
Traditionally, the main source of debt has been the government. Both the central and state
governments lend the money to utilities from time to time for expansion plans or working
capital. They extend loans for longer tenure and at lower interest rates than commercial
27
rates.
Commercial Banks and Financial Institutions;
Commercial banks and Financial Institutions (FIs) have consistently increased lending to
power sector in the last 4‐5 years. Most of the lending has been skewed towards the
generation segment. With the opening up of the T&D segment to the private sector,
commercial lending is likely to increase in future. For generation projects, the standard
tenure of loans is 13‐14 years, which included construction period and repayment period of
10 years. Earlier the lending use to be under recourse financing, but in the last 4‐5 years,
the lending institutions have become more liberal and comfortable with lending to
bankable power projects. Although, commercial banks and FIs continue to increase their
exposure to the power sector, individual exposure of banks to the sector remains limited.
This is mainly because they are still constrained by financing limits as per prevalent
prudential norms prescribed by the Reserve Bank of India (RBI).
Niche Institutions;
There are also niche institutions such as Power Finance Corporation (PFC) and Rural
Electrification Corporation (REC), which provide loans specifically to power sector. While
PFC provides loans for all kinds of investments, REC focuses mainly on rural electrification.
The state sector’s reliance on these institutions for debt is very high mainly due to the
competitive rates and liberal terms and conditions offered by them. In the recent past, due
to their experience and expertise in the sector, these institutions have been competing with
commercial banks. Moreover, since issues like asset‐liability mismatch and exposure limits
are not applicable to PFC and REC, it is easier for these institutions to lend to the sector.
28
Insurance Companies;
Insurance companies like the Life Insurance Corporation of India (LIC), General Insurance
Corporation of India (GIC) have extended financial support to the power sector. There are
limits on the investments prescribed by the Insurance Regulatory and Development Authority
of India (IRDA). Life insurance and general insurance companies have to invest at least 15%
and 10% of the fund respectively to the infrastructure and social sectors.
External Commercial Borrowings;
External commercial borrowings (ECBs) were quite a popular means to raise finances until
some time back, especially for large projects funding. These loans are raised at Libor‐plus
rates, which are generally lower than the interest rates in the domestic market. ECBs have
declined of late due to RBI restrictions on foreign funds flows for rupee expenditure and due
to an increase in borrowing costs as a result of the sub‐prime effect.
Export Credit Agencies;
Loans from export credit agencies are cheaper than commercial loans and are generally used
when equipment needs to be imported from a particular country. These are likely to gain
importance in the medium term mainly fuelled by the requirement of importing super‐critical
units in the eleventh and Twelfth plan periods, and until this demand is met by the domestic
market.
Bonds;
Several utilities and state power corporations have resorted to issuing bonds to raise funds.
These are generally subscribed by provident and pension funds, gratuity trusts, insurance
companies, mutual funds, individual, etc. These bonds typically have tenure of 7‐8 years.
29
7.1.2 Equity
The equity in power projects, like in other projects, is driven by the rate of return that is
expected from the investment apart from acting as a cushion to project finance. In the power
sector, the return on equity is fixed at 15.5% on 30% of the equity investment. The sources of
equity are promoter’s equity, internal accruals, equity funds and strategic equity investors.
Raising funds from capital markets is also becoming increasingly popular. The following are some
of the sources of equity available to power project developers:
Promoter’s Equity and Internal Accruals ;
Most project developers invest some amount of the total project cost as promoter’s equity
to be able to earn the minimum return on equity and raise the required debt. Many CPSUs,
including National Thermal Power Corporation (NTPC) are increasingly relying on internal
accruals for investing equity in new projects.
Primary/Capital Markets;
In recent times, power sector companies have been raising funds from primary markets
through Initial Public Offerings (IPOs). Almost all IPOs of power companies in the last two to
three years have met with an overwhelming response from investors or have been
performing well in the stock markets. Some of the successful IPOs have been those of CPSUs
like NTPC, and PGCIL, private developers like Suzlon Energy, JP Hydro and Reliance Power
and infrastructure companies like GMR, GVK and Lanco. Many power companies are
expected to launch their IPOs in the coming years. NTPC is also planning to come out with a
follow‐on public offer.
30
Qualified Institutional Placements;
Another source of equity, which is increasingly being tapped by power sector companies, is
private placement with qualified institutional investors. For instance, GVK Power &
Infrastructure Limited (GVKIL) and Kalpataru Power Transmission raised USD 300 million
and USD 85 million respectively through this route in May 2007 and September 2006
respectively. PTC India also raised around USD 29 million through this route in January 2008
by allotting shares to institutional buyers like LIC and Morgan Stanley, among others.
Equity Funds
Specialized equity funds such as India Development Fund by Infrastructure Development
Finance Company (IDFC) have been set up to invest in equity in private sector power
sectors. India Infrastructure Finance Company Limited (IIFCL), Citigroup, Blackstone have
also instituted a USD 5 billion India infrastructure financing initiative for investing in
infrastructure projects. The Anil Dhirubani Ambani Group and Singapore’s Temasek
Holdings constituted the Reliance India Power Fund with equal contributions. Others
planning to set up infrastructure funds, which would pick up equity in power projects as
well, include a USD 2 billion infrastructure by ICICI bank, the USD 1 billion Macquarie India
Infrastructure Opportunities Fund by Macquarie and International Finance Corporation
(IFC), a USD 1 billion India focused infrastructure private equity fund by Standard Chartered
and IL&FS Investment Managers and a USD 2 billion India Infrastructure Fund by JP Morgan
and Chase Company. PTC India’s investment arm PTC Financial Services also plans to pick up
equity in power projects through an Energy Equity Fund.
31
7.2 Trends in Power Sector Financing
• Increased investor confidence resulting in commitment and disbursement of more funds
• IPP revival triggered by increased investor confidence
• Gradually increasing interest rates leading to increased project costs
• Increased availability of longer‐term debt
• Skew towards investment in generation continues
• External Commercial Borrowings (ECB) loses sheen as RBI tightens norms
• As local capital market mature, more companies are opting for IPOs
• Lenders no longer demand government guarantees, counter guarantees.
• Bankable and competitively priced projects are able to raise funds easily.
• Project financing criteria relaxed by financiers for new types of projects.
• Promoter’s track record is a important consideration
7.3 Major Financiers in Power Sector
1) Power Finance Corporation
2) Rural Electrification Corporation
3) World Bank
4) International Finance Corporation
5) Asian Development Bank
6) Japan Bank for International Cooperation
7) Department of International Development
8) India Infrastructure Finance Company Limited
9) Infrastructure Development Finance Company
10) Life Insurance Company
11) Commercial banks like State Bank of India, Punjab National Bank , IDBI Bank, ICICI
Bank, SBI Capital Markets.
32
8.0 Budgeting in Power Plants;
8.1 Types of budget heads in power plant;
1. Direct capital outlay
2. Commissioning Expense
3. Construction materials
4. Technical consultancy
5. Training & Recruitment
6. Incidental expenditure during construction
I. Employee cost
II. Other establishment expenses
7. Miscellaneous brought out Assets (MBOA)
8. Interest during construction (IDC)
9. Working Capital margin
10. Capital Expenditure not represented by assets
11. Township and social overheads.
1. Directly Capital Outlay ;
This represents all cost directly identifiable with capital work and includes cost of land ,
infrastructural facilities, and mechanical, electrical works , township ,MGR and construction
facilities. The budget provision is to be made against each budget head listed.
As per CERC Tariff Regulation 2009 Capital cost for a project shall include:
a) 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
33
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
check;
b) Capitalized initial spares subject to the ceiling rates as specified by CERC; and
c) Additional capital expenditure determined under special circumstances like (i) Un
discharged liabilities; (ii) Works deferred for execution; (iii) Procurement of initial capital
spares within the original scope of work, (iv) Liabilities to meet award of arbitration or
for compliance of the order or decree of a court; and (v) Change in law:
2. Commissioning expenses
All direct expenses for running of individual units up to date of commercial operation,
including fuel costs, startup power chemicals & lubricants consumption and anticipated sale
of energy during trail run are to be indicated.
3. Construction Materials;
Provision should be made for accretion or decretion of stock of construction of stock of
construction materials such as structural steel, reinforcement steel cement and other
materials. This consumption of materials should be valued at budget cost represented by
difference between the issue price and contract price should provide for indirect capital
outlay.
34
4. Technical Consultancy;
Payment to technical consultants identifiable with system such as main plant, MGR, Coal
Handling plant, & other are to be included in this head. TA, lodging expense payable to
consultants based on contractual obligations and income tax provisions in respect of tax‐
free foreign consultancy payments should also be provided under this head.
5. Training & Recruitment Expenditure;
The first part of this budget consists of expenses for training executives/non‐ executives and
trainees, including stipends, faculty fee, course material for trainees, rent for training hall
and expenses for management development courses. Second part consists of expenses for
recruitment, interview expenses, TA to candidate etc.
6. Incidental Expenses during Construction
a) Employee Costs;‐ These comprise salaries, wages, allowances, contribution to PF and
other funds , welfare expenses. Any other provision for arrears of salary/DA or incentive
should be shown separately.
b) Other Establishment Expenses: ‐ Expenses incidental to construction and capital works
not traceable directly to any capital activity are chargeable to incidental expenditure
during construction repair and maintenance of buildings, construction equipment.
Vehicle running expenses, official rent, LC charges, cost of drawing, travelling expenses,
advertising for tenders are major items falling in this category.
7. Miscellaneous Brought out Assets‐
Furniture and other office equipments, medical and hospital equipments, miscellaneous
assets of Township and loans to employees figure in this subject budget.
35
8. Interest during Construction;
Interest to be paid and capitalized during construction period on loans has to to be included
in this budget.
9. Working Capital Margin
The accretion to working capital comparison inventory of fuel, spares, consumables etc plus
cash expenses on operation and maintenance less cash realization anticipated during
budget period is to be financed to the extent of 25% by way of working capital margin from
budgets and the balance from cash credit etc.
10. Capital Expenditure Not Represented by Assets:
This includes capital expenditure on assets belonging to their agencies for example,
construction of approach roads, canal, and lining etc. on property belonging to local
authorities/SEBs. These items should be included under respective budgets head in direct
capital outlay budget and these should also be presented separately in the format for
capital expenditure not represented by assets to facilitate identification and control such
works. The budget proposals for these should be supported by specific approval from
competent authority. The relevant information in respect of details of agreement and the
date of transfer etc.
11. Township and Social overheads;
This is an analysis of provision already in the IEDC budgets pertaining to the cost of
administration and maintenance of Permanent Township and income from township. Other
social overheads comprising maintenance of schools, hospitals, sub‐sided transport etc.
should also be indicated.
9.0 Capital Budgeting for dummy Power project;
A dummy power project was given with the life of 25 years starting from April‐2011. Some assumptions
for the input values were taken from NTPC/NSPCL standards (shown in the table below). Using these
assumptions following parameters were calculated:
a) Primary and Secondary Fuel Cost
b) Depreciation, return on equity and Operations & Management (O&M) Cost
c) Working Capital and Interest on working Capital
d) Term Loan and Interest
e) Average fixed cost
f) Tariff
g) Profit and Loss statement
h) Cash Flow statement and NPV, IRR
45
Since, the value of NPV is positive also the value of IRR is more than WACC, so NSPCL should
accept this project.
For the year ended March 31, 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023
Installed Capacity MW 2x250 2x251 2x252 2x253 2x254 2x255 2x256 2x257 2x258 2x259 2x260 2x261 2x262Plant Load Factor 80.00% 80.00% 80.00% 80.00% 80.00% 80.00% 80.00% 80.00% 80.00% 80.00% 80.00% 80.00% 80.00%Income Units generated million kWh 2044 3504 3504 3504 3504 3504 3504 3504 3504 3504 3504 3504 3504Less: Auxiliary Consumption million kWh 184 315.36 315.36 315.36 315.36 315.36 315.36 315.36 315.36 315.36 315.36 315.36 315.36Units sold million kWh 1860 3189 3189 3189 3189 3189 3189 3189 3189 3189 3189 3189 3189Tariff for the year Rs. 2.14 2.16 2.24 2.36 2.31 2.26 2.21 2.16 2.11 2.06 2.01 1.67 1.49Total Sales Rs. Crore 398 687 713 752 736 720 704 688 673 657 642 533 476
ExpenditureRaw Material Rs. Crore 128 219 219 219 219 219 219 219 219 219 219 219 219O & M expenses Rs. Crore 31 55 58 60 63 66 68 71 74 78 81 85 88water charges 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00Total Expenditure 159 274 277 279 282 285 287 290 294 297 300 304 307
PBDIT 239 413 437 473 454 436 417 398 379 360 341 229 169
Depreciation Rs. Crore 80 138 138 138 138 138 138 138 138 138 138 138 138
Interest‐ Term Loan Rs. Crore 106 186 170 151 132 113 94 75 57 38 19 2 0‐ Working Capital Rs. Crore 9 14 14 15 15 15 15 15 15 15 15 14 13
PBT 44 76 115 170 170 170 170 170 170 170 170 76 18
Gross Cash Accruals Rs. Crore 125 214 253 308 308 308 308 308 308 308 308 214 156
For the year ended March 31, 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035
Installed Capacity MW 2x257 2x257 2x257 2x257 2x257 2x257 2x257 2x257 2x257 2x257 2x257 2x257Plant Load Factor 80.00% 80.00% 80.00% 80.00% 80.00% 80.00% 80.00% 80.00% 80.00% 80.00% 80.00% 80.00%Income Units generated million kWh 3504 3504 3504 3504 3504 3504 3504 3504 3504 3504 3504 3504Less: Auxiliary Consumption million kWh 315.36 315.36 315.36 315.36 315.36 315.36 315.36 315.36 315.36 315.36 315.36 315.36Units sold million kWh 3189 3189 3189 3189 3189 3189 3189 3189 3189 3189 3189 3189Tariff for the year Rs. 1.51 1.52 1.53 1.55 1.56 1.58 1.59 1.61 1.63 1.65 1.67 1.69Total Sales Rs. Crore 480 484 489 493 498 503 509 514 520 526 532 538
ExpenditureRaw Material Rs. Crore 219 219 219 219 219 219 219 219 219 219 219 219O & M expenses Rs. Crore 92 96 100 104 109 113 118 123 128 134 139 145water charges 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00Total Expenditure 311 315 319 323 328 332 337 342 347 353 358 364
PBDIT 169 169 170 170 170 171 171 172 172 173 173 174
Depreciation Rs. Crore 138 138 138 138 64 0 0 0 0 0 0 0
Interest‐ Term Loan Rs. Crore 0 0 0 0 0 0 0 0 0 0 0 0‐ Working Capital Rs. Crore 13 14 14 15 15 15 16 16 17 17 18 18
PBT 18 18 18 18 92 156 156 156 156 156 156 156
Gross Cash Accruals Rs. Crore 156 156 156 156 156 156 156 156 156 156 156 156
2x250MW Project Profitalibility Projections
For the year ended March 31, 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023AssetsGross Block 2,645 2,645 2,645 2,645 2,645 2,645 2,645 2,645 2,645 2,645 2,645 2,645 2,645 Less: Depreciation 80 218 356 494 632 770 908 1,046 1,184 1,322 1,460 1,598 1,736 Net Block 2,565 2,427 2,289 2,151 2,013 1,875 1,737 1,599 1,461 1,323 1,185 1,047 909 Capital Work in Progress ‐ ‐ ‐ ‐ ‐ Current Assets 116 182 188 197 196 196 195 195 195 196 196 181 175 Cash and bank balances 141 244 307 425 544 664 783 903 1,022 1,142 1,261 1,385 1,542
Total 2,821 2,853 2,784 2,772 2,753 2,734 2,716 2,697 2,679 2,660 2,642 2,613 2,626 Liabilities
Share Capital 807 807 807 807 807 807 807 807 807 807 807 807 807 Reserves and surplus 44 120 235 405 575 744 914 1,084 1,254 1,424 1,594 1,670 1,687 Term Loan‐ Rupee borrowing 1,883 1,789 1,601 1,413 1,224 1,036 848 659 471 283 94 (0) (0) ‐ FC borrowing 0 0 0 0 0 0 0 0 0 0 0 0 0 Bank Borrowings 87 137 141 148 147 147 147 146 147 147 147 136 131 Current Liabilities 0 0 0 0 0 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
Total 2,821 2,853 2,784 2,772 2,753 2,734 2,716 2,697 2,679 2,660 2,642 2,613 2,626
Difference 0 0 0 0 0 0 0 0 0 0 0 0 0
For the year ended March 31, 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036AssetsGross Block 2,645 2,645 2,645 2,645 2,645 2,645 2,645 2,645 2,645 2,645 2,645 2,645 Less: Depreciation 1,874 2,012 2,150 2,288 2,352 2,352 2,352 2,352 2,352 2,352 2,352 2,352 Net Block 771 633 495 357 293 293 293 293 293 293 293 293 Capital Work in ProgressCurrent Assets 179 184 189 193 199 204 210 216 222 229 236 244 Cash and bank balances 1,696 1,850 2,005 2,159 2,313 2,468 2,622 2,776 2,930 3,083 3,237 3,391
Total 2,646 2,667 2,688 2,710 2,805 2,965 3,125 3,285 3,445 3,606 3,767 3,928 Liabilities
Share Capital 807 807 807 807 807 807 807 807 807 807 807 807 Reserves and surplus 1,705 1,722 1,740 1,757 1,849 2,005 2,160 2,316 2,471 2,627 2,782 2,938 Term Loan‐ Rupee borrowing (0) (0) (0) (0) (0) (0) (0) (0) (0) (0) (0) (0) ‐ FC borrowing 0 0 0 0 0 0 0 0 0 0 0 0 Bank Borrowings 135 138 141 145 149 153 157 162 167 172 177 183 Current Liabilities ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
Total 2,646 2,667 2,688 2,710 2,805 2,965 3,125 3,285 3,445 3,606 3,767 3,928
Difference 0 0 0 0 0 0 0 0 0 0 0 0 0
Balance Sheet
For the year ended March 31, 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 20231 2 3 4 5 6 7 8 9 10 11 12 13
InflowGross Cash Accruals 125 214 253 308 308 308 308 308 308 308 308 214 156 Increase in equity 201 0 0 0 ‐ Term Loan Drawls‐ Rupee borrowing 468 0 0 0 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ FC borrowing 0 0 0 0 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ Increase in Current Liabilities ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ Decrease in Current Assets ‐ ‐ ‐ ‐ 1 0 0 0 ‐ ‐ ‐ 15 6 Increase in bank borrowings 87 50 5 6 ‐ ‐ ‐ ‐ 0 0 0 ‐ ‐
Total 880 263 258 314 308 308 308 308 308 308 308 228 162
OutflowCapital investments 669 0 0 0 ‐ Repayment‐ Rupee borrowing ‐ 94 188 188 188 188 188 188 188 188 188 94 ‐ ‐ FC borrowing ‐ 0 0 0 0 0 0 0 0 0 0 0 ‐ Decrease in Current Liabilities ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ Increase in Current Assets 116 66 6 8 ‐ ‐ ‐ ‐ 0 0 0 ‐ ‐ Decrease in bank borrowings ‐ ‐ ‐ ‐ 0 0 0 0 ‐ ‐ ‐ 11 5
Total 785 161 194 197 189 189 189 188 188 189 189 105 5
Opening Balance 46 141 244 307 425 544 664 783 903 1,022 1,142 1,261 1,385 Surplus / (Deficit) 96 103 63 117 120 120 120 120 119 119 119 123 157 Closing Balance 141 244 307 425 544 664 783 903 1,022 1,142 1,261 1,385 1,542
Gross Cash Accruals Rs. Crore 114 195 233 284 284 284 284 284 284 284 284 196 141 Difference 11 18 21 24 24 24 24 24 24 24 24 18 15 Discounting factor 9% 0.92 0.84 0.78 0.71 0.65 0.60 0.55 0.51 0.47 0.43 0.39 0.36 0.33NPV 9.66 15.60 15.93 17.11 15.70 14.41 13.22 12.13 11.13 10.21 9.36 6.52 4.88
For the year ended March 31, 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 203514 15 16 17 18 19 20 21 22 23 24 25
InflowGross Cash Accruals 156 156 156 156 156 156 156 156 156 156 156 156 Increase in equityTerm Loan Drawls‐ Rupee borrowing ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ FC borrowing ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ Increase in Current Liabilities ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ Decrease in Current Assets ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ Increase in bank borrowings 3 3 3 4 4 4 4 5 5 5 5 6
Total 159 159 159 159 159 160 160 160 160 161 161 161
OutflowCapital investmentsRepayment‐ Rupee borrowing ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ FC borrowing ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ Decrease in Current Liabilities ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ Increase in Current Assets 4 4 5 5 5 5 6 6 6 7 7 8 Decrease in bank borrowings ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
Total 4 4 5 5 5 5 6 6 6 7 7 8
Opening Balance 1,542 1,696 1,850 2,005 2,159 2,313 2,468 2,622 2,776 2,930 3,083 3,237 Surplus / (Deficit) 154 154 154 154 154 154 154 154 154 154 154 154 Closing Balance 1,696 1,850 2,005 2,159 2,313 2,468 2,622 2,776 2,930 3,083 3,237 3,391
Gross Cash Accruals Rs. Crore 141 141 141 141 141 141 141 141 141 141 141 142 Difference 15 15 15 15 14 14 14 14 14 14 14 14 Discounting factor 9% 0.31 0.28 0.26 0.24 0.22 0.20 0.18 0.17 0.15 0.14 0.13 0.12NPV 4.47 4.09 3.75 3.43 3.14 2.88 2.63 2.41 2.20 2.02 1.84 1.69
Cashflow Projections
DSCR Calculations 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023Numerator‐ Gross Cash Accruals 125 214 253 308 308 308 308 308 308 308 308 214 156‐ Interest on Term Loans 106 186 170 151 132 113 94 75 57 38 19 2 0
231 400 423 459 440 421 402 383 364 346 327 215 156
Denominator ‐ Interest on Term Loans 106 186 170 151 132 113 94 75 57 38 19 2 0‐ Repayment 0 94 188 188 188 188 188 188 188 188 188 94 0
106 280 358 339 320 301 283 264 245 226 207 96 0
DSCR 1.43 1.18 1.35 1.37 1.40 1.42 1.45 1.49 1.53 1.58 2.25
DSCR Calculations 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035Numerator‐ Gross Cash Accruals 156 156 156 156 156 156 156 156 156 156 156 156‐ Interest on Term Loans 0 0 0 0 0 0 0 0 0 0 0 0
156 156 156 156 156 156 156 156 156 156 156 156
Denominator ‐ Interest on Term Loans 0 0 0 0 0 0 0 0 0 0 0 0‐ Repayment 0 0 0 0 0 0 0 0 0 0 0 0
0 0 0 0 0 0 0 0 0 0 0 0DSCR
Maximum DSCR 2.25Average DSCR 1.46Minimum DSCR 1.18
DSCR and IRR CALCULATIONS
IRR CALCULATIONS 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023
Capital Expenditure incl. IDC 320.3 774.1 881.7 668.8 0.0 0.0 0.0 0.0 0.0Less: IDC 12.0 48.5 112.1 63.8 0.0 0.0 0.0 0.0 0.0Capital Expenditure excl. IDC 308 726 770 605 0 0 0 0Current Assets build up 116 66 6 8 ‐1 0 0 0 0 0
Gross Cash Accruals 125 214 253 308 308 308 308 308 308 308Interest (term loan + WC) 115 200 184 165 147 128 109 90 71 52Salvage Value
Net Cash flow ‐308 ‐726 ‐770 ‐482 347 431 465 455 436 417 398 379 360
IRR CALCULATIONS 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035
Capital Expenditure incl. IDCLess: IDCCapital Expenditure excl. IDCCurrent Assets build up 0 ‐15 ‐6 4 4 5 5 5 5 6 6 6
Gross Cash Accruals 308 214 156 156 156 156 156 156 156 156 156 156Interest (term loan + WC) 34 15 13 13 14 14 15 15 15 16 16 17Salvage Value
Net Cash flow 341 244 175 165 165 165 165 165 165 165 166 166
IRR 12.15%
IRR CALCULATION
For the year ended March 31, 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023Components of Fixed TariffDepreciation 55 94 134 188 188 188 188 188 188 188 188 94 36Interest on Term Loan 106 186 170 151 132 113 94 75 57 38 19 2 0O & M expenditure 34 61 63 66 68 71 74 77 80 83 87 90 94Return on equity 66 113 113 113 113 113 113 113 113 113 113 113 113Interest on working capital 9 14 14 15 15 15 15 15 15 15 15 14 13Total Fixed Charges 270 468 494 533 517 501 485 469 453 438 422 314 257
Total variable cost 128 219 219 219 219 219 219 219 219 219 219 219 219Incentive 0 0 0 0 0 0 0 0 0 0 0 0 0
Fixed Tariff 1.45 1.47 1.55 1.67 1.62 1.57 1.52 1.47 1.42 1.37 1.32 0.98 0.81Variable tariff 0.69 0.69 0.69 0.69 0.69 0.69 0.69 0.69 0.69 0.69 0.69 0.69 0.69Total Tariff 2.14 2.16 2.24 2.36 2.31 2.26 2.21 2.16 2.11 2.06 2.01 1.67 1.49Discounting factor 0.89 0.80 0.71 0.64 0.57 0.51 0.45 0.40 0.36 0.32 0.29 0.26 0.23Discounted Tariff 1.91 1.72 1.59 1.50 1.31 1.14 1.00 0.87 0.76 0.66 0.58 0.43 0.34Levelised Tariff (Rs / unit) 2.05
For the year ended March 31, 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034Components of Fixed TariffDepreciation 55 36 36 36 36 36 36 36 36 36 36 36Interest on Term Loan 106 0 0 0 0 0 0 0 0 0 0 0O & M expenditure 34 97 101 105 110 114 119 123 128 133 139 144Return on equity 66 113 113 113 113 113 113 113 113 113 113 113Interest on working capital 9 13 14 14 15 15 15 16 16 17 17 18Total Fixed Charges 270 261 265 270 274 279 284 289 295 301 306 313
Total variable cost 128 219 219 219 219 219 219 219 219 219 219 219Incentive 0 0 0 0 0 0 0 0 0 0 0 0
Fixed Tariff 1.45 0.82 0.83 0.85 0.86 0.88 0.89 0.91 0.92 0.94 0.96 0.98Variable tariff 0.69 0.69 0.69 0.69 0.69 0.69 0.69 0.69 0.69 0.69 0.69 0.69Total Tariff 2.14 1.51 1.52 1.53 1.55 1.56 1.58 1.59 1.61 1.63 1.65 1.67Discounting factor 0.89 0.20 0.18 0.16 0.15 0.13 0.12 0.10 0.09 0.08 0.07 0.07Discounted Tariff 1.91 0.31 0.28 0.25 0.23 0.20 0.18 0.17 0.15 0.13 0.12 0.11Levelised Tariff (Rs / unit) 2.05
Tariff Estimates
9.0 Conclusions and Recommendations
From the above capital budget projections on a dummy project, it is observed that the IRR
for 500MW unit is 11.4% & for a 2x250MW unit is 12.15% and the levellized Tariff is `2.51/‐ &
`2.05/‐ per unit respectively. NPV for both the projects are found positive. By comparing two
options 2x250MW unit is looking more feasible compared to a single 500MW unit. Of course we
can’t say this statement is always true. There certain other factors like nature of project whether it
is a Green field or Brown filed, Fuel price, distance from coal fields & type of transportation etc.
Installing a single unit has always has a drawback in terms of inventory. Single unit requires large
percentage of investment in inventory like spares & other overheads compared to a multi unit
structure.
The Electricity Act, 2003 aims to bring in more competition in the power sector in India to
increase the efficiency of the system. It is evident that the deficit in power availability in India is a
significant impediment to the smooth development of the economy. In this context, bridging the
gap in demand and supply has become critical and consequently, large projects are being
undertaken in different segments of the sector; Generation, Transmission and Distribution. As India
has not witnessed such a large scale of implementation before, there is a need to review and
enhance project execution capabilities to help ensure targets are met.
It is necessary to appreciate that inspite of all the encouragement and reforms; the power
sector is still riddled with many gross uncertainties. Emerging economies such as India has
therefore much to do and learn about the execution of the reform processes. The reforms process
should be carried out in gradual steps and the sector should not be left to market forces from the
very outset. Government reforms should be investor friendly to attract more investments in Indian
Power Sector.
Government should pay more attention on development of non conventional energy
sources rather than depending on coal based plants. The Ministry of Power needs to accelerate the
development of the National Grid because the lack of Transmission capacity is harming the cost
effectiveness of delivered power. As for financing the sector, the Inter‐Institutional Group needs to
start working on the Public Private Participation model wherein the Private entrepreneurial skills
are actively supported by public funds not just in the form of debt financing but also equity
participation.
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References/Bibliography
Literature References
Reports & Executive summary on Power Sector from Central Electricity Authority
(CEA),CERC
Planning Commission reports on Indian Power Sector( 11& 12th plan Volume3)
INDIA ‐ Power Sector: Emerging Developments & Critical issues
Indian Power sector‐ Performance, Challenges & Opportunities by CRISIL
The Hindu‐ Survey of Indian Industry.
Business report on NSPCL by M/s Deloitte Touche Tohmatsu India Private Limited.
Power sector Financing Key Issues in INDIA by Power Minsistry
Investment Opportunities in Indian Power Sector and Cooperation with International
Energy Agency ‐R.V. Shahi ,Secretary, Ministry of Power ,Government of India.
Various Reports of Power Finance Corporation (PFC), Central Electricity Regulatory
Commission (CERC), Ministry of Power (MoP), Power Finance Corporation (PFC) ,Power
Grid Corporation of India (PGCIL)
Weblinks
1. Ministry of Power, Govt. of India (powermin.nic.in)
2. Central Electricity Authority (www.cea.nic.in)
3. Central Electricity Regulatory Commission (cercind.gov.in)
4. Infraline (www.infraline.com)
5. The Associated Chambers of Commerce and Industry in India (www.assocham.org)
6. Confederation of Indian Industries (www.ciionline.org )
7. Power Finance Corporation ( www.pfcindia.com )