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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Energy deficit

Energy available Energy deficit

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Peak d

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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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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

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*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

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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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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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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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>40 IN FY 12, 27% of Capacity (30235

MW) is from Unit Age >25 years

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