Mr. Darshan Hiranandani Managing Director, Hiranandani Group at RPR 2012, 23-26 August, Goa, India

1. Effect of Primary Fuels on the Availability
and Cost of Power in India

2. 2

3. Contents
Power scenario in the country
Coal
Diesel
Gas – Best option
Requisite policy/regulatory initiatives
3

4. Power scenario in the country
4

5. India is characterized by power supply deficit
1000 Energy deficit 140 Peak deficit
900
79 BU 120 14 GW
800
Peak demand in GW
100
Energy demand in BU
700
600 80
500
60
400
300 40
200
20
100
0 0
1985
1987
1989
1991
1993
1995
1997
1999
2001
2003
2005
2007
2009
2011
1985
1987
1989
1991
1993
1995
1997
1999
2001
2003
2005
2007
2009
2011
Energy available Energy deficit Peak met Peak deficit
• Energy deficit increased from 66BU in FY 2007 to 79BU in FY2012
• High system load factor (82% in 2012) indicates peak demand is understated
- Realistic peak deficit* could be in range of 25% to 30%
• Appropriate capacity addition plan needs to be pursued
5 * Assumption - system load factor of 65%

6. Coal based plants and renewables dominate capacity addition plan
Source Wise Capacity Coal Gas Diesel Nuclear Hydro Renewable Total
Total installed capacity till end of 11th
plan 112,022 18,381 1,200 4,780 38,990 24,503 199,877
Expected capacity addition during 12th
62,695 1,086 - 2,800 9,204 18,500 94,285
Plan
% share of capacity addition 66% 1% 0% 3% 10% 20% 100%
Retirement of old plants -4,000*
Cumulative Capacity -End of 12th Plan 170,717 19,467 1,200 7,580 48,194 43,003 294,162
Source: Planning Commission
• 66% of the capacity addition expected from coal based plants
• Renewable energy to contribute 20% of capacity addition
- However, contribution in terms of energy would be around 8%
• Coal cannot meet peak deficit economically
6 *Source: CEA

7. Power Sector is facing capacity constraints and system stability issues
Capacity Constraints
• Falling PLFs indicate underutilization of existing capacity due to
- non availability of fuels
- base plants being used as peakers
• Coal availability from CIL/SCCL suffered due to lack of increase in production
• 13 GW of gas capacity would be stranded due to non-availability of domestic gas
• Under utilization results in extensive use of diesel which is subsidized
System Stability
• Share of hydro and gas is expected to comedown from 29% to 23% by FY 2017
• Focus should be on proper pricing of peak power, ability to revive grid after blackout
7 *Source: NEP

8. Coal
8

9. Coal shortage will limit coal based capacity addition
Availability / Shortfall analysis of coal in MT FY 12 FY 17
Avg Annual Coal requirement 460 842
Coal availability from
CIL & SCCL 380 450
Captive blocks allocated to power utilities 28 100
Total domestic coal availability 408 550
Coal shortfall met/to be met by further imports 52 292
• 292 MT of coal will be required through import in FY 17
• Logistic nightmare to import this quantity of coal
• Export restrictions by key coal producing countries would limit supply
9

10. Domestic coal linkage based capacities will be stranded
Coal source Capacity (MW)
Installed capacity as on 31 March 2012 112,022
Expected capacity addition in 12th Plan
Coal Linkage 38,578
Coal Block 17,825
Imported coal 6,292
Total Capacity addition 62,695
Total capacity at end of 12th Plan (FY 17) 170,717*
• Additional coal available from CIL and SCCL for linkage based plants = 70 MTPA
• Considering 15% blending, capacity supported ~ 16 GW
• Approximately 22 GW of linkage based plants expected to be stranded to non availability of coal
• Coal shortage and increase in peak demand indicates real peak deficit may increase
10 *4000 MW will be retired in 12th Plan as per CEA

11. Diesel
11

12. Diesel gensets - used for back up power
• Load curtailment for industrial as well as commercial consumers
• Estimated Yearly loss of Rs. 16000 crores to State Government due to curtailment
• Fuel oil / diesel generation sets used by industries/ commercial houses
• 2.1% of all India energy requirement in FY12 was produced by diesel gensets
• An environmental disaster to have DG sets running all over the country
Parameter Unit Value
Diesel Sales ‘000 MT 59,852
Diesel Used for power ‘000 MT 4,908
Power generated from diesel MUs 19,700
Capacity Estimates @ 16.67% load factor MW 13,495
Assumptions
• 8.2% of total diesel consumption in India is used for power generation
• Generation sets are run for an average of 4 hours daily
12

13. Cost economics of diesel based power generation
Extremely costly
• Per unit cost is Rs. 12.7 per kwh with
subsidized diesel at Rs. 43.47/litre
• Cost is Rs. 16.07 per kwh, considering
With brand new 1 MW
free market price of diesel
diesel gen sets
Subsidy loss to Government
• Under recovery of Rs. 11.35 per litre
• FY 11 estimate – Rs. 6500 crores
under-recovery by subsidized diesel
13

14. Gas – Best option
14

15. Gas - Best option for meeting base and peak demand
Parameters Coal Gas Storage Hydro Wind Solar
Capital Cost Rs Crs.
6-7 4-5 7-10 6-7 8-13
/MW)
Average PLF 85% 85% 45% 22% 18%
High SOx &
Emission Level & SPM Negligible No No No
NOx
Load Centre Proximity Not Allowed Possible Not Possible Not Possible Not Possible
300-400 ha 40 ha for Very High for
Land Requirement High Very high
for 1000MW 1000MW catchment area
Ramp Up & Ramp
High Instantly Instantly NA NA
Down time
Fluctuating Power
No Yes Yes No No
Conditions operations
Outage Time for
High Low Low High High
Planned Maintenance
Plant Availability for
Not Suitable Yes Unpredictable No No
Peak Supply
• Gas based plants are ideal for environmentally fragile areas
• For Environmental clearance, priority to be given to gas based plants over coal based plants
15

16. Gas start up – 6 to 10 times faster than Coal
800 740 Switch on-off characteristics of coal Switch on-off characteristics of CCGT
800
Load -100%
Load - 100%
700 700
Load - 90% Load - 90%
588
600 600 Load - 80%
Load - 80%
500 Load - 70% 500 Load - 70%
Time (Min)
Time (Min)
400 Load - 60% Load -60%
340 400
Load - 50% Load - 50%
300 193 300
190 Load - 40%
200 200
110 Load - 30%
100 Load - 20% 84 62
100 54 31 34 25
Load - 10%
0 0
From Cold Start From Warm From Hot Start Load - 0% From Cold Start From Warm From Hot Start
Start Start
Cold start: more than 72 hours after shutdown, Warm start: 8 to 72 hours after shutdown, Hot start: less than 8 hours after shutdown
• Coal takes almost ten times the time to start from cold start as compared to gas and six times
even in hot start mode
• Additionally, there is upward pressure on coal prices
‒ Domestic coal prices are moving towards import parity
‒ Policies on benchmarking, DMO are pushing international coal prices up
16 *Running CCGT below 40% is not recommended by OEMs

17. Gas - most suitable for reserve capacity
Switch on-off characteristics of reserve plants (in cold start
800 740 mode : more than 72 hours after shutdown)
680
700
Load -100%
600 Load - 90%
500 Load - 80%
400 Load - 70%
Load -60%
300
Load - 50%
200
84
100 62
0
Coal CCGT
• CEA has recommended that the power system should have
‒ Primary reserves capable of starting in 15 secs and achieving full load in 30 seconds
‒ Secondary reserves capable of starting in 30 secs and achieving full load in 15 minutes
‒ Tertiary reserves capable of starting in 15 minutes
• Gas based plants are the only ones capable of meeting reserve requirement reliably. Coal based
plants take 740 minutes to achieve full load after a shutdown, whereas CCGT can be started in
just 84 minutes.
• CCGT machines in open cycle mode can meet the requirements of Primary and Secondary
reserves and can then operate in combined cycle mode to achieve better efficiency
17

18. CCGT plants can instantaneously ramp up to meet peak demand
Ramp up characteristics of CCGT plant
10 9
9
8 7
7
6
mins
5 4
4
3 2
2 1
1
0
100 90 80 70 60 50
PLF
• This unique ability to ramp up / ramp down the load in minutes, with minimal loss is efficiency
and heat rate, makes gas-based generation the best suited option to address varying peak
loads.
• This provides the much needed flexibility to a distribution company to manage its dispatch
schedule efficiently and at a reasonable price
18 *Running CCGT below 40% is not recommended by OEMs

19. Globally, natural gas supply and LNG capacity will increase significantly
Worldwide natural gas demand supply position (BCM) Projected LNG liquefaction capacity by country
Regions 2015 2020 2025 2030 2035
Natural gas consumption
OECD 1615 1691 1773 1865 1950
Non OECD 2070 2328 2611 2912 3182
World 3685 4019 4384 4778 5132
Natural gas supply
OECD 1175 1237 1280 1343 1404
Non OECD 2509 2782 3104 3435 3728
World 3685 4019 4384 4778 5132
• Total reserves of conventional and non • Share of LNG in global gas trade has increased
conventional gas is 810,000 BCM significantly
• Emerging markets – China, India, Korea, Japan • Between FY 15 to FY 20, 500 BCM of
will be dominant buyers in future additional liquefaction capacity is being
considered
19 Source: World Energy Outlook, 2011

20. Demand for gas in India expected to rise significantly
Natural gas demand supply position in India (MMSCMD) LNG availability projections (MMTPA)
700
LNG
2013 2014 2015 2016 2017 2022
600 Terminal
75
500 Dahej 10 12 12 14 14 15
HLPL
400 3 4 4 6 8 10
Hazira
300 Dabhol 1 4 4 4 4 5
Kochi 4 4 4 4 4 10
200
Ennore 0 0 0 4 4 5
100
Mundra 0 0 0 4 4 10
0
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 East Coast 0 0 0 0 4 15
Domestic supply Imports - LNG
Total LNG
Imports - Transborder pipeline Demand 17 24 24 35 41 70
availability
1 MMTPA = 3.6 MMSCMD
• Gas demand primarily driven by power • Due to supply deficit, LNG will be used to
generation, fertilizer, LPG, Industrial sectors. meet demand
20 Source: Report of Working Group Petroleum & Natural Gas Sector for 12th Five Year Plan

21. Domestic gas supply for power is limited
Shortfall in Domestic gas mmscmd
Requirement for projects commissioned till end of 12th plan as per CEA* 96
Additional requirement by 2017 for stranded capacity of 13GW* 63
Total Gas requirement 158
Domestic Gas Availability as on FY12 58
Shortfall 100
*Based on normative requirement of 4.8MMSCMD gas per 1000MW at 90% PLF
• Only 37% of gas requirement (FY17) can be met at current production levels
• Gas production in key gas fields (KG basin) is reducing
• Imported gas (LNG/Transnational Pipeline) would be required to meet the supply deficit
21

22. LNG is more economical than real cost of peak power
Real Cost of Power
Price % Contribution (Assumed)
5 year average price of peak power
5.08 30%
purchased from spot market (Source: IEX)
Cost of power generated from diesel 12.70 40%
Cost to Industry due to production loss per
5.87 30%
unit of electricity not supplied
Total Rs. 8.37
With LNG Case 1 Case 2 Case 3 Case 4
Landed price of LNG ($/mmbtu) 8 10 12 14
Capacity charge for 8 hour operation (Rs/kwh) 3.90 3.90 3.90 3.90
Energy charge (Rs/kWh) 2.43 3.04 3.64 4.25
Total price (Rs/kWh) 6.33 6.94 7.54 8.15
22

23. LNG can be comparable to other fuels for both base and peaking power
plant
Fixed Charges Total Cost
Delivered SHR Energy Base Base
Fuel type Peaking Peaking
fuel price^ (kcal/kwh) charge load load
plant* plant*
plant plant
100% domestic coal Rs. 1860 / ton 2300 1.45 1.70 5.10 3.15 6.55
85% domestic
Rs. 2556 / ton 2300 1.78 1.70 5.10 3.48 6.88
and 15% imported
100% imported coal $ 130 / ton 2300 2.80 1.70 5.10 4.50 7.90
Domestic gas
$9 / mmbtu 1533 3.45 1.30 3.90 4.75 7.35
(Post revision)
Current Spot LNG $ 14.18 / mmbtu 1533 5.41 1.30 3.90 6.71 9.31
Term LNG (HH linked) $ 11.01 / mmbtu 1533 3.45 1.30 3.90 4.75 7.35
Term LNG (NBP linked) $ 17.19 / mmbtu 1533 5.39 1.30 3.90 6.69 9.29
Term LNG (JCC linked) $ 21.65 / mmbtu 1533 6.79 1.30 3.90 8.09 10.69
Subsidized diesel Rs 43.47/ litre 2691 12.70 1.00 3.00 13.70 15.70
Furnace oil Rs. 56 / litre 2691 15.00 1.00 3.00 16.00 18.00
^Price assumptions in Annexure A * full fixed charges to be recovered in 8 hour operation for peaking plant
23

24. Requisite policy/regulatory
initiatives
24

25. Policy/Regulatory measures to promote peaking power plants
1. Gas based capacities, 18GW of existing capacity and 13 GW of future additions, should only cater to peak or
flexible loads while coal based generation should continue to serve base load (Annexure B).
2. Distribution companies should be mandated to meet their entire load requirements with appropriate penalty
provisions for load shedding.
3. Mandatory procurement of at least 10% of overall procurement by discoms through gas based generation to
meet peaking needs and up to 20% to complement renewables as well.
4. Separate competitive bid documents for gas-based peak power procurement as the current case 1 / 2
documents are inadequate. Evaluation criteria for competitive procurement with various scenarios of prospective
fuel costs:
1. Capital Cost
2. Technology
3. Ability of the plant to provide flexible loads
4. Station Heat rate (minimum of 1785 kcal/kWh on HHV basis)
5. Conservation of water / use of air cooled condensers
6. Incentives for generators to procure cheaper gas
7. Availability and reliability of the plant capacity
5. Domestic Gas & Domestic Coal should be allocated based on the efficiency of the plant and not on first come
first served basis. It should be shared pro-rata amongst all efficient generators (Annexure C).
6. LNG Terminals play an ideal role in flexible / peak power generation due to their ability to store gas. Appropriate
regulations in storage and transmission of gas are required for peak power generation.
25

26. Policy/Regulatory measures to promote peaking power plants
7. Old and inefficient plants (~16 GW) should be modernized or replaced with new capacities. (Annexure D)
8. Formulation of Mega Efficient Policy in lieu of erstwhile Mega Power Policy.
a. All new power projects regardless of size should receive Customs Duty Exemption & Deemed Export benefits
account the technology used / efficiency of the Power Project.
b. Size should no longer be a criterion. Investments in transmission can be minimized if small and efficient power
plants are located near load centres.
c. Discoms on one hand are facing load shedding and on the other hand not purchasing power. Hence, the
objective should be to create efficient power generation in the country not linked to PPAs.
9. Coal and Gas should be internationally priced, and any subsidy should be given to consumers directly. This
would result in:
a. Huge royalty incomes to government.
b. Ability of Indian resource companies to mine with international standards and practices given international
pricing.
c. Focus on efficiency rather than allocation.
d. Nature of electricity provides numerous easy options for cross subsidization to the ‘aam aadmi’. (e.g. for
Gujarat a cess of 34 paise/kwh on other consumers can support the agricultural subsidy provided by state
government thus improving state finances)
e. Availability of power as and when required.
26

27. Questions
27

28. Thank you
28

29. Annexures
29

30. Annexure A -1 Back
Fuel GCV (Kcal/Kg) Price assumption
Domestic coal (FY12) 3,200 Rs. 1860 per ton
Imported coal (FY 12) 5,800 USD 130 per ton
Natural gas - Ex Kakinada
9,800 USD 9 per mmbtu
(Post Revision)
LNG Spot price DES West Coast
13,000 USD 14.18 per mmbtu
(Aug 11 – Jul 12 average)
LNG Term price DES West Coast
13,000 USD 8.55 per mmbtu
(HH Linked)
LNG Term price DES West Coast
13,000 USD 14.12 per mmbtu
(NBP Linked)
LNG Term price DES West Coast
13,000 USD 18.13 per mmbtu
(JCC Linked)
Subsidized diesel (FY 12) 10,800 Rs. 43 per litre
Furnace oil (FY 12) 10,500 Rs. 56 per litre
30

31. Annexure A- 2 Back
NBP Linked HH Linked JCC Linked
USD per MMBTU
(from US) (from US) (from AUS)
Gas price 8.70* 3.13** 16.60
Liquefaction cost 2.92 2.92 0.00
Shipping cost to West coast (India) 2.50 2.50 1.53
DES West Coast (India) 14.12 8.55 18.13
Customs duty @5% 0.71 0.43 0.91
Regasification cost 0.70 0.70 0.70
Fuel Boil off @0.85% 0.25 0.15 0.32
Marketing Margin 0.17 0.17 0.17
Transmission Cost 0.58 0.58 0.58
Taxes @4% VAT 0.66 0.42 0.83
Plant Gate 17.19 11.01 21.65
Source: Platts LNG daily 16th August 2012
*ICE NBP London Close (September)
** NYMEX HH US Close (September)
31

32. Annexure B Back
 All existing gas fired plants (about 18,000 MW) are operated as base load plants.
 If these plants are operated only during peak hours (say 8 hours in a day) the existing gas supply
will be able to support 54,000 MW of peak power. The loss of base load can easily be replaced by
18,000 MW of coal based capacity.
 If this gas based capacity is available during peaking hours, it can completely wipe out the peak
deficit of India.
 Thus, if utilities plan to use gas only to address peak power and call for tenders to purchase such
peak power on long term basis, new gas capacity can be added in next 26 to 30 months wiping
out the peak deficit of India in next 3 years.
32

33. Annexure C Back
 New plants based on advanced F class
Plant Capacity SHR (kcal/ Inefficiency
machines can achieve heat rates much MW kWh) vs new plant
below 1,785 kcal/kWh Uran 672 2019 12%
 A sample analysis of 7 state based large Dhuvaran 218 1950 8%
gas plants revealed that they are about Utran 135 2150 17%
15% inefficient than new plants
Utran – extn 375 1850 4%
 Given the shortage of gas in the country,
Dholpur 330 1950 8%
inefficient utilization of gas should be
Pragati 330 2003 11%
avoided and such plants should either be
modernized or replaced with new Indraprastha 270 3300 29%
capacities
Source: SERC tariff orders
 Gas allocation should not be on a first Efficient plant would have SHR below 1,785kcal/kwh
come first serve basis
 Gas should be shared pro-rata amongst
all efficient plants with the balance
requirements coming from LNG.
33

34. Annexure D Back
• CEA has a detailed policy of R&M aimed to increase life Installed SHR (kcal/kwh) Efficiency
Power
or improve performance of existing units of State and Station
Capacity
Deteriorat
(MW) Design Actual Design Actual
Central plants. ion
Panipat 1,360 2,344 2,785 19% 37% 31%
• Old units have significantly higher SHRs than newer units
and hence use more fuel per unit of electricity produced. Bhatinda 440 2,510 3,105 24% 34% 28%
Further, such units are not performing even up to their Faridabad 165 2,811 4,797 71% 31% 18%
design heat rates at present. Hence, such units should be Sikka 240 2,389 3,298 38% 36% 26%
phased out on priority in order to optimally utilize the
Koradi 1,040 2,432 3,057 26% 35% 28%
existing fuel resources through newer and more efficient
Satpura 1,143 2,438 3,283 35% 35% 26%
plants.
50
>40 IN FY 12, 27% of Capacity (30235 Birsinghpur 840 2,293 3,114 36% 38% 28%
45 4158
36-40 MW) is from Unit Age >25 years
Unit Age Group
40 4612 Korba West 840 2,312 2,709 17% 37% 32%
31-35
35 7505
Ennore 450 2,497 3,367 35% 35% 26%
30
26-30 13960
13120 Neyveli-I 600 2,739 3,904 43% 31% 22%
25
21-25
20 10395 Raichur 1,470 2,284 2,629 15% 38% 33%
16-20
15 7350
11-15 Bokaro B 630 2,492 3,324 33% 35% 26%
10 9790
6-10
5 41133 Durgapur, DVC 350 2,396 3,047 27% 36% 28%
0-50
0% 5% 10% 15% 20% 25% 30% 35% Source: CEA - Performance Review of Thermal Power Stations
% of Total Coal Based Capacity
We estimate 16275 MW (>35 yrs in FY 17) will be phased out. We considered the age of Coal
power plants which amount to 112022 MW
34