Effect of Primary Fuels on the Availability and Cost of Power in India
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Transcript of Effect of Primary Fuels on the Availability and Cost of Power in India
Effect of Primary Fuels on the Availability
and Cost of Power in India
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Contents
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Power scenario in the country
Coal
Diesel
Gas – Best option
Requisite policy/regulatory initiatives
Power scenario in the country
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India is characterized by power supply 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
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En
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BU
Energy deficit
Energy available Energy deficit
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Peak d
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GW
Peak deficit
Peak met Peak deficit
* Assumption - system load factor of 65%
79 BU 14 GW
Coal based plants and renewables dominate capacity addition plan
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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
Plan 62,695 1,086 - 2,800 9,204 18,500 94,285
% 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
• 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
Source: Planning Commission
*Source: CEA
Power Sector is facing capacity constraints and system stability issues
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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
*Source: NEP
Coal
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Coal shortage will limit coal based capacity addition
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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
Domestic coal linkage based capacities will be stranded
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• 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
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*
*4000 MW will be retired in 12th Plan as per CEA
Diesel
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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
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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
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
Cost economics of diesel based power generation
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With brand new 1 MW
diesel gen sets
Extremely costly
Subsidy loss to Government
• 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
free market price of diesel
• Under recovery of Rs. 11.35 per litre
• FY 11 estimate – Rs. 6500 crores
under-recovery by subsidized diesel
Gas – Best option
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Gas - Best option for meeting base and peak demand
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Parameters Coal Gas Storage Hydro Wind Solar
Capital Cost Rs Crs.
/MW) 6 - 7 4 - 5 7-10 6-7 8-13
Average PLF 85% 85% 45% 22% 18%
Emission Level & SPM High SOx &
NOx
Negligible No No No
Load Centre Proximity Not Allowed Possible Not Possible Not Possible Not Possible
Land Requirement 300-400 ha
for 1000MW
40 ha for
1000MW
Very High for
catchment area High Very high
Ramp Up & Ramp
Down time High Instantly Instantly NA NA
Fluctuating Power
Conditions operations No Yes Yes No No
Outage Time for
Planned Maintenance High Low Low High High
Plant Availability for
Peak Supply Not Suitable Yes Unpredictable No No
• Gas based plants are ideal for environmentally fragile areas
• For Environmental clearance, priority to be given to gas based plants over coal based plants
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62 31 25
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From Cold Start From WarmStart
From Hot Start
Switch on-off characteristics of CCGT Load -100%
Load - 90%
Load - 80%
Load - 70%
Load -60%
Load - 50%
Gas start up – 6 to 10 times faster than Coal
• 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
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From Cold Start From WarmStart
From Hot Start
Switch on-off characteristics of coal
Load - 100%
Load - 90%
Load - 80%
Load - 70%
Load - 60%
Load - 50%
Load - 40%
Load - 30%
Load - 20%
Load - 10%
Load - 0%
Tim
e (
Min
)
*Running CCGT below 40% is not recommended by OEMs
Cold start: more than 72 hours after shutdown, Warm start: 8 to 72 hours after shutdown, Hot start: less than 8 hours after shutdown
Tim
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Coal CCGT
Switch on-off characteristics of reserve plants (in cold start mode : more than 72 hours after shutdown)
Load -100%
Load - 90%
Load - 80%
Load - 70%
Load -60%
Load - 50%
Gas - most suitable for reserve capacity
• 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
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CCGT plants can instantaneously ramp up to meet peak demand
• 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
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100 90 80 70 60 50
min
s
PLF
Ramp up characteristics of CCGT plant
Globally, natural gas supply and LNG capacity will increase significantly
• Total reserves of conventional and non
conventional gas is 810,000 BCM
• Emerging markets – China, India, Korea, Japan
will be dominant buyers in future
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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
Worldwide natural gas demand supply position (BCM) Projected LNG liquefaction capacity by country
Source: World Energy Outlook, 2011
• Share of LNG in global gas trade has increased
significantly
• Between FY 15 to FY 20, 500 BCM of
additional liquefaction capacity is being
considered
Demand for gas in India expected to rise significantly
• Gas demand primarily driven by power
generation, fertilizer, LPG, Industrial sectors.
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Natural gas demand supply position in India (MMSCMD)
Source: Report of Working Group Petroleum & Natural Gas Sector for 12th Five Year Plan
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600
700
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022Domestic supply Imports - LNG
Imports - Transborder pipeline Demand
LNG
Terminal 2013 2014 2015 2016 2017 2022
Dahej 10 12 12 14 14 15
HLPL
Hazira 3 4 4 6 8 10
Dabhol 1 4 4 4 4 5
Kochi 4 4 4 4 4 10
Ennore 0 0 0 4 4 5
Mundra 0 0 0 4 4 10
East Coast 0 0 0 0 4 15
Total LNG
availability 17 24 24 35 41 70
LNG availability projections (MMTPA)
• Due to supply deficit, LNG will be used to
meet demand
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1 MMTPA = 3.6 MMSCMD
Domestic gas supply for power is limited
• 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
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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
LNG is more economical than real cost of peak power
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Real Cost of Power
Price % Contribution (Assumed)
5 year average price of peak power
purchased from spot market (Source: IEX) 5.08 30%
Cost of power generated from diesel 12.70 40%
Cost to Industry due to production loss per
unit of electricity not supplied 5.87 30%
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
LNG can be comparable to other fuels for both base and peaking power
plant
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Fuel type Delivered
fuel price^ SHR
(kcal/kwh)
Energy
charge
Fixed Charges Total Cost
Base
load
plant
Peaking
plant*
Base
load
plant
Peaking
plant*
100% domestic coal Rs. 1860 / ton 2300 1.45 1.70 5.10 3.15 6.55
85% domestic
and 15% imported Rs. 2556 / ton 2300 1.78 1.70 5.10 3.48 6.88
100% imported coal $ 130 / ton 2300 2.80 1.70 5.10 4.50 7.90
Domestic gas
(Post revision) $9 / mmbtu 1533 3.45 1.30 3.90 4.75 7.35
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
Requisite policy/regulatory
initiatives
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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.
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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.
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Questions
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Thank you
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Annexures
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Annexure A -1
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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
(Post Revision) 9,800 USD 9 per mmbtu
LNG Spot price DES West Coast
(Aug 11 – Jul 12 average) 13,000 USD 14.18 per mmbtu
LNG Term price DES West Coast
(HH Linked) 13,000 USD 8.55 per mmbtu
LNG Term price DES West Coast
(NBP Linked) 13,000 USD 14.12 per mmbtu
LNG Term price DES West Coast
(JCC Linked) 13,000 USD 18.13 per mmbtu
Subsidized diesel (FY 12) 10,800 Rs. 43 per litre
Furnace oil (FY 12) 10,500 Rs. 56 per litre
Back
Annexure A- 2
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USD per MMBTU NBP Linked
(from US)
HH Linked
(from US)
JCC Linked
(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
Back
Source: Platts LNG daily 16th August 2012
*ICE NBP London Close (September)
** NYMEX HH US Close (September)
Annexure B
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.
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Back
Annexure C
New plants based on advanced F class
machines can achieve heat rates much
below 1,785 kcal/kWh
A sample analysis of 7 state based large
gas plants revealed that they are about
15% inefficient than new plants
Given the shortage of gas in the country,
inefficient utilization of gas should be
avoided and such plants should either be
modernized or replaced with new
capacities
Gas allocation should not be on a first
come first serve basis
Gas should be shared pro-rata amongst
all efficient plants with the balance
requirements coming from LNG.
Plant Capacity
MW
SHR (kcal/
kWh)
Inefficiency
vs new plant
Uran 672 2019 12%
Dhuvaran 218 1950 8%
Utran 135 2150 17%
Utran – extn 375 1850 4%
Dholpur 330 1950 8%
Pragati 330 2003 11%
Indraprastha 270 3300 29%
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Source: SERC tariff orders
Efficient plant would have SHR below 1,785kcal/kwh
Back
Annexure D
• CEA has a detailed policy of R&M aimed to increase life
or improve performance of existing units of State and
Central plants.
• Old units have significantly higher SHRs than newer units
and hence use more fuel per unit of electricity produced.
Further, such units are not performing even up to their
design heat rates at present. Hence, such units should be
phased out on priority in order to optimally utilize the
existing fuel resources through newer and more efficient
plants.
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
Power
Station
Installed
Capacity
(MW)
SHR (kcal/kwh) Efficiency
Design Actual Deteriorat
ion Design Actual
Panipat 1,360 2,344 2,785 19% 37% 31%
Bhatinda 440 2,510 3,105 24% 34% 28%
Faridabad 165 2,811 4,797 71% 31% 18%
Sikka 240 2,389 3,298 38% 36% 26%
Koradi 1,040 2,432 3,057 26% 35% 28%
Satpura 1,143 2,438 3,283 35% 35% 26%
Birsinghpur 840 2,293 3,114 36% 38% 28%
Korba West 840 2,312 2,709 17% 37% 32%
Ennore 450 2,497 3,367 35% 35% 26%
Neyveli-I 600 2,739 3,904 43% 31% 22%
Raichur 1,470 2,284 2,629 15% 38% 33%
Bokaro B 630 2,492 3,324 33% 35% 26%
Durgapur, DVC 350 2,396 3,047 27% 36% 28%
Source: CEA - Performance Review of Thermal Power Stations
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41133
9790
7350
10395
13120 13960
7505
4612
4158
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0% 5% 10% 15% 20% 25% 30% 35%
Un
it A
ge G
rou
p
% of Total Coal Based Capacity
0-5
6-10
11-15
16-20
21-25
26-30
31-35
36-40
>40 IN FY 12, 27% of Capacity (30235
MW) is from Unit Age >25 years
Back