kpmg india electricity outlook 2008
TRANSCRIPT
The India Electricity Market Outlook
A DV I S O RY
INF R AST R UC TURE AN D G OVERN MENT
Foreword
These are indeed exciting times for the power sector- the winds of change have
significantly impacted the business. Starting from the reforms in the1990’s which
focused on power generation, the current reforms are targeted at the distribution
side of the business. There is also an attempt at establishing a well functioning
power market by allowing power trading as a separate licensed business.
These changes are apparent in the rising level of private participation, increasing
scale of operation, complex fuel procurement plans, initiation of power trading
activity and competitive tariff determination.
These changes coupled with an estimated demand for 227 GW by 2012 indicates
significant opportunities for sector participants. In line with this potential, private
sector involvement to the tune of 76 GW is expected over the same time period.
The sector has also seen a surge in investment across all activities of the value
chain. However, this does not automatically suggest that all private players would
book significant returns. Each player would have to define its competitiveness
across some parameters- fuel supply, equipment sourcing, ability to understand
the regulatory environment and demand risk management.
KPMG has witnessed and participated in this process of change. We have
advised a variety of clients- regulatory bodies, state electricity boards, IPP’s,
international transmission companies and private equity firms; on issues ranging
from tariff determination, choice of fuel, fuel procurement strategy, competitive bid
development, commercial review, to name a few. Our clients have benefited from
our advisory services; which reflects deep understanding of the sector and activity
specificin sights.
The “India Electricity Market Outlook” attempts to outline the key issues and
Developments shaping the power sector. Critical questions with respect to invest-
ment, growth opportunities, and potential market and regulatory risks have been
addressed to develop a well rounded perspective. By tackling these fundamental
questions, the document has set the tone for better understanding of the current
and future prospects of the power sector.
We have enjoyed sharing our understanding and experience of the sector through
the “Indian Electricity Market Outlook”. I hope the reader benefits from the
simple representation of the complex is sues which have been taken up in the
document.
The power sector is poised for exponential growth and we look forward to our
continued association and involvement with this dynamic sector.
Arvind Mahajan
National Industry Director - Infrastructure & Government
Table of contents
1. What is the likely Demand-Supply scenario in 2012? 1
2. Can India afford all this Power? 4
3. Is the Regulatory Scenario conducive to Investment? 6
4. Will the Transmission Network support the new 7Generating Capacity?
5. What is the process for Establishing Generation? 8
6. What are the options for sale of Power? 10
7. How do the Fuel Sourcing options compare? 12
8. What are the typical Contracting Structures adopted? 17
1. What is the likely Demand-Supply scenario in 2012?
1.1 Key Questions addressed
• Are the much publicized demand estimates for real?
• What is supply response to this aggressive demand and how is the deficit
scenario likely to change over the next few years?
• What are the key implications of the demand supply gap on generation
investment?
• If the sector is so attractive, will everyone setting up a power plant succeed?
1.2 Conclusions
• To sustain a Gross Domestic Product (GDP) growth rate of 8 percent, KPMG
estimates that India would need to increase its installed capacity to 227 GW
by 2012, from the existing 132 GW. In a low GDP growth scenario (4 percent),
India would still need 183 GW by 2012.
Installed Capacity Requirement
Source: Ministry of Power, Planning Commission, and KPMG Analysis
Demand for power is showing a steep increase in order to:
• Meet the unmet demand as it exists today
• Cope with incremental demand created with rapid economic growth
KPMG estimates that a commercially viable end-user demand for an incre-
mental capacity of 95 GW will exist by 2012.
• The supply response to this shortfall has been more rapid than in the previous
years. KPMG estimates that 65 GW of capacity will come on stream by 2012,
which will translate to a 13.2 percent peak deficit (in case of an 8 percent
GDP growth) and a 7.7 percent peak surplus (in case of 4 percent GDP
growth).
1
Till date, 40 GW (out of the 68 GW planned by the Government from the
Public Sector in the 2007-12 period) of capacity is under various stages of
construction by the Public sector. In addition to this, 76 GW (as against the
governement 2007-12 estimate of 11 GW) has been announced by the Private
sector, for completion by 2012.
KPMG projections are based on the historical success rate and a feasibility of
implementation of the announced projects based on progress achieved so far.
Demand Supply scenario by 2012 (GW)
Source: KPMG Analysis
• Not all private players can be winners. Winners need to have a competitive
edge on one or more of the following:
• Fuel Supply
• Equipment Sourcing
• Ability to withstand short-term financial pain
• Ability to obtain clearances and permissions
• Choice of market segment and ability to manage demand risk
Based on the current trend of regulations, there is a no move towards separation
of distribution and supply businesses of the distribution utilities, nor is there a
high degree of emphasis on ensuring non-discrimination between the distribution
utility’s supply business and other suppliers. Coupled with reducing cross
subsidies in utility tariffs and access to a pool of relatively cheap power, implies
that the distribution utility will be more competitive than an IPP. Hence, for power
producers, it will be prudent to ensure assured off-take through a PPA and to
assume conservative levels of merchant power sales in a project portfolio.
2
The key drivers of return are the choice of fuel, the merchant power pricing and
timely completion of the Project. IRR increase due to standalone increase in
some parameters is illustrated below
IRR sensitivity to select parameters
80%
70%
60%
50%
40% 6.50%
6.48%30%
2.63% 2.36% 1.52%
20% 2.36%4.18%
10%
0%
21.73% 28.21%
34.72%
-8.32%
8.69%
-10%
-20% Base Case PLF (90%) Aux Con SHR O&M Working Case 2 Case 3 Captive 20% Case 4 Imported -CERC (7%) (2400) (Rs. 1 Mn/ Capital Linkage Captive Coal Merchant Merchant Coal
MW) Mgmt Coal Total Coal Total Sale @ with (1 month) Captive
Rs. 3.5 Coal
till 2015)
Source: KPMG Analysis
The key implications of the demand supply gap and planned capacity
additions are
• If successful capacity build-out happens, beyond 2015-17, the price of
power may not be determined as in a ’supply constrained scenario’
witnessed today
• India is likely to have established leaders in the Power Sector and new
players are expected to operate as marginal players.
In the unlikely scenario of a deficit existing beyond 2015-17, the promoters of
power plants who have assumed demand risks are expected to earn very high
returns.
3
US
$ m
n
2. Can India afford all this Power?
2.1 Key Questions addressed
• Who pays for power in India?
• Is the system financially sustainable?
• How does a power developer insulate himself from credit risk?
2.2 Conclusions
• Although set by independent Electricity Regulatory Commissions, state level
differences exist in retail tariff and they vary across consumer categories as
well.
Tariffs are still to reflect the cost of service to the consumers. Domestic and
Agriculture consumers pay lower tariffs as compared to Industrial and
Commercial Consumers; (i.e. the former two are being cross subsidized by
the latter). Despite the cross subsidization overall revenue receipts are
short of the overall expenditure in many states. This is mainly on account of
the cost of service being compounded due to the high Transmission &
Distribution losses in India (31 percent). On an India-wide basis, the gap
between Average Cost of Service and Average Realization was 0.57 INR/ unit
in 2004-05. Often, part of this gap is met by the subsidies from the state government.
• To the extent that tariff is unable to meet financing requirements of the
system, sustainability is dependent on affording deficit. In terms of
sustainability, it is not possible to take a country wide view across the value
chain. Due to regional differences, analysis needs to be done at a State/
contracting party level.
Sources of subsidy (mn US$)
8,000
7,000
6,000
5,000
4,000
3,000
2,000
1,000
-
2,117 3,170 2,703 2,396
902
1,170 1,496 1,699
5,417 3,115 3,888 4,273
2001-02 2002-03 2003-04 2004 - 05 Govt. Subsidy Cross Subsidy Uncovered Subsidy
Sources: Statistical Outline of India, Tata Services Ltd
4
• However, individual contracts can be sustainable in a financially difficult
environment. A power generator needs to insulate itself from credit risk by:
• Obtaining a PPA with a more credit worthy Distribution utility
• Obtaining a PPA with Central Govt. agencies such as Power Trading
corporation (PTC)
• Minimizing the cost of delivered power – If the margina cost of a power
plant is competitive in cpmarison to other plants of the State, it is more
likely to be dispatched and hence more likely to get paid
• Making captive power arrangements where the counter-party is a part
owner of the power plant (e.g. one or more large industrial consumers).
5
3. Is the Regulatory Scenario conducive to Investment?
3.1 Key Questions addressed
• How has the power reform process changed since the 1990s?
• How does India compare to a well functioning power market?
• What are the key implications on generation investment?
3.2 Conclusions
• Legislation like Electricity Act 2003 along with other policy initiatives have
initiated India’s move towards establishment of a well functioning power
market. It has provided “choice” to buyers and sellers of power through
functioning of a multi-buyer / multi-seller market
• Power Projects now have a higher chance of success as compared to the
1990’s. But hurdles still exist in the form of:
• Multiple Clearances. Upto13-15 clearances are required from the land,
environment, forest, civil aviation and water departments. The clearances
are required from a combination of State and Central level bodies and the
cumulative process can take up to two years
Clearance Classification
Source: KPMG Analysis
• Lack of transparency in the Fuel Supply. State bodies control over 95
percent of Domestic Coal Production. An objective and transparent process
for awarding a Fuel Linkage to conumers is lacking. The existing process
takes time and could affect the timelines for setting up a plant. Price
increases of both Domestic Coal and Gas are uncertain and not linked to
international market considerations.
The Government has announced plans to address all these issues, but these are
expected to take time. Therefore, private players and financial sponsors need to
find ways to deal with this situation. The ability of a promoter to address these
issues is an important parameter while assessing a generation opportunity.
6
4. Will the Transmission Network support the new Generating Capacity?
4.1 Key Questions addressed
• Is the transmission network adequate to support the additional capacity
generation?
• Is interregional transfer of power feasible?
• What are the key implications on generation investment?
4.2 Conclusions
• India has five regional grids and each grid is monitored and operated by a
regional dispatch center. The inter-regional transmission capacity is around 17
GW which is inadequate and leads to network congestion. To address this
issue, the Government plans to increase the inter-regional capacity to 37 GW
by 2012.
• In addition to congestion, power transmission across several utility systems
or zones leads to accumulating utility or zone access charges or ‘pan caking’
and this can increase the tariff to be paid by the end consumer for power
flowing from fuel centres (Eastern Region) to demand centres (Northern and
Western Regions). Though the Central Electricity Regulatory Commission
(CERC) in its concept paper has discussed alternative transmission pricing
methods (Contracted Path, Incremental Postage Stamp), there is uncertainty
regarding its immediate implementation.
• Though open access is allowed in the Transmission network, the allotment
priority of a long-term customer (> 7 years) is higher than that of a short-term
customer.
Inter-regional Transmission capacity (MW)
Region Capacity in 2007(MW) Additional Capacity planned till 2012(MW)
NER-NR 0 4000
NER-ER 1250 1000
ER-NR 5000 3500
ER-WR 2800 5700
ER-SR 3600 0
NR-WR 2100 5500
WR-SR 1700 1000
All India 16450 20700
Source: National Electricity Plan, CEA
7
5. What is the process for Establishing Generation?
5.1 Key Questions addressed
• What is the process followed now for procuring power?
• What is the Capital cost for setting up a Power Plant?
• What are the Timelines for setting up a Generating Plant?
5.2 Conclusions
• After the implementation of the Electricity Act, tariff determination based on
Competitive Bidding has been mandated by the MoP through its ‘Guidelines
for Determination of Tariff by Bidding Process for Procurement of Power by
Distribution Licensees’ (‘Guidelines’) in January 2005.
In the Competitive bidding regime
• Distribution Companies or Trading companies call for competitive bids and
award the PPA to the bidder with the lowest levelized tariff bid
• Bids typically require a submission of multi-part tariff structure (separate
capacity and energy components)
• Two types of Bidding processes exist
o Case 1: Location, Technology or Fuel are not specified
o Case 2: Location Specific Projects with specific fuel allocation
• Capital costs of generation plants vary acoording to the fuel type. Typical
costs per MW are
•Coal-based plant: INR 3.8 to 4 crore
•Gas-based plant: INR 3.5 crore
•Hydro: INR 5 crore
•Wind: INR 5-6 crore
•Nuclear: INR 6 crore (going by the project cost for PWR and PHWR
reactors)
• Timelines for setting up a project vary depending on the nature of the
requirement of approvals and clearnaces by the developer and fuel type of the
plant. Project timelines associated with a Case 2 based bid are lower, since
the developer is normally not required to complete land acquisition, obtain
environmental clearances and establish fuel linkage. They are carried out by
the entitiy running the bid process at the start. Timelines for setting up a plant
are depicted in the schematics on the next page
• Timelines for financing have changed with Financial institutions taking a view
on the Developer capability to successfully execute the Project within time
and cost estimates. At present, some projects even achieve Financial Closure
prior to entering into a PPA.
8
Overall Timelines till Commercial Operation
Source: KPMG Analysis
9
6. What are the options for sale of Power?
6.1 Key Questions addressed
• Which are the key demand segments?
• Is offtake of power assured for a plant with a PPA?
• What are the issues associated with sale through network Open Access?
• What is the outlook of prices across various demand segments?
6.2 Conclusions
• Sale of power through a Long-term PPA, sale in the Short-term market and
sale through Distribution Open Access are the three main options for sale of
power today.
The Long-term market is characterized largely by bilateral and multilateral
contracts (PPAs) between Distribution Utilities/State Trading Companies and
the Generating Companies - as a culmination of a Competitive Bidding
process.
Sale in the Short-term market is typically through Power Trading Companies.
Currently, the Short-term market is characterized by bilateral contracts and
there is no organized trading mechanism such as a power exchange.
However, at least 2 power exchanges are expected to be operational in the
next few years.
Direct sale to consumers through network Open Access requires convincing
the customer to move from the Distribution utility by demonstrating that it
would result in significantly lower costs without any risks on availability of
power.
• Assured off-take in the Long-term market is dependent on the marginal cost
of power from a plant and the relative position of such cost among the
different competing stations in the benefficiary State. Hence, gas based
power plants, due to higher cost of fuel (and hence higher marginal cost in a
2 part tariff system) are at the “bottom in the merit order” and are often
asscoiated with poor Plant Load Factor.
Hence, in project evaluation, it is important to understand the marginal cost
profile (as per tariff submission) of competing stations in the target market, to
evaluate whether the off-take for the Power Plant is assured
10
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
• Based on the current trend of regulations, there is a no move towards
separation of distribution and supply businesses of the distribution utilities,
nor is there a high degree of emphasis on ensuring non-discrimination
between the distribution utility’s supply business and other suppliers.
Coupled with reducing cross subsidies in utility tariffs and access to a pool of
relatively cheap power, implies that the distribution utility will be more
competitive than an IPP. Hence, sale through Distribution Open Access is
exposed to switching risk of the consumer. In the event of tariff
rationalisation, the conusmer may choose to move back to the State utility
unless the utility tariff and the tariff under open access continue to be
significantly different
• Prices in the Short-term market have risen sharply and are positively
correlated with the size of peak deficit. These prices are expected to remain
firm for some more time before reducing with the reduction in the size of the
deficit. The prices also different from one State to another due to differential
capabilities around load management and “political” implications associated
with unreliable power.
The outlook for the different demand segments is represented below
Price outlook across demand segments
2009-10 2011-12 2016-17 Risks
Source: KPMG Analysis
Sale in Retail
Market (Group
Captive/ Open
Access)
Switching risk of
consumer, when
utility is undertak-
ing tariff rationali-
zation
Ability of con-
sumer to enter in
a long term con-
tract
Feasibility
needs to be
evaluated at a
State level
Hurdle rates as
high as
Rs.3.39/kWh in
Maharashtra
Feasibility needs
to be evaluated at
a State level
The hurdle rate
likely to decrease
with decrease in
cross subsidy
Unlikely as utility
would be able to offer
more reliability
Pressure on pricing
likely due to higher
bargaining power
Sale in
Short Term
Market
(Trading)
Sale in
Long Term
Market
(PPA based)
Uncertainty of
Off-take
Low risk
Sale possible
marginal cost of
power
Likely price INR/unit
1.8-2.5
Sale Possible
Captive coal block
may be essential to
be cost competitive
Sale possible
The average price
likely to come
down to INR/unit
3-3.5 and then go
down
Sale possible
Surplus and more
pit-head
generation
Likely price to
remain unchanged
Sale possible
Price likely to
remain firm at
current tariffs of
INR/unit 4-4.5
Sale possible
Deficit scenario
driving Case-I
and Case-II bids
Likely price Rs/
unit 1.8-2.25
11
7. How do the Fuel Sourcing options compare?
7.1 Key Questions addressed
• What are the various fuel sourcing options?
• What is the existing status of Fuel Supply to Power Plants in India?
• What factors influence the choice of Coal as a fuel? Is the regulatory environ-
ment conducive in the Domestic Coal segment?
• What are the various Coal Import options?
• How does the cost of various coal options compare?
• What are the Gas sourcing options?
7.2 Key Conclusions
• The three main fuel sources used in India are Coal, Gas and Hydro, with Coal
being the dominant source. The dominance of coal in the fuel mix is expected
to increase.
Capacity addition by fuel-type (MW, %)
Source: Infraline
12
• The existing status of the vaious fuel supply options are as following:
Current status of fuel supply
Coal Gas
Linkage Captive Imported Domestic LNG
Supplier Govt. of India Govt. of India Indonesia,
South Africa
ONGC, OIL, GSPC,
Reliance Qatar, Iran
Price Determination
Govt. of India N.A. Market prices Uncertain Market prices
Length of con-tract
25 years or Mine life,
whichever is earlier
Minelife 7 years
Current: 5-15 years
Future: Uncertain
Typically short-term
Current prices (5500 GCV for coal and per BTU for gas) US$
25.9 19.4 35 Current: 3.5-5
Future: Uncertain
Current: 10
Current ener-gy - adjusted prices US$mn Kcal
4.7 3.5 6.4
Ongoing: 13.9-19.8
Future: Uncertain
Current: 39.7
Tariffs / Import duties
N.A. N.A. Nil N.A. 5%
Delivery infra-structure responsibility
Power plant developer
responsibility
Developer responsibility
Can be CIF or FOB
Power plant developer
responsibility
Power plant developer
responsibility
Washery responsibility
Power plant developer
responsibility
Developer responsibility
Typically suppli-er responsibili-
ty N.A. N.A.
Note: Transportation charges for Coal and Transmission charges for Gas have not been considered
Source: KPMG Analysis
13
• The key factor affecting the choice of coal source is the Developers
ability to manage the regulatory environment. Generally, a domestic captive
mine is the cheapest coal source and hence should be the natural choice for a
Developer. However, there is signif icant uncertainity around the mechanism
for allocation of coal blocks to private developers.
Factors affecting choice of fuel
Domestic DomesticFactor/Coal Source Imported
Linkage Captive
Procurement difficulty
Level of Regulation
Capital Expenditure
Supply insecurity
Landed Price
Quality problems
Environmental impact
Source: KPMG Analysis = High; = Medium; = Low
• State owned bodies still control over 95 percent of domestic coal production
with the remaining 5 percent being captive coal blocks allotted to companies
in the Power, Cement and Steel sectors. Merchant mining is not allowed. For
a Coal Linkage, price increases are uncertain and not market related.
14
• Three options for imported coal exist viz. buying from a trader, buying from a
supplier, and obtaining rights to mine. The characteristics of each of these are
illustrated below
Imported coal options
Buying from a trader
Buying from Supplier
Rights to Mine
Ease of Procurement
Easy Easy Moderate
Downsides Higher than market price
Country risk to be borne by the devel-oper e.g. Export Curbs
Country risk to be borne by the developer
Nature of Contract
Easy Easy Moderate
Typical Counterparties
Party 1: State Utility Party 2: Coal Trader The Coal is typically blended by the State utilities with low-grade Indian coal
Party 1: Independent Power Producer Party 2: Supplier in Indonesia
Party 1: Independent Power Producer Party 2: Indonesian company
Examples MMTC with State Utility
Nagarjuna Power with Rio Tinto
Tata Power 30% equity stake in PT Kaltim Prima Coal and PT Arutmin Indonesia
Source: KPMG Analysis
• A comparison of the existing costs for various coal types is illustrated below
Cost comparison: Domestic and imported coal
Source of Coal Imported Domestic @ 500km from
Linkage
Domestic @ 1350km from
Linkage
Domestic Captive @ 500 km
Domestic Captive @ 1700 km
GCV (KCal / Kg) of Indo-Sub bituminous
5,500 5,270 5,270 5,270 5,270
Price of Coal (USD/MT) 35 27 27 20.25 20.25
Add: Freight (USD/MT) 13 - - -
Add: Port Charges (USD/MT) 1.3 - - -
Add: Inland Transportation (USD/MT)
7 9.8 27.5 9.8 34.0
Total (USD/MT) 56.3 36.8 54.5 30.05 54.3
Cost (USD) / Mn KCal
10.3 7.0 10.3 5.7 10.3
Assumption for Imported coal: Coal prices & freight assume current market prices. Depending on the sourcing strategy for imported coal, these might be lower.
Source: KPMG Analysis
15
• The two gas sourcing options are domestically produced gas and re-gasified
imported Liquefied Natural Gas (LNG). Long-term domestic gas procurement
is not possible currently due to low availibility and uncertainity over pricing.
Long-term use of re-gasified imported LNG is not economically viable due to
the current high price. The supply deficit is expected to continue till 2011
• A Petroleum and Natural Gas Regulatory Board (PNGRB) has been formally
established in July, 2007. The PNGRB has the mandate of regulating all
downstream activities in the sector- refining, processing, storage,
transportation, distribution, marketing and sale of petroleum, petroleum
products and natural gas. The regulatory approach to common carrier pipelines
puts significantly impact crictical gas transport infrastructure, and its availibility
and pricing.
16
8. What are the typical Contracting Structures adopted?
8.1 Key Questions addressed
• What are the typical contractual structures for Plant Construction?
• What are the typical contractual structures for Plant O&M?
• Are Power Purchase Agreements standardized?
• What are the typical contractual structures for Fuel Supply?
8.2 Key Conclusions
• Four contracting options for Plant Construction exist as represented in the
schematic below
Contracting options: Plant construction
Activity/Options 1 2 3 4
Boiler supply
Turbine-Generator supply
Boiler Design and Engineering services
T-G Design and Engineering Services
Coal Handling System supply / erection
Ash Handling System supply / erection
Transformers supply / erection
Switchyard supply / erection
Cooling towers supply / erection
Civil & Structural work
Source: KPMG Analysis
17
Option 1 2 3 4
Description
The entire project is contracted to one vendor on an EPC basis
The Boiler island and T-G island Supply are contracted through separate EPC contracts. BoP supply and services is given out to various vendors
B-T-G supply and services is contracted to one vendor while the BoP is given out to various vendors
A variant of Option-3 used as a Tax-saving mechanism in case of import of B-T-G
Developer risk Low: Overall Timelines managed by vendor
Developer risk is High because Overall Timelines have to be managed by the developer
Risk is slightly lower than Option 2 since one vendor is handling B-T-G
With a wrap-around agreement, same as Option 3
Process followed
One NIT for the entire plant
Separate NITs for com-ponents
Separate NITs for com-ponents
Separate NITs for com-ponents
Typical plants going in for the option
IPPs Public Sector Plants IPPs, Public Sector Plants
IPPs
In India, public as well as private developers are planning to set up power
projects through a split contract system to ensure cost competitiveness.
• Four options exist for contracting O&M as represented below
Contracting options: O&M
Activity/Options 1 2 3 4
Plant Manpower
Plant Supervision
Daily Operations
Routine Maintenance
BoP Maintenance
Planned Maintenance
Unplanned Maintenance
Plant Availability
Plant Performance
Spares Consumption
Spares Prices
Logistics
Insurance
O&M Contractors responsibility Developers responsibility
Source: KPMG Analysis
18
• Public sector plants typically go in for in-house O&M due to significant
experience in plant operations. Historically, few Private sector plants have
awarded O&M contracts. Reasons for this are the higher cost of outsourced
O&M and the easy practice of hiring human resources, experienced in Plant
Operations, from Public sector plants.
• Power Purchase Agreements in India have become fairly standardised
documents. However, certain key clauses with respect to Conditions of
Default, Liquidated Damages, Collateral Arrangements still demonstrate
variance and need to be critically examined
• Fuel Supply Agreements, for both international supply of coal and gas are also
failry standardised. Fuel Linkage Agreements for Indian coal have room for
improvement around clauses likked to quality of coal and it measurement,
testng, etc.
In case of captive coal block development, for the purpose of mine operations
three types of contracting structures are typicall adopted viz. Joint Venture route,
Contract Outsourcing and Owner mining.
19
Glossary
CERC Central Electricity Regulatory Commission
SERC State Electricity Regulatory Commission
MoU Memorandum of Understanding
PPA Power Purchase Agreement
RoE Return on Equity
EA 2003 Electricity Act 2003
UI Unscheduled Interchange
IPP Independent Power Producer
EoI Expression of Interest
NIT Notice Inviting Tender
B-T-G Boiler-Turbine-Generator
T-G Turbine-Generator
EPC Engineering, Procurement and Construction
O&M Operation & Maintenance
CSA Coal Supply Agreement
CIL Coal India Limited
ONGC Oil and Natural Gas Corporation Limited
OIL Oil India Limited
MoP Ministry of Power
MoC Ministry of Coal
CEA Central Electricity Authority
CMPDIL Coal Mining Planning & Designing India Limited
SECL South Eastern Coal Limited
LNG Liquefied Natural Gas
RIL Reliance Industries Limited
PFC Power Finance Corporation
PTC Power Trading Corporation
PGCIL Power Grid Corporation India Limited
20
NVVNL NTPC Vidyut Vyapar Nigam Limited
NTPC National Thermal Power Corporation
MSCMD Million standard cubic meters a day
TCM Trillion cubic meters
MMBTU Million British Thermal Units
KCal Thousand Calories
kg Kilograms
MT Metric Ton
NELP New Exploration Licensing Policy
EGoM Empowered Group of Ministers
PNGRB Petroleum and Natural Gas Regulatory Board
KV Kilo Volt
kWh Kilowatt hour (1 unit)
MU Million units
BU Billion units
KW Kilowatt (1000 watts)
MW Megawatt (1000 KW)
GW Gigawatt (1000 MW)
GoI Government of India
INR Indian Rupee
USD United States Dollar
mn. Million
bn. Billion
Lakh One hundred thousand
Crore Ten Million
GCV Gross Calorific Value
kWh Kilowatt Hour
HT High Tension
21
LT Low Tension
Aux. Con. Auxiliary Consumption
T&D Transmission & Distribution
CoS Cost of Supply
PLF Plant Load Factor
SHR Station Heat Rate
R&M Renovation & Modernization
SEB State Electricity Board
NLDC National Load Despatch Center
RLDC Regional Load Despatch Center
STU State Transmission Utility
CTU Central Transmission Utility
22
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Pune 411 001
Tel: +91 20 305 85764/65
Fax: +91 20 305 85775
Bangalore
Maruthi Info-Tech Centre
11-12/1, Inner Ring Road
Koramangala,
Bangalore 560 071
Tel: +91 80 3980 6000
Fax: +91 80 3980 6999
Chennai
No.10 Mahatma Gandhi Road
Nungambakkam
Chennai 600 034
Tel: +91 44 3914 5000
Fax: +91 44 3914 5999
Hyderabad
II Floor, Merchant Towers
Road No. 4, Banjara Hills
Hyderabad 500 034
Tel: +91 40 2335 0060
Fax: +91 40 2335 0070
Kolkata
Park Plaza, Block F, Floor 6
71 Park Street
Kolkata 700 016
Tel: +91 33 2217 2858
Fax: +91 33 2217 2868
The information contained herein is of a general nature and is not intended to address the circumstances of any particular individual
or entity. Although we endeavor to provide accurate and timely information, there can be no guarantee that such information is
accurate as of the date it is received or that it will continue to be accurate in the future. No one should act on such information
without appropriate professional advice after a thorough examination of the particular situation.
Key Contacts
Pradeep Udhas
Head Markets
Tel: +91 22 3983 6205
Fax: +91 22 3983 6000
e-Mail: [email protected]
Arvind Mahajan
National Industry Director
Infrastructure and Government
Tel: +91 22 3983 6206
Fax: +91 22 3983 6000
e-Mail: [email protected]
Manish Agarwal
Director, Infrastructure Advisory
Tel: +91 22 3983 6229
Fax: +91 22 3983 6000
e-Mail: [email protected]
© 2007 KPMG, an Indian Partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International, a Swiss cooperative. All rights reserved. KPMG and the KPMG logo are registered trademarks of KPMG International, a Swiss cooperative.