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CA
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SING
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LYSIN
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IN E
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INDIA
ENERGY BOOK
2012
WORLD ENERGY COUNCILCONSEIL MONDIAL DE L’ÉNERGIE
INDIAN MEMBER COMMITTEE
Contents
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Overview of Indian Energy Sector
Energy Scenarios
1. Indian Coal Sector 1 - 12
2. Indian Gas Sector 13 - 32
3. Indian Oil Sector 31 - 40
4. Indian Nuclear Energy Sector 41 - 52
5. Indian Power Sector 53 - 90
6. Indian Renewable Energy Sector 91 - 110
1. Integrated Energy Policy : A brief with selected data 111 - 122
2. International Energy Outlook 2011 : Selected data 123 - 148
INDIAN COAL SECTOR
R.K. Sachdev Former Advisor (Coal) to Government of IndiaPresident, Coal Preparation Society of India
A well-acclaimed Coal & Energy Expert, Mr. R K Sachdev is a qualified Mining Engineer from the
prestigious Indian School of Mines and a Chartered Engineer. He is credited with vast experience in
coal, mining, energy, environment and policy related fields and many senior positions in the Indian
coal industry and with Government of India. He also served the US Department of Energy-USAID,
India, the World Bank and also the Expenditure Reforms Commission constituted by the
Government of India.
He is the Founder President of Coal Preparation Society of India and a Member of the IOC of the
International Coal Preparation Congress. He is a Fellow of Institution of Engineers (India), Member,
Mining, Geological & Metallurgical Institute, India and Member, Polish Mineral Engineering Society.
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Coal Production, Demand and Supply:India's coal dependence is borne from the fact that 54 % of the total installed electricity generation
thcapacity is coal based and 67% of the capacity planned to be added during the 11 Five year Plan period
(2007-12), is coal based. Furthermore, over 70 % of the electricity generated is from coal based power
plants.
In order to achieve economic growth of 8-9% in terms of GDP, country's total coal demand, even after
allowing for the slippages that have occurred in the current plan period, has been projected to increase
from the present ~ 730 million tons in 2010-11 to ~ 2,000 million tons in 2031-32. Of this, about 75 % of
coal would go to power plants. Given the projected increase in coal requirement, the domestic coal
industry alone can not fully meet the demand. Present demand–supply gap is around 85 million tons and
it is expected to increase gradually to nearly 140 million tons by 2017.
Min ist ry of Coa l has the overa l l
responsibility of determining polices and
strategies in respect of exploration and
development of coal and lignite reserves,
sanctioning of important projects of high
value and for deciding all related issues.
These key functions are exercised through
its Central govt. public sector undertakings,
viz. Coal India limited(CIL), Nevyeli Lignite
Corporation(NLC) limited and Singareni
Collieries Company limited(SCCL), a joint
sector undertaking of Government of
Andhra Pradesh and Government of India
with equity capital in the ratio of 51:49
respectively.
Figure 1 : Coal Demand and Supply2500
2000
1500
1000
500
02006-07 2011-12 2016-17 2021-22 2026-27 2031-32
Demand Supply
Mill
ion
to
ns
Table-1 : Projected Coal Demand (Million Tons)
Sector 2005-06 2006-07 2011-12 2016-17 2021-22 2026-27 2031-32
Electricity (A) 310 341 539 836 1,040 1,340 1,659
Iron & Steel 43 43 69 104 112 120 150
Cement 20 25 32 50 95 125 140
Others 53 51 91 135 143 158 272
Non-elect. (B) 116 119 192 289 350 403 562
Total (A) + (B) 426 460 731 1,125 1,390 1,743 2,221
th• Figures for 2011-12 and 2016-17 are of the Working Group for 11 Five Year Plan's estimate and for
2031-32 are of the Integrated Energy Policy Report. • Figures for intervening years have been extrapolated.
On the domestic production front, Coal India Ltd is the largest contributor accounting for 81 % of
country's coal production. Of the balance, 9.5 % comes from the Singareni Collieries Company Ltd
(jointly owned by the central government and the state government of Andhra Pradesh) and the
remaining comes from privately operated collieries and the captive coal mines. Small mines in the
northeastern state of Meghalaya also add about 6 million tons to the total production. (Table – 2)
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Presently the country imports about 85 million tons of coal. Out of this, about 25 million tons is
metallurgical coking coal for the iron & steel industry. The balance is thermal coal used by power plants
(50%), cement industry (17%) and other industries (33%). Presently, main sources of thermal coal
imports are Indonesia, Australia, New Zealand and South Africa. Canada, Mozambique and the USA are
amongst the emerging supply sources. Present coal handling capacity at the ports is around 85-90
million tons per annum. This has to be augmented to at least 120 million tons per annum in next two thyears. Further it has to be doubled the present capacity by the end of the 12 Five Year Plan period.
Coal Resources:As on April 2011, India's inventory of coal resource was 284 Billion Tons (BT) comprising of: Proven – 113
BT; Indicated – 137 BT and Inferred – 34 BT. n recent past there has been a slant criticism of the reliability
of India's coal resource base. Geological Survey of India (a 160 years old institution) gives the estimate
based on data captured by them plus inputs obtained from various public and private agencies involved
in carrying out coal exploration. It is being claimed that if India's coal resources are re-estimated on
UNFC methodology these would be much lower than the official stated figure. This is a wrong and non-
tenable statement. A mere change in methodology of estimation will not materially change the total
numbers.
I
SCCL 37.71 40.64 44.54 50.00 51.33 51.00 45
Captive 19.29 26.00 30.03 38.00 36.30 43.00 304 (?)
Tata Steel 7.04 7.21 8.95 7.20 7.02 7.00 7
Meghalaya 5.79 5.60 5.96 5.70 6.09 6.00 6
Total 430.85 456.40 493.21 531.90 532.06 554.00 1,026 (?)
*Demand **450.00 **502.00 553 .00 604 .00 630.00 670 (?) 1,125 (?)
Gap 19.15 45.6 59.79 72.10 97.94 116 99 (?)
*Demand given in the table is as originally projected for 11th Plan period. ** Assessed demand including imported coal. # Coal India has lowered their production target for FY 2011-12.
Table - 2: Domestic Coal Production Plan: (million tons)
Entity
X Plan 11th Five Year Plan 12th Plan
2006-07 2007-08 2008-09 2009-10 2010-11 2011-12 2016-17
Actual Projected#
CIL 361.02 379.49 403.73 431.00 431.32 447.00 664
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Only error margin in the present system of estimation
(ISP System) is to the extent that it does not account for
the coal reserves that have been extracted so far. Even
today if the total coal produced in the country in last 110
years is deducted from the total resource it will not
make any material change in the total figure.
(Table–3a & 3b)
Table - 3a : India’s Coal inventory of Gondwana coal (as on 1.4.2011)
State Million tons
Proved Indicated Inferred Total
Andhra Pradesh 9296.85 9728.37 3029.36 22054.58
Assam 0 2.79 0 2.79
Bihar 0 0 160 160
Chhattisgarh 12878.99 32390.38 4010.88 49280.25
Jharkhand 39760.73 32591.56 6583.69 78935.98
Madhya Pradesh 8871.31 12191.72 2062.70 23125.73
Maharashtra 5489.61 3094.29 1949.51 10533.41
Orissa 24491.71 33986.96 10680.21 69158.88
Sikkim 0 58.25 42.98 101.23
Uttar Pradesh 866.05 195.75 0 1061.80
West Bengal 11752.54 13131.69 5070.69 29954.92
Total 113407.79 137371.76 33590.02 284369.57
Source: Ministry of coal
Table - 3b : India’s coal inventory of tertiary coal (as on 1.4.2011)
State Million tons
Proved
Indicated
Inferred
(Exploration)Inferred
(Mapping) Total
Arunachal Pradesh
31.23
40.11
12.89
6.00
90.23
Assam
464.78
42.72
0.50
2.52
510.52
Meghalaya 89.04 16.51 27.58 443.35 576.48 Nagaland
8.76 0
8.60
298.05 315.41
Total 593.81 99.34 49.57 749.92 1492.64
Coal reserves in India
(as on 01.04.2011)
Indicated137 BT
48%
Proven113 BT
40%
Inferred
34 BT12%
Captive Mining Policy:With over 90 % of domestic coal production coming from government controlled mines, the present
institutional structure is a near monopoly. Although the government has allocated over 200 coal blocks
for development by private / public entities out side the government owned coal companies but
progress has not been promising. In order to bring about competition and transparency the
government is working hard in getting an effective regulatory framework in place.
Captive mining policy was introduced in 1993 as an interregnum to full and unrestricted opening of coal
sector to private investment. For various reasons, out of over 200 coal blocks containing coal reserve of
over 50 billion tons and with an aggregate ultimate annual production capacity of ~ 550 million tons,
have not yielded promised coal production. Only some 30 odd mines have commenced production that
contributed merely 36.30 million tons in FY 2010-11 against a target of 104 million tons. This shortfall
has also led to shortfall in the availability of coal in the country. (Table – 4)
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Issues pertaining to captive mining that require immediate resolution and attention of the government
and other stakeholders inter - alia include:
a. Contentious issues to be resolvedb. Facilitating availability of geological datac. Augmentation of exploration effortsd. Expediting land acquisition and resolution of R & R issuese. Forestry, environment and related clearancesf. Getting mining leases etc
Table - 4 : Overall allocation captive Blocks (As on February 2011)
Sector / End use Number of Blocks allocated
Geological Reserve In Billion Tons
I. Power 53 18.92Power - UMMPP 12 4.85II. Commercial mining 39 7.31III. Iron & Steel
4
1.71
Sub Total I + II + III (A) 108 32.79
Power 28 5.01Iron & Steel 61 8.60
Cement 6 0.63 Coal - to - Liquid 2 3.00Others 2 0.39
Sub Total (B) 100 17.63
Grand Total (A + B) 208 50.42
Public sector companies
Private companies
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Institutional setup and Coal Sector Reforms:As a part of further reforming the coal sector, government has since decided to allocate any further coal
blocks through a transparent open bidding system. Presently, government is engaged in consulting all
the stakeholders for framing the rules for introduction of auction based allocation of coal blocks. Issues
pertaining to captive mining that require immediate resolution and attention of the government and
other stakeholders are also being addressed at highest level.
Notwithstanding any of these reasons, if a country's coal demand has to be met, there is no option but to
expedite the development of these blocks which were allotted hoping that the private developers would
be in a better position to deal with various issues and bottlenecks and getting faster output of coal. The
government is reported to be working towards opening up of the coal sector without any restriction on
the marketing of coal. This, however, would happen only after legislative approval, which is likely to take
some more time.
In addition to the captive developers, the public sector coal companies that are contributing > 90 % of
total production also need immediate support in taking measures for increasing coal production from
existing and new mines. The institutional set up and management of the Indian coal industry has been a
subject of debate every now and then. In recent past, the government had set up a committee to study
the coal industry's problems and come out with recommendations with a view to making the coal sector
more self reliant in terms of technical management capability so as to function in a competitive
environment.
This committee has identified the following areas that need to be addressed:
• Speeding up exploration by opening it to private sector• Productivity Improvement & Increasing share of UG Mines• Institutional Capability• Coal Washing & Transportation• Environmental Approval Issues• Climate Change Issues• Governance and Regulation• R&D in Coal Technologies and New Resources
Coal Quality Management:Indian coals by their very nature are high in ash content but low in sulphur content. Power plants
complain of high ash content, inconsistent quality and size. Main reason of this is that over 87% of coal is
produced from mechanized open pit mines where there is a pronounced degree of out of seam dilution.
After a long and protracted debate that lasted for over 30 years 'whether to wash' or 'not to wash’
thermal coal for power plants, the government has decided that all coal supplied to power plants (except
for pit-head stations) should be washed at the mine mouth. Accordingly, Coal India Ltd. has initiated a
mega plan of setting up of some 20 odd coal washeries of an aggregate throughput capacity of over 110
million tons per year on.
These washeries would be set up on 'Build, Operate and Maintain' (B O M) basis and is estimated to cost
CIL~ Rs. 4500 crore or USD 1.0 billion. As a precursor to the recent IPO that helped Coal India to garner
over Rs 15200 crore from its maiden public issue, the company having realized the commercial
importance of 'coal quality' had in its pre-IPO road-shows declared that it would set up adequate
washing facilities to ensure the quality of coal supplies to all consumers. Some end users like power
utilities, iron & steel makers, cement producers are also setting up their captive washing plants to
improve the quality of coal. Going by the foregoing developments one can hope that the contentious
issue of coal quality will be a thing of past in coming 5 to 7 years.
Coal Transport Infrastructure:Hitherto, the development of new coal mines was taking place wherever transport infrastructure for
evacuation of coal and its further transportation to various designated destinations could be managed
without much of a problem. With the increased demand, more and more new and far-flung coalfields
are being taken up for development to meet the increasing demand of coal in the country. Initially such
developments can go along with road transport. But road haulage is not easy due to lack of road
infrastructure of adequate strength. This highlights the need for development of railway facilities for all
such locations. Similarly, for handling and transportation of increasing volumes of imported coal,
integrated port and railway infrastructure has to be established.
Coal and Climate Change:The adverse impact of increased CO emissions from increasing use of coal in thermal power stations 2
and other industries is well known. Climate change issues are being debated globally particularly in the
context of increasing growth rate in countries like India and China where energy supply is heavily coal-
dependent. In this backdrop, adoption of Super Critical steam parameters in Ultra Mega Power Plants
and other plants is definitely a step forward. It is time for the government not to allow any new coal
based power plant with sub critical steam parameters.
Summing Up:To sum up, in a heavily coal dependent economy like India continuously widening demand - supply gap
of coal is a matter of serious concern and steps should be taken for increasing domestic coal production
for long term energy security. Solution inter alia lies in accelerated development of captive coal block
and for this, outstanding issues must be resolved early. A strong domestic coal production and delivery
system would be imperative if the country has to achieve the goal of energy self-sufficiency and long-
term energy security. An independent coal regulator is required to create confidence in the mind of
private investors and to provide them a level playing field. Coal imports are set to increase. This calls for
securing coal prospects abroad and development of port capacity with matching inland transport
infrastructure. To contain carbon emissions, the coal-energy chain has to be clean and environmentally
acceptable. For this, the impact of the increased use of fossil energy sources has to be enjoined in the
policy framework so as to guard against any negative environmental trade-off in future particularly in
the context of global climate change concerns.
*****
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Ministry of coal has issued a strategic plan in February 2011 which seeks to enable the Coal Sector in
the sustainable, efficient and economical exploitation of its coal resources. The strategic plan has
discussed the issues and actions at length. The report has a detailed SWOT analysis; and discussion on
interdepartmental and cross-sectional issues, which gives a very good insight into dynamics of the coal
sector in India. A snapshot of the report is presented here.
STRATEGIC PLAN - MINISTRY OF COAL (Issued : 10th February, 2011)
SWOT Analysis :
(i) Adequate reserves(ii) Huge workforce comprising of expert and highly
skilled man power is available with the coal
companies(iii) Adequate and rising domestic demand for coal.(iv) Coal reserves are available at relatively shallow
depth which can be easily extracted by cost
effective open cast mining methods.
(i) Poor quality of thermal coal available in India -
mostly E and F grade coal. (ii) Inadequate extractable reserves of coking coal.(iii) Low productivity in coal mines operated by CIL.(iv) Coal sector not truly opened up for commercial mining.(v) Lack of adequate infrastructure for speedy
evacuation of coal produced.(vi) Coal reserves are available mostly in the eastern
part of India whereas the demand of coal is
through-out India. This leads to high transportation
cost of coal or higher transmission losses of power
generated at pit-head power plants.(vii) Long time taken in getting the environment and
forest clearance for new coal projects. (viii) Problems in land acquisition and rehabilitation &
re-settlement.(ix) Law and order problem in Eastern coal producing
states.(x) Constraints in exploration of coal - Out of 277 billion
tonnes geological reserves, only 110 billion tonnes
reserves are in “proved category”.(xi) Problems and constraints in under ground mining –
use of old technology labour intensive processes for
mining and safety issues.
(i) A fast growing economy offers a huge domestic
market (with relatively inelastic demand) for
coal.(ii) Bulk of power generation is coal based and likely
to remain so in the foreseeable future.(iii) As other energy sectors viz. oil and gas, power
etc. have been opened up, opening up of coal
sector for private investment will give a big boost
to the sector.(iv) Wide gap between the price of domestic coal
and that in the international market should give
comfort to domestic industry and encourage
higher investment in the sector.
(i) De lays in obtain ing statutory c learances
(environment and forest) and land acquisition cause
delays in the commissioning of new coal project.(ii) Law and order problem in some of the Eastern States
can adversely impact coal production and movement.
(iii) Delay in the development of coal blocks allotted to
new players (both public and private sector) would
place intense pressure on public sector companies.(iv) Opposition from various quarters to the opening up of
coal sector to private sector investment for
commercial mining will impede speedier growth of
the sector.
Strengths Weaknesses
Opportunities Threats
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Inter-Departmental and Cross-functional Issues
1. Ministry of Environment and Forests(I) Increase in the number of exploratory boreholes in forest land to undertake proper resource
assessment for preparation of feasibility reports.(ii) Expediting Forestry and Environmental clearances for coal projects.(iii) Drawing up of standard Terms of Reference (ToR) for opencast and underground mines to
reduce time for Environment Management Plan (EMP) preparation.2. Ministry of Power(i) The imports by power sector consumers to be as planned in terms of quantity and schedule fixed
by Central Electricity Authority.(ii) Unloading constraints at thermal power stations end to be removed. 3. Ministry of Railways(i) To expedite the construction of new railway tracks in the coalfields.(ii) To ensure availability of the requisite number and type of wagons for dispatch of coal to various
consumers.4. State Governments(i) Land acquisition is one of the major problems for expansion of the coal projects or starting of new
coal projects and development of coal blocks. State Governments should play more active role in
this regard.(ii) Law and order situation in many States specially Jharkhand, Chhattisgarh, Orissa and West Bengal
have adversely affected coal mining operations and also increase in illegal mining operations and
have stopped creation of much needed infrastructural facilities like roads, railways, etc. in areas like
Karanpura Coalfields. More active involvement of State Government authorities can only prevent
and eradicate these problems to facilitate continuance of mining operations smoothly.(iii) Considerable delay is taking place to accord approval for prospecting lease, mining lease, land
acquisition, etc. These procedures are under the control of the States. Greater awareness and
appreciation from the State Government machineries are required for hastening the approval
processes for development of new mines and expansion of the existing mines.5. Ministry of Labour
Issues related to Mine safety and contract labour.6. Ministry of Steel
Ministry of Steel has requested to give more stress on exploitation of coking coal reserves, so that
the import of coking coal is reduced. More facilities for washing of coking coal may be set up, so t h a t
the lower grade coking coal extracted from the bottom seams can be used by the steel plants.7. Ministry of Shipping(I) To reduce the detention of railway wagons inside the port.(ii) Exchange yards between ports and railways to be dispensed with.
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Consumption of Raw Coal by Different Industries(Million Metric Tonnes)
* Includes jute, bricks, coal for soft coke, colliery, fertilisers & other industries consumption.
@From 1996-97 and onwards Cotton includes 'Rayon'also
0.00
100.00
200.00
300.00
400.00
500.00
600.00
19
70
-71
19
72
-73
19
74
-75
19
76
-77
19
78
-79
19
80
-81
19
82
-83
19
84
-85
19
86
-87
19
88
-89
19
90
-91
19
92
-93
19
94
-95
19
96
-97
19
98
-99
20
00
-01
20
02
-03
20
04
-05
20
06
-07
20
08
-09
Mill
ion
Tons
Electricity Steel & Washery Cement Others * Paper
Year ElectricitySteel &
WasheryCement Railways Paper
Cotton
@Others * Total
1970-71 13.21 13.53 3.52 15.58 0.27 1.45 23.67 71.23
1973-74 16.64 13.78 3.65 13.92 1 1.78 26.89 77.66
1978-79 24.8 20.26 4.88 12.13 1.72 2.34 34.02 100.15
1979-80 30.03 19.85 3.87 11.36 1.54 1.99 36.89 105.53
1984-85 57.66 25 7.29 9.46 2.83 2.57 36.64 141.45
1989-90 108.32 30.61 9.53 5.8 2.9 2.7 43.564 203.424
1990-91 113.71 30.91 10.43 5.24 2.81 2.58 47.68 213.36
1991-92 126.84 34.03 10.8 5.06 2.67 1.96 50.97 232.33
1996-97 199.62 39.76 10.08 0.14 3.51 1.311 44.199 298.62
2001-02 265.191
30.036
14.847 - 2.775 0.936 35.955 349.74
2002-03 267.9 30.603 16.359 - 2.788 0.721 43.374 361.745
2003-04 279.956 29.671 16.634 - 2.513 0.522 50.109 379.405
2004-05 305.348 34.43 18.097 - 2.612 0.464 46.457 407.408
2005-06 316.486 32.416 18.08 - 2.773 0.288 63.214 433.257
2006-07
331.58
34.9
19.67
-
2.62
0.303
73.251
462.324
2007-08 360.735 39.017 21.351 - 2.642 0.366 78.549 502.66
2008-09 407.49 40.986 21.787 - 2.947 0 64.58 537.79
2009-10 411.06 41.11 21.34 - 3.5 0.270 110.200 587.48
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Foreign Trade in Coal
0
10
20
30
40
50
60
70
80
1970
-71
1973
-74
197
6-7
7
197
9-8
0
1982
-83
1985
-86
1988
-89
199
1-92
199
4-95
199
7-98
2000
-01
2003
-04
200
6-0
7
200
9-1
0
Mil
lio
nTo
ns
Imports Exports
Million Metric Tons
Year Imports Exports Net Imports
(Import - Export)
1970-71 - 0.470 - 0.470
1973-74 - 0.620 - 0.620
1978-79 0.220 0.270 - 0.050
1979-80 0.940 0.090 0.850
1984-85 0.580 0.130 0.450
1989-90 4.410 0.160 4.250
1990-91 4.900 0.100 4.800
1991-92 5.920
0.110
5.810
1996-97 13.177 0.480 12.697
2001-02 20.548 1.903 18.645
2002-03 23.260 1.517 21.743
2003-04 21.683
1.627
20.056
2004-05 26.128 1.374 24.754
2005-06 36.869
1.329
35.540
2006-07 43.080
1.550
41.530
2007-08 49.794 1.627 48.167
2008-09 59.000
1.410
57.590
2009-10 67.744 2.171 65.573
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Wholesale Price Indices of Coal, Coke & Lignite in India
0
50
100
150
200
250
Coal Lignite Coking Coal Non Coking Coal Coke
Ind
ex
20
05
-06
20
06
-07
20
07
-08
20
08
-09
20
09
-10
20
10
-11
Year
Wholesale price index (2004-05=100)
Coal Coking Coal Non Coking Coal Coke Lignite
2005-06 117.6 106.7 102.58 152.7 85.7
2006-07 117.71 106.7 102.52 152.7 88.47
2007-08 121.69 111.37 106.53 155.43 99.13
2008-09 151.26 119 112.7 234.4 140.04
2009-10 156.45 126.8 121.16 234.4 134.85
2010-11 184.6 178.7 166.5 219.3 168.9
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NATURAL GAS SECTORINDIAN
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Ranjan GhoshFormer Executive DirectorGAIL India Limited
Mr. Ranjan Ghosh, Former Executive Director (GAIL Ltd.), with a masters degree in Engineering, has
over 36 years experience in Oil and Gas sector. He was with GAIL Limited for 27 years and successfully
led many of GAIL's prestigious projects across various functions including planning, project
execution and marketing. Major projects included Gas pipeline control, metering and automation
projects, including SCADA and application programs, commissioned gas processing plants & large
number of gas terminals.
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Overview of Indian Gas SectorIn last decade, Indian economy has shown
incredible growth. Steadily and slowly, India is
gaining strategic importance globally owing to the
impressive economic growth pattern and market
attractiveness. After coming out successfully from
the financial crisis, Indian economy is set to
demonstrate robust growth again with the GDP
growth rate of around 8.6 percent for 2010-11.
Estimated GDP growth rate for 2011-12 is expected
to be over 9%. Even as developed economies
grapple with slow economic growth and rising
sovereign risk currently, emerging economies such as China and India are witnessing robust economic
growth and strong demand for clean and economical energy. In the long run, powerful trends continue
to shape the modern energy economy- industrialization, urbanization and motorization.
With growing economy, there will be more energy consumption in the country which will result in
increased share of natural gas in India's energy basket. With a targeted GDP growth rate of over 9 %,
India's energy demand is expected to grow at 5.2 per cent. Currently, India is the world's 5th largest
energy consumer accounting for about 4.1% of the world's total annual energy consumption and moving
fast enough to become the third largest consumer by
2025 after US and China. The current per capita
energy consumption of India is 0.5 toe as compared
to the world average of 1.9 toe, and this indicates a
high potential for energy consumption. Per capita
consumption of India is expected to reach 1.22 toe
by 2030. China and India are two Asian nations which
are expected to show highest energy consumption
growth rate in coming years, owing to rapid
urbanization and consequent high demand.
With the massive rate of urbanization, the demand for energy has grown manifold in the past few years
and will continue to grow in future. Last decade also showed tremendous growth in Indian gas sector and
gas has slowly emerged as a primary source of energy for India along with coal and oil. The demand of
natural gas has sharply increased in the last two decades. In India natural gas was first discovered off
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India GDP Growth Rates
12.010.0
8.06.04.02.00.0
2005-06
2006-07
2007-08
2008-09
2009-10
2010-11
9.5 9.7 9.06.7 7.4
8.6
PRIMARY ENERGY PER CAPITA(kg oil equivalent, 2008; source: BP 2010 and World Bank 2010)
12000
10000
8000
6000
4000
2000
0World
avereage
Norway US Russia NewZealand
Japan Germany China India
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the west coast in 1970s, and today, it constitutes 10% of India's total energy consumption. As per BP
statistical review 2010, the share of natural gas is expected to reach 20% by 2025 from current 10%. As
per the global consulting firm McKinsey, by 2015 Indian gas market is likely to be as large as Japan
which is currently the largest consumer of LNG in Asia region. In its Reference Scenario, the IEA
expects Indian gas demand to increase to 94 billion cubic meters by 2020 and to 132 billion cubic
meters by 2030, driven by the industrial and power generation sectors. This means an annual increase
of 5.4% – one of the highest in the world.
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As a result of the size and growth of the economy, India is expected to play a key role in global energy
markets including natural gas markets. In fact, gas suppliers now will look to India and China to provide
growth instead of other developed markets like USA or Europe. As a result of growth in demand and
supply, Indian gas sector offers large value creation potential across upstream, midstream and
downstream of gas value chain. In the next five years alone, for instance, these opportunities will grow
to a revenue potential of USD 50 billion from USD 25 billion today, with a corresponding growth in
EBIDTA to USD 30 billion from USD 15 billion today.
Current consumption of gas in India is around 166 MMSCMD. Power sector is the anchor customer for
gas sector which consumes almost 37 % of the total supply where as fertilizer sector consumes around
23%. Sector wise consumption of gas in India is given in the table.
Estimated Indian Energy basket - 2025Indian Energy basket - 2009
Oil32%
Coal52%
Gas10%
Hydro5% Nuclear
1%
Oil25%
Gas20%
Hydro2% Nuclear
2%
Coal51%
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Sourcing of gas was primarily
dependent on domestic
sources till date. But due to
the limited supply, customers
are slowly moving towards
importing LNG. Sourcing
scenario of India is as given in
table.
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Both the demand and supply for LNG have grown at a healthy rate over the past decade. The recent
development of shale gas reserves in North America has increased the supply of LNG to the global
market but LNG demand is expected to grow substantially over the next decade driven in particular by
India, China and other emerging markets (Argentina, Brazil, Bangladesh etc.).
Demand for natural gas in India is expected to grow at a very rapid pace. As per the estimate released th thby Ministry of Petroleum and Natural Gas recently for 12 and 13 five year plan, the demand for gas is
expected to increase by a CAGR of 14% during 2011-12, to 2016-17, from 194 MMSCMD to 373
MMSCMD. In 2020, this demand could reach to over 500 MMSCMD.
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As the Indian economy accelerates and moves towards a cleaner energy mix, a number of attractive
growth opportunities are emerging in and around the gas value chain. A few opportunities are city gas
distribution, construction of new LNG regasification terminals, gas based peaking power generation,
completion of national gas grid, development of unconventional gas sources etc. These opportunities
are detailed out in the next chapters.
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Development of National Gas Grid (NGG)NGG is an ambitious blueprint conceived by GoI, aiming to develop a nationwide network of natural
gas to connect the consumers with sources. The government is also planning to boost use of clean fuel
by reaching out to unserviced areas through a national gas highway.
India currently has around 12,000 km of natural gas pipeline. State-owned gas transportation major
GAIL (India) Ltd operates around 8,000 km pipelines and is planning to add another 6,000- 8,000 km in
next few years. Most gas pipelines are currently in the northern and western region, and there is need
to develop networks in southern, eastern and central regions. when compared with some of the more
developed natural gas markets in the world, the network density is still quite low – pipeline length to
country area ratio of 0.003 km/square km as compared to 0.06 for USA, 1.17 for UK, 1.24 for Germany
and 0.02 for Bangladesh. So India has huge opportunities in transmission and developing natural gas
grid.
PETROLEUM AND NATURAL GAS REGULATORY BOARD1ST FLOOR, WORLD TRADE CENTRE, BABAR ROAD, NEW DELHI-110001 FAX No: 23709151
Ph. No: 011-23457700, 011-23457744, 011-23457751www.pngrb.gov.in
PETROLEUM AND NATURAL GAS REGULATORY BOARD LIMITED
GAS PIPELINES IN INDIA
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Development of LNG marketIn the last 20 years, growth of the Indian gas market was steady and with improved infrastructure and
domestic discoveries, price levels have begun to rise gradually. Currently, India has a substantial
demand for gas, estimated to be 350 MMSCMD in 2015 and 480 MMSCMD in 2020. As domestic gas
discoveries are expected to be limited, the demand–supply gap is expected to continue due to non-
availability of cheap gas. Although gas price has changed in the last two decades and is slowly moving
towards market driven price, Indian gas market is still sensitive to price. Though there are some
consumers segments which can afford high priced LNG which include existing fertilizer plants
(naphtha and fuel oil-based), refining (naphtha conversion), power (naphtha switching), CGD and
industrials (fuel oil-based and captive power), future gas demand is likely to be low as new markets
can't be unlocked at current high LNG price. LNG is available both under long term contracts and in
spot market. While the price of LNG imported under term contracts is governed by the SPA (Special
Purchase Agreement) between the LNG seller and the buyer, the spot cargoes are purchased on
mutually agreeable commercial terms. It is important to develop new LNG markets through seeding
with low priced LNG/ domestic gas, develop infrastructure, create demand and make them ready for
absorbing high priced LNG.
Currently, several options are being explored including gas price pooling and gas allocation policy for
power sector which is the biggest consumer of natural gas. The objective of all these initiatives is to
promote the use of LNG in India and make LNG more affordable for new sets of consumers. Gas price
pooling can bring down the effective cost of using LNG for new customers and will help to expand the
natural gas market through bringing new opportunities and new set of players in downstream market.As per the new allocation guidelines, no power plant will be assured gas for its entire capacity.
Domestic linkage will be provided for 60% of the power plant capacity and there will be no distinction
between private and public companies. It was also decided that initial allocation would be done on an
in-principle basis, though the actual drawl of gas would happen only after the developer ties up at
least 85% of the capacity, corresponding to 60% of domestic gas allocated. CEA has been asked to
prepare a list of power plants expected to come during 2012-17 period for the same. So the power
plants which are allocated domestic gas in 2012-17 will have to source 40% of its total requirement in
form of LNG. It may reform the LNG market in India if the reform in power tariff happens. As power
sector is the largest consumer of gas, there will be opportunities to participate in value chain and
supply LNG to the power plants.
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LNG regasification terminalsIndia is pushing hard to increase its domestic gas production to cater its enormous demand. Since the
creation of NELP, eight rounds of bidding have taken place and more than 200 E&P blocks are offered.
NELP - IX bidding is currently in progress. There is consensus that a large portion of the possible
onshore sedimentary basin has been explored. Currently, there is prevailing uncertainty over potential
from the new NELP and CBM blocks. In addition, the government is expected to bring out the New
Open Acreage Licensing policy towards the end of 2011 which could prove to be a discontinuity against
the earlier regime. As the demand is far exceeding supply in India and there are very few new domestic
sources available, in future, additional demand will be catered through LNG (unless any large domestic
discovery will be made) or through transnational pipelines if and when they get constructed. China
and India are likely to account for 74% of LNG import requirement in the non-OECD Asia.
As on date, LNG re-gasification capacity in the country is 12.5 mtpa (10 mtpa at PLL's terminal at Dahej
and 2.5 mtpa at Shell's terminal at Hazira). Capacity of Dahej is expected to reach 13.6 mtpa by 2013-
14 after expansion. The capacity of HLPL Hazira is also likely to be expanded to 5 mtpa in next 3-4 years.
While current capacity at the Dahej
terminal is deployed for importing LNG
from Qatar and short term supplies
from other sources, the Hazira
terminal sources spot cargoes. Beyond
this, PLL is adding another 5 mtpa
terminal at Kochi and RGPPL adding a 5
mtpa terminal at Dabhol. The initial
capacity of Dhabol terminal will be 1.2
mtpa after commissioning without
breakwater facilities. After completion
of breakwater facilities by 2013-14, the
terminal will be in a position to handle
5 mtpa. Kochi terminal is expected to
be in place by 2012 with an initial capacity of 2.5 mtpa which will subsequently increase to 5 mtpa.
In view of huge demand supply of natural gas, there is a substantial potential to import LNG into the
country. For handling LNG volumes, there is an attractive opportunity to set up LNG reagasification
terminals. GSPC-Adani plans to add a 5 mtpa terminal at Mundra, and IOCL plans to add a 5 mtpa
terminal at Ennore in next 4-5 years. PLL is planning to set up another terminal on east coast while as
GAIL is exploring the potential to set up an onshore terminal or FSRU on East Coast.
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City Gas Distribution
• Vehicular segment:
City Gas Distribution has not properly evolved in India, barring a few cities like Delhi and Mumbai.
Most of the current demand is driven by mandated segments and discretionary demand has been low
But CGD is slowly evolving and rapid growth is expected in coming years with more than 250 cities
likely to be targeted. Demand of city gas can be further categorized into the following four segments.
For the vehicular segment, the alternate fuel is diesel and this segment
can afford up to USD 17/ mmbtu of natural gas based on price of diesel, mileage of car and
cost of CNG conversion kit. At CNG cost of INR
35/kg or USD 13.5/mmbtu, this results in
savings of around 20 per cent over the diesel
price. This segment is expected to be 20–25
per cent of total CGD volumes.
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We can expect that, if all
terminals are commissioned
on time, LNG regasification
capacity will reach around 40 –
45 mtpa (around 145 – 160
M M S C M D ) b y 2 0 1 6 - 1 7 .
Beyond 2017, terminals are
being planned at port locations
like Dighi Port, Mumbai,
Paradeep, Vizag, Mangalore,
Cuddalore Port etc. If at least
50% (3 out of 6) of these
terminals materialize, the total
regasification capacity will
reach 60-65 mtpa by 2021-22.
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• C o m m e r c i a l :
•
•
T h e
alternate cost of fuel f o r
commercial segment is very
high owing to the removal of
subsidy. The alternate fuel is
LPG and this segment can
afford up to USD 18/mmbtu.
At CNG cost of INR 35/kg or
USD 13.5/mmbtu, this
results in savings of around
40–50 per cent over the LNG
prices. This segment is
expected to be 15–20 per
cent of total CGD volumes.
Industrial sector is the most
a t t r a c t i v e c o n s u m e r
segment to tap into given
the large anchor load
comprising of 50 per cent of
demand. It can afford up to
USD 16/mmbtu of natural
gas.
The domestic consumer segment can only afford up to USD 12/mmbtu of delivered gas price,
and will have limited potential other than high-density urban consumers, given government
subsidies on LPG, high servicing costs and the corresponding low volume off take.
Demand for CGD is expected to reach around 45-46 MMSCMD by 2016-17 due to addition of new
cities, price advantage of CNG and increased use of PNG in domestic, industrial and commercial th
sectors. As per the estimates released by Planning Commission for 12 five year plan, the growth in gas
demand in the City Gas Distribution (CGD) sector between 2012 and 2017 is projected to be the
highest among all sectors, at a CAGR of 28.8%, from 13 MMSCMD to 46 MMSCMD. Hence, there are
multiple opportunities for the companies to bid and construct CGD networks across India. Though
CGD is capital intensive and needs a longer gestation period, it is lucrative for many gas utility
companies due to high affordability of consumers. As per an independent study done by McKinsey in
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2010, CGD in India has capacity to absorb gas prices ranging from USD 12 to USD 16/mmbtu at crude
prices of USD 90/bbl considering soaring alternative liquid fuel prices. Supply of natural gas makes
economic sense vis-à-vis competing fuels for most of the segments, viz. domestic, industrials,
commercial and vehicular. Industrial and commercial segments are the most attractive consumer
segments given large anchor load and high affordability and comprising 60-70 percent of total CGD
volumes. Vehicular segment is expected to consume 20–25 per cent of total CGD volumes while as
domestic consumer segment will have limited potential other than high-density urban consumers,
given government subsidies on LPG, high servicing costs and the corresponding low volume off take.
There are three key challenges faced by the CGD sector in India - inadequate network infrastructure
available to facilitate proliferation of CGD, inadequate availability of gas for CGD particularly for non-
mandated segments and regulatory uncertainty. But this is changing rapidly with new planned
pipelines coming up to connect new geographical areas, new sources of gas including CBM getting
available and changes in regulations to lay out a growth roadmap for CGD segment. With these
developments, the CGD segment is expected to grow rapidly over the next few years with entry of new
players and expansion of CGD network to new geographical territories.
Power sector is the largest consumer of natural gas in India and has huge potential due to significant
deficit. But gas based power generation is constrained by the ability to pay for a higher fuel expense.
India has the fourth largest coal reserves in the world and has significant hydro potential. Cost of
power generated using coal as fuel is significantly lower compared to other thermal power generation
means. For example, a base-load open cycle gas turbine (OCGT) can compete with coal only if it can get
gas at $5- $6 per mmbtu whereas combine cycle gas turbine (CCGT) can compete at a gas price of $8-
$10 per mmbtu. Peaking power plants can afford higher price of gas on account of higher power tariff.
Similarly, combined cooling, heating and power (CCHP) plants can also afford a slightly higher price for
gas due to increased efficiency. So opportunity lies primarily in decentralized gas based power
generation & peaking power.
Currently India's power demand is around 150 GW. India's peaking power shortfalls are set to intensify
over the next 10 years and are expected to reach more than 70 GW by 2020 from the current peaking
deficit of around 30 GW. A bulk of the peak power deficit can be attributed to five key power deficit
states – Maharashtra, Madhya Pradesh, Uttar Pradesh, Punjab and Haryana. Seasonal peaking deficits
will exist in northern states, whereas demand for daily peaking power would continue to increase
especially in the southern states and major urban centers. Base load power demand will primarily be
met through the thermal coal-based plants, whereas gas and hydro plants are best placed to meet the
peaking power demand. Gas is the energy source to bridge the peaking power gap other than solar
and hydro power given scalability, availability and time to construct. So far, gas-based peaking power
capacity addition has been constrained by domestic gas shortage and absence of peaking power tariff
regulations.
Decentralized gas based power generation & peaking power
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Significant market failures at the state
distribution company level have
prevented significant peaking capacity
from coming up so far. The present tariff
structure does not fully address the
critical dimensions like (a) differentiation
of tariff based on 'value' of the electricity
during a particular time of day, that is,
peak and off-peak periods (b) separate
tariff structure for peaking plants, that is,
separate tariffs for the plants that need
to operate only during peak periods to
meet the peak demand. However, key
foundational regulations have started coming in place. The Rakesh Nath committee report lays the
framework for peaking PPAs to be contracted with the SEBs. The report emphasizes the need for a
differential power tariff based on the availability of plant and value of power during peak period. The
report also advocates tying in time of day tariff at the distribution end with corresponding
differentiation of supply side tariff. In addition to the recommendations by the Rakesh Nath
committee, certain basic frameworks are being set in place – Multi Year Time of Day tariffs (MYToD),
Time of Day (TOD) metering; 23 states have announced MYToD tariffs (15 have notified and 9 have
issued orders).
Increasing demand and lagging supply leads to high prices for both oil and gas, making exploitation
of unconventional gas far more lucrative for producers. Globally, unconventional gas reservoirs are
present in significant number of geological basins. Typical unconventional gas resources are Shale
Gas, Tight Gas, Coal Bed Methane and Gas Hydrates. It is estimated that globally 16,000 trillion
cubic feet of gas is present in shales.
Among various unconventional gas resources; the CBM, tight gas and shale gas are being commercially
exploited in US and Canada, Australia, China etc. in different proportions. India too is making efforts to
keep pace with the CBM industry but the tight gas and shale gas are yet to find a place in the country's
energy basket.
Coal Bed Methane (CBM) offers tremendous potential due to high coal reserves. However, CBM
production has been slow to pick up globally with current production of about 15 MMSCMD coming
primarily from the US. Global production is expected to grow to around 65 MMSCMD by 2015 with
technical challenges being gradually resolved. India has the sixth largest coal reserves in the world
Alternative sources of gas
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with projected CBM reserves of about 92 TCF. The government has developed a policy to encourage
CBM production and 33 blocks have already been offered in four bidding rounds. Five of these have
established reserves of about 8.9 TCF. However, after several years of existence and big promise, CBM
production in India is still 0.1 MMSCMD from 1 block. DGH expects production to grow up to 7.4
MMSCMD by 2015 (RIL: 5.0 MMSCMD, GEECL: 1.5 MMSCMD, ONGC/ Essar: 0.9 MMSCMD). Several
challenges still exist in meeting CBM production targets and increasing production beyond 2015 which
includes technical challenges related to assessment of potential, utilization of produced methane,
inferior grade of coal in India and low production from wells on account of low porosity and
permeability, regulatory challenges related to use delineation of blocks for mining and CBM
exploitation, environmental challenges on account of higher requirement of land and disposal of
water, logistical challenges on account of requirement to drill large number of wells at low cost, big
requirement of fracking and especially off take of gas and political challenges as most prospective coal
mines lie in insurgency affected areas and pose a threat to safe operations.
It has been estimated that
India possesses shale deposits
across the Gangetic plain,
Assam, Gujarat, Rajasthan,
and a few other areas. The
shales in Gondwana & Cambay
b a s i n h a v e b e e n f i e l d
experimented for evaluating
the shale gas potential. Initial
results are found encouraging
and at par with US producing
shales. Hence it has opened
v a s t g e o g r a p h i c a l a n d
stratigraphic frontiers for shale gas exploration.
In India, although the potential of shale oil and gas has been recognized to some extent, not much has
been done. No credible estimates of the actual reserves are available. In this context, Government is
planning to come up with a policy dealing with the exploration and development of shale gas and oil.
On the lines of NELP, interested operators could bid for acreages, promising a work program that
covers both seismic surveys to understand the potential and actual drilling.
Shale Gas
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With the growing demand for natural gas in India and the
fact that existing gas fields are in decline, shale gas could
fill the gap between demand and supply. The recent
Reliance-BP deal shows how Indian firms can partner with
global majors and benefit the Indian energy market. While
the deal was in the exploration and production area at the
outset, BP stated that Indian market has huge potential
and they will look forward to extend their partnership to
gas transmission and marketing as well in future.
Open acreage licensing policy (OALP)After NELP – IX, there are wide speculations that the
government may stop inviting bids for rights to explore oil and gas under New Exploration Licensing
Policy (NELP) terms and replace it with a new exploration policy model called open acreage licensing
policy (OALP). The open acreage model allows domestic and global oil majors to bid for exploration
rights through the year unlike NELP which is an annual event. Also, companies can identify and bid any
offshore or onshore block in the country.
Though OALP is being considered as next stage in India's exploration scenario, there are a few
roadblocks ahead. From past successful OALP examples, it is observed that for being successful, OALP
requires availability of large number of blocks for exploration and production, besides a stable fiscal
regime and, above all, availability of geological data in public domain and prospective details of the
area if not individual blocks. In India, not much data is available for its sedimentary basins. As for
geological data availability, nearly 50% of the total area is poorly explored and India has very little data
of value. India's upstream regulator Directorate General of Hydrocarbon is in the process of setting up
an NDR to collect and preserve valuable data related to the Indian sedimentary basins which will be
used by energy exploration firms in discovering hydrocarbon assets. But these efforts will take
substantial time to materialize.
In recent NELP-IX round, a total of 74 bids were received for 33 blocks out of the 34 blocks on offer. Of
the 15 offshore blocks and 19 onshore blocks, single bids were placed for 10 offshore and 4 onshore
blocks respectively. Despite serious efforts, there are tepid responses from most of the global oil and
gas majors and ONGC emerged as the highest winner winning 10 of these 33 blocks. Even in past NELP
– VIII, most global energy majors stayed away from the bidding process and none of the top five global
majors, namely Exxon, Shell, Chevron, Statoil and Conoco Philips, participated with bids. Many
experts believe that in this stage implementing OALP may unduly help the entrenched PSUs or
promote crony capitalism. So it is likely that the NELP & OALP may co-exist for some time before OALP
is implemented finally.
Regulatory Dimensions
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PNGRB – tariff and pipeline biddingHistorically, gas transportation sector was dominated by single PSU with transportation tariff
determined by the central government. From 1987 to 2005,
transportation tariff was fixed by the Empowered Group of Ministers
(EoGM). Govt. of India decided to develop a policy concerning the
approval of pipeline construction that would be consistent, market-
friendly, and would help avoid duplication of gas transport routes. To
address all the above issues, a board called The Petroleum and Natural
Gas Regulatory Board (PNGRB) was formed under Petroleum and
Natural Gas Regulatory Board Act 2006. The board also has to ensure
adequate and secure supply of the petroleum products throughout
the country at the competitive and regulated prices and act as an
enabler in developing gas infrastructure by providing regulatory
support for the development of the pipeline network. The board
formally came into existence on June 25, 2007 with the objective to
regulate the refining, processing, storage, transportation, distribution, marketing and sale of
petroleum, petroleum products and natural gas excluding production of crude oil and natural gas so as
to protect the interest of consumers and entities engaged in specified activities and to ensure
uninterrupted & adequate supply and to promote competitive markets.
Currently all the entities have to take prior authorization to lay, build, operate or expand any pipeline
as a common carrier or contract carrier by the board. The regulator PNGRB also set up the Access Code
requiring third-party access for one third of the capacity and setting the tariffs of transportation for
third parties. PNGRB has therefore to determine tariffs for existing pipelines as well as for pipelines
authorized by the government (before PNGRB was created). PNGRB has proposed amendments to the
(Determination of Natural Gas Pipeline Tariff) Regulations, 2008, and has invited comments from
stakeholders and experts. These will allow gas transporters like GAIL and Reliance Gas Transportation
Infrastructure to charge a lower rate than that determined by PNGRB or those approved earlier on a
cost-plus basis. The Petroleum & Natural Gas Regulatory Board (PNGRB) also issues regulations for
authorizing entities for developing City or Local Natural Gas Distribution (CGD) Networks; exclusively
for CGD Networks and determination of network tariff of such networks.
Emerging of PNGRB brought reforms and transparency to the natural gas sector. PNGRB always
encourages competition and wants to increase the number of players which is an encouraging trend
for players who want to invest in India.
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Gas Allocation Policy/ Gas Utilization Policy
Rakesh Nath Committee report
Demand for gas in India is higher than the supply. In 2008, GoI came up with a gas allocation policy to
prioritize gas supply to various industries. These guidelines are applicable for five years and shall be
reviewed afterwards. India primarily utilizes natural gas in power generation, fertilizer, city gas,
petrochemicals/ refineries & steel/sponge iron industries. Presently, the allocation of domestic gas is
based on sectoral priorities, gas availability and potential gas markets in particular regions and done
by EGoM. Existing users have priority over Greenfield users. Fertilizer sector has been given highest
priority of gas allocation in India followed by LPG and Petrochemical plants and power. CGD and
refineries are given least priority due to their high price affordability. Priority to power generators and
fertilizer producers make them the major customers of natural gas supplied at the lowest rate
(Administered Pricing Mechanism prices decided by the government) by the state-owned oil and gas
companies.
There are a few drawbacks in allocation policy. Power and fertilizer sector are put on the priority list
whereas other sectors are considered less important by the authorities. But these sectors are often
willing to pay a higher price of domestic gas than power and fertilizer companies, but they are unable
to buy gas because demand exceeds supply. In such scenario, domestically produced gas will not be
able to discover its true market price and also reduce competition. The NELP producers have liberty to
market their own gas but they have to abide by gas allocation policy which reduces their choice of
marketing their gas. In simple words, gas allocation policy effectively took away gas producers' rights
to sell the gas they discovered in the open market.
The recent ruling of the Supreme Court in May 2010 regarding the dispute between RIL (Reliance
Industries Ltd.) and RNRL (Reliance Natural Resources Ltd.), reaffirms the role of the government in
the allocation and pricing of gas.
India is currently facing huge power deficit in peak hours. India's peaking power shortage is estimated
at 18,000 -20,000 MW, or 10-12% of the total installed capacity. As per an independent analysis done
by consultancy firm McKinsey, this gap could widen to 25% by 2017.
A one member taskforce was formed by Central Electricity Regulatory Commission (CERC) in 2009
under Shri Rakesh Nath, former Chairperson, Central Electricity Authority (CEA) and ex-officio
Member, CERC for examining the issues related to tariff structure for generating stations set up for
meeting the peak demand and to suggest measures that could suitably incentivize as also mitigate the
risks to the investors who want to set up power stations for meeting peaking power requirements.
Task Force was also to examine the desirability of permitting differential peak and off-peak tariffs even
for base load power plants to make the sale of costlier peaking power from peaking stations easier.
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Committee made certain recommendation to reduce the peak hour deficit. As per the task force
recommendation, differential tariff for peak hours (6 hours – 2 hours in the morning and 4 hours in the
evening) and off-peak hours for the generating station can be introduced for incentivizing the peaking
power generation. As per the task force, differential tariff may be worked out in such a way that the
value of power generated during peak hours becomes 25% more than the value of power generated
during off-peak hours. The task force strongly supported gas based power plants for peaking power
generation and suggested that for a gas based (existing and new combined cycle) generating station,
recovery of the fixed cost should be linked to achievement of Normative Plant Availability Factor
(NPAF) 90% for peak hours and 63% for off-peak hours respectively and incentive may be linked to
achievement of NPAF beyond 85%. For open cycle GTs/gas reciprocating engines, task force suggested
that they should meet the peaking demand to be located near the metro cities in the vicinity of the
existing or proposed national gas grid. For new open cycle gas based peaking generating station, the
incentive/disincentive for over-achievement/under-achievement by each percentage vis-a-vis NPAF
during peak hours has been suggested as 10% of the peak capacity charge rate. Task force also
suggested higher O&M margins for cyclic power generating stations catering peaking power demand
by provide them additional margin in heat rate norms as well as additional O&M charges to allow for
additional starts and stops.
If these recommendations come into effect, differential tariff for peak and off-peak period will
encourage the State Commissions to go for time of day tariff for end consumers. Time of day tariff at
the distribution end does not make complete sense without the corresponding differentiation of
supply side tariff. All this will also induce demand side management at the consumer end and help the
distribution companies to manage their load better. In future, BAT (Basic Availability Tariff) and BIC
(Basic Incentive Credit) can be modified on a seasonal, time-of-day, or week-end/weekday basis. This
will provide a means to send accurate signals to the generators that reflect the differing needs of the
system. Tariff could also be linked to achievement of Normative Plant Availability Factor (NPAF) for
peak and off-peak periods respectively
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ConclusionIndian natural gas sector offers a range of opportunities for both domestic and global players. But India needs a clear policy and regulatory framework in order to attract investments required in energy sector, not only to sustain a high economic growth, but also to deal with poverty which leaves millions of people without access to energy. The role and powers of the regulators have to be clearly defined. India has opened up to private and foreign companies and these need regulatory stability with minimum intervention from the state. There have been some positive developments in the upstream sector resulting in participation of JV and private companies and leading to some attractive discoveries including that in KG Basin but there are still some policy and pricing issues in NELP which is discouraging wide participation and investment by private companies.
Pricing will determine the balancing point between supply and demand. India remains largely under-explored and major efforts have to be made in this respect to develop additional domestic supplies. Although India is geographically located close to gas rich countries like Iran, Turkmenistan, etc., import of gas from these countries to India through pipelines is yet to become a reality. India has been increasingly importing LNG and is building new regasification terminals to handle additional imports in future.
It is expected that the future gas supplies in the coming five years will be based on two sources: domestic production and LNG supplies.
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OIL SECTORINDIAN
Dr. D.M.Kale, Director General – ONGC Energy Centre, holds a Doctorate Degree in Astrophysics from
prestigious Tata Institute of Fundamental Research. He has more than 30 years of experience in
Reservoir Management of Oil & Gas fields. He began his career in ONGC in developing Numerical
Reservoir Simulators. As a talented Scientist he has conceptualized several schemes for enhanced oil
recovery besides carrying out responsibilities such as heading Exploration Business Group of Eastern
Region and Mumbai Region of ONGC. As Head of COIN, Dr. Kale coordinated all the R&D works in
Institutes of ONGC.He has taken initiative in setting up “ONGC Energy Centre” for Research,
Development & Demonstration of all Alternate forms of energy. He is recipient of the medal of “Peter
the Great” by Russian Academy of Natural Sciences.
DR. D.M. KALE Director GeneralONGC Energy Centre
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Introduction
Production of Crude Oil and petroleum products :
The Ministry of Petroleum & Natural Gas is the nodal ministry responsible for activities relating to
exploration and production of oil and natural gas (including import of Liquefied Natural Gas), refining,
distribution & marketing, import, export and conservation of petroleum products. Following Public
Sector Undertakings and other organizations are under the administrative control of the Ministry of
Petroleum & Natural Gas :
Public Sector organisations Other OrganisationsOil & Natural Gas Corporation Limited Oil Industry Development BoardIndian Oil Corporation Limited Petroleum Safety DirectorateHindustan Petroleum Corporation Limited Oil Industry Safety DirectorateBharat Petroleum Corporation Limited Centre for High TechnologyEngineer India Limited Directorate General of HydrocarbonsBiecco Lawrie & Co. limited Balmer Lawrie Investments Limited
Crude Oil production has been at the level of 33 Million Metric Tonnes (MMT) for some years now.
During the year 2010-11 production of petroleum products from crude oil is 196 MMT. This is an
increase of 5.3% compared to the year 2009-10. During the year 2010-11 consumption of petroleum
products (in terms of domestic sale) was 142 MMT. This shows increase of 2.9% compared to last year.
Petroleum Products
250
200
150
100
50
02001-
022002-
032003-
042004-
052005-
062006-
072007-
082008-
092009-
102010-
11
Crude Oil Production (MMT) Natural Gas Production(BCM)
Petroleum Products Production (MMT) Crude Import (MMT)
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Refining Capacity
Overseas Oil and Gas Operations
During the year 2010-11, domestic refinery production was 196 MMT. Availability of petroleum
products during 2010-11 from domestic refineries and non-refineries was more than the domestic
demand on overall basis demand except for Liquefied Petroleum Gas (LPG). In fact, the country is net
exporter of petroleum products (42 Million Tonnes) and products like Naphtha, Petrol, Diesel and
Aviation Turbine Fuel (ATF) etc.
During the financial year 2010-11, import of crude oil has been 163 MMT valued at Rs. 4559 billion,
against that during 2009-10 at 159 MMT valued at Rs. 3754 billion. This marked an increase of 2.8%
during 2010-11 in quantity terms but increased by 21.45% in value terms. In US$ terms imports have
increased from US$ 79.5 billion to US$ 100 billion from 2009-10 to 2010-11, marking an increase of
25.7%.
New Exploration Licensing Policy (NELP)New Exploration Licensing Policy (NELP) provides an international class fiscal and contract framework
for Exploration and Production of Hydrocarbons. In the first eight rounds of NELP spanning 2000-
2010, Production Sharing Contracts (PSCs) for 235 exploration blocks have been signed. Under NELP,
90 oil and gas discoveries have been made by private/joint venture (JV) companies in 26 blocks. As
exploration activities are progressing, new oil and gas discoveries are likely to come in future.
The largest natural gas discovery in the country has been made in KG deepwater, from where
production has commenced in April, 2009 with initial production of 5 million metric standard cubic
meter per day (MMSCMD). The current natural gas production is in the range of 52-55 MMSCMD.
Investment commitment under NELP is about US$ 11 billion on exploration, against which actual
expenditure so far under NELP is about US$ 8.27 billion. In addition, US$ 7.37 billion investment has
been made on development of discoveries. Thus actual investment made by E&P companies under
NELP is of the order of US$ 15.64 billion.
With a view to accelerate further the pace of exploration, in the Ninth round of NELP (NELP-IX), 34
exploration blocks are on offer.
In order to enhance hydrocarbon securities for the country, the Government has been encouraging
National Oil Companies (NOCs) to aggressively pursue equity oil and gas opportunities overseas.
ONGC Videsh Limited (OVL) is expected to have produced about 8.7 Million Metric Tonnes(MMT) of oil
and equivalent gas during the year 2010-11 from its assets abroad in Sudan, Vietnam, Russia, Syria,
Colombia and Venezuela.
Imports and Exports of Crude Oil & Petroleum Products
Enhancing Hydrocarbon Resource Base
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Conservation of Petroleum Products
Use of alternate fuels
In association with major national industrial associations, Petroleum Conservation Research
Association (PCRA) has initiated steps to approach the Small and Medium Industrial clusters where
energy consumption is substantial and a large scope for its optimization exists. Through interaction,
the areas where Research & Development interventions are sought by the Industrial clusters are
finalized and then necessary action initiated for required R &D and its implementation.
Petroleum Conservation Research Association (PCRA) has been active in undertaking energy
conservation awareness campaigns through the Print, Electronic and Outdoor Media. These
awareness campaigns are coupled with the direct services leading to improvement in efficient energy
utilization across all major sectors of the economy viz. transport, industry, agriculture, domestic and
commercial. For enhancing the effectiveness and reach of PCRA's efforts, linkages have been
developed with the “Bureau of Energy Efficiency” (BEE) and “Confederation of Indian Industry” (CII)
where several joint programmes are planned and implementation.
The Ministry of Petroleum & Natural Gas has set up a Hydrogen Corpus Fund with a corpus of Rs.1
billion with contribution from five major oil companies and Oil Industry Development Board (OIDB)
for supporting Research and Development in various aspects of hydrogen, which could substitute part
of natural gas as transport fuel in future.
IOC (R&D) has set up a Hydrogen-CNG mixture dispensing station at IOC's Company Owned and
Company Operated (COCO) retail outlet at Dwarka, New Delhi in collaboration with MNRE (Ministry of
New & Renewable Energy). A fleet of 3 wheelers operating on 18% HCNG are being fueled from this
station and have completed more than 18,000 Km mileage.
The implementation of H2 blended CNG fuel will depend on the success of demonstration projects
which are likely to be completed in next 2-3 years. The cost of Hydrogen –CNG would depend upon the
cost of hydrogen production, cost of CNG and the ratio in which they are blended.
To encourage production of bio-diesel in the country, the Ministry of Petroleum and Natural Gas has
announced a Bio-diesel Purchase Policy, in October, 2005, which became effective from 1.1.2006.
Under this scheme Oil Marketing Companies will purchase bio-diesel for blending with High Speed
Diesel (HSD) to the extent of 5% at identified purchase centres across the country. The bio-diesel
industry is still at nascent stage of growth and blending has not been set in motion so far.
IOC and its JV companies have taken up Jatropha plantation in MP and Chhattisgarh. Another Limited
Liability Partnership (LLP) Agreement has been signed with a company for Jatropha plantation in UP.
Hydrogen as Auto Fuel
Bio-diesel Purchase Policy
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Ethanol-Blended Petrol (EBP) ProgrammeThe Oil Marketing Companies (OMCs) have been mandated to sell 5% Ethanol Blended Petrol (EBP).
Low availability of Ethanol has made the progress difficult.
In order to ensure the energy security of the country, Government has given in-principle approval for
constructing a Strategic Storage of crude oil of 15 MMT capacity, of which the first phase of 5 Million
Metric Tonne (MMT) has been taken up at three locations, viz. Visakhapatnam (Vizag) (1.33 MMT),
Mangalore(1.5 MMT) and Padur (2.5MMT).
This strategic storage would, in addition to the existing storages of crude oil and petroleum products
with the oil companies, provide an emergency response mechanism in case of short term supply
disruptions. The construction of the proposed strategic facilities is being managed by Indian Strategic
Petroleum Reserves Limited (ISPRL), a special purpose vehicle of the Oil Industry Development Board
(OIDB). The proposed Strategic Crude Oil Storage would be in the underground rock caverns/concrete
structure.
As the crude oil requirement is increasing, a pre-feasibility study of certain locations having potential
of setting up of crude storage has been taken up.
For the current stage of development, the unhindered, affordable supply of oil and gas is a necessary
condition for the economic growth in
India. Western European countries
and Japan immediately after Second
World War had cheap oil available in
plenty for the development and
industrialization. The world was
ignorant about the GHG emissions
and sustainability issues. The broad
contours of finite Earth and therefore
finite fossil fuel resources were
unheard of. Same was the case with
South Korea and Asian tigers
subsequently. The oil consumption of
China also has doubled to 9 million
BOPD in the last decade. The recent
incremental GDP growth rate is highly
sensit ive to oi l consumption
as depicted in the figure 1.
Strategic Storage
Analysis and Conclusion
12
10
8
6
4
2
0
-2
2003
2004
2005
2006
2007
2008
2009
% changeIndia oilconsump.
% GDP - realgrowth rate
INDIA Sensitivity : Change in Oil Consumption & GDP (YOY)
Energy is not a segment of the economy,it is the economy! Figure 1
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India has to heavily depend on the import of oil and also LNG. Therefore, this sector is affected by the
global development in the industry. The oil supply, which has been historically growing with about 3%,
has stagnated since 2005. The oil price shock of $147 per barrel and the economic down turn are
consequence of the immediate limiting oil supply. The oil under ground is far from over. The recent
resource to reserves document of IEA talks about 9 trillion barrels of resources known yet to be
exploited in comparison with just little more than 1 trillion barrels cumulatively produced so far
globally. At the same time the fact remains that the easy to produce and refine cheap oil is over. The
world will have to pay high price for the oil. The more difficult oil will be expensive in terms of required
energy inputs as well. For example at the beginning of the last century, for every barrel invested in oil
exploration and production resulted in hundred barrels. In the MENA region even today the ratio is
very high. But globally, for the additional barrel from deep water or heavy oil or oil from oil sand it is
anywhere from 20 to 4. It is very doubtful whether the world oil production will increase beyond
current level. The production decline rates from the giant, old fields on average are 5% or more. It is
the giant fields which contribute substantial oil production. There are not many giants discovered, not
many virgin fields waiting to be developed are connected. From 1982 in every year, the oil produced
has exceeded oil discovered and lately with huge margin. It is the reduction in the oil consumption of
OECD countries that has enabled growth in consumption in China, India and Middle East as brought
out in figure 2.
“ Shrinking oil supply - contracting economies?”
2000
1500
1000
500
0
-500
-1000
-1500
-2000
-2500
Tho
usa
nd
bar
rels
/ D
ay
OECD
Rest of theWorld
Middle East
India
China
200920082007
Year On Year Consumption
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The recent global events point in the same direction. The major three global events since last April
have sharply brought into focus the limits of oil supply in the years ahead.
The deep water blowout at Macando, in the Gulf of Mexico has demonstrated the risks in the deep
water exploration and the heavy collateral damage to the environment. The Herculean control
operation spanning several months and area of hundreds of square kilometers required huge energy
inputs for planes, helicopters, vessels, boats, oil based chemicals and so on. The additional safety
requirements are definitely going to add the energy cost of the deep water oil in the future.
The second event was political turmoil in the MENA Countries. The event has wiped out 1.5 million
BOPD from the Libya. The revolution in Egypt was consequence of falling oil production in Egypt after
peaking in 1996 and increasing local consumption. The exportable surplus vanished in 2010. The
government had no source to give subsidy on fuel and food. The result was social unrest and
revolution. Depletion of existing fields and increasing oil consumption is happening in all OPEC
countries. The other countries are also susceptible to similar turmoil. As per one projection oil
consumption in Saudi Arabia will increase to 5.5 million BOPD in 2030. Currently it is growing at 5.9%.
The exports have already dipped to 7.5 million BOPD and are expected to plunge to 6.3 million BOPD
by 2015. If the income from exports is to remain same, the oil price demanded by the kingdom in 2030
will be $320 per barrel. To keep the restless populace quite, the only way is subsidies with additional
income from oil. Irrespective of lifting cost the oil prices will continue to rise while exportable surplus
shrinks.
Egypt : Population21% growth since 200080
60
40
20
0
Year 1950 1960 1970 1980 1990 2000 2010
Data : US Census Bureau IDB Graphic : mazamasclence.com
YoY Change
+6%
+2%
-2%
Po
pu
lati
on
(m
illo
ns)
78.9million
Egypt : A Case of Double Exponential Trap?
Egypt : Oil2009 exports decreased by 26%
Consumption
Production
net Exports
net Imports
mill
ion
bar
rels
per
day
Year 1960 1970 1980 1990 2000 2010
-1.0
-0.5
0.0
0.5
1.0
Data : BP statistical Review 2010 Graphic : mazamasclence.com
Figure 3
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The third event was the major earthquake accompanied by unprecedented Tsunami in Japan. This led
to huge loss of property and life. Recovery operations will require huge energy. Further, there was the
biggest nuclear accident at Fukushima where a cluster six nuclear reactors produced 4.7 Giga watts of
electricity. Prime Minister of Japan wants to shut all the 54 plants by next April. If that happens there is
permanent hole of about 50 Giga watts power generation same as to be immediately made up mainly 3
by oil and gas. This will require 1 million BOPD or 300 million M /day of gas. The additional imports of
LNG by Japan have already kicked up the LNG prices by 30% to $15 per MBTU.
In the days when cheap oil was available, similar events namely Valdez oil spill, several regime changes
in the Middle East, and earthquake of Kobe and subsequent reconstruction did not leave any mark on
the energy markets.
The quick development of indigenous resources for India becomes all the more important in the light
of peak oil and the expected decline in the availability of oil in the market even at high costs. However,
more important question is the demand side management. Should Indian economy develop crippling
dependence on the imported commodity like oil whose supply is going to dry up in coming decades? The events in the new millennium on various fronts are taking place at such rapidity, that the previous
forecasts and plans soon become obsolete and unrealistic. It was envisaged that by 2030 India will
consume around 10MBOPD and close to 95% of it will be imported. There is no chance that such
profuse quantities of oil will be available for importing then. Year after year the forecast of oil
production by IEA is moving southwards. In the latest forecast the oil production in 2030 will not
exceed 96 million BOPD and of that substantial production is from fields yet to be developed, which is
a way of saying there will be shortfall. Further, most of this oil production will be energy-wise
expensive. Therefore, may be 5 to 10 % of it will be required as an input to produce the oil and really
not available on the market.
100
80
60
40
20
01990 1995 2000 2005 2010 2015 2020 2025 2030 2035
Unconventional oil
Natural gas liquids
Crude oil fields yetto be found
Crude oil fields yetto be developed
Crude oil currently producing fields
World oil production by type in the New Policies Scenario
Figure 4
MB
/D
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More stress is required on the unconventional oil and gas development. This will help in continuing to
exploit the huge infrastructure available for the conventional oil and gas. In the foreseeable future
hydrocarbon will continue to play a crucial role. Even to maintain oil and gas supply at current level
more and more difficult and unconventional oil from the resources of 9 trillion barrels that IEA lists,
will have to be brought on stream. This additional oil and will generate GHG in their production
process, in addition to GHG contributed by the oil and gas when used. Any carbon sequestration or
other mitigation method will make oil expensive in money and energy terms. That is another
substantial portion of the energy generated will be expended for carbon management. This will
further reduce the energy available for markets.
Production cost curve (not including carbon pricing)
150
140
130
120
110
100
90
80
70
60
50
40
30
20
10
00 1000 2000 3000 4000 5000 6000 7000 8000 9000
Arctic
Other EORCO EOR2
All deepwater
MENAconv. oil
Already produced
Otherconv. oil
Heavy ofbituman
Oilshales
GTL
BTLEt
han
ol
CTL
Bio
Die
sel
Every source beyond 3 trillion barrels is very geographically and geologically specific. Further it
demands specific research and development. CO flooding and other EOR techniques are highly field 2
specific. These require sustained efforts for a long time. There is substantial scope of enhancing
production and mitigating decline from the producing fields by these efforts. Already such efforts are
contributing. Hydro-fracturing and horizontal drilling are two technologies which are responsible for
bringing on stream CBM, shale oil and gas from tight gas reservoirs. There are known heavy oil pools in
western part which are not contributing today. Very careful and detailed geo scientific data collection
and analysis will reduce the risk of shale oil and gas exploration and exploitation. Focus away from the
philosophy of concentrated efforts in expensive deep water exploration as the single pursuit for more
oil and gas, is required. Currently available technologies for CTL require very large scale projects to be
economic. The Bio fuels including ethanol, bio diesel and bio mass gasification are very sensitive
issues. The net energy gains in these sources are very marginal. These methods are attractive from the
environmental point of view that they may contribute very small quantity of GHG , though they are not
carbon neutral.
Figure 5
Pro
du
ctio
n c
ost
(2
00
8 U
S $
)
Available Oil in billion barrels
Competing Fuel Sources
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In the immediate future, there is a scope and prospects in all these areas. However, in long term there
is a need to manage the demand side to cut oil and energy use in general through austerity and be
ready to do without hydrocarbons as the sources dry out, prices sky rocket, energy gains vanish and
prove environmentally untenable.
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NUCLEAR ENERGY SECTOR
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Sudhinder Thakur
Distinguished Scientist & Fellow
Nuclear Power Corporation of India Limited
Mr. Sudhinder Thakur, former Executive Director, NPCIL, with four decades of experience in nuclear
power is Distinguished Scientist & Fellow, NPCIL. He has served as Consular Science with Embassy of
India, France and served NPCIL & UCIL Boards. He has been a consistent contributor to IAEA.
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Nuclear Power Organization The Atomic Energy Commission (AEC), reporting directly to the Prime Minister, is the apex body of the
Government of India for atomic energy. AEC has executive and financial powers and has powers of the
Government of India within the limits of approved budget provision. AEC provides direction on policies
related to atomic energy. The members of AEC include, among others, some eminent scientists &
technocrats, secretaries of different ministries and seniormost officials from the office of the
Prime Minister.
Development and implementation of AEC directions in nuclear power, related nuclear fuel cycle activities
and research & development activities is carried out by various units of Department of Atomic Energy
(DAE). DAE organization is divided into four major sectors, viz. research & development sector, industrial
sector, public sector undertakings and services & support sector. The DAE also provides for the interaction
needed between the production and R&D units. As integrated group of different units, DAE comprises of
five research centres, three industrial organizations, five public sector undertakings and three service
organizations. It has under its aegis two boards for promoting and funding extra-mural research in nuclear
and allied fields, mathematics, and a national institute (deemed university). It also supports seven
institutes engaged in research in basic sciences, astronomy, astrophysics, cancer research and education.
Nuclear Power Corporation of India Ltd (NPCIL), is a 100% Government of India owned, public sector
undertaking of the DAE and is responsible for design, construction, commissioning and operation of
thermal nuclear power plants. The responsibility of fast nuclear power reactors rests with BHAVINI,
another public sector undertaking of the DAE.
Atomic Energy Regulatory Board (AERB) is the national regulatory body having powers to frame safety
policies, lay down safety standards & requirements and powers to monitor & enforce safety provisions in
nuclear and radiation installations and practices. AERB reports to the Atomic Energy Commission. A bill on
constitution of an independent National Regulatory Authority is currently under consideration of the
Government of India.
India has only moderate reserves of Uranium but it is endowed with large reserves of Thorium; in fact
about 1/3rd of the total global reserves are in India. India's indigenous nuclear programme is, therefore,
focused on using the large resource base of Thorium through three-stage nuclear power programme. The
known uranium reserves (Though current exploration shows much higher resource at Thumalapalli mine
in AP) can support a first-stage programme of about 10,000 MW based on Pressurised Heavy Water
Reactors (PHWRs) using natural uranium as fuel and heavy water as moderator and coolant. The energy
potential of natural uranium can be increased to about 300,000 MW in the second stage through Fast
Breeder Reactors (FBRs) which utilize plutonium obtained from the reprocessed spent fuel of the first
stage. Thorium is a fertile element, and needs to be first converted to a fissile material, Uranium-233, in a
reactor. Once a large FBR capacity is in operation thorium can be introduced as blanket, to produce U-233.
Nuclear Power Strategy - Three-Stage Programme
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With the deployment of thorium at third stage reactors using U-233 as fuel, the energy potential for
electricity generation is very large. A Three-Stage nuclear power programme has been envisaged from the
very beginning of nuclear power programme in India to ultimately use Thorium reserves.
The three stages of India's Nuclear Programme are: 1. Natural uranium fuelled Pressurised Heavy Water Reactors.2. Fast Breeder Reactors (FBR) utilizing plutonium based fuel.3. Breeder Reactors for utilization of thorium.
The three stages of the programme have important fuel cycle linkages and have to be gone through
sequentially.
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Table 1 : Nuclear Energy Potential based on domestic resources
Particulars Stage Reserves Thermal Energy Electricity
TWh GW-Yr. GW-Yr. MW
170,000-tIn PHWR I 7,992 913 330 10,000
In FBR II 1,027,616 117,308 42,200 5,00,000
2,25,000-t
In Breeders III 3,783,886 431,950 1,50,000 Very large
Uranium-Metal
Thorium-Metal
Electricity
155000GWe-Year
300 GWe-Year
About 40000 GWe- YearPower potential~530 GWe with 300 GWe using thorium
Stage 3Stage 2Stage 1
Power generation primarily by PHWRBuilding fissile inventory for stage 2
Thorium utilisation forSustainable power programme
Expanding power programme233
Building U inventory
Pu Fueled Fast Breeders
Dep. U
233U
Th
Th
Nat. U
Pu
Pu
233U 233U FueledReactors
U fueled PHWRs
Electricity
Electricity
AHWRPHWR FBTR
Three Stage Indian Nuclear Power Programme incorporates closed fuel cycle and thorium utilisation as a main-stay for sustained growth.
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Role of Nuclear Power in India India is not an energy resource rich country. More than 80% of our hydrocarbons needs are imported and
cover essentially the transportation needs. With about 190,000 MW installed power capacity including
captive capacity, India is fifth largest electricity producer. The generation, other than captive, during the
year 2010-11, has been:
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Generation BUs
Share Y-o-Y Growth%
Coal
535.3 66.0
4.0
Lignite 26.4 3.3 6.6
Gas 97.8 12.1 10.4
Multi fuel 2.5 0.3 70.2
Diesel 3.0 0.4 25.7
Hydro
114.3 14.0 10.0
Nuclear 26.3 3.3 41.0
Imports 6.5 0.7 4.7
Total 811.1 100 5.6
In addition, we have 14550 MW Wind power, 3100 MW small hydro (less than 25 MW unit size), 1045 MW
Bio mass, and 1742 MW bagasse co generation and 600 MW off grid renewable.
The per capita annual consumption of electricity at about 700 units needs to be increased to about 2000
units to provide a reasonable quality of life. India is not energy resource rich nation. The coal, main stay of
electricity generation, availability is also restricted with current production of about 400 million tons. The
coal imports along with need for development of associated infrastructure are rising. Multiplying the
power capacity quickly implies exploitation of all sources including hydro, wind, solar, biomass in addition
to coal, gas and nuclear.
The Integrated Energy Policy released in September 2006 assessed the energy needs very
comprehensively and projected development of all sources. The policy document projects, amongst other
sources, a significant increase in nuclear power capacity to about 63,000 MW by the year 2032.
Nuclear power has a very important role to play in India's future energy. Nuclear power is economically
competitive and therefore can provide large base load generation, while contributing significantly to de
carbonization of the power sector, being devoid of greenhouse gas emissions, with life cycle emissions
comparable with hydro and wind power.
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Current Status of Nuclear Power in IndiaWith commencement of operation of Kaiga-4 (220 MW) in January 2011 a capacity of 4780 MW with
20 nuclear reactors is now in operation.The operating nuclear power plants in India are given in Table-2.
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Total Nuclear Power Plant Capacity : 4780 MW
Plant Unit TypeCapacity
(MW)
Date Of Commercial
Operation
Tarapur Atomic Power Station
Maharashtra (TAPS)
1
BWR
160 October 28, 1969
2
BWR 160 October 28, 1969
3
PHWR 540 August 18, 2006
4
PHWR 540 September 12, 2005
Rajasthan Atomic Power Station
Rajasthan (RAPS)
1
PHWR 100 December 16,1973
2
PHWR
200 April 1,1981
3
PHWR
220 June 1, 2000
4
PHWR 220 December 23, 2000
5 PHWR 220 February 4, 2010
6 PHWR 220 March 31, 2010
Madras Atomic Power Station 1 PHWR 220 January 27,1984
2 PHWR 220 March 21,1986
Kaiga Generating Station
(KGS) Karnataka
1 PHWR 220 November 16, 2000
2
PHWR 220 March 16, 2000
3 PHWR 220 May 6, 2007
4 PHWR 220 January 20, 2011
Narora Atomic Power Station 1 PHWR 220 January 1,1991
2 PHWR 220 July 1,1992
Kakrapar Atomic Power Station 1 PHWR 220 May 6, 1993
2 PHWR 220 September 1,1995
Table 2 : Nuclear Power Plants in Operation
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Performance of Nuclear Power PlantsNPCIL achieved power generation of 26,473 million units - the highest ever, in the year 2010-11. This was
an increase of 41% over the power generation in the previous year. For the current financial year 2011-12,
the power generation up to June 30, 2011 has been 7993 million units. NPCIL's operating reactors MAPS-2
and TAPS-2 recorded continuous operation of more than a year without outage. During the year 2010-11,
thirteen of the twenty operating units achieved availability factor of more than 85%.The overall availability
factor of the full fleet for the year was 89% and capacity factor was 71%. The operating reactors have
registered over 340 reactors-years of safe operation so far. Table-3 gives the data for last few years.
While the availability factors are high some of the reactors have been operated at reduced power levels
consistent with availability of indigenous uranium. The situation has progressively improved, though some
shortfall still exists and all but one PHWRs of 220 MW are operated at 70% of their power rating.
In addition to the 20 operating reactors, 7 reactors units with total capacity of 5300 MW are under
construction as shown in Table-3.
Capacity under Construction
Year
2011-12 (3 months)
2010-11
2009-10
2008-09
2007-08
2006-07
Gross Generation
(MUs)
7993
26473
18831
14927
16956
18880
Capacity Factor (%)
79
71
61
50
53
64
Availability Factor (%)
91
89
92
82
83
85
Table 3: Performance of Nuclear Power Plants
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Both the reactors of Kudankulam Nuclear Power Project-1&2 (2x1000 MW), being set up in technical
collaboration with Russian Federation, have reached an advanced stage of completion with hot runs of
nuclear steam supply system completed in unit 1 August 2011. The second unit is closely following the
first reactor. First pour of concrete has been carried out at KAPP-3&4 in November 2010, and at
RAPP-7&8 in July 2011.
The second stage envisages setting up of Fast Breeder Reactors (FBRs) along with associated
reprocessing and fuel fabrication plants. A large power-generating base is also needed to establish use of
thorium on a large scale in the third stage of the programme. A 40 MWt Fast Breeder Test Reactor (FBTR)
has completed 25 years of operation at Indira Gandhi Centre for Atomic Research (IGCAR), Kalpakkam.
The FBTR has been in operation at 18 MWt with turbo-alternator synchronized to the grid. FBTR has
provided valuable experience with liquid metal Fast Breeder Reactor Technology and the confidence to
embark upon construction of a 500 MW Prototype Fast Breeder Reactor (PFBR). The Bharatiya Nabhikiya
Vidyut Nigam Limited (BHAVINI), a public sector undertaking of the DAE is implementing the India's first
prototype Fast Breeder Reactor (PFBR) project at Kalpakkam, Tamil Nadu. PFBR is a pool type reactor
using mixed oxide of uranium and plutonium as fuel and liquid sodium as coolant. Two more FBRs are
planned at same site. The emphasis for future FBRs is on use of metallic fuels in view of their higher
breeding ratio.
The strategy for large scale deployment of nuclear energy is focused towards utilisation of thorium. The
third stage will be based on the thorium-uranium-233 cycle. Uranium-233 is obtained by irradiation of
thorium in PHWRs and FBRs. India already has small-scale experience over the entire thorium fuel cycle.
An example is the KAMINI reactor in Indira Gandhi Center for Atomic Research (IGCAR), the only
currently operating reactor in the world, which uses U-233 as fuel. This fuel was bred, processed and
fabricated indigenously. Efforts are currently on to enlarge that experience to a bigger scale.
Fast Breeder Reactors
Thorium based reactors
Table 3 : Nuclear Power Plants under Construction Project
Capacity
Expected Commercial Operation
Kudankulam Ato mic Po wer P roject units 1&2
2x1000MW
LWRs
Unit 1 –
2011, Unit 2 –
2012
Fast Breeder Reactor 500 MW 2013
Kakrapar Atom ic Pow er Project un its 7&8
2x700 MW
PHWRs
2015-16
Rajasthan Ato m ic Po w er Pr o ject u n its 7&8
2x700 MW
PHWRs
2016-17
Total Nuclear Capacity under Construction: 5300 MW
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Back End Fuel Cycle
Future Plans
International Nuclear Cooperation
The recycling and optimal utilization of uranium is essential to meet India's current and future energy
security needs. Towards this end, a significant milestone in the country's three-stage nuclear energy
programme has been achieved with the commissioning of the second Power Reactor Reprocessing Plant
by BARC at Tarapur. Work on setting up of an Integrated Nuclear Recycle Plant with facilities for both
reprocessing of spent fuel and waste management have also commenced at Kalpakkam. At the Waste
Immobilisation Plant, Kalpakkam, the trials on second ceramic melter have been started.
The inland sites are considered appropriate for setting up 700 MW PHWRs. The government has approved
green field sites at Gorakhpur (Haryana) and Chutka (Madhya Pradesh) for these reactors. Pre project
activities including land acquisition have been taken up at these sites. More sites are also currently under
consideration by the Government for setting up additional 700 MW PHWRs.
India's Three Stage Nuclear Power Programme will be reaching a capacity of 10000 MW in the near term
based on indigenous uranium, while the technologies for second stage and advanced reactor systems need
more time for development and commercial deployment. The three stages of the programme have
important fuel cycle linkages and need to be executed sequentially. Nuclear Power in India has been by and
large an indigenous effort and developed in isolation of the global developments. This has resulted in 20
reactors but with installed capacity of 4780 MW only.
There was a realization that with 16% of the world's population, having reached an advanced maturity in
nuclear power and have handled nuclear business as a responsible nation, we should not remain isolated.
This resulted, around the year 2000, in discussions on international co-operation in nuclear power. The
discussions started with co-operation in nuclear safety assessment as a first stage and evolved for
commercial exploitation later. These discussions resulted in agreement of the Nuclear Suppliers' Group
(NSG) to have nuclear co-operation in India, safeguard agreement with International Atomic Energy
Agency (IAEA), and nuclear co-operation agreement with many countries including with USA, France and
Russian Federation. In parallel, work also proceeded on the required legislative framework. The essential
framework for setting up of Nuclear Power Reactors with foreign co-operation, import of fuel and other
nuclear equipment / components and also option for the Indian industry to participate in the global
nuclear market has been established. The improvement of plant load factor as a result of availability of
imported uranium, first benefit of international co operation, for reactors under safeguards is clear from
the capacity factors for the year 2010-11.
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Nuclear Cooperation AgreementsCivil nuclear cooperation agreements have been signed with many countries, including, USA, Russia,
France, UK, South Korea, Namibia, Mongolia, Canada and others. The Bilateral Agreements signed during
the year 2010 were as follows:
• Arrangements and Procedures agreed between India and the USA pursuant to Article 6 of their
Agreement for Cooperation Concerning Peaceful Uses of Nuclear Energy.• Joint Declaration by India and the United Kingdom on Civil Nuclear Cooperation.• Agreement between India and the Russian Federation on Cooperation in the Use of Atomic Energy for
Peaceful Purposes.
The Government of India, as a first step, also identified four sites at coastal locations for setting up large
capacity reactors with foreign collaboration. Preliminary discussions with France, Russian Federation,
General Electric Co and Westinghouse were also initiated for setting-up of these reactors. The country is
fully poised to establish a nuclear capacity of 10,000 MW through first set of reactors, based on foreign
collaboration. The sites for these reactors have been approved by the Government. The process of pre
project activities including land acquisition has been initiated. Ministry of Environment & Forests after
evaluation of the Environment Impact Assessment Report and review of proceedings of the public hearing
have accorded environmental clearance in respect of Kudankulam and Jaitapur sites. The terms of
reference in respect of Gujarat and Andhra Pradesh sites for EIA studies have also been approved by
MoE&F. Setting up Light Water Reactors is in addition to the nuclear power reactors belonging to the
indigenous nuclear power programme, which is proceeding as originally envisaged. The setting up of the
reactors based on foreign collaboration is to be seen as an additionality and not at the cost to the
indigenous nuclear power program which will not only be continued but in fact be accelerated.
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80
60
40
20
0
Capacity Factors 2010 - 11
RAP
S-2
RAP
S-4
RAP
S-5
RAP
S-2
RAP
S-1
RAP
S-1
RAP
S-3
RAP
S-2
RAP
S-6
KGS-
4
TAPS
-3
KGS-
3
TAPS
-4
MAP
S-1
KGS-
1
NAP
S-1
NAP
S-2
KGS-
2
MAP
S-2
Rxs with Imported Fuel (IAEA Safeguards) Reactors based on Indigenous fuel
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• Agreement between India and Canada for Cooperation in Peaceful Uses of Nuclear Energy.• Agreement between India and Argentine Republic for Cooperation in the Peaceful Uses of Nuclear
Energy.• Agreement between the French Republic and India, concerning Intellectual Property Rights on the
Development of the Peaceful Uses of Nuclear Energy.• Agreement between India and the French Republic on the Protection of Confidentiality of Technical
data and information relating to Cooperation in the Peaceful Uses of Nuclear Energy.• Road Map for the Serial construction of the Russian Design Nuclear Power Plants in India.• Memorandum of Understanding between DAE and the State Atomic Energy Corporation “ROSATOM”
concerning broader Scientific and Technological co-operation in the field of peaceful uses of nuclear
energy.• Agreement with the European Atomic Energy Community for cooperation in the field of Fusion
Energy Research.
The “Civil Liability for Nuclear Damage Act-2010” has been enacted in September 2010. This act provides
for civil liability for nuclear damage, and prompt compensation to the victims of a nuclear incident through
a no fault liability regime channeling liability to the operator. With a domestic legislation in place, India has
also signed Convention of Supplementary Compensation for nuclear damage (CSC) in October 2010. The
CSC also allows for compensating civil damage occurring within a State's exclusive economic zone,
including loss of tourism or fisheries related income.
Post March 11, 2011 the accident in Japan, the Prime Minister has ordered a review of safety systems at all
the nuclear plants in the country. The Prime Minister informed both Houses of Parliament that India was in
constant touch with the International Atomic Energy Agency (IAEA), the Japanese Atomic Industrial Forum
and the World Association of Nuclear Operators. The Department of Atomic Energy and its agencies,
including the Nuclear Power Corporation of India (NPCIL) have been instructed to undertake an immediate
technical review, he said. He assured the country that its atomic power generators were safe.
stThe Prime Minister took another review on 1 June 2011 with emphasis on disaster management and
safety upgrade to include “beyond design basis accidents”. It is pointed out that in the Generation
3 & 3+ NPPs which India will be setting up with foreign cooperation, beyond design basis accident and
severe accidents are addressed in the design. These NPPs as well as Indian PHWRs will withstand a
Fukushima type of multiple natural disasters with almost no or minimal action in public. However this
needs to be rechecked by thorough review and modifications, if required, will be carried out.
Legislative Framework
Beyond Fukushima
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While the setting up of nuclear power plants is by Government owned companies, large number of
industries, both in private and public sector, have been responsible for manufacturing of the components
for nuclear plants. These companies have acquired expertise in high tech manufacture over the year and
the manufacturing base in India is alive and vibrant. The expertise for manufacture of high pressure
components like reactor vessel or steam generators for light water reactors of 1000 MW and higher is only
marginal and well within reach of the industry. The manufacturing industry is poised to be a hub for global
nuclear needs including services for the nuclear plants.
Surely, for a significant nuclear power programme in future, more players will be needed. The current
thinking is to involve other players and set up nuclear plants jointly as permitted by the Atomic Energy Act.
These players mostly from power/ energy sector, having obtained the experience can set up plants on their
own.
National commitment to Nuclear Power
Nuclear Power in India- An Ongoing Activity
Two important decisions made very promptly are creation of an independent regulatory authority and
bringing a National Regulatory Authority of India Act in Monsoon session and acceptance of an
international review OSART by India. These actions which were swift and decisive indicate the importance
of nuclear safety and commitment of India's for global cooperation in nuclear power.
Unlike many other countries where no nuclear power plants have been set up during last two decades,
nuclear power is an on going activity where new plants have been set up at regular intervals since 1990.
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Reactors under Construction(last 20 years)
70
60
50
40
30
20
10
0
19901991
19921993
19941995
19961997
19981999
20002001
20022003
2004
20052006
20072008
20092010
No
s.
World India
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To Sum upIn conclusion, the nuclear industry in India has made great strides in mastering the technology and has
acquired comprehensive capabilities in the complete fuel cycle. The indigenous programme has been
robust and on course. While the potential of electricity generation is huge, the respective technologies
need time before commercial deployment. International cooperation can make significant contribution in
capacity addition and serve global nuclear markets from the Indian industry. While nuclear power as base
load electricity generation source has significant advantages in terms of economic competitiveness, much
lower infrastructure relative to fossil fuels for fuel transportation, lower fatalities per kilowatthour of
electricity generation, and emission comparable to renewable sources of energy, invisibility of radiation
associated with nuclear power does put fear in the minds of public. This needs a quantum jump in
interaction with public in a transparent manner so as to increase the public acceptance of nuclear power.
At the same time actions of the Government to further enhance the safety need to be implemented by all
stake holders in nuclear power.
RAJASTHAN ATOMIC POWER STATION UNIT - 1 TO 4
(1X100, 1X200 & 2X220) MWe, CHITTORGARH DIST., RAJASTHAN
TARAPUR ATOMIC POWER PROJECT UNIT - 3 & 4
(2X540) MWe, THANE DIST., MAHARASHTRA
NARORA ATOMIC POWER STATION UNIT - 1&2
(2X220) MWe, BULANDSHAHR DIST., UTTAR PRADESH
MADRAS ATOMIC POWER STATION UNIT - 1&2
(2X220) MWe, CHINGLEPUT DIST., TAMILNADU
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Indian Power Sector
V. Raghuraman is a post graduate in Chemical Engineering. He has over 40 years experience in energy
management, energy conservation and industrial engineering, and as a consultant, trainer and chief
executive and primary specialization in combustion, fuel efficiency, in-depth industrial consulting
and training activities in energy conservation, energy management and National Productivity
Council (1966-1992). He pioneered 'energy audit methodology' in India and was involved with Inter-
Ministerial working group on 'Utilization and Conservation of Energy' (1981-1983). He coordinated
200 energy audits for projecting the potential of energy savings in the Indian economy. As Principal
Adviser (Energy) to the Confederation of Indian Industries, he worked with policymakers, Indian
government ministries and other national and international bodies on energy sector issues.
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V. RaghuramanFormer Principal advisor (Energy)Confederation of Indian Industries
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IntroductionElectricity is a concurrent subject in the Constitution of
India. The Ministry of Power is the nodal central ministry
responsible for development of power sector in India.
The main items of work dealt with by the Ministry of
Power are as given below: • General Policy in the electric power sector and
issues relating to energy policy and coordination
thereof.• All matters relating to hydro-electric power
(except small/mini/micro hydel projects of and
below 25 MW capacity) and thermal power and
transmission & distribution system network;• Research, development and technical assistance
relating to hydro-electric and thermal power,
transmission system network and distribution
systems in the States/UTs;• Administration of the Electricity Act, 2003, the
Energy Conservation Act, 2001, the Damodar
Valley Corporation Act, 1948 and Bhakra Beas
Management Board as provided in the Punjab -
Reorganisation Act, 1966.• All matters relating to Central Electricity
Authority, Central Electricity Board and Central
Electricity Regulatory Commission; • Rural Electrification; Power schemes and issues
re lat ing to power supply/ deve lopment
schemes/programmes/ decentral ized and
distributed generation in the States and Union
Territories; • All matters concerning energy conservation
Vision, Mission and Objectives of
Ministry of Power
VisionReliable, adequate and quality power
for all at reasonable prices.
MissionMinistry of Power seeks to achieve its
vision by providing necessary support
and enabling policy framework for
integrated development of power
infrastructure in the country to meet
the requirements of the growing
e c o n o m y a n d t o m e e t t h e
requirements and aspirations of the
people for quality power particularly
of poor households in rural areas.
Objectives• Improving the power availability.• Expanding the Transmission
Network in the country• Universal power access through
implementat ion o f RGGVY
scheme• Reducing AT & C losses though
implementation of R-APDRP
scheme• Enhancing the availability of
trained and skilled manpower for
the power sector
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Public Sector Undertakings and other organizations under the administrative control of the Ministry
Bhakra Beas Management Board (except North Eastern Electric Power Corporation
matters relating to irrigation) LimitedBureau of Energy Efficiency NTPC LimitedCentral Power Research Institute Power Finance Corporation LimitedDamodar Valley Corporation Power Grid Corporation of India LimitedNational Hydroelectric Power Corporation Rural Electrification Corporation Limited
Satluj Jal Vidyut Nigam LimitedLimitedTehri Hydro Development CorporationNational Power Training Institute
Installed Capacity
Figure1 : Sector wise share in installed capacity
0
10
20
30
40
50
60
70
80
90
Central State Private
Sector
%sh
are 1979
2009
2011
Figure 2: Installed Generation Capacity (As on 30-08-2011)
Nuclear
4780 MW
3%
Gas
17706 MW
10%
Diesel
1200 MW
1%
Renewables
20162 MW
11%
Coal 99503 MW
54%
Hydro
38206 MW
21%
The all India installed power generation capacity as on 30.08.2011 was 181558 MW comprising of
118409 MW thermal, 38206 MW hydro, 4780 MW nuclear and 20162 MW R.E.S. Over the years
share of state sector in installed capacity has gone down, whereas the share of central sector and
private sector has increased. In the XII plan, 60% of the capacity is expected to come in private
sector.
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The annual growth in the energy generation during the year has been 5.55% against the CAGR of
5.17% during the period 2001-02 to 2010-11. The target and actually achieved generation 2010-11
is as given below-
Actual Generation: 811.1 BU
Growth in Generation: 5.55 %
Coal67.01%
Lignite3.35%
Gas 11.89%
(liquid fuel)0.41%
Diesel0.49%
Nuclear2.65%
Hydro13.42%
Bhutan Import0.78%
Figure 3 : Fuel wise % share of Energy Generation during 2010-11
Table 1: Electricity generation and growth rate
Category % of
Target
Actual Last Year2009-10
(BU)
Growth
Target (BU)
Actual (BU)
(%)
Coal 556.1 535.3 96.25% 514.7 3.99%
Lignite 27.8 26.4 95.05% 24.8 6.59%
Gas Turbine (gas)
98.7 97.8 99.05% 88.2 10.85%
(liquid fuel) 3.4 2.5 73.61% 8.4 -70.27%
Diesel 4.1 3.0 73.52% 4.0 -25.71%
Sub Total (Thermal)
690.9 664.9 96.24% 640.5 3.81%
Nuclear 22.0 26.3 119.55% 18.6 41.40%
Hydro 111.4 114.3 102.60% 103.9 10.01%
Bhutan Import 6.5 5.6 86.15% 5.4 3.70%
Total 830.8 811.1 97.63% 768.4 5.56%
2010-11
Generation
Target generation: 830.8 BU
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National average PLF and AvailabilityThe average Plant Load Factor (PLF) achieved
during the year 2010-11 was 75.07% as compared
to 77.68% in the previous year. 53 power stations
with an aggregate installed capacity of 53827.5
MW achieved PLF greater than the national
average PLF. Main reasons of low PLF, as compared
to the previous year were mainly increased forced
outage of thermal units, unscheduled/ extended
planned maintenance of some of the thermal units
and forced shut down/ backing down of some
thermal units due to raw water problems, coal
shortages and receipt of poor quality / wet coal and
also due to receipt of lower schedule from the
beneficiary states. During the year 2010-11, one
thermal power station achieved PLF greater than
100%. Dahanu TPS (500 MW) of M/s Reliance
Energy Limited recorded a PLF of 101.00%. During
the year 2010-11, operational availability of
thermal stations has marginally reduced to 84.24 %
as compared to 85.10 % during the previous year. It
was mainly due to increased forced outages of
thermal units.
During the year 2010-11, 19 coal based thermal
power stations with an aggregate installed capacity
of 21995 MW operated above 90% PLF. Of these 19
stations, 10 are NTPC stations and 1 is the Bhilai
TPS, a JV of NTPC and SAIL.
Figure 4: Trend of national average PLF and availability factor of Thermal Stations
57.1
61
60 6
3
64.4
64.7
64.6 67.
3 69
69.
9
72.
27
2.7
74.8
73.6 76
.87
8.6
77.
2
77.
5
75.
1
83.7
28
4.76
85.
05
85.
1
84.
24
50
55
60
65
70
75
80
85
90
95
100
1992
-93
199
4-9
5
1996
-97
1998
-99
20
00-0
1
200
2-0
3
2004
-05
2006
-07
200
8-0
9
201
0-1
1
%
PLF Availability Factor
Power Supply position in 2010-11As reported by the CEA country had deficit of 8.5%
in energy supply and the peak demand deficit was
10.3%. In 2009-10 energy deficit was 11% and peak
demand deficit was 11.9%.
Capacity addition during 2010-11The definitions of commissioning have been changed from the year 2008-09. Earlier “rotation of the
machine” in case of hydro projects and “oil synchronization” in case of thermal projects were treated
as commissioning for declaring capacity addition. However, the new definition now is-
Table 2: Energy / Demand deficit in 2010-11
Region Energy Demand Peak Demand
MU Deficit(%)
(MW) Deficit(%)
Northern 259,426 8.0 37,431 8.9
Western 268,452 13.3 40,798 14.7
Southern 229,853 5.2 33,225 6.3
Eastern 94,515 4.3 14,528 9.9
North Eastern 9,879 8.8 1,913 18.5
All India 862,125 8.5 112,167 10.3
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Hydro projects:
Thermal Projects
Capacity addition in respect of hydro projects would be the date when following
conditions are met:(i) The trial run operation has started.(ii) The unit has achieved full
rated capacity in case of
purely run of river station
and run of river stations with
pondage.(iii) The unit has achieved full
rated capacity or the designed
capacity corresponding to
prevailing reservoir level in
case of storage power stations.
: Commissioning of
the plant can be related to actual
output in the form of generation that
is emerging from plant for auxiliary
consumption and input to the grid
based on its designated fuel and
completion of all plants and
equipments required for fuel
handling and safe operation of the
plant.
The capacity addition target for the year 2010-11 was 21441 MW, out of which a capacity of 12161
MW was commissioned.
Capacity Addition Programme in the XIth PlanCapacity addition of 78,700 MW had been initially proposed for the XI plan. During the midterm
appraisal carried out by the Planning
Commission, the capacity addition
target for the XI plan has been revised to
62374 MW. A capacity of 34463 MW has
been commissioned till 2010-11. In
addition, projects totaling 12,590 MW
are being attempted for commissioning
on best effort basis during the XI plan.
Table 3 : Capacity addition in 2010-11
Schemes Status of Schemes
APRIL 2010 - MARCH 2011 Deviation
Target Achievement (+) / (-)
Thermal Central 6015.00 3740.00 -2275.00
State 6549.20 2581.00 -3968.20
Pvt. 6191.00 4929.50 -1261.50
Total 18755.20 11250.50 -7504.70
Hydro
Central
649.00
320.00 -329.00
State
356.00
178.00 -178.00
Pvt.
461.00
192.00 -269.00
To tal 1466.00
690.00
-776.00
Nuclear
Central
1220.00
220.00
-1000.00
Total
1220.00
220.00
-1000.00
RES @
State
0.00
0.00
0.00 Pvt.
0.00
0.00
0.00
Total
0.00
0.00
0.00
All India
Central
7884.00
4280.00
-3604.00
State
6905.20
2979.00
-3926.20
Pvt.
6652.00
5121.50
-1530.50
Total
21441.20
12160.50
-9280.70
Table 4 :Original Capacity addition target for XI plan (MW)
Source Central State Private Total Share(%)
Hydro 8654 3482 3491 15627 19.9
Thermal 24840 23301 11552 59693 75.8
Nuclear 3380 - - 3380 4.3
Total 36874 26789 15043 78700 100
Share(%) 46.9 34 19.1 100
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A number of corrective steps have been initiated to prevent slippages. These include bulk tendering
of 660 MW and 800 MW units with supercritical technology and mandatory phased indigenous
manufacturing programme, enhancement of manufacturing capacity of equipment by BHEL from
6000 MW to 15000 MW per year and formation of joint venture companies for manufacture of
various power plant equipments. For an effective monitoring of the projects, Ministry of Power has
adopted 3 levels of monitoring as described below-
1. Monitoring by the CEA (Central Electricity Authority): The CEA has a nodal officer associated
with each project and submits a monthly report for review by the chairman CEA. CEA also
holds quarterly review meetings with developers and other stakeholders.2. Monitoring by the Ministry of Power: At the apex level, the XI plan capacity addition
programme is monitored by the PMO, planning commission and Cabinet secretariat.
Quarterly progress reviews of the PSUs and meetings with the leading equipment
manufacturers are organized by the Ministry of Power to monitor the critical milestones
associated with each project.3. Power Project Monitoring Panel (PPMP): PPMP has been set up for monitoring of thermal and
hydro projects targeted for commissioning during the XI plan along with associated
transmission schemes. The PPMP at present comprises of five independent project monitoring
consultants. Each consultant is responsible for submitting progress and exception report of
projects assigned to it. All such reports are
consolidated by the coordinator consultant and
submitted to the Ministry of Power.
The stipulation under section 63 of Electricity Act 2003
has provided impetus to the participation of private
sector in generation and transmission. The private
investors have responded to the policy initiatives very
positively.
Private Sector participation in Power Sector
Table 5 : Capacity Addition in XI plan (MW)
Year
Source - wise Sector - wise
Hydro Thermal Nuclear Total Central State Private Total
2007-08 2423 6620 220 9263 3240 5273 750 9263
2008-09 969 2484 0 3454 750 1821 883 3454
2009-10 39 9106 440 9585 2180 3118 4287 9585
2010-11 690 11250 220 12161 4280 2979 5122 12161
2011-12(Aug'11)
639 5730 0 6369 1660 1289 3420 6369
Total 4760 35190 880 40832 12110 14480 14462 40832
Figure 5 : Sector-wise % share of capacity
addition
0%
20%
40%
60%
80%
100%
20
04
-05
200
5-0
6
200
6-0
7
200
7-0
8
20
08
-09
200
9-1
0
20
10
-11
201
1-1
2(A
ug‘1
1)
Private
State
Central
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Major policy initiatives to streamline the process of project development:To accelerate capacity addition several policy initiatives have been undertaken by Ministry of Power.
Some of the prominent policy initiatives which have boosted the private players' confidence in the
sector are:
• National Electricity Policy.
• Ultra Mega Power Project Policy.
• Mega Power Policy.
• Tariff Policy.
• New Hydro Policy 2008
The Electricity Act, 2003 does away with the requirement of approval /clearance of any authority for
setting up a captive generating plant. The new law (as amended) also ensures non-discriminatory
open access for transmission of electricity generated from a captive generating plant to the
destination of its use, subject to availability of transmission capacity. The surcharge and cross
subsidies are being progressively reduced in a manner as may be specified by the State Regulatory
Commission. Any person setting up a captive power plant can also establish and maintain dedicated
transmission lines.
Under the new Electricity Act, 2003, non-discriminatory open access in transmission and
distribution has been envisaged. The move is intended to encourage competition amongst
generators and distributors and trading in power from surplus to deficit regions.
Section 14 of the Electricity Act, 2003 allows any generator of electricity to distribute electricity in a
rural area without the requirement of any license, subject to compliance with the measures as may
be specified by the Central Electricity Authority under Section 53. Under the provisions of Section 4
of the Act, the Central Government, in consultation with the State Governments, has prepared and
notified a National Policy, facilitating stand alone systems (including those based on renewable
sources of energy and other non-conventional sources of energy) for rural areas.
Automatic approval (RBI route) for 100% foreign equity is permitted in generation, transmission,
and distribution and trading in power sector without any upper ceiling on the quantum of
investment.
Captive power plants
Open access to transmission
Generating company permitted to distribute electricity in rural areas
Automatic approval for FDI
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Setting up of Ultra Mega Power ProjectsThe Government of India had launched an initiative for the development of coal-based Ultra Mega
Power Projects (UMPPs), each with a capacity of 4,000 MW. The objective of the initiative is to
obtain cheaper tariffs utilizing economies of scale and to mitigate the risk relating to tie up of land,
fuel, water and other statutory clearances. The projects are awarded to developers on the basis of
tariff-based competitive bidding. To facilitate tie-up of inputs and clearances, project-specific shell
companies have been set up as wholly owned subsidiaries of the Power Finance Corporation (PFC)
Ltd. These companies undertake preliminary studies and obtain clearances relating to water, land,
fuel and power off take tie-up prior to award of the project.
Originally, nine sites were identified by CEA in various States for the proposed UMPPs. These
included four pithead sites, one each in Chhattisgarh, Jharkhand, Madhya Pradesh and Orissa, and
five coastal sites, one each in Andhra Pradesh, Gujarat, Karnataka, Maharashtra and Tamil Nadu. It is
proposed to set up pithead projects as integrated projects with captive coal mines and for the
coastal projects, usage of imported coal is envisaged. The UMPP projects would help lower the cost
of power to consumers and reduce emissions.
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For the UMPP at Sarguja in Chhatisgarh and Sundargarh in Orissa, RfQ have been issued. For
Tamilnadu UMPP, site at Cheyyur has been finalized with the captive port at Panaiyur. The site for
second UMPP in Andhra Pradesh has been finalized at Nayunipalli Village in Prakasham District. The
sites in the States of Jharkhand, Tamilnadu and Gujarat for their second UMMPPs are being
examined.
Table 6 : Status and plan of allotted Ultra Mega Power Projects
UMPP Mundra SASAN Krishnapatnam Tilaiya
State Gujarat Madhya Pradesh Andhra Pradesh Jharkhand Name of Developer
Coastal Gujarat Power Limited (Tata Power Ltd.)
Sasan Power Limited (Reliance Power Ltd.)
Coastal Andhra Power Limited (Reliance Power Ltd.)
Reliance Power Limited
Levelised Tariff: (Rs/kwh)
2.26 1.19616 2.33 1.77
Date of LOI 28.12.2006 01.08.2007 30.11.2007 12.02.2009
Date of Transfer of SPV to developer
22.04.2007 07.08.2007 29.01.2008 07.08.2009
Date of signing of PPA
23.04.2007 07.08.2007 23.03.2008 07.08.2009
Unit size 800 MW 660 MW 660 MW 660 MW
Unit 1
September, 2011 January, 2013 June, 2013 May, 2015
Unit 2 March, 2012 April, 2013 October, 2013 October, 2015
Unit 3 July, 2012 July, 2013 February, 2014 March, 2016
Unit 4 November, 2012 October, 2013 June, 2014 August, 2016
Unit 5
March, 2013 February, 2014 October, 2014 January, 2017
Unit 6 June, 2014 February, 2015 June, 2017
Other Details
Unit 1 ready for commissioning.
Associated transmission line not completed, likely to be delayed beyond September, 2011
Boiler erection started, TG raft
cast for unit-3, Construction for BOP commenced, contract awarded for major coal mining equipment
Loan document signed. BTG order
placed. Soil investigation for sea water intake system in progress. Leveling of main plant site completed.
Land acquisition in progress. Soil
investigations in progress. EPC contract placed.
Rev
ise
dC
OD
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TransmissionTransmission projects continue to be accorded a high priority in the context of the need to evacuate
power from generating stations to load centres, system strengthening and creation of National Grid.
Table 8 : PROGRESS OF TRANSMISSION LINES PROJECTS (in ckt. Km)
Voltage Level
Sector Programme 2010-11 Including slipped in 2009-10
Achievement
Ckt. km
%
400 KV Central Sector 7261 4718 64.98%
State Sector 2889 2308 79.89%
JV/Private Sector
2365 970 41.01%
Total 12515 7996 63.89% 220kV Central Sector 481 268 55.72%
State Sector 5375 6539 121.66% JV/Private Sector
192 358 186.46%
Total 6048 7165 118.47%
Grand Total
18563
15161 81.67%
Table 7 : Status of transmission sector as in Aug'11
Description Unit Rating Central State JV/Pvt Total Transmission Lines Circuit Km 765 kV 4667 409 5076
400 kV 72571 31641 6387 110599
220 kV 10549 125758 425 136732
Sub-stations MVA 765 kV 4500 4500
400 kV 69100 67652 630 137382
220 kV 5856 201365 1440 208661+/- 500 KV HVDC Lines Circuit Km 500 KV HVDC 5948 1504 1980 9432+/- 500 KV HVDC Converter / BTB Stn. Converter Terminal
MW MW 9500 1700
11200
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Towards formation of National GridThe exploitable energy resources in our country are concentrated in certain pockets. As a result,
some regions do not have adequate natural resources for setting power plants to meet future
requirements whereas others have abundant natural resources. This has necessitated formation
of National Power Grid to transmit power from resource rich areas to deficit areas as well as to
facilitate scheduled/ unscheduled exchange of power. POWERGRID, the Central Transmission
Utility (CTU) is responsible for establishing the requisite transmission capacity in the central sector
to match the generation capacity addition and encourage inter-state/inter-regional exchange of
power to mitigate the situation of surplus/deficit of power in various regions.
Ministry of Power has envisaged the establishment of an integrated National Power Grid in the
country by the year 2012 with an inter-regional power transfer capacity of about 38,650 MW. A
perspective transmission plan has been evolved for strengthening the regional grids and enhance
the interregional power transfer capacity of National Grid with the ultimate objective of
establishment of a strong National Grid to support the generation capacity addition programme of
XI Plan. Inter regional power transfer capacity as at the end of 2010 was 22400 MW.
Table 9 : PROGRESS OF SUBSTATION PROJECTS (in MVA)
Voltage Level
Sector Programme 2010-11 Including slipped in 2009-10
Achievement
MVA
% 400 KV Central Sector 5010 4650 92.81%
State Sector 10320 8690 84.21% JV/Private Sector
630 630 100.00%
Total 15960 13970 87.53%
220kV Central Sector 650 660 101.54%
State Sector 11000 17027 154.79%
JV/Private Sector
126 0 0.00%
Total 11776 17687 150.20%
Grand Total 27736 31657 114.14%
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Private sector participation in transmission
Through tariff based competitive bidding route :
Competitive bidding route under directions of CERC:
Private Sector Participation through Public Private Partnership (JV route):
Tariff Based Competitive Bidding Guidelines for
Transmission Services aim at facilitating competition in the sector through wide participation in
providing transmission services and tariff determination through a process of tariff based
competitive bidding. An Empowered Committee under the Chairmanship of Member, Central
Electricity Regulatory Commission (CERC) was constituted for identifying transmission projects to
be taken up through tariff based competitive bidding route. Six such transmission projects
recommended by the Empowered Committee have been awarded to the successful bidders. These th
schemes are likely to be commissioned during 12 Plan.
Two schemes viz. (i) Western Regional
System Strengthening – II-B at an estimated cost of Rs. 946 crores and (ii) Western Region System
Strengthening – II- C at an estimated cost of Rs. 546 crores in private sector are under
implementation through 100% private participation. These schemes are anticipated to be
commissioned by the end of 2011.
Transmission System
associated with Tala HEP implemented through Joint Venture route (JV between PGCIL and Tata
Power) has already been commissioned successfully in August' 2006. Power Grid Corporation of
India has entered in to JV with following companies to set up transmission lines:
I. JV with Torrent Power AEC Ltd (Torrent Powergrid Co. Ltd.) for implementation of
transmission system for evacuation of power from 1100 MW generation project being
developed by them near Surat in Gujarat. ii. JV with Jaiprakash Hydro Power Ltd (Jaypee Powergrid Ltd.) for implementation of
transmission system for evacuation of power from proposed 1000 MW Karcham- Wangtoo
HEP in Himachal Pradesh being developed by M/S Jaypee Karcham Hydro Corporation Ltd. iii. JV with Reliance Energy Ltd (Parbati Koldam Transmission system Co. Ltd.) for implementation
of part transmission system for evacuation of power from proposed Parbati –II & III (800 MW
and 520 MW of NHPC) and Koldam HEP (800 MW of NTPC) in Himachal Pradesh. iv. JV with Teesta Urja. Ltd (Teesta Valley Power Transmission Ltd.) for implementation of part
transmission system for development of pooling station in Sikkim and transfer of power to a
new pooling station in north West Bengal/Bihar.v. JV with North East Transmission Company Ltd for implementation of evacuation system for
740 MW Pallatana gas based project in Tripuraviz Pallatana – Silchar 400 kV D/C, and Pallatana-
Bongaigaon 400kV D/C line
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Rural Electrification ProgrammeRural electrification has been regarded as a vital programme for the development of rural areas. In
1947, only 1500 villages were electrified in India and per capita consumption was 14 units. The
initial focus was on 'electrification for irrigation' to enhance agricultural produce which was
reflected in the definition of village electrification accepted till 1997 - that "a village was deemed to
be electrified if electricity is being used within its revenue area for any purpose whatsoever". This
definition of village electrification was reviewed in consultation with the State Governments and
State Electricity Boards and following new definition was adopted after 1997:
"A village will be deemed to be electrified if-electricity is used in the inhabited locality within the
revenue boundary of the village for any purpose whatsoever.”
In February, 2004, the definition was made even more encompassing as also target specific. A
village would be declared electrified if :
i. Basic infrastructure such as distribution transformer and distribution lines are provided-in the
inhabited locality as well as the dalit basti/ hamlet where it exists. (For electrification through
Non-conventional Energy Sources a distribution transformer may not be necessary).ii. Electricity is provided to public places like schools, panchayat offices, health centres,
dispensaries, community centres, etc. andiii. The number of households electrified should be at least 10% of the total number of
households in the village.
Government of India from time to time has launched the following programmes for electrification
of rural areas in the country:
Rural Electrification under Minimum Needs Programme (MNP) was started in 5th Five Year Plan
with rural electrification as one of the components of the programme. Under this programme
funds were provided as Central assistance to the states in the form of partly grants and partly loans.
The areas covered under the MNP for the purposes of rural electrification were remote, far flung
and difficult villages with low load potential.
Pradhan Mantri Gramodaya Yojana (PMGY) scheme was implemented from financial
year-2001-02 and State Electricity Boards/ Electricity Departments/Power Utilities were
designated as implementing agencies. Funds under the programme were provided to the states as
Additional Central Assistance.
Kutir Jyoti Scheme was launched in 1988-89 to provide single point light connections to
households of rural families below the poverty line including harijans and adivasi families. The
allocation amongst the States was based on the size of rural population below the poverty line and
level of village electrification in the State, with higher weightage given to States having larger
population of rural poor and low electrification levels.
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Accelerated Rural Electrification Programme (AREP) scheme was introduced in the year 2003-04
under which interest subsidy of 4% was to be provided on loans availed by State Governments/
Power Utilities from Financial Institutions for carrying out rural electrification programme. The
assistance was limited to electrification of un-electrified villages, electrification of hamlets/
dalitbastis/ tribal villages and electrification of households in village through both conventional
and non-conventional sources of energy.
A scheme called Accelerated Electrification of one lakh villages and one crore households was
introduced by Government of India in 2004-05 by merging the interest subsidy Scheme – AREP
(Accelerated Rural Electrification Programme) and Kutir Jyoti Programme. Under this scheme
there was a provision for providing 40% capital subsidy for rural electrification projects and the
balance as loan Assistance on soft terms from REC.
The above rural electrification schemes have either been discontinued or merged with RGGVY. This
Scheme of Rural Electricity Infrastructure and Household Electrification was introduced in April,
2005 for achieving the National Common Minimum Programme objective of providing access to
electricity to all Rural Households. Rural Electrification Corporation (REC) is the nodal agency for
the programme. Under this scheme 90% Capital Subsidy is provided for rural -electrification
infrastructure as given below. Balance 10% is loan assistance on soft terms by REC.
i. Creation of Rural Electricity Distribution Backbone (REDB) with one 33/11 kV (or 66/11 kV)
substation in every block where it does not exist.ii. Creation of Village Electricity Infrastructure (VEl) for electrification of all un-electrified
villages/habitations and provision of distribution transformer(s) of appropriate capacity in
every village/habitation.iii. Decentralized Distributed Generation (DDG) and Supply System from conventional sources for
villages/ habitations where grid supply is not cost effective and where Ministry of New and
Renewable Energy would not be providing electricity through their programme(s).
The scheme also provides for funding of electrification of all un-electrified Below Poverty Line
(BPL) households with 100% capital subsidy.
Capital subsidy of Rs. 280 billion during XI Plan period has been provided at this stage, which
includes a provision of subsidy of Rs. 5.4 billion for DDG.
All the States except Delhi & Goa have signed Agreements under RGGVY. CPSUs are implementing
the scheme in 138 districts. 578 projects have been taken up to electrify 11,7819 un-electrified
villages and to release free connections to 24.6 million BPL households. At the end of September
Rajiv Gandhi Grameen Vidyutikaran Yojana (RGGVY)
Status of Rural Electrification under Rajiv Gandhi Grameen Vidyutikaran Yojana
(RGGVY)
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2011, the cumulative achievement is - electrification of 98,054 un-electrified villages, intensive
electrification of 216,532 already electrified villages and release of connections to 17.26 million
BPL households. Franchisees are in place/operation in 16 States namely, Uttar Pradesh,
Uttarakhand, Karnataka, West Bengal, Assam, Nagaland, Haryana, Orissa, Madhya Pradesh,
Andhra Pradesh, Rajasthan, Bihar, Gujarat, Punjab, Maharashtra and Chhattisgarh covering
1,10,567 villages. Revenue collection and consumer services have improved in the States where
franchisees are in operation. All the 27 States participating in RGGVY have notified constitution of
District Committees to, inter-alia, monitor the implementation of RGGVY & all States have notified
rural areas to take the advantage of the exemptions provided in the Act for setting up
Decentralized Distributed Generation.
Energy Conservation Act in 2001 and establishment of the Bureau of Energy Efficiency, (BEE) under
Ministry of Power, Government of India, on 1st March 2002 paved way for institutionalization of
energy conservation efforts in the country. BEE has initiated a number of energy efficiency
initiatives through a range of measures, including the launch of Energy Conservation Building Code
for large, new commercial buildings; the launch of energy labeling scheme for appliances; the
initiation of process for the development of energy consumption norms for industrial sub sectors
and an annual examination to certify energy auditors and energy managers.
Energy Conservation (Amendment) Act, 2010 'Energy Conservation (Amendment) Act, 2010', notified on 25.08.2010 further strengthens the
provisions for energy efficiency in buildings, appliances and equipments and has set a mechanism
for incentives and penalties to energy intensive industries in lieu of complying with energy
performance targets. With this amendment, there will be one Appellate Tribunal both for the
Electricity Act as well as the Energy Conservation Act.
Schemes for Promoting Energy Efficiency in India during XI PlanBachat Lamp Yojana (BLY) Scheme: The “ Bachat Lamp Yojana” aims at large scale replacement of
incandescent bulbs in households by CFLs. It seeks to provide CFLs to households at the price of an
incandescent bulb by leveraging the Clean Development Machanism (CDM) of the Kyoto Protocol
to recover the cost differential between the market price of the CFLs and the price at which they
are sold to households. The “Bachat Lamp Yojana” is desiged as a public-private partnership
between the Government of India, private sector CFL suppliers and State level Electricity
Distribution Companies (DISCOMs). In order to reduce the transaction costs associated with the
approval of CDM projects, BEE has developed a Programme of Activities (PoA), an umbrella CDM
project, and is registered with the CDM Executive Board on 29th April, 2010. The individual
projects, designed to be in conformity with the umbrella project, would be added to the umbrella
project as and when they are prepared. More than 20 million CFLs have been distributed so far
under the programme.
Energy Conservation
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Standards and Labeling program: Under this program, the end use equipments and appliances are
tested and certified as compliant to energy saving norms and standards by self certification by the
manufacturers and based on their performance, they are given STAR rating, ranging from 1 to 5 in
the increasing order of energy efficiency. The labeling program has been notified for 12 categories
of equipment but has been made mandatory from January 2010 for Frost Free Refrigerators,
Distribution Transformers, Room Air Conditioners and Tubular Fluorescent Lamps
Energy Conservation Building Codes: The Energy Conservation Building Code (ECBC) was
launched on 27th May 2007. BEE has come out with the revised edition of ECBC incorporating the
comments received from stakeholders and organizations like CPWD, MES etc. This code is intended
for new commercial buildings having a connected load of more than 500 kW and has initially been
launched on voluntary basis. In order to ensure administration of ECBC implementation in a
uniform and consistent manner all over the country, the BEE has set up an ECBC Programme
Committee (EPC) by pooling in the expertise of all stake holders, including State Designated
Agencies, Industry etc. This committee facilitates the development of ECBC compliant building
design, credible implementation of a few demonstration projects in the public sector, making
arrangements for evaluation of the progress and outcomes by creating appropriate institutional
mechanism.
With a view to build adequate technical capacity and develop building procedures and tools to
effectively implement ECBC - a panel of 37 ECBC expert architects has been shortlisted. The
shortlisted Architects would act as resource persons and are the Brand Ambassadors for the ECBC.
These expert architects support the implementation of ECBC by providing services to architects
who are designing ECBC compliant buildings.
Energy Efficiency in Existing Buildings: There is a huge potential of energy savings in existing
buildings. Energy Audit studies conducted in several office buildings, hotels and hospitals indicate
energy saving potential of 23% to 46% in end uses such as lighting, cooling, ventilation,
refrigeration etc. The potential is largely untapped, partly due to lack of effective delivery
mechanisms for energy efficiency. Performance Contracting through Energy Service Companies is
an innovative delivery mechanism for overcoming the barriers faced by energy users. The overall
energy efficiency investment market size under ESCO system of performance contract in India has
been estimated by the ADB Study project team at Rs. 140 billon (Rs. 14000 crores) and has the
potential to save about 54 billion units of electricity annually.
In order to create a market pull for Energy Efficiency activities in the commercial buildings, the
Bureau of Energy Efficiency has now developed a Star Rating Programme for office buildings which
is based on actual performance of the building, in terms of specific energy usage (in kWh/ sq
m/year). This Programme would rate office buildings on a 1-5 star scale,with 5- star labeled
buildings being the most energy efficient. Till date, 136 buildings have been found eligible for the
award of label. A scheme for implementation of Energy Conservation Building Code (ECBC) and
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improving energy efficiency in existing buildings has been approved by the government at a total
cost of Rs.139.9 million during the XI Plan period. Targeted avoided capacity addition during XI plan
through this route is 500 MW.
Agricultural (Ag DSM) and Municipal (Mu DSM) Demand Side Management scheme: Ag DSM
promises immense opportunity in reducing the overall power consumption, improving efficiencies
of ground water extraction. Potential savings of 45-50% have been projected by many studies by
mere replacement of inefficient pumps, the overall electricity savings (from 20 million pumps) is
estimated at 62.1 billion units annually. A scheme has been approved at a total cost of Rs. 362.9
million for agricultural DSM. The scheme targets an avoided capacity of 2000 MW during the XI
plan.
Energy Efficiency in Small and Medium Enterprises (SMEs) Scheme: Bureau of Energy Efficiency
(BEE), in consultation with Designated State Agencies, will initiate diagnostic studies in 25 SME
clusters in the country, including a cluster in North East Region, and develop cluster specific energy
efficiency manuals/booklets, and other documents to enhance energy conservation in SMEs. The
scheme seeks to provide comprehensive energy efficiency solutions to 25 SME clusters
Strengthening Institutional Capacity of SDAs Scheme : State Designated Agencies (SDAs) are
statutory bodies set up by states to implement energy conservation measures at state level. The
main emphasis of the scheme is to build capacity necessary to enable them to discharge
regulatory, facilitative and enforcement functions under the Act. 32 States have designated their
agencies so far.
National Certification Examination for Energy Managers and Energy Auditors: National Level
Certification Examination has to be passed to qualify as a Certified Energy Manager and Certified
Energy Auditor, to be appointed or designated by the designated consumers under the Energy
Conservation Act. The country has now 8013 Certified Energy Managers, out of which 5726 are
also qualified as Certified Energy Auditors, from the 10 examinations conducted during the years
2004 to 2010.
National Mission for Enhanced Energy Efficiency (NMEEE) is one of the eight national missions
under the National Action Plan on Climate Change. The mission seeks to upscale the efforts to
create the market for energy efficiency which is estimated to be around Rs.74,000 crores through
creation of a conducive regulatory and policy regime to foster innovative and sustainable business
models to unlock this market. As a result of implementation of this Mission over the next five years,
it is estimated that at the end of this period, about 23 million tons oil equivalent of fuel savings in
coal, gas, and petroleum products will be achieved along with an expected avoided capacity
addition of over 19,000 MW. As a consequence, carbon dioxide emission reduction is estimated to
be 98.55 million tons annually. The mission was has been approved by the Cabinet on 24.06.2010.
Subsequently, amendment of EC Act, 2001 was passed in both Houses of Parliament for successful
implementation of the mission.
National Mission for Enhanced Energy Efficiency (NMEEE)
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Mechanisms under NMEEE-
Implementation and financing of NMEEE
Status of Power Sector Reforms
1. Perform Achieve and Trade (PAT) is a market based mechanism to enhance cost effectiveness
of improvement in energy efficiency in energy-intensive large industries and facilities, through
certification of energy savings that could be traded. Energy efficiency improvement targets will
be set under section 14 of the Energy Conservation Act, 2001 in a manner that reflects fuel
usage and the economic efforts involved. Amendments to the Act for the effective
implementation of the PAT mechanism has been considered and passed in Parliament.2. Market Transformation for Energy Efficiency (MTEE) is a mechanism to accelerate the shift to
energy efficient appliances in designated sectors through innovative measures to make the
products more affordable. The focus is on leveraging international financial instruments,
including CDM to make energy efficient appliances affordable and increase their levels of
penetration.3. Energy Efficiency Financing Platform (EEFP) is an important enabling mechanism which seeks
to enable financing of demand side management programmes in all sectors by capturing future
energy savings. It would help stimulate necessary funding for Energy Service Company (ESCO)
based delivery mechanisms for energy efficiency.4. Framework for Energy Efficient Economic Development (FEEED) mechanism seeks to develop
fiscal instruments and policy measures like the Partial Risk Guarantee Fund (PRGF) and Venture
Capital Fund for Energy Efficiency (VCFEE), Public Procurement of energy efficient goods and
services, Utility based Demand Side Management (DSM), etc.
BEE is the nodal agency for implementation of the mission and Director General, BEE designated as
the Mission Director. In addition, a company named as Energy Efficiency Services Ltd. (EESL), as a
Joint Venture of 4 CPSUs viz. NTPC, PGCIL, REC and PFC has been created to provide
implementation leadership in the market. The enabling financing required to create the
appropriate market conditions to enable investments to the tune of Rs. 74,000 crores to flow in, is
Rs. 435.35 crores. The Cabinet approved the National Mission for Enhanced Energy Efficiency
(NMEEE) with a financial outlay of Rs. 235.35 crores and a budgetary provision for Rs. 108.30 crores
was made for the year 2010-11.
Electricity (Amendment) Act, 2007The Electricity (Amendment) Act, 2007, which came into force w.e.f. 15.6.2007 has amended
certain provisions of the Electricity Act, 2003. The main features of the Amendment Act are:• Central Government, jointly with State Governments, to endeavour to provide access to
electricity to all areas including villages and hamlets through rural electricity infrastructure and
electrification of households.• No license required for sale of electricity from captive units.• Definition of theft expanded to cover use of tampered meters and use for unauthorized
purpose.
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• Theft made explicitly cognizable and non-bailable.• Deletion of the provision for elimination of cross subsidies. The provision for reduction of cross
subsidies would continue.
The provisions of Tariff Policy notified under Section 3 of the Electricity Act, 2003 on 6th January,
2006 regarding mandatory procurement of power by distribution licensees has come into effect
from 6th January, 2011 even for public sector projects. Para 6.4 (1) of Tariff Policy has been amended
on 20.1.2011 fixing a minimum percentage of the total consumption of electricity in the area of a
distribution licensee from solar energy, in accordance with the National Solar Mission strategy.
In compliance with Section 63 of the Electricity Act, 2003, the Central Government on January 19,
2005 had notified guidelines for procurement of power by Distribution Licensees through
competitive bidding. On March 31, 2006, Central Government has also issued the Standard Bidding
Documents for Case-2 containing Request For Qualification (RFQ), Request For Proposal (RFP) and
model Power Purchase Agreement (PPA) for long term procurement of power from projects having
specified site and location through tariff based competitive bidding. SBD (standard bidding
document) for Case-2 has been amended on 12.03.2010. The Central Government has also issued
Standard Bidding Document for Case-1 on April 2, 2009, where the location, technology, or fuel is not
specified by the procurer and amended on 21.7.2010 after consultation with stakeholders.
Open access is one of the key features of Electricity Act, 2003 for making the electricity industry
competitive. Open access in inter-State transmission is fully operational. To give a fresh impetus to
implementation of open access over transmission lines of State Utilities and over the distribution
networks, discussions have been held at senior most levels. It has been resolved that non-
discriminatory open access in intra-State transmission and distribution system would be provided in
letter and spirit as per the provisions of the Electricity act and the National Policies.
CERC has issued guidelines for setting up power exchanges. Two Power Exchanges i.e. Indian Energy
Exchange and Power Exchange India Ltd. are functional. In principle approval has been given by CERC
to National Power Exchange Ltd. but it is yet to become operational.
Before enactment of the Electricity Act, 2003, various States had enacted State Electricity Reforms
Acts, which provided for reorganization of their State Electricity Boards (SEB). Section 172 (a) of the
Electricity Act, 2003 provides that the SEB shall be deemed to be the State Transmission Utility (STU)
and a licensee under the provisions of the Act for a period of one year from the appointed date, i.e.
10th June, 2003. However a SEB can continue for some more time as agreed to mutually by State and
Central Government. So far, 18 states have reorganized their SEBs and three States (Bihar, Jharkhand
and Kerala) have requested for extension of time for reorganization of their respective SEBs.
Tariff Policy
Guidelines for Procurement of Electricity
Operationalisation of open access:
Power exchanges
Reorganisation of the State Electricity Boards
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Distribution Reforms
Accelerated Power Development and Reforms Programme
Investment component-
Incentive component-
The Ministry of Power has taken various initiatives towards reforms and other policy measures for
helping the state power Utilities bring improvement in their efficiency towards bringing about
commercial viability in the power sector. Some of the major initiatives are establishment of
regulatory mechanism at central and state level, restructuring of the state power Utilities,
metering of feeders & consumers, energy accounting & auditing, securitization of outstanding
dues of CPSUs. 20 SEBs / Electricity Departments have been unbundled & corporatised.
The Accelerated Power Development Reforms Programme (APDRP) was launched in 2002-03 for
implementation in 10th Plan as additional central assistance to the states for strengthening and
up-gradation of sub-transmission and distribution systems of high-density load centres like towns
and industrial areas. The main objectives of the programme were to reduce AT&C loss, reduction of
commercial loss and improve quality and reliability of supply. Revised APDRP (RADRP) has since
been launched, which is covered subsequently. Here we describe the original provisions in the
APDRP. The Programme had two components: investment component and incentive component.
Central Government provided assistance to the tune of 25% and 90% of
the project cost in the form of grant to Non-special category and Special Category states
respectively. Balance amount had to be arranged from financial institutions / own resources.
Earlier, Government was providing 10% loan to special category and 25% to Non-special category
states in addition to the grant as mentioned above. However, as recommended by the 12th
Finance Commission, the loan component was discontinued by the Ministry of Finance w.e.f. 2005-
06. Funds were released by Ministry of Finance, Government of India under the advice from
Ministry of Power in three installments progressively based on implementation progress.
This component was designed to incentivize the SEBs / utilities to reduce
their financial losses. Funds were to be released to the SEBs for actual cash loss reduction, for every
Rs.2 of cash loss reduction Rs.1 was to be given as grant. The cash losses were calculated net of
subsidy and receivables. The year 2000-01 had been adopted as the base year for the purpose.The AT&C loss loss came down in towns where APDRP was implemented. Some of the utilities
which adopted various interventions as envisaged under the programme showed significant
reduction in AT&C loss. AT&C losses were brought down below 20% in 215 APDRP towns in the
country, of which 163 towns were brought below 15%.
The billing efficiency at national level improved from 68.37% during 2002-03 to 71.04% during
2006-07. The national average collection efficiency also improved from 92.68% during 2002-03 to
94.20% during 2006-07. With this improvement in billing and collection efficiency, the national
average AT&C loss of the distribution companies reduced from 36.63% to 33.07%. The overall
commercial loss (without subsidy) of the utilities reduced from Rs. 293.31 billion during 2001-02 to
Rs. 274.46 billion during 2006-07.
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RE-STRUCTURED APDRP
Part A:
Part B:
Part C:
Cabinet Committee on Economic Affairs (CCEA) approved the “Re-structured APDRP" for XI Plan as a
Central Sector Scheme on 31.07.2008. The focus of the re-structured programme is on actual,
demonstrable performance in terms of AT&C loss reduction. Projects under the scheme are to be
taken up in two parts in urban areas-towns and cities with population of more than 30,000 (10,000 in
case of special category states). Projects execution under the scheme is to be taken up as given
below-
It shall include the projects for establishment of baseline data and IT applications for energy
accounting/auditing & IT based consumer service centers. It shall cover preparation of base-line data
for the project area covering Consumer Indexing, GIS Mapping, Metering of Distribution
Transformers and Feeders, and Automatic Data Logging for all Distribution Transformers and
Feeders.SCADA / DMS system shall be included for big cities only. It would also include Asset
Mapping of the entire distribution network at and below the 11kV transformers and include the
Distribution Transformers and Feeders, Low Tension lines, poles and other distribution network
equipment. It will also include adoption of IT applications for meter reading, billing & collection,
energy accounting & auditing, redressal of consumer grievances, establishment of IT enabled
consumer service centers etc. The base line data shall be verified by an independent agency
appointed by the Ministry of Power. Expected investment in Part-A (Baseline System) shall be Rs. 100
billion. Initially 100% funds for part A shall be provided through loan from the Govt. of India. The
entire amount of loan for Part-A projects shall be converted into grant once the establishment of the
required Base-line data system is achieved and verified by an independent agency appointed by
MoP.
It shall cover regular distribution strengthening projects, which will include, renovation,
modernization and strengthening of 11 kV level substations, transformers/transformer centers, re-
conductoring of lines at 11kV level and below, Load Bifurcation, Load Balancing, HVDS, installation of
capacitor banks and mobile service centers etc. In exceptional cases, where subtransmission system
is weak, strengthening at 33 kV or 66 kV levels may also be considered. Expected investment in Part-B
shall be Rs. 400 billion. In case of Part-B, 25% (90% for special category states) funds shall be provided
through loan from the Govt. of India. The balance funds for Part B projects shall be raised from
financial institutions. Up to 50% (90% for special category States) of the project cost of Part-B
projects shall be converted into grant in five equal installments on achieving the 15% AT&C loss in the
project area on a sustainable basis for a period of five years. In addition, utility level loss reduction
(AT&C losses) @ 3% per annum for utilities with baseline loss levels exceeding 30% and @ 1.5% for
utilities with baseline loss levels less than 30% have to be achieved.
Part C of the programme is an enabling component for the implementation of APDRP.
Provision of Rs 11.77 billion has been provided in the scheme. This part is to be implemented by
Ministry of Power / Nodal Agency. PFC has been appointed as nodal agency for operationalising the
programme. The activities included in Part-C are-
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1. Preparation of a template for System Requirement Specifications2. Validation of the Base-line data3. Appointment of project advisors and project management consultants4. Appointment of a panel of project evaluators for project evaluation5. Capacity building and development of franchisees in distribution sector6. Carrying out consumer attitude survey
Under Part D of the scheme, there is provision for incentive for utility staff in towns where
AT&C loss levels are brought below the base line levels. An amount equivalent to 2% of the grant
for Part-B projects (Rs 4 billion) is proposed as incentive of utility staff in project areas where AT&C
loss levels are brought below 15%.
A Steering Committee under Secretary (Power) comprising of representatives of Ministry of
Finance, Planning Commission, Central Electricity Authority, Power Finance Corporation, Rural
Electrification Corporation, selected State Governments (on one year rotation basis) and of
Ministry of Power has been constituted. The Steering Committee will –a) Sanction projects, including modification or revision of estimates; Monitor and review the
implementation of the Scheme;b) Approve the guidelines for operationalisation of various components of the schem including
the approval of the charges to be paid to the nodal agency;
1401 projects have been approved for 29 states under Part-A at the cost of Rs 56.49 billion. Under
part-B, 775 projects worth Rs. 148.54 billion were sanctioned. Budget allocation for 2010-11 was
Rs. 25.71 billion (Rs. 24.71 billion as loan and Rs. 1 billion as grant).
Central Electricity Regulatory Commission (CERC)CERC is an independent statutory body with quasi-judicial powers. It was constituted on 25th July,
1998 under the Electricity Regulatory Commission's Act, 1998 and has been continued under
Electricity Act, 2003. The Commission consists of a Chairperson and four other Members including
the Chairperson, CEA as the Ex-officio Member.
The functions of CERC include-• Tariff regulation – regulation of tariff of
� Generating companies owned or controlled by the Central Government
Part D:
Implementation of Re- Structured APDRP
Status of Re- Structured APDRP
Regulation
c) Approve and sanction activities to be taken up by the Ministry under Part C of the Scheme;d) Appoint agencies for verification and validation of base-line data systems, for verifying the
fulfillment of programme conditions by utilities;e) Approve conversion of loan into grant upon fulfillment of the necessary conditions.
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� Other generating companies having a composite scheme for generating and sale of
electricity in more than one State� Inter-state transmission of electricity� Regulation of inter-State transmission of electricity;� Granting licence for inter-state transmission and inter- State trading in electricity;� Adjudication of disputes;� Specifying Grid Code� Specifying and enforcing the standards with respect to quality, continuity and reliability of
service by licensees;� Fixing trading margin in the inter-State trading of electricity, if considered, necessary;
The Commission also has advisory functions on-(i) Formulation of National Electricity Policy and Tariff Policy;(ii) Promotion of competition, efficiency and economy in the activities of the electricity industry;(iii) Promotion of investment in electricity industry;(iv) Any other mater referred to the Central Commission by the Central Government.
The Commission has issued the Tariff Regulations for generation and transmission projects for the
period 2009-14. These regulations would also be the guiding principles for the State Electricity
Regulatory Commissions. The regulations aim at attracting much desired investment in power
infrastructure in the country while ensuring that the consumers get electricity at reasonable cost.
Base rate for allowing return on equity has been raised from 14% to 15.5% to attract investment.
Additional 0.5% is given for timely completion of projects. Base rate is grossed up by applicable tax
rate for the company. Target availability for recovery of fixed cost for thermal plants raised from 80%
to 85%. Station heat rate has been tightened for existing stations and for new stations, a new
methodology has been adopted with operating margin of 6.5% with respect to design heat rate.
Norms for secondary fuel oil consumption has been reduced from 2 ml per unit to 1 ml per unit.
Incentive has been linked to availability to incentivise higher availability (instead of plant load factor)
of power plants.
The main objectives of the restructuring of UI regime are to enforce grid discipline and to rationalize
the UI rates for the entities who abide by the specified grid operation parameters. Simultaneously,
operational frequency range has been narrowed down with the objective of improving the quality of
supply. Sending a clear message that UI is not a route for trading of electricity, CERC has for the first
time specified limits for the overdrawal from the grid within the permissible operating range. This is
in accordance with the philosophy that main purposes of UI are enforcing grid discipline and
providing for settlement rates for unintended UI Interchanges.
Some recent Regulations
Tariff Regulations, 2009-14
Unscheduled Interchange charges Regulations, 2009 & (Amendment) Regulations, 2010
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Tariff determination from Renewable Energy Sources Regulation 2009
Connectivity, Long-term Access and Medium-term Open Access in inter-State Transmission
Regulation 2009
Grant of trading licence Regulations, 2009
Power Market Regulations, 2010
These regulations have been finalized keeping in view the statutory mandate to Electricity
Regulatory Commissions for promoting cogeneration and generation of electricity from
renewable sources of energy. The regulations assume special importance in view of the National
Action Plan on Climate Change which stipulated that minimum renewable purchase standards may
be set at 5% of the total power purchases in year 2010 and thereafter should increase by 1% each
year for ten years. Specifying capital cost norms and fixing tariff upfront for the whole tariff period
are the two main features of the new regulations. The regulations provide normative capital costs
for projects based on different renewable technologies. These capital costs are to be revised every
year for incorporating the relevant escalations. The norms themselves would be reviewed in the
next control period which will start after a period of three years.
These regulations provide transmission products of different varieties, standardization of
procedures, defining the timelines and ensuring level playing field among different categories of
market players. These regulations introduced medium term open access to inter-state grid
through which transmission corridor can be availed for a period ranging from three months to
three years. Now any 100 MW and above consumer can be connected directly to the CTU grid
without having to go to the State Load Dispatch Centers (SLDC).
The new Trading Regulations aim to tighten the terms & conditions for grant of trading licence
keeping in view current price of the trading power, liquidity requirements of the power trading
business and to encourage only the serious players intending to undertake trading business. Power
having been imported from other countries for resale in the domestic market is also covered under
these regulations.
The provisions of these regulations would govern transactions in various contracts related to
electricity. These regulations shall apply to various types of inter-state contracts related to
electricity whether these contracts are transacted directly, through electricity traders, on power
exchanges or on other exchanges. Launching electricity related contracts on exchanges would
require permission of the Commission. The regulations give certain guidelines for the contracts to
be dealt with by electricity traders which are to be complied with detailed capital structure.
Management structure for power exchanges has been specified in the regulations keeping in view
the requirements of ring-fencing, demutualization and creation of widely held market institutions.
Power exchanges have been required to realign their rules and byelaws with the new regulations
within a period of three months.
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Regulations for “Fixation of Trading Margin”, 2010
Regulations on “Terms and Conditions for recognition and issuance of Renewable Energy
Certificate for Renewable Energy Generation”, 2010
Indian Electricity Grid Code Regulations, 2010
The CERC had earlier fixed a trading margin of 4 paise per unit in 2006. The earlier regulations were
reviewed keeping in view the increase in the risk faced by traders which is also a function of the prices
of electricity. As per new regulations, the trading margin shall not exceed 4 paise per unit if the sale
price of electricity is less than or equal to Rs. 3 per unit. The ceiling of the trading margin shall be 7
paise per unit in case the selling price of electricity exceeds Rs. 3 per unit. If more than one trading
licensees are involved in a chain of transactions, the ceiling on trading margin shall include the
trading margins charged by all the traders put together. In other words, traders cannot circumvent
the ceiling by routing the electricity through multiple transactions.
These regulations consist of a set of technical and commercial rules for all entities taking part in grid
operation and consist of planning code, connection code operation code, scheduling and dispatch
code as well as compliance thereof. These regulations lay down the rules, guidelines and standards
to be followed by various persons and participants in the system to plan, develop, maintain and
operate the power system, in the most secure, reliable, economic and efficient manner, while
facilitating healthy competition in the generation and supply of electricity.
This concept seeks to address the mismatch between availability of RE sources and the requirement
of the obligated entities to meet their RPO. With this regulation, a broad architecture of REC has been
crafted at the national level. The RE generators will have two options - either to sell the renewable
energy at a preferential tariff fixed by the concerned Electricity Regulatory Commission (ERC) or to
sell the electricity generation and environmental attributes associated with RE generation
separately. On choosing the second option, the environmental attributes can be exchanged in the
form of REC. The price of electricity component would be equivalent to weighted average power
purchase cost of the distribution company including short-term power purchase but excluding
renewable power purchase cost. The Central Agency designated by CERC will issue REC to RE
generators. The value of REC will be equivalent of 1 MWh of electricity injected into the grid from
renewable energy sources. The REC will be exchanged only in the power exchanges approved by the
CERC within the band of a floor price and a forbearance (ceiling) price to be determined by the CERC
from time to time. The distribution companies, open access consumers, captive power plants (CPPs)
will have an option of purchasing the REC to meet their RPO. Pertinently, RPO is the obligation
mandated by the SERC under the Act, to purchase minimum level of renewable energy out of the
total consumption in the area of a distribution licensee.
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Appellate Tribunal for Electricity
Challenges and way forward
The Appellate Tribunal for Electricity (APTEL) has been setup under the provisions of the Electricity
Act, 2003 (section 110) with all India jurisdiction and it started functioning on 21st July, 2005.
APTEL is headed by a Chairperson who has the status of a sitting judge of the Supreme Court. The
Tribunal has also been conferred jurisdiction under the Petroleum and Natural Gas Regulatory
Board Act, 2006 to hear appeals against the orders/decisions of the Petroleum and Natural Gas
Regulatory Board set up under the Act. APTEL hears and disposes of appeals filed against the
orders of the Central Electricity Regulatory Commission, State Electricity Regulatory Commissions,
Joint Commissions and Adjudicating Officers. Subsequent to the setting up of APTEL, the appeals
pending in the High Courts of all States except the State of Jammu & Kashmir on the subject were
also transferred to this Tribunal.
The power sector is passing though challenging times. The original target of 78,700 mw of capacity
addition for the eleventh plan was scaled down to 62,374 MW. This capacity addition will be
feasible because investment in the private sector has grown rapidly and its share in the total
capacity is likely to go up from less than 10 per cent in the Tenth Plan to 32 per cent during the
eleventh plan.; and, in the twelfth plan, private sector is likely to contribute 60% of planned
capacities.
The slippages by the public sector are mainly impacted by issues related to procurement
procedures and co-ordination within different Govt. agencies. Further capacity constraint of
equipment manufactures like BHEL and Balance of Plant equipment viz coal, ash handling, cooling
tower, chimney etc have compounded the delays. As public sector companies are constrained,
private players have successfully established strategic partnerships with Chinese Companies;
currently 36,000 MW of orders from private power companies are placed with them. Import of
Chinese equipment without developing local manufacturing capabilities will also mean
dependence on imported components and spare parts from China, which may turn out to be a
bottleneck as is being experienced by some utilities.
Challenges persist with respect site clearances, problems in open access and fuel linkages. The 'go'
and 'no go' areas for coal projects is adding to further uncertainties. 17,000 MW of new projects
are held up due to in-ordinate delays in getting mining projects allotted and obtaining environment
and forest clearances. While coal production needs to be increased 8 – 10% every year the
achievement is less than 5-6 %. Even in this scenario, 70 million tonnes of coal is piled up pitheads,
which cannot be moved due to rail bottlenecks.
It is easier to acquire and develop mines in Australia and Indonesia with predictable timeframes
along with the port and rail infrastructure. But getting coal from outside is expensive and has
implications of energy security. Indonesia has recently tightened the conditions on exports and
prices. Australia has imposed additional tax. Imported coal will be 50% more expensive with
additional challenges of port and rail linkages within the country.
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It is in this context, the recommendation by Central Electricity Authority advisory to power
developers to adopt boiler with design to use 30% imported coal needs to be under scored. Using
imported coal will increase generation costs and utilities may not opt to buy costly power. For
instance NTPC had its PLF drop from 91% in 2009-10 to 88% in 2010-11.
States prefer load-shedding than to buy costlier power. In fact capacity up to 10,000 MW was not
utilized last year and the power exchanges were not able to sell costly power. Hence it would be in the
fitness of things for Government to announce a pool price for coal to mitigate the generation cost
variations and ensure a level playing field for all developers. It is reported that the UMPP projects
with competitive tariff bids with fuel costs not allowed as pass through will face difficulties; unless
tariff revisions are done in time the projects may not come up or even if they come up will not be able
to operate due to high fuel costs. The case of Adani power and Gujarat Urja Vikas Nigam Limited
(GUVNL) is another example where the supplier gave a notice of termination of PPA arrived based on
case-1 tariff based bidding, citing increased fuel cost because it could not get domestic coal linkage
and with imported coal the cost of electricity would be higher. Though The Appellate Tribunal for
Electricity (APTEL) has ruled against the termination of contract, uncertainty on fuel prices puts a
question mark over the plants coming up through tariff based route.
It is reported that draw out of loans in many power projects is not according to schedule as the
projects are on a pause mode. Implementation risks coupled with banks nearing their sector
exposure limits, pose difficulties in new projects realizing financial closure. Banks are asking
companies to tie up for fuel a year before the commercial operation where six months was the
practice.
Most state utilities have not revised tariffs for a number of years. The state electricity regulatory
commissions are independent only on paper and are subjected to political compulsion. In Tamil
Nadu, tariff order was issued after a gap of eight years; in Rajasthan, last revision was in 2005. The
situation is similar in other states. The outcome of this inaction has resulting in monthly losses of
utilities. Power Finance Corporation has estimated the annual losses of state electric utilities at
Rs.51,193 cores (without subsidy) in 2008-09 and the losses this year could be over Rs.100,000 cores
for which uneconomic pricing is the main factor. Political pressures continue against reduction of
gross-subsidies like free power and against the cut back of distribution losses. The share of costs
recovered by the SEBs has deteriorated from 82.5% in 2006-07 to 77% in 2008-09. This trend needs
to be reversed. Only when rational user charges are realized, the sector will be viable and the
developers will be able to execute their projects. The ominous signs are clear – the need is to take
bold actions with accountability well defined.
Power sector has seen slow FDI, only 5% as compared to say telecom which has seen 8% of FDI in
2010-11, although 100% FDI is permissible. Commercial losses and poor health of state utilities,
capped regulatory returns on equity, delays in land, forest and environmental clearances and fuel
linkage constraints are the main reasons for low inflow of FDI.
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The Renovation and modernization program has not made much progress even after decade of
efforts by Power Finance
Corporation, BHEL and NTPC.
There is hope for progress on
t h i s f r o n t w i t h t h e
operationalisation of the PAT –
Perform, Achieve and Trade
scheme mandated by BEE for
designated consumers which
i n c l u d e s t h e r m a l p o we r
stations. As the power plants
have been set up over a large
time frame with different
capacities, technology choices and fuel quality, there is a large variation in the performance of the
units.
With such figures PAT will identify areas to
improve efficiency of each unit with a 3 year
time frame to meet the target set by Energy
Audit reports. The exercise would enable
unviable units to be phased out and help
Renovation and modernization Program to
gain momentum. Units overachieving, that
is, above the targets set, will be issued
Energy Saving Certificate (Escerts), whereas those underperforming will need to buy the certificate
from the achievers.
Low energy density of the Renewable Energy and remote locations in many instances make
provision of evacuation infrastructure a costly affair. The project cycle time of a transmission
project is much longer as compared to Renewable Energy project. An optimal planning and
connectivity of Renewable energy projects is essential or else it will further increase the cost of
power from renewable energy. Financing of power evacuation infrastructure for renewable is
eligible for funding under NCEF and a proposal of the state of Rajasthan to evacuate 4000 MW
renewable power has been processed for funding under NCEF.
Advance planning of transmission network is also important for conventional power plants. First
unit of Mundra UMPP, which is ready for commissioning in July 2011, is likely to be delayed beyond
September 2011 for the want of connectivity. Alternate temporary arrangements are being
worked out to evacuate the power. To ensure that evacuation does not become a bottleneck,
Transmission projects are being planned through JV route and also total private participation
through competitive bidding, which is a welcome step.
Table 10 : Efficiency - wise Classification of Steam-BasedElectricity Generation Stations in India (2007-2008)
Thermal Efficiency
(%)
No. of Generating
Stations
Installed Capacity (MW)
% of Total Installed Capacity
Energy Generated
(GWh)
≤20 9
1,696
2.23 1,503
>20 & ≤25 10 4,418 5.81
15,453
>25 & 30≤
25
14,055
18.49
69,071
>30 53
55,580
73.47 400,970
Total 97 76,019 486,997
Table 11 : Overall Thermal Efficiency of Steam -Based Electricity Generation Stations in India
Year Efficiency (%)
2004 -2005 32.16
2005 -2006 32.73
2006 -2007 32.44
2007 -2008 32.69
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The finding of the study by “German Watch” ranking 57 countries on their Climate Climate
Performance Index (CCPI) 2011 have interesting observations. CCPI has been computed on three
parameters namely trends, level and policy. The first three positions have not been assigned as no
country is said to qualify, Brazil tops the list at No 4 and India is favorably at No 9 while US and China
are at 54 and 56, Canada is at the bottom at No. 60.
That the initiatives taken by India have been yielding results is evident from the CCPI. A well thought
agenda with targeted goals are providing insights to tweak the orientation and improve the delivery
of the intended plans with in- built monitoring and evaluation methodologies.
However, the picture changes when clean technology investments are compared. Here, China leads
followed by Germany and US, while India is No 10 among the G-20 list of nations. The disturbing part
is the R&D investment in clean technologies. Here Japan leads followed by US, China and Germany.
India is no where in the picture.
While India is well positioned with its sights well set on short term goals of enhancing energy
efficiency, the long term goals of technology development R&D leave much to be desired. National
Clean Energy Fund (NCEF) has been created for funding research and innovative projects in clean
energy technology. To build the corpus of NCEF, a clean energy cess of Rs. 50 per tonne is levied on
indigenous as well as imported coal. Around Rs 3,124 crore has been collected from the coal cess in
2010-11, and the corpus under the fund is expected to be over Rs 6,500 crore in 2011-12. The NCEF
corpus needs to be leveraged and a R&D plan for technology development worked out. Public Private
Partnerships will help in enhancing innovation and developing cutting edge technologies to address
Indian priorities and simultaneously prepare for global applications.
As part of the National Mission for Development of Clean Coal (Carbon) Technologies, BHEL and
NTPC have also come together to develop Advanced Ultra Supercritical (Adv-USC) technology in
association with Indira Gandhi Centre for Atomic Research (IGCAR). BHEL has also established R&D
Gateway at IIT Madras Research Park Chennai for promoting research in Ultra Supercritical power
cycles and high temperature materials.
To Conclude, realising ambitious target of 800,000 MW by 2032 will be challenging task. Action will
be needed on all the fronts. One suggestion put forth in the mid term appraisal of XI plan is
identification of one hundred sites for environmental clearances and acquisition of land to make
these ready for future power projects to reduce time taken in pre-project activities. Distribution
reforms and improved health of state distribution utilities is an area which needs long due urgent
attention in order to have a strong and vibrant power sector. Drawing the roadmap towards realising
rational user charges with timely tariff notifications by electricity regulatory commissions are the
quintessential pre-requistes for a healthy power sector.
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Installed CapacityInstalled Generation Capacity
0
20000
40000
60000
80000
100000
120000
140000
160000
180000
200000
19
84
-85
19
89
-90
19
91
-92
19
96
-97
20
01
-02
20
02
-03
20
03
-04
20
04
-05
20
05
-06
20
06
-07
20
07
-08
20
08
-09
20
09
-10
20
10
-11
20
11
-12
(Au
g'1
1)
Coal Gas Diesel Hydro Nuclear RES
Year End of Plan
ThermalHydro
Nuclear
RES
TotalCoal Gas Diesel Total
1984-85 6th 26311 542 177 27030 14460 1095 0 42585
1989-90 7th 41238 2343 165 43746 18308 1565 18 63637
1991-922 Annual
Plans 44792 3095 168 48055 19194 1785 32 69066
1996-97 8th
54155 6562
294
61011
21658
2225
902
85796
2001-02
95th 62131 11163 1135 74429 26269 2720 1628
105046
2002-03 63951 11633 1178 76762 26767 2720 1628
107877
2003-04 64956 11840 1173 77969 29507 2720 2488
112684
2004-05 67791 11910
1202
80903
30942
2770
3811
118426
2005-06
68519 12690 1202 82411 32326 3360 6191
124288
2006-07 10th 71121 13692 1202 86015 34653 3900 7761 132329
2007-08 76049 14656 1202 91907 35909 4120 11125 143061
2008-09 77649 14877 1200 93726 36878 4120 13242 147966
2009-10 84198 17056 1200 102454 36863 4560 15521 159398
2010-11
93918 17706
1200
112824
37567
4780
18455
173626
2011-12(Aug'11) 99503 17706 1200 118409 38206 4780 20162 181557
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MW
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Plan wise Generation Capacity Achievements
Plan YearsTarget
MW
Achievement
MW
Achievement
%
I
1951-56
1300 1100 84.6%
II 1956-61 3500 2250 64.3%
III 1961-66 7040 4520 64.2%
Annual Plans
1966-69
5430
4120
75.9%
IV
1969-74 9264 4579 49.4%
V
1974-79 12499 10202 81.6%
Annual Pan
1979-80 2813 1799 64.0%
VI
1980-85 19666 14266 72.5%
VII 1985-90 22245 21401 96.2%
Annual Plan
1990-91 4212 2776 65.9%
Annual Plan 1991-92
3811
3027 79.4%
VIII 1992-97 30538 16423 53.8%
IX 1997-2001
40245 11919 47.5%
X 2002-07 41110 21180 51.5%
XI (Upto 2010-11) Up to 2010-11 78700 41297 52.5%
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0
10000
20000
30000
40000
50000
60000
70000
80000
90000
I II III
An
nu
alP
lan
s IV V
An
nu
alP
an VI
VII
An
nu
alP
lan
An
nu
alP
lan
VIII IX X
XI(
Up
to2
01
0-1
1)
PlansTargetMW
AchievementMW
MW
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Gross Generation of Electricity Million Units
*From 1995-96 onwards, Thermal includes RES in this table
0
100000
200000
300000
400000
500000
600000
700000
800000
900000
20
04
-05
20
05
-06
20
06
-07
20
07
-08
20
08
-09
20
09
-10
20
10
-11
Years
MU
Coal Gas Diesel Hydro Nuclear
Year Utilities Non
Utilities Total Thermal Hydro Nuclear Total
1970-71 28162 25248 2418 55828 5384 61212
1973-74 35321 28972 2396 66689 6107 72796
1978-79 52594 47159 2770 102523 7607 110130
1979-80 56273 45477 2877 104627 8193 112820
1984-85 98836 53948 4075 156859 12346 169205
1989-90 178697 62116 4625 245438 23226 268664
1990-91 186547 71641 6141 264329 25111 289440
1991-92 208747 72757 5525 287029 28602 315631
1996-97 317918 68901 9071 395890 40840 436730
2001-2001 424385 73579 19475 517439 61681 579120
2002-2003 449289 64014 19390 532693 63850 596543
2003-2004 472080 75242 17780 565102 68173 633275
Year
Thermal
Hydro
Nuclear
RES
Total
Coal Gas Diesel Total
2004-05 424244 61525 7066 492835 84610 17011 594456
2005-06 435494 60802 7068 505002 101494 17324 623820
2006-07 461340 63719 2489 527548 113502 18802 8000 667852
2007-08 486732 68779 3304 558815 120387 16957 12325 708484
2008-09 512527 72865 4708 590100 114081 14713 27731 746625
2009-10 539957 96651 4243 640851 106656 18654 30172 796333
2010-11 561674 100261 2979 664914 114296 26285 NA 805495
2011-12 (Aug'11) 244310 40481 992 285783 62353 13334 NA 361470
Up to 2005-06, RES is included in Diesel, at present data for RES not available for 2010-11, 11-12
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Consumption of Electricity by Sectors in IndiaMillion Units
Sector-wise Electricity Consumption
0100000200000300000400000500000600000700000
1970
-71
1974
-75
1978
-79
1982
-83
198
6-87
199
0-91
1994
-95
1998
-99
2002
-03
2006
-07
MU
Industry Agriculture Domestic
Commercial Traction&Railways
Others
Sector-wise Electricity Consumption (2009-10)
Agriculture
20%
Industry
38%
Others
6%
Traction &Railways 2%
Commercial
10%
Domestic
24%
Industry Agriculture Domestic Commercial Traction
&Railways
OthersTotal
Energy consumed
29579 4470 3840 2573 1364 1898 43724
32481 6310 4645 2988 1531 2291 50246
47728 12027 7576 4331 2186 3445 77293
45955 13452 8402 4657 2301 3317 78084
63019 20960 15506 6937 2880 4766 114068
80694 44056 29577 9548 4070 7474 175419
84209 50321 31982 11181 4112 8552 190357
87288 58557 35854 12032 4520 9394 207645
104165 84019 55267 17519 6534 12642 280146
107296 81673 79694 24139 8106 21551 322459
114959 84486 83355 25437 8797 22564 339598
124573 87089 89736 28201 9210 22128 360937
137589 88555 95660 31381 9495 23454 386134
151557 90292 100090 35965 9944 24039 411887
171293 99023 111002 40220 10800 23411 455749
189429 104182 120918 46685 11108 29660 501977
209474 109610 131720 54189 11425 37577 553995
236752 120209 146080 60600 12408 36595 612644
Year
1970-71
1973-74
1978-79
1979-80
1984-85
1989-90
1990-91
1991-92
1996-97
2001-02
2002-03
2003-04
2004-05
2005-06
2006-07
2007-08
2008-09
2009-10
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Electricity Growth Indices
Per Capita Electricity Consumption
0
100
200
300
400
500
600
700
800
19
50
19
61
19
66
19
69
19
74
19
78
19
80
19
85
19
90
19
92
19
97
20
02
20
04
20
05
20
06
20
07
20
08
20
09
Kw
h p
er
An
nu
m
Village electrification
0
100000
200000
300000
400000
500000
600000
No
. of
Vill
age
s
19
50
19
66
19
74
19
80
19
90
19
97
20
03
20
05
20
07
20
09
20
11
As On 31 March
Per capita Electricity Consumption
Kwh
No.of villages electrified
1950 26.4 7294
1961 37.9 21754
1966 61.4 45148
1969 77.9 73739
1974 97.5 156729
1979 130.9 232770
1980 130.5 249799
1985 168.5 370332
1990 238 470838
1992 270 487170
1997 334.3 498836
2002 559.2 512153
2003 566.7 492325
2004 592 495031
2005 606 439800
2006 631.5 459486
2007 671.9 482864
2008 717.13 487347
2009 733.14 489532
2010 500920
2011 537888
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Growth of Transmission Sector
At the end of
400 kV Transmission lines 220 kV Transmission lines
Central State JV/Pvt Total Central State JV/Pvt Total
6th Plan 1831 4198 6029 1641 44364 46005
7th Plan 13068 6756 19824 4560 55071 59631
8th Plan 23001 13141 36142 6564 73036 79600
9th Plan 29345 20033 49378 8687 88306 96993
10th plan 50992 24730 75722 9444 105185 114629
11th Plan (Aug'11)
72571 31641 6387 110599 10549 125758 425 136732
B. SUB - STATIONS (MVA)
At the end of
400 kV Sub-Stations 220 kV Sub-Stations
Central State JV/Pvt Total Central State JV/Pvt Total
6th Plan 715 8615 9330 500 36791 37291
7th Plan 6760 14820 21580 1881 51861 53742
8th Plan 17340 23525 40865 2566 81611 84177
9th Plan 23575 36805 60380 2866 113497 116363
10th Plan 40455 52487 92942 4276 152221 156497
11th Plan
(Aug'11)69100 67652 630 137382 5856 203165 1440 210461
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A. TRANSMISSION LINES (ckm)
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Wholesale Price Index of Electricity
Reference:
1. Office of economic advisor, Ministry of commerce and industry; URL: eaindustry.nic.in
95
100
105
110
115
120
125
130
2005
-06
200
6-0
7
200
7-0
8
200
8-0
9
200
9-1
0
2010
-11
Who
leSa
lePr
ice
Inde
x(
Bas
e20
04-0
5=
100
)
Domestic Commercial Agricultural Railway Traction Industry Electricity
Year
WPI of Electricity for different Sectors (2004-05=100)
ElectricityDomestic Commercial Agricultural Railway Traction
Industry
2005-06 99.25 96.95 109.27 102.22
101.85
102.57
2006-07 101.87 98.58 115.26 103.48 102.91 105.3
2007-08 104.14 98.05 115.52 103.52 103.51 106.18
2008-09 104.86
98.96
116.77 104.94
102.39
106.38
2009-10 108.7 101.4 114.5 106.9 103.2 107.4
2010-11 114.3 104.5 128.1 114.2 102.8 112.5
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RENEWABLE ENERGY SECTORINDIAN
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Pradeep Chaturvedi
Chairman
Indian Association for the Advancement of Science
Mr. Pradeep Chaturvedi, Chairman, Indian Association for the Advancement of Science, is an
internationally known Energy and Environment Expert. He is Vice Chairman (Energy committee),
World Federation of Engineering Organisations and Vice President of World Environment
Foundation. He has been involved with action-oriented projects on sustainable development
strategies, energy and environment policy and planning (especially the climate change) for over
three decades in India and other Asian and Pacific countries. He has been involved with the Studies
Programme of the World Energy Council since early 1980s. He has authored/edited 35 books of
energy management, and is recipient of several Awards.
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Introduction
Significance of Renewable Energy Sources in Primary Energy Supply Mix
The Ministry of New and Renewable Energy (MNRE) being the nodal ministry of the Government of India
for matters relating to new and renewable energy, promotes renewable energy technologies to enhance
their share in the total energy mix. MNRE lays down the overall policy guidelines for renewable energy
programmes and provides budgetary support for research and development and demonstration of
technologies; facilitates institutional finance to financial institutions; and promotes private investments
through fiscal incentives, tax holidays, depreciation allowance and remunerative returns for power fed into
the grid.
Renewable energy sources contribute over 30% in India's primary energy supply. It is no longer alternate
energy but is increasingly becoming a key part of the solution to the nation's energy needs. India has made
continuous progress in electricity generation through conventional as well as renewable power
generation. From the year 2002 onwards, renewable based grid capacity (as a percentage of total
capacity) has increased by almost four times. In April 2002, renewable energy based power generation
installed capacity was 3,497 MW which was 3% of the total installed capacity in the country. On 30 June
2011, it has reached 18455 MW, which is about 12% of the total installed capacity of 1,76, 990 MW and
corresponds to a contribution of about 4.13% in terms of electrical energy.
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Renewables18455 MW10%
Hydro38106 MW22%
Nuclear4780 MW3%
Gas17706 MW10%
Diesel1200 MW1%
Coal98743 MW54%
Installed Generation Capacity (As on 30-06-2011)
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thDuring the first three years of the 11 Plan (2007-2012) and the current year up to 31 January 2011,
renewable power capacity addition has been 8,564 MW, while the conventional power capacity addition
has been 28,529 MW, which corresponds to over 23% of the total capacity addition. Major contribution
has come from wind power, which is 70% of the total capacity. It is to be also noted that 23% of all capacity
today is large hydro which is renewable but not accounted as such. Table-1 gives potential and
contribution of different renewable sources.
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Increasing contribution of Renewable Energy to power mix
200000
175000
150000
125000
100000
75000
50000
25000
0
20
01
-02
20
02
-03
20
03
-04
20
04
-05
20
05
-06
20
06
-07
20
07
-08
20
08
-09
20
09
-10
20
10
-11
Thermal Hydro Nuclear Renewables
Strategic PlanRenewable energy programme is guided by a strategic plan developed by the Ministry of New and
Renewable Energy for 2011 – 2017. This is documented in their paper titled “Renewable Energy in India:
Progress, Vision and Strategy”. In view of the fast changing energy scenario, both domestically and
internationally, the Ministry of New and Renewable Energy decided to develop the Strategic Plan for the
period 2011-17 so as to ensure targeted achievements for the year 2022. Based on an assessment of the
external factors that are likely to affect renewable energy growth in the future, and internal capabilities,
MNRE has adopted the strategy to address general and sector specific weaknesses even as successful
policy initiatives are proposed to be upscaled and emerging opportunities exploited.
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Estimated
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The Strategic Plan Initiatives have been formulated to address the following issues:i) Pursue initiatives that fit national strengths;ii) Overcome weaknesses with new knowledge and capabilities; iii) Identify actions that can leverage India's strength to reduce vulnerabilities to external threats; and iv) Establish a defensive plan to prevent internal weaknesses from making it perceptible to external
threats.
The Strategic Plan Initiatives are expected to lead to:i) Cost reduction for incubating technologies with high future potential; ii) Opening market channels and introducing new business models;iii) Continuing improvements in regulatory and policy initiatives;iv) Developing and deploying appropriate financial instrumentsv) Developing framework for monitoring and verification of projects;vi) Promoting schemes; and vii) Promoting human resource development.
MNRE has undertaken a review of technical and economic feasibility of different sources as per
international norms. Important and significant observations have emerged.
Potential for wind power has been assessed for sites that have wind power density greater than 200
W/sqm assuming land availability in potential areas at 1% and requirement of wind farms at 12 ha /mw,
now all of which may be technically feasible for grid interactive wind power. In line with the international
practice for setting up grid interactive wind power systems on sites having wind power density higher
than 300 W/sqm, the potential would be only 5,000 MW. Further, preliminary surveys do not at this
stage suggest a sizeable grid interactive offshore wind power potential.
Technically feasible and economically viable hydro-potential is generally accepted at 40% of the total
estimated potential. Accordingly for a total potential of 15,000 MW, the technically feasible and
economically viable small hydro power potential could be around 600 MW.
With more sugar mills coming online and modernisation of existing ones, technically feasible potential is
assessed at 5,000 MW, not all of which may be economically viable. Further more, several sugar
companies/cooperatives are unable to develop bankable projects on account of their financial and
liquidity positions, which again lowers the potential.
With expansion of urban population, post census 2001, current technically feasible municipal waste to
energy potential is assessed at 1,700 MW, not all of which is economically viable. However, subsidy
disbursement under the municipal Energy Waste to Energy Programme has been kept in abeyance on
the orders of the Supreme Court in the case of a PIL in May 2005. This stay has now been vacated for
setting up five pilot projects.
Resource Potential Assessment
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The potential based on surplus agro residues has a number of practical issues. There are several barriers
in collection and transportation of such agro-residues to the generation site and biomass power station
units prefer to use fuel-wood for techno economic reasons. A potential of 45,000 MWe from around 20
mha of waste lands assumed to be yielding 10 MT/ha/annum of woody biomass having 4000 Kcal/kg
with system efficiency of 30% and PLF of 75% is not being presently considered by MNRE . In order to
realise this potential a major inter-ministerial initiative involving, among others, environment and
forest, agriculture, rural development and Panchayati Raj would be required. MNRE has undertaken a
major program of preparing biomass surplus which is expected to more accurately assess state wise
renewable energy potential from agro-residues.
This is for the first time that MNRE has indicated these problems and has given a true perspective on
potential.
In June 2008, National Action Plan on Climate Change was announced, which included eight major
national missions: one on solar energy being the centre piece. This mission envisages a major step up in
the utilization of solar energy for power generation and other purposes.
Jawaharlal Nehru National Solar Mission (JNNSM) was launched by the Prime Minister in January 2010,
with the objective to help reach grid parity by 2022 and help set up indigenous manufacturing capacity.
The target is to set up 20,000 MW grid solar power (based on solar thermal power generating systems
and solar photovoltaic technologies), 2,000 MW of Off-grid capacity including 20 million solar lighting
systems and 20 million square meter solar thermal collector area by 2022. The Mission is being
implemented in three phases. The first phase is of three years (up to March, 2013), the second till March
2017 and the third phase will continue till March, 2022. The target of phase-I is to set up 1,100 MW grid
connected solar plants including 100 MW of roof top and small solar plants; and 200 MW capacity
equivalent off-grid solar applications and 7 million square meter solar thermal collector area.
A new architecture has been designed for the 1,000 MW grid connected projects. These will be
implemented through NTPC Vidyut Vyapar Nigam (NVVN). NVVN will sell the solar power to the State
utilities after bundling solar power with equivalent capacity of thermal power. CERC has announced
tariff for purchase of solar power by NVVN. The tariff for the year 2010-11 for PV was Rs. 17.91 per unit
and for solar thermal power Rs.15.31 per unit.
In addition, project developers for 100 MW capacity of grid (below 33 KV) connected solar projects (of
100 kW to MW capacities each) have also been selected. It is expected that 150-200 MW of solar power
will be installed in the country by December 2011.
The guidelines for implementation were announced on 25 July 2010. They provide for deployment of
both solar PV technology projects and solar thermal technology projects in a ratio of 50:50 in MW
capacity terms.
Solar Mission
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It was decided that the selection of PV grid power projects be done in two batches by allocating overall
capacities over two financial years in phase one, i.e. 2010 – 11 and 2011-12. The total capacity of solar
PV projects to be selected in first batch was limited to 150 MW. The projects for remaining capacity for
solar PV projects would be selected in the second batch. This was done keeping in view the declining
cost trends in PV technology and in order to prevent bunching of large capacities at one time. The other
objective was to avoid the difficulty that may arise in achieving financial closure by a large number of
such projects as may get selected together given that this is a new area of financing to a financial
institution in India. This would also facilitate incremental indigenisation. The size of PV projects in the
first stage was fixed at 5 MW. The size of solar thermal projects were kept in the range of 20 MW to 100
MW totalling to 500 MW.
Expression of interest was issued by NVVN in August 2010 to select 150 MW of solar PV projects and 417
MW of solar thermal projects, which yielded huge response by way of an offer of more than 5,000 MW.
Since this led to a situation wherein the short listed applicants were offering to set up capacities much
more than what was on offer, the short listed projects were asked in October 2010 to indicate the
discount in rupee per kwh on CERC approved applicable tariff. This process was also discussed in
consultation meetings and the pre-bid meetings. Projects offering the maximum discount on the CERC
applicable tariff were selected.
A total of 704 MW capacity grid connected solar power projects were selected by December, 2010,
which comprise of:
i) 16 projects of 84 MW capacity selected in July, 2010 by NTPC Vidyut Vyapar Nigam (NVVN) under the
migration scheme at CERC tariff.ii) 37 projects of 620 MW capacity (7 projects of 470 MW of solar thermal and 30 projects of 150 MW of
PV) projects selected by NVVN through discounts on CERC tariff.iii) The eligible bids to set up PV plants have offered weighted average discount of Rs. 6.06 per unit on
CERC tariff of Rs. 17.91 per unit; and for solar thermal plants the average discount is Rs.3.95 per unit
on CERC tariff of Rs.15.31 per unit.
Under this component of the mission, MNRE will provide a generation based incentive of Rs.12.41 per
kwh to the state utilities that will directly purchase solar power from the project developers. The
quantum of generation based incentives to the utilities is kept fixed as a difference of CERC tariff for
2010-11 (Rs.17.91/kwh) and a reference of Rs.5.5/kwh.
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A state-wise list of solar power projects selected under the mission is given at Table-2. Also a list of SPV
system installations during the year is given in Table-3. Table-4 gives state-wise cumulative installation
of SPV systems.
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Andaman & Nicobar
Arunanchal Pradesh
Himachal Pradesh
Jammu & Kashmir
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Concentrating Solar Thermal Technologies
Solar Cities Programme
Energy Efficient Buildings and Rating
Concentrating solar-thermal technologies have formed good application for steam generation and air
conditioning also at places where vapour absorption machines are in operation using conventional fuel.
A total of 13 solar steam generating systems and 21 indoor community cookers covering around
4000 sqm of the collector area have been were sanctioned.
Under the Development of Solar Cities Programme the Ministry has accorded “in-principle” approval to
develop 48 cities in 23 States as Solar Cities. Master Plans are under preparation for development of 31
cities as Solar Cities. Draft Master Plans have been developed for 11 cities. Two cities, Nagpur and
Chandigarh are being developed as Model Solar Cities. The proposal of Gandhinagar for developing as a
model solar city has also been received. The development of Solar Cities Programme has been modified
in January 2011, so as to provide financial support;
i) for the establishment of ten cities to be developed as 'Pilot Solar Cities';ii) for developing four cities as 'Model Solar Cities', apart from 60 Solar Cities, 50 new Small
townships/campuses duly notified/permitted by the concerned Authorities being developed by the
promoters/builders, SEZs/industrial towns, Institutional campus etc will be developed as Solar
Township/Solar Campus.
Scheme on Energy Efficient Solar/Green Buildings is being implemented with the objective to promote
the widespread construction of energy efficient solar/green buildings in the country through a
combination of financial and promotional incentives. The Ministry has created an independent
registered society, 'Association for Development and Research in Sustainable Habitats' (ADaRSH) for
promotion and implementation of GRIHA rating system in the country. A decision has been taken that all
new buildings of Central Government/Public Sector Undertakings would at least meet the requirements
of GRIHA-3 Star rating, though every effort would be made by them to achieve higher star rating,
wherever site conditions permit to do so. Ideally all government organisations would aim to reaching
GRIHA 4-star rating. So far 117 projects have already been registered for GRIHA rating certification with
4.99 million square meter built up area; out of which 81 projects are from various Government
Departments, Public Sector Undertakings (PSU), Educational Institutions, including, All India Institute of
Medical Sciences, with a total 3.22 million square meter built up area have been registered for the
construction based on green rating norms for acquiring GRIHA Ratings. A GRIHA manual containing a set
of 5 volumes was released in January 2011. Guidelines for Green Campuses are under preparation.
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Green Rating for Integrated Habitat Assessment - a building rating system for promotion of energy
efficient green buildings in the country - is an integrated framework for ensuring design, construction
and in turn rating of ECBC compliant green buildings. They have not only incorporated ECBC as a
mandatory provision but also promote integration of passive, low energy strategies into building design,
thus making energy efficient buildings more cost effective. The GRIHA rating system contains 34
evaluation criteria with 100 points. These have been categorised into: (i) site planning including
conservation and efficient utilisation of resources, health and wellbeing during building planning and
construction stage; (ii) water conservation; (iii) energy efficiency including energy embodied in
construction and renewable energy; (iv) waste management including waste minimisation, segregation,
storage, disposal and recovery of energy from waste; (v) environment for good health and wellbeing.
Additional criteria for innovative development such as, alternative transportation, environmental
education, enhanced accessibility for physically/mentally challenged are also awarded points.
A wind power capacity of 1,377 MW has been added during the year up to January 31, 2011, taking the
cumulative installed capacity to 13,184 MW. Wind electric generators of unit sizes between 225 KW and
2.10 MW have been deployed across the country. Wind turbines are being promoted in 29 models by 18
manufacturers in the country, mainly through joint-ventures or under licensed production agreement.
The current annual production capacity of domestic wind turbine industry is in the range of 3,000-4,000
MW. Table-5 gives the status of wind power in India.
Wind Power
9 Others 255 0 4.30
Total 48561 1376.83 13183.58
Table 5: Status of Wind Power in India 2010-11
Sl. No. States Potential Capacity installed during 2010-11
( Upto Jan.2011 )
Cummulative capacity (upto
Jan 2011)
1. Andhra Pradesh 8968 44.80 180.90
2. Gujarat 10645 172.18 2035.81
3. Karnataka 11531 121.30 1594.10
4. Kerala 1171 0 27.75
5. Madhya Pradesh 1019 7.80 237.20
6. Maharashtra 4584 125.05 2202.80
7. Rajasthan 4858 292.70 1381.00
8. Tamil Nadu 5530 613.00 5519.72
A package of incentives which includes fiscal concessions such as 80% accelerated depreciation,
concessional customs duty for specific critical components, excise duty exemption, income tax
exemption on profits for power generation are available for wind power projects. A number of states
have also announced renewable purchase obligations, which catalyses the growth in the wind power
generation.
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Small Wind Energy System
Biomass Power
Biomass Gasifier Programme
Small wind energy systems, mainly water pumping wind mills, aero-generators and wind solar hybrid
systems have been found to be useful for harnessing wind and solar energy in un-electrified areas, or
areas having intermittent electric supply. These systems can be set up in rural, semi-urban/urban areas,
having annual average wind speed of about 15 kmph or above, at 20 meter height. The promotional
scheme has been modified during the year to bring it in market mode with greater involvement of
manufacturers and beneficiaries. During the year, 6 manufacturing companies with a total 11 models of
small aero generators were approved. The implementation of the programme during the year has
resulted in sanctioning a capacity of around 600 Kw taking up a cumulative total of 1,351 Kw. Also an
aggregate capacity of 1,072 Kw of the aero generations/hybrid systems have been installed under the
programme.
Biomass resource potential is assessed at 500 MT/year and about 30% of the same or about 150
MT/annum is estimated surplus biomass availability creating a potential of about 18,000 MW electricity
generation. 143.50 MW capacity biomass projects were installed during the year taking the cumulative
biomass capacity to 997 MW from 130 projects. Improved high output technologies have been used in
these projects. 14 biomass power projects of aggregate capacity of 142 MW with project configuration
of 67 ata and 485 degree C have been commissioned during the year. Biomass power projects
aggregating to 50 MW capacity are in different stages of implementation.
Biomass gasifier programme promotes electricity generation using locally available biomass resource in
rural areas where surplus biomass such as wood chips, rice husk, arhar stalks, cotton stalks and other
agro residues are available. Also small biomass gasifier and combustion based power plants connected
at the tail-end of the grid for captive power and thermal applications in rice mills and other industries is
promoted. Biomass gasifier programme is promoted in three different modes: i) biomass gasifier based
distributed/off-grid power programme for rural areas, which may preferably be set up following a cluster
approach; ii) biomass gasifier based power generation in rice mills and other industries for meeting their
captive electrical and thermal needs and surplus power being fed into the grid; and iii) biomass gasifier
based grid connected power projects with 100% producer gas engine or biomass based grid connected
boiler turbine generator projects with a maximum installed capacity of each of such project to be 2 MW. 42 rice husk gasifier projects of 32 KW each have been sanctioned and 25 such projects have been
installed and providing unmet demand of electricity for 6 hours in the night to about each of 70 villages.
40 rice husk gasifier systems retrofitted with existing diesel generators are under installation. Seven
biomass gasifiers and combustion based power projects up to 2 MW capacity with cumulative capacity
of 13.20 MW, connected to the tail-end of the grid have been approved for installation. Also 500 KW
gasifier projects are under installation.
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Bagasse co-generation programme added power generation capacity of 257 MW during the year. Thus,
the total capacity in the country has increased to 1,603 MW from 152 projects. Special focus has been
on cooperative sector sugar mills through higher incentive for accelerated development of bagasse co-
generation projects. Nine cooperative sugar mills in Maharashtra adopted the latest technologies with
configuration varying from 67 ata to 110 ata adding 116 MW during the year. MNRE adopted an
innovative approach to continue the existing scheme with two modifications related to (a) cogeneration
projects through BOOT model in cooperative sugar mills and (b) boiler upgradation of cogeneration
projects in cooperative sugar mills.
Biomass cogeneration (non-baggase) in industry is another route being promoted to exploit the
potential of thermal energy and power for captive use in industry. A total of 20 projects with a capacity
of over 60 MW have been completed up to January 31, 2011. In addition 8 projects with an aggregate
capacity of 30 MW are under implementation.
Incineration and bio-methanation are the most common technologies for conversion of urban and
industrial waste into energy. Pyrolysis and gasification are also emerging as desirable technological
options. The recent potential for generation of over 3,600 MW of power from urban and industrial
wastes in the country has been identified. During the year, MNRE has promoted three different schemes
aimed at a variety of wastes, such as municipal solid wastes, vegetable markets, and slaughter house
waste, cattle dung along with agricultural residue and agro-industrial wastes. The first scheme is to set
up 5 pilot projects on energy recovery from municipal solid waste. The second scheme refers to power
generation from biogas generated at sewerage treatment plant. The third scheme refers to power
generation from other urban wastes and mix of urban and agricultural/agro-industrial wastes.
A total of 11 projects with an aggregate capacity for 28.77 MW based on industrial wastes have been
completed up to January 31, 2011. Ten projects with an aggregate capacity of 25 MW are under
installation.
Small hydro power projects up to 25 MW capacity is also the responsibility of MNRE. Though the
potential for power generation from such plants is projected at 15,384 MW at 5,718 potential sites, but
technically and economically viable capacity addition is projected to be 6,000 MW only. This programme
is essentially private investment driven. A project has been sanctioned to set up a small
hydro turbine R&D laboratory with an objective of creating international level facilities for testing,
design and R&D in the area of hydraulic turbines, hydro mechanical equipments, control and
instrumentation of small hydro electric power plants. The on-line monitoring system that adds to
longevity of uninterrupted power supply from large hydro power systems worldwide are also being
considered for adoption.
Biomass Cogeneration (non-Bagasse)
Energy Recovery from Urban and Industrial Wastes
Small Hydro Power
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Renewable Energy for Rural Applications
MNRE has focused on rural applications through following activities:
National Biogas and Manure Management Programme (NBMMP) caters to setting up of family type
biogas plants for meeting cooking energy needs in rural areas along with making available enriched bio-
fertilizer. 73,281 biogas plants were installed during the year up to 31 January 2011. Since the launch of
the programme in 1981-82 a total of 4.31 million family type biogas plants have been installed by 31
January 2011. Installation of 1,19,914 family type biogas plants during the year 2009-10 is estimated to
bring in a saving of about 3.05 lakh tonnes of fuel-wood equivalent and production of about 115.7 lakh
kg of urea equivalent or 21.47 lakh tonnes of organic manure per year. In addition the rural families
benefit in terms of reducing drudgery of women involved in collecting fuel-wood from long distances
and minimising health hazards during cooking in smoky kitchens. Also construction of these biogas
plants in 2009-10 would have generated about 3.35 million person-days of employment for skilled and
unskilled workers in rural areas during the year.
MNRE has also started a scheme “Biogas based Distributed/Grid Power Generation Programme” (BGPG)
from 2005-06 with a view to promote biogas power generation, especially in the small capacity range
(from 3 KW to 250 KW), based on the availability of large quantity of animal waste and wastes from
forestry/rural based industries (agro/food processing), kitchen wastes etc. MNRE has also undertaken
the new initiatives of bottling of biogas to demonstrate an integrated technology package in
entrepreneurial mode on medium size mixed feed Biogas Fertilizer Plants (BGFP) for generation,
purification/enrichment, bottling and piped distribution of biogas. Installation of such plants aims at
meeting stationary and motive power, cooling, refrigeration and electricity needs in addition to cooking
and heating requirements. In one of the 16 projects sanctioned, it is observed that the biogas generated
from the plant has been purified and the purity of 98.4% methane has been achieved. The capacity of
BGFP could be 1,100 cum to 20,000 cum biogas per day, and above thereof, depending on the availability
of suitable biomass feed materials and cattle dung.
The remote village electrification programme is being implemented by use of renewable energy
technologies for electrification of remote villages including small hydro, biomass and solar energy.
Solar PV lighting remains the most preferred option. The decision to use a particular technology is taken
by the state implementing agency after examination of the technical feasibility and resource availability. th
A target of coverage of 10, 000 villages and hamlets has been set for the 11 Plan (2007-2012) of which
4,589 villages and hamlets have been taken up by 15 January, 2011.
National Biogas and Manure Management Programme
Biogas based Distributed/Grid Power Generation Programme
Remote Village Electrification Programme
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An evaluation study in three states, namely, Madhya Pradesh, Orissa and Chattisgarh, to assess the
implementation of the rural village electrification programme found that the provision of lighting in the
remote villages has improved the life of the villagers. Around 5,200 households in 186 villages for the
three states were covered in the survey. The functionality of the solar lighting systems was found to be
between 68% and 86%.
thVillage Energy Security Test projects were taken up by the Gram Panchayats since the 10 Plan. 61 test
projects have so far been commissioned, of which 6 test projects have been commissioned and 8 test
projects have been completed during the year 2010-11 till 31 January 2011. During the mid-term thappraisal of the 11 Plan in September 2009, it was decided to concentrate on consolidating the projects
already taken up for implementation and take up new villages only under the Rural Village Electrification th
Programme. During the remaining period of the 11 Plan, consolidation of Village Energy Security
Programme will be undertaken. As such no new test projects will be sanctioned.
The Special Area Demonstration Project Scheme of the Ministry has been introduced with the objective
of demonstrating application of various renewable energy systems in a project mode at places of
national and international importance including world heritage sites, heritage monuments, religious
locations and places of public interest to create greater awareness of renewable energy sources and to
supplement the energy requirements at such locations. 41 proposals for world heritage sites have been
supported.
A programme on tidal energy has been implemented to develop and harness about 8,000 to 9,000 MW
of estimated tidal energy potential for power generation. First tidal project of 3.75 MW capacity is being
set up at Durgaduani Creek in Sundarbans.
A broad based programme on research, development and demonstration of battery operated
vehicles/hybrid electric vehicles/plug hybrid electric vehicles is being implemented to get a feed back on
the performance of battery operated vehicles under operating conditions.
Village Energy Security Test Projects
Special Area Demonstration Project Scheme
Tidal Energy
Electric Vehicles
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Renewable Energy CertificatesIn January 2010, the Central Electricity Regulatory Commission issued a notification on 'Terms and
Conditions for recognition and issuance of Renewable Energy Certificate (REC) for Renewable Energy
Generation'. REC seeks to address the mismatch between availability of renewable sources and the
requirements of the obligated entities to meet their renewable purchase obligation. It allows certificate
holders to sell renewable energy to states deficient on this front, individual or other entities is expected
to stimulate competition and create a market for power across states. The National Load Despatch
Centre has been appointed as Central Agency for implementation of RECs. Renewable Energy Certificate
Mechanism has been launched on 18 November 2010. Based on this states like Maharashtra, Gujarat,
Chhattisgarh and Kerala have started accepting application for accreditation of renewable energy
projects. 646 REC generators have already signed up under the scheme. The status of RECs is given in the
graph. As of now, all the RECs are under non solar category. There are 183 accredited generators with a
total capcity of about 1100 MW.
Potential of Power from RenewablesWhereas the Solar Mission itself will create a capacity addition of 22,000 MW by the year 2021-22, wind
and biomass can substantially contribute to power generation capacity from renewables. The current
estimates indicate that about 60,000 to 70,000 MW of installed capacity will be added by wind power
and biomass. Thus, about 90,000 MW of power from renewable sources can be expected to be installed
by 2021-22. At that stage, the total installed capacity is expected to be around 400,000 MW.
The way forward
REC SUMMARY
50000
40000
30000
20000
10000
0
March-11 April-11 May-11 June-11 July-11 August-11
Opening Balance REC Issued REC Redeemed Closing Balance
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Thus 20 to 25% of power generation capacity could be contributed by the renewable sources of
energy, which in terms of energy supply will be 11 to 12% of the total energy supply from different
power generation sources. However, it will be necessary to overcome some of the challenges.
Strategy for implementation of programme under Solar Mission has been well defined but its project
implementation still needs smoothening.
The off-grid gasification project, with dedicated fuelwood plantation has been a successful attempt
that has helped the local people in Sunderbans. However, as the fuelwood plantations grew in girth
to a dimension bigger than what is specified by the forest department, the users were stopped by the
forest department from felling such plantation as per the Act.
A number of similar other examples of how the successful projects have been stopped for legal or
administrative reasons can be identified. All these need careful handling.
In an overall consideration following barriers and the policies targeted to deal with them will be
necessary for successful implementation :
There are three challenges that have been identified and need to be overcome. These are the
following:
i) Barriers in establishment and operation of systemsii) Barriers in spread of renewable energy based power generation technologiesiii) Barriers to development of commercially viable small and medium enterprises
Appropriate policy framework is necessary to address various constraints and thereby create
opportunities for business to fulfil the objectives of power generation from renewable sources.
Targeted policies are necessary to address the following issues:
i) Promoting innovative delivery modelsii) Supporting structured training programmes to create a pool of skilled personnel iii) Facilitating innovative designs and loan schemes to reduce cost iv) Creating effective monitoring and evaluation frameworks v) Reviewing R&D policies and projects for cost reduction and performance under field conditionsvi) Creating fiscal and policy incentives to enhance public and private sector participation, and
their mainstreaming with the global markets.vii) Creating decentralised manufacturing and service facility.
Challenges
Targeted Policies Needed
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ConclusionThe government has taken serious note of
mainstreaming renewables in the energy
supply for the country. This is a major move
'from considering new renewables as
m a r g i n a l s o u r c e s o f e n e r g y t o
mainstreaming them'. The Integrated
Energy Policy Report, released in August
2006 (that laid the foundation for
Integrated Energy Policy announcement in
December 2008) triggered mainstreaming
of renewables. A consolidation of
government's policy framework and
actions for continuous upward movement
for renewables can result in verifiable
targeted achievement of 90,000 to 100,000
MW of power from new renewables (not
including hydro projects of capacity more
than 25 MW) by the year 2021-22.
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INTEGRATED ENERGY POLICYPlanning Commission, Government of India, August 2006
INTEGRATED ENERGY POLICY Planning Commission, Government of India, August 2006
Introduction
Achieving an efficient configuration of the various forms of energy requires consistency in the policies
governing each sector and consistency in the pricing of different types of energy. There is also a need
for clarity in the direction in which we wish to move in aspects like energy security, research and
development, addressing environmental concerns, energy conservation, etc.
To address these issues in an integrated manner, the Prime Minister had directed that the Planning
Commission should constitute an Expert Committee to undertake a comprehensive review and to
make recommendations for policy on this basis. The Expert Committee was constituted under the
chairmanship of Dr. Kirit S. Parikh, Member, Planning Commission. The report of the committee has
been adopted by the Government on December 26, 2008.
The report on Integrated Energy Policy covers all sources of energy and addresses all aspects of energy
use and supply including energy security, access and availability, affordability and pricing, as well as
efficiency and environmental concerns. It provides a broad overreaching framework for guiding the
policies governing the production and use of different forms of energy from various sources. It also
makes specific recommendations on a very large range of issues. The report shall be a valuable input
into policy making. It defines the broad vision behind the energy policy as –
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“To reliably meet the demand for energy services of all sectors including the lifeline energy needs
of vulnerable households, in all parts of the country, with safe and convenient energy at the least
cost in a technically efficient, economically viable and sustainable manner.”
The report emphasizes that meeting this vision would require that India pursues all available fuel
options and forms of energy, conventional and non-conventional, as well as new and emerging
technologies and energy sources. The approach of the policy has therefore to be directed to
realising a cost-effective energy system. For this the following are proposed:
(I) Wherever possible, energy markets should be competitive. However, competition alone
has been shown to have its limitations in a number of areas of the energy sector and
independent regulation becomes even more critical in such instances.(ii) Pricing and resource allocations that are determined by market forces under an
effective and credible regulatory oversight(iii) Subsidies are transparent and targeted(iv) Efficiencies are improved across the energy chain.(v) Policies should reflect externalities of energy consumption.(vi) Policies should rely on incentives/ disincentives to regulate market and consumer
behaviour.(vii) Policies should be implementable.(viii) Management reforms should create accountability and incentives for efficiency.
The Policy has presented demand projections leading up to 2031-32. For this purpose historical
data and the demand scenarios of various organisations have been reviewed. The correlation
with GDP of the country has also been established and based on this correlation; projections have
been calculated for each energy source for the above period. The elasticities used for scenario
building are as given in table-1.
Scenarios to 2031-32
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Table 1: Elasticities used for projections
Years
Electricity
Constant elasticitiesFalling
elasticities0.95
0.85
0.78
0.95
0.95
0.95
2004-05 to 2011-12
2011-12 to 2021-22
2021-22 to 2031-32
Total Primary Commercial Energy Supply(TPCES)
Constant elasticitiesFalling
elasticities0.75
0.70
0.67
0.8
0.8
0.8
Two elasticities have been considered, one taking constant elasticities, that is presuming that the
demand for energy remains constant over this period and the second taking falling elasticities, that is,
expecting the demand for energy to fall as percentage of GDP over this period. Based on these
elasticities, demand scenario for TPCES has been worked out as given in table-2.
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Table 2: Demand Scenario for TPCES(Million Tons of Oil Equivalent)
Years Populationin millions
GDP(Rs. In Billion
@ 1993-94 prices)
TPCES (Mtoe)
FallingElasticities
TPCES (Mtoe)
ConstantElasticities
GDP Growth Rate2006-07
2011-12
2016-17
2021-22
2026-27
2031-32
1114
1197
1275
1347
1411
1468
17839
26211
38513
56588
83145
122170
18171
27958
43017
66187
101837
156689
389
521
684
898
1166
1415
397
551
748
1015
1360
1823
394
537
732
998
1361
1856
403
570
807
1142
1617
2289
9%8%9%9% 8%8%
The demand scenario for electricity has been worked out as given in table-3.
Table 3: Demand Scenario for Electricity
YearsTotal At Bus Bar
Energy (Billion kWhr) Projected PeakDemand (GW)
Installed CapacityRequired (GW)
GDP Growth Rate
2003-04
2006-07
2011-12
2016-17
2021-22
2026-27
2031-32
633
761
1097
1524
2118
2866
3880
633
774
1167
1687
2438
3423
4806
592
712
1026
1425
1980
2680
3628
592
724
1091
1577
2280
3201
4493
89
107
158
226
323
437
592
89
109
168
250
372
522
733
131
153
220
306
425
575
778
136
155
233
337
488
685
960
8% 9% 8% 9% 9% 9%8% 8%
Demand scenario for fuel choices for electricity generation, as given in table-4, has been worked out
by the committee based on certain assumptions. The projections assume exploitation of full hydro
potential of 1,50,000 MW in the country, a capacity addition of 63,000 MW from nuclear power
sources and a 14,000 MW capacity from wind farms by 2031- 32. However, it states that these
scenario assumptions in respect of hydro and nuclear may not be fully realised and are made in order
to characterise the boundaries of alternative choices. Here generation from coal-based stations also
includes electricity generation from lignite. The scenario also forces gas usage for power generation
with gas-based electricity share rising from about 10% to 16% between 2003-04 and 2031-32. As a
result of these assumptions, the share of coal-based electricity drops from 72% to 61%. The demand
for oil in power sector covers consumption of petroleum products in diesel based plants as well as
secondary oil consumption in coal based plants.
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Table 5: Commercial Fuel Requirement for Non-Power Use - One Possible Scenario
YearNon-Power Coal
MtNon-Power Oil
MtNon-Power Natural Gas
BCM
GDP Growth Rate
2003-04
2006-07
2011-12
2016-17
2021-22
2026-27
2031-32
91
123
164
221
299
408
562
91
123
170
237
334
475
684
113
126
158
205
266
351
469
113
142
178
231
299
395
528
20
20
30
38
56
73
100
20
22
32
45
65
93
133
8% 8% 8%9% 9% 9%
It is emphasized in the report that the table only represents one possible scenario and it should not, in
any way, be considered as the preferred scenario. Also to the extent that gas, hydro or nuclear capacity
cannot be realised as projected in the scenario, coal-based generation will need to fill the gap. In
reality, the choice between coal and gas will be guided by economic and commercial considerations
including any policy prescriptions for pricing-in certain environmental externalities. The level of gas
use projected in the scenario is also based on somewhat optimistic assumptions of gas availability and
of its ability to compete with coal on price. It is expressed that should these assumptions not hold true,
coal dependence will increase.
The report discusses in detail projections for coal, oil and natural gas for non-power use. Based on
these discussions, the commercial fuel requirement for non-power use are summarised as given in
table-5.
Table 4: Sources of Electricity Generation - One Possible Scenario
Year
ElectricityGeneration at Bus Bar
(BkWh)
Hydro(BkWh)
Nuclear(BkWh)
Wind(BkWh)
Thermal energy(BkWh)
Fuel Needs (MMT)
Coal(Mt)
NG(BCM)
Oil*(Mt)
GDPGrowthRate2003-042006-072011-122016-172021-222026-272031-32
8% 9%
592711
10261425198126803528
592724
10911577228032014493
7487
139204270335401
173964
118172274375
38
1114182124
498577812
1089152120502828
498590877
1241182025713693
318337463603832
11091475
318379521678936
12481659
111219335277
119
111421375987
134
6689
121417
668
10121520
8% 8% 8% 8%9% 9% 9% 9%
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Total commercial primary energy requirements based on the scenario drawn for power in Table-4 and
the projections made for non-power oil, coal and gas in table-5 are summarised in Table-6 using the
common unit of million tonnes of oil equivalent (Mtoe). Report emphasizes that this is merely one
scenario that forces Hydro (1,50,000 MW), forces Nuclear (63,000 MW) and forces share of gas-based
power generation (16%). Other scenarios based on DSM, efficiency improvements, renewables etc.
will bring down the commercial energy requirements further and change the fuel mix.
Table 6: Total Commercial Energy Requirement - One Possible Scenario(Mtoe)
Year Hydro Nuclear Coal OilNatural
GasTPCES
GDP Growth Rate
2011-122016-172021-222026-272031-32
1218232935
1731457198
257338464622835
283375521706937
166217278365486
186241311410548
446497
135197
4874
111162240
496665907
12221651
546739
101113781858
CAGR - %Compounded
Annual Growth Rate 5.9
24
6.53.7
67
4.614.6
569
1573.6
638
1574.1
331
1112.9
373
1113.4
134
275.2
163
276.3
1124
3063.7
1266
3064.1
11.2 5.9 6.3 5.1 5.6 7.2 8 6 6.4
Per Capita2032 (Kgoe)
Kgoe in 2004Ratio 2032/2004
8% 8% 8% 8%9% 9% 9% 9%
Integrated ScenarioFinally, to explore the consequences of different alternatives and their quantitative significance a
number of scenarios have been developed using a multi-sectoral, multi period optimising linear
programming model. These scenarios present commercial energy supply and the commercial energy
mix under a number of scenarios reflecting specific policy initiatives. They are designed to assess the
importance of critical policy options for meeting energy requirements. These scenarios are designed
to map out extreme points of feasible options and none of them should be looked upon as a preferred
scenario. The commercial energy supply under these scenarios varies from a low of 1351 Mtoe to a
high of 1702 Mtoe.
The linear programming model used for the scenarios obtains the least-cost solution subject to
constraints over ten 5-year periods from 2000 till 2050. It also has sub-periods characterizing peak,
intermediate and base load during summer and winter seasons. Power demand is characterised for
three regions: (a) near coal mines, (b) distant coastal regions and (c) the rest. Options at distant coastal
regions include transmission from pithead plants and load centre based generation using domestic
coal or imported coal. The amount of pithead generation is restricted due to environmental115
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reasons. In the case of hydro, India's full potential of 1,50,000 MW is taken as exploited by 2031-32.
Nuclear capacity of 63,000 MW is assumed to be realised by 2031-32. As regards gas, the model is
forced to have a 16% share for gas-based power generation by 2031-32. A model scenario critically
depends on the set of assumptions, parameters and constraints, and in particular on the relative costs
and prices of the alternatives available, the discount rate and the projected requirements.
Requirements have been specified in terms of billion units of electricity, billion tonne-kilometre of
freight traffic, and billion passenger-kilometer of passenger traffic. The freight and passenger traffic
projections have been made using elasticities with respect to GDP of 1.0 and 0.8, estimated using time
series data from 1930 to 2000. The “optimality” of the solution is contingent on the various
inputs/assumptions detailed herein. The importance of the model is that each solution provides a
consistent scenario. It should be noted that the model does not suggest preferred scenarios. They are
in fact extreme options to define the feasible space for alternate policy choices. Thus when 1,50,000
MW of hydel by 2031-32 is estimated, it does not mean that given the various social, political and
environmental constraints we will in fact fully develop our hydel resources to reach this estimate. The
scenario does, however, show what the implications are for energy supply if we were able to develop
the full hydro potential. Table-7 summarises the results of the scenarios in 2031-32. Figure shows this
graphically. Table-8 presents the results in %.
Based on the comparison of energy requirements and our resource base, the report concludes that
our hydrocarbon resources would be grossly inadequate to meet our needs. From a longer term
perspective, a number of actions have been recommended:
• Relentlessly pursue energy efficiency and energy conservation as the most important virtual
source of domestic energy.• Institute policies that maximise domestic coal production. • Create coastal infrastructure for import and use of coal.• Develop coal transportation infrastructure including alternatives such as coastal and river
movement.• Develop fully the nuclear and hydro option.• Mount R&D efforts to develop commercially viable in-situ coal gasification technology.• Redouble exploration efforts for oil, gas and coal.• Raise the level of diplomacy to access hydrocarbon reserves overseas and gas pipelines to India.• Undertake a technology mission on carbon sequestration.• Undertake pilot projects to assess the economics and social benefits of biomass plantations and
bio-fuels
Main Recommendations
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• Undertake a solar technology mission to make solar power using photo-voltaics or solar
thermal economically attractive.• Undertake R&D for exploiting gas-hydrates. • Undertake R&D for fusion to keep open that option for unlimited power.• Assess off-shore wind power potential.
Some of the measures put forth by the energy policy to achieve the objectives are brought out
below.
These are a representative list, for complete details, please refer the report.
1. Explore and maximize domestic sources2. Acquire oil equity abroad3. Build adequate strategic reserves
Currently the Energy Sector is dominated by large Public Sector Companies with some sub-sectors
having monopoly. Under this scenario, the policy recommendations are-
1. Restructure markets so as to promote competition. Allow multiple players in each element of the
energy value chain to compete under transparent & level playing field2. The regulatory responsibility/functions of the State should be separated from the Ministries that
control the Public Sector Units that dominate the energy sector3. Till competitive markets emerge, independent regulators should fix prices or price caps to mimic
competitive markets 4. A common energy regulator at the level of the Central Government could provide a positive
impetus to some of the policy initiatives foreseen under the Integrated Energy Policy5. All monopoly carriers must be common carriers with no interest in content
1. Promote Energy efficiency in all sectors2. Emphasis on mass transport / rail freight3. Active policy on renewable energy including bio-fuels and fuel plantations 4. Promote Distributed Generation & Clean fuel technologies for rural population5. Accelerated development of nuclear and hydro-electricity6. Technology missions for clean coal technologies7. Focused R&D on climate friendly technologies
1.0 Energy security
2.0 Enabling an Environment for Competitive Efficiency
3.0 Reduction of Demand-Supply Gap and Reduction of GHG
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4.0 Pricing, Taxation, incentives and Subsidies
4.1 General
4.2 Petroleum
4.3 Coal
4.4 Gas
4.5 Power
4.6 Renewables
1. Allow market forces to determine pricing and resource allocation under an effective and credible
regulatory oversight, as far as possible2. Provide transparent and targeted subsidies.3. As a general rule, all commercial primary energy sources must be priced at trade parity prices at
the point of sale. 4. Eliminate cross subsidy charges on movement of primary energy sources (e.g. Freight on coal
must not subsidize passengers)5. Taxes and subsidies must be equivalent across fuels. Equivalence must be in terms of calories6. Differential taxation must be allowed only to promote environment friendly energy resources7. The top 5% of India's households could pay for subsidies to poor through a cess on their incomes
or a more widely distributed cess on consumption could fund this subsidy burden.
1. Eliminate custom duty differential on crude and petroleum products2. Permit full price competition at the refinery gate and the retail level.
1. Coal prices should ideally be left to competitive market and trading of coal, nationally and
internationally, should be free. 2. Pending the creation of a competitive market independent regulation of coal prices becomes
essential. Prices should be based on GCV to promote coal dressing and washing. A competitive
coal market is also important for setting a proper price of natural gas on a net-back-basis.
1. Gas price can be determined through competition among different producers or independently
regulated on a cost plus basis including reasonable returns. 2. Another option could be to price gas on a net-back-basis.
1. If a cost plus regime cannot be avoided and the payments are guaranteed by the Government of
India (GOI) the internal rate of return on total capital employed should bear a reasonable
relationship to the long-term government bond coupon at the time of the approval.2. Cut down cross subsidies
1. Link all incentives to energy generated as opposed to capacity created2. Phase out all capacity subsidies by the end of 10th plan
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3. Environment subsidy to renewables should be financed by a cess on non renewables and fuels
causing environment damage4. Ensure that renewables are given a tariff at least equal to avoided cost of generation5. Selective price subsidy may continue to renewables promoting employment and livelihood to
poor6. Finance a large scale socio-economic experiment to operate community sized bio-gas plants as a
commercial enterprise.7. Coordination between MoP and MNRE programmes must be ensured
1. Policy recommends providing autonomy to PSUs for commercial decisions2. It also recommends for specific policies for promotion of renewables
Entry barriers should be removed to foster competition
1. Private participation in mining should be allowed2. Domestic coal production should be stepped up by allotting coal blocks to central and state public
sector units and for captive mines to notified end users3. Coal producers must enter into fuel supply agreements with power plants4. Restructure CIL in separate competing entities & CIL should be left with responsibility of reviving
loss making collieries
1. Power Sector Reforms must focus on control over aggregate technical and commercial losses of
state power utilities. 2. Central assistance to states should be linked to loss reduction and improved viability3. Full energy audit for each distribution transformer is essential to reform and reduction in AT&C
losses. 4. Incentives to staff for reduction in AT&C losses & also based on collections 5. The Committee also recommends that a liberal captive and group captive regime be foreseen
under the Electricity Act 2003 be realised on the ground.6. Separate the cost of the pure wires business (carriage) from the energy business (content) in both
transmission & distribution.
5.0 Reforms and Restructuring:
5.1 Petroleum
5.2 Coal
5.3 Power Sector
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7. The Government Policy should seek to ensure that all generation & transmission projects started
in the 11th Plan & beyond should be competitively built on the basis of tariff based bidding under
a prescribed price cap.8. Standardise the unit size and invite global tenders for 20 to 30 units to get substantial bulk
discount. New power plants should have efficiency of not less than 38%9. Distribution should be bid out on the basis of a distribution margin or paid for by a regulated
distribution charge determined on a cost plus basis including a profit mark up
1. The Petroleum Conservation Research Association (PCRA) should be merged with Bureau of
Energy Efficiency (BEE) and should establish end use efficiency standards for energy intensive
industry.2. Promote urban mass transport, freight movement by railways, and energy efficient vehicles.3. Appropriate incentives to the firm which first commercialises equipment that exceeds energy
efficiency target.4. Promote minimum life cycle cost purchases instead of minimum initial cost procurement by
government and public sector. 5. Require industry with a turnover in excess of say Rs. 50 crores to employ at least one certified
internal energy auditor reporting directly to the board/owner like the current internal auditor. For
smaller industries achieve the same by clubbing a group of them together or requiring each
industrial estate to provide such services collectively for a fee.6. Annual audits must include energy audits for all specified energy intensive industries and
industries with a turnover exceeding say Rs.100 crores.
1. Energy coordination committee may act as a nodal agency for development of new technologies2. Lead should be taken in CBM, in-situ gasification of coal, carbon capture and IGCC3. Fast breeder reactor programme should be reinforced
1. A National Energy Fund (NEF) should be set up by levying a cess of 0.1% of the turnover of all
companies engaged in the field of primary/secondary energy production. In order to encourage
the firms to do their own R&D a rebate of up to 80% of this cess may be given to firms for R&D
carried out in-house. The R&D priorities have to be based on a strategic vision which is frequently
updated. The NEF should periodically commission and fund such studies.2. The NEF could provide R&D funding in support of applications, innovation of new ideas,
fundamental research etc. to researchers in different institution, universities, organisations and
even individuals working independently.
5.4 Energy Efficiency:
6.0 New Technologies
7.0 Research & Development
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Non-Commercial Natural Gas
Table 7: Scenario summaries for 8% GDP Growth Fuel Mix in Year 2031-32 (in Mtoe)
Scenario No.
Scenario Description
Crude OilNatural Gas
Coal Hydro Nuclear RenewablesNon-
commericalTotal
Total withoutNon-commercial
1 104
2 Forced Hydro 485 105 953 35 76 2 185 1840 1655
3 Forced Nuclear 486 104 998 13 98 2 185 1885 1700
4 Forced Nuclear+Hydro 485 105 929 35 98 2 185 1839 1654
5Forced
Nuclear+Hydro+GAS486 197 835 35 98 2 185 1837 1652
6Forced
Nuclear+Hydro+GAS+DSM486 174 715 35 98 2 185 1695 1510
7Forced
Nuclear+Hydro+GAS+Coal eff
485 197 818 35 98 2 185 1813 1628
8Forced
Nuclear+Hydro+GAS+DSM+coal eff
485 171 698 35 98 2 185 1673 1488
9
ForcedNuclear+Hydro+GAS+DSM
+coal eff+Rail share up447 171 701 35 98 2 185 1639 1454
10
ForcedNuclear+Hydro+GAS
+coal eff+Rail share up+Transport eff
361 171 707 35 98 2 185 1558 1373
11Scenario
10+Forced Renewable350 150 632 35 98 87 185 1536 1351
Coal Dominant Case 486 1022 13 76 2 185 1887 1072
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Table 8: Scenario summaries for 8% GDP Growth Fuel Mix in Year 2031-32 (in %)
Nuclear+Hydro+GAS+DSM+
1
2
3
4
5
6
7
8
9
10
11
Nuclear+Hydro+GAS+DSM+
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INTERNATIONAL ENERGY OUTLOOK 2011
The Annual International Energy Outlook is the flagship publication of Information Administration,
the independent statistical and analytical agency within the Department of Energy, USA. It is widely
referred to as one of the most authoritative energy reports on global energy projections and analysis.
It presents medium to long-term energy market projections, statistics and analysis.
The International Energy Outlook 2011 (IEO2011), released on 19th September, 2011, presents an
assessment by the Energy Information Administration (EIA) of the outlook for international energy
markets through 2008 to 2035. The report focuses on marketed energy but does not take into account
incorporate prospective legislation or policies that might affect energy markets. Non marketed energy
sources, which continue to play an important role in some developing countries, are not included in
the estimates.
The reference case projects that world-wide energy consumption will grow by 53 percent between
2008 and 2035, with most of the increase coming from strong economic growth in the developing
countries, especially, China and India. China and India would be accounting for about half of the
projected increase in world energy use.
Oil prices have been as uncertain as ever, rising in 2010 as a result of growing demand associated with
signs of economic recovery from 2008-09 global recession and a lack of a sufficient supply response.
Prices were even higher at the end of 2010 and into 2011 as social and political unrest unfolded in
several Middle Eastern and African economies. Oil prices increased from about $82 per barrel at the
end of November 2010 to more than $110 per barrel. The impacts of quickly rising prices and possible
regional supply disruptions add substantial uncertainty to the near-term outlook.
Highlights of the report
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124
Some key findings that have been reported in the report are (under reference case)-
• India and China: The Indian and Chinese economies were least affected by the worldwide
recession and will continue to lead world economic growth and energy demand growth in the
reference case. In 2008, China and India combined accounted for 21 percent of total world
energy consumption. With strong economic growth in both countries over the projection
period, their combined energy use will more than double by 2035, when they will be
accounting for 31 percent of world energy use.
• Renewable energy is projected to be the fastest growing source of primary energy over the
next 25 years, but fossil fuels remain the dominant source of energy. Renewable energy
consumption is expected to grow by 2.8 percent per year and the renewable share of total
energy use will increase from 10 percent in 2008 to 15 percent in 2035; however, fossil fuels
will still account for 78 percent of world energy use. The report observes that the projections
under reference case reflect current laws and policies but renewable energy deployment is
significantly affected by policy changes.
• Natural gas has the fastest growth rate among the fossil fuels over the 2008 to 2035 projection
period. World natural gas consumption is expected to increase at 1.6 percent per year, from
111 trillion cubic feet in 2008 to 169 trillion cubic feet in 2035. Unconventional natural gas
(tight gas, shale gas, and coal bed methane) supplies are expected to increase substantially -
especially from the United States, Canada and China.
• World oil prices are expected to remain high, but oil consumption will continue to grow; both
conventional and unconventional liquid supplies will be used to meet rising demand. The price
of light sweet crude oil (in real 2009 dollars) is expected to remain high, reaching $125 per
barrel in 2035. Total world petroleum and other liquids fuel use will increase by 26.9 million
barrels per day between 2008 and 2035, but the growth in conventional crude oil production
will be less than half this amount at 11.5 million barrels per day, while production of natural
gas plant liquids will increase by 5.1 million barrels per day, World production of
unconventional resources (including bio-fuels, oil sands, extra-heavy oil, coal-to-liquids, and
gas-to-liquids), which totalled 3.9 million barrels per day in 2008, will increase to 13.1 million
barrels per day in 2035.
• Total world energy consumption will rise by an average annual 1.6 percent in from 2008 to
2035. Strong economic growth among the non-OECD (Organization for Economic
Cooperation and Development) nations will drive the increase. Non-OECD energy use will
increase by 2.3 percent per year; in the OECD countries energy use will grow by only 0.6
percent per year.
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• Petroleum and other liquid fuels will
remain the largest energy source
worldwide through 2035, though
projected higher oil prices will erode
their share of total energy use from
34 percent in 2008 to 29 percent in 2035.
• Petroleum prices are very sensitive to
both supply and demand conditions.
Higher economic growth in developing
countries coupled with reduced supply
from key exporting countries will
result in a High Oil Price case in which real
oil prices may exceed $169 per barrel by 2020 and approach $200 per barrel by 2035. Conversely, lower economic growth in developing
countries coupled with increased supplies from key exporting countries will result in a Low Oil
Price case in which real oil prices may fall to about $55 per barrel in 2015 and then gradually
decline to $50 per barrel after 2030 where they remain through 2035.
• World coal consumption will increase from 139 quadrillion Btu (3502 Mtoe) in 2008 to 209
quadrillion Btu (5267 Mtoe) in 2035, at an average annual rate of 1.5 percent. In the absence
of policies or legislation that would limit the growth of coal use, China and, to a lesser extent,
India and the other nations of non-OECD Asia will consume coal in place of more expensive
fuels. China alone may account for 76 percent of the projected net increase in world coal use,
and India and the rest of non-OECD Asia may account for another 19 percent of the increase.
800
600
400
200
0
354
406
505
573619
671721
770Non-OECD
OECD
1990 2000 2008 2015 2020 2025 2030 2035
150
100
50
01990 2000 2008 2015 2025 2035
Rest of World
OECD
Non-OECD Asia
History 2008 Projections
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• Transportation sector accounted for 27 percent of total world delivered energy consumption
in 2008, and transportation energy use will increase by 1.4 percent per year from 2008 to
2035. The transportation share of world total liquids consumption may increase from 54
percent in 2008 to 60 percent in 2035, accounting for 82 percent of the total increase in world
liquids consumption
• Energy-related carbon dioxide emissions may rise from 30.2 billion metric tons in 2008 to
43.2 billion metric tons in 2035—an increase of 43 percent. Much of the increase in carbon
dioxide emissions is projected to occur among the developing nations of the world, especially
in Asia.
This publication is available on the WEB at: http://www.eia.gov/forecasts/ieo/index.cfm
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• Electricity is the world's fastest-growing form of end-use energy consumption, as it has been
for the past several decades. Net electricity generation worldwide will rise by 2.3 percent per
year on average from 2008 to 2035. Renewables are the fastest growing source of new
electricity generation, increasing by 3.0 percent and outpacing the average annual increases
for natural gas (2.6 percent), nuclear power (2.4 percent), and coal (1.9 percent).
40
30
20
10
0
2008 2015 2020 2025 2030 2035
Coal
Natural Gas
Hydropower
Nuclear
RenewablesLiquids
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EIA 2011 projections
World Population
Region/Country History Projections Annual
growth (%) 2006 2007 2008 2015 2020 2025 2030 2035
United States 299 302 305 326 342 358 374 390 0.9
Canada 33 33 33 36 38 40 42 43 1.0
Japan 128 128 128 126 124 122 119 116 -0.4
South Korea 48 48 48 49 49 49 49 48 0.0
Australia/New Zealand 25 25 25 27 28 30 31 32 0.8
Russia 143 142 141 138 135 132 129 125 -0.4
China 1,314 1,321 1,328 1,385 1,419 1,441 1,451 1,450 0.3
India 1,148 1,165 1,181 1,294 1,367 1,431 1,485 1,528 1.0
Brazil 188 190 192 203 209 214 217 219 0.5
Total OECD 1,193 1,201 1,209 1,257 1,287 1,314 1,338 1,358 0.4
Total Non -OECD 5,385 5,454 5,522 5,999 6,321 6,613 6,869 7,095 0.9
Total World 6,579 6,655 6,731 7,257 7,609 7,927 8,207 8,453 0.9
Gross domestic product (GDP) expressed in purchasing power parity
Region/Country
History Projections Annualgrowth%
2006
2007
2008
2015
2020
2025
2030
2035
United States 12,976 13,229 13,229 15,336 17,421 20,020 22,731 25,692 2.5
Canada 1,200 1,226 1,233 1,408 1,572 1,741 1,942 2,167 2.1
Japan 3,952 4,043 3,995 4,235 4,405 4,483 4,558 4,624 0.5
South Korea 938 986 1,009 1,274 1,506 1,737 1,969 2,196 2.9
Australia/New Zealand 816 853 869 1,055 1,213 1,375 1,559 1,764 2.7
Russia 1,835 1,984 2,094 2,377 2,681 3,055 3,589 4,197 2.6
China 6,130 7,000 7,672 13,358 18,206 23,550 28,953 34,366 5.7
India 2,759 3,025 3,180 5,207 7,147 9,121 11,255 13,433 5.5
Brazil 1,594 1,692 1,778 2,452 3,079 3,840 4,784 5,951 4.6
Total OECD 35,929 36,897 37,005 41,701 46,822 52,506 58,517 65,052 2.1
Total Non-OECD 24,924 27,131 28,774 42,131 54,052 67,107 81,345 96,596 4.6
Total World 60,853 64,028 65,779 83,832 100,874 119,612 139,862 161,648 3.4
(Millions)
(Billion 2005 dollars)
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Per Capita Carbon dioxide emissions
EIA 2011 projections
Energy Intensity
(kgoe per 2005 dollar of GDP)
(Tons carbon dioxide per capita per annum)
Region/Country History Projections Annual
growth (%) 2006 2007 2008 2015 2020 2025 2030 2035
United States 19.8 19.9 19.1 17.4 16.9 16.6 16.3 16.2 0.3
Canada 18.0 18.4 18.0 15.8 15.3 15.2 15.1 15.8 0.5
Japan 9.7 9.8 9.5 8.9 9.2 9.3 9.3 9.4 -0.4
South Korea 10.1 10.5 10.9 11.3 11.5 12.2 12.9 14.1 1.0
Australia/New Zealand 17.6 18.0 18.6 17.3 17.0 16.4 16.4 16.5 0.5
Russia 11.7 11.4 11.8 11.9 11.9 12.1 12.9 14.0 0.2
China 4.4 4.7 5.1 6.8 7.1 8.0 8.7 9.3 2.6
India 1.1 1.2 1.2 1.4 1.5 1.7 1.8 2.0 2.7
Brazil 2.0 2.1 2.2 2.6 2.8 3.0 3.4 4.0 2.7
Total OECD 11.4 11.4 11.1 10.4 10.3 10.3 10.4 10.5 0.2
Total Non-OECD 2.8 2.9 3.0 3.4 3.5 3.7 3.9 4.1 2.1
Total World 4.4 4.4 4.5 4.6 4.6 4.8 5.0 5.1 1.3
Region/Country History Projections Annual
growth (%) 2006 2007 2008 2015 2020 2025 2030 2035
United States 0.19 0.19 0.19 0.17 0.15 0.14 0.12 0.11 -2.0
Canada 0.29 0.29 0.29 0.26 0.25 0.24 0.23 0.22 -1.1
Japan 0.15 0.14 0.14 0.13 0.13 0.13 0.13 0.13 -0.4
South Korea 0.25 0.25 0.25 0.22 0.19 0.18 0.17 0.16 -1.7
Australia/New Zealand 0.20 0.20 0.20 0.18 0.16 0.15 0.14 0.13 -1.6
Russia 0.40 0.38 0.37 0.33 0.29 0.27 0.24 0.21 -2.1
China 0.30 0.28 0.28 0.23 0.19 0.17 0.15 0.14 -2.6
India 0.17 0.17 0.17 0.13 0.12 0.11 0.10 0.09 -2.2
Brazil 0.18 0.18 0.18 0.16 0.14 0.13 0.12 0.11 -1.7
Total OECD 0.17 0.17 0.17 0.15 0.14 0.13 0.12 0.11 -1.5
Total Non -OECD 0.24 0.23 0.23 0.19 0.17 0.15 0.14 0.13 -2.2
Total World 0.20 0.19 0.19 0.17 0.15 0.14 0.13 0.12 -1.8
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Carbon dioxide intensity of energy use
EIA 2011 projections
Primary Energy Consumption (Mtoe)
(Co2 emissions/toe (tonnes)
Region/Country History Projections Annual
growth (%) 2006 2007 2008 2015 2020 2025 2030 2035
United States 2.4 2.3 2.3 2.2 2.2 2.2 2.2 2.2 -0.2
Canada 1.7 1.7 1.7 1.5 1.5 1.5 1.4 1.4 -0.5
Japan 2.1 2.2 2.2 2.0 2.0 1.9 1.9 1.8 -0.6
South Korea 2.0 2.1 2.1 2.0 2.0 2.0 2.0 2.0 -0.3
Australia/New Zealand 2.7 2.7 2.7 2.5 2.4 2.4 2.4 2.3 -0.5
Russia 2.3 2.2 2.2 2.1 2.0 2.0 2.0 2.0 -0.4
China 3.1 3.2 3.1 3.0 2.9 2.8 2.8 2.8 -0.4
India 2.7 2.7 2.8 2.6 2.5 2.5 2.5 2.5 -0.4
Brazil 1.3 1.3 1.3 1.4 1.3 1.3 1.3 1.3 -0.1
Total OECD 2.2 2.2 2.2 2.1 2.0 2.0 2.0 2.0 -0.4
Total Non-OECD 2.5 2.5 2.5 2.5 2.4 2.4 2.4 2.4 -0.2
Total World 2.4 2.4 2.4 2.3 2.3 2.2 2.2 2.2 -0.2
Region/Country History Projections Annual
growth (%)2006 2007 2008 2015 2020 2025 2030 2035
OECD
United States 2,515.0 2,562.8 2,522.5 2,570.4 2,643.5 2,721.6 2,797.2 2,877.8 0.5
Canada 352.8 360.4 360.4 367.9 395.6 413.3 443.5 473.8 1.0
Japan 587.2 579.6 564.5 559.4 584.6 597.2 597.2 599.8 0.2
South Korea 236.9 247.0 252.0 279.7 292.3 312.5 330.1 350.3 1.2
Australia/New Zealand 163.8 166.3 171.4 186.5 196.6 204.1 214.2 224.3 1.0
Russia 733.3 748.4 771.1 783.7 788.8 814.0 849.2 894.6 0.6
China 1,849.7 1,988.3 2,172.2 3,129.8 3,543.1 4,054.7 4,483.1 4,823.3 3.0
India 473.8 504.0 531.7 700.6 834.1 980.3 1,116.4 1,239.8 3.2
Brazil 289.8 304.9 320.0 390.6 436.0 501.5 584.6 677.9 2.8
Total OECD 6,156.4 6,201.7 6,156.4 6,310.1 6,567.1 6,799.0 7,023.2 7,262.6 0.6
Total Non-OECD 5,972.4 6,211.8 6,564.6 8,142.1 9,044.3 10,122.8 11,158.6 12,136.3 2.3
Total World 12,128.8 12,413.5 12,718.4 14,452.2 15,611.4 16,921.8 18,181.8 19,399.0 1.6
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EIA 2011 projections
Carbon dioxide emissions
Region/Country
History Projections Annual growth
(%)2006 2007 2008 2015 2020 2025 2030 2035
United States 5,918 6,022 5,838 5,680 5,777 5,938 6,108 6,311 0.3
Canada 594 607 595 569 582 608 635 679 0.5
Japan 1,240 1,254 1,215 1,125 1,142 1,136 1,110 1,087 -0.4
South Korea 484 503 522 553 562 597 634 678 1.0
Australia/New Zealand 440 449 464 466 477 492 509 528 0.5
Russia 1,668 1,618 1,663 1,648 1,607 1,603 1,659 1,747 0.2
China 5,817 6,257 6,801 9,386 10,128 11,492 12,626 13,441 2.6
India 1,281 1,367 1,462 1,802 2,056 2,398 2,728 3,036 2.7
Brazil 380 397 423 528 579 644 739 874 2.7
Total OECD 13,606 13,742 13,472 13,031 13,252 13,549 13,882 14,323 0.2
Total Non-OECD 15,152 15,786 16,718 20,426 21,958 24,383 26,758 28,897 2.1
Total World 28,758 29,529 30,190 33,457 35,210 37,932 40,640 43,220 1.3
(Million Tons)
Gross domestic product (GDP) expressed in market exchange rates
(Billion 2005 dollars)
Russia 824 890 940 1,067 1,204 1,371 1,611 1,884 2.6
China 2,544 2,905 3,184 5,543 7,555 9,772 12,015 14,261 5.7
India 920 1,008 1,060 1,736 2,382 3,040 3,752 4,478 5.5
Brazil 917 972 1,022 1,410 1,770 2,208 2,750 3,421 4.6
Total OECD 36,772 37,736 37,806 42,317 47,326 52,667 58,434 64,684 2.0
Total Non -OECD 10,865 11,798 12,502 18,062 23,022 28,469 34,426 40,836 4.5
Total World 47,637 49,534 50,308 60,380 70,348 81,136 92,860 105,520 2.8
Region/Country History Projections Annual
growth (%)2006 2007 2008 2015 2020 2025 2030 2035
United States 12,976 13,229 13,229 15,313 17,479 19,982 22,726 25,731 2.5
Canada 1,166 1,192 1,198 1,368 1,528 1,692 1,887 2,106 2.1
Japan 4,650 4,758 4,701 4,984 5,184 5,276 5,364 5,441 0.5
South Korea 888 934 955 1,206 1,426 1,645 1,864 2,080 2.9
Australia/New Zealand 869 909 926 1,125 1,293 1,465 1,661 1,880 2.7
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Liquid fuel consumption
Consumption of Natural Gas
(Million tons)
(Billion cubic meter)
Region/Country History Projections Annual
growth (%) 2006 2007 2008 2015 2020 2025 2030 2035
United States 1,031 1,026 971 1,016 1,031 1,046 1,066 1,091 0.4
Canada 115 115 110 115 115 115 115 120 0.2
Japan 264 259 249 214 229 234 229 224 -0.4
South Korea 110 110 105 115 120 120 125 129 0.7
Australia/New Zealand 55 55 55 60 60 60 60 65 0.5
Russia 139 129 139 144 139 134 139 144 0.1
China 364 374 388 603 677 777 817 842 2.9
India 134 139 149 189 229 284 339 374 3.5
Brazil 115 120 125 144 154 164 179 194 1.7
Total OECD 2,470 2,470 2,390 2,366 2,405 2,435 2,465 2,510 0.2
Total Non-OECD 1,778 1,808 1,877 2,286 2,455 2,704 2,908 3,078 1.9
Total World 4,248 4,278 4,268 4,646 4,860 5,139 5,378 5,588 1.0
Region/Country History Projections Annual
growth (%) 2006 2007 2008 2015 2020 2025 2030 2035
United States 614 654 657 710 716 710 733 750 0.5
Canada 93 96 96 99 105 119 130 142 1.5
Japan 96 105 105 105 105 110 113 113 0.3
South Korea 31 34 37 42 45 51 54 54 1.5
Australia/New Zealand 34 34 37 37 42 51 57 62 2.1
Russia 470 473 475 458 456 458 475 492 0.1
China 57 71 76 150 192 243 289 325 5.5
India 40 42 42 93 110 127 139 144 4.6 Brazil 20 20 23 31 42 51 65 91 5.1
Total OECD 1,483 1,525 1,542 1,624 1,684 1,743 1,840 1,936 0.8
Total Non-OECD 1,466 1,514 1,590 1,862 2,091 2,343 2,595 2,841 2.2
Total World 2,946 3,039 3,133 3,484 3,775 4,087 4,437 4,774 1.6
EIA 2011 projections
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Consumption of Coal (Mtoe)
Consumption of Nuclear Energy (Billion kilowatt hours)
Region/Country History Projections Annual
growth (%) 2006 2007 2008 2015 2020 2025 2030 2035
United States 567 572 564 496 524 570 590 612 0.3
Canada 35 35 35 25 25 25 25 28 -0.7
Japan 116 123 121 116 111 106 101 96 -0.8
South Korea 53 58 66 66 66 71 78 86 1.0
Australia/New Zealand 60 63 66 63 63 63 63 63 -0.1
Russia 111 106 113 113 108 108 113 123 0.3
China 1,290 1,391 1,522 2,034 2,155 2,429 2,684 2,863 2.4
India 232 255 275 312 343 386 436 491 2.2
Brazil 10 13 13 20 23 28 35 48 5.2
Total OECD 1,179 1,205 1,179 1,074 1,086 1,124 1,142 1,177 0.0
Total Non-OECD 2,026 2,157 2,323 2,890 3,059 3,405 3,765 4,095 2.1
Total World 3,205 3,359 3,503 3,964 4,148 4,528 4,906 5,269 1.5
Region/Country History Projections Annual
growth (%) 2006 2007 2008 2015 2020 2025 2030 2035
United States /a 787 806 806 839 877 877 877 874 0.3
Canada 93 89 89 113 131 134 152 162 2.2
Japan 288 251 245 319 342 358 388 417 2.0
South Korea 141 136 143 183 218 233 253 266 2.3
Australia/New Zealand 0 0 0 0 0 0 0 0 0.0
Russia 144 152 154 197 275 342 366 388 3.5
China 55 63 65 223 419 585 749 916 10.3
India 16 16 13 66 119 157 187 211 10.8
Brazil 14 12 14 18 22 31 31 41 4.1
Total OECD 2,255 2,176 2,175 2,430 2,576 2,680 2,799 2,873 1.0
Total Non-OECD 405 422 427 748 1,154 1,508 1,747 2,043 6.0
Total World 2,660 2,598 2,602 3,178 3,731 4,188 4,546 4,916 2.4
EIA 2011 projections
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C o n s u m p t i o n o f Hydroelectricity and other renewable energy (Mtoe)
South Korea 3 3 3 5 5 5 8 8 3.0
Australia/New Zealand 18 18 18 30 35 35 38 40 3.3
Russia 48 48 43 53 55 63 71 78 2.1
China 118 134 161 282 398 449 496 549 4.6
India 60 63 60 88 118 134 151 169 3.9
Brazil 139 149 151 181 207 244 290 330 2.9
Total OECD 514 522 557 738 847 935 993 1,043 2.4
Total Non-OECD 675 701 736 990 1,225 1,376 1,542 1,716 3.2
Total World 1,187 1,222 1,293 1,726 2,071 2,311 2,535 2,759 2.9
Region/Country History Projections Annual
growth (%) 2006 2007 2008 2015 2020 2025 2030 2035
United States /a 161 156 176 217 239 267 285 297 1.9
Canada 93 98 101 108 123 131 144 151 1.5
Japan 30 28 28 40 50 55 58 60 2.9
EIA 2011 projections
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EIA 2011 projections
End use energy consumption in India (Mtoe)
Sector Fuel
2008
Projections Annual Growth (%)2015 2020 2025 2030 2035
Res
iden
tial
Liquids 22.7 27.7 25.2 25.2 22.7 22.7 -0.2 Natural gas 0.0 0.0 0.0 2.5 2.5 2.5 3.1
Coal 5.0 5.0 5.0 5.0 7.6 7.6 2.3
Electricity 12.6 30.2 37.8 45.4 52.9 60.5 6.1
Renewables 0.0 0.0 0.0 0.0 0.0 0.0 —
Total 40.3 60.5 70.6 78.1 85.7 90.7 3.1
Co
mm
erci
al
Liquids 0.0 0.0 0.0 0.0 0.0 0.0 —
Natural gas
0.0
0.0
0.0
0.0
0.0
0.0
—
Coal
5.0
5.0
7.6
7.6
10.1
10.1
2.9
Electricity
5.0
10.1
12.6
15.1
20.2
22.7
6.1 Renewables
0.0
0.0
0.0
0.0
0.0
0.0
—
Total
10.1
15.1
20.2
22.7
27.7
32.8
4.8
Ind
ust
rial
Liquids
75.6
85.7
100.8
115.9
133.6
148.7
2.6 Natural gas
22.7
35.3
40.3
45.4
47.9
50.4
3.2
Coal
95.8
110.9
131.0
148.7
168.8
186.5
2.5 Electricity
32.8
37.8
45.4
52.9
60.5
68.0
2.7
Renewables
30.2
35.3
40.3
45.4
50.4
55.4
2.3 Total
257.0
307.4
357.8
408.2
461.2
511.6
2.6
Tran
spo
rtat
ion
Liquids
47.9
75.6
103.3
151.2
186.5
209.2
5.6
Natural gas 2.5 2.5 2.5 2.5 5.0 5.0 2.9
Coal 0.0 0.0 0.0 0.0 0.0 0.0 —
Electricity 0.0 2.5 2.5 2.5 5.0 5.0 5.4
Renewables 0.0 0.0 0.0 0.0 0.0 0.0 —
Total 50.4 80.6 110.9 156.2 196.6 219.2 5.5
All
end
-use
sec
tors
Liquids 146.2 189.0 231.8 289.8 342.7 380.5 3.6
Natural gas 25.2 40.3 45.4 47.9 52.9 58.0 3.2
Coal 105.8 121.0 143.6 163.8 184.0 204.1 2.5
Electricity
50.4
78.1
98.3
118.4
138.6
156.2
4.2
Renewables
30.2
35.3
40.3
45.4
50.4
55.4
2.3
Delivered
energy
357.8
463.7
556.9
665.3
771.1
854.3
3.3
Electricity-related losses 173.9
236.9
277.2
312.5
345.2
385.6
3.0
Total
531.7
700.6
834.1
980.3
1,116.4
1,239.8
3.2
Elec
tric
Po
wer
Liquids
5.0
5.0
5.0
5.0
5.0
5.0
-1.0
Natural gas
17.6
47.9
60.5
73.1
78.1
80.6
6.0
Coal
168.8
189.0
199.1
224.3
252.0
287.3
2.0
Nuclear
5.0
17.6
32.8
42.8
50.4
55.4
10.2
Renewables
30.2
55.4
78.1
88.2
100.8
113.4
5.0
Total
226.8
315.0
375.5
430.9
483.8
541.8
3.3
Tota
l En
ergy
C
on
sum
pti
on
Liquids
151.2
194.0
236.9
294.8
347.8
385.6
3.5
Natural gas
40.3
88.2
105.8
121.0
131.0
136.1
4.6
Coal
274.7
312.5
342.7
385.6
436.0
491.4
2.2
Nuclear
5.0
17.6
32.8
42.8
50.4
55.4
10.2
Renewables 60.5 88.2 118.4 133.6 151.2 168.8 3.9
Total 531.7 700.6 834.1 980.3 1,116.4 1,239.8 3.2
IND
IA E
NER
GY
BO
OK
20
12
EIA 2011 projections
End use energy consumption in world
Sector Fuel 2008
Projections Annual
Growth
(%)
2015 2020 2025 2030 2035
Resi
dent
ial
Liquids
247.0
244.4
229.3
224.3
221.8
221.8
-0.4
Natural gas
524.2
562.0
587.2
612.4
625.0
640.1
0.8
Coal
110.9
113.4
115.9
115.9
113.4
110.9
0.0
Electricity
408.2
488.9
554.4
622.4
693.0
763.6
2.3
Renewables 10.1 10.1 10.1 10.1 10.1 10.1 -0.2
Total 1,302.8 1,416.2 1,496.9 1,585.1 1,665.7 1,746.4 1.1
Com
mer
cial
Liquids
115.9
108.4
105.8
103.3
103.3
103.3
-0.4
Natural gas 209.2 231.8 241.9 252.0 259.6 267.1 0.9
Coal
30.2
32.8
32.8
35.3
35.3
37.8
0.7
Electricity
347.8
428.4
486.4
546.8
602.3
650.2
2.3
Renewables
2.5
2.5
2.5
2.5
2.5
2.5
0.1
Total 708.1 803.9 871.9 940.0 1,005.5 1,060.9 1.5
Indu
stri
al
Liquids 1,393.6 1,449.0 1,491.8 1,559.9 1,640.5 1,728.7 0.8
Natural gas
1,108.8
1,252.4
1,368.4
1,481.8
1,610.3
1,751.4
1.7
Coal
1,255.0
1,542.2
1,625.4
1,731.2
1,822.0
1,902.6
1.6
Electricity
703.1
816.5
914.8
1,035.7
1,161.7
1,295.3
2.3
Renewables
357.8
388.1
433.4
488.9
539.3
584.6
1.8
Total
4,820.8
5,448.2
5,833.8
6,297.5
6,773.8
7,262.6
1.5
Tran
spor
tati
on
Liquids
2,356.2
2,691.4
2,887.9
3,122.3
3,29 3.6
3,429.7
1.4
Natural gas 90.7 93.2 95.8 98.3 105.8 115.9 0.9
Coal 5.0 5.0 2.5 0.0 0.0 0.0 —
Electricity
22.7
30.2
30.2
32.8
37.8
35.3
1.6
Renewables
0.0
0.0
0.0
0.0
0.0
0.0
—
Total
2,474.6
2,819.9
3,021.5
3,253.3
3,439.8
3,580.9
1.4
All
end-
use
sect
ors
Liquids
4,115.2
4,490.6
4,714.9
5,009.8
5,259.2
5,486.0
1.1
Natural gas
1,935.4
2,137.0
2,293.2
2,441.9
2,603.2
2,774.5
1.3
Coal 1,401.1 1,696.0 1,779.1 1,882.4 1,970.6 2,048.8 1.4
Electricity
1,484.3
1,766.5
1,988.3
2, 240.3
2,497.3
2,744.3
2.3
Renewables 373.0 400.7 446.0 501.5 551.9 597.2 1.8
Delivered energy
9,308.9
10,490.8
11,224.1 12,075.8 12,884.8 13,650.8 1.4
Electricity-related losses
3,409.6
3,961.4
4,387.3
4,846.0
5,297.0
5,748.1
2.0
Total 12,718.4 14,452.2 15,611.4 16,921.8 18,181.8 19,399.0 1.6
Elec
tric
Pow
er
Liquids 244.4 226.8 216.7 206.6 196.6 189.0 -0.9
Natural gas 945.0 1,071.0 1,184.4 1,323.0 1,486.8 1,627.9 2.0
Coal 2,101.7 2,268.0 2,368.8 2,646.0 2,933.3 3,220.6 1.6
Nuclear 685.4 834.1 980.3 1,101.2 1,194.5 1,290.2 2.4
Renewables 919.8 1,325.5 1,625.4 1,806.8 1,983.2 2,162.2 3.2
Total 4,896.4 5,728.0 6,375.6 7,083.7 7,794.4 8,492.4 2.1
Tota
lEn
ergy
Consum
ption
Liquids 4,359.6 4,717.4 4,934.2 5,216.4 5,45 8.3 5,675.0 1.0
Natural gas 2,880.4 3,208.0 3,477.6 3,764.9 4,090.0 4,402.4 1.6
(Mtoe)
Coal
Nuclear
Renewables
Total
3,502.8 3,964.0 4,147.9 4,528.4 4,906.4 5,269.3 1.5 685.4 834.1 980.3 1,101.2 1,194.5 1,290.2 2.4
1,292.8 1,726.2 2,071.4 2,310.8 2,535.1 2,759.4 2.9
12,718.4 14,452.2 15,611.4 16,921.8 18,181.8 19,399.0 1.6
135
INTER
NA
TION
AL EN
ERG
Y O
UTLO
OK
20
11
IND
IA EN
ERG
Y BO
OK
20
12
136
INTE
RN
ATI
ON
AL
ENER
GY
OU
TLO
OK
20
11
End use energy consumption in OECD
(Mtoe)
Sector Fuel
2008
Projections Annual
Growth
(%)
2015 2020 2025 2030 2035
Resi
dent
ial
Liquids 113.4 98.3 95.8 93.2 90.7 90.7 -0.8
Natural gas 302.4 310.0 312.5 310.0 304.9 299.9 0.0
Coal
17.6
15.1
15.1
12.6
12.6
10.1
-1.4
Electricity
254.5
272.2
289.8
304.9
320.0
335.2
1.0
Renewables
10.1
10.1
10.1
10.1
10.1
10.1
-0.2
Total 698.0 705.6 720.7 733.3 740.9 748.4 0.3
Com
mer
cial
Liquids
75.6
63.0
63.0
63.0
63.0
63.0
-0.7
Natural gas
166.3
178.9
184.0
184.0
184.0
186.5
0.4
Coal
5.0
5.0
5.0
5.0
5.0
5.0
-1.0
Electricity 252.0 282.2 304.9 327.6 352.8 378.0 1.5
Renewables
2.5
2.5
2.5
2.5
2.5
2.5
0.1
Total
504.0
531.7
559.4
582.1
607.3
632.5
0.8
Indu
stria
l
Liquids
708.1
660.2
680.4
690.5
695.5
705.6
0.0
Natural gas
481.3
509.0
534.2
551.9
577.1
604.8
0.9
Coal 231.8 216.7 216.7 221.8 226.8 231.8 0.0
Electricity
287.3
289.8
310.0
327.6
345.2
362.9
0.9
Renewables
133.6
136.1
153.7
176.4
191.5
201.6
1.6
Total 1,839.6 1,814.4 1,895.0 1,968.1 2,033.6 2,106.7 0.5
Tran
spor
tatio
n
Liquids
1,459.1 1,479.2 1,501.9 1,524.6 1,554.8 1,595.2 0.3
Natural gas
25.2 30.2
27.7
25.2
27.7
27.7
0.5
Coal 0.0 0.0 0.0 0.0 0.0 0.0 —
Electricity
10.1 12.6
10.1
10.1
12.6
12.6
0.6
Renewables
0.0 0.0
0.0
0.0
0.0
0.0
—
Total 1,494.4 1,522.1 1,542.2 1,559.9 1,592.6 1,633.0 0.3
All e
nd-u
se s
ecto
rs
Liquids
2,356.2 2,300.8 2,341.1 2,371.3 2,404.1 2,452.0 0.2
Natural gas 972.7 1,028.2 1,058.4 1,071.0 1,093.7 1,116.4 0.5
Coal 252.0 236.9 234.4 239.4 241.9 249.5 -0.1
Electricity 806.4 859.3 914.8 972.7 1,030.7 1,088.6 1.1
Renewables 146.2 148.7 166.3 189.0 204.1 214.2 1.4
Delivered energy 4,536.0 4,573.8 4,714.9 4,843.4 4,974.5 5,120.60.5
Electricity-related losses
1,617.8 1,736.3 1,849.7 1,953.0 2,048.8 2,142.0 1.0
Total 6,156.4 6,310.1 6,567.1 6,799.0 7,023.2 7,262.6 0.6
Electr
icPo
wer Liquids 75.6 70.6 68.0 65.5 63.0 60.5 -0.8
Natural gas 443.5 463.7 491.4 529.2 597.2 660.2 1.5
Coal 924.8 836.6 851.8 884.5 897.1 927.4 0.0
Nuclear 569.5 635.0 672.8 700.6 733.3 751.0 1.0
Renewables 410.8 589.7 682.9 745.9 788.8 829.1 2.6
Total 2,424.2 2,595.6 2,767.0 2,925.7 3,079.4 3,228.1 1.1
Liquids 2,431.8 2,371.3 2,409.1 2,436.8 2,467.1 2,512.4 0.1 Natural gas 1,418.8 1,491.8 1,547.3 1,602.7 1,690.9 1,779.1 0.8 Coal 1,179.4 1,073.5 1,086.1 1,123.9 1,141.6 1,176.8 0.0
Nuclear 569.5 635.0 672.8 700.6 733.3 751.0 1.0
Renewables 556.9 738.4 846.7 934.9 992.9 1,043.3 2.4
Total 6,156.4 6,310.1 6,567.1 6,799.0 7,023.2 7,262.6 0.6
Tota
l En
erg
y C
on
sum
pti
on
EIA 2011 projections
IND
IA E
NER
GY
BO
OK
20
12
EIA 2011 projections
End use energy consumption in Non OECD
Sector Fuel
2008
Projections Annual
Growth
(%)
2015 2020 2025 2030 2035
Resi
dent
ial
Liquids 133.6 146.2 133.6 131.0 131.0 131.0 -0.1
Natural gas
221.8
252.0
274.7
299.9
320.0
340.2
1.6
Coal
95.8
98.3
100.8
100.8
100.8
98.3
0.2
Electricity 153.7 216.7 267.1 320.0 373.0 425.9 3.9
Renewables 0.0 0.0 0.0 0.0 0.0 0.0 —
Total
604.8
713.2
776.2
851.8
924.8
997.9
1.9
Com
mer
cial
Liquids
42.8
45.4
42.8
40.3
40.3
40.3
0.0
Natural gas 42.8 52.9 58.0 68.0 75.6 80.6 2.4
Coal
25.2
27.7
27.7
30.2
30.2
32.8
1.0
Electricity
95.8
148.7
181.4
216.7
249.5
274.7
4.0
Renewables 0.0 0.0 0.0 0.0 0.0 0.0 —
Total 204.1 272.2 312.5 357.8 398.2 430.9 2.8
Indu
stria
l
Liquids
685.4
786.2
811.4
866.9
945.0
1,023.1
1.5
Natural gas
630.0
740.9
834.1
929.9
1,035.7
1,149.1
2.3
Coal
1,025.6 1,328.0 1,411.2 1,509.5
1,595.2
1,668.2
1.8
Electricity 415.8 526.7 604.8 708.1 819.0 932.4 3.0
Renewables
224.3
252.0
282.2
312.5
347.8
383.0
2.0
Total 2,981.2 3,633.8 3,938.8 4,329.4 4,740.1 5,153.4 2.1
Tran
spor
tatio
n
Liquids
897.1
1,212.1
1,388.5
1,597.7
1,738.8
1,837.1
2.7
Natural gas 65.5 63.0 68.0 73.1 80.6 85.7 1.0
Coal
2.5
5.0
2.5
0.0
0.0
0.0
-23.5
Electricity
12.6
17.6
20.2
22.7
27.7
25.2
2.2
Renewables
0.0
0.0
0.0
0.0
0.0
0.0
—
Total
980.3
1,300.3
1,479.2
1,693.4
1,847.2
1,948.0
2.6
All e
nd-u
se se
ctor
s
Liquids 1,759.0 2,189.9 2,373.8 2,638.4 2,855.2 3,034.1 2.0
Natural gas
960.1 1,108.8 1,237.3 1,370.9 1,509.5 1,655.6 2.0
Coal
1,149.1 1,459.1 1,544.8 1,643.0 1,728.7 1,799.3 1.7
Electricity 677.9 907.2 1,071.0 1,267.6 1,466.6 1,658.2 3.4
Renewables 224.3 252.0 282.2 312.5 347.8 383.0 2.0
Delivered energy 4,772.9 5,917.0 6,509.2 7,232.4 7,907.8 8,530.2 2.2
Electricity-related losses
1,791.7 2,222.6 2,535.1 2,890.4 3,248.3 3,606.1 2.6
Total 6,564.6 8,142.1 9,044.3 10,122.8 11,158.6 12,136.3 2.3
Elec
tric
Pow
erTo
tal E
nerg
y
(Mtoe)
Liquids 168.8 156.2 148.7 141.1 133.6 128.5 -1.0Natural gas 501.5 604.8 693.0 793.8 889.6 967.7 2.5Coal 1,174.3 1,431.4 1,517.0 1,761.5 2,036.2 2,295.7 2.5Nuclear 115.9 199.1 307.4 398.2 461.2 539.3 5.9Renewables 509.0 738.4 942.5 1,063.4 1,194.5 1,333.1 3.6Total 2,469.6 3,129.8 3,608.6 4,158.0 4,717.4 5,264.3 2.8Liquids 1,925.3 2,346.1 2,522.5 2,779.6 2,991.2 3,162.6 1.9Natural gas 1,461.6 1,716.1 1,930.3 2,164.7 2,399.0 2,623.3 2.2Coal 2,323.4 2,890.1 3,059.3 3,404.5 3,764.9 4,095.0 2.1Nuclear 115.9 199.1 307.4 398.2 461.2 539.3 5.9Renewables 735.8 990.4 1,224.7 1,375.9 1,542.2 1,716.1 3.2Total 6,564.6 8,142.1 9,044.3 10,122.8 11,158.6 12,136.3 2.3C
on
sum
pti
on
137
INTER
NA
TION
AL EN
ERG
Y O
UTLO
OK
20
11
IND
IA EN
ERG
Y BO
OK
20
12
138
INTE
RN
ATI
ON
AL
ENER
GY
OU
TLO
OK
20
11
EIA 2011 projections
End use energy consumption in USA
Sector Fuel 2008
Projections AnnualGrowth
(%)
2015 2020 2025 2030 2035
Resi
dent
ial
Liquids
30.2
27.7
25.2
22.7
22.7
22.7
-1.2
Natural gas
126.0
123.5
126.0
126.0
126.0
123.5
-0.1
Coal
0.0
0.0
0.0
0.0
0.0
0.0
-1.6
Electricity 118.4 115.9 121.0 126.0 131.0 138.6 0.6
Renewables 10.1 10.1 10.1 10.1 10.1 10.1 -0.2
Total
287.3
277.2
282.2
284.8
289.8
294.8
0.1
Com
mer
cial
Liquids
15.1
12.6
12.6
12.6
12.6
12.6
-0.7
Natural gas
80.6
88.2
90.7
93.2
95.8
98.3
0.7
Coal
2.5
2.5
2.5
2.5
2.5
2.5
-0.6
Electricity
115.9
121.0
131.0
141.1
151.2
161.3
1.3
Renewables 2.5 2.5 2.5 2.5 2.5 2.5 0.1
Total 216.7 226.8 239.4 249.5 264.6 279.7 0.9
Indu
stri
al
Liquids
224.3
234.4
231.8
231.8
226.8
224.3
0.0
Natural gas
204.1
239.4
244.4
239.4
239.4
239.4
0.6
Coal
45.4
42.8
42.8
47.9
55.4
65.5
1.4
Electricity
85.7
88.2
90.7
88.2
85.7
83.2
-0.2
Renewables
63.0
68.0
80.6
100.8
110.9
115.9
2.3
Total
622.4
672.8
688.0
708.1
718.2
728.3
0.6
Tran
spor
tati
on
Liquids 685.4 700.6 710.6 725.8 748.4 778.7 0.5
Natural gas 17.6 17.6 17.6 17.6 20.2 20.2 0.7
Coal
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Electricity
0.0
0.0
0.0
0.0
2.5
2.5
4.4
Renewables
0.0
0.0
0.0
0.0
0.0
0.0
—
Total
705.6
718.2
730.8
745.9
768.6
801.4
0.5
All
end-
use
sect
ors
Liquids 957.6 975.2 980.3 992.9 1,010.5 1,038.2 0.3
Natural gas
428.4
468.7
478.8
476.3
481.3
483.8
0.5
Coal
47.9
42.8
45.4
50.4
58.0
68.0
1.3
Electricity
320.0
327.6
342.7
355.3
370.4
385.6
0.7
Renewables
75.6
83.2
93.2
113.4
123.5
128.5
1.9
Delivered energy 1,829.5 1,897.6 1,940.4 1,988.3 2,043.7 2,104.2 0.5
Electricity-related losses
693.0
672.8
705.6
730.8
753.5
773.6
0.4
Total 2,522.5 2,570.4 2,643.5 2,721.6 2,797.2 2,877.8 0.5
Elec
tric
Pow
er
Liquids
12.6
10.1
10.1
12.6
12.6
12.6
0.0
Natural gas 171.4 181.4 176.4 171.4 189.0 204.1 0.6
Coal 516.6 453.6 481.3 519.1 531.7 544.3 0.2
Nuclear 211.7 221.8 231.8 231.8 231.8 229.3 0.3
Renewables 100.8 136.1 146.2 153.7 161.3 168.8 2.0
Total 1,013.0 1,000.4 1,045.8 1,088.6 1,123.9 1,159.2 0.5
(Mtoe)To
tal E
nerg
y Co
nsum
ptio
n
Liquids 970.2 985.3 992.9 1,003.0 1,023.1 1,050.8 0.3
Natural gas 599.8 650.2 655.2 647.6 670.3 685.4 0.5
Coal 564.5 496.4 524.2 569.5 589.7 612.4 0.3
Nuclear 211.7 221.8 231.8 231.8 231.8 229.3 0.3
Renewables 176.4 216.7 239.4 267.1 284.8 297.4 1.9
Total 2,522.5 2,570.4 2,643.5 2,721.6 2,797.2 2,877.8 0.5
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EIA 2011 projections
End use energy consumption in China
Sector Fuel
2008
Projections Annual Growth (%)
2015 2020 2025 2030 2035
Liquids
25.2
27.7
25.2 22.7
22.7
20.2
-1.0
Natural gas 17.6 35.3 47.9 63.0 78.1 88.2 6.3
Coal 73.1 75.6 75.6 75.6 75.6 73.1 -0.1
Electricity 37.8 63.0 83.2 105.8 131.0 156.2 5.4
Renewables
0.0
0.0
0.0 0.0
0.0
0.0
—
Total
153.7
201.6
231.8 269.6
304.9
337.7
2.9
Com
mer
cial
Liquids
22.7
25.2
22.7 20.2
20.2
20.2
-0.7
Natural gas 10.1 17.6 22.7 30.2 35.3 42.8 5.8
Coal 12.6 12.6 12.6 12.6 12.6 12.6 0.2
Electricity
12.6
45.4
58.0 70.6
73.1
65.5
6.2
Renewables
0.0
0.0
0.0 0.0
0.0
0.0
—
Total
58.0
100.8
115.9 133.6
141.1
138.6
3.4
Liquids 173.9 199.1 206.6 229.3 254.5 277.2 1.7
Natural gas 37.8 50.4 63.0 78.1 95.8 110.9 4.1
Coal
708.1
985.3
1,033.2 1,098.7 1,146.6 1,181.9 1.9
Electricity
206.6
292.3
337.7 405.7
476.3
544.3
3.7
Renewables 5.0 7.6 10.1 10.1 12.6 15.1 3.1
Total 1,131.5 1,534.7 1,648.1 1,824.5 1,985.8 2,129.4 2.4
Tran
spor
tatio
n
Liquids
171.4
360.4
441.0 521.6
539.3
546.8
4.4
Natural gas
0.0
0.0
0.0 0.0
0.0
0.0
5.6
Coal
2.5
5.0
2.5 0.0
0.0
0.0
—
Electricity
2.5
5.0
7.6 7.6
10.1
7.6
4.3
Renewables
0.0
0.0
0.0 0.0
0.0
0.0
—
Total
178.9
373.0
453.6 531.7
551.9
556.9
4.3
All
end-
use
sect
ors
Liquids
395.6
612.4
695.5 793.8
836.6
864.4
2.9
Natural gas 63.0 105.8 133.6 171.4 209.2 244.4 5.1
Coal
796.3
1,078.6
1,123.9 1,186.9
1,234.8
1,265.0
1.7
Electricity
259.6
405.7
488.9 592.2
690.5
773.6
4.1
Renewables
5.0
7.6
10.1 10.1
12.6
15.1
3.1
Delivered energy
1,522.1 2,210.0 2,449.4 2,756.9 2,983.7 3,160.1 2.7
Electricity-related losses
647.6 919.8 1,091.2 1,297.8 1,496.9 1,660.7 3.6
Total 2,172.2 3,129.8 3,543.1 4,054.7 4,483.1 4,823.3 3.0
Elec
tric
Po
wer
Liquids 2.5 2.5 2.5 2.5 2.5 2.5 -0.8
Natural gas 7.6 35.3 45.4 52.9 58.0 60.5 7.9
Coal 723.2 955.1 1,030.7 1,242.4 1,449.0 1,597.7 3.0
Nuclear 17.6 58.0 108.4 153.7 196.6 239.4 10.4
(Mtoe)
Renewables 156.2 274.7 390.6 436.0 483.8 534.2 4.7
Total 907.2 1,325.5 1,580.0 1,887.5 2,187.4 2,434.3 3.7Liquids 400.7 617.4 698.0 796.3 839.2 866.9 2.9Natural gas 70.6 141.1 178.9 226.8 267.1 304.9 5.5
Coal 1,522.1 2,033.6 2,154.6 2,429.3 2,683.8 2,862.7 2.4
Nuclear 17.6 58.0 108.4 153.7 196.6 239.4 10.4
Renewables 161.3 282.2 398.2 448.6 496.4 549.4 4.6
Total 2,172.1 3,129.8 3,543.1 4,054.7 4,483.1 4,823.3 3.0
Tota
l Ene
rgy
Cons
umpt
ion
Indu
stri
alRe
side
ntia
l
139
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140
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EIA 2011 projections World total Installed generation Capacity and net electricity generation
World total installed generating capacity
(Gigawatts)
Region/Country History Projections Annual
Growth(%)
2008 2015 2020 2025 2030 2035
United States 1,009 1,075 1,085 1,119 1,170 1,221 0.7
Canada 128 136 143 153 167 180 1.3
Japan 281 283 288 294 299 306 0.3
South Korea 80 89 95 103 111 119 1.5
Australia/New Zealand 65 72 77 79 82 85 1.0
Russia 224 227 235 242 258 277 0.8
China 797 1,118 1,313 1,492 1,666 1,817 3.1
India 177 240 290 332 371 411 3.2
Brazil 104 122 144 172 205 242 3.2
Total OECD 2,495 2,684 2,798 2,917 3,047 3,181 0.9
Total Non-OECD 2,128 2,628 2,998 3,352 3,722 4,091 2.5
Total world 4,623 5,312 5,796 6,269 6,769 7,272 1.7
World total net electricity generation
(Billion kilowatthours)
Region/Country History Projections Annual
Growth (%)
2008 2015 2020 2025 2030 2035
United States 4,122 4,253 4,453 4,682 4,930 5,167 0.8
Canada 632 622 695 756 828 908 1.4
Japan 1,017 1,072 1,117 1,160 1,204 1,248 0.8
South Korea 419 482 530 590 651 714 2.0
Australia/New Zealand 285 319 345 364 383 401 1.3
Russia 985 1,028 1,080 1,166 1,284 1,423 1.4
China 3,221 5,011 6,041 7,322 8,562 9,583 4.1
India 786 1,181 1,444 1,701 1,942 2,196 3.9
Brazil 455 544 661 801 969 1,178 3.6
Total OECD 10,220 10,880 11,609 12,371 13,157 13,948 1.2
Total Non-OECD 8,904 11,772 13,852 16,294 18,786 21,227 3.3
Total world 19,125 22,652 25,462 28,665 31,943 35,175 2.3
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EIA 2011 projections
World Gas based generation Capacity and net electricity generation
World Gas based installed generating capacity
Region/Country History Projections Annual
Growth (%)
2008 2015 2020 2025 2030 2035
338 368 373 395 436 482 1.3
16 15 14 18 20 24 1.5
79 74 74 76 78 78 -0.1
24 26 28 31 33 33 1.1
14 15 17 20 23 25 2.3
97 91 87 84 91 96 -0.1
31 52 58 64 67 68 2.9
19 42 52 62 65 67 4.9
9 12 19 23 28 43 6.0
690 720 744 797 876 959 1.2
499 575 642 722 800 866 2.1
United States
Canada
Japan
South Korea
Australia/New Zealand
Russia
China
India
Brazil
Total OECD
Total Non-OECD
Total world 1,189 1,295 1,386 1,519 1,676 1,825 1.6
(Gigawatts)
World Gas based net electricity generation
Region/Country History Projections Annual
Growth (%)
2008 2015 2020 2025 2030 2035
United States 882 1,000 1,002 1,003 1,152 1,288 1.4
Canada 40 37 39 69 79 108 3.8
Japan 273 255 268 292 311 320 0.6
South Korea 79 99 112 137 149 153 2.5
Australia/New Zealand 48 57 77 102 123 139 4.0
Russia 472 445 424 414 463 504 0.2
China 31 182 234 281 305 315 9.0
India 81 242 311 374 399 410 6.2
Brazil 28 51 98 123 163 264 8.7
Total OECD 2,310 2,501 2,668 2,922 3,359 3,777 1.8
Total Non-OECD 1,848 2,448 2,961 3,548 4,117 4,594 3.4
Total world 4,158 4,948 5,629 6,470 7,476 8,371 2.6
(Billion kilowatthours)
141
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RN
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GY
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EIA 2011 projections
World Coal based generation Capacity and net electricity generation
World Coal based net electricity generation (Billion Kilowatthours)
Region/Country History Projections Annual
Growth (%)
2008 2015 2020 2025 2030 2035
United States 1,987 1,799 1,907 2,069 2,138 2,218 0.4
Canada 104 76 73 76 76 88 -0.6
Japan 265 250 241 233 227 225 -0.6
South Korea 178 170 169 186 214 257 1.4
Australia/New Zealand 188 178 171 166 160 158 -0.7
Russia 179 169 163 158 180 229 0.9
China 2,566 3,518 3,858 4,775 5,674 6,330 3.4
India 537 637 681 800 938 1,111 2.7
Brazil 12 20 20 20 20 2 3.2
Total OECD 3,605 3,320 3,379 3,525 3,609 3,779 0.2
Total Non-OECD 4,087 5,173 5,566 6,659 7,901 9,088 3.0
Total world 7,692 8,492 8,946 10,184 11,510 12,867 1.9
based installed generating capacity World Coal (Gigawatts)
Region/Country History Projections Annual
Growth(%)
2008 2015 2020 2025 2030 2035
United States 313 322 323 326 329 334 0.2
Canada 16 12 12 12 12 13 -0.8
Japan 48 45 44 42 41 40 -0.7
South Korea 27 26 26 28 31 37 1.2
Australia/New Zealand 31 30 28 27 27 26 -0.7
Russia 50 47 46 44 46 52 0.1
China 557 695 733 848 962 1,043 2.4
India 99 111 116 131 149 171 2.0
Brazil 2 3 4 4 4 4 2.8
Total OECD 641 632 622 618 620 633 0.0
Total Non-OECD 862 1,014 1,056 1,191 1,347 1,496 2.1
Total world 1,503 1,646 1,677 1,810 1,968 2,129 1.3
IND
IA E
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BO
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EIA 2011 projections World Nuclear generation Capacity and net electricity generation
World Nuclear installed generating capacity (Gigawatts)
Region/Country History Projections Annual
Growth(%)
2008 2015 2020 2025 2030 2035
United States 101 106 111 111 111 111 0.4
Canada 13 15 18 18 20 22 1.8
Japan 48 52 55 56 59 61 0.9
South Korea 18 23 27 29 31 33 2.3
Australia/New Zealand 0 0 0 0 0 0 0.0
Russia 23 28 39 47 49 52 3.0
China 9 30 55 75 95 115 9.9
India 4 9 16 21 25 28 7.4
Brazil 2 3 3 4 4 5 3.7
Total OECD 313 331 349 360 373 379 0.7
Total Non-OECD 65 104 157 201 230 265 5.3
Total world 378 436 505 561 603 644 2.0
Region/Country History Projections Annual
Growth (%)
2008 2015 2020 2025 2030 2035
United States 806 839 877 877 877 874 0.3
Canada 89 113 131 134 152 162 2.2
Japan 245 319 342 358 388 417 2.0
South Korea 143 183 218 233 253 266 2.3
Australia/New Zealand 0 0 0 0 0 0 —
Russia 154 197 275 342 366 388 3.5
China 65 223 419 585 749 916 10.3
India 13 66 119 157 187 211 10.8
Brazil 14 18 22 31 31 41 4.0
Total OECD 2,175 2,430 2,576 2,680 2,799 2,873 1.0
Total Non-OECD 428 748 1,154 1,508 1,747 2,043 6.0
Total world 2,602 3,178 3,731 4,188 4,546 4,916 2.4
World nuclear net electricity generation (Billion Kilowatthours)
143
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144
INTE
RN
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EIA 2011 projections
World hydrogeneration Capacity and net electricity generation
World Hydro installed generating capacity
World hydro net electricity generation
(Gigawatts)
(Billion kilowatthours)
Region/Country History Projections Annual
Growth(%)
2008 2015 2020 2025 2030 2035
United States 78 78 78 79 80 81 0.1
Canada 74 78 81 86 95 100 1.1
Japan 22 24 24 24 24 24 0.4
South Korea 2 2 2 2 2 2 0.1
Australia/New Zealand 13 13 13 13 14 14 0.3
Russia 47 53 57 61 66 72 1.6
China 172 247 318 327 335 360 2.8
India 39 56 80 85 96 106 3.8
Brazil 78 89 104 127 154 173 3.0
Total OECD 355 371 389 406 421 432 0.7
Total Non-OECD 502 654 806 866 941 1,031 2.7
Total world 857 1,025 1,195 1,272 1,362 1,463 2.0
Region/Country History Projections Annual
Growth(%)
2008 2015 2020 2025 2030 2035
United States 256 297 305 309 312 314 0.8
Canada 379 374 398 421 462 486 0.9
Japan 75 88 93 93 93 95 0.9
South Korea 3 4 4 4 4 4 1.2
Australia/New Zealand 34 40 41 41 42 44 1.0
Russia 163 199 202 235 259 286 2.1
China 522 810 1,067 1,097 1,127 1,215 3.2
India 113 174 260 279 319 356 4.3
Brazil 366 416 483 585 707 792 2.9
Total OECD 1,329 1,418 1,520 1,600 1,668 1,717 1.0
Total Non-OECD 1,791 2,363 2,946 3,224 3,536 3,903 2.9
Total world 3,121 3,781 4,465 4,823 5,204 5,620 2.2 IND
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EIA 2011 projections World wind generation Capacity and net electricity generation
World wind-powered installed generating capacity
Region/Country History Projections Annual
Growth(%)
2008 2015 2020 2025 2030 2035
United States 25 51 51 54 55 57 3.1
Canada 2 11 13 14 15 17 7.5
Japan 2 4 5 8 8 8 5.6
South Korea 0 1 2 2 3 4 9.9
Australia/New Zealand 2 8 11 11 11 11 6.2
Russia 0 0 0 0 0 0 0.1
China 12 62 99 119 139 156 9.9
India 10 14 16 20 22 24 3.3
Brazil 0 2 2 3 3 4 8.5
Total OECD 97 204 267 300 315 330 4.7
Total Non-OECD 24 88 130 157 181 203 8.2
Total world 121 293 398 456 496 533 5.7
World wind-powered net electricity generation
Region/Country History Projections Annual
Growth(%)
2008 2015 2020 2025 2030 2035
United States 56 145 145 154 159 163 4.1
Canada 4 6 37 39 42 46 9.9
Japan 2 7 13 20 20 20 8.1
South Korea 0 3 5 6 8 11 12.9
Australia/New Zealand 5 21 30 30 31 32 7.3
Russia 0 0 0 0 0 0 1.1
China 12 161 273 334 394 447 14.2
India 13 24 31 44 50 56 5.5
Brazil 1 5 5 6 7 9 10.8
Total OECD 181 492 689 806 852 898 6.1
Total Non-OECD 29 219 347 426 499 564 11.6
Total world 210 710 1,035 1,232 1,350 1,462 7.5
(Gigawatts)
(Billion kilowatthours)
145
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EIA 2011 projectionsWorld Solar generation Capacity and net electricity generation
World solar installed generating capacity
World solar net electricity generation
(Gigawatts)
(Billion kilowatthours)
Region/Country History Projections Annual
Growth(%)
2008 2015 2020 2025 2030 2035
United States 2 15 17 18 19 21 8.9
Canada 0 0 0 0 1 1 8.6
Japan 2 8 17 23 30 40 11.5
South Korea 0 2 2 2 2 2 7.5
Australia/New Zealand 0 2 2 2 3 3 11.1
Russia 0 0 0 0 0 0 —
China 0 13 34 36 37 40 21.5
India 0 2 6 13 15 16 28.5
Brazil 0 0 0 0 0 0 —
12 68 86 95 105 120 8.8
0 19 48 60 65 71 22.8
13 87 134 155 170 191 10.6
Total OECD
Total Non-OECD
Total world
Region/Country History Projections Annual
Growth(%)
2008 2015 2020 2025 2030 2035
United States 1 9 11 11 12 13 8.8
Canada 0 0 0 0 0 0 7.7
Japan 2 8 12 16 20 27 9.8
South Korea 0 1 1 1 1 1 4.7
Australia/New Zealand 0 1 1 1 1 1 9.6
Russia 0 0 0 0 0 0 —
China 0 7 18 19 20 21 20.2
India 0 1 3 6 7 8 35.6
Brazil 0 0 0 0 0 0 —
14 52 61 67 73 83 6.9
0 10 25 31 36 36 21.6
14 62 86 97 106 119 8.3
Total OECD
Total Non-OECD
Total world
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EIA 2011 projections
World geothermal generation Capacity and net electricity generation
World geothermal installed generating capacity
Region/Country History Projections Annual
Growth(%)
2008 2015 2020 2025 2030 2035
United States 2 3 3 4 6 6 3.7
Canada 0 0 0 0 0 0 0.0
Japan 1 1 1 2 2 2 4.0
South Korea 0 0 0 0 0 0 0.0
Australia/New Zealand 1 1 2 2 2 2 4.7
Russia 0 0 0 0 0 0 4.4
China 0 0 0 0 0 0 —
India 0 0 0 0 0 0 —
Brazil 0 0 0 0 0 0 —
Total OECD 6 8 9 11 13 14 3.3
Total Non-OECD 4 8 8 9 10 11 4.3
Total world 9 16 17 19 22 25 3.7
World geothermal net electricity generation
Region/Country History Projections Annual
Growth (%)
2008 2015 2020 2025 2030 2035
United States 15 20 25 31 42 49 4.5
Canada 0 0 0 0 0 0 —
Japan 3 4 6 10 10 10 5.3
South Korea 0 0 0 0 0 0 —
Australia/New Zealand 4 11 13 13 15 15 5.1
Russia 0 1 1 2 2 2 5.5
China 0 0 0 0 0 0 —
India 0 1 1 1 1 1 —
Brazil 0 0 0 0 0 0 —
Total OECD 38 56 67 79 93 104 3.8
Total Non-OECD 22 56 58 61 70 81 5.0
Total world 60 112 125 139 163 186 4.2
(Gigawatts)
(Billion kilowatthours)
147
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148
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EIA 2011 projections World Other renewable generation Capacity and net electricity generation
World other renewable installed generating capacity
Region/Country History Projections Annual
Growth(%)
2008 2015 2020 2025 2030 2035
United States 35 38 41 46 49 49 1.3
Canada 2 2 2 2 2 2 0.6
Japan 27 27 27 27 27 27 0.0
South Korea 4 6 6 6 6 6 1.7
Australia/New Zealand 2 3 4 4 4 4 1.7
Russia 1 1 1 1 1 1 0.3
China 3 14 22 30 38 44 10.5
India 2 3 3 3 3 4 2.6
Brazil 7 7 7 8 8 9 0.9
Total OECD 139 148 151 158 162 164 0.6
Total Non-OECD 22 35 42 51 61 68 4.3
Total world 161 183 194 209 223 232 1.4
World other renewable net electricity generation
Region/Country History Projections Annual
Growth (%)
2008 2015 2020 2025 2030 2035
United States 72 96 131 177 187 193 3.7
Canada 8 8 8 8 9 10 0.9
Japan 21 21 21 21 21 22 0.1
South Korea 1 9 9 9 9 10 10.6
Australia/New Zealand 3 7 8 8 8 9 4.5
Russia 2 2 2 3 3 3 1.1
China 2 82 136 197 257 300 19.9
India 2 11 11 12 14 15 8.0
Brazil 19 19 19 23 28 33 2.1
Total OECD 217 268 309 362 381 398 2.3
Total Non-OECD 41 132 186 252 321 375 8.5
Total world 258 400 496 614 702 772 4.1
(Gigawatts)
(Billion kilowatthours)
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Annexure
149
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Conversion and Multiplying Factors
Multiplying factors6 9 12 15 18 15Mega =10 ; Giga = 10 ; Tera = 10 ; Peta = 10 ; Exa = 10 ; Quadri = 10
UnitsUnits 1 metric tonne = 2204.62lb=1.11023 short tons1 kilolitre=6.2898 barrels = 1 cubic metre1 kilocalorie (kcal) = 4.187kJ = 3.968Btu1 kilojoule (kJ) = 0.239kcal = 0.948Btu1 British thermal unit (Btu) = 0.252 kcal = 1.055kJ1 kilowatt-hour (kWh) = 860kcal = 3600kJ = 3412Btu
Conversion Factors for Basic Units1 Metric ton / Tonne = 1000 kilogramLong Tonne = 1016 KgShort Tonne = 907.2 KgTo convert Barrels per day to Tons/year multiply 49.8To convert Billion Cubic Feet to Billion Cubic meter multiply 0.028
Conversion of Energy Contents for India’s dataOne million tones of coal = 16.60 peta joules of energyOne billion cubic metre of natural gas = 38.52 peta joules of energyOne million cubic metre of natural gas = 38.52 peta joules of energyOne billion kilowatt hour of electricity = 36.00 peta joules of energy
Energy Conversion table
From
TJ Gcal Mtoe MBtu Gwh
To (multiply by)
TJ(Terajoule)
PJ(Peta joule)
Gcal(Gigacalorie)
Mtoe(Million Tonnes of Oil Equivalent)
MBtu(Million British Thermal unit)
GWH (Gigawatt-hour)
Qbtu
1
1
-34.1868x10
-44.1868x10
-31.0551x10
3.6
238.8
2.388
1
107
0.252
860
-52.388x10
-22.388x10
710
1
-82.52x10
-58.6x10
25.5
947.8
3.968
73.968x10
1
3412
-31.163x10
0.2778
11630
-42.931x10
1
09
IND
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150
DisclaimerThe data and information in this book is sourced from websites and documents
available in public domain and does not purport to be official view of Government or
any organization. Sincere efforts have been made to present correct data; however,
errors and omissions, if any, are regretted and the same may please be brought to the
notice of WEC-IMC for necessary corrective action.
!
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