“development of financial model & assessment of financial ... · • feasibility report/...
TRANSCRIPT
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DECLARATION
I, Pankaj Kumar Sharma, Roll No. 54, student of MBA (POWER MANAGEMENT) at
National Power Training Institute, Faridabad hereby declare that the Summer Training Report
entitled –
“DEVELOPMENT OF FINANCIAL MODEL &
ASSESSMENT OF FINANCIAL VIABILITY FOR 2X150
MW COAL BASED THERMAL POWER PLANT
OUTSIDE INDIA”
is an original work and the same has not been submitted to any other Institute for the award of
any other degree. A Seminar presentation of the Training Report was made on
____________________________________ and the suggestions as approved by the faculty
were duly incorporated.
Presentation Incharge Signature of the Candidate
Countersigned
Director/Principal of the Institute
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ACKNOWLEDGEMENT
The words are not enough to express my true regards to all those who in some or the other
way helped me in completing this project. I shall always remember them with gratitude and
sincerity.
I am grateful to LAHMEYER INTERNATIONAL (INDIA) PRIVATE LIMITED for giving
me the opportunity to do my summer internship with the company.
I would like to thank MR. S. MAJUMDER, Senior Vice President, MR. BHUPENDER
SINGH, Head (HR), MR. A. P. SINGH, Manager (HR), in Lahmeyer International (India)
Pvt. Ltd. , for giving me the opportunity to do the summer internship project in the company.
I express my deepest thanks and gratitude to my project guide MR. SADASIB
MOHAPATRA, General Manager (Project Finance), in Lahmeyer International (India)
Pvt. Ltd. , who guided me with his insights and knowledge into thw world of Finance .He
took active interest in my project and was always there to give me his word of guidance.
I extend my thanks to MS. DEEPIKA MOHARANA, Senior Engineer (PFP - LE), Senior
Officers in Lahmeyer International who were always ready to provide help whenever
required.
I also thank MR. S. K. CHOUDHARY (Principal Director- NPTI), MRS. MANJU MAM
(Director, NPTI), MR. ROHIT VERMA, (Dy. Director, NPTI), MRS. INDU
MAHESWARI, (Dy. Director, NPTI), for arranging my summer internship program with
Lahmeyer International (India) Pvt. Ltd and providing assistance and support whenever
required.
Finally, I am highly obliged to My Internal Project in charge MS. FARIDA, Senior Fellow
(CAMPS), NPTI, for her constant support and guidance during my internship program.
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ABOUT THE COMPANY
Lahmeyer International (India) Pvt. Ltd. (LII), the Indian subsidiary of Lahmeyer
International, GmbH Germany, was founded in 1993 to provide world-class engineering
services in the Indian and International power and infrastructure sectors. Lahmeyer is
reorganized as an independent consulting firm by all major international institutions such as
World Bank, Asian Development Bank, other Regional Development Banks, European
Banks, United Nations (FAO, WHO, UNDP etc.) and by National Development Funds.
Lahmeyer-India has emerged as a leading Independent Consulting Engineering Company
active in the Energy, Water Resources & Management and other Infrastructure projects in
India and Overseas. Lahmeyer-India offers an extensive range of advisory, planning and
consultancy services covering the below mentioned activities for various types of Power and
Infrastructure Projects which are under various stages of development, construction and
operation:
• Risk assessment, due diligence and project appraisal,
• Feasibility studies and detailed project reports,
• Basic and detailed design and engineering,
• Preparation of specifications, evaluation of bids and procurement assistance,
• Surveys, investigations and reconnaissance studies,
• Contract & construction management and site supervision and workshop inspections,
• Overseeing of performance guarantee tests and
• O&M audit.
Lahmeyer provides solutions that are optimized technically, economically and ecologically;
Projects are implemented – from conception to commissioning, efficiently and successfully.
Lahmeyer-India operates from its engineering offices at Gurgaon in the National Capital
Region of New Delhi and Kolkata, West Bengal.
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Services:
Lahmeyer-India provides comprehensive services to all major participants involved in Project
Development as:
• Owner’s Engineer / Technical Advisor - to Owners / Developers / Central & State
Utilities.
• Independent / Lender’s Engineer -to Financial Institutions / Banks & Multilateral
Funding Agencies/ Private Equity Firms / Hedge Funds.
• Architect Engineer - to EPC Contractors.
Owners Engineers – services to Owners/Developers
Choosing a feasible project, that offer good return on investment is a very critical decision for
the Developer seeking to be the Plant Owner. Selecting suitable technology, optimization of
plant and facilities and timely implementation will make the project a profitable venture.
While the following list is not exhaustive, it does indicate typical services which Lahmeyer
provides to Developers / Owners:
Project Development Phase
• Site Selection Studies.
• Power Potential Studies.
• Geo-technical Investigations.
• Feasibility Report/ Detailed Project Report.
• Assessment of design and reliability concept.
• Socio-environmental Studies.
• Project Financial Model.
• Assistance with pre-qualification and proposal preparation.
• Regulatory compliance checks of Consents and Clearances.
• Preparation of Technical and Commercial IPP bid.
• Preparation of Technical and Commercial bids for tariff based bidding.
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Assistance up to Financial Closure
• Preparation of EPC / Package specifications and evaluation of the bids.
• Preparation of O&M bid specifications and evaluation of O&M proposals.
• Assistance during “Security Package” negotiations.
• Interfacing with Lenders, Advisors and Statutory bodies.
Lenders Engineers - Services for Financial Institutions and Banks as Lender’s
Independent Engineer
Lahmeyer provides expert services to financial Institutions/ Banks/ Lenders / Private Equity
Firms & Hedge Funds during Pre-financial closure phase, Implementation phase,
Performance guarantee testing and Project completion phase and Operation phase of the
projects in evaluating and developing projects and by virtue of an extensive knowledge of the
marketplace, can introduce investors to suitable likely projects. The services provided
broadly include:
Pre Financial Closure Phase
• Review of the project’s conceptual design and basic engineering, construction &
operation plans.
• Assessments of the fuel supply chain.
• Assessment of Power Potential.
• Assessment of the redundancy concept.
• Review of Project Agreements (Power Purchase Agreement, Fuel Supply Agreement,
Transportation Agreement etc.)
• Review of Permits and Licenses.
• Assessment of EPC/various packages and O&M Contracts.
• Review of financial model and Security Package Mechanism.
Implementation Phase
• Monitoring of construction progress and monitoring Capital Cost & Disbursement
• Adherence to time schedule & Budget.
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• Assessment of variation orders.
• Regular reporting during construction up to commercial operation.
• Quality Surveillance at workshops and Project Site.
• Supervision of plant commissioning.
• Assessment of the testing provisions.
• Performance Guarantee tests- witnessing and evaluation.
• Review of Punch List Closure.
• Project Completion Certification.
Architect Engineer - Services as Architect Engineer (Detailed Engineering)
During the execution of the project, Lahmeyer provides both Basic as well as Detailed
Engineering Services to EPC / Turnkey Contractors in all disciplines such as Mechanical,
Electrical, Civil and Control & Instrumentation. The services provided broadly includes:
• Proposal Engineering and Bidding Support.
• Basic Engineering.
• Designing of systems, structures and sizing of equipment.
• Preparation of procurement specifications and offer evaluations.
• Contract negotiations.
• Preparation of detailed design drawings/documents for construction/ Installation.
• Trouble shooting during erection, commissioning and operation.
• Supervision of construction and erection.
• Quality Surveillance at workshops and Project Site.
• Preparation of performance guarantee test procedures.
• Performance testing and evaluation.
• Preparation of As-built drawings.
Technical advisor - Services as Technical Advisor
There is a worldwide trend for Governments to encourage private participation in power
generation, transmission and distribution projects. Lahmeyer has expertise in providing
services in privatization transactions.
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Development Phase
• Advice on energy policy.
• Establishing energy master plan.
• Least cost expansion planning.
• Regulatory framework.
• Privatization master plan and road map.
• Preparation of bid document (RfQ and RfP).
• Implementation of complete tendering procedures.
• Coordination during the privatization process.
• Development of tariff payment schemes.
• Shortlisting the best-suited investor/developer.
Project Implementation Phase
• Monitoring of the project implementation progress.
• Follow up of “Security Package” agreements.
• Evaluation of tariff re-openers.
• Assessment of plant performance for compliance with contractual obligations.
IPP – Solicitation up to Financial Closure
• Technical and commercial evaluation of tariff/ IPP-bids.
• Develop a financial model to be used during bid evaluation and “Security Package”
negotiations.
• Development of bid negotiation strategies.
• Preparation of risk allocation matrix.
• Assistance during “Security Package” negotiations.
• Power Purchase Agreement (PPA), Implementation Agreement.
• Training of staff of government and utility.
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Lahmeyer carries out specialized studies for utilities, owners/developers and contractors,
which facilitate decision-making. Lahmeyer carries specialized studies in all sectors of its
operations. The type of studies includes:
• Site Selection.
• Route Survey.
• Power Potential.
• Selection of Technology.
• Comparative Studies.
• Market Survey.
• Asset Valuation.
• Energy Audits.
• Load flow and short circuit analysis.
• Clean Development Mechanism (CDM).
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EXECUTIVE SUMMARY
Working with LAHMEYER INTERNATIONAL (INDIA) PRIVATE LIMITED was a
learning experience, especially with my guide who had given me a great job to do with lots of
support for making it a success. I have got the project of “Development of Financial Model
& Assessment of Financial Viability for 2X150 MW Coal based Thermal Power Plant
Outside India”.
The main objective of this project is to create Financial model for Determination of tariff, do
a thorough bankable feasibility study and learn the financial aspect used in the power sector
nowadays globally.
In this project the necessary inputs are taken from various sources and some of them are
assumed rationally in order to proceed further in the Financial Modeling process. After
compiling the input data various dependent variables such as IDC, Depreciation, Working
Capital , Interest on Working Capital, ROE, Fuel costs , O & M cost , Cost of spares , Interest
on Loan , Interest on loan etc. are calculated which are further used to calculate the Tariff. In
order to keep in mind the time value of money the levelised tariff is calculated to denote the
nominal tariffs of different years by a single value. Then the next step is to prepare sheets of
Profit & Loss account, Cash flow statement, NPV, IRR, DSCR and WACC which are main
determiners for the analysis of financial viability of any upcoming power generation project.
Once the relationships between various indicators of the financial aspects of the project are
developed (in excel sheet) with the help of financial tools, we interpolate the different values
of the changeable inputs such as Interest on loan, PLF, Total Project cost, Debt Equity ratio
etc. to find out the different outcomes and the way the changes in these inputs impacts the
financial indicators such as IRR, NPV, Tariff etc. This is done to know the degree and
direction of impact of inputs on the outputs in order to select the best suited set of inputs.
Financial modelling tool has been designed to calculate IDC, levelised tariff for 25 years at
10% discount rate, NPV, IRR and DSCR. The financial model also offers the flexibility
to change and adapt different inputs and assumptions for different projects.
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LIST OF ABBREVIATIONS
ASEAN Association of South East Asian Nations
BOO Build-Own-Operate
BOOT Build-Own-Operate-Transfer
BOT Build-Operate-Transfer
BOP Balance of plant
BTU British thermal units
BTG Boiler-Turbine-Generator
COC Cycles of concentration
COD Date of Commercial operation
CPP Captive Power Producers
DC Declared Capacity
DSCR Debt Service Coverage Ratio
EPC Engineering, Procurement and Construction
GDP Gross domestic product
GCV Gross Calorific Value
IDC Interest during construction
IDCT Induced draft cooling towers
IPP Independent Power Producer
IRR Internal rate of return
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kV Kilo Volt
kW Kilo Watt
kWh Kilo Watt Hour
LNG Liquified Natural Gas
MU Million Units
MW Mega Watt
MWh Mega Watt Hour
NOI Net Operating Income
NPV Net present value
NTP Notice To Proceed
OECD Organisation for economic cooperation & development
O&M Operation and Maintenance
PLF Plant Load Factor
PLN PT Perusahen Listrik Negara
PPA Power purchase agreement
PPP Public Private Partnership
PV Present Value
RFP Request for Proposal
RFQ Request for Qualification
ROE Return on Equity
WACC Weighted Average Cost of Capital
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TABLE OF CONTENTS
DECLARATION ...................................................................................................................... i
ACKNOWLEDGEMENT ........................................................................................................ ii
ABOUT THE COMPANY .................................................................................................... iii
EXECUTIVE SUMMARY .................................................................................................... ix
LIST OF ABBREVIATIONS ................................................................................................. x
1. WORLD ENERGY SCENARIO ........................................................................................ 1
2. CONCEPT OF INDEPENDENT POWER PRODUCERS (IPP’s) .............................. 15
3. POWER PROJECT DETAILS ........................................................................................ 20
4. PROJECT FINANCE ........................................................................................................ 26
5. FINANCIAL MODELING ............................................................................................... 32
6. TARIFF STRUCTURE ..................................................................................................... 35
7. FINANCIAL INDICATORS ............................................................................................ 42
8. METHODOLOGY OF FINANCIAL ANALYSIS ......................................................... 47
9. PROJECT COST ESTIMATE AND TARIFF CALCULATION ................................ 53
10. CONCLUSION: ............................................................................................................... 59
11. BIBLIOGRAPHY ............................................................................................................ 60
ANNEXURE 1 ........................................................................................................................ 61
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1. WORLD ENERGY SCENARIO
1.1. Introduction:
Energy is one of the major inputs for the economic development of any country. In the case
of the developing countries, the energy sector assumes a critical importance in view of the
ever-increasing energy needs requiring huge investments to meet them.
Energy can be classified into several types based on the following criteria:
• Primary and Secondary energy.
• Commercial and Non commercial energy.
• Renewable and Non-Renewable energy.
1.1.1. Primary and Secondary energy
Primary energy sources are those that are either found or stored in nature. Common primary
energy sources are coal, oil, natural gas, and biomass (such as wood). Other primary energy
sources available include nuclear energy from radioactive substances, thermal energy stored
in earth’s interior, and potential energy due to earth’s gravity.
Major Primary and secondary sources
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Primary energy sources are mostly converted in industrial utilities into secondary energy
sources; for example coal, oil or gas converted into steam and electricity.
Primary energy can also be used directly. Some energy sources have non-energy uses, for
example coal or natural gas can be used as a feedstock in fertilizer plants.
1.1.2. Commercial Energy and Non Commercial Energy
• Commercial Energy
The energy sources that are available in the market for a definite price are known as
commercial energy. By far the most important forms of commercial energy are
electricity, coal and refined petroleum products. Commercial energy forms the basis
of industrial, agricultural, transport and commercial development in the modern
world. In the industrialized countries, commercialized fuels are predominant source
not only for economic production, but also for many household tasks of general
population.
Examples: Electricity, lignite, coal, oil, natural gas etc.
• Non-Commercial Energy
The energy sources that are not available in the commercial market for a price are
classified as non-commercial energy. Non-commercial energy sources include fuels
such as firewood, cattle dung and agricultural wastes, which are traditionally
gathered, and not bought at a price used especially in rural households. These are also
called traditional fuels. Non-commercial energy is often ignored in energy
accounting.
Example: Firewood, agro waste in rural areas; solar energy for water heating,
electricity generation, for drying grain, fish and fruits; animal power for transport,
threshing, lifting water for irrigation, crushing sugarcane; wind energy for lifting
water and electricity generation.
1.1.3. Renewable and Non-Renewable Energy
Renewable energy is energy obtained from sources that are essentially inexhaustible.
Examples of renewable resources include wind power, solar power, geothermal energy, tidal
power and hydroelectric power. The most important feature of renewable energy is that it can
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be harnessed without the release of harmful pollutants. Non-renewable energy is the
conventional fossil fuels such as coal, oil and gas, which are likely to deplete with time.
Renewable Non-Renewable
1.2. Energy scenario in World:
Energy is one of the major inputs for the economic development of any country. The major
sources of energy in the world are oil, coal, natural gas, hydro energy, nuclear energy,
renewable combustible wastes and other energy sources. The contribution of different energy
sources to the total supply of energy in the world is: Oil-35.1%, Coal-23.5%, Natural gas-
20.7%, Renewable combustible wastes-11.1%, Nuclear-6.8%, Hydro-2.3% and other
sources-0.5%. World electricity demand is expected to continue more strongly than any other
form of Energy. The total world energy use rises from 505 quadrillion British thermal units
(Btu) in 2008 to 619 quadrillion Btu in 2020 and 770 quadrillion Btu in 2035 (International
Energy Outlook, 2011). As it is expected to grow by 2.2% per year between 2008 and 2035,
with more than 80% of the increase occurring in non-OECD countries (World Energy
Outlook, 2010).
Out of total global power demand, coal based thermal power is meeting about 2/3rd of the
total requirement. Increased demand is most dramatic in developing countries like China and
India. By 2030, both the countries together will be the world’s largest energy consumers
(B.P.2012). Coal power generation is an established part of the world's electricity mix
providing over 44.7% of world electricity (nuclear 20.6%, oil 1.1%, natural gas 22.3% and
hydro & other 11.3%). It is especially suitable for large-scale, base-load electricity demand.
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The coal power is in increase demand in all over the world and over the next decade is still
the largest contributor to the growth of power fuels accounting for 39% (B.P.2012).
Share of Coal Energy in Global Electricity Generation
1.2.1. Coal’s Dominant role in power
STRONG economic growth driving the need for substantial new power generating capacity,
particularly in Asia, will see coal play the dominant role over gas, nuclear and renewable
energy for at least the next 20 years. The dominance is set to increase and not diminish until
at least 2030 despite arguments against it.
This trend has been outlined in a report by energy and metal industries analyst Wood
Mackenzie, titled ‘Can coal deliver to South East Asia?’ In the report South East Asia Gas
and Power Service head Graham Tyler says, “A shift to coal in the region’s fuel mix has
already started with 35GW of committed coal-fired plant being developed in Indonesia,
Malaysia, Thailand, Vietnam and even on a smaller scale in Singapore. We think that while
there are opportunities for gas suppliers, the trend towards more coal-fired power in South
East Asia will continue beyond 2020 despite arguments against it.”
Wood Mackenzie forecasts South East Asia’s aggregate Gross Domestic Product (GDP) to
grow at 5.2% annually over the next decade, compared to the global average of 3.5%. As a
result, power demand is expected to triple, representing a need for an additional 190GW of
generating capacity by 2030. This is akin to rebuilding the capacity of Thailand, currently the
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largest consolidated power market in South East Asia, six times over. To meet this demand,
there must be an increase in all fuel types, especially in coal and gas that can operate at
baseload.
Graham Tyler says, “Local gas reserves in decline will be insufficient to match existing
production levels to feed the domestic markets. Reserve replacement is an issue with a
number of production areas such as Java/Sumatra, Gulf of Thailand and the Malay Basin
maturing. LNG is a potential solution but it is too costly for a region used to low and often
subsidized gas prices. The era of cheap local and abundant gas reserves is over, which leaves
coal to meet demand.”
The report considers the three main arguments by skeptics against the growth prospects for
coal but says these factors are not long-term obstacles for development of coal-fired plants.
The key factors are introduction of carbon abatement policies, coal’s negative impact on air
quality, and the lack of available infrastructure.
He explains, “Governments have expressed that reducing carbon emissions should not come
at the expense of developing their economies. As such, we do not expect them to take the
lead on carbon abatement without internationally agreed measures, especially considering
their absolute carbon emissions fall well below China and USA. Regarding concerns of air
quality, coal-fired power is only one of the factors that can contribute to air pollution.
Furthermore, this can be reduced with increased energy efficiency and improvements in
technology to reduce pollution from coal. The implementation cost will still make coal-fired
plants more economical than LNG.”
On the lack of coal infrastructure, Graham Tyler says, “South East Asia’s power markets
benefit from proximity to Indonesia, which has sufficient supply to meet domestic and Asia
Pacific export market demand growth to 2030. This proximity provides the option of barging
coal directly from Indonesian mines to regional markets, rather than depending on port
infrastructure. Even if port infrastructure is required, the import requirements in Indonesia,
Malaysia, Thailand and Vietnam are still easily accommodated with only one or two ports
needed in each country.”
In summary, when faced with growing energy demand, South East Asia will ultimately still
have a choice between importing coal and gas via LNG. However, Wood Mackenzie’s view
is that weighing up the key factors for and against coal, power plant economics still suggest
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that coal has a significant cost advantage and will be the dominant fuel in the region’s power
generation.
1.2.2.World coal reserves
1.2.3. Major coal producers
The reserve life is an estimate based only on current production levels and proved reserves
level for the countries shown, and makes no assumptions of future production or even current
production trends. Countries with annual production higher than 100 million tonnes are
shown.
Production of Coal by Country and year (million tonnes)
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1.2.4. Major coal consumers
Countries with annual consumption higher than 150 million tonnes are shown.
Consumption of Coal by Country and year (million short tons)
1.2.5. Major coal exporters
Countries with annual gross export higher than 10 million tonnes are shown. In terms of net
export the largest exporters are still Australia (328.1 millions tonnes), Indonesia (316.2)
and Russia (100.2).
Exports of Coal by Country and year (million short tons)
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1.2.6. Ratio coal production and export in certain coal production country
1.2.7. Major coal importers
Countries with annual gross import higher than 20 million tonnes are shown. In terms of net
import the largest importers are still Japan (206.0 millions tonnes), China (172.4) and South
Korea (125.8).
Imports of Coal by Country and year (million short tons)
1.3. South East Asia Countries (ASEAN):
Southeast Asia will be the next big growth engine in Asia. Indonesia, Malaysia, the
Philippines, Thailand, and Vietnam, with a population of 525 million and a combined GDP of
$2.8 trillion (when measured by purchasing power parity), are expected to grow almost 6
percent between now and 2030, according to the Asian Development Bank. For years, they
have been eclipsed by China and India, but now their combined GDP is catching up with
India and they could overtake Japan in less than two decades. For U.S. firms, these five
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members of the Association of South East Asian Nations—hereafter the ASEAN-5—are a
trade, energy, and environment story.
Potential sales of billions of dollars of energy equipment produced by U.S. companies are at
stake in the major economies of the region. They are expected to import as much as $16
billion worth of energy products over the next few years to power their economic growth. But
unless the United States launches new initiatives to snare sizeable shares of this investment,
U.S. companies are unlikely to be major players in all this trade.
To support the rapid economic growth of the ASEAN-5, their installed energy capacity will
need to increase 20 to 40 percent, adding between 168 and 192 gigawatts of power, according
to estimates by U.S. energy companies. Demand is already outstripping production in most of
the five and will soon do so in all of them. Further, onshore oil and coal resources are
dwindling after decades of exploitation and minimal investment, driving the ASEAN-5 to
import increasing amounts of energy and seek new domestic sources.
As the economies of the region grow, the ASEAN-5 are burning increasing amounts of
hydrocarbons, including vast amounts of coal, to fire their power plants. These countries,
particularly Indonesia and Vietnam, are rapidly becoming a major source of greenhouse gas
emissions, adding to the region’s global environmental footprint. Turning more toward
cleaner-burning natural gas, both piped and liquefied, to fire power plants could help reduce
the emission of greenhouse gases in the short to medium term and offset dwindling oil and
coal reserves.
Natural gas is not a sufficient path to achieve energy independence and sustainable
development, however, as all the ASEAN-5 nations have recognized. They will also need to
bolster renewable energy capacity and take a serious look at nuclear power.
The ASEAN-5 will need to import most, if not all, of the equipment to achieve these energy
targets. In the past, U.S. companies would likely have been major suppliers of this
equipment, but today that is no longer guaranteed. As in 2004, the United States was
Southeast Asia’s largest trading partner, with two-way trade reaching $192 billion. U.S. trade
with the region has kept growing since then, but it is rapidly losing market share to China.
Today, the United States only ranks as Southeast Asia’s fourth-largest trading partner.
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1.4. INDONESIAN COAL INDUSTRY:
1.4.1. Distribution of Indonesian Coal map Reserves (In Percentages)
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1.4.2. Indonesian Coal map Resources and Reserves (Billion Tons)
1.4.3. Strategy of coal management policy
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1.4.4. Indonesia coal quality based on the specific energy (kcal/kg)
1.4.5. Indonesian National Energy mix Policy
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1.4.6. Coal production: export & domestic
1.4.7. Coal companies
Coal contract of work (CCoW)
Nowadays there are 75 companies are involved in CCoW, which are 49 companies are on the
production stage, 12 companies are doing construction, 9 companies are now actively on
feasibility study stage, while only 5 companies are now involved on exploration stage.
Contract of work (CoW)
At the moment there are 42 companies are still in contract with government, with only 12
CoW are in production stage, 7 companies are doing construction, 14 companies are still
doing feasibility study and 9 companies are in exploration stage.
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1.4.8. Investment opportunities
1.4.9. Current Condition
• The Percentages of domestic demand of coal still lower (25 %) and export always
higher (75%), in term of quality low ranks coal from Indonesia can’t fulfill a domestic
demand.
• The coal in Indonesia still functions as commodity not as sources of energy like in
many countries. The target of Non Tax Government Revenue in 2011 24.24 Billion
Rupiah, it is contributed from coal 20.82 Billion Rupiah (86 %) and from Mineral
3.42 Billion Rupiah (14 %). The level of production has related to the target of non-
tax revenue because it has already approved in Energy and Mineral Resources for the
People’s Welfare National Budget Plan by Parliament.
• The Coal Prices in December 2012 started decreasing, HBA in December was US
$ 81.75/ton, in November HBA was US$ 81.44/ton. The good price of HBA was in
March 2012, a price of Coal reach 112.87 US$/ton and in September 2012 it was
going down to 86.21 US$/ton (decrease 23.62%). All of this is based on Price
Reference Index of Coal Indonesia (HBA). The low prices of coal is caused due to
economic crisis in Europe, freight cost decrease, coal production from Mongolia to
Asia pacific sales, the demand of coal from China and India diminishing and over
supply of coal in major destination export country.
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2. CONCEPT OF INDEPENDENT POWER
PRODUCERS (IPP’s)
2.1. Introduction:
An Independent Power Producer is an entity, which is not a public electric utility, but which
owns and or operates facilities to generate electric power for sale to a utility, central
government buyer and end users. IPP's may also be privately-held facilities, such as rural
solar or wind energy producers, and non-energy industrial concerns generating electric power
for on-site use and who may also be capable of feeding excess energy into the distribution or
transmission grid system.
Forms of private investment in Power sector
The classic IPP is a privately sponsored power plant that sells electricity under a long-term
contract. Typically, the offtaker is a state-owned electric utility, although occasionally
offtakers have included private distributors or large private users. The plant is generally
financed on a project basis, with a project-specific company established for the purpose. The
company draws equity from a number of foreign and domestic investors and secures debt
from a syndicate of banks on the basis of expected revenues. Most projects are highly
16
leveraged, with debt accounting for as large a share of project finance as the bank syndicate
will tolerate.
Increasingly governments are turning to the private sector for power generation. Some
developing countries started allowing private firms to enter electricity generation at the
beginning of the 1990s. Investment by Independent Power Producers (IPPs) grew rapidly –
particularly in Asia. While expansion faltered following the financial crisis in the region,
IPPs have been gaining ground in other parts of the world. Africa, South and Central America
as well as Eastern Europe have all opened the door to IPPs in some way or another.
IPPs are presented as an attractive option because they are supposed to facilitate investment
where a bankrupt public sector can barely afford to make ends meet; and because they allow
the private sector to operate without the need for lengthy regulations to be in place
beforehand, because the conditions of operating can be specified in the terms of the IPP
contract. IPPs are heralded as the start of further liberalisation and subsequent privatisation of
electricity.
However, more and more governments are running into difficulties with IPPs. In the
countries where they have been established for some time, such as Pakistan and Indonesia,
IPPs have been the subject of protracted legal, political and economic battles. Other countries
have seen electricity utilities crippled by payments due to IPPs, for example, the Philippines
and Dominican Republic. Others have questioned the generous terms offered to power
producers by previous governments and have attempted to limit the damage such
arrangements might cause for example, Croatia and Hungary. Despite these difficulties, more
IPPs are still being planned in various countries.
2.2. Issues/ Concerns with IPP’s:
2.2.1. IPP’s - not a source of funds
IPPs are sometimes presented as new sources of finance, that for investment in electricity
generation. This is misleading. Investors in an IPP will not construct (or buy) a power plant
unless they are sure they will be repaid (with a profit margin), and so usually require that a
power purchase agreement (PPA) is in place. Under the terms of a PPA, the electricity utility
undertakes to buy (usually) all the power produced by a power plant. The price of the power
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and the amount to be sold are specified. This is considered to be essential to induce
investments.
This highlights a further point – that the financial status of the IPP customer – usually the
government electricity utility - is crucial to the IPP obtaining finance for the project. A
guarantee from the electricity utility may be underwritten by a government guarantee. The
government guarantee is in fact assisting the IPP investors to raise finance – not the other
way around.
For eg,
• In the Philippines the electricity utility, Napocor, has amassed extensive debts due to
the terms of its IPPs. Around $9bn of the $15bn total liability consists of obligations
under power purchase agreements with IPPs. With Napocor scheduled for
privatisation in the next couple of years, advisors recommend that the debts be
assigned to the government so as not to deter investors. Thus, the central government
would be saddled with debts of $9bn on account of IPPs. This also shows that IPPs
can inhibit privatisation, as private investors are unlikely to be racing to get into
onerous PPAs or take on debts to IPPs.
2.2.2. IPPs are uncompetitive and inflexible
The terms of power purchase agreements can be fixed for decades, in some cases for up to 35
years. Circumstances can change dramatically over such a timeframe. Yet, the terms by
which governments have to purchase power from IPPs is inflexible. Governments are tied
into buying the same amount, regardless of fluctuations in demand or alternative sources of
supply. Prices are fixed in foreign exchange, regardless of how this might relate to domestic
prices or to what utilities are able to charge customers. Once PPAs have been signed, it can
be difficult to change the terms, not least because of the fear that future investors will be put
off by a government that is seen to renege on agreements.
For eg,
• In the Philippines, a total of 42 IPP contracts were signed under the Aquino and
Ramos administrations, in response to the power crisis that had hit the country
between 1990 and 1994. The IPP contracts contain a take-or-pay provision. A
18
subsequent downturn in the demand for power due to the Asian economic crisis has
resulted in excess capacity in the system. Napocor is currently faced with a problem
on where to distribute its generated capacity. Prices have increased as a result.
2.2.3. High prices and generous concessions
IPPs are an expensive source of power according to the World Bank. “In the final analysis, it
appears that IPPs have often inflated supply prices for utilities”. Prices paid under PPA terms
are often so high relative to sales tariffs that they leave no margin for the costs of
transmission. Raising prices for the end user is not always a solution as higher prices may just
result in less usage or efforts to avoid charges.
For eg,
• In Indonesia state electricity company PT Perusahaan Listrik Negara (PLN)
announced in a twelve fold increase in losses of in the first half of the year 2000.
These losses were made despite a 30% increase in revenue over the period. A stronger
US $ caused a big increase in the cost of power from IPPs. PLN buys power from
independent power producers (IPP’s) at an average price of 5.5 U.S. cents or about Rp
453 per kilowatt-hour (KWh) but resells it to the public at an average of Rp 250. PLN
calculates that it will owe almost $1bn a year just to Paiton I and II, two IPPs that
have started production.
• In the Philippines, the average generating cost for IPPs in 1996 was $ 76 per MWh
compared with $57 per MWh for the state-owned utility. In the Philippines, Power
contracts entered into by the former Ramos administration with independent power
producers (IPPs) are bleeding the National Power Corp. to death. Napocor chief
operating officer Asisclo Gonzaga told senators that they paid a total of P51 billion to
various IPPs during 1999 and the amount was equivalent to 60% of Napocor's total
operating expenses. Gonzaga said Napocor had to obtain foreign loans to pay up P12
billion to the IPPs. Napocor's revenue was simply not enough, he said.
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2.2.4. Risk exposure for governments is akin to debt
One of the supposed advantages of foreign investment is that it allows the burden of risk to
be shared, thus reducing risk exposure for investment partners (in this case, electricity
utilities and governments). Under normal equity arrangements, an investor, producing for the
local market would sell goods in local currency. Profits would be remitted to the parent
company in the form of dividends. If the value of the currency falls, the investor’s profit
would have less value and the international value of dividends falls.
For eg,
• In Indonesia, there are vehicles to help businesses to reschedule their dollar-
denominated debts. With IPPs there is no such mechanism. The Indonesian electricity
utility, the PLN, faces mounting obligations on its IPP and no way of paying them.
Conventional legal mechanisms are failing. In Indonesia, even when investors won a
court ruling in their favour, the PLN still cannot raise the revenue to meets its
obligations.
2.2.5. Excess capacity
Establishing power generation in excess of the country’s requirements is a feature associated
with corruption if the process provides an income source for those negotiating the contracts.
Even aside from corruption allegations, there are concerns that power generation capacity
might grow faster than demand.
For eg,
• In Indonesia under IPP contracts signed with the former government under the
Suharto regime, PLN has 50% more capacity than it needs on the main grid of Bali
and Java.. The PLN had to switch off some of its own capacity to meet the guarantees.
20
3. POWER PROJECT DETAILS
3.1. Introduction:
3.1.1. Background
The State Owned Electricity Corporation of Indonesia is promoting the development of the
thermal power plant on BOOT basis to private sector, which shall develop and operate the
plant. The successful bidder shall establish a Project Company that will Finance, Design,
Procure, Construct, Test, Commission, Operate and Maintain the plant. Accordingly, Buyer
has called for global tenders for coal fired mine mouth thermal power plant at South Sumatra
Province, Indonesia.
Project Company has participated in the global tender and won (2x150 MW) coal fired power
plant at South Sumatera Province, Indonesia.
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3.1.2. Site Selection
Desired conditions for selecting suitable site for the coal fired steam power plant can be
categorized into three (3) aspects, namely as follows:
Technical Aspects
• Topographic conditions: Relatively flat, a little high, dry (flood free)
• Geologic conditions: Soil hard enough for foundation with soil condition
requiring not more than 40 m of piling, low seismicity, no faults or land
slides
• Proximity to cooling water source, including makeup water
• Availability of water source for potable water and service water
• Proximity to construction material (stone, sand‐gravel, soil)
• Easy access and close to main road
• The availability of connection to the nearest existing PLN’s substation.
• Low cost of Site development.
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Socio-Economic Aspects
• Located away from residential area, office area, and airport. Within
acceptable distance from local community taking into consideration social /
environmental / safety requirements.
• As less as possible to relocate existing infrastructures (such as bridge,
road).
• Located on non-productive land or government land and preferably within
industrial zone or areas easily convertible to industrial zone.
• Not an archaeological site, no historic buildings or nature reserve.
Environmental Aspects
• Availability of disposal area (preferably a valley) for ash disposal area
where soil is quite impervious.
• In relation to emission effect of coal fired steam power plant, desired site
should be far from residential area and relatively flat as not to block the
main wind direction.
• To avoid noise effect due to coal fired steam power plant operation, site
should be far from residential area.
3.2. Input Requirements:
3.2.1. Land
The land requirement for the proposed 2x150 MW is about 50 hectares (120 acres) which
includes the power block, coal yard, water treatment facilities, cooling towers, ash handling
and disposal area and other balance of plant (BOP) buildings viz. administration building,
workshop, stores, canteen, township & colony, security office complex etc.
23
3.2.2. Water
Circulating Water System
• Closed recirculating cooling water system using cooling towers has been
proposed for the project. Raw seawater shall be used as make-up for the
closed recirculating cooling water system. It is envisaged to design the
system for 1.5 cycles of concentration (COC) and 10˚C temperature rise
across condenser.
• Estimated seawater requirement for circulating water system is around
20,264 m3/hr for each unit, which includes 18,000 m3/hr as condenser
cooling water (with 10°C temperature rise across the condenser) and
auxiliary cooling water requirement of 2264 m3/hr approximately.
Considering evaporation, drift loss and blow down and selected COC, the
make-up water requirement will be about 2190 m3/hr for two units.
Raw Water System
• Consumptive water requirements viz. Power Cycle make-up, HVAC
system make-up, Fire Protection, Potabilisation, Service water requirements
for plant washing, ash handing system sealing requirements, coal handling
plant requirements and green-belt requirements shall be met with seawater
reverse osmosis (SWRO) system. Demineralization water requirements
shall be met through brackish reverse osmosis (BWRO) system wherein
permeate from the SWRO system shall be further treated in BWRO
membranes.
• Estimated intake water requirement for the plant works out as 2473 m3/hr,
which includes the raw seawater make-up requirement for the circulating
water system, ash handling system (considering fly ash and bed ash
disposal in dry mode) and other plant consumptive requirements indicated
earlier.
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3.2.3. Coal
The plant has been identified as a coal fired thermal power plant. The coal source for this
project will be from Captive Mine close to the plant site.
Requirement of Coal:
The annual coal requirement at 80% PLF based on the gross plant heat rate of 2468.7
kcal/kWh and the design coal GCV of 3800 kcal/kg for a plant capacity of 300 MW works
out at around 1.37 million tonnes per annum.
3.2.4. Plant Capacity & Availability
The steam condition of the main plant for the project capacity of 2x150 MW has been
proposed considering the international trend, feedback from operating plants, and commercial
25
competitiveness etc. Based on the above, the following turbine throttle steam parameters and
exhaust conditions at condenser have been considered:
• Main Steam Pressure at turbine inlet : 134.4 bar (a)
• Main Steam Temperature : 540°C
• Hot Reheat Steam Temperature : 540°C
• Turbine Back Pressure : 9.7 kPa
• Condenser Cooling Water Inlet Temperature : 30.2˚C
• Temperature Rise Across Condenser : 10˚C
3.2.5. Power Evacuation
Evacuation of power from the proposed power plant will be done at 275 kV level. The
generation voltage is envisaged as 15.75 kV or will be as per the standard design of
manufacturer. For evacuation of power, one (1) no 3-Phase 15.75/290kV generator
transformer is envisaged for each unit. One 275 kV switchyard will be constructed in the
proposed power plant. Four numbers of dedicated 275kV high capacity transmission lines are
proposed from plant switchyard and Phi interconnection between Aurduri and Betung
substations which are approximately 11.0 km from the location of the Plant.
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4. PROJECT FINANCE
4.1. Introduction:
Project finance is the long-term financing of infrastructure and industrial projects based upon
the projected cash flows of the project rather than the balance sheets of its sponsors. Usually,
a project financing structure involves a number of equity investors, known as 'sponsors', as
well as a 'syndicate' of banks or other lending institutions that provide loans to the operation.
They are most commonly non-recourse loans, which are secured by the project assets and
paid entirely from project cash flow, rather than from the general assets or creditworthiness
of the project sponsors, a decision in part supported by financial modeling. The financing is
typically secured by all of the project assets, including the revenue-producing contracts.
Project lenders are given a lien on all of these assets and are able to assume control of a
project if the project company has difficulties complying with the loan terms.
Generally, a special purpose entity is created for each project, thereby shielding other assets
owned by a project sponsor from the detrimental effects of a project failure. As a special
purpose entity, the project company has no assets other than the project. Capital contribution
commitments by the owners of the project company are sometimes necessary to ensure that
the project is financially sound or to assure the lenders or the sponsors' commitment. Project
finance is often more complicated than alternative financing methods.
4.2. Project Finance Transactions:
How can a project financing be identified? What details should we expect to find about the
transaction? Not every project financing transaction will have every characteristic, but the
following provides a preliminary list of common features of project finance transactions.
• Capital – Intensive.
• Highly leveraged.
• Long Term.
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• Independent Entity with a finite life.
• Limited Recourse financing.
• Controlled dividend policy.
• Many participants.
• Allocated risk.
• Costly.
4.3. Project Finance Structure:
Structure of Project finance with respect to a power plant
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4.4. Parties to a project financing:
There are several parties in a project financing depending on the type and the scale of a
project. The most usual parties to a project financing are:
4.4.1 Government
Though local governments generally participate only indirectly in projects, their role is often
most influential. The local government’s influence might include: approval of the project,
control of the state company that sponsors the project, responsibility for operating and
environmental licenses, tax holidays, supply guarantees, and industry regulations or policies,
providing operating concessions.
4.4.2 Project sponsors or owners
The sponsors are the generally the project owners with an equity stake in the project. It is
possible for a single company or for a consortium to sponsor a project. Typical sponsors
include foreign multinationals, local companies, contractors, operators, suppliers or other
participants. The World Bank estimates that the equity stake of sponsors is typically about 30
percent of project costs. Because project financings use the project company as the financing
vehicle and raise nonrecourse debt, the project sponsors do not put their corporate balance
sheets directly at risk in these often high-risk projects. However, some project sponsors incur
indirect risk by financing their equity or debt contributions through their corporate balance
sheets. To further buffer corporate liability, many of the multinational sponsors establish
local subsidiaries as the project’s investment vehicle.
4.4.3. Project Company
The project company is a single-purpose entity created solely for the purpose of executing the
project. Controlled by project sponsors, it is the center of the project through its contractual
arrangements with operators, contractors, suppliers and customers. Typically, the only source
of income for the project company is the tariff or throughput charge from the project. The
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amount of the tariff or charge is generally extensively detailed in the off-take agreement.
Thus, this agreement is the project company’s sole means of servicing its debt. Often the
project company is the project sponsors’ financing vehicle for the project, i.e., it is the
borrower for the project. The creation of the project company and its role as borrower
represent the limited recourse characteristic of project finance. However, this does not have
to be the case. It is possible for the project sponsors to borrow funds independently based on
their own balance sheets or rights to the project.
4.4.4. Contractor
The contractor is responsible for constructing the project to the technical specifications
outlined in the contract with the project company. These primary contractors will then sub-
contract with local firms for components of the construction. Contractors also own stakes in
projects.
4.4.5. Operator
Operators are responsible for maintaining the quality of the project’s assets and operating the
power plant, pipeline, etc. at maximum efficiency. It is not uncommon for operators to also
hold an equity stake in a project. Depending on the technological sophistication required to
run the project, the operator might be a multinational, a local company or a joint venture.
4.4.6. Supplier
The supplier provides the critical input to the project. For a power plant, the supplier would
be the fuel supplier. But the supplier does not necessarily have to supply a tangible
commodity. In the case of a mine, the supplier might be the government through a mining
concession. For toll roads or pipeline, the critical input is the right-of-way for construction
that is granted by the local or federal government.
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4.4.7. Customer
The customer is the party who is willing to purchase the project’s output, whether the output
is a product (electrical power, extracted minerals, etc.) or a service (electrical power
transmission or pipeline distribution). The goal for the project company is to engage
customers who are willing to sign long-term, off take agreements.
4.4.8. Commercial banks
Commercial banks represent a primary source of funds for project financings. In arranging
these large loans, the banks often form syndicates to sell-down their interests. The syndicate
is important not only for raising the large amounts of capital required, but also for de facto
political insurance. Even though commercial banks are not generally very comfortable with
taking long-term project finance risk in emerging markets, they are very comfortable with
financing projects through the construction period. In addition, a project might be better
served by having commercial banks finance the construction phase because banks have
expertise in loan monitoring on a month-to-month basis, and because the bank group has the
flexibility to renegotiate the construction loan.
4.5. Global trends in Project Finance:
• Private-sector participation in infrastructure projects:
o Build-Own-Operate (BOO).
o Build-Operate-Transfer (BOT).
o Build-Own-Operate-Transfer (BOOT).
• Risk management techniques:
o Interest rate risk.
o Currency risk.
o Raw material price/supply risk.
o Demand risk.
• Deepening of capital markets in emerging countries.
• Issuance of bonds in some developing capital markets.
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4.6. Risks and Mitigants involved in project financing:
Financing infrastructure projects, especially in developing countries, entails a formidable set
of risks. It is the role of the project finance advisor, the project sponsor and other participants
to structure the financing in such a manner that mitigates these risks. Lenders and investors
always are initially concerned about financing immobile assets in distant, politically risky
areas of the world. The project finance advisor’s role is to carve out the risks, assigning them
to the party who is best suited to be responsible for controlling them. The purpose of this
section is to provide a checklist of the risks that a project finance transaction faces rather than
a strict taxonomy of these risks.
4.6.1. Risks and Mitigants Pyramid
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5. FINANCIAL MODELING
5.1. Introduction:
1. Financial modeling is an integrated part of financial planning.
2. It uses the past data to estimate the financial requirements.
3. The model makes it easy for the financial managers to prepare financial forecasts.
5.2. Financial Model Has Three Parts:
I. Input
• Cost related to the Project.
• Guidelines of regulator related to the Project
• Terms and condition of the company.
• Existing financial rules & regulations.
• Taxation and Corporate laws.
II. Model
• It defines the relation between financial variables and develops appropriate equations.
E.g. net working capital and fixed assets investment may be related to sales.
• When one independent variable changes the corresponding variable also changes.
III. Outputs
• Applying the model equations to the inputs, output in the form of projected or pro
forma of financial statements are obtained.
• The output shows the investment and funds requirements as per the sales objective
and relationship between the financial variables.
• The use of excel applications can help in further developing of the financial model.
33
5.3. Objective:
• The objective should be that the financial model should be simple so that it does not
lose sight of critical parameters and decisions.
• A complicated model may distract attention from real strategic issue.
5.4. Need for Financial Model:
• Transactions (e.g. receipts of the bills, incentives, penalties)
• Investments – new plant, machinery, facilities or financial investments.
• Corporate finance – to assist in deciding the best capital/corporate structure of a
company.
• Project financing – if borrowing money, banks will usually wants to see a model,
which shows the borrower will be able to meet the repayments, and stay within the
covenants set by the bank.
• What-if scenarios – to forecast the potential outcomes of available courses of action.
34
5.5. Purpose of Financial Model:
• Many assumptions have to be made when developing the model and its user will have
greater confidence in it if the assumptions are stated explicitly.
• A common reason for building a model is to test the sensitivity of a business case to
uncertainty about key drivers, so give some thoughts to the flexibility required.
5.6. Advantages:
• It makes financial forecasting automatic and saves the financial manager’s time and
efforts performing a tedious activity.
• Financial planning model helps in examining the consequences of alternative
financial strategies.
5.7. Applications:
• It establishes the relationship between financial variables and targets, and facilitates
the financial forecasting and planning process.
• The financial model can be improved by including many more financial variables e.g.
assets as current assets and fixed assets, borrowings as long term and short term
borrowing components.
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6. TARIFF STRUCTURE
6.1. Meaning of Tariff:
Governments may impose tariffs to raise revenue or to protect domestic industries from
foreign competition, since consumers will generally purchase cheaper foreign produced
goods. Tariffs can lead to less efficient domestic industries, and can lead to trade wars as
exporting countries reciprocate with their own tariffs on imported goods. Organizations such
as the WTO exist to combat the use of egregious tariffs.
6.2. Approaches to Electricity Pricing:
• Demand based Pricing
o Pricing based on consumers ability to pay.
o Generally prevail in monopolistic market environment.
• Cost based Pricing
o Pricing based on actual costs.
o Generally prevail in regulated market environment.
• Market based Pricing
o Pricing based on competition among the market players.
o Prevail in a competitive market environment.
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6.3. Tariff Philosophy for Generation:
• Cost Plus Approach.
• Recovery of Fixed Charges in proportion of target availability (thermal) and capacity
index (hydro & gas based).
• Normative parameters ensure incentives upon achieving higher efficiency.
• Fair return on investment.
• Promoting competition among generators through competitive bidding.
• Return on Equity irrespective of Dispatch.
6.4. Components of Generation costs:
Generation Costs = Investment costs + O&M expenses + Fuel Costs + Auxiliary
consumption
6.5. Tariff Structure – Thermal:
Two-part tariff:
• Capacity Charges (for recovery of Annual Fixed Costs)
• Energy Charges (for recovery of Primary Fuel Costs)
37
6.5.1. Capacity charges
• Interest on Loan Capital - For purpose of Tariff calculation, the normative loan shall
be worked out by deducting the cumulative repayment from the gross normative loan.
The repayment for the year shall be deemed to be equal to the depreciation allowed
for that year inspite of any moratorium availed.
• Depreciation - Depreciation shall be calculated annually based on Straight Line
Method. Depreciation shall be chargeable from the first year of commercial operation.
• Return on equity - Return on equity shall be computed on pre-tax basis.
• Operation and Maintenance expenses - Operation and maintenance expenses shall be
calculated on annual basis with an annual escalation rate spread across plant life.
• Interest on Working Capital - Rate of interest on working capital shall be on
normative basis. Interest on working capital shall be payable on normative basis
notwithstanding that the generating company or the transmission licensee has not
taken loan for working capital from any outside agency. The working capital for a
thermal power station has following components:
6.5.2. Energy Charges
• Fuel costs - Energy charges for thermal power stations are linked to the normative
operational parameters. The energy charge shall cover the primary fuel cost and
limestone consumption cost (where applicable), and shall be payable by every
beneficiary for the total energy scheduled to be supplied to such beneficiary during
the calendar month on ex-power plant basis, at the energy charge rate of the month
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(with fuel and limestone price adjustment). Total Energy charge payable to the
generating company for a month shall be:
(Energy charge rate in USD/kWh) x {Scheduled energy (ex-bus) for the month in
kWh.}
6.6. Tariff philosophy for Transmission:
• Cost Plus Approach.
• Simple & easy to understand.
• Fair Return on investment.
• Lower the costs to the consumers.
• Should not distort the market.
6.7. Components of Transmission Costs:
Trasmission Costs = Fixed costs + System Losses + System Services
6.8. Tariff Structure – Transmission:
• Interest on Loan capital.
• Depreciation.
• Return on Equity.
• Operation & Maintenance Expenses.
• Interest on working capital.
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6.9. General Concepts & Definitions in reference to Tariff determination:
Auxiliary energy consumption
The quantum of energy consumed by auxiliary equipment of the generating station, and
transformer losses within the generating station, expressed as a percentage of the sum of
gross energy generated at the generator terminals of all the units of the generating station.
Date of Commercial Operation’ or ‘COD’
The date declared by the generating company after demonstrating the maximum continuous
rating (MCR) or the installed capacity (IC) through a successful trial run after notice to the
beneficiaries, from 0000 hour of which scheduling process is fully implemented, and in
relation to the generating station as a whole, the date of commercial operation of the last unit
or block of the generating station.
Declared capacity
The capability to deliver ex-bus electricity in MW declared by such generating station in
relation to any time-block of the day or whole of the day, duly taking into account the
availability of fuel or water, and subject to further qualification in the relevant regulation.
Gross calorific value
The heat produced in kCal by complete combustion of one kilogram of solid fuel or one litre
of liquid fuel or one standard cubic meter of gaseous fuel.
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Gross station heat rate
The heat energy input in kCal required to generate one kWh of electrical energy at generator
terminals of a thermal generating station.
Infirm power
Electricity injected into the grid prior to the commercial operation of a unit or block of the
generating station.
Installed capacity
The summation of the name plate capacities of all the units of the generating station or the
capacity of the generating station (reckoned at the generator terminals).
Operation and maintenance expenses
The expenditure incurred on operation and maintenance of the project, or part thereof, and
includes the expenditure on manpower, repairs, spares, consumables, insurance and
overheads.
Plant availability factor (PAF)
The average of the daily declared capacities (DCs) for all the days during that period
expressed as a percentage of the installed capacity in MW reduced by the normative auxiliary
energy consumption.
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Conversion of MW into Million Units (MUs)
Tariffs
• Nominal Tariff - The tariff calculated at for each year (fixed cost + variable cost).
• Discount Tariff - The tariff calculated at present value of the future tariffs.
Discounting future tariffs by a discount rate does this.
Discount tariff = Nominal tariff x Discount factor
• Levelised Tariff - The tariff calculated for all years. This is a simple tariff representing
the tariffs throughout the plant life. In concept, this is “Weighted Mean” of all tariffs
with weights as discounting factors.
Where, ‘i’ varies from 1 to n
&
‘n’ is the life of plant.
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7. FINANCIAL INDICATORS
7.1. Net Present Value (NPV):
Net present value (NPV) is a standard method for the financial appraisal of long-term
projects. Used for capital budgeting, and widely throughout 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.
Each cash inflow/outflow is discounted back to its PV. Then they are summed. Therefore,
Where,
t - The time of the cash flow
n - The total time of the project
r - The discount rate
Ct - the net cash flow (the amount of cash) at time t.
C0 - the capital outlay at the beginning of the investment time (t = 0)
7.1.1. The 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.
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7.1.2. 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.
NPV > 0, the investment would add value to the firm the project should be accepted
NPV < 0, the investment would subtract value from the firm the project should be rejected
NPV = 0, the investment would neither gain nor lose value for the firm we should be
indifferent in the decision whether to accept or reject the project. This project adds no
monetary value. Decision should be based on other criteria, e.g. strategic positioning or other
factors not explicitly included in the calculation.
7.2. 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 (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.
Mathematically the IRR is defined as any discount rate that results in a net present value of
zero of a series of cash flows.
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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:
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. This is to compensate the
risk that he is taking on this project. Another factor that could influence the discounted rate of
return is the general market rate of return.
7.3. Debt Service Coverage Ratio (DSCR):
The debt service coverage ratio, or debt service ratio, is the ratio of net operating income to
debt payments on a piece of investment. The higher this ratio is, the easier it is to borrow
money for the property. The phrase is also used in corporate finance and may be expressed as
a minimum ratio that is acceptable to a lender; it may be a loan condition, a loan covenant, or
a condition of default.
In corporate finance, it is the amount of cash flow available to meet annual interest and
principal payments on debt, including sinking fund payments.
45
In commercial real estate finance, this is the main measure to determine if a property will be
able to sustain its debt based on cash flow. Most banks will lend to a 1.2 DSCR, but at times
with more aggressive practices you begin to see this number decreasing. A DSCR below 1.0
on a property indicates that there is not enough cash flow to even cover the loan.
In general, it is calculated by:
DSCR = Net Operating Income / Total Debt service
PAT+DEPRICIATION+INTEREST ON LOAN+LEASE RENTALS
Or DSCR = -----------------------------------------------------------------------------------------
INTEREST ON LOAN + REPAYMENT OF LOAN
A DSCR of less than 1 would mean a negative cash flow. A DSCR of less than 1, say .95,
would mean that there is only enough net operating income to cover 95% of annual debt
payments. For example, in the context of personal finance, this would mean that the borrower
would have to delve into his or her personal funds every month to keep the project afloat.
Generally, lenders frown on a negative cash flow, but some allow it if the borrower has
strong outside income.
Typically, most commercial banks require the ratio of 1.15 - 1.35 times (net operating income
or NOI / loan amount) to ensure cash flow sufficient to cover loan payments is available on
an ongoing basis.
7.4. Weighted Average Cost of Capital (WACC):
The weighted average cost of capital (WACC) is used in finance to measure a firm's cost of
capital. This has been used by many firms in the past as a discount rate for financed projects,
as the cost of financing (capital) is regarded by some as a logical discount rate (required rate
of return) to use. Weighted Average Cost of Capital is the return a firm must earn on existing
assets to keep its stock price constant and satisfy its creditors and owners.
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Corporations raise money from two main sources: equity and debt. Thus the capital structure
of a firm comprises three main components: preferred equity, common equity and debt
(typically bonds and notes). The WACC takes into account the relative weights of each
component of the capital structure and presents the expected cost of new capital for a firm.
The weighted average cost of capital is defined by:
Where,
K= D+E
c = weighted average cost of capital %
y = required or expected rate of return on equity, or cost of equity %
b = required/expected rate of return on borrowings, or cost of debt %
tc = corporate tax rate %
D = total debt and leases currency
E = total equity and equity equivalents currency
K = total capital invested in the going concern currency
Or in other words:
WACC = weight of preferred equity × cost of preferred equity
+ Weight of common equity × cost of common equity
+ Weight of debt × cost of debt × (1 − tax rate)
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8. METHODOLOGY OF FINANCIAL ANALYSIS
8.1. Project Cost and IDC Calculation:
As power plant requires a huge amount of investment, the initial step in financial modeling of
power plant is to calculate the initial cost i.e the expenditure estimated to occur in the
construction of the plant. It enables the company to further analyse its financial capability and
proceed accordingly in making investment decisions. Based on these estimates the company
decides and plans how much money to invest on its own and how money to borrow from the
market. It also gives the company initial inputs to decide on whether to proceed further with
the same project or go for certain modifications in the project in order to bring the project
cost in accordance with the financial capability of the company.
The project cost includes various expenses, which are divided into two categories, which
consists of the following components.
8.1.1. 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
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8.1.2. 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)
IDC is the interest on the debt (expenses), which is incurred during the construction of the
plant. It depends upon the construction period and phasing of expenditure.
The important point about the IDC calculation is that the upfront equity should be paid first
and then after equal drawl of debt and equity rest of fund required every time period is
funded by both debt and equity in 70:30 ratio.
8.2. Assumption and Input Sheet:
Assumption and input sheet is the base of the Financial Modeling. In initial stage of Financial
Modeling , we rationally assume certain independent variables on which the whole
calculation is based . 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.
The variables listed in the assumption sheet are following:-
• Cost related to the Project.
• Guidelines of regulator related to the Project
• Terms and condition of the company.
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8.3. Fixed Cost Calculation:
There are five components of fixed cost calculation these are
• Interest on loan
• Depreciation
• O&M expenses.
• Interest on working capital
• Return on equity.
8.4. Variable Cost Calculation:
In Coal Based Thermal Power Plant the variable cost include :-
• Cost of Primary Fuel (coal).
• Cost of Secondary Fuel (oil).
8.5. Tariff Calculation:
In order to calculate Levelised Tariff, we first of all calculate Tariff for each year of operation
of the Power Plant . Tariff includes both fixed cost and variable costs. After calculating tariff
for each year we calculate the present value of Tariff of all the years. Then we will calculate
levelised tariff . It is calculated to give the single figure value for the tariffs of multiple years.
The essence of calculation of Tariff is that it enables the generation utilities to justify the
reason for the proposed Tariff in the PPA.
Now a days the process of Competitive bidding is being promoted and in this mechanism the
generation company has to bid i.e it can quote the tariff without justifying it to the
regulatory. It means the lowest bidder will get the contract irrespective of it’s quantum of
profit margin .
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8.6. 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.
• Potential lenders or creditors who want a clear picture of a company's ability to repay.
8.7. Profit & Loss Account:
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:
8.7.1. 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.
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8.7.2. 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 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.
8.8. Balance Sheet:
A balance sheet is a statement of the book value of all of the assets and liabilities (including
equity) of a business or other organization or person at a particular date, such as the end of a
"fiscal year." It is known as a balance sheet because it reflects an accounting identity: the
components of the balance sheet must (by definition) be equal, or in balance; in the most
basic formulation, assets must equal liabilities and net worth, or equivalently, net worth must
equal assets minus liabilities.
A balance sheet is often described as a "snapshot" of the company's financial condition on a
given date. Of the four basic financial statements, the balance sheet is the only statement
which applies to a single point in time, instead of a period of time.
8.9. Sensitivity Analysis:
Sensitivity analysis is done to know the effect of change certain individual variables on the
dependent variables. As in real life scenario all things does not go as smoothly as planned
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initially and the planners must take into account the possibility of deviation of any financial
or technical component from its anticipated ,assumed or planned value .For example a
company should know that what effect will be on Profit and the Tariff if interest rate on loan
or cost of fuel changes . It gives us wider picture of the financial model of the plant and
determines the key components , change in which can have highly leveraged effect on the
balance sheet of the company.
8.10. Optimization:
The process of energy asset management begins with insight into load and price behavior in
the future. It’s imperative to start this process off on the right track. The quality of your load
forecasting will shape your scheduling and bidding strategies, resource availability, real-time
operations, P&L and revenues, directly impacting your bottom line performance.
Optimization of Profit is most concerned feature in Merchant Power Plant. Unlike the
Traditional PPA, where return is fixed, Independent Power Producers can respond according
to the behavior of the market. The power producers can go through 100% PPA or an
optimized mix up of PPA and Spot Trading to maximize the profit. However making profit
through trading of power is directly proportionate to demand of electricity.
In the process of optimization of profit, the top management analyses the outcome of various
mix of the selling of power through PPA, STA or on daily schedule.
Long Term PPA is the long term Power Purchase Agreement that is for the period of more
than 3 years.
STA is Short Term Agreement, which is for the period upto 1 year. Generally the price of
STA is higher as compared to that of PPA.
Presently the average price of selling power in open market on daily basis is high among all
three modes of selling power.
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9. PROJECT COST ESTIMATE AND TARIFF
CALCULATION
A comprehensive financial model has been set up representing a complete simulation of the
Project with regard to technical and financial aspects.
9.1. Basis of Project Cost:
The project cost estimate has been worked out on the basis of following assumptions:
9.1.1. Assumptions for Hard Cost Input
The followings are the key assumptions made while estimating the project cost:
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• Total Two (2) Units of 150 MW gross capacity has been considered.
• The cost of different facilities of Power plant with auxiliaries has been worked out on
the basis of the cost of similar kind of projects.
• Contingency @2.5% on Project Cost has been considered in the Project Cost estimate.
• Cost of land has been considered for 120 Acres of Land.
• Site leveling & grading has been considered in the Project cost estimate for higher
undulations of the project site.
• Capital cost for Water Intake system, Coal Conveyor, Transmission line, Widening of
nearest canal for reservoir, Coal Dryer has been considered.
• The cost estimate for Taxes and duties has been considered in the project cost
estimate. The completion schedule is considered as 26 months for the first Unit and
32 months for the second Unit from date of Financial Closure Date.
9.1.2. Assumptions for Soft Cost Input
The major assumptions made to compute the soft cost are as follows:
• Financing - Debt: Equity - The project is considered to be financed by equity and
term loan with Debt Equity Ratio of 75:25.
• Interest During Construction (IDC) - has been worked out in the Project Cost based
on the phasing of the expenditure up to COD of 2nd Unit with a project schedule of
32 months for Financial Closure Date.
• Working Capital - The rate of interest on working capital loan is assumed to be 10%
p.a.
9.2. Project Cost:
On the basis of assumptions discussed above, the estimated cost of the project is USD 415
Million. The specific cost of the project is USD 1.38 Million per MW. The summary of
breakup of the project cost is indicated in table below:
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9.2.1. Project Cost Break Up
S. No. Project Cost USD Million
1 Land & Site Development 13.68
2 BTG Island 97.11
3 BOP Packages 101.49
4 Civil Works 81.93
5 Taxes & Duties 6.71
6 Erection, Testing & Commissioning & Other
Infrastructure 60.26
7 Contingency 10.34
8 Preoperative and Preliminary Expenses 10.44
9 Financing expenses 6.20
10 Working Capital Margin 5.75
11 Interest during Construction (IDC) 21.09
12 Total 415.00
9.3. Technical Input Assumptions:
Basic operational inputs data for the purpose of estimation of tariff are as follows:
• Plant gross capacity has been considered as 2x150 MW.
• Plant Load Factor (PLF) of 80% has been considered.
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• Station heat rate has been considered as 2468.7 kcal/kWh
• Auxiliary power consumption of plant with IDCT has been considered @ 10.0 %.
• Secondary fuel consumption of 2 ml/kWh has been considered.
• For the purpose of tariff calculation, the gross calorific value (GCV) of coal has been
considered as 3800 kcal/Kg. GCV of auxiliary fuel (LDO) has been considered as
10,200 kcal/L.
9.4. Financial Input Assumptions:
The following are the financial assumption in tariff calculation:
9.4.1. Debt Structure
Rate of interest, the repayment period and the moratorium period for the proposed loan
structure have been shown in the table below:
Loan Structure
Description Unit FCL
Interest Rate % 7.0%
Repayment Period Years 10
Moratorium Months 12
Repayment Mode Instalments Quarterly
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9.4.2. Working Capital
Working capital covers the following:
• Fuel costs for 1 Month
• Secondary fuel cost for 2 Months
• O&M expenses for 1 Month
• Maintenance spares, equivalent to 20% of O&M expenses
• Receivables equivalent to 1.5 Months
9.4.3. O&M Expenses
Annual fixed operation and maintenance cost is sum total of Repair & maintenance
Expenses, (R&M), establishment including employee expenses and administrative & general
expenses. O&M Expenses allowed during the first year of Control period shall be escalated at
the rate of 3% per annum over the tariff period.
9.4.4. Fuel Cost
Landed cost of coal is considered as USD 23.13 per tonne considering 2015-16 as base year
with the escalation rate of 3 % per annum is considered on the coal cost. Secondary fuel cost
is considered as USD1.03/l with an escalation of 3.48 % per annum.
9.4.5. Depreciation
All assets have been depreciated based on straight line method. The rate of 5 % for initial 11
years (Loan period) has been considered and after 11 years the remaining depreciable value
shall be spread over the balance useful life of the assets considering maximum depreciable
value of 100% under BOOT model. The economic plant life has been considered as 25 years.
9.4.6. Corporate Tax
The rates of corporate tax have been considered as 25% as per Indonesia local tax law.
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9.5. Financial Analysis:
• Assumptions - Annexure 1 (Sheet I)
• Debt repayment - Annexure 1 (Sheet II)
• Depreciation - Annexure 1 (Sheet III)
• O&M Expenses - Annexure 1 (Sheet III)
• Fuel expenses - Annexure 1 (Sheet IV)
• Interest on Working Capital - Annexure 1 (Sheet V)
• Tariff Calculation - Annexure 1 (Sheet VI)
• Profit & Loss Statement - Annexure 1 (Sheet VII)
• Cash Flow Statement - Annexure 1 (Sheet VIII)
• Balance Sheet - Annexure 1 (Sheet IX)
• NPV & IRR Calculation - Annexure 1 (Sheet X)
• WACC & DSCR Calculation - Annexure 1 (Sheet XI)
9.6. Sensitivity Analysis:
A sensitivity analysis has been carried to ascertain the robustness of its financials. Various
scenarios for which the sensitivities was carried out and the results are as follows:
Scenario Min
DSCR
Avg.
DSCR
Project
IRR(%)
Equity
IRR(%)
Base Case 1.29 1.63 12.19 18.26
Case 1: Fuel cost increased by 10% 1.30 1.64 12.37 18.64
Case 2: Increase in Project Cost by 10% 1.28 1.61 12.02 17.91
Case 3: Decrease in GCV of coal by 1000 kCal/kg 1.32 1.67 12.72 19.46
Case 4: Interest rate increased by 1% 1.27 1.60 12.73 18.36
Case 5: Increase in Gross station heat rate by 10% 1.30 1.64 12.34 18.60
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10. CONCLUSION:
Financial results:
1. Levelised Tariff : 0.06459927 USD/kWh
2. NPV : 648.72 Million USD
3. Project IRR : 12.19%
4. Equity IRR : 18.26%
5. WACC : 10%
6. DSCR Max : 3.13
Min : 1.29
Avg. : 1.63
• With the above financial results showing all the Financial Indicators of a Thermal
Power Plant being analyzed in this report, it is being concluded that the proposed
power plant is bankable which makes it financially viable for the private sector firms
to accept the project.
• An Average and Minimum Debt service coverage ratio of 1.63 & 1.29 respectively
may be considered satisfactory for a bank to lend money for the project.
• Since the project IRR is greater than the cost of capital, the project will add value to
the firm & hence, the project should be accepted.
• Since NPV > 0, the investment would add value to the firm & hence, the project
should be accepted.
• It may be observed from the sensitivity analysis that project financials are quite robust
in various scenarios and the DSCR levels are satisfactory.
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11. BIBLIOGRAPHY
BOOKS REFERRED:
• FINANCIAL MANAGEMENT – I. M. Pandey
WEBSITE REFFERED:
• PT Perusahen Listrik Negara www.pln.co.id
• Indonesian coal mining association apbi-icma.org
• Ministry for energy and mineral resources Indonesia www.esdm.go.id
• International Energy agency www.iea.org
• Wikipedia www.wikipedia.org
• National Power Training Institute www.npti.nic.in
• Lahmeyer International India www.liindia.com
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ANNEXURE 1