KPMG India Electricity Outlook 2008

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)


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?


• 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?


• 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


• 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?


• 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?


• 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


9

6. What are the options for sale of Power?


• 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


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?


• 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


responsibility


responsibility

Washery responsibility


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


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


• 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.


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?


• 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


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



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


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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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


Manish Agarwal

Director, Infrastructure Advisory

Tel: +91 22 3983 6229

Fax: +91 22 3983 6000


© 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.

mailto:[email protected]



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KPMG India Electricity Outlook 2008

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