Utilities: Power sector At the peak of over capacity

Utilities | At the peak of over capacity

Contents

Power sector at the peak of over capacity .......................................................................... 3

Info graphic......................................................................................................................... 6

Demand to grow at 6-7% CAGR over five years ................................................................... 7

Financial health of DISCOMs likely to improve ................................................................. 14

Unrealistic demand expectations created overcapacity .................................................... 22

DISCOMs have 41% more PPAs than FY20E peak load ...................................................... 28

Investment in transmission to continue............................................................................ 31

Identifying winners: Two CSPUs and three pvt. GENCOs ................................................... 36

Annexures I – Comparative financial analysis ................................................................... 42

Annexures II – Private generation capacity ....................................................................... 45

Annexures III – Capacities expected to be closed .............................................................. 46

Companies ........................................................................................................................ 48

NTPC ........................................................................................................................... 49

JSW Energy ................................................................................................................. 70

Powergrid ................................................................................................................... 99

Coal India ...................................................................................................................104

Price as on July 8 , 2016

Investors are advised to refer through important disclosures made at the last page of the Research Report.

Motilal Oswal research is available on

www.motilaloswal.com/Institutional-Equities,

Bloomberg, Thomson Reuters, Factset and S&P Capital.

July 2016

Utilities | At the peak of over capacity

Utilities

Power sector at the peak of over capacity

Identifying winners; PWGR, NTPC and JSW Energy are our picks

Indian consumption is expected to grow at 6-7% CAGR over five years



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Brokers Poll 2016 for India

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request your ballot.



India’s elasticity of electricity consumption with GDP growth is declining due to

low share of manufacturing in GDP.

Per capita consumption growth of electricity tends to peak at USD2000 per

capita GDP. India’s per capita GDP is already inching towards USD2000 mark.

India has perhaps missed the bus of accelerated electricity consumption growth

period.

Although India’s specific electricity consumption is low, yet per capita electricity

consumption is not low at current level of per capita GDP.

Energy efficiencies will partially offset demand drivers. UDAY will improve

sustainability of DISCOMs.

Four states are witnessing strong traction in demand, but they together are only

20% of country. But, the consumption growth is decelerating in rest of country

and dragging India’s growth rates.

We believe that India’s per capita consumption of electricity can increase at 5-

6% CAGR assuming that India is able to clock 7-8% GDP growth. Add to this the

population growth rates, India’s electricity consumption can grow at CAGR of 6-

7% over next 5 years.

Power sector at the peak

of over capacity

Utilities

Financial health of Discoms is likely to improve but, this may not be enough

to drive demand



MoP is doing all the right things to improve the financial health of DISCOMs, in

our view.

There are structural issues that will take longer to resolve. States with low share

of industry will find it more challenging to turn around. Access to low cost

energy will be equally important.

Data analysis suggests that there is no correlation between demand growth and

financial health of DISCOMs. Improved financial health of DISCOMs may not

necessarily derive demand.

Sanjay Jain

Unrealistic demand expectation created overcapacity; it may take 5-6 years

to rebalance the market



Dhruv Muchhal

Please click here for Video Link



All India conventional capacity has increased at CAGR of 11% to 259GW during

FY11-FY16 spurred by flurry of private investment expecting unrealistic demand

growth.

Conventional capacity addition is peaking, yet the capacity will grow at CAGR of

3.8% to 301GW during FY16-20E. Capacity addition will fall sharply post FY17E in

private sector, but it will pick up in central sector. It will take 5-6 years to

rebalance the market.

Any sign of tightness in market will revive another 20GW of projects where

more than 50% of budget is already spent.

July 2016

Utilities | At the peak of over capacity



All India conventional capacity PLF will bottom out in FY17E, but central sector

PLF will continue to decline until FY19E because of continued momentum in

capacity addition.

Private sector PLF will be improving from 52% in FY17E to 64% by FY20E as

capacity addition drops sharply post FY17E. State’s PLF will languish at 40%.

Share of RE in generation will increase from 4% to 7%. Coal will remain main

driver of generation growth but its dependence will keep reducing.

Discoms have signed 41% more PPAs than FY20E peak load; 21-28GW

stranded capacity will be vying for 4.7GW of PPAs



Indian power supply is very comfortable with 259GW of commissioned

conventional capacity as on 31st March 2016, while the peak load was only

153GW in FY16. States had 237GW available commissioned capacity with PPAs

i.e. 55% more than the peak demand. Approx. 21GW private commissioned

capacity was stranded without PPAs.

Rolling forward to FY20E, the conventional capacity will rise to 301GW after

deletion of 6-10GW old capacity, while peak load will increase to 194GW at

CAGR of 6%. States will have 273GW available commissioned capacity with PPAs

i.e. 41% more than the projected all India peak demand. Approx. 28GW private

commissioned capacity may still be stranded without PPAs if states don’t sign

more PPAs.

Despite a very comfortable situation at the country level, Gujarat, Andhra

Pradesh, Kerala, J&K and few smaller states may need to seek 4.7GWPPAs over

next 2-4 years to meet their long term requirements.

Investment in transmission will continue; RE, need for flexibility, arbitrage

in variable cost across country will be the drivers



Investment in RE capacities will keep driving demand for spinning capacities and

investment in transmission and sophisticated equipment to maintain quality of

electricity.

Demand centers and sources of energy are polarized. It makes more sense to

transmit electricity rather the transporting coal.

Over investment in long distance transmission is desirable to create flexibility in

Grid.

16.3 GW of stranded capacity will demand inter region transmission capacity

because they can sell power at lower rate than the variable cost of many

capacities in demand centers e.g. NR and SR.

Merchant power market will thrive but it is unlikely to be profitable for couple

of years.

Identifying winners: 2 CSPUs and 3 Pvt.; PWGR is top pick; Re-initiate on

JSW Energy with BUY



Post analysis of 50 private companies and 5 central PSUs, we have identified

two CPSUs and three private GENCOs as likely outperformer.

PWGR and NTPC are growing organically with visibility of next 3-5 years of capex

and are delivering double digit RoEs. PWGR is our top pick.

It is prudent to grow inorganically at the peak of over capacity. Among the 50

private companies, we have short listed three names that have strong both

July 2016

Utilities | At the peak of over capacity



balance sheet and free cash flows. JSW Energy, Tata Power and CESC meet the

criteria and are likely outperformer.

Businesses of Tata Power and CESC are complex as they have exposure to RE,

Distribution, coal mining, retail, cricket (IPL), information technology etc.

We re-initiate coverage on JSW Energy with BUY rating for its simple business

model, strong balance sheet, regionally diversified portfolio of assets and strong

negotiating power in M&A.

Exhibit 1: Sector valuation table

TP Up/(dw) MCAP

Rating CMP#

(INR) (INR)

% (USD M)

Buy

165 205

24 12,994

Buy

153 185

21 19,034

Buy

17 2,064

Buy

312 370

19 29,633

FY16E

11.5

12.3

8.5

22.6

EPS

FY17E

14.0

11.5

7.0

19.0

FY18E

16.3

13.7

8.0

23.0

P/E (x)

FY17E FY18E

11.8

10.1

13.3

11.2

12.0

10.5

16.4

13.5

P/B(x)

FY17E FY18E

1.7

1.5

1.4

1.3

1.5

1.3

5.6

5.4

RoE (%)

FY17E FY18E

15.7

16.1

10.8

12.2

12.9

13.4

34.8

40.6

Powergrid

NTPC

JSW Energy

Coal India

# as on July 8th, 2016

Source: MOSL, Company

July 2016

Utilities | At the peak of over capacity

Info graphic

July 2016

Utilities | At the peak of over capacity

Demand to grow at 6-7% CAGR over five years

Elasticity of consumption is declining w.r.t. GDP growth rates



India’s elasticity of electricity consumption w.r.t. GDP growth is declining due to a low

share of manufacturing in GDP.

Per capita consumption growth of electricity tends to peak at USD2,000 per capita

GDP. Thus, given that India’s per capita GDP is already inching toward the USD2,000

mark, we believe the country has perhaps missed the bus of accelerated electricity

consumption growth.

Although India’s specific electricity consumption is low, per capita electricity

consumption is not low at the current level of per capita GDP.

Energy efficiencies should partially offset demand drivers, in our view. UDAY is likely

to improve the sustainability of DISCOMs.

Four states are witnessing strong traction in demand; however, they together account

for only 20% of the country’s demand. Moreover, consumption growth is decelerating

in the rest of India, thereby dragging the country’s growth rates.

We believe India’s per capita consumption of electricity can increase at a 5-6% CAGR,

assuming that the country is able to clock 7-8% GDP growth. Also, given the

population growth rates, India’s electricity consumption can grow at a CAGR of 6-7%

over the next five years.

India’s elasticity of electricity of demand w.r.t. GDP growth is declining…

While most countries clock

elasticity of >1 during high

GDP growth phases, a

reverse trend is observed in

India.

Based on our analysis of historical data, we note that the per capita GDP growth rate

is the key driver of per capita electricity demand growth in a country. Indian

electricity demand growth has been disappointing for the last 20 years, despite

acceleration in the GDP growth rate. While per capita GDP CAGR has accelerated

from 3.3% over 1984-94 to 4.4% over 1994-2004 and to 6.2% over 2004-14, the

generation CAGR has dropped from 6.4% over 1984-94 to 3.9% over 1994-2004, and

then slightly increased to 4.8% over 2004-14. While most countries clock elasticity of

>1 during high GDP growth phases, a reverse trend is observed in India.

Exhibit 2: Elasticity of electricity demand growth and GDP growth rate

12%

10%

-2%

per capita GDP growth (10 year CAGR)

10%

Note: Three decades data for India (red), world, USA, Japan, S. Korea, Malaysia, China, Indonesia and

Thailand Source: MOSL, Company

July 2016

Utilities | At the peak of over capacity

Declining elasticity of

manufacturing in GDP

demand

due

low share

One of the key reasons for the declining elasticity of demand w.r.t. GDP growth is

that manufacturing has a very low share in India’s GDP, unlike most other fast-

growing nations which rely heavily on manufacturing to sustain their growth rates.

Exhibit 3: Share of manufacturing remains low in India, unlike most other countries (%)

World

China

India

S.Korea

Indonesia

Malaysia

Thailand

Source: MOSL

Per capita consumption growth of electricity tends to peak at USD2,000 per

capita GDP

We also note that demand for electricity tends to slow down in ensuing five years

after industrial activities peak and a country achieves certain per capita GDP. In fact,

the US and Japan are now witnessing a fall in per capita consumption of electricity

driven by efficiencies and peaking of industrial activities.

Electricity demand growth

starts to slow-down after

reaching a particular per

capita GDP

Exhibit 4: Per capital demand CAGR v/s per capita GDP

-2

-4

Source: MOSL

Per Capital GDP (USD 000)

A closer look at the data with lower per capita GDP also reveals a similar trend. Most

countries (e.g. Thailand, S. Korea, Malaysia and Indonesia) witnessed slower

demand growth in ensuing five years after they achieved USD2,000 per capita GDP.

China is the only outlier because the share of manufacturing in its GDP too is an

outlier. However, we note that China is witnessing slower demand growth after its

per capita GDP crossed the USD2,600 mark. India’s per capita GDP is not very far

from the USD2,000 mark.

July 2016

Utilities | At the peak of over capacity

India’s per capita GDP is not

very far from the USD2,000

mark. We thus believe that

India has perhaps missed

the bus of accelerated

demand growth period.

Exhibit 5: Growth rates slow down after a point

India

2,000

4,000

6,000

8,000

10,000

Source: MOSL

Per Capita GDP (USD)

Indonesia

S.Korea

China

Malaysia

Thailand

India’s per capita electricity consumption is not low at current level of per

capita GDP

It is often said that India’s absolute per capita consumption of electricity is very low

compared to developed countries or the world average. Although this implies that

the potential for growth is huge, India is struggling with the growth rates and its

trajectory of absolute per capita consumption is not very different from other

countries.

India is not an outlier.

Exhibit 6: Generation v/s GDP at 2014 prices

5,000

4,000

3,000

2,000

1,000

2,000

4,000

6,000

8,000

Per capita real GDP in 2014 USD prices

10,000

12,000

Source: MOSL

World

China

Vietnam

India

Indonesia

Thailand

Exhibit 7: Generation v/s GDP on purchasing power parity basis

5,000

4,000

3,000

2,000

1,000

4,000

8,000

Per Capita GDP -PPP (USD)

12,000

16,000

Source: MOSL

World

China

Indonesia

Thailand

Vietnam

India

July 2016

Utilities | At the peak of over capacity

After analyzing 30 years of historical data for major countries in the world, we

conclude that India is unlikely to witness a natural tailwind that can accelerate

demand growth. The drivers have to be found back home.

Initiatives to improve efficiencies will partly erode demand growth

Let us have a look at domestic factors. The Indian government’s focus on providing

“24x7” electricity to all is likely to boost demand from domestic and commercial

consumers at an accelerated rate. However, initiatives to improve energy

efficiencies will partly erode demand growth, in our view.



Emphasis on highly energy efficient LED lights can erode 20GW of potential

demand over time. Over 100m LED bulbs are already distributed under the

UJALA scheme. LED lights are 50-90% more energy efficient.



The MoP has recently launched a scheme to replace pumps used by farmers

with energy-efficient/solar pumps free of cost. These pumps offer convenience

as they can be operated remotely with mobile phones. They also help lessen

wastage of electricity, as well as reduce wear and tear of pumps, and

deterioration of soil. The cost of pumps will be funded from the savings of

subsidies given to farmers. Through this scheme, the government will also have

more accurate information about electricity consumption in farming, thereby

helping reduce power leakage and pilferage.



Under UDAY, states have committed to reduce T&D losses substantially, which

will plug pilferage and partially erode demand.



The biggest driver of demand is the industry, which is gradually getting less

dependent on DISCOMs. The tariff structure is inverted in India – bulk

consumers (like industry and offices) are charged the highest, while small

consumers are charged the least. The actual cost of delivery is high in retailing

than selling it to bulk consumers. Tariffs are so high for the industry that doing

business is becoming unviable. Most of the energy-intensive industries do not

depend on grid, but instead set up captive power plants.

Exhibit 8: Share of CPPs in electricity consumption by industries (%)

LED lights can erode 20GW

of potential demand.

If pilferages are plugged, we

can see some demand

erosion.

Industry reliance on CPP is

increasing…

FY05

FY06

FY07

FY08

FY09

FY10

FY11

FY12

FY13

FY14

FY15

Source: MOSL, CEA

July 2016

Utilities | At the peak of over capacity

Exhibit 9: Industrial Tariff (EUR/MWH)

122

117

145

Source: MOSL, CEA

Industry’s demand from grid has grown at a slower pace. After raising tariffs, some

of the states have seen the share of industry in the consumption basket decline.

Exhibit 10: Rajasthan raised industry rapidly during FY11-14

Avg Tariff (INR/kwh)

Industry tariff (INR/Kwh)

5.3

3.8

4.2

Exhibit 11: Industry’s share in consumption declined (%)

Others

Industry

Agri

AT&C

3.7

5.0

3.0

2.9

2.8

2.6

2.8

3.4

FY06 FY07 FY08 FY09 FY10 FY11 FY12 FY13 FY14

Source: MOSL, PFC

FY06 FY07 FY08 FY09 FY10 FY11 FY12 FY13 FY14

Source: MOSL, PFC

Exhibit 12: TN raised industry rapidly during FY11-14

Avg Tariff (INR/kwh)

Industry tariff (INR/Kwh)

10.5 10.3

7.0

4.4

4.3

2.8

4.3

4.2

2.8

4.4

4.8

Exhibit 13: Industry’s share in consumption declined (%)

Others

Industry

Agri

AT&C

2.8

2.9

2.8

1.9

3.7

4.8

5.2

FY06 FY07 FY08 FY09 FY10 FY11 FY12 FY13 FY14

Source: MOSL, PFC

FY06 FY07 FY08 FY09 FY10 FY11 FY12 FY13 FY14

Source: MOSL, PFC

Consumption growth accelerating in four states, but slowing in rest of India

As the supply of electricity is improving and the focus of state politics is shifting

toward development, we note that electricity consumption over the past four years

has started growing faster in only four states (Bihar, Chhattisgarh, MP and Gujarat),

which together account for only 20% of consumption. However, consumption in rest

of the country is slowing.

July 2016

Utilities | At the peak of over capacity

We need to watch UP more closely as it has the potential to make a mark in

consumption due to its (1) high population base and (2) 8.5% share in the country’s

consumption. There is lot of work being done to improve the transmission and

distribution infrastructure in the state, while supply of electricity is improving.

Specific consumption is low, which means it has the potential to grow faster as

supply improves.

Exhibit 14: Four states have seen acceleration in demand over the last four years

200

400

600

800

Per capita consumption (kWh)

1,000

1,200

1,400

1,600

Bihar

Chhattisgarh

Gujarat

Note: Size of bubble indicates population of the state

Source: MOSL, PFC

Exhibit 15: Four states growing faster, but rest are slowing

CAGR (%) over FY08-12

11.0

6.7

CAGR (%) over FY12-16

Exhibit 16: 80:20 rule applies

Fast growing 4 states

Rest of the country

5.4

5.2

Fast growing 4 states

Rest of the country

Source: MOSL, PFC, CEA

consumtption (%)

Population (%)

Source: MOSL, PFC, CEA

Therefore, we believe that there is no breakthrough trend that can change the

trajectory of India’s demand growth, despite measures undertaken under UDAY.

However, we strongly believe that UDAY will be able to improve the sustainability of

DISCOMs. In the absence of UDAY, consumption growth would have instead

decelerated.

India’s electricity consumption can grow at 6-7% CAGR

We believe that India’s per capita consumption of electricity could increase at a 5-

6% CAGR, assuming that the country is able to clock 7-8% GDP growth. Also, given

the population growth rate, we believe India’s electricity consumption could grow at

a CAGR of 6-7% over the next five years.

July 2016

Utilities | At the peak of over capacity

We expect consumption to

grow at a CAGR of 7% over

FY16-20E.

Exhibit 17: All India electricity consumption growth (%)

Source: MOSL

July 2016

Utilities | At the peak of over capacity

Financial health of DISCOMs likely to improve

But this may not be enough to drive demand



The MoP is taking the right steps to improve the financial health of DISCOMs, in our

view.

However, there are structural issues, which we believe will take longer to resolve.

States with a low share of industry will find it more challenging to turn around. Access

to low-cost energy will be equally important.

Our data analysis suggests that there is no correlation between demand growth and

financial health of DISCOMs, as improved financial health of the latter may not

necessarily drive demand.

MoP moving in the right direction

There is a clear roadmap for

debt reduction, AT&C loss

reduction, and timely tariff

revisions.

We see Mr. Piyush Goyal as a dynamic power minister. After engaging with various

stakeholders in about 1,000 meetings, the MoP has come out with a comprehensive

scheme called “UDAY” to clean up the malaise in the system. There is a clear

roadmap for debt reduction, AT&C loss reduction, and timely tariff revisions to

reduce the revenue gap (ARG) between average cost of supply (ACS) and average

revenue on subsidy received basis (ARR). The MoP is also undertaking steps to bring

about supply-side efficiencies, e.g. swapping of coal linkages to reduce

transportation costs, improving quality of coal and substituting imports by

improving domestic supply of coal. All of this will reduce ACS. There is a focus on

energy efficiency in consumption. LED bulbs are being promoted aggressively, which

we believe brings a two-fold advantage: saving of 93% energy in lighting, which in

turn (1) flattens of load curve and (2) reduces the pressure on grid. Among recent

initiatives, energy-efficient pumps are being promoted, which will have SIM cards so

that they can be operated remotely by farmers to save energy. Investment in

distribution is being pursued aggressively to reduce power leakage and theft, and to

provide 24x7 electricity. Round-the-clock electricity will reduce dependence on

diesel generators, and thus reduce oil imports and bring lucrative customers to grid.

Thus, we believe the MoP is moving in the right direction in terms of improving the

financial health of DISCOMs.

UDAY has right mix of carrots and sticks for it to succeed



DISCOM liabilities (INR4.8t) can shift to state – 50% in FY16 and 25% in FY17.

Rest 25% liabilities can be converted to state-guaranteed bonds – lower interest

rate (base +0.1%).

Incremental losses post FY17 will be taken over by states (5%/10%/25%/50% in

FY18/19/20/21).

States will issue non-SLR (including SDL) bonds, which will not be counted in the

states’ fiscal deficit for FY16 and FY17.

DISCOMs will be obligated to reduce AT&C losses from 22% to 15% and bridge

the gap between ACS and ARR.

Handholding

through additional grant under DDUGJY, IPDS, PSDF. Increased

supply of cheaper domestic coal, coal linkage rationalization, liberal coal swaps

from inefficient to efficient plants, coal price rationalization based on GCV,

supply of washed and crushed coal, and faster completion of transmission lines.

July 2016

Utilities | At the peak of over capacity



Sticks:

Non-performance will result in forfeiting of benefits under DDUGJY

(INR756b) and IPDS (INR326b). Banks will not be allowed to fund losses.

17 states are joining: expect 50% reduction in losses



17 states together account for 80% of all DISCOMs’ losses (after receiving

subsidies).

17 UDAY states accounted for 75% of INR4.3t debt in FY14.

There will be reduction in interest cost of INR219b.

Thus, the losses will reduce by 45% for these states

TN still remains outside UDAY, which accounts for 92% of losses for the

remaining states.

Key lies in execution of T&D investment by states; things have started to move

in the right direction.

Exhibit 18: Interest cost savings to reduce 45% losses for participating DISCOMs (INR b)

S.N.

MoU signed

Uttarakhand

Punjab

Gujarat

Bihar

Chattishgarh

Jharkhand

J&K

Haryana

Rajasthan

Uttar Pradhesh

Formally agreed to join

Goa

Himachal Pradesh

Maharashtra

Odisha

Karnataka

Andhra Pradesh

Madhya Pradesh

Total

Non-UDAY states

All States

Commercial loss

on subs recd basis

(397)

(3)

(6)

(15)

(24)

(31)

(156)

(167)

(90)

(0)

(1)

(3)

(5)

(14)

(64)

(487)

(154)

(641)

Debt

2,153

208

130

302

786

584

1,070

240

114

286

310

3,223

4,300

Interest

cost

207

284

Net loss

Int. Savings recasted

165

(231)

(0)

(5)

(10)

(24)

(11)

(87)

(127)

(37)

(2)

(4)

(0)

(56)

219

(268)

(154)

(422)

Source: MOSL, PFC

There are many structural issues which will take longer to resolve

We believe efforts of the MoP are likely to yield positive results in restoring the

financial health of DISCOMs. We need to watch out if that will drive demand for

electricity. There are certain structural issues with states which will take longer to

resolve. Over the past 10 years, we have seen the focus of discussions shifting from

shortage of capacity, to shortage of coal to shortage of funds as key impediments to

demand growth. But many structural issues are still less understood.

July 2016

Utilities | At the peak of over capacity

Less industrialized states will find it more challenging to turn around

Increasing domestic and

agriculture tariff is the only

option, which is highly price

sensitive.

One of the key reasons behind the poor financial health of DISCOMs is the low share

of industry in the consumption basket, which are the key providers of cross subsidy.

Some states have raised industry tariff at such a pace that they have driven the

industry out of those states. In Tamil Nadu, the industry tariff is up 130%, while the

share of industry in the consumption basket has dropped from 31% in FY06 to 19%

in FY14. On the other hand, financially well-managed Maharashtra has maintained

the industry share in consumption at 31%, while Gujarat has increased the share of

industry from 29% in FY06 to 41% in FY14. Industry tariff was up 81% in

Maharashtra and just 51% in Gujarat during the same period. There is a similar story

across most of the loss-making states. This is not to say that high AT&C losses, low

tariff do not contribute to financial stress. What we are trying to say is that even

after achieving targeted AT&C losses, DISCOMs may not necessarily stop making

losses. Increasing tariff is going to help, but we need to be cognizant of the fact that

demand is highly price sensitive. Industry tariffs are already too high in most of the

states. A bulk consumer like Indian Railways is gradually substituting expensive

power from DISCOMs with cheaper power from private producers. Industry is

increasingly becoming dependent upon captive power for its survival. Some states

have already started working on reducing tariff for industry to save them from

extinction. Increasing domestic and agriculture tariff is the only option, which is

highly price sensitive. Therefore, the states with a low share of industry will find it

more challenging to turn around.

Exhibit 19: DISCOMs profitability and share of sales to industries

1.00

0.50

0.00

-0.50

-1.00

-1.50

-2.00

-2.50

-3.00

Low share of Industry

and lack of access to low

cost electricity

High share

Industry

Source: MOSL, PFC

Low share

of Industry

Delhi

West Bengal

Karnataka

Kerala

Maharashtra

Odisha

Haryana

Punjab

Andhra Pradesh

Chhattisgarh

Gujarat

Madhya Pradesh

Bihar

Uttar Pradesh

Tamil Nadu

J&K

Jharkhand

Rajasthan

Share of Industry (%)

July 2016

Utilities | At the peak of over capacity

On analyzing the data in Exhibit 19, we note that there are few states (e.g. Delhi,

Karnataka and West Bengal) which have a low share of industry, but are still

profitable. On detailed analysis of these three states, we note that there are state-

specific reasons.



Delhi is fully urban and is able to charge high rates to its customers.



Karnataka’s ACS is low because it has a high share of hydro power in the supply

basket.



West Bengal has been able to charge high rates to its customers, although ACS is

high. The combined share of AT&C loss and Agri is 35% in West Bengal, which is

among the lowest in India. Agriculture has just 3% share. West Bengal is among

the few states in India which charge a high INR3/kwh to agriculture.

Exhibit 20: Cost of supply (ACS), Revenue (ARR), and the revenue gap

Note: Size of the bubbles is representative of the state's relative electricity consumption. The numbers in the bubble indicate the Revenue Gap

(INR/kWh)

Source: MOSL, PFC

July 2016

Utilities | At the peak of over capacity

Exhibit 21: Combined AT&C loss and Agri consumption are better indicators of malaise

(%)

AT&C Loss

Agri

Energy Input (% of India)

Source: MOSL, PFC

Access to low-cost energy is equally important

Inflationary pressures

Improved domestic supply, better quality and swapping of linkage are helping

reduce variable cost for coal-based power plants. However, there are other

inflationary pressures that DISCOMs have to face. Environmental cess on coal has

increased dramatically over the past few years from nil to INR400/t. DISCOMs have

signed too many PPAs, as discussed later in the report. Fixed portion of ACS is

increasing because specific fixed cost of a new project is higher and average PLF is

declining due to over-commitment of PPAs/capacities. ACS has nearly doubled over

FY07-FY14 due to an increase in variable, fixed, transmission and distribution costs.

Exhibit 22: ACS has nearly doubled in seven years (INR/kWh)

Purchase

T&D cost

ACS

4.8

4.2

3.5

2.8

2.7

FY07

3.0

2.9

FY08

3.2

FY09

3.3

FY10

3.6

3.7

4.2

4.7

4.9

5.2

5.3

FY11

FY12

FY13

FY14

Source: MOSL, PFC

July 2016

Utilities | At the peak of over capacity

Exhibit 23: Cost of power varies from one state to another

all fuels (INR/kWh)

39 41

31 36 32

Share of own gen. (%)

Source: MOSL, PFC, CEA

Chhattisgarh and Karnataka get 50% of power below INR2/kwh and INR3/kwh.

Exhibit 24: Chhattisgarh power purchase cost-curve

Chhatisgarh - INR/kWh

4.47

2.67

3.01

Exhibit 25: Karnataka power purchase cost-curve

Karnataka - INR/kWh

4.15

3.72

4.56

2.02

1.00

0.54

upto 20%

21-50%

51-80%

81-90%

90-100%

upto 20%

21-50%

51-80%

81-90%

90-100%

Source: MOSL, CEA

While, Rajasthan and AP pay more than INR3/kwh for 80% of energy purchases.

Exhibit 26: Rajasthan power purchase cost-curve

Rajasthan - INR/kWh

3.82

4.06

4.49

3.42

2.33

Exhibit 27: Andhra Pradesh power purchase cost-curve

Andra - INR/kWh

3.83

4.44

4.67

3.18

1.71

upto 20%

21-50%

51-80%

81-90%

90-100%

Source: MOSL, PFC

upto 20%

21-50%

51-80%

81-90%

90-100%

Source: MOSL, PFC

No correlation between financial health of states and demand growth

The financial position of state power distribution companies (DISCOMs) is being

cited as a key impediment to demand growth. Analysis of state-wise demand

suggests that there is no correlation between demand growth and financials of

DISCOMs. Gujarat has the best financials, yet growth of energy input/purchased by

DISCOMs has been just 5% over FY06-FY14. Of the seven states that have the

July 2016

Utilities | At the peak of over capacity

Improved financial health of

DISCOMs may not

necessarily drive demand.

highest ARG, only Tamil Nadu and Jharkhand’s energy input (consumption) grew at

~4-5% CAGR over FY06-14. The other five states’ (Bihar, Haryana, MP, Rajasthan,

and UP) energy input/purchased grew at a CAGR of high ~8% over the same period.

In other words, the improved financial health of DISCOMs may not necessarily drive

demand. In fact, there is risk of demand erosion if these states return to financial

prudence.

Exhibit 28: DISCOM profitability v/s. demand growth

1.00

0.50

0.00

0.0

-0.50

-1.00

-1.50

-2.00

-2.50

-3.00

Raj.

Jharkhand

2.0

4.0

-0.27 Punjab

6.0

Delhi

Kerala

Gujrat

Karnataka Mah.

Odisha 8.0

Haryana

HP 10.0

Uttrak.

12.0

cagr of energy purchased by Discoms over FY06-14

Source: MOSL, PFC

Analysis of Rajasthan DISCOMs suggests that ACS will continue to rise

The balance sheet of DISCOMs is set to get a makeover as state governments take

over 75% of DISCOMs’ debt by the end of FY17. This will re-start the flow of credit to

them. The states are committing to reduce AT&C losses in a graded manner and

increase tariff more frequently to bridge the gap between ARR and ACS. We have

studied and tried to forecast ACS for Rajasthan DISCOMs. Our analysis suggest that

fixed cost will increase further because of (1) a decline in the average utilization of

committed capacities, (2) new capacities came at higher average capex, (3) average

cost of transmission infrastructure is now trending up and (4) the share of

renewable energy is increasing. Although an increase in domestic supply of coal is

deflationary for variable cost, there are inflationary pressures (e.g. increase in clean

environment cess from nil few years ago to INR400/t for FY17). Therefore,

increasing ARR is the only way for DISCOMs’ turnaround.

July 2016

Utilities | At the peak of over capacity

Will continue increasing due

to rising fixed cost of PPAs

Exhibit 29: ACS for Rajasthan will increase due to rising fixed cost of PPAs (INR/kWh)

FC Discom

4.9

3.0

1.1

4.8

2.8

1.3

4.9

2.9

1.3

FC PPA

VC PPA

5.0

2.8

1.5

5.1

2.8

1.6

5.2

2.8

1.7

Source: MOSL, ARRs

July 2016

Utilities | At the peak of over capacity

Unrealistic demand expectations created overcapacity

It may take 5-6 years to rebalance the market



All India conventional capacity has increased at a CAGR of 11% to 259GW during FY11-

FY16, spurred by flurry of private investment amid expectation of unrealistic demand

growth.

Conventional capacity addition is peaking, yet the capacity should grow at a CAGR of

3.8% to 301GW during FY16-20E. Capacity addition will fall sharply post FY17E in the

private sector, but will pick up in the central sector. It will take 5-6 years to rebalance

the market.

Any sign of tightness in the market will revive another 20GW of projects, where more

than 50% of budget is already spent.

All India conventional capacity PLF will bottom out in FY17E, but central sector PLF will

continue declining until FY19E because of continued momentum in capacity addition.

Private sector PLF will improve from 52% in FY17E to 64% by FY20E as capacity

addition drops sharply after FY17. The state sector’s PLF will languish at 40%.

The share of RE in generation will increase from 4% to 7%. Coal will remain the main

driver of generation growth, but its dependence will keep reducing.

Unrealistic demand expectations created overcapacity

The Indian power sector has witnessed rapid capacity addition over the past five

years in anticipation of unrealistic high demand growth. Capacity grew at a CAGR of

11% over FY11-16, while peak load grew at a CAGR of only 4.6% over the same

period.

Last five years have seen a

period of rapid capacity

addition

Exhibit 30: Conventional capacity and peak load

Conv. Cap. (GW)

Peak load (GW)

155

118

122

153

Period of rapid

capacity addition

301

259

194

Source: MOSL, CEA

Capacity addition was driven by huge private sector investment. Doling out of

captive coal mines during 2007-2009 and a very attractive merchant power market

during 2009-2011 attracted huge investment by private developers. Many did not

care to even secure PPAs. Almost everyone kept some spare capacity for the

merchant market.

May take 5-6 years to rebalance the market

According to analysis of data provided by CEA on the broad status of projects and

based our interaction with industry, we note that capacity addition has peaked.

Private developers are hurrying to complete projects before 31 March 2017 in order

July 2016

Utilities | At the peak of over capacity

to retain tax benefits. Commissioning of projects by private players will dry post

FY17. However, capacity addition by the central sector, led by NTPC, will be high in

FY18 and FY19. We expect conventional capacity to increase by net 42GW to 301GW

in FY20 after counting the deletion of nearly 6GW largely by the state sector (see

Annex. III for details).

Conventional capacity

addition has peaked

Exhibit 31: Conventional capacity addition (GW)

Central

State

Pvt.

Source: MOSL, CEA

Conventional capacity addition growth will be slower at 3.8% over FY16-20E, while

peak load may grow at a CAGR of 6%. Furthermore, we expect renewable energy

(RE) capacity to increase by 41GW to 80GW by FY20. Thus, total installed capacity

will increase by 83GW to 381GW by FY20E on factoring reasonable conservatism.

It will take as long as 5-6

years for overcapacity to

correct

Exhibit 32: Conventional cap./peak load (x)

1.7

1.6

1.5

1.4

1.3

1.2

1.1

Source: MOSL, CEA

The Indian power sector is at the peak of overcapacity, as evident from Exhibit 32. If

peak load grows at a CAGR of 6%, it will take as long as 5-6 years for overcapacity to

correct. We are assuming that RE will not crowd out conventional capacity from

peak load. In reality, some amount of wind energy is indeed available during evening

peak load, but it cannot be relied upon.

There is a tendency of slower growth in peak load as the load curve tends to flatten

as per capita consumption increases. This is evident from the following regional

peak load charts. The load curve is steeper in the eastern region (ER), which is less

developed compared to the northern region (NR). Further, LED lights are reducing

peak load in the evenings. Therefore, we believe that it will take at least 5-6 years

for overcapacity to correct even if energy demand were to grow at a CAGR of 7-8%.

July 2016

Utilities | At the peak of over capacity

Further, we have identified 21GW of projects, which are held up either because of

shortage of funds or other issues. Of this, there is 10GW of capacity with revised

project cost of INR660b, which are stopped due to shortage of funds; INR400b is

already spent on them. Any sign of tightness in the market will improve the chances

of revival of these projects. Therefore, overcapacity may last for longer.

Exhibit 33: Load curve - Eastern Region at peak in FY15

Exhibit 34: Load curve – Northern region at peak in FY15

Conventional

Wind

Solar

Conventional

Wind

Solar

Time (hours)

10 12 14 16 18 20 22 24

Source: MOSL, CEA

8 10 12 14 16 18 20 22 24

Source: MOSL, CEA

We expect generation to grow at 7% CAGR; private sector - key driver

Electricity generation has increased at a CAGR of 6.4% over FY11-16. Private sector

has been the key driver of this growth. Indian DISCOMs have an impressive system

of scheduling power from generating stations that have lower variable cost among

the contracted capacities.



Electricity generation by private generators increased at a CAGR of 25% over the

past five years. Most private producers secured PPAs at low rates through

competitively bid tenders. Private producers find preference in merit order

dispatch as they enjoy low variable cost due to economy of scale, lower

transportation costs and highly efficient new equipment. Private names will

continue to lead generation because their plants are located either closer to

ports or closer to coal mines. We are factoring in a 12% CAGR in private sector

generation over FY16-20E.

Private sector is key driver

of generation growth

Exhibit 35: Electricity generation (billion kWh)

State

Central

Private

1,155

348

116

346 364 376 385 395 409 429 456 479 509

231 245 267 299 304 324

304 315 336 338 346 348 360 368 348 351 367 345 349 352 356 360

624

846

540

1,514

Source: MOSL, CEA



The state sector’s generation remains stagnant, despite capacity increasing by

25% to 100GW in FY16. As a result, PLF of the state sector declined from 53% in

FY11 to 41% in FY16. The state sector has been a major loser due to system

July 2016

Utilities | At the peak of over capacity

inefficiencies and the strategic disadvantage of having location away from the

source of energy. State GENCOs’ variable costs are elevated as they incur high

transportation cost for coal, and SHR (station heat rate) is high due to frequent

back-downs and poor maintenance. Only ~20% of coal based capacity has

variable cost less than INR2/kWh. As transmission-related bottlenecks are

addressed, high-variable-cost plants will find it difficult to get schedule. The

state sector is likely to remain laggard, in our view. We are factoring a 1% CAGR

in state sector generation over FY16-20E.

Only 12GW of 64GW of

state-owned coal capacity

has variable cost less than

INR2/kWh

Exhibit 36: Variable cost curve for state-owned coal capacities

Source: MOSL, State Gencos ARR (FY16-17)



The central sector too has been a laggard as generation grew at a CAGR of

3.4% v/s 6.4% for all India over FY11-16. Capacity increased at a CAGR of 7%

to 76GW over FY11-16. As a result, PLF declined from 73% in FY11 to 61% in

FY16. The MoP and the MoC (ministry of coal) have taken various initiatives

to improve the quality of coal and reduce transportation cost by swapping

of linkage, which should help reduce overall cost of coal transportation and

variable cost. We expect generation to grow at a CAGR of 5% over FY16-20,

which is better than the state sector but lower than all India generation

CAGR of 7% over the same period.

Exhibit 37: NTPC’s plants energy cost

Energy Charges (INR/kWh)

4.6

2.6 2.4 2.6 2.6

1.7 1.2 1.7 1.6 1.6 1.6

1.1 1.0

2.4 2.5

1.3 1.5 1.5 1.4 1.4

2.8 2.8 2.8

3.9 3.6

3.0 2.9 3.4

3.8 3.7

Source: NTPC's Tariff Petitions



The MoP is targeting aggressively to increase RE capacity to 175GW by 2022. We

are, however, conservatively factoring in RE capacity of 80GW by the end of

July 2016

Utilities | At the peak of over capacity

FY20E, which means an addition of 41GW in four years. This is achievable, in our

view, given the strong push by the MoP, falling cost of projects and competitive

tariffs.

We expect RE capacity and

generation to increase at a

CAGR of 20% over FY16-

20E.

Exhibit 38: Renewable energy capacity (GW)

Source: MOSL, CEA



All India PLF of conventional capacity will bottom out in FY17E at 50%. State

sector PLF will remain low at 40%, while central sector plants’ PLF will decline

further from 61% in FY16 to 55% in FY19E. Private sector’s PLF is at 52%, which

is expected to start improving rapidly after FY17.

Private sector PLF is at its

lowest point

Exhibit 39: Plant load factors (%)

PLF(%)

All India conventional

Central

State

Private

Source: MOSL, CEA

Coal will retain dominant

share in power generation,

while RE’s share will

increase 230bp to 7%

Exhibit 40: Power generation fuel-wise

Share (%)

100

Coal

Gas

Hydro

Nuclear

Source: MOSL, CEA



In the past five years, all India generation increased by 325b kWh to 1155b kWh.

Coal was the key driver of generation growth. Coal contributed 102%, RE 9% and

July 2016

Utilities | At the peak of over capacity

nuclear 3% of the 325b kWh total growth in generation. Hydro contributed just

2%, while gas-based generation dragged 16% of total growth in generation.

Exhibit 41: Contribution (%) in generation growth (FY11-16)

Exhibit 42: Contribution (%) in generation growth (FY16-20)

100

(325b

kWh)

Hydro

Nuclear

Gas

FY11-16

Source: MOSL, CEA

Coal

Hydro

Nuclear

102

Coal

Source: MOSL, CEA



We expect electricity generation to increase at a CAGR of 7% over FY16-20E.

According to our estimates, RE will contribute 14% to growth, while hydro will

contribute 7%. Nuclear energy too will contribute nearly 4%. If there are

slippages in hydro generation (either due to water shortage or delay in new

projects), coal’s share will be correspondingly higher.

July 2016

Utilities | At the peak of over capacity

DISCOMs have 41% more PPAs than FY20E peak load

21-28GW capacities without PPAs, while demand may be just 4.7GW



Power supply in India is comfortable with 259GW of commissioned conventional

capacity as on 31 March 2016, while peak load was only 153GW in FY16. States had

237GW of available commissioned capacity with PPAs, i.e. 55% more than peak

demand. Approx. 21GW of private commissioned capacity was stranded without PPAs.

Rolling forward to FY20E, we believe conventional capacity will rise to 301GW after

the deletion of 6-10GW old capacity, while peak load will increase to 194GW at a

CAGR of 6%. States will have 273GW of available commissioned capacity with PPAs,

i.e. 41% more than the projected all-India peak demand. However, approx. 28GW of

private commissioned capacity may still be stranded without PPAs if states do not sign

more PPAs.

Despite a very comfortable situation at the country level, Gujarat, Andhra Pradesh,

Kerala, J&K and a few smaller states may need to seek 4.7GW PPAs over the next 2-4

years to meet their long-term requirements.

Exhibit 44: Cap. w/o PPA outstrips expected PPAs by FY20E

Capacities /PPAs(GW)

27.8

Exhibit 43: 41% more PPAs than FY20E peak load

Peak load (GW)

Avg. load (GW)

273

238

PPAs (GW)

+41%

194

161

129

4.7

+55%

153

FY16

FY20E

Source: MOSL

Expected PPAs

Cap. w/o PPA

Source: MOSL

States may seek 4.7GW of PPAs over the next 2-4 years

Gujarat, Andhra Pradesh,

Kerala and J&K may need to

enter into PPAs.



Although the PPA situation at the country level is very comfortable, yet some

states will need to sign PPAs to meet their average energy requirement as they

often plan in isolation for political reasons. Among the larger states, Gujarat,

Andhra Pradesh, Kerala and J&K may need to enter into PPAs to meet their

average energy requirement (Exhibit 45). Around 4.7GW of PPAs may come up

in the next 2-4 years from 11 states, despite surplus central sector unallocated

PPAs of 14GW by FY20. Our calculations for the requirement of PPA capacities

are based on an average PLF of 75% for average energy requirement and PLF of

80% for peak load requirement. If gas-based capacities become viable, Andhra

Pradesh and Gujarat too may not need new PPAs until FY20.

Karnataka, Kerala and Bihar’s PPA situation has been tight in FY16. These states

are expecting new capacities (they have signed PPAs, which will be

commissioned over the next few years), which should put them it a comfortable

position. Therefore, as of now, these states are managing their short-term

needs from the oversupplied merchant market.

Our analysis reveals that if each state were to plan from the point of view of

securing PPAs to meet their peak load requirement individually, 25 states may

July 2016

Utilities | At the peak of over capacity

need to sign 39GW of PPAs by FY20. However, this analysis may not hold true as

peak load demand can and is being met by power banking and from merchant

power market. Peak load for most states in the northern region (NR) is 42-80%

more than average load requirement. On the other hand, NR’s peak load is just

31% higher than average requirement. Therefore, power banking and short-

term PPAs can prove to be a cost-effective solution, in our view.

Exhibit 45: Conventional Power Projects with PPAs, Peak and Avg. load requirement – in MW

Region

Maharashtra

Uttar Pradesh

Tamil Nadu

Gujarat

Punjab

Rajasthan

Karnataka

Madhya Pradesh

Haryana

Telangana

West Bengal

Andhra Pradesh

Delhi

Orissa

Chhattisgarh

Kerala

Bihar

DVC

Jammu & Kashmir

Uttarakhand

Assam

Himachal Pradesh

Jharkhand

Dadra and Nagar

Goa

Puducherry

Meghalaya

Chandigarh

Tripura

Daman & Diu

Manipur

Nagaland

Arunachal Pradesh

Mizoram

Sikkim

State PPAs

Cen. Unalloc. PPA

Pvt PPAs

Pvt Gas PPAs

Without PPA

Adjustment

Grand Total

FY16 Load

Peak

Avg.

PPAs

20,973 16,755 28,364

16,988 12,484 18,368

14,217 11,373 15,497

14,495 12,004 17,716

10,852

6,329 12,198

10,961

7,727 12,986

10,196

7,391 10,239

10,902

6,299 13,736

9,113

5,646 10,621

6,854

4,708

9,501

7,905

5,342 10,183

7,381

6,119

8,020

5,846

3,253

8,541

4,341

3,263

5,373

3,932

2,406

6,912

3,974

2,734

4,037

3,735

2,825

2,928

2,814

2,199

6,694

2,544

1,809

2,446

2,034

1,470

2,606

1,491

965

1,184

1,488

1,012

2,419

1,151

857

2,129

740

622

280

583

463

352

368

290

330

400

223

462

342

190

113

300

148

601

307

242

168

149

140

100

139

141

102

109

182

177,885 127,500 215,526

7,958

2,750

5,000

21,280

6,725

259,238

U/C Cap.

FY20E load

with PPA

Peak

Avg.

PPAs

3,323 27,491 21,963 31,687

4,279 22,268 16,364 22,647

4,288 17,949 14,359 19,785

2,367 19,000 15,735 20,083

274 14,225

8,297 12,472

3,725 14,368 10,129 16,711

3,242 12,872

9,331 13,481

3,727 14,290

8,256 17,463

1,029 11,945

7,401 11,650

840

8,653

5,943 10,341

1,970 10,362

7,003 12,153

1,069

9,318

7,725

9,089

425

7,663

4,264

8,966

3,125

5,690

4,276

8,498

1,055

5,154

3,154

7,967

486

5,017

3,452

4,523

4,110

4,896

3,704

7,037

3,689

2,883

6,763

204

3,335

2,371

2,650

269

2,666

1,926

2,875

428

1,954

1,265

1,612

1,221

1,950

1,327

3,640

953

1,509

1,124

3,082

970

815

304

165

764

607

517

136

465

366

466

524

292

555

448

249

134

306

393

194

907

402

318

220

111

149

184

106

100

330

182

471

221

134

294

345

143

527

44,134 231,094 165,551 259,659

6,373

14,331

2,750

5,000

6,493

27,773

-8,598

57,000

300,915

FY20E reqd. PPA

Peak#

Avg.$

34,364 29,284

27,835 21,818

22,436 19,145

23,750 20,979

17,781 11,062

17,960 13,506

16,090 12,441

17,863 11,009

14,932

9,868

10,816

7,925

12,952

9,337

11,648 10,299

9,579

5,686

7,113

5,702

6,443

4,206

6,271

4,602

6,120

4,938

4,611

3,843

4,168

3,161

3,333

2,569

2,443

1,687

2,438

1,769

1,886

1,498

1,212

1,087

955

809

581

488

655

389

560

332

492

259

503

424

275

147

229

141

228

128

167

100

179

288,867 220,735

Surplus (deficit)

Peak

Avg.

-2,677 2,403

-5,187

829

-2,651

640

-3,667

-897

-5,309 1,410

-1,248 3,206

-2,609 1,040

-399 6,455

-3,282 1,782

-475 2,417

-799 2,816

-2,559 -1,211

-613 3,280

1,386 2,796

1,524 3,761

-1,748

-79

918 2,099

2,152 2,920

-1,519

-512

-458

306

-831

-75

1,202 1,871

1,196 1,583

-909

-783

-439

-292

-115

-22

-101

165

-426

-198

416

648

-439

-360

-126

-130

-42

243

343

126

193

348

432

-29,208 38,925

14,331 14,331

2,750 2,750

5,000 5,000

-8,598 -8,598

-15,724 52,408

Source: MOSL, CEA, Company Data

July 2016

Utilities | At the peak of over capacity

Exhibit 46: Central and state sectors will be key drivers of capacity addition with PPA

Central

Private

State

Grand Total

24,101

4,807

15,226

44,134

Source: MOSL, Company, CEA

Exhibit 47: Private sector is likely to add ~4.8GW tied-up capacity

Ind bharath

JPVL

KSK

RKM

TRN

Pvt

Asian Genco

IL&FS

Grand Total

Project

Ind Barath

Prayagraj (Bara)

Akaltara

Uchpinda

TRN

Tidong-I

Teesta- III

Cuddalore

2017

350

1,122

350

390

1,020

600

2,812

1,945

2018

2019

Grand Total

350

1,122

925

350

390

1,020

600

4,807

925

Source: MOSL, Company, CEA

Regional analysis reveals that SR has only marginal surplus



Our region-wise analysis reveals that the northern region (NR), the western

region (WR) and the eastern region (ER) are well positioned to meet their

average load requirements. Even the southern region (SR) is comfortable with

marginal surplus PPAs of 2.4GW.

There are two states – Andhra Pradesh and

Kerala – that appear in a tight situation in SR. We can expect these two states

to sign some PPAs.

Andhra Pradesh is aggressively installing RE capacities, which

can help it to partly meet its energy requirements.

Region-wise peak load too appears manageable with unallocated central

capacity of 14GW and improved inter-region connectivity.

Exhibit 48: Electricity demand-supply balance by regions

Region

NER

Sum

All-India

FY16 Load

U/C Cap.

FY20E load

Peak

Avg.

PPAs with PPA

Peak

Avg.

54,474 41,681 70,297

11,447 71,404 54,636

48,640 39,947 67,409

10,675 63,757 52,362

40,445 34,006 47,623

10,061 49,161 41,334

18,076 14,019 27,488

10,573 23,694 18,376

2,573

1,692

2,709

1,378

3,373

2,217

164,208 131,344 215,526

44,134 211,389 168,924

153,366 128,879 237,959

44,134 193,621 161,351

PPAs

81,745

78,084

57,684

38,060

4,087

259,659

273,143

FY20E reqd. PPA

Peak# Avg.USD

89,255 72,847

79,696 69,816

61,451 55,112

29,617 24,501

4,216

2,956

264,236 225,232

242,026 217,824

Surplus (deficit)

Peak

Avg.

-7,511 8,897

-1,613 8,267

-3,767 2,572

8,443 13,560

-129 1,130

-4,577 34,427

31,117 55,319

Source: MOSL, CEA

July 2016

Utilities | At the peak of over capacity

Investment in transmission to continue

RE, need for flexibility and arbitrage in variable cost across the country will

be the drivers



Investment in RE capacities should keep driving demand for spinning capacities, while

investment in transmission and sophisticated equipment should help maintain quality

of electricity.

Demand centers and sources of energy are polarized. It makes more sense to transmit

electricity rather than transporting coal.

Over-investment in long -distance transmission is desirable to create flexibility in grid.

16.3GW of stranded capacity will demand inter-region transmission capacity because

these plants can sell power at a lower rate than the variable cost of many capacities in

demand centers, e.g. NR and SR.

The merchant power market will thrive, but is unlikely to be profitable for the next

few years.

Investment in RE will keep driving demand



The MoP is targeting aggressively to increase RE capacity to 175GW by 2022. We

are, however, conservatively factoring in RE capacity of 80GW by the end of

FY20, which implies addition of 41GW in four years.

This is achievable, in our view, given the strong push by the MoP, falling cost of

projects and competitive tariffs. Investment is transmission will be more driven

by the MoP’s RE capacity target of 175GW, because it takes longer to set up

transmission infrastructure compared to RE capacity addition.

Investment in RE capacities should keep driving demand for spinning capacities,

while investment in transmission and sophisticated equipment should help

maintain quality of electricity.

We expect RE capacity and

generation to increase at a

CAGR of 20% over FY16-

20E.

Exhibit 49: Renewable energy capacity (GW)

Source: MOSL, CEA

Centre of gravity of generation has shifted away from demand…

New investments in generation are closer to energy sources



WR was the key driver of capacity addition (43% of total addition) over FY05-

FY15, spurred by allocation of captive coal mines and success of three UMPPs of

4GW each. Peak demand, on the other hand, grew the most (32% of all India

growth) in SR. Very attractive merchant power rates during FY08-FY11

July 2016

Utilities | At the peak of over capacity

discouraged many of new capacities at pithead to get in long-term PPAs, leaving

them stranded for transmission capacities.

Economics driving additional need for transmission



Although the northern region is well invested in generation, it is now looking to

source cheaper power from WR at the cost of keeping its capacities idle. This

has created additional need for transmission for right reasons. It is always

cheaper to produce power close to mines/port and transmit power, compared

to transporting coal more than 1000km from mines/ports to the generation

capacities in NR. This has created an imbalance in generation capacities with

respect to demand centers, thereby creating transmission bottlenecks.

Exhibit 50: WR hogged 43% of cap. addition FY05-15

21%

NE etc

25%

32%

Exhibit 51: While demand grew most in SR over FY05-15

NE etc

24%

10%

16%

Source: MOSL, CEA

26%

Source: MOSL, CEA

43%

…due to uneven disposition of energy resources



New investments in generation have come close to coal mines in Odisha,

Chhattisgarh, MP and Jharkhand. Large hydro projects are located far off from

load centers in Sikkim and the north-eastern regions. UMPPs are either located

on coastline or closer to coal mines.

Coal mines are mostly in central and eastern part of India, while load is

distributed across NR, WR and SR.

July 2016

Utilities | At the peak of over capacity

Exhibit 52: Energy sources in India

Source: Company

Cost of power transmission is far cheaper than cost of transporting coal

Cost of transmission

declines, while cost of coal

transportation increases

over time



Economics of total cost of delivered power will decide the location of electricity

generation in future, due to plenty of redundancy in generation capacities.

Cost of transmitting electricity can be lowered with the help of technological

upgrade, e.g. higher MVA lines (800KV HVDC - lower system losses and can carry

larger amount of electricity on single line), while cost of transporting coal keeps

increasing because of higher cost of new rail infrastructure and general inflation.

As such, there are bottlenecks in the rail freighting infrastructure. Transmission

is much less labor-intensive compared to rail/road transport of coal.

July 2016

Utilities | At the peak of over capacity

Exhibit 53: High density of stranded IPP (red pointers) & CPP (green pointers) in proximity to coal fields (black pointers)

Source: MOSL

Over-investment in transmission is desirable to create flexibility in grid



Availability of fuel and

water is volatile.



Long distance HVDC transmission corridors are being built to connect the

power-surplus western region to the north and south regions. The NE-Agra

HVDC line has been commissioned recently, which provides a large connection

between NR and ER. Although this line is largely idle currently due to a delay in

the hydro project (Subhanshiri) in NE, it has provided much-needed flexibility in

the system. The Champa-Krukshetra HVDC line is expected to be commissioned

in June 2016, which will connect stranded capacities in WR to demand centers in

NR.

Over-investment in transmission is desirable for a country like India because the

sources of energy lie either in the central/eastern coal belt or hydro resources in

north (i.e. Himalayas), while demand centers are in the planes of north, west

and south. Cost of transporting coal is very high from coal belts to demand

centers in north, west or south of India because of long distances and

bottlenecks in rail infrastructure. For a coastal power plant in west or south, it is

often cheaper to import rather than sourcing it domestically from Coal India.

However, economics keep changing depending on coal prices. Also, there is

another angle of water shortage.

At times, some thermal power plants are

rendered idle due to water shortage. Therefore, it is prudent to overinvest in

inter-region transmission capacities to create the desired flexibility. Hence, we

July 2016

Utilities | At the peak of over capacity

believe that investment momentum in the transmission system will continue.

Power Grid is the key beneficiary.

Arbitrage in variable cost demands additional transmission infra



14GW of stranded capacity

without PPAs near coal

mines.



Stranded power capacities of 22-28GW may have to wait for 2-3 years for

securing PPAs. The MoP has come up with a good idea to capitalize on this – it

has started promoting the short-term power market. Coal is being made

available in a separate e-auction window for the power sector. At the same

time, states have been asked to come to the electronic platform for meeting

their short-term requirements. We believe the outlook for the short-term power

market in India is promising.

Many generating companies have high variable costs because of high

transportation costs, low operating efficiencies, coal pilferage and corruption.

Variable cost ranges as high as INR3-4/kwh. These plants do not get scheduled

in merit order dispatches. On the other hand, new efficient merchant power

plants are able to supply power at total cost as low as INR2.2/kwh. Clearly, there

is an arbitrage, and the future of the short-term market appears promising, in

our view. Availability of transmission infrastructure is the only bottleneck at

times. However, these issues are being addressed gradually.

There is nearly 14GW of stranded capacity without PPAs near coal mines in the

states of MP, Chhattisgarh, Odisha and Maharashtra. These capacities have low

variable cost and they sell to states like Delhi and Rajasthan (where variable cost

is high due to transportation of coal) or to states in the south that have to either

pay high transportation cost or import coal. Similarly, 2.2GW of hydro capacity

can supply to states in north India. Therefore, we believe demand for

investment in cross-country lines will continue.

U/C

3,270

990

1,200

1,080

855

244

535

2,368

2,020

150

total

14,143

5,626

3,024

1,315

4,178

2,125

1,418

631

6,505

3,170

945

1,092

980

120

198

5,000

27,773

Remarks

This power will have to be sold

outside of state because

cost of power is low and states

are over supplied

This power will have to be sold

outside of state

Exhibit 54: Stranded capacities w/o PPAs – in MW

Coal bearing states

Chhattisgarh

Madhya Pradesh

Odisha

Maharashtra

Hydro

Himachal Pradesh

Sikkim

Uttarakhand

Demand Centers

Andhra Pradesh

Gujarat

Tamil Nadu

Karnataka

Rajasthan

Uttar Pradesh

Private Gas

Total

Comm.

10,873

4,636

1,824

1,315

3,098

1,270

1,174

4,137

1,150

945

942

980

120

5,000

21,280

This capacity may eventually get

absorbed within state/region

198

6,493

Even this may demand transmission

Source: MOSL, CEA

July 2016

Utilities | At the peak of over capacity

Identifying winners: Two CSPUs and three pvt. GENCOs

PWGR is our top pick; re-initiating coverage on JSW Energy with BUY



After analyzing 50 private companies and five central PSUs, we have identified two

CPSUs and three private GENCOs as likely outperformers.

PWGR and NTPC are growing organically with capex visibility for the next 3-5 years,

and are delivering double-digit RoEs. PWGR is our top pick.

It is prudent to grow inorganically at the peak of overcapacity. Among the 50 private

companies, we have shortlisted three names that have strong balance sheets and free

cash flows. JSW Energy, Tata Power and CESC have balance sheet strength and FCF.

We re-initiate coverage on JSW Energy with a BUY rating for its simple business model,

strong balance sheet, regionally diversified portfolio of assets and strong negotiating

power in M&A.

Businesses of Tata Power and CESC are complex as they have exposure to RE,

distribution, coal mining, retail, cricket (IPL), information technology, etc.

GENCOs have attracted major chunk of private investment in the sector

The Indian power sector comprises generation companies (GENCOs), transmission

companies (TRANSCOs) and distribution companies (DISCOMs). Among the three

verticals, GENCOs have witnessed large private sector investment. PWGR dominates

with more than 90% share in the inter-state-inter-region (ISIR) transmission system.

There are few private sector TRASCOs, but they are much smaller in size and less

relevant. DISCOMs are largely state government entities, though there are a few

private franchises but largely in metropolitan cities like Mumbai, Delhi and Kolkata.

Most of them are engaged in generation as well. Therefore, we will focus our

discussion on GENCOs with the exception of PWGR.

Exhibit 55: RoE (%)

PSU

Power Grid

NTPC

SJVN

NHPC

Neyveli Lignite

Pvt. Sector

JSW Energy

Torrent Power

Tata Power

CESC

Reliance Power

Adani Power

KSK Energy

JP Power

Lanco Infratech

FY11

FY12

-6

-4

FY13

-1

-42

-21

FY14

-5

-4

-5

-67

FY15

-14

-21

-10

-132

FY16

-13

-4

Source: MOSL, Company

Central PSUs delivering consistent double-digit RoEs

PWGR is our top picks.

Among GENCOs, central PSUs have been able to deliver consistent double-digit RoEs

as they work on cost plus model. Revenue is approved by the regulator based on

regulations, which are revised every five years and are currently applicable for the

command period 2014-19. Among the five key listed names, PWGR, NTPC, Neyveli

July 2016

Utilities | At the peak of over capacity

Lignite and SJVN have been able to report double-digit RoEs. Capacity addition in

hydro has slowed down drastically due to environmental issues and opposition from

local residents. This has affected growth for SJVN and NHPC. The RoE of NHPC is

adversely affected because (1) projects have taken longer time to complete and (2)

the share of equity in projects is higher than the regulatory ceiling of 30%, which

yield lower debt return, i.e. negative EVA.

PWGR and NTPC have

reinvestment opportunities

because of their capex

visibility of the next 4-5

years.

Both PWGR and NTPC are well managed and have been able to consistently

generate double-digit RoEs, despite trimming of incentives under the revised

regulations for the command period 2014-19. PWGR’s RoE is superior to NTPC

because it takes shorter period of ~3 years to complete a transmission project,

compared to 5-6 years for coal-based power plants. IRR (internal rate of return) for

a project is superior if the execution period is shorter because equity invested

during the construction period does not earn RoE. Further, PWGR has higher

balance sheet leverage compared to NTPC. Although investment in private GENCOs

is drying up, both PWGR and NTPC have reinvestment opportunities because of

their capex visibility of the next 4-5 years. PWGR is our top pick because of superior

RoEs and lower execution risk. We also find NTPC attractive because capex has

picked up momentum, which will be followed by capitalization and earnings growth.

Exhibit 56: Central sector power capacity (GW)

Coal

Gas

Hydro

Nuclear

102

FY08

FY09

FY10

FY11

FY12

FY13

FY14

FY15

FY16 FY17E FY18E FY19E FY20E

Source: Company, MOSL

Organic growth is drying in private sector

Private sector capacity grew

at a CAGR of 29% over

FY09-FY17E.

The Indian power sector witnessed maximum tightness in supply during FY09, which

is evident from the ratio of conventional capacity to peak load (Exhibit 57).

Merchant power rates had shot through the roof. DISCOMs were buying power in

the short-term market at very high rates, ranging from INR6/kwh to INR10/kwh. This

was followed by a spurt in investment in the private sector.

July 2016

Utilities | At the peak of over capacity

Exhibit 57: Conventional capacity to Peak load (x)

1.7

1.6

1.5

1.4

1.3

1.2

1.1

Source: MOSL, CEA

Capacity in the private sector grew at a CAGR of 29% to 91GW over FY09-FY17E. This

was driven largely by coal-based projects, which grew at a hopping CAGR of 40% to

78GW over the same period.

Coal-based private

capacities grew at a 40%

CAGR.

Exhibit 58: Private sector power capacity (GW)

Coal

Gas

Hydro

Source: MOSL, CEA

Private capacity addition is also expected to remain strong in FY17E as companies

are rushing to complete projects before the exhaustion of tax benefits. Capacity

addition will fall off the cliff in the private sector post FY17E, essentially implying

that organic growth opportunities are drying up for the private sector. As a result,

we expect the overcapacity situation to start correcting gradually.

Nine relevant companies in the listed space

There are about 50 companies (Annexure II) that have undertaken total projects of

97GW (excluding stalled projects), which are either already commissioned or will be

commissioned by FY20E. Of these, nearly 28GW of capacity are without PPAs. There

are many players with large projects which have material operations in other sectors

(e.g. steel, construction). However, since power is not their core business and

majority of their capacities are without PPAs and debt laden, they are likely to exit

over time.

We have identified nine private companies with total capacities of 45GW in the

listed space which are pure play in the sector and worth focusing on. These

companies have nearly 4GW capacity under construction, while 19% of their

capacity is stranded without PPAs.

Nine companies control half

of private capacities.

July 2016

Utilities | At the peak of over capacity

Exhibit 59: Private Gencos capacity and their status

S.N. Companies

(MW)

9,034

5,845

4,440

10,044

2,438

3,280

2,700

3,272

4,320

45,373

Capacity

Thermal

Hydro

(MW)

7,661

693

5,760

3,140

1,300

10,044

2,325

3,231

2,700

3,262

3,920

400

42,043

2,393

Renew.

(MW)

680

113

937

Status

Comm.

u/const.

(MW)

9,034

5,845

4,440

10,044

2,438

3,280

1,350

2,072

1,200

2,880

1,440

41,383

3,990

Capacity w/o LT PPA

(MW)

270

1,360

2,235

490

1,402

1,350

523

1,173

8,803

Tata Power

RPower

JSW Energy

Adani

CESC

Torrent Power

Rattan India

KSK

Jai Prakash

Source: MOSL, Company, Bloomberg

Three likely winners: JSW Energy, Tata Power and CESC

Torrent’s business model is volatile because most of its capacity is gas-based and

nearly 43% is without PPAs. Gas prices remain highly volatile. Despite a fall in gas

prices, its cost of generation is still not competitive with coal-based power plants.

Gas supply is likely to remain short in India due to low domestic production. Torrent

has a franchisee business which is stable. Although its balance sheet is not

leveraged, the company’s value will remain volatile. This further narrows the

discussion to eight companies.

Exhibit 60: Private companies: Key financials and valuation ratios

S.N. Names

CMP#

Mkt

Net

Cap.

Net Debt*

O/S

EV*

EBITDA Net Debt

Cap. Worth

INRm capex

INRm FY17E

/EBITDA

(INR) (INR b) (INR b) (MW) (INR b) /MW (INR b) (INR b) /MW (INR b)

(x)

198

150

9,034

360

559

4.3

6.7

146

209

5,845

289

435

5.5

8.3

137

4,440

169

306

3.8

6.9

10,044 483

580

7.9

9.5

609

2,438

116

197

3.5

6.0

2,700

147

202

12.3

16.8

3,272

226

279

9.0

11.1

4,320

253

300

11.5

13.6

P/BV

(x)

1.3

0.7

1.6

1.3

0.7

0.5

0.2

Tata Power#

Rpower#

JSW Energy

Adani#

CESC#

Rattan India#

KSK#

Jai Prakash#

* incl. o/s capex; # as on July 8th, 2016

Source: MOSL, Company, Bloomberg

Looking closely at the key financials of these eight companies, it is clear that there

are only three companies with good fundamentals and sound financials. JSW

Energy, Tata Power and CESC are likely to emerge as winners in the sector, in our

view. On the other hand, we believe RPower and Adani would barely sustain

themselves. Also, Rattan India, KSK and Jai Prakash are heavily debt laden and have

pending capex, open capacities, etc.

July 2016

Utilities | At the peak of over capacity

Exhibit 61: Private companies: Key financials and valuation ratios

JSWE

CESC

(substaintial

assets other

than GENCO)

Tata Power

Adani

KSK

RPower

JPVL

Rattan

Net Debt / MW - INR m

Source: MOSL, Company, Bloomberg

JSW Energy is simple and best among the lot

Overcapacity in the sector is at its peak level, which will take another 5-6 years to

correct, in our view. Therefore, we believe it is prudent to grow inorganically rather

than investing in new projects. In our view, companies with low financial leverage

and robust free cash flows are better placed to grow inorganically given the

immense opportunities. We believe JSW, Tata and CESC fit the matrix. CESC has

chosen to grow its business in distribution by acquiring two circles in Rajasthan. Tata

Power has acquired the renewal energy business of Welspun Group. JSW Energy has

recently acquired and integrated hydro assets of JP and signed MoUs to acquire

more assets. JSW Energy has the lowest net debt/EBITDA, significant free cash flows

(post interest), management with risk appetite, and strong negotiating power.

Exhibit 62: JSWE has one of the lowest financial leverage

Net Debt / EBITDA - x

10.1

4.3

5.5

7.4

7.9

10.6

-4

-6

Exhibit 63: JSWE has strong free cash flows as well – INR b

FCF (post-interest)

Interest

assumed @ 11%

3.5

3.8

Source: MOSL, Company, Bloomberg

Although JSW Energy has 31% of its capacities without long-term PPAs, it has been

able to secure short-term PPAs for its merchant plant in Karnataka, benefiting from

the short-term regional tightness. Assets without PPAs will become more valuable

over the next 3-4 years as the market rebalances, in our view.

We re-initiate our

July 2016

Utilities | At the peak of over capacity

coverage on JSW Energy with a BUY rating for its simple business model, strong

balance sheet, regionally diversified portfolio of assets and strong negotiating

power in M&A.

Exhibit 64: Sector valuation table

TP Up/(dw) MCAP

Rating CMP#

(INR) (INR)

% (USD M)

Buy

165 205

24 12,994

Buy

153 185

21 19,034

Buy

17 2,064

Buy

312 370

19 29,633

FY16E

11.5

12.3

8.5

22.6

EPS

FY17E

14.0

11.5

7.0

19.0

FY18E

16.3

13.7

8.0

23.0

P/E (x)

FY17E FY18E

11.8

10.1

13.3

11.2

12.0

10.5

16.4

13.5

P/B(x)

FY17E FY18E

1.7

1.5

1.4

1.3

1.5

1.3

5.6

5.4

RoE (%)

FY17E FY18E

15.7

16.1

10.8

12.2

12.9

13.4

34.8

40.6

Powergrid

NTPC

JSW Energy

Coal India

# as on July 8th, 2016

Source: MOSL, Company

July 2016

Utilities | At the peak of over capacity

Annexures I – Comparative financial analysis

Exhibit 65: RoIC (%)

PSU

Power Grid

NTPC

SJVN

NHPC

Neyveli Lignite

Pvt. Sector

JSW Energy

Torrent Power

Tata Power

CESC

Reliance Power

Adani Power

KSK Energy

JP Power

Lanco Infratech

FY11

FY12

FY13

-1

FY14

FY15

FY16

Source: MOSL, Company

Exhibit 66: RoCE (%)

PSU

Power Grid

NTPC

SJVN

NHPC

Neyveli Lignite

Pvt. Sector

JSW Energy

Torrent Power

Tata Power

CESC

Reliance Power

Adani Power

KSK Energy

JP Power

Lanco Infratech

FY11

FY12

FY13

-1

FY14

FY15

FY16

Source: MOSL, Company

Exhibit 67: Net Debt / EBITDA (x)

PSU

Power Grid

NTPC

SJVN

NHPC

Neyveli Lignite

Pvt. Sector

JSW Energy

Torrent Power

Tata Power

CESC

Reliance Power

Adani Power

KSK Energy

JP Power

Lanco Infratech

FY11

FY12

FY13

FY14

FY15

FY16

-1

Source: MOSL, Company

July 2016

Utilities | At the peak of over capacity

Exhibit 68: Net Debt – INR b

PSU

Power Grid

NTPC

SJVN

NHPC

Neyveli Lignite

Pvt. Sector

JSW Energy

Torrent Power

Tata Power

CESC

Reliance Power

Adani Power

KSK Energy

JP Power

Lanco Infratech

Total

FY11

751

370

252

-3

125

957

214

232

111

142

1,708

FY12

974

509

325

-1

118

1,550

112

297

137

354

165

298

2,525

FY13

1,216

663

397

-3

124

1,912

110

347

227

401

121

221

334

3,128

FY14

1,584

786

628

147

2,120

103

351

107

274

433

143

269

361

3,703

FY15

1,954

928

861

-2

136

2,269

372

132

296

439

169

314

384

4,223

FY16

2,184

1,016

1,011

-12

128

2,347

151

375

116

289

516

186

223

417

4,531

Source: MOSL, Company

Exhibit 69: Net Debt / MW - INR m

PSU

Power Grid

NTPC

SJVN

NHPC

Neyveli Lignite

Pvt. Sector

JSW Energy

Torrent Power

Tata Power

CESC

Reliance Power

Adani Power

KSK Energy

JP Power

Lanco Infratech

FY11

-2

117

FY12

-1

110

102

FY13

-2

136

101

FY14

117

FY15

-1

FY16

-6

100

138

Source: MOSL, Company

Exhibit 70: EV/MW – INR m

PSU

Power Grid

NTPC

SJVN

NHPC

Neyveli Lignite

Pvt. Sector

JSW Energy

Torrent Power

Tata Power

CESC

Reliance Power

Adani Power

KSK Energy

JP Power

Lanco Infratech

FY11

116

106

121

242

107

117

FY12

129

375

109

127

160

103

FY13

101

157

156

135

FY14

FY15

FY16

139

116

104

117

135

114

101

142

Source: MOSL, Company

July 2016

Utilities | At the peak of over capacity

Exhibit 71: EV/EBITDA (x)

PSU

Power Grid

NTPC

SJVN

NHPC

Neyveli Lignite

Pvt. Sector

JSW Energy

Torrent Power

Tata Power

CESC

Reliance Power

Adani Power

KSK Energy

JP Power

Lanco Infratech

FY11

11.4

183

FY12

9.1

FY13

8.2

FY14

8.0

FY15

8.4

FY16

7.9

Source: MOSL, Company

Exhibit 72: P/E (x)

PSU

Power Grid

NTPC

SJVN

NHPC

Neyveli Lignite

Pvt. Sector

JSW Energy

Torrent Power

Tata Power

CESC

Reliance Power

Adani Power

KSK Energy

JP Power

Lanco Infratech

FY11

14.3

17.7

17.5

10.1

12.6

13.4

24.0

14.0

11.2

10.3

14.0

48.1

30.6

18.7

54.4

14.5

FY12

10.9

15.3

14.4

7.6

7.1

10.2

14.3

30.3

7.6

11.1

37.9

-50.7

15.7

26.7

35.4

FY13

8.9

11.6

9.3

7.4

8.4

7.6

9.3

8.2

16.9

6.9

17.1

-4.2

10.7

21.4

-2.3

FY15

FY16

9.7

10.3

15.1

11.9

12.0

10.5

6.0

8.5

7.8

9.3

7.4

11.4

13.8

14.8

14.1

9.2

21.3

9.6

46.9

15.1

10.9

26.8

15.7

19.2

15.4

11.6

-71.2

-10.5

19.1

-15.4

-6.9

-2.8

88.8

17.8

-10.8

-0.7

-0.6

66.7

Source: MOSL, Company

FY14

1.0

1.6

1.2

1.0

0.7

1.2

1.5

0.7

1.6

1.1

1.0

2.1

1.0

0.7

1.2

FY15

1.2

2.0

1.5

1.0

0.7

0.8

0.9

2.6

1.2

1.3

0.8

2.4

0.8

0.5

-3.0

FY16

1.1

1.7

1.2

1.1

0.9

0.8

0.6

1.3

1.1

1.2

0.8

1.3

0.5

0.4

-1.9

FY14

9.9

12.4

8.8

7.8

12.9

7.4

10.2

8.6

41.2

Exhibit 73: P/BV (x)

PSU

Power Grid

NTPC

SJVN

NHPC

Neyveli Lignite

Pvt. Sector

JSW Energy

Torrent Power

Tata Power

CESC

Reliance Power

Adani Power

KSK Energy

JP Power

Lanco Infratech

FY11

1.7

2.2

2.3

1.3

1.2

1.6

2.0

2.1

2.5

1.6

0.8

2.2

3.9

1.5

1.7

2.1

FY12

1.4

2.1

1.8

1.0

0.8

1.2

1.5

1.8

1.7

1.9

0.6

1.9

2.5

0.8

2.0

0.9

FY13

1.2

1.9

1.5

0.9

0.8

0.9

1.2

1.4

1.1

1.9

0.6

0.9

2.3

0.6

1.2

0.7

Source: MOSL, Company

July 2016

Utilities | At the peak of over capacity

Annexures II – Private generation capacity

Exhibit 74: Promoter group wise private generation capacity ownership (incl. under-

construction projects) along with the share of capacity without-PPA

Group

Adani Power

Tata Power

Lanco

Rpower

Vedanta

JSW Energy

JPVL

Essar

Jindal Power

GMR

KSK Energy

RattanIndia

CESC

Bajaj Energy

GVK

L&T

RKM

Abhijeet

Sembcorp

East Coast Energy Pvt. LTD.

CLP India

Nagarjuna

SKS

Athena

JITPL

Asian Genco

Coastal

IL&FS

MB Power

Thapar

Monnet

Hinduja

Ind bharath

Meenakshi

Pvt

Aryan

TRN

Madhucon

Adhunik

Rinfra

GIPCL

S Kumar

Torrent

Himagiri

Vandana

Gati

Patel Engg

LNJ Bhilwara

PIL and NSL

Total

11,040

6,792

6,336

5,760

4,980

4,440

4,320

4,200

3,400

3,300

2,940

2,700

2,485

2,430

1,720

1,499

1,440

1,326

1,320

1,200

1,050

1,040

1,000

887

625

600

540

500

400

300

270

161

144

2,235

270

2,956

1,360

1,173

1,655

2,440

1,322

523

1,350

490

180

540

250

1,320

250

606

622

180

380

775

181

425

1,000

479

210

600

250

243

144

w/o PPA

(%)

100

Source: MOSL, Company, CEA

July 2016

Utilities | At the peak of over capacity

Annexures III – Capacities expected to be closed

Exhibit 75: State gencos capacity retirement year-wise – in MW

Plant

Amarkantak

State

M.P

FY 17

240

FY20

FY21

FY22

Comments

- U 1 and 2 have already been decommissioned and are to be retired

- PLF of 46.6

- A supercritical unit is proposed to replace the retired units

- Proposal has been submitted for retirement and replacement

- High heat rates and the units proposed to be retired are 50 years old non-

reheat units

- Lower efficiency

- PLF of 44

- NTPC has taken over the plant

- 315 MW capacity is already under the process of being phased out and 130

MW will be phased out after revival of U7 and U9 which is under way

- U5 is a 38 years old non-reheat unit and hence is to be phased out to set up a

supercritical unit

- U 1 to U4 and U6 (270 MW) have already been retired

- U3 to U6 (244 MW) have already been retired, U8 has been non-operational

since 2006.

- U1 & 2 (50 MW) to be phased out after COD of U7&8 of Anpara unit (500

MW) - Are 48 years old

- PLF of 35

- Proposal has already been submitted for approval of UP government

- U1-4 are 48 years old and U5-8 are 37 years old with very high heat rates

- Enivronmental clearance for new 800 MW capacity has been granted in July

2015 subject to retirement of these units by end of 2019

- Over 45 years old with very high heat rate

- Low PLF of 32%

- Has a low PLF of 36 and the govt. has suggested lower R&M spending for 4

units (840 MW) proposed for R&M.

- Is a potential site for replacement with supercritical units

- High heat rate and low PLF of 25

- However LE and R&M has been carried out in 2007 (U1 & 2) and 2012 (U3 &

4) and the state wishes to continue operating the plant

Source: MOSL, Company, ARRs

Korba East II

CHH

200

Patratu

Harduaganj*

Jharkhand

U.P

445

Obra

U.P

194

Kothagudam Telangana

Ramagund.

Ropar

Bhatinda

Telangana

Punjab

720

62.5

1260

440

July 2016

Utilities | At the peak of over capacity

Exhibit 76: Conditional capacity retirements by state gencos

Plant

State

Capacity Capacity

to be

retired added

(in MW) (in MW)

830

660

Condition

Comments

- Has already retired 5*62.5 MW units and U 6 to U 9 have high heat rates

- Comprehensive R&M has not been approved

Satpura

M.P

On JV with NTPC

Panki

U.P

210

Chandrap.

Santaldih

Parli

Jharkhand

MAH

390

440

420

- U3 & 4 are non-reheat units and no R&M works are proposed for these units

- Environmental clearance of supercritical unit was subject to retirement of U3

On COD of

660

supercritical unit

- Have already decommissioned two units of 32 MW capacity each

- NIT for supercritical unit floated

- Has already retired U4 to U6 (390 MW) and retiring U1 to U3 (390 MW) is

On setting up 2

1320

necessary to set up the supercritical units for which primary studies have

660 MW units

been carried out

- The units have been decommissioned and the dismantling work has begun

- Has been under economic shutdown and had a PLF of 18

On commissioning - Units have to be shutdown due to nonavailability of water

of 250 MW unit - The 250 MW unit would be commissioned in FY17 depending on the rainfall

and availability of water

- U3 to U5 were declared retired since April 2014 and are under shut down

and U1 and U2 decommissioned in 2010 and 2011 respectively

Source: MOSL, Company, ARRs

Durgapur

220

July 2016

Utilities | At the peak of over capacity

Companies

BSE Sensex: 27,127

Companies

NTPC

S&P CNX: 8,323

July 2016

JSW Energy

Power Grid Corporation

Coal India

104

July 2016

July 2016

Utilities | At the peak of over capacity

Update

| Sector:

Utilities

NTPC

BSE SENSEX

27,127

S&P CNX

8,323

CMP: INR153

TP: INR185(+21%)

Buy

Earnings growth picking up along with capitalization

RoE to start improving from FY18E and drive rerating of stock

Stock Info

Bloomberg

Equity Shares (m)

52-Week Range (INR)

1, 6, 12 Rel. Per (%)

M.Cap. (INR b)

M.Cap. (USD b)

Avg Val ( INRm)

Free float (%)



NTPC IN

8,245.5

158/107

3/1/17

1,264.4

18.8

632

30.0



Financials Snapshot (INR b)

Y/E MAR

2016 2017E 2018E

Net Sales

787.1 825.4 965.8

EBITDA

191.6 221.3 288.9

PAT

101.5

95.1 112.9

EPS (INR)

12.3

11.5

13.7

Gr. (%)

15.7

-6.3

18.8

BV/Sh (INR)

104.7 109.0 115.5

RoE (%)

12.1

10.8

12.2

RoCE (%)

7.3

6.3

7.4

P/E (x)

12.5

13.3

11.2

P/BV (x)

1.5

1.4

1.3

Shareholding pattern (%)

As On

Promoter

DII

FII

Others

Mar-16 Dec-15 Mar-15

70.0

75.0

17.0

13.2

12.3

10.8

9.6

10.3

2.3

2.4



FII Includes depository receipts

Stock Performance (1-year)

NTPC

Sensex - Rebased

160



145

130

115

100



INR1.7t capitalization over five years:

NTPC is in the midst of a major capacity

expansion. The commercial capacity of NTPCsa (regulated standalone business)

is expected to grow at an accelerated five-year CAGR of 7.5% (FY16-FY21) to

56GW, as compared to 5.5% CAGR over the last five years (FY11-FY16).

Regulated equity, a key earnings driver, will grow at an even higher CAGR of

14.9% to INR829b as the specific capex for new capacities is higher. Further,

the capacity of JVs will increase by 4.7GW to 10.7GW, while solar capacity will

increase by 4GW. Thus, we expect total capitalization of INR1.7t over the

period.

PLF to decline, but some plants to earn incentives:

Despite assuming an

accelerated five-year CAGR of 6% in power generation (FY16-FY21) (as against

2% CAGR over FY11-FY16), the PLF of NTPCsa will decline from 74% in FY16 to

64% in FY21E. Some of its pit-head plants will continue to earn PLF incentives

despite the decline in overall PLF of the company and the country.

Working capital incentives to continue:

Under the new regulations for 2014-

19, most of the incentives have been squeezed out. The share of interest

income in earnings will also decline. NTPCsa will continue to earn working

capital incentives, as it is able to source capital at a much lower cost than the

normative rate as well as manage its working capital more efficiently.

We see merit in NTPC’s stand on GCV:

According to our calculations, NTPCsa is

not deriving any benefit from measurement of GCV. Hence, it is unlikely to lose

on the RoE front if it shifts to a “as received on wagon basis” from “as received

on crusher basis” as directed by the regulator. We see merit in NTPC’s position

to measure GCV at crusher. Coal India and the Ministry of Coal & Power are

making efforts to address the issue and the results are already evident in the

decline in specific coal consumption.

Earnings CAGR of 10% over five years:

As a result, we expect the NTPC group’s

consolidated (NTPCgrp) EPS to grow at a slower pace than regulated equity,

but achieve a healthy five-year CAGR of ~10% over (FY16-FY21) to

INR19.5/share in FY21E.

Book value will grow at a CAGR of 6.0% to INR140.3/share and RoE will

improve by 230bp to 14.4% in FY21E, as the share of equity invested in CWIP

declines. This is likely to result in a rerating of the stock’s P/BV multiple.

Dividend yield is likely to remain healthy at ~5%. We expect the stock to deliver

12-15% annual return (inclusive of dividends) over the next five years.

Strong business model; Reiterate Buy:

NTPC has one of the best business

models in Indian power sector. Its revenue is guaranteed by government under

PPA. Most of its plants are located close to mines and operate efficiently.

Regulators are highly dependent on inputs from NTPC for laying down norms.

We value the stock at INR185/share based on 1.5xFY18E book value.

Buy.

July 2016

Utilities | At the peak of over capacity

Capitalization momentum picking up

Regulated equity to grow at five-year CAGR of 15%

Commercial capacity of regulated business to grow at five-year CAGR of

7.5% over FY16-21E

The project work on most of the 23GW capacities has picked up, which is also

reflected in the amount of capex and commissioning of capacities. The installed

capacity of NTPC consolidated or Group (NTPCgrp) increased by 2.2GW to 46.6GW

during FY16. NTPCgrp’s commercial capacity increased by 2GW to 45.1GW. Barring a

few, most projects are running on schedule.

Exhibit 77: Commercial capacity addition schedule - MW

NTPCsa

Northern Region

Unchahar- IV

Tanda II

Koldam

TapobanVishnu.

Western Region

Vindhyachal V

Mouda II

Lara

Solapur

Gadarwara

Eastern Region

Barh-II Bihar

Barh I

N. Karanpura

Bongaigaon

Darlipalli

Southern Region

Kudgi

Solar

NTPCjv

Meja Urja Nigam

Nabinagar, BRBCL

Nabinagar NPGCPL

Kanti,Bihar

NTPCgrp

390

1,960 3,400

7,980

7,470 3,120 3,620

25,590

Source: MOSL, Company

FY16 FY17

1,960 2,760

800

FY18

5,250

FY19 FY20 FY21

6,150 3,120 3,620

1,680

660

500

660

520

3,060

FY16-21

20,900

2,340

CEA's estimate for CoD

18-Apr

U1 -Nov 18, U2 - May 19, no revision

800

500

660

2,120

660

800

660

1,820

1,320

250

500

800

1600

1,600

250

640

250

800

510

2,730

1,320

750

660

750 1,000 15,00

1,320

800

2,400

U1 -Jul 16, U2 - Mar 17, U3-Jun 17; U1&2 behind

schedule

We expect 4GW against target of 10GW

U1 -Jun 17, U2-Dec 17, advanced by one month

U1 -Apr 16, U2-Apr 17, U3-Aug 17, U4 Nov 17, delayed

by 5-6 months

U1 -Aug 17, U2-Feb 18, U3-Aug 18, advanced by 2

months

U3 195MW-Sep15, U4 195MW - May 16, actual CoD

delayed

5,840

30 Oct 2015 actual

U1 -Oct 16, U2 - Apr 17, no revision

U1 -Feb 17, U2 - Aug 17, no revision

U1 -Apr 17, U2 -Oct 17, no revision

U1 -Aug 17, U2 -Feb 18, no revision

6,310

U1 -Nov 14 actual, U2 - Feb 16

U1 -July 17, U2 - Jan 18, U3-July 18; delayed by 3 months

U1 -Dec 18, U2 - Apr 19, U3-Aug 19; no revision

U1 -Apr 16, U2 - June 17, U3-Aug 17; delayed by 4

months

U1 -Apr18, U2 - Aug 18; no revision

660

250

800

660

1,600

660 1,460 2,120

660

660 1,320

4,010

4,690

1,320

We expect NTPCsa (standalone) to add 16.9GW of conventional and 4GW of solar

capacity, while the joint ventures (NTPCjv) will add another 4.7GW of conventional

commercial capacity over the next five years. NTPCgrp’s commercial capacity will

increase by ~26GW to 71GW by end of FY21.

With the pickup in project activities, the capex momentum has already increased.

Capitalization will start picking up in FY17 with the commercial capacity addition of

2.5GW (Mauda, Bongaigaon and Kudgi). The 660MW Mauda and 250MW

July 2016

Utilities | At the peak of over capacity

Bongaigaon capacities have already been commissioned during FY16, while the

800MW Kudgi capacity is in the advanced stages of commissioning.

Capitalization to accelerate

in FY18 and FY19

Exhibit 78: Standalone capex momentum picks up

INR b

Capex

Capitalization

454

272

198

108

FY10

111

FY11

131

FY12

163

FY13

FY14

FY15

FY16

FY17

FY18

FY19

FY20

FY21

189

192

314

248

305

229

462

287

158

252

185

Source: MOSL, Company

Capitalization will see a spike in FY18 and FY19 when almost every project under

construction will add at least one unit to commercial capacity. We expect an

addition of ~5GW each to the commercial capacity. NTPCjv are expected to add

another 2.7GW in FY18 and 1.3GW in FY19.

Higher specific capex for

new projects to drive a

regulated equity growth of

~15% over FY16-21E as

against a capacity growth of

7.5% over the same period

Exhibit 79: Commercialized capacity and regulated equity (NTPCsa)

Capacity (GW)

Regulated Equity (INR b)

829

900

800

700

600

414

254

FY11

FY12

FY13

FY14

FY15

FY16

FY17

FY18

FY19

FY20

FY21

500

400

300

200

Source: MOSL, Company

Commercial capacity is expected to grow at an accelerated five-year CAGR of 7.5%

over FY16-FY21 to 56GW as compared to a five-year CAGR of 5.5% over FY11-FY16

for the standalone business. Regulated equity, a key earnings driver, will grow at an

even higher CAGR of 14.9% to INR829b as the specific capex for new capacities is

higher. The average specific capex for new capacity addition will be INR81m/MW in

FY16-FY21 as compared to INR59m/MW in FY11-FY16.

July 2016

Utilities | At the peak of over capacity

Incentives reduced under new regulations

Working capital incentives to continue, but marginal incentives for PLF and

thermal efficiencies

NTPCsa operates under a regulated environment and its revenue is approved by the CERC

(Central Electricity Regulated Commission) as per the regulations for that command

period. These regulations are reviewed every five years and ensure a defined return of

15.5% (+0.5% for early completion) on equity invested in projects and a number of

incentives for operational and financial efficiencies. NTPC sells its entire power through

PPAs (power purchase agreements) to state Discoms. Its revenue is secured through

tripartite agreement with the RBI being the third party.

NTPC had been earning handsome incentives under the old regulations for 2009-14.

Tax incentives discontinued – approximately 2-3% knocked off PAT



The actual tax rate was lower than the normative tax rate of 33.9%. The revenue

was calculated based on a marginal tax rate of 33.9%, while the actual tax rate

was lower due to various tax benefits arising from capex.

According to our calculations, NTPCsa earned approximately INR13b over FY10-

FY14 i.e. an average of INR2.5b per annum. This comprises nearly 2-3% of its

profit.

Tax incentives have now been discontinued under the new regulations for 2014-

19 and actual tax is charged to the customer.

Operating norms tightened – approximately 6-10% knocked off PAT



NTPCsa has been earning revenue based on the normative station heat rate

(SHR) and normative auxiliary consumption, while it has been operating at a

significantly better rate, which allowed it to earn additional revenue.

According to our compilation of station-wise data of normative SHR and

calculated SHR, NTPCsa was saving nearly 70kcal in SHR. This amounted to

additional earnings of INR9b-12b per annum until FY14.

Under the new regulations, the normative rates have been tightened by

~50kcal. Thus, the SHR savings have been reduced to ~17kcal. As a result, the

SHR-based incentive has reduced to INR3b-4b. Further, 40% of these reduced

savings are now shared with the beneficiary as compared to nil earlier. Thus,

NTPCsa will earn only ~INR2b incentives on a post-tax basis.

Additionally, the actual auxiliary consumption was lower than the normative

rates. As a result, NTPCsa was earning additional small incentives of ~INR200m.

The norms related to this have also been tightened.

July 2016

Utilities | At the peak of over capacity

Exhibit 80: Station heat rate and incentives (pre-tax basis)

Actual (Kcal)

Normative (Kcal)

Savings (INR b) RHS

FY11

FY12

FY13

FY14

FY15

FY16

FY17

FY18

FY19

FY20

FY21

Source: MOSL, Company



SHR norms tightened

by Rs50 kcal

2,500

2,450

2,400

2,350

2,300



The norms for secondary fuel oil consumption have been tightened from

1ml/kwh to 0.5ml/kwh and it has moved from annual fixed charges to variable

charges.

NTPCsa’s actual consumption hovers at around 0.4ml/kwh, allowing it to earn

additional incentives of nearly INR5b-8b.

One minor relief here is the reduction in sharing of incentives with the

beneficiary from 50% to 40%.

Normative rates halved, but

sharing reduced from 50%

to 40%

Exhibit 81: Savings in oil consumption (pre-tax basis)

Actual (ml/kwh)

1.00

0.75

0.50

0.25

0.00

FY11

FY12

FY13

FY14

FY15

FY16

FY17

FY18

FY19

FY20

FY21

Normative (ml/kwh)

Savings (INR b) RHS

10.0

7.5

5.0

2.5

0.0

Source: MOSL, Company



According to our calculations, the incentives from SHR, oil and Aux.

consumption contributed 8-12% to the PAT until FY14. These incentives are now

estimated to be less than 2%.

July 2016

Utilities | At the peak of over capacity

Exhibit 82: PAF / PLF incentive (post-tax basis) in INRb

Regulation (FY10-14): PAF based

Regulations (FY15-19): Incentives are based

on PLF, which is declining

FY21

Approximately 6-8%

knocked off PAT due to new

regulations

FY10

FY11

FY12

FY13

FY14

FY15

FY16

FY17

FY18

FY19

FY20

Source: MOSL, Company



Under the new regulations, the PAF-based incentives have been done away

with. Instead, the incentives are now linked to PLF, which is now dependent

upon scheduling by Discoms and it is beyond the control of NTPCsa if its variable

cost is high.

NTPCsa has increased its capacities at a CAGR of 5.5% over the last five years,

though generation has grown at a CAGR of only 2%. As a result, NTPCsa’s PLF

has declined from 86% in FY11 to 74% in FY16. Despite assuming a faster CAGR

of 6% in demand, NTPCsa’s PLF will decline further to 65% as capacity addition

will grow at a faster CAGR of 7.5% over the next five years.

All India PLF has also been on a declining trend due to capacity addition

outpacing demand growth.

Exhibit 83: Sales and PLF

Sales (b kwh)

320

PLF (%) on RHS

100

FY11

FY12

FY13

FY14

FY15

FY16

FY17

FY18

FY19

FY20

FY21

Source: MOSL, Company



PLF to decline further

300

280

260

240

220

200

Despite the decline in NTPCsa’s PLF, some of its plants and units continue to

achieve a PLF of above 90%. These plants are pithead-based and have been

operating at very high operating efficiencies. Therefore, we expect NTPCsa to

continue earning PLF-linked incentives, which however are likely to be much

lower.

July 2016

Utilities | At the peak of over capacity

Exhibit 84: Fuel-wise share of capacities

Dominance of coal-based

plants to continue

Coal

Gas

Hydro

Solar

FY11

FY12

FY13

FY14

FY15

FY16

FY17

FY18

FY19

FY20

FY21

Source: MOSL, Company

Exhibit 85: NTPC’s coal-based plant PLFs FY16 (%)

Source: MOSL, Company



NTPCsa earns incentives mostly on its coal-based power plants which will

continue to dominate the overall capacity, as there are virtually no new

investments in new gas and hydro projects. However, the share of coal

capacities will decline marginally due to solar plants.

Gas-based power plants run on a low PLF due to shortage of domestic gas and

high cost of imports. Hence, these plants do not earn incentives.

Discoms have a prudent system of scheduling power purchases, which is based

on merit order. Power plants are scheduled in such a way that the overall

variable cost for a Discom is minimized. In such a situation, NTPCsa’s pithead

plants are at an advantage as the variable cost of power generation comprises

the cost of coal and transportation. The cost of coal is similar for all players as

they all source coal from Coal India, but the key difference lies in transportation

costs. Pithead power plants are at a distinct advantage and still operate at a PLF

of above 85% despite the huge overcapacity in the country.

July 2016

Utilities | At the peak of over capacity

Exhibit 86: Distance of coal-based power plants from coal mines (share %)

Share of pithead plants

to decline

>1000kms

600-1000

kms

<600 kms

Pit Head

Source: MOSL, Company

Exhibit 87: Generation based incentive on PLF >85% - INR m

Source: MOSL, Company

Working capital a key source of incentives



As per aggregation of data from tariff order, NTPCsa’s actual total debt is lower

than the normative debt (excluding working capital), indicating that the

company has been funding its entire working capital from equity.

Exhibit 88: Normative debt as per tariff orders and actual debt

(Normative - actual debt) in INR b

Increasing capex will force

NTPCsa to fund its working

capital through borrowings

-20

-40

-60

-80

FY11

FY12

FY13

FY14

FY15

FY16

FY17

FY18

FY19

FY20

FY21

Source: MOSL, Company



Normative working capital interest, charged to revenue, is based on short term

bank lending rates and normative days for inventory of fuel, debtors, and

spares.

July 2016

Utilities | At the peak of over capacity



NTPCsa enjoys a dual advantage as its actual working capital is lower than the

normative and its cost of funding is much lower than the normatively allowed

short term bank lending rates.

During FY15, there was an increase in the actual working capital, resulting in

lower working capital incentives. We expect working capital to normalize

(reduce) and incentives to increase.

Exhibit 89: Working capital incentives (post-tax) – INR b

120

100

FY11

FY12

FY13

FY14

FY15

FY16

FY17

FY18

FY19

FY20

FY21

Actual WC

Normative WC

Incentive from WC savings (RHS)

Source: MOSL, Company



NTPCsa also earns from

equity funding of working

capital

Capital structure was leveraged by issuing bonus debenture towards the end of

FY15. We believe that NTPCsa will have to resort to borrowings in order to fund

its working capital which will pull down its core earnings.

Regulated equity now the key earnings driver

Regulated equity contributed only 40-45% of NTPC’s earnings until FY14. NTPC

earned handsome incentives under the liberal structure of the previous regulations

for 2009-14 and also recorded a high other income from surplus funds on its balance

sheet. However, the normative parameters have now been tightened under the new

regulations for 2014-19, resulting in most of the incentives being squeezed out.

Exhibit 90: NTPC’s PAT distribution (%)

100

With incentives getting

squeezed, regulated equity

becomes the key earnings

driver

WC etc.

PAF/PLF

Thermal eff.

Oth. income

Tax

Reg. Equity

FY10 FY11 FY12 FY13 FY14 FY15 FY16 FY17 FY18 FY19 FY20 FY21

Source: MOSL, Company

July 2016

Utilities | At the peak of over capacity

GCV: As received at crusher or at incoming wagon

We are not factoring any GCV gains in our estimates

The 2014-19 CERC regulations changed the norms for determining GCV of coal from

an ‘as fired’ basis to ‘as received’ basis. NTPC and a few other power plants are

contesting the change in the High Court. The norms were refined to fix

accountability for GCV losses incurred between “as billed” and “as fired.” While

there is undoubtedly a big gap between the two, the gap arises because coal starts

to lose GCV as soon as it comes into contact with air i.e. immediately after over

burden removal. Mined coal remains in inventories of mines for 3-4 weeks, remains

for a couple of weeks in rail transit, and for 3-4 weeks in inventories of power

plants. Further, there are issues of grade slippages. As per compilation of data in the

following table, the gap ranges from ~1000kcal/kg for a pithead plant to

1,875kcal/kg for Tanda.

Exhibit 91: NTPC’s gap between GCV ‘as billed’ and ‘as fired’ coal

gap with as billed

4,488

4,725

4,096

4,151

4,808

4,973

3,917

As fired

4,663

4,704

4,790

5,022

5,354

954

968

1,008

1,029

1,084

1,215

1,318

1,327

1,371

1,496

1,584

1,875

** Pithead plants

Source: Form15 (Jan-Mar 2014) in tariff petitions

Coal India making concerted

efforts to improve the

quality of coal

In the last two years, Coal India and the Ministry of Power have undertaken a

number of initiatives to address this issue. There is a joint sampling to accurately

measure the GCV of coal. Coal India has also begun supplying 100% crushed coal.

Both the Ministry of Power and Coal India have committed to the states in the

agreement under UDAY that there will re-grading of coal mines, while pricing of coal

will move to a GCV basis and Coal India will supply 100% crushed coal to address the

quality issues. The results of these efforts are reflected in the trends in average

specific consumption of coal at power plants.

July 2016

Utilities | At the peak of over capacity

Exhibit 92: Specific consumption of coal in power generation

declining, implying part benefit of GCV improvement

0.71

0.69

0.67

0.72

0.71

0.69

0.66

0.65

Exhibit 93: Specific cons. In FY16 improved despite fall in

share of imported coal in total mix

Share of imports (%)

16.2

17.2

14.8

13.8

10.8

7.8

0.0

Source: MOSL, Company

NTPC’s stand is reasonable,

in our view

As a result of the regulation NTPC has also moved its billing to “as received basis”

but at secondary crusher. There is still a dispute regarding the point of sampling. The

CERC and the High Court want the coal sample for measuring GCV to be picked up

from incoming wagons. NTPC has claimed that it is unsafe to collect samples from

wagons due to overhead electric traction. There is also additional demurrage as a

result of a slower turnaround. Further, there will be high volatility in GCV

measurements as coal is not homogeneous. Hence, it is desirable to blend and crush

before taking measurements.

We believe that NTPC is just a processor of coal. According to our analysis of its

earnings and operational data, NTPC is not under reporting GCV of coal. It must also

be kept in mind that the design station heat rates are based on coal “as fired basis.”

No equipment supplier will take responsibility for loss of GCV in storage.

We are currently not building any gains/losses on account of the changed

regulations as, in-line with the CERC, we believe that the losses are minimal. In any

case, if they turn out to be significant, but under normative conditions, we believe

(as per the Statement of Reason given by CERC on the 2014-19 regulations), it would

be adequately factored by the CERC in its tariff computation unless they are

particularly on account of NTPC.

We believe NTPC is not

under reporting GCV of coal

We are not factoring

GCV gains in our estimates

July 2016

Utilities | At the peak of over capacity

Joint ventures to add 4.7GW

Turnaround expected by FY18

NTPC has four subsidiaries and a number of joint ventures. A few of its subsidiaries

are into trading and distribution of power. Most of the JVs are profitable, barring a

few. Ratnagiri Gas operates a 1,967MW gas-based power plant in Maharashtra and

reported a loss of INR4b in FY15 due to high gas prices. Together, NTPCjv reported a

PAT of INR4.3b in FY14 and a loss after tax of INR3b in FY15.

Exhibit 94: Financials and subsidiaries of JVs

Name of the Company

(%)

NTPC Electric Supply Company Ltd.

NTPC Vidyut Vyapar Nigam

Kanti Bijlee Utpadan Nigam

Bhartiya Rail Bijlee Company

Minority interest

JVs Major

Ratnagiri Gas & Power Private Ltd

NTPC-SAIL Power Company Private

NTPC-Tamilnadu Energy Company

Aravali Power Company Private

Meja Urja Nigam Private

Nabinagar Power Generating Company

JVs

Utility Powertech

NTPC - Alstom Power Services Private

NTPC - BHEL Power Projects

National High Power Test Laboratory

Transformers & Electricals Kerala

Energy Efficiency Services

CIL NTPC Urja

Anushakti Vidyut Nigam

Overseas

Trincomalee Power Company, Sri Lanka

Bangladesh -India Friendship Power Company

Winding up

NTPC-SCCL Global Ventures Private (Withdrawn)

BF - NTPC Energy Systems (withdrawn)

National Power Exchange (winding up)

International Coal Ventures (withdrawing)

Pan-Asian Renewables (winding up)

100

FY14

Asset

Rev.

Cash

flow

(%)

Asset

FY15

Rev.

Cash Attrib.

flow

PAT

-1,486

-2,902

436

343

112

863

-257 -4,052

-201 1,137

-178

-434

899

176

-25

-69

-65

-14

-4

116

-147

7,311

591 -1,364

12,244 35,323 1,146

31,118 1,622

132

43,007

-72

100 6,449

418

236

100 11,662 2,059 38,880

65 38,279 8,843 4,605

74 52,375 11,720

8,879

29,688 2,621

525

16,710 8,212 8,115

47,127 12,433 9,864

49,076 16,438 22,257

18,973 5,400

20,553 5,105

1,307

625

3,760

507

598

789

405

272

113

663

234

383

287

2,954

349

2,963

590

176

40,836 7,283 -1,982

17,079 8,835

151

45,947 7,550

48,885 17,492

-4

9,262

276

9,846

-59

1,091

405

2,304

214

734

318

2,505

176

429

758

105

-1

316

-49

-1

-6

320

-2

-4

Source: MOSL, Company

The JVs had a combined commercial capacity of 6GW by end of FY16. It is likely that

Ratnagiri Gas’ losses would reduce due to a fall in gas prices and the JV with TNEB to

return to profitability as the third 500MW unit at Vallur stabilizes with a higher PLF.

However, we are not factoring the expected turnaround in our estimates.

NTPCjv to begin adding to commercial capacities from start of FY17



Nearly 640MW (390MW Kanti + 250MW Nabinagar) of capacity was

commissioned during FY16 and is expected to be commercialized in FY17. This

July 2016

Utilities | At the peak of over capacity



will add INR19b (share of NTPCjv) to the gross block and INR871m to the bottom

line of NTPCgrp.

2.7GW of capacities are expected to be commercialized during FY18. The

1,320MW Meja Urja project’s CEA’s expected date of CoD has been advanced by

one month in the recent CEA’s broad status report for January. This will add

INR129b (share of NTPCjv) to the gross block and INR6b to the bottom line of

NTPCgrp.

1,320MW i.e. the second and third units of Nabinagar JV are expected to be

commercialized in FY19. The state government of Bihar has shown active

interest in the project. In last 3-4 months, the CEA’s expected date of CoD has

been advanced by two months. This will add INR67b (share of NTPCjv) to the

gross block and INR3.1b to the bottom line of NTPCgrp.

Exhibit 95: Commercial capacity addition estimates

NTPCjv

Meja Urja Nigam

Nabinagar, BRBCL

Nabinagar NPGCPL

Kanti,Bihar

FY17

FY18

640 2,730

1,320

250

750

660

390

FY19

1,320

FY16-21

4,690

CEA's estimate for CoD

U1 -Jun 17, U2-Dec 17, advanced by one month

U1 -Apr 16, U2-Apr 17, U3-Aug 17, U4 Nov 17, delayed by 5-6

months

U1 -Aug 17, U2-Feb 18, U3-Aug 18, advanced by 2 months

U3 195MW-Sep15, U4 195MW - May 16, actual CoD delayed

Source: MOSL, Company



1,320

We expect NTPCjv to turnaround by FY18E on the back of CoD of 3.4GW

projects during F17E and FY18E.

Exhibit 97: Capitalization to pick up

7.0

3.9

Exhibit 96: JVs to turnaround in FY18

PAT (INR b)

4.3

-3.0

FY14

FY15

-3.0

FY16

-2.1

FY17

FY18

FY19

Source: MOSL, Company

July 2016

Utilities | At the peak of over capacity

Project commissioning to drive earnings and RoE

INR1.7t of capitalization ahead; Reiterate BUY



NTPC is in the midst of a major capacity expansion. The commercial capacity of

NTPCsa (regulated standalone business) is expected to grow at an accelerated

five-year CAGR of 7.5% (FY16-FY21) to 56GW, as compared to 5.5% CAGR over

the last five years (FY11-FY16). Regulated equity, a key earnings driver, will grow

at an even higher CAGR of 14.9% to INR829b as the specific capex for new

capacities is higher. Further, the capacity of JVs will increase by 4.7GW to

10.7GW, while solar capacity will increase by 4GW. Thus, we expect total

capitalization of INR1.7t over the period.

Despite assuming an accelerated five-year CAGR of 6% in power generation

(FY16-FY21) (as against 2% CAGR over FY11-FY16), the PLF of NTPCsa will decline

from 74% in FY16 to 64% in FY21E.

Under the new regulations for 2014-19, most of the incentives have been

squeezed out. The share of interest income in earnings will also decline. NTPCsa

will continue to earn working capital incentives, as it is able to source capital at

a much lower cost than the normative rate as well as manage its working capital

more efficiently. Some of its pit-head plants will continue to earn PLF incentives

despite the decline in overall PLF of the company and the country.

According to our calculations, NTPCsa is not deriving any benefit from

measurement of GCV. Hence, it is unlikely to lose on the RoE front if it shifts to a

“as received on wagon basis” from “as received on crusher basis” as directed by

the regulator. We see merit in NTPC’s position to measure GCV at crusher.

As a result, we expect the NTPC group’s consolidated (NTPCgrp) EPS to grow at a

slower pace than regulated equity, but achieve a healthy five-year CAGR of 10%

over (FY16-FY21) to INR19.5/share in FY21E.

Book value will grow at a CAGR of 6% to INR140.3/share and RoE will improve

by 230bp to 14.4% in FY21E, as the share of equity invested in CWIP declines.

This is likely to result in a rerating of the stock’s P/BV multiple.

Dividend yield is likely to remain healthy at ~5%. We expect the stock to deliver

12-15% annual return (inclusive of dividends) over the next five years.

We value the stock at INR185/share based on 1.5xFY18E book value. We

reiterate

Buy.

Exhibit 98: Regulated equity and conventional generation capacity growth

Regulated equity to grow at

CAGR of 15%

Capacity (GW)

Regulated Equity (INR b)

829

900

800

700

600

414

254

FY11

FY12

FY13

FY14

FY15

FY16

FY17

FY18

FY19

FY20

FY21

500

400

300

200

Source: MOSL, Company

July 2016

Utilities | At the peak of over capacity

Share of cash and

equivalents to decline and

impact share of interest

income in PAT

Exhibit 99: Application of equity

Working Capital etc

Cash & equiv.

Investments (non-

current)

30% of adj. CWIP

Reg. Equity

Source: MOSL, Company

NTPCsa EPS to grow at a

slightly slower CAGR of

~12% due to declining share

of Other income

Exhibit 100: NTPCsa EPS (INR/share) will grow at CAGR of ~12% over FY16-21E

14.8

16.7

18.2

9.9

7.7

10.7

11.2

10.6

10.5

11.4

12.8

FY10

FY11

FY12

FY13

FY14

FY15

FY16

FY17

FY18

FY19

FY20

FY21

Source: MOSL, Company

NTPCsa RoE to improve

along with decline in share

of CWIP

Exhibit 101: NTPCsa RoE

RoE (%)

13.0

9.8

12.4

12.0

10.7

11.5

12.6

13.5

13.8

10.5

10.4

10.3

FY10

FY11

FY12

FY13

FY14

FY15

FY16

FY17

FY18

FY19

FY20

FY21

Source: MOSL, Company

Dividend yield remains

attractive (assuming payout

~45-55%)

Exhibit 102: NTPCgrp DPS (INR/share) and yield

DPS

15.0

8.0

6.2

FY20

8.5

6.6

FY21

Div. Yield (%)

5.8

4.5

FY14

11.6

6.0

4.7

6.0

4.7

FY17

6.0

4.7

FY18

7.5

5.8

FY19

FY15

FY16

Source: MOSL, Company

July 2016

Utilities | At the peak of over capacity

Book value to grow at

CAGR of 6%

Exhibit 103: NTPCgrp BV and RoE

140

130

120

110

100

FY14

FY15

FY16

FY17

FY18

FY19

FY20

FY21

106

100

105

BV (INR/sh.)

RoE (%), RHS

Source: MOSL, Company

July 2016

Utilities | At the peak of over capacity

Annexure

Exhibit 104: NTPC approved fixed and variable cost unit-wise (FY15)

Fixed charges (INR/kWh)

Energy Charges (INR/kWh)

5.5

3.9

3.6

NTPC avg. (INR/kWh)

5.9

4.6

8.2

3.8

6.2

3.7

3.1

1.7

2.9

2.6

3.4

2.8 3.9

3.0

1.6

1.0

2.6 2.4 2.6

4.5

1.4 1.4 2.8 2.8

2.5 1.3

1.6

2.4

1.7 1.6

1.5 1.5

2.5

1.2

1.1

1.4 0.6 0.9 0.8 1.3 1.6 0.6 1.7 0.6 0.9 1.9 0.9 0.8 1.5 1.4 0.9 1.0 1.4 0.9 1.8 1.0 1.9 1.1 1.3 1.0 1.4 1.1 1.7

1.8

3.2

2.5 2.4 2.9

3.5 3.1

2.9 2.9

2.7 3.1

2.3 2.3

3.7 3.7 4.1

4.8

4.8 4.5

4.3

3.6 3.8 3.7

Source: MOSL, Company

Exhibit 105: Regulated Equity (as per tariff orders) – INR b

Coal-based

Singrauli

Rihand

Unchahar

Tanda

Korba

Vindyachal

Sipat

Mauda

Ramagundam

Simhadri

Farakka

Kalagaon

Talcher Kaniha

Talcher

Dadri

Badarpur

Barh

Bonglagaon

Muzaffarpur

Gas-based

Anta

Auraiya

Kawas

Dadri

Jhanor Gandhar

Kayamkulam CCPP

Faridabad

Total

FY10

196

240

FY11

212

256

FY12

235

279

FY13

282

327

FY14

FY15

301

343

347

386

Source: MOSL, Company

July 2016

Utilities | At the peak of over capacity

Exhibit 106: Normative Debt (as per tariff orders) – INR b

Coal-based

Singrauli

Rihand

Unchahar

Tanda

Korba

Vindyachal

Sipat

Mauda

Ramagundam

Simhadri

Farakka

Kalagaon

Talcher Kaniha

Talcher

Dadri

Badarpur

Barh

Bonglagaon

Muzaffarpur

Gas-based

Anta

Auraiya

Kawas

Dadri

Jhanor Gandhar

Kayamkulam CCPP

Faridabad

Total

FY10

159

166

FY11

177

184

FY12

207

215

FY13

290

299

FY14

332

342

FY15

346

358

Source: MOSL, Company

July 2016

Utilities | At the peak of over capacity

Exhibit 107: Fixed charge incl. WC and O&M – INR b

Coal-based

Singrauli

Rihand

Unchahar

Tanda

Korba

Vindyachal

Sipat

Mauda

Ramagundam

Simhadri

Farakka

Kalagaon

Talcher Kaniha

Talcher

Dadri

Badarpur

Barh

Bonglagaon

Muzaffarpur

Gas-based

Anta

Auraiya

Kawas

Dadri

Jhanor Gandhar

Kayamkulam CCPP

Faridabad

Total

FY10

136

158

FY11

154

176

FY12

166

190

FY13

204

228

FY14

221

246

FY15

238

261

Source: MOSL, Company

Exhibit 108: Operating heat-rate (kCal/kg)

FY10

Coal-based

Singrauli

Rihand

Unchahar

Tanda

Korba

Vindyachal

Sipat

Mauda

Ramagundam

Simhadri

Farakka

Kalagaon

Talcher Kaniha

Talcher

Dadri

Badarpur

Barh

Bonglagaon

Muzaffarpur

2,393

2,347

2,387

2,728

2,369

2,375

2,360

2,372

2,351

2,415

2,372

2,356

2,867

2,500

2,773

FY11

2,393

2,347

2,383

2,727

2,375

2,372

2,347

2,371

2,348

2,407

2,378

2,357

2,859

2,285

2,750

FY12

2,393

2,346

2,403

2,732

2,381

2,372

2,349

2,371

2,348

2,400

2,390

2,353

2,851

2,483

2,750

FY13

2,393

2,350

2,417

2,770

2,383

2,370

2,340

2,371

2,364

2,399

2,405

2,360

2,843

2,481

2,749

FY14E

FY15E

2,390

2,392

2,357

2,405

2,408

2,759

2,754

2,384

2,378

2,380

2,376

2,343

2,369

2,370

2,371

2,365

2,357

2,403

2,401

2,398

2,371

2,385

2,366

2,823

2,839

2,481

2,429

2,755

2,751

2,262

Source: MOSL, Company

July 2016

Utilities | At the peak of over capacity

Financials and Valuations

Income Statement

Y/E Mar

Net Sales

Change (%)

EBITDA

EBITDA Margin (%)

Depreciation

EBIT

Interest

Other Income

Extraordinary items

PBT

Tax

Tax Rate (%)

Min. Int. & Assoc. Share

Reported PAT

Adjusted PAT

Change (%)

2011

550,627

18.7

119,729

21.7

24,857

94,872

14,210

23,447

16,387

120,496

29,470

24.5

91,026

80,192

-1.0

2012

620,522

12.7

137,263

22.1

27,917

109,346

17,116

27,897

3,136

123,262

31,024

25.2

92,237

90,969

13.4

2013

657,370

5.9

170,672

26.0

33,968

136,704

19,244

31,188

17,138

165,786

39,592

23.9

126,194

109,726

20.6

2014

789,506

20.1

197,106

25.0

47,700

149,406

32,031

27,601

-119

144,858

30,824

21.3

114,034

91,496

-16.6

2015

806,220

2.1

171,941

21.3

55,646

116,295

35,704

20,789

3,292

104,672

4,638

4.4

100,034

87,706

-4.1

2016

787,055

-2.4

191,632

24.3

61,534

130,098

41,513

12,341

100,926

-589

-0.6

101,514

15.7

2017E

825,365

4.9

221,275

26.8

66,382

154,893

49,983

15,317

120,226

25,125

20.9

95,101

-6.3

(INR Million)

2018E

965,827

17.0

288,860

29.9

85,215

203,645

73,001

11,046

141,691

28,752

20.3

112,939

18.8

Balance Sheet

Y/E Mar

Share Capital

Reserves

Net Worth

Debt

Deferred Tax

Total Capital Employed

Gross Fixed Assets

Less: Acc Depreciation

Net Fixed Assets

Capital WIP

Investments

Current Assets

Inventory

Debtors

Cash & Bank

Loans & Adv, Others

Curr Liabs & Provns

Curr. Liabilities

Provisions

Net Current Assets

Total Assets

2011

82,455

596,468

678,923

431,877

6,030

1,116,829

727,552

335,192

392,360

354,953

105,328

404,748

36,391

14,350

179,973

174,034

140,560

264,188

1,116,829

2012

82,455

650,457

732,912

502,789

6,369

1,242,070

818,283

365,719

452,564

418,279

95,839

441,626

37,029

58,325

177,643

168,630

166,237

275,389

1,242,070

2013

82,455

721,421

803,875

581,461

9,153

1,394,489

1,032,457

403,096

629,361

371,094

91,376

519,333

40,572

53,650

184,902

240,210

216,676

302,657

1,394,489

2014

82,455

790,843

873,297

814,549

12,393

1,707,044

1,313,937

471,858

842,080

538,250

16,635

603,487

59,885

67,257

186,876

289,470

293,408

310,080

1,707,044

2015

82,455

738,485

820,940

1,022,520

12,656

1,864,995

1,443,608

525,077

918,530

675,547

141

601,543

79,725

92,499

161,390

267,929

330,766

270,777

1,864,995

2016

82,455

780,753

863,208

1,149,537

12,656

2,034,280

1,531,162

586,611

944,550

859,623

141

563,365

67,307

89,682

138,447

267,929

333,399

229,966

2,034,280

2017E

82,455

816,487

898,941

1,299,585

12,656

2,220,062

1,797,658

652,994

1,144,664

906,947

141

498,422

61,336

80,258

88,899

267,929

330,112

168,310

2,220,062

(INR Million)

2018E

82,455

870,058

952,513

1,432,885

12,656

2,406,933

2,380,374

738,208

1,642,166

628,922

141

478,411

67,333

91,794

51,355

267,929

342,707

135,704

2,406,933

July 2016

Utilities | At the peak of over capacity

Financials and Valuations

Ratios

Y/E Mar

Basic (INR)

EPS

Cash EPS

Book Value

DPS

Payout (incl. Div. Tax.)

Valuation(x)

P/E

Cash P/E

Price / Book Value

EV/Sales

EV/EBITDA

Dividend Yield (%)

Profitability Ratios (%)

RoE

RoCE

RoIC

Turnover Ratios (%)

Asset Turnover (x)

Debtors (No. of Days)

Inventory (No. of Days)

Leverage Ratios (%)

Net Debt/Equity (x)

2011

9.7

14.1

82.3

3.8

34.4

13.9

10.9

1.9

2.8

14.0

2.5

9.8

7.7

15.9

1.5

0.4

2012

11.0

14.6

88.9

4.0

35.8

13.7

10.5

1.7

2.6

11.8

2.6

12.4

8.7

15.9

1.5

0.4

2013

13.3

19.4

97.5

5.8

37.6

10.0

7.9

1.6

2.5

10.7

3.7

12.0

8.8

16.0

1.2

0.5

2014

11.1

19.6

105.9

5.8

41.6

11.1

7.8

1.4

2.4

10.6

3.7

10.9

8.2

13.7

1.1

0.7

2015

10.6

18.9

99.6

5.8

47.4

12.6

8.1

1.5

2.6

11.9

3.7

10.0

6.0

11.2

0.9

1.0

2016

12.3

19.8

104.7

6.0

48.7

12.5

7.8

1.5

2.9

11.9

3.9

12.1

7.3

12.7

0.8

1.2

2017E

11.5

19.6

109.0

6.0

52.0

13.3

7.8

1.4

3.0

11.2

3.9

10.8

6.3

10.8

0.8

1.3

2018E

13.7

24.0

115.5

6.0

43.8

11.2

6.4

1.3

2.7

9.2

3.9

12.2

7.4

11.0

0.7

1.4

Cash Flow Statement

Y/E Mar

Adjusted EBITDA

Non cash opr. exp (inc)

(Inc)/Dec in Wkg. Cap.

Tax Paid

Other operating activities

CF from Op. Activity

(Inc)/Dec in FA & CWIP

Free cash flows

(Pur)/Sale of Invt

Others

CF from Inv. Activity

Inc/(Dec) in Net Worth

Inc / (Dec) in Debt

Interest Paid

Divd Paid (incl Tax) & Others

CF from Fin. Activity

Inc/(Dec) in Cash

Add: Opening Balance

Closing Balance

2011

108,335

68,026

-24,655

-29,544

-11,312

110,850

-110,855

-5

34,199

-1,215

-77,872

50,473

-30,998

-36,511

-17,036

15,943

164,030

179,973

2012

134,446

56,429

-23,494

-17,607

-11,109

138,666

-130,577

8,089

18,039

234

-112,304

52,135

-39,693

-41,133

-28,691

-2,330

179,973

177,643

2013

155,792

62,983

-5,971

-28,956

-28,896

154,952

-162,912

-7,960

16,225

6,519

-140,169

72,624

-39,461

-40,688

-7,524

7,259

177,643

184,902

2014

178,937

45,263

-13,109

-26,867

-18,917

165,308

-189,485

-24,176

16,225

37,017

-136,243

93,854

-62,429

-58,516

-27,091

1,975

184,902

186,876

2015

179,139

16,355

-11,694

-20,100

-16,242

147,459

-191,772

-44,314

16,391

17,182

-158,200

205,811

-72,371

-148,185

-14,745

-25,486

186,876

161,390

2016

191,632

12,451

17,868

589

-12,341

210,198

-271,630

-61,432

12,352

-259,278

127,017

-41,513

-59,367

26,137

-22,943

161,390

138,447

2017E

221,275

15,317

12,108

-25,125

-15,317

208,258

-313,821

-105,563

15,317

-298,504

150,048

-49,983

-59,367

40,698

-49,548

138,447

88,899

(INR Million)

2018E

288,860

11,046

-4,938

-28,752

-11,046

255,170

-304,691

-49,521

11,046

-293,645

133,299

-73,001

-59,367

931

-37,544

88,899

51,355

July 2016

July 2016

Utilities | At the peak of over capacity

Update

| Sector:

Utilities

JSW Energy

Buy

BSE SENSEX

27,127

S&P CNX

8,323

CMP: INR84

TP: INR98 (+17%)

Lowest leverage at peak of overcapacity in the sector

Stock Info

Bloomberg

Equity Shares (m)

52-Week Range (INR)

1, 6, 12 Rel. Per (%)

M.Cap. (INR b)

M.Cap. (USD b)

Avg. Val (INR m)/Vol m

Free float (%)

Reinstating coverage with BUY and TP of INR98

JSW IN

1,640.1

106/59

18/-8/-13

138.3

2.1

218.6 / 2.5

25.0

Financials Snapshot (INR b)

Y/E MAR

2016 2017E 2018E

Net Sales

99.7 101.0 101.7

EBITDA

41.4

42.5

42.0

PAT

14.0

11.5

13.1

EPS (INR)

7.6

7.0

8.0

Gr. (%)

-10.0

-8.0

14.1

BV/Sh (INR)

52.0

56.8

62.4

RoE (%)

15.5

12.9

13.4

RoCE (%)

12.5

11.0

11.3

P/E (x)

9.2

12.1

10.6

P/BV (x)

1.3

1.5

1.3

Shareholding pattern (%)

As On

Promoter

DII

FII

Others

Mar-16 Dec-15 Mar-15

75.0

11.8

12.0

6.2

9.0

8.9

7.2

4.2

4.1

11.5

FII Includes depository receipts

Stock Performance (1-year)

JSW Energy

Sensex - Rebased

120

100

Two-thirds of capacity contracted under PPAs, providing sufficient cash flows to

service consolidated debt



JSW Energy’s (JSWE) 2,777MW of capacity is contracted under long-term (LT)

PPAs. Another 200MW of LT PPA is expected from Punjab for its hydro assets,

which will increase the share of LT PPAs to 67%.



LT PPAs have a set of structured and fairly predictable cash flows. In the first

10 years, annual EBITDA is expected to be ~INR20-25b (~60% of consolidated

EBITDA), which we believe is sufficient to service debt.

Open capacity is well diversified, only 10% capacity is vulnerable



JSWE has benefited in the short-term (ST) market from tight supply in the

southern region (SR). With improving inter-region transmission, JSWE is

reducing its exposure to the ST market as premiums are coming off in SR.



Only 33% capacity is now exposed to the ST market, but majority of it is in the

critically balanced market of Karnataka in SR. Expected PPAs from this state

are likely to help tide over the next three difficult years, after which the

market is expected to find balance. Only 10% of its capacity is vulnerable

being exposed to the oversupplied western region (WR).

Merchant power market will thrive, but rates will be capped at INR3/kWh



Despite oversupply, the merchant market will thrive as there is an arbitrage

between high variable cost of contracted capacities and cost of new stranded

plants. Merchant rates will be capped at INR3/kWh, in our view.



We are factoring in INR2.75/kWh for non-SR and INR4.3/kWh for SR.

High capital efficiency and strong free cash flows



JSWE is one of the few companies in the sector that has built a strong set of

assets at low cost. JSWE is generating strong operating cash flows.



JSWE’s balance sheet and return ratios are the best among private names.

With capex now behind, free cash flows have turned positive.

Inorganic growth opportunities plenty, patience is the key



At the peak of overcapacity, organic growth still does not make sense.



But inorganic growth opportunities are plenty amid financially stressed

competition. Patience is the key, in our view.

Reinstating coverage with BUY with TP of INR98



Strong free cash flows and lowest financial leverage amid financially stressed

competition provide strong negotiating power to JSWE for inorganic growth at

the peak of overcapacity. JSWE has been able to consistently generate double-

digit RoEs due to low cost of its projects.



SOTP of EV is INR279b, which will decline gradually if not reinvested. Since net

debt is declining at a faster rate, equity value will continue increasing. We

value JSWE at INR98/share based on FY18E SOTP. We reinstate coverage with

a BUY rating.

July 2016

Utilities | At the peak of over capacity

63-67% of capacity contracted under PPAs

This provides sufficient cash flows to service consolidated debt



63% or 2,777MW of JSWE’s generation capacity is contracted under long-term PPAs.

Another 200MW of PPA is expected from Punjab for its Karcham Wangtoo hydro

assets, which will increase the share of LT PPAs to 67%.

LT PPAs have a set of structured and fairly predictable cash flows. In the ensuing 10

years, annual EBITDA is expected to be ~INR20-25b (i.e. ~60% of consolidated EBITDA),

which we believe is sufficient to service consolidated debt.

~63% or 2,777MW of JSWE’s generation capacity is contracted under long-term

PPAs. Another 200MW of PPA is expected from Punjab once the tariff is approved

for its Karcham Wangtoo hydro power plant, which was acquired from Jai Prakash

Power (JPVL) in FY16. If the Punjab PPA is finalized, the share of PPAs will increase to

67% of total capacity.

Exhibit 109: Portfolio of diversified assets

S.N. Asset

Vijaynagar

Ratnagiri

RajWest

Baspa-II

K. Wangtoo

Location

State Region

K'taka

Maha.

Raj.

Fuel

Imp. coal

Lignite

Hydro

Capacity

LT PPAs (MW)

Open

PLF (%)

(MW) free PPA Total (MW) FY15 FY16 FY17E FY18E

860

860 97.4 89.7 90.0

90.0

1,200

773

427 72.7 79.8 85.0

85.0

1,080

1,080 1,080

77.7 76.3 85.0

85.0

300

264

300

47.7 49.7 50.0

50.0

1,000

120 504

624

376 48.4 54.0 50.0

50.0

4,440

156 2,621 2,777 1,663 73.8 56.2 68.3

68.3

FY19E

90.0

85.0

50.0

68.3

FY20E

90.0

85.0

50.0

68.3

Source: MOSL, Company

Contracted capacities have a set of structured and fairly predictable cash flows. In

the ensuing 10 years, annual EBITDA is expected to be ~INR20-25b (~60% of

consolidated EBITDA), which is enough to service debt of the company, in our view.

Exhibit 110: Break-up of operating cash flows through contracted capacities – INR b

Rajwest 1,080mw

Baspa-II 300mw

Karcham Wangtoo 700mw

JSW Steel 473mw

Maharashtra 300mw

24 25 25 25 24 23 23

3 3 3 3 3 3 3 3

8 9 10 10 10 9 9 9

3 1 1 1 1 1 1 1

10 10 10 9 9 9 9 8

20 20 20 20 19 20 19 19

3 2 2 2 2 2 2 2 1

7 7 8 8 8 8 8 8 8

1 1 1 1 2 2 2 2 2

8 8 8 7 7 7 7 7 8

16 16 15

1 1 0

8 8 8

2 2 2

5 5 5

0 9

2 9

9 10 10

0 0 0

9 10 10

0 0 0

11 11 12

0 0 0

11 11 12

Source: MOSL, Company

July 2016

Utilities | At the peak of over capacity

Exhibit 111: EBITDA – INR b

Contracted capacity EBITDA

Other-than contracted capacity EBITDA

FY16

FY17E

FY18E

FY19E

FY20E

Source: MOSL, Company

Earnings from contracted capacities are fairly predictable and secured, and thus

provide a strong base for future growth opportunities and help absorb earnings

volatility from its merchant power capacities. Cash flows from contracted

arrangements are sufficient to meet the group’s annual interest obligation of

~INR13-15b and normative debt repayment of ~INR7-8b. A strong balance sheet and

steady operating cash flows have enabled JSWE to secure better terms with lenders

(such as interest rate reduction and elongated debt repayment). JSWE’s strong

balance sheet (~2.0x debt-to-equity in FY16) compared to its stressed peers

provides room for inorganic growth.

We discuss the individual long-term contracts below:

Raj West (Barmar)



Entire 1,080MW capacity is contracted with the state of Rajasthan.



Fuel (lignite) is sourced through captive mines (49% owned), while costs are

pass-through.



Returns are determined based on the Rajasthan State Regulatory Commission

norms, which are broadly in line with norms set by the Central Electricity

Regulatory Commission.



JSWE has claimed project cost of INR69b, but the regulator has approved only

INR59b. JSWE has petitioned against the disallowance. If approved, it could lead

to an upside to our estimates.



Approved equity (at approved project cost) is INR14.8, representing 25% of

project cost. The plant was commissioned in a phased manner beginning FY2010

and was fully complete by FY2014.

In FY15/16, the plant operated at PLF of ~76-77%, lower than the normative 80%,

due to shortage of lignite. JSWE has ramped up production at the captive mines,

which should help in increasing PLF to 85%.

Raj West is expected to generate annual operating cash flows of ~INR 9-10b over the

next five years. The long-term cash flow profile (typical for a regulated project) will

decline due to normative debt repayments.

July 2016

Utilities | At the peak of over capacity

Exhibit 112: Raj West annual operating cash flow stream – INR m

Rajwest (1,080mw)

Source: MOSL, Company

Baspa-II



300MW of hydro capacity is fully contracted to Himachal Pradesh. Free power is

12% of the plant capacity. The plant was commissioned in 2003.



Revenues are regulated under the Himachal Pradesh Electricity Regulatory

Commission norms.



Approved project cost is INR16.3b and normative equity is INR4.9b.



Normative debt (including approved costs of ~INR100-120m related to debt

restructuring) was fully repaid in FY16. Annual normative depreciation is

INR702m, but due to the reversal of advance depreciation (as debt becomes

nil), net normative depreciation charge is nil. This will reduce operating cash

flows in FY17E.

Baspa-II’s annual operating cash flow generation is estimated to decline from

~INR2.7b in FY16E to INR1.4b in FY17E.

Exhibit 113: Baspa-II operating cash flow stream – INR m

Baspa-II (300mw)

Source: MOSL, Company

Karcham Wangtoo



The project capacity is 1,000MW (design 1,091MW) with 504MW under long-

term PPA. 120MW is supplied as free power to Himachal Pradesh, which will

increase to 180MW from FY24. It has long-term open access of 880MW.



Tariff is determined as per the CERC norms. However, the project cost is yet to

be approved. Hence, billing is being done on a provisional basis.



JSWE is in discussion with the state of Punjab for the off-take of 200MW under

long-term contract. This is expected to be concluded once the CERC finalizes the

July 2016

Utilities | At the peak of over capacity

tariff. Management expects it to be done by 1HFY17. We are factoring in

Punjab’s 200MW PPA in our numbers – 50% in FY17E and 100% from FY18E.



For the remaining 180/120MW, JSWE is participating in other long-term PPA

bids. In the meantime, it is selling power in the merchant market.

We estimate the contracted capacity of 700MW (beginning FY18) to generate

annual operating cash flows of ~INR8.8-10b over the next five years. Contracted

cash flow is estimated to increase in FY17-18E as more capacity gets under PPA (viz.

Punjab). Cash flows will then fall gradually as the decline in normative interest cost

will be partly offset by the increase in O&M (escalation of 6.64%). After debt

repayment, operating cash flows would see a rising trend as the actual increase in

O&M cost estimate of 5% p.a. lags the normative 6.64%.

Exhibit 114: Karcham Wangtoo contracted capacity operating cash flow stream – INR m

Karcham Wangtoo (700mw)

Source: MOSL, Company

Ratnagiri



The project capacity is 1200MW. There is a PPA of 473MW with JSW Steel and

300MW with the state of Maharashtra. Remaining 427MW capacity is exposed

to the merchant market.



The plant is located at a port in Maharashtra and operates on imported coal.

JSW Steel PPA (473MW):

Fixed charge is determined as per the CERC regulation,

while variable cost is pass-through. Annual operating cash flow generation is

estimated at INR3.3-2.9b over the next five years.

Cash flows will likely have a declining

trajectory due to falling normative debt.

July 2016

Utilities | At the peak of over capacity

Exhibit 115: Operating cash flow stream from JSW Steel PPA (INR m)

JSW Steel (473mw)

Source: MOSL, Company

Maharashtra PPA (300MW):

The PPA was awarded after competitive bidding.

Capacity charge includes a stream of pre-defined non-escalable unit charge and

escalable unit charge (linked to inflation). Fuel cost is adjusted for a change in the

benchmark coal index,

but on base value that was set when bid in FY10

. Transportation

and fuel costs are non-escalable. The operating cash flow profile is volatile due to

the structure of capacity charge.

Exhibit 116: Maharashtra PPA capacity operating cash flow stream – INR m

Maharashtra (300mw)

Source: MOSL, Company

July 2016

Utilities | At the peak of over capacity

Open capacity is well diversified

Only 10% capacity is vulnerable



JSWE has benefited in the ST market from tight supply in the southern region (SR).

With improving inter-region transmission, JSWE is reducing its exposure to

ST/merchant market as premiums are coming off in SR.

Only 33% of the capacity is now exposed to the ST market, but majority of it is in the

critically balanced market of Karnataka in SR. Expected PPA from the state will help

tide over the next three difficult years, after which the market is expected to find

balance.

Only 10% of its capacity is vulnerable due to its exposure to the oversupplied western

region.

JSWE has benefited from its exposure to the ST market in the tight southern region,

despite being dependent on imported coal. With improving inter-region

transmission capacities, regional premiums are coming off. JSWE too has been

gradually reducing its exposure to the ST market, but 33% or ~1,463MW capacity is

still exposed to the short-term power market. This is spread over three regions and

is well diversified. Only 10% capacity is exposed to the vulnerability of the merchant

market because of being in the oversupplied western region.



860MW Vijanagar plant is located in SR - critically balanced if not tight. This unit

is likely to secure ST PPA for three years from Karnataka at decent realizations,

while short-term opportunities in Andhra and Telengana are drying up.



176MW of hydro capacity is very competitive in the ST market. As hydro

projects are difficult to build and costs are high, the MoP is working toward

making these projects more attractive. Recently, hydro projects have been

exempted from competitive bidding. There is a move to bring large hydro

projects into the ambit of renewal energy (RE). Hydro projects with open

capacities will become more valuable with time.



427MW Ratnagiri capacity is most vulnerable as it is situated in the oversupplied

WR. But its location on the western side of the state offers some advantage

because there are transmission bottlenecks between east and west

Maharashtra.

Exhibit 117: Open to short-term market

S.N. Asset

1 Vijaynagar

2 Ratnagiri

3 K. Wangtoo

Location

State

Region

K'taka

Maha.

Fuel

coal

import

coal

import

Hydro

Open

(MW)

860

427

176

1,463

Remarks

Tight supply in the region

expecting 3 year PPA from K'taka

Over supplied market

headwind for few years

Hydro is likely to be next RE

Source: MOSL, Company

JSWE has benefited from its merchant portfolio in SR

India has been an oversupplied merchant power market for the past few years.

However, JSWE has benefited from its exposure to the merchant market. Its

merchant market portfolio’s significant positioning in southern India has come to its

July 2016

Utilities | At the peak of over capacity

advantage. Prior to the acquisition of JPVL’s hydro assets in FY16, 67% of its

merchant power capacity was in south. However, post the acquisition, it has come

down to 59%. The advantage for the merchant power market in south is evident

from the premium in day-ahead rates in south compared to the western region.

Southern region merchant

day-ahead rates have

trended at a premium to

other regions amid

constraints in transmission.

Premium, however, has

come off recently.

Exhibit 118: Southern region rates have been at a premium to the western region

S1 rates (INR /kWh)

7.0

5.5

4.0

2.5

1.0

W1 rates (INR/kWh)

Source: MOSL, Company

JSWE has benefited from its

position in the supply-short

southern region. Under its

bilateral arrangement for

sales in south, it has

secured a realization of

more than INR5/kWh.

Exhibit 119: Vijaynagar’s realization on inter-state bilateral sales – INR/kWh

6.6

6.2

5.6

5.4

5.6 5.6 5.6 5.6 5.6

5.5 5.6

5.7 5.7 5.6

5.9 6.0 5.9 5.9

Vijaynagar realn. on inter-state bilateral sales - INR/kWh

6.1

6.2

6.1 6.1

6.0

5.9

Source: MOSL, Company

But premium is easing in SR due to improving inter-region transmission

The two key constraints – lack of transmission network and delayed new capacity

starts – driving the premium in south over the past few years are gradually starting

to ease. Transmission grid capacity to south has increased from ~3GW a year back to

~5.9GW due to the commissioning of ancillary lines connecting Raichur-Sholapur.

The grid network is likely to expand further. Starting FY18, various transmission

projects are likely to get commissioned and are estimated to increase grid

connectivity to south to ~18GW by FY20.

Various new generation capacities have also been added to the grid over the past

few years, and the trend would continue over the next few years as per our

demand-supply model. 8.2GW of coal-based power generation capacity was

commissioned in the southern region in FY15/16, and additional ~9GW is expected

over the next few years.

July 2016

Utilities | At the peak of over capacity

With the commissioning of

ancillary grid lines

connecting the Raichur-

Sholapur line, export

capacity between WR and

SR has increased from

~3,000MW a year ago to

~5,900MW.

Exhibit 120: Export volumes from WR to SR transmission grid

HVDC Bhadrawati (Chandrapur)

Sholapur - Raichur

Kolhapur-Kudgi

Exports from WR to SR (in MU)

Source: MOSL, Company

Exhibit 121: Coal-based generation capacity commissioned/to be in Southern India

6,690

Capacity - in MW

6,160

3,600

1,560

2,100

760

FY15

FY16

FY17

FY18

FY19

Tentative

Source: MOSL, Company

The two major short/bilateral market purchasing states – Andhra Pradesh and

Telangana – are expected to significantly reduce short-term/open market power

purchases. In FY16, JSWE’s Vijaynagar plant sold ~50% of its volumes to these two

states at a lucrative ex-bus realization estimated to be at +INR 5.0/kWh. We

estimate AP’s electricity balance would turn from a deficit of ~3.4b kWh in FY16 to a

surplus of ~4.2b kWh in FY18. Telangana (in its ARRs) is expecting to reduce short-

term power purchase from ~26% of its total energy requirement in FY16 to just

~12% in FY17. Post FY17, we estimate both these states to be in a power surplus

position with the start of new capacities, PPAs and RE addition as the key drivers.

JSWE too has been gradually reducing its exposure to ST market

JSWE’s share of ST/merchant market volumes has declined over the years due to the

ramp-up of the Raj West power plant and the acquisition of hydro assets of JP which

had lower merchant exposure (180MW of 1,300MW). The merchant market

volumes share has declined from ~64% in FY12 to ~40% in FY16, and is estimated to

fall to ~37% in FY18.

July 2016

Utilities | At the peak of over capacity

JSWE’s merchant exposure

has declined.

Exhibit 122: Share of merchant/ST volumes

Merchant vols. share %

FY12

FY13

FY14

FY15

FY16

FY17E

FY18E

FY19E

FY20E

Source: MOSL, Company

Karnataka is processing 1,000MW ST bids

JSWE is well placed for

750MW ST PPA, given it is

the only open IPP capacity

in the state.

What could come as a silver lining to JSWE is the increase in deficit in Karnataka due

to a sharp fall in hydro generation, while there are delays in new projects. According

to our calculations, Karnataka’s electricity deficit is expected to increase from ~1b

kWh in FY15 to ~5b KWh in FY16, and is unlikely to decline meaningfully in FY17E.

Karnataka has called for 1,000MW of ST/medium-term PPAs in order to fill this gap.

According to media reports, JSWE has emerged as an L2 bidder for supplying

750MW at a realization of INR4.38/kWh. Supplies under this PPA are expected to

start from July 2016. We believe JSWE is well positioned for this PPA as:



It is the only open-IPP capacity in the state that can offer large volumes. This

helps as it saves inter-state transmission cost (of ~INR0.3-0.5/kWh) as against

other open capacities that are based mostly in Andhra Pradesh.



The southern power supply market is still relatively well balanced. The southern

region’s peak requirement is ~43-50GW (assuming 7% growth over FY16).

Untied private-IPP supply, adjusting for upcoming bilateral/PPA in Andhra

Pradesh and KA, would be ~5-7% of the peak requirement, which is not

significant.

Besides Karnataka, our estimates suggest AP and Telangana would still remain

buyers in the short-term market, but to a limited extent.

Exhibit 123: Southern region peak demand and untied capacity

(In MW)

Southern region peak demand

Untied capacities in south

NCC

Meenakshi

Simhapuri

JSW

Ind Bharath

Thermal Powertech

Less:

PPA to Andhra

KA's upcoming PPA

Untied % of peak

FY16

40,445

2,310

300

600

860

300

250

FY17E

43,276

3,330

1,320

1,000

600

860

300

250

FY18E

46,305

2,430

1,320

1,000

600

860

300

250

-900

-1,000

FY19E

49,547

3,430

1,320

1,000

600

860

300

250

-900

FY20E

53,015

3,430

1,320

1,000

600

860

300

250

-900

Source: MOSL, Company

Remark

7% growth

-1,000

July 2016

Utilities | At the peak of over capacity

Based on recent similar bids in the southern region, we believe JSWE can secure a

price of ~INR4.0-4.5/kWh (we build in INR4.3/kWh, media reports suggest

INR4.38/kWh). In March 2016, Thermal Powertech, based in Andhra Pradesh, was

supplying power at ~INR5/kWh to Karnataka under a short-term contract.

Exhibit 124: Recent Case1 bids in southern India

State

Tamil Nadu

Kerala

Andhra Pradesh

Year

FY14

FY15

FY16

Supplier

DB Power

Jindal Power Ltd

Jindal Power

Jhabua Power

Balco

Jindal India - Thermal

Jindal Power

East Coast Energy Ltd

NCC Power Projects

Korba West Avantha

MB Power Ltd

Jindal India Thermal Ltd

Capacity

Levelized tariff

(MW)

(INR/kWh)

200

4.91

400

4.95

200

3.60

115

4.15

115

4.29

200

4.39

150

4.29

488

4.27

500

4.35

540

4.49

374

4.69

400

4.83

Source: MOSL, Company

JSWE’s Karnataka ST PPA could be timely to tide over difficult three years

The Karnataka three-year ST PPA is very timely to fill the gap created by the end of

ST PPA with AP in June 2016 and should help tide over the next difficult three years

when the sector is at the peak of overcapacity. Improving inter-region transmission

connectivity is having an adverse impact on merchant rates of power. Although the

merchant power market is expected to remain well supplied for the foreseeable

future, things would definitely start improving by FY20E as new capacity addition

slows.

Demand and supply in Telangana, Andhra and Karnataka

Telangana: Market purchases to halve in near term; deficit signs again in FY19

Telangana, under its ARR filings, is estimating short-term market purchase of

electricity to almost halve in FY17 on the back of new capacity starts. From ~14b

kWh or ~26% of its electricity requirement in FY16, it estimates short-term

purchases to decline to ~7b kWh or ~12% of electricity requirement in FY17. Our

supply-demand model for Telangana also corroborates this trend – a deficit of ~14%

in FY16 declining to ~4% in FY17. Commissioning of Singareni 1,200MW (recently

signed 570MW PPA with Thermal Powertech) and upcoming solar capacities are

driving improved near-term availability.

Over the longer term, Telangana may turn into deficit only if demand grows by ~17%

in FY18 and ~19% in FY20, as projected in ARR filings by Telangana. Industries and

particularly government’s pet project Lift Irrigation Scheme (LIS) are expected to be

the major drivers of this optimism. LIS is estimated to represent ~33% of

incremental demand in FY18 and ~72% in FY19. More encouragingly, unlike

agriculture which is free, LIS is estimated to fetch realization of > INR5/kWh. Our

discussions with Telangana DISCOM officials suggest that the government is working

July 2016

Utilities | At the peak of over capacity

very actively on LIS. This was also corroborated by our discussions with a few steel

companies that have seen major pipeline order flows from Telangana.

If demand, as estimated in ARR filings, materializes, we believe Telangana would see

its electricity deficit rising to ~9% in FY19. We, however, base our estimate on 7%

demand growth assumption. As per our demand-supply model, Telangana would be

in a surplus of ~15% in FY19. Our supply assumptions are based on bottom-up

forecast of upcoming capacity and normalized PLFs, rather than the state

government’s upcoming project pipeline.

Exhibit 125: Surplus (deficit) as per ARR

(Deficit)/Surplus - in MU

% of state's demand (def.)/sur.

-2

-7

-3,628

-14

-6,942

FY16

FY17E

FY18E

-6,679

FY19E

-1,161

-9

-14

-6,942

FY16

Exhibit 126: Surplus (deficit) estimate at 7% p.a. growth

(Deficit)/Surplus - in MU

% of state's demand (def.)/sur.

6,200

-4

-2,131

FY17E

FY18E

FY19E

9,175

Source: MOSL, Company

Exhibit 127: Telangana’s electricity demand-supply balance

Available supply - in MU

Demand (as per ARRs) - in MU

growth (%)

Share of incremental demand (%)

Domestic

Commercial

Industrial

Agriculture

LIS

Others

(Deficit)/Surplus - in MU

% of state's demand (def.)/sur.

Demand (MOSL) - in MU

growth (%)

(Deficit)/Surplus - in MU

% of state's demand (def.)/sur.

FY15

44,294

46,273

FY16

42,790

49,732

7.5

FY17E

51,082

54,710

10.0

-3,628

-7

53,213

7.0

-2,131

-4

FY18E

63,138

64,299

17.5

-1,161

-2

56,938

7.0

6,200

FY19E

70,099

76,778

19.4

-6,679

-9

60,924

7.0

9,175

Remarks

Bottom-up analysis of upcoming supply

Can be at risk

Pet project of Telangana government

-1,980

-4

46,273

-1,980

-4

-6,942

-14

49,732

7.5

-6,942

-14

Avg. demand growth of ~7%

Source: MOSL, Company

Although it is too early to say if demand growth as estimated under ARRs or LIS

would materialize, we believe demand could get some push because of elections

that are due in the state in FY19. The government, being in its first term, is expected

to push for delivery of its poll commitments. Some signs are already visible in LIS.

July 2016

Utilities | At the peak of over capacity

Andhra Pradesh: Backing of 2,400MW PPAs, new capacities to drive surplus

Andhra Pradesh was estimating about 12% of electricity demand to be met from

short-term purchases in 2HFY16, which has come down to just ~1% in FY17. After

our recent interactions with AP’s Transco officials, we see the likelihood of AP

turning into a net seller in the short-term power exchange market. AP is benefiting

from the extension of KSK’s medium-term PPA from 216MW to 400MW, and the

start of Hinduja’s 1,050MW and Thermal Powertech’s 231MW coal-based capacities.

Gas-based supplies are also expected to increase due to the central government’s E-

RLNG scheme. Our demand-supply model for AP estimates a net deficit (or short-

term market purchase) of ~5.3bu in FY16, which would balance out in FY17.

Exhibit 128: AP expects short-term power purchases to be insignificant in FY17E

Short-term purchase % of total mix

Source: MOSL, AP ARRs

Over the long term, we estimate AP to be in a significant electricity surplus position.

Based on 14% electricity demand growth in FY17 (as per ARR, which could be at risk)

and 7% thereafter (our view), we expect a surplus of ~7.5b kWh or ~11% of its

electricity demand. Under our bottom-up supply model, we estimate ~3.8GW of

renewable capacity to be added by FY19E (though the target is much higher, as per

our interactions with AP Transco officials). We also assume ~1,000MW of long-term

PPAs will be signed. AP has already concluded bids for 2,400MW long-term PPA. Of

the 2,400MW, ~900MW is offered by south-based plants, for which there are no

transmission constraints. We estimate ~1,000MW of supplies to come from these

PPAs beginning FY18. Our checks with Transco officials highlighted that actual

acceptance of bids may be lower than 2400MW because of a jump in renewable

capacity addition.

AP has not provided long-term electricity demand forecast in its ARR, unlike

Telangana. But as per ‘Power for All’, it estimates electricity demand to increase to

~82b kWh by FY19 (as against our base case estimate of ~66bu). The document

assumes ~10b kWh of demand to come from load relief and ~5b kWh from an

increase in supply to the agriculture sector from 7 hours currently to 9 hours. We

are more hopeful of the agriculture demand potential due to an increase in the

number of hours of supply, based on our interactions with AP’s Transco officials.

Even if we were to consider the whole of ~5b kWh (incremental agriculture demand)

in our forecast for AP, there will still be in a surplus of ~2.5b kWh.

July 2016

Utilities | At the peak of over capacity

On the other hand, if ‘Power for All’ demand estimates were to materialize, we

would be looking at electricity deficit of ~9b kWh or ~11% of AP’s demand.

Exhibit 129: Andhra Pradesh electricity supply-demand balance

FY15

Available - in MU

Demand (as per PFA) - in MU

growth (%)

(deficit)/Surplus - in MU

% of state's demand (def.)/sur.

Demand (MOSL) - in MU

growth (%)

(deficit)/Surplus - in MU

% of state's demand (def.)/sur.

FY16

45,144

50,444

FY17E

54,096

68,563

35.9

-14,467

-21

57,506

14.0

-3,410

-6

FY18E

65,788

75,201

9.7

-9,413

-13

61,532

7.0

4,256

FY19E

73,341

82,392

9.6

-9,051

-11

65,839

7.0

7,503

Source: MOSL, Company

14% growth in FY17 is based on ARR filings.

Remarks

Bottom-up analysis of upcoming supply

Demand as per Power For All. FY17E sharp

increase is on factoring of load relief

-5,300

-11

50,444

-5,300

-11

Exhibit 130: Surplus (deficit) under base-case estimates

(deficit)/Surplus - in MU

% of state's demand (def.)/sur.

4,256

-5,300

-3,410

-6

-11

FY16

FY17E

FY18E

FY19E

7,503

Exhibit 131: Surplus (deficit) as per “Power for All”

(deficit)/Surplus - in MU

% of state's demand (def.)/sur.

-5,300

-14,467

-9,413

-9,051

-11

-13

-21

FY17E

-11

FY16

FY18E

FY19E

Source: MOSL, AP’s ARRs, AP’s Power for All

Source: MOSL, Company, AP’s Power for All

Karnataka: Can be a silver lining for JSWE

Karnataka’s electricity deficit (or short-term market purchase requirement) surged

from ~1.1b kWh in FY15 to ~5.1b kWh in FY16 (or ~8% of its electricity demand).

Karnataka’s ~25% of power capacity is hydro based, which had suffered in FY16 as

deficient monsoon led to a sharp fall in plant PLFs. Hydro power’s PLF dropped to

23% in FY16 from 41% in FY15. In addition, deficit in FY16 was partly constrained

due to below-average electricity demand growth of just 2% (based on CEA’s data).

Karnataka’s deficit situation is not likely to improve meaningfully in FY17. In the ARR

filings, Karnataka is estimating electricity demand of ~68b kWh in FY17, while our

supply model suggests available supply of ~64b kWh, leading to a deficit of ~4.6b

kWh or ~7% of its electricity demand. Our supply model assumes 30% PLF for hydro

capacities, up from 25% in FY16, which can surprise negatively considering low

reservoir water levels, unless off-course monsoon is extremely good. We also

assume some benefit from the start of Bellary U-3 (700MW) and Yeramarus

(800MW) thermal coal-based capacities. However, these supplies could also be at

some risk in the near term due to low water availability at these plants and

transmission constraints.

July 2016

Utilities | At the peak of over capacity

Post FY17, we estimate the supply situation for the state to improve on new

capacities (and considering demand forecast made by KA’s DISCOM, which assumes

5-6% demand growth), but still remain critically balanced in FY18. Start of Kudgi

(1,200MW), Yeramarus U-2 (800MW) and renewable capacities would drive

improved supply.

Exhibit 132: Karnataka’s electricity demand-supply

balance…

Available - in mu

Demand - in mu

Exhibit 133: ..and deficit – in Kwh (mu)

(deficit)/surplus

FY15

FY16

FY17

FY18

FY19

FY15

FY16

FY17

FY18

FY19

Source: MOSL, KA’s ARR filings, Power For All

Source: MOSL, Company, KA’s ARR filings, Power For All

Exhibit 134: Karnataka’s hydro capacity PLFs (%)

Karnataka hydro capacity PLFs (%)

Exhibit 135: Sales to KA from Vijaynagar (% of total)

Vijaynagar sales to Karnataka (% of total) impled

57 56 55

49 51

Source: MOSL, Company

July 2016

Utilities | At the peak of over capacity

Merchant power market will thrive

But rates will be capped at INR3/kWh



Despite oversupply, the merchant market will thrive as there is an arbitrage between

high variable cost of contracted capacities and total cost of new stranded power

plants.

We expect merchant rates to be capped at INR 3/kWh. We are factoring in rates of INR

2.75/kWh for non-SR and INR 4.3/kWh for SR capacities of JSWE.

As discussed earlier in the sector report, the Indian power sector is at the peak of

overcapacity. It will take 5-6 years for the market to re-balance. DISCOMs have

signed 41% more PPAs than FY20E peak load. Therefore, LT PPAs will be few over

the next 3-4 years. According to our calculations, 28GW of capacity will remain

stranded without PPAs. Therefore, the short-term market will remain oversupplied

for at least three years, in our view.

It will take 5-6 years for the

market to re-balance…

Exhibit 136: Conventional cap./peak load (x)

1.7

1.6

1.5

1.4

1.3

1.2

1.1

Source: MOSL, CEA

…yet the merchant market

will thrive…

Although DISCOMs are comfortable with available capacities and PPAs, they will

keep buying in the merchant market for reducing costs. There is an arbitrage

between variable cost of existing capacities (high for many GENCOs) and many

open/stranded capacities that are able to generate power at very low cost because

of the proximity to mines, improved domestic coal supply and operating efficiencies.

We find that state-owned generating stations typically fall at the higher end of the

contracted supply cost curve. Their variable cost, adjusted for transmission cost, sets

the cap for merchant power rates, in our view.

…but rates will be capped at

INR3/kWh, in our view

At variable cost of more than INR3/kWh, the generation potential of state-owned

companies was ~90b kWh (or 9-10% of India’s electricity generation) in FY16E.

Therefore, we believe INR3/kWh will likely be the cap for around 2-3 years.

July 2016

Utilities | At the peak of over capacity

Exhibit 137: Variable cost curve for state-owned coal capacities

5.00

4.00

3.00

2.00

1.00

0.00

> INR 3/kwh VC gen.

potential is ~90bu or 10%

VC - INR/kWh

Source: MOSL, State GENCOS ARR

We are factoring in realization of INR2.75/kWh in WR

We are factoring in INR2.75/kWh realization for JSWE’s merchant market sales in

regions other than SR. As mentioned above, merchant power prices would have to

be competitive enough to incentivize state DISCOMs to substitute their contracted

capacity volumes with merchant power. For JSWE’s SR merchant sales, we estimate

realization of INR 4.3/kWh on the back of KA’s three-year ST PPAs.

July 2016

Utilities | At the peak of over capacity

High capital efficiency and strong free cash flows

Inorganic growth opportunities plenty, patience is the key



JSWE is one of few companies in the sector that has built a strong set of assets at low

cost. JSWE is generating strong operating cash flows. As a result, its balance sheet and

return ratios are the best among private names.

With capex behind now, free cash flows have turned positive. At the peak of

overcapacity, organic growth still does not make sense, but inorganic growth

opportunities are plenty. Patience is the key, in our view.

Strong operating cash flows

JSWE has been generating strong operating cash flows, which have grown from

INR5b in FY09 to INR36b in FY16. Since hydro assets acquired from JPVL were

consolidated in 2HFY16, the benefit in operating cash flow was partial in FY16.

Therefore, operating cash flows are likely to see a jump in FY17E.

Exhibit 138: Operating cash flows

Opr. cash flows after WC change (INR b)

FY09

FY10

FY11

FY12

FY13

FY14

FY15

FY16

FY17E FY18E FY19E FY20E

Source: MOSL, Company

Assets have been installed/acquired at low cost and operated efficiently

JSWE has set up projects at low cost. First 260MW capacity was set up in FY2001 at

INR43m/MW, while the brown field expansion of 600MW came at much lower

capex of INR33m/MW in FY10. Next capacity expansion of 1200MW at green field

site of Ratnagiri came at INR46m/MW in FY12. Finally, 1080MW Raj West green field

site came at specific capex of INR66m/MW. The specific capex has been slightly

higher at Raj West to accommodate the CFBC boiler in order to use lignite from

captive mines. Even the recent acquisition of the hydro asset has been at attractive

valuation of INR70m/MW in FY16. JSWE has been able to grow its business both

organically and inorganically and at attractive project cost.

July 2016

Utilities | At the peak of over capacity

Exhibit 139: Efficient capital allocation and project execution

Source: Company

Exhibit 140: Efficiently run operating assets

Source: Company

July 2016

Utilities | At the peak of over capacity

Strong return ratios and free cash flow generation

This has helped in reporting

attractive return ratios and

generating healthy free

cash flows.

Exhibit 141: Return on equity

RoE (%)

FY09

FY10

FY11

FY12

FY13

FY14

FY15

FY16

FY17E FY18E FY19E FY20E

Source: MOSL

Exhibit 142: Capex has tapered

Capex (INR b)

FY14

FY15

FY16

Exhibit 143: Free cash flow generation is growing

FCF post interest and capex (INR b)

-22

-5

-1

-35

-30

FY09

FY10

FY11

FY12

FY13

Source: Company, MOSL

Financial leverage is declining sharply with strong free cash flows. Both debt-to-

equity and debt-to-EBITDA ratios are likely to decline sharply, despite the INR92b

acquisition in FY16.

Exhibit 144: Financial leverage

7.8

5.3

5.8

3.9

3.2

4.1

2.4

1.2

FY15

2.0

FY16

3.3

2.9

1.2

FY18E

Net Debt/Equity

Net Debt/EBITDA

2.4

0.9

FY19E

2.3

0.7

FY20E

1.3

FY10

1.6

FY11

2.0

FY12

1.8

FY13

1.6

FY14

1.5

FY17E

Source: MOSL

JSWE turned FCF positive in FY14 as it was able to spot stress in the sector early and

pull out of organic growth at the right time. Thereafter, FCF has been growing

despite pressure in the merchant market. This has helped JSWE in making attractive

acquisitions and allocating capital efficiently. Acquisition of hydro assets has fueled

July 2016

Utilities | At the peak of over capacity

growth in both FY16 and FY17. At the peak of overcapacity, organic growth still does

not make sense, although there are multiple brown field growth options at the

existing sites. Since government policies are turning favorable for hydro projects,

JSWE has started working on the 240MW Kutehar project at capex of INR29b.

Exhibit 145: Inorganic growth and potential

1300MW Hydro acquired (INR b)

M&A Potential at D/E of 1.5x (INR b)

FY16

FY17E

FY18E

FY19E

FY20E

Source: MOSL

JSWE has the potential to acquire assets worth INR60-67b, i.e. approximately 1GW

each year if it leverages FCF at a D/E ratio of 1.5x. Re-investment is necessary to

prevent the RoE from declining.

JSWE stands out in the private sector

What stands out unique for JSWE is that it is one of the few companies in the Indian

power sector (except for public sector companies) that is generating strong stream

of cash flows. For many groups, investment in power is non-core.

Exhibit 146: Least financial leverage in the sector

Net Debt / EBITDA - x

10.1

7.4

3.5

3.8

4.3

5.5

7.9

10.6

-4

-6

Exhibit 147: FCF generation among the top in the sector

FCF (post-interest)

Interest

assumed @ 11%

CESC

JSW

Tata Rpower KSK

Adani

Rattan

Source: Company, MOSL

Acquisition opportunities plenty, but patience needed

With 28GW of stranded capacities and under recoveries in many large-size projects,

the sector is under financial stress. Most developers are optimistic that demand

growth will accelerate following the balance sheet restructuring of DISCOMs under

UDAY, which will prompt states to invite bids for PPAs. However, the wait is only

getting longer.

According to our calculations, DISCOMs have signed more than sufficient PPAs to

cover their demand growth requirements over the next 4-5 years. Therefore, we

July 2016

Utilities | At the peak of over capacity

believe there will be paucity of PPAs for at least the next 2-3 years. This will increase

financial stress on the balance sheets of many companies and force them to sell

assets. Therefore, we believe a patient player like JSWE stands to benefit from its

strong negotiating power.

JSWE is already in negotiation for multiple assets and has signed MoUs for three of

them (i.e. 500MW Bina plant from JPVL, 1050MW thermal power plant from

Monnet, and 1000MW power plant from Jindal Power). These negotiations are

getting dragged due to the lack of agreement on valuations. We believe patience is

needed to get the right valuation.

JP’s 500MW Bina Power Plant

JSWE is reportedly in talks with JPVL for the acquisition of its 500MW Bina Power

Plant in Madhya Pradesh. The plant has signed long-term PPA for 350MW with the

state of Madhya Pradesh – 325MW is supplied under regulated return as per MP

tariff norms and the remaining 25MW is at variable cost (5% of the plant capacity of

500MW). The remaining capacity of 150MW is without any PPA.

Our view

The long-term PPA (for 325MW) earns normative pre-tax equity return of

INR1,327m p.a (for 65% capacity). The last approved variable cost was INR2.7/kWh.

While 325MW PPA is a strong point of this asset, open capacity of 150MW in the

most oversupplied western region is a negative.

JSPL’s 1,000MW Tamnar power plant

JSWE has entered into an agreement with Jindal Steel and Power (JSPL) to acquire

the 1,000MW power plant in Tamnar. The deal is structured such that if the plant is

able to secure a PPA and coal linkage before May 2018, the transaction value will be

INR65b. Otherwise, the asset will be valued at INR40b. JSPL will have to complete

regulatory formalities by May 2018 for the deal to go through.

Our view

JSWE is seeking minimum RoE of ~15% under the PPA. Assuming a 15% regulated

equity return for the remaining theoretical asset life of ~15 years, discounted at cost

of equity of 12% (pre-tax WACC of 11.9%), the value of the asset is ~INR 68b, close

to what JSWE has agreed to pay.

If there is no PPA by May 2018, the transaction value is INR40b. Although merchant

power rates will remain subdued for the next 3-4 years due to overcapacity, we

believe market volumes will thrive. Since this asset is located close to coal mines in

Chhattisgarh, it will still be able to generate EBITDA of INR0.4-0.6/kwh and sell

power generated. This implies annual operating cash flows of INR3-5b. We believe

that capacities without PPAs will demand better valuation after 3-4 years as the

market starts to balance.

July 2016

Utilities | At the peak of over capacity

Monnet’s 1,050mw Odisha power plant

The power plant is located in the coal-belt area of Angul, Odisha. The plant is further

at least two years into completion. Capital spent (as per CEC report) was INR53b as

of December 2014, post which limited activities have happened. The project has

PPAs with West Bengal for 400MW and Odisha for 269MW. Remaining 200MW PPA

is with PTC and 181MW capacity is open/untied. The deal is currently undergoing

due-diligence process.

Our view

We believe the major bottleneck in the deal finalization is its value. Both equity and

debt provides would have to likely take a cut in light of escalation in project cost due

to delays.

July 2016

Utilities | At the peak of over capacity

Reinstating coverage with BUY and TP of INR98

Strong FCF, double-digit RoE, lowest leverage at peak of overcapacity



SOTP of EV is INR279b, which will decline gradually if FCF is not reinvested. Since net

debt is declining at a faster rate, equity value will continue increasing. We value JSWE

at INR98/share based on FY18E SOTP.

Strong free cash flows and lowest financial leverage amid financially stressed

competition provide strong negotiating power to JSWE for inorganic growth at the

peak of overcapacity.

JSWE has been able to consistently generate double-digit RoEs due to low cost of

projects. We reinstate coverage with a BUY rating.

JSWE has a well-diversified set of power assets spread across three high-demand

regions. Two-thirds of capacity is secured through PPAs, while the remaining is

competitive in the merchant market. Only 10% of capacity is vulnerable due to its

exposure to the oversupplied western region.



Nearly two-thirds of capacity is committed through long-term PPAs, which

provides sufficient cash flows to meet interest and debt repayment obligations.

DCF value of cash flows (FY19E onwards) is INR171b. This value decreases

gradually with time due to the reducing average life of PPAs.



Merchant capacity of Karcham Wangtoo is very valuable because of low

operating cost and a high likelihood of securing PPAs. The Ministry of Power has

recently come out with a favorable policy for hydro projects. New hydro

projects are 50-60% more expensive than the project cost of Karcham Wangtoo.



We are valuing Ratnagiri’s 427MW open capacity at INR50m/MW. Although this

capacity is currently vulnerable, it will be more valuable after 3-4 years as the

market balances, in our view. This project has an advantage of being near the

port and water surplus region.

Exhibit 148: JSW Energy: SOTP-based valuation

NPV of PPAs

Merchant capacity

Vijaynagar

Ratnagiri

Karcham Wangtoo

JSW Power Trading

Jaigarh Power Transco

Barmer Mining

JSW Steel

Total value

Less: Net Debt

Equity Value

No. of shares (m)

Value per share (INR/sh)

MW INR/MW

2,777

860

427

180

FY17E

177,291

51,600

21,350

13,495

700

5,919

10,156

280,604

140,061

140,543

1,640

FY18E

171,615

51,600

23,485

13,201

700

5,919

13,307

279,922

119,997

159,925

1,640

FY19E

166,054

51,600

24,424

12,917

700

5,919

14,638

276,347

98,891

177,455

1,640

108

FY20E

160,538

51,600

25,401

12,641

700

5,919

16,102

272,996

79,942

193,053

1,640

118

FY21E

155,068

51,600

26,417

12,375

700

5,919

17,712

269,885

61,872

208,013

1,640

127

INR million

Remarks

DCF, 12% RoE, debt:equity 75:25

will be more valuable in 3-4years

1x invested equity

6x FY15 EV/EBITDA

1x FY15 net worth

Current market price

Source: MOSL, Company, MOSL

July 2016

Utilities | At the peak of over capacity



SOTP of EV is INR279b, which will decline gradually if FCF is not reinvested. Since

net debt is declining at a faster rate, equity value will continue increasing. We

value JSWE at INR98/share based on FY18E SOTP.



Strong free cash flows and lowest financial leverage amid financially stressed

competition provide strong negotiating power to JSWE for inorganic growth at

the peak of overcapacity. JSWE has been able to consistently generate double-

digit RoEs due to strong operating cash flows and low cost of projects. We

reinstate coverage with a BUY rating.

Equity value is increasing,

despite falling EV, due to a

faster decline in net debt.

Exhibit 149: Equity Value and Net Debt (INR b)

281

140

Equity value

280

120

Net Debt

276

273

141

FY17E

160

177

193

FY18E

FY19E

FY20E

Source: MOSL

July 2016

Utilities | At the peak of over capacity

Operating assets

…and organic growth opportunities

Exhibit 150: Diversified set of power assets

Source: Company

Exhibit 151: Organic growth opportunity

Source: Company

July 2016

Utilities | At the peak of over capacity

Story in Charts

Exhibit 152: Contracted capacity drives ~60% of EBITDA;

steady and predictable

JSWE group EBITDA

Other-than contracted capacity EBITDA

FY16

FY18E

FY19E

FY20E

Source: MOSL, Company

Exhibit 153: JSWE has reduced its exposure to merchant

power market

Merchant vols. share %

FY17E

Source: MOSL, Company

Exhibit 154: Karnataka’s electricity supply position critically

balanced; JSWE well-placed to secure KA’s 3 year PPA

Deficit/(surplus)

in b kWh

Telangana

6.2

2.6

7.5

9.2

5.4

Exhibit 155: One of the healthiest returns in the private

generation sector; low cost capacity a key advantage

RoCE post-tax (%)

13.9

12.8

11.4

11.2

11.1

12.8

11.0

9.7

12.5

11.0

11.3

10.4

ROIC post-tax (%)

4.3

-5.3

-6.9

FY16

-5.0

-3.4

-2.1

-4.6

FY18

FY19

10.2

FY17

Source: MOSL, Company

Exhibit 156: Growing and healthy FCF generation provides

firepower for acquisition

FCF (pre-interest) - INR b

Exhibit 157: One of the most comfortable balance sheets in

the Indian power sector

Net debt/equity (x)

2.50

2.00

1.50

1.00

0.50

0.00

3.2

1.56

3.3

2.4

1.50

0.88

Net debt/EBITDA (x) - rhs

5.0

4.0

3.0

2.0

1.0

0.0

Source: MOSL, Company

July 2016

Utilities | At the peak of over capacity

Financials and Valuations

Income Statement

Y/E Mar

Net Sales

Change (%)

EBITDA

EBITDA Margin (%)

Depreciation

EBIT

Interest

Other Income

Extraordinary items

PBT

Tax

Tax Rate (%)

Min. Int. & Assoc. Share

Reported PAT

Adjusted PAT

Change (%)

2011

43,021

82.7

15,718

36.5

2,668

13,050

4,325

1,255

9,979

1,562

15.6

-1

8,418

12.9

2012

61,188

42.2

14,478

23.7

5,033

9,444

7,172

1,466

-1,613

2,125

419

19.7

1,701

-79.8

2013

89,343

46.0

27,932

31.3

6,615

21,317

9,628

2,134

-1,966

11,857

2,733

23.1

-29

9,037

431.4

2014

87,054

-2.6

32,514

37.3

8,100

24,415

12,059

2,022

-3,777

10,600

2,836

26.8

7,547

-16.5

2015

93,802

7.8

36,234

38.6

7,898

28,337

11,375

2,301

-342

18,921

5,150

27.2

13,495

78.8

2016

99,689

6.3

41,446

41.6

9,502

31,944

15,032

2,100

1,500

20,513

6,051

29.5

133

13,955

3.4

2017E

101,015

1.3

42,483

42.1

10,616

31,867

16,745

960

16,082

4,342

27.0

11,465

-17.8

(INR Million)

2018E

101,677

0.7

42,041

41.3

10,656

31,385

14,695

1,609

18,299

4,941

27.0

13,083

14.1

Balance Sheet

Y/E Mar

Share Capital

Reserves

Net Worth

Debt

Deferred Tax

Total Capital Employed

Gross Fixed Assets

Less: Acc Depreciation

Net Fixed Assets

Capital WIP

Investments

Current Assets

Inventory

Debtors

Cash & Bank

Loans & Adv, Others

Curr Liabs & Provns

Curr. Liabilities

Provisions

Net Current Assets

Total Assets

2011

16,401

40,364

56,765

103,785

1,562

162,835

73,982

9,767

64,214

70,518

2,389

38,756

5,348

7,645

12,231

13,533

13,213

10,917

2,296

25,543

162,835

2012

16,401

40,600

57,001

121,112

1,292

179,904

124,268

14,818

109,450

36,702

2,871

43,671

7,658

10,640

8,786

16,587

13,084

11,336

1,748

30,588

179,904

2013

16,401

45,637

62,038

120,726

1,524

184,740

160,288

21,335

138,953

9,772

2,714

52,062

4,415

18,487

10,825

18,334

19,041

14,837

4,204

33,021

184,740

2014

16,401

49,311

65,712

114,643

1,933

182,791

166,247

30,006

136,241

6,146

2,535

47,416

4,158

11,976

12,016

19,266

9,653

5,449

4,204

37,763

182,791

2015

16,401

58,780

75,180

105,127

2,930

183,784

169,858

38,047

131,810

4,536

2,327

55,430

5,483

11,723

17,376

20,849

10,416

6,062

4,353

45,014

183,784

2016

16,401

68,958

85,358

173,365

4,383

263,657

262,307

47,304

215,003

7,265

1,932

56,344

6,494

28,381

4,701

16,767

17,717

13,322

4,394

38,627

263,657

2017E

16,401

76,676

93,077

153,365

5,348

252,426

263,307

57,920

205,387

7,265

1,932

52,765

6,089

16,605

13,304

16,767

15,752

11,358

4,394

37,012

252,426

(INR Million)

2018E

16,401

86,013

102,413

133,365

6,446

242,946

264,307

68,576

195,731

7,265

1,932

52,977

6,128

16,714

13,367

16,767

15,789

11,394

4,394

37,188

242,946

July 2016

Utilities | At the peak of over capacity

Financials and Valuations

Ratios

Y/E Mar

Basic (INR)

EPS

Cash EPS

Book Value

DPS

Payout (incl. Div. Tax.)

Valuation(x)

P/E

Cash P/E

Price / Book Value

EV/EBITDA

Dividend Yield (%)

Profitability Ratios (%)

RoE

RoCE

Turnover Ratios (%)

Asset Turnover (x)

Debtors (No. of Days)

Inventory (No. of Days)

Leverage Ratios (%)

Net Debt/Equity (x)

2011

5.1

6.8

34.6

1.0

19.5

14.0

10.6

2.1

13.3

1.4

16.1

8.7

2012

2.0

5.1

34.8

0.5

24.8

30.3

12.0

1.8

14.7

0.8

5.8

6.1

2013

6.7

10.7

37.8

2.0

29.8

8.2

5.1

1.4

7.1

3.7

18.5

11.4

2014

6.9

11.8

40.1

2.0

29.0

8.6

5.0

1.5

6.1

3.4

17.7

12.8

2015

8.4

13.3

45.8

2.0

23.7

14.1

9.0

2.6

7.8

1.7

19.6

13.9

2016

7.6

13.4

52.0

2.0

26.3

9.2

5.2

1.3

6.8

2.9

15.5

12.5

2017E

7.0

13.5

56.8

2.0

28.6

12.1

6.3

1.5

6.6

2.4

12.9

11.0

2018E

8.0

14.5

62.4

2.0

25.1

10.6

5.8

1.3

6.1

2.4

13.4

11.3

0.3

64.9

45.4

1.6

0.3

63.5

45.7

2.0

0.5

75.5

18.0

1.8

0.5

50.2

17.4

1.5

0.5

45.6

21.3

1.2

0.4

103.9

23.8

2.0

0.4

60.0

22.0

1.5

0.4

60.0

22.0

1.2

Cash Flow Statement

Y/E Mar

Adjusted EBITDA

Non cash opr. exp (inc)

(Inc)/Dec in Wkg. Cap.

Tax Paid

Other operating activities

CF from Op. Activity

(Inc)/Dec in FA & CWIP

Free cash flows

(Pur)/Sale of Invt

Others

CF from Inv. Activity

Inc/(Dec) in Net Worth

Inc / (Dec) in Debt

Interest Paid

Divd Paid (incl Tax) & Others

CF from Fin. Activity

Inc/(Dec) in Cash

Add: Opening Balance

Closing Balance

2011

15,718

637

-4,467

-2,995

8,892

-27,341

-18,449

621

-26,720

17,591

-4,071

-1,802

11,718

-6,110

18,341

12,231

2012

14,478

312

6,323

-826

20,287

-18,833

1,454

632

-18,200

3,571

-7,196

-1,906

-5,532

-3,445

12,231

8,786

2013

27,932

-1,185

-6,874

-2,627

17,246

-9,783

7,464

1,420

-8,363

3,819

-9,710

-953

-6,844

2,040

8,786

10,825

2014

32,514

-2,341

-4,894

-2,588

22,691

-4,940

17,751

2,030

-2,910

-2,701

-12,052

-3,838

-18,591

1,191

10,825

12,016

2015

36,234

861

1,322

-4,489

33,929

-6,772

27,156

1,475

-5,297

-8,124

-11,328

-3,820

-23,272

5,359

12,016

17,376

2016

41,446

2,080

-4,855

-2,998

35,673

-693

34,981

-31,674

-32,366

3,003

-15,036

-3,948

-15,982

-12,675

17,376

4,701

2017E

42,483

10,217

-3,377

49,323

-1,000

48,323

960

-40

-20,000

-16,745

-3,936

-40,681

8,603

4,701

13,304

(INR Million)

2018E

42,041

-112

-3,843

38,086

-1,000

37,086

1,609

609

-20,000

-14,695

-3,936

-38,631

13,304

13,367

July 2016