petronet lng ltd - spark capitalmailers.sparkcapital.in/uploads/vishnu/gas sector note - june...

VISHNU KUMAR A S [email protected] +91 44 4344 0069

June 24, 2016

GAIL (India) Ltd

Petronet LNG Ltd

Initiating Coverage on

Company Update

Petronet LNG CMP

Rs. 287

Target

Rs. 261

Rating

REDUCE

Page 1

Stock performance

1m 3m 12m

PLNG 5% 15% 51%

Sensex -1% 4% -5%

BSEOG 1% 5% -4%

Date 28 June 2016

Market Data

SENSEX 26403

Nifty 8095

Bloomberg PLNG IN

Shares o/s 750mn

Market Cap Rs. 215bn

52-wk High-Low Rs. 293-164

3m Avg. Daily Vol Rs. 395mn

Index member BSE OIL & GAS

Promoters 50.0

Institutions 37.7

Public 12.3

Company Update


Financial summary - Standalone

Year Revenues (Rs. bn) EBITDA (Rs. bn) Adj PAT (Rs. bn) EPS (Rs.) P/E (x) EV/EBITDA (x) ROE %

FY15 395 14.4 7.3 9.8 29.7x 16.6x 13.7%

FY16 271 15.9 9.1 12.2 23.8x 13.7x 15.2%

FY17E 244 19.0 11.5 15.3 19.0x 11.2x 16.9%

FY18E 339 23.1 14.1 18.8 15.4x 8.8x 18.5%

Too much gas – not much demand; Change in stance to REDUCE

Petronet LNG is nearing completion of its 5mmt brownfield expansion at Dahej (~35% increase), leading to the next earnings growth

phase (from FY18e onwards). We have remained positive on the stock over the last 1 year and it has delivered >50% returns. We

play devil’s advocate on our positive thesis on various parameters and negatively conclude that 1) There may not be adequate

demand for the two new terminals (PLNG & GSPC – Mundra – 10MMT), which could impact utilisations @ Dahej. 2) We also see a

likelihood of GSPC shifting volumes of 1-1.5mmt of volumes from Dahej on start up of Mundra terminal (COD – 2HFY17E). Also a

similar shift in GSPC’s volumes from Hazira terminal & start up of RIL’s Petcoke Gassifer can result in Hazira terminal’s utilisation

dropping to <20% from ~80% currently, leading to intensifying competition 3) The Take or Pay clause on the new 5mmt terminal may

not be water tight and could cover only 50-60% of the capacity in its initial years. Also the regas tariff could be lower for the new

terminal as the entity is 65% funded from customer advances and does not have boil off costs. We model - Rs. 40/mmbtu (vs Rs.

42.5/mmbtu for extant terminal) and see further downside risks and 4) Lastly, we see a remote possibility of tariff cut for the existing

Dahej facitlity in the next reset date (Jan’17) as PLNG is currently benefitting benefit from substantially lower boil off costs, which may

be required to be passed on (we do not model for a tariff cut yet). Overall we believe utilisation post expansion would range ~90% for

FY18/19 (vs earlier expectation of 100%+). Also we lower our blended tariff assumptions leading to an EPS decline of ~10% (our

estimates are lower than street by ~20% for FY18E). Though we like PLNG’s high cash generating business model, superior ROEs,

solid long term growth opportunities, we see a case for consensus earnings downgrade as high expectations gets tempered and we

would wait for a more opportune time to play a structural story. Change in stance to REDUCE with a TP of Rs. 261 (Rs 283 earlier)

Our analysis of demand potential from anchor load sectors (power & fertilisers) suggest bleak gas demand

Power Sector: Our channel checks with various gas power producers, suggest merchant rates of <=Rs. 3/kwh in the northern grid

to be a spoiler for gas demand in power. Also announcements by a few gas producers to restart plants seems to be anchored with

an assumption of <$5/mmbtu of LNG (FOB) which is currently not the case. On the Southern grid merchant rates of Rs. 5/kwh are

healthy for AP based plants, however lack of adequate swapping mechanism (with RGTIL) is hampering flow of gas. Resolution of

this issue (likely in Jul’16) could boost demand in the next bidding round under the PSDF scheme. We see the benefit to be short

lived as resolution of grid connectivity issues in 2HCY17 would lead to lower prices and hence demand may not sustain. Overall we

see sustained LNG demand only if price remains <$5/mmbtu, eternal continuation of PSDF scheme (unlikely) & pollution concerns

resulting in gas based power demand especially in Delhi

Fertiliser sector is already running near peak and incremental demand is likely only from CY20 onwards.

Others: Demand from refineries tend to be volatile and is unlikely to materially jump in the near term. All other sectors are unlikely to

materially move the needle. Hence we do not see a case for full 100% utilisation for the new terminal

Kochi utilisation to languish <20% in the next 3 years as the current pace of construction would be completed only by 2019/2020

aiding higher utilisations only from FY20/21 onwards

LNG Capacity set to jump 50% by CY17 and double by CY20 – Is there enough demand ?

Source: MoPNG, PPAC, Industry, Spark Capital Research

LNG terminals in India Capacity Capacity Additions Capacity

Existing + New Grid Location 2015 2016 2017/18 2019/2020 2020

Petronet West Dahej 10.0 10.0 5.0 2.5 17.5

Shell West Hazira 5.0 5.0 - - 5.0

GAIL West Dabhol 1.7 1.7 - 3.3 5.0

GSPC Adani West Mundra - - 5.0 - 5.0

Petronet Southern Kochi 5.0 5.0 - - 5.0

Ennore - IOCL Southern Chennai - - - 5.0 5.0

Total (mmt) 21.7 21.7 10.0 10.8 42.5

Petronet’s Dahej expansion to 15MMT (10 currently) and GSPC’s Mundra terminal (5mmt) will increase LNG regasification capacity from

22MMT to 32MMT by FY18 and to 43mmt by 2019/2020. Excluding anchor load customers like Fertiliser & Power sector (cannot buy LNG

without regulatory involvement) we see a peak demand potential of 26mmscmd or 7mmt vs an addition of 20mmt by CY19/20. Also the peak

demand numbers are indicative and may not translate into actual demand

Total Total Total CY19/20 Remarks # Additional Potential

Fertilizer 40 43 42 41 43 Peak demand already; incremental from CY21/22 Limited 2

Power (40% PLF) 43 29 29 32 34 Assuming PSDF scheme continue Limited 2

LPG 6 3 3 3 5 Peak demand Limited 2

CNG / PNG 9 8 10 11 14 Assuming 10% CAGR demand of CGD's - 3

Refineries* 9 13 14 15 18 Potential of 20+ Yes 3

Petrochemicals Gas Based 5 5 7 7 10 Peak demand Yes 3

Steel 5 4 4 4 7 Peak demand Yes 3

Commercial & Others 18 17 10 11 13 Assuming 10% CAGR industrial demand Yes 2

Total (mmscmd) 134 122 117 124 143 26

Ability to Buy LNGParticulars

Theoritical Demand2013 2014 2015Current

LNG Offtake in the power sector is a very tricky case – We think the sector will not draw big volumes

NegativesPositives

Assessing LNG demand from the power sector

is a very tricky case as a lot depends on the

availability of LNG @ <$5.5/mmbtu (FOB). Also

competition from Merchant power which is

currently available @<Rs. 3/kwh makes for a

difficult case to assess the medium term

demand. Hence we believe the spike in power

demand could only continue as long as the

PSDF support exists.

Source: Industry, Spark Capital Research

Gas Capacity in India (MW) OperationalNon -

OperationalTotal

Plants with APM gas 6,806 6,806

Plants with Non APM gas 6,009 6,009

Plants with KG D6 gas 3,294 3,294

Plants with no gas allocation 3,782 3,782

Plants ready for commissioning 4,619 4,619

Grid Connected Sub-total 19,890 4,619 24,509

Non Grid Connected plants 2,387 2,387

Total 22,277 4,619 26,896

6.8

4.9

3.5

2.4

0.8

0.1

3.3

0.4

0.9

6.8

8.2

3.9

2.4

0.8

1.0

Gujarat

Andhra

Maharashtra

Delhi

Rajasthan

Uttaranchal

GW

Commissioned

Not Commissioned

Total Gas demand from power sector has slightly increased from

24mmscmd in May’15 to ~32mmscmd in May’16 led by support from PSDF

Sizeable Capacity operating @ very low PLFs – Waiting for more gas !

Total Gas based capacity stands @ 27GW with little gas supplies Three States (Gujarat / AP & Maharashtra account for 75% of the capacity

18.417.8

18.4

19.618.9

23.0

21.522.3

25.3

22.9 23.023.5

21.7

23.2

25.3

24.0 23.7

14

18

22

26

Jan

-15

Fe

b-1

5

Ma

r-15

Ap

r-15

Ma

y-1

5

Jun

-15

Jul-1

5

Au

g-1

5

Se

p-1

5

Oct-

15

Nov-1

5

Dec-1

5

Jan

-16

Fe

b-1

6

Ma

r-16

Ap

r-16

Ma

y-1

6

Pan India PLFs of gas based capacity stands at a paltry – 20% with many

stranded for want of gas

28 29

28 30

18

29

24 27

25 27 28

25 23 22 23 25 24

29 27

29

33 31 31 32

29 31

34 32 32

0

5

10

15

20

25

30

35

40

mm

scm

d

On-grid Off-grid

Source: CEA, Industry, Spark Capital Research

PSDF Support for FY16 & FY17 FY 15-16 FY 16-17

Stranded Capacity INR 30bn INR 35bn

Under Utilised Capacity Rs. 5bn Rs. 5bn

Particulars1st Round

1 st June – 30th Sep 2016

2nd Round

1st Oct’15 – 31st Mar’16

3rd Round

1st April- 30th Sep 2016

Target Price (Net Power Purchase

Cost by DISCOMs)

INR 5.50/kWh @ 25% PLF &

INR 4.70 @ 35% PLF

INR 4.70/kWh constant

from 35% to 50% PLF

INR 4.70/kWh

at 30% PLF

PSDF CellingINR 0.94/kWh @ 25% PLF &

INR 1.74/kWh @ 35% PLF

INR 1.45/kWh constant

from 35% to 50% PLF

INR 0.41/kWh to negative

bidding.

Gas Price (DES USD/MMBTU) 8 8 5.5

Total Celling Price (Selling price) INR 6.44 per unit INR 6.15 per unit INR 4.70 per unit

Quantity of RLNG 8.9 MMSCMD 13.35 MMSCMD 8 MMSCMD

Maximum PLF 35% 50% 30%

PSDF Support INR 8.4bn INR 16.bn No support

LNG arrangement for gas based capacity under PSDF support – How long?

Government of India and Ministry of Power

sanctioned the “Scheme for utilization of gas

based power generation capacity” by providing

LNG @ subsidised rates (i.e, Zero taxes; 75% cut

in marketing margin & 50% cut in pipeline tariff) to

operationalise the stranded gas based capacity.

Also the Govt. provided support from PSDF fund

subsidising the cost of electricity to State

Electricity Boards. The plan is valid for tow years

however, we see the same continuing as long as

the PSDF balance is available under the scheme

The Govt. has provided a support of Rs. 75bn

for reviving the idled / stranded gas power

plants off which Rs. 25bn has been utilised.

Based on our estimates we see Rs. 5/10/20bn

of yearly withdrawal from PSDF fund if LNG

prices hover around $6/$7/$8/mmbtu. With a

balance pool of Rs. 50bn under the scheme,

we see this plan continuing for at least 2-3

years

Note: While various AP power plants have won

bids under this scheme – operational issues like

high taxes under the swapping scheme (recently

resolves), agreements with pipeline operators –

RGTIL for gas swapping has been an impediment

due to which the scheme is not completely

utilised. Our discussion with various stake

holders, suggest the issue could be resolved in

the next few months & expect flows in Round 4

Source: News Reports, Industry, Spark Capital Research

$4.0 $5.0

$4.5 $5.5

$5.0 $6.0

$5.5 $6.5

$6.0 $7.0

$6.5 $7.5

FOB

LNG Prices ($/mmbtu)

Delivered

2.5

2.8

3.0

3.3

3.5

3.8

2.9

3.2

3.5

3.8

4.1

4.4

Old Plants New Plants

State Wise Short term Power prices in May/Jun’16Variable Cost of

Power (Rs. /kwh)

Gas based power stations loose out on Northern / Western grid, whereas South offers hope !

At a delivered costs of $5-6/mmbtu the variable cost of power works out to Rs. 2.5-3.0/kwh for efficient plants & Rs. 3-3.5/kwh for inefficient gas based power

plant. The merchant rates in the Western region for May/Jun’16 has ranged between Rs. 2-3.5/kwh (lower range indicated in the map), primarily from coal

supplies. At such rates the gas based power stations are unable to compete for short term contracts with State Electricity boards. However in the Southern

grid merchant rates are Rs. 4.7/kwh which is very feasible to sell gas based power with LNG costs upto $7/mmbtu

Source: Ministry of Power, Industry, Spark Capital Research

Andhra Pradesh- Gas Power Plants CapacityJan'16 to May'16 Gas requirement

@30% PLFUnits Generated PLF Gas utilised

Commissioned MW Mn. Units % mmscmd mmscmd

Vijeswaran CCPP 272 253 25% 0.4 0.4

Peddapuram CCPP 220 - - 0.4

Gautami CCPP 464 - - 0.8

Gmr energy ltd - Kakinada 220 - - 0.4

Grel ccpp (Rajahmundry) 768 534 19% 0.8 1.3

Jegurupadu CCPP 455 341 21% 0.5 0.8

Konaseema CCPP 445 - - 0.7

Kondapalli Extn CCPP . 366 41 3% 0.1 0.6

Kondapalli CCPP 350 311 24% 0.5 0.6

Kondapalli st-3 Ccpp 742 565 21% 0.9 1.2

Godavari Ccpp 208 195 26% 0.3 0.3

Vemagiri Ccpp 370 206 15% 0.3 0.6

Total 4,880 2,446 14% 3.7 8.1

Completed but not commissioned

Gvk Industries (j1) 235

Gvk Industries Expansion (j2) 220

Samalkot Exp. 2,400

Panduranga 116

Astha power 35

Total 3,006

Total Andhra based power capacity 7,886

Resolution of pipeline issues could result in additional theoritical demand of ~4-

5mmscmd – though only for short term

While various AP power plants have won bids

under this “Scheme for utilisation of stranded

gas based power” scheme, however operational

issues like high taxes under the swapping

scheme (recently resolved), agreements with

pipeline operators – RGTIL for gas swapping

has been an impediment due to which the

scheme is not completely utilised. Our

discussion with various stake holders, suggest

the issue could be resolved in the next few

months & expect superior gas flows in Round 4.

While it is difficult to predict the volumes we

believe there is a potential for additional

5mmscmd assuming all the operational gas

based power plants run @30% PLF.

Source: CEA, Spark Capital Research

The gap in transmission capacity between Rest-Of-India and Southern-Region is attributed to Southern States

not approving or accepting transmission projects in the period 2005-2010 as they were confident of being

power surplus (due to large power generation capacity additions foreseen in the region). However, large part of

this generation capacity were either significantly delayed (e.g. Tamil Nadu’s 2000MW Kudankulam Nuclear

project) or were left without fuel (~5,000MW of gas based power plants in A.P. were stranded without gas). This

resulted in high demand for power from other regions; however, as no transmission capacity was created for

such a scenario Southern-Region was not able to meet its power requirements

Historically (till 2005), Southern-Region was connected to Rest-Of-India via 3 major HVDC (High Voltage

Direct Current) links with a transmission capacity of 4000MW:

− 2000/2500 MW HVDC Talcher-Kolar Bipole – Commissioned on June 2003

− 1000 MW HVDC Gazuwaka Back to Back link – Commissioned on March 2005

− 1000 MW HVDC Bhadrawati (Chandrapur) Back to Back link – Commissioned on December 1997

Due to reasons discussed above, after 2005 no major transmission project was under construction till 2011. Post the

power crisis in Southern Region, 3 crucial AC (Alternating Current) links commenced construction, they are:

− 765 KV Raichur-Sholapur single circuit line – 1st line – Commissioned on January 2014

− 765 KV Raichur-Sholapur single circuit line – 2nd line – Commissioned on September 2015

− Kolhapur (new) – Narendra (Kudgi) GIS 765 kV double circuit line - Commissioned on Dec 2015.− These 3 lines have total power import capacity of ~1,500MW into the Southern-Region. Though, these recent

AC lines have eased the power scenario for the Southern-Region, it has not completely addressed it;Power Grid is building the following crucial transmission projects to address this. Details and status ofthese projects are:

Project Commissioning Schedule Addn Transmission Capacity (MW)

765 kV Wardha – Nizamabad -

Hyderabad double circuit line

May 2018, PGCIL is targeting to

Commission Wardha –

Nizamabad section by May 2017

2,500

Warora- Warangal – Hyderabad -

Kurnool 765 kV linkJune 2019 NA

765 kV Angul - Srikakulam double

circuit line

By August 2016, other associated

elements by December 2017NA

6000 MW HVDC Bipole

Link [Raigarh (Chhatisgarh) -

Pugalur-Trichur (TN, Kerala)]

April 2019 6,000

Power Grid is confident that the congestion

to export power from Rest-Of-India to

Southern-Region will be addressed by Mid

2017. This means that states like

Telangana, A.P., Karnataka and Tamil Nadu

which are facing Demand-Supply mismatch

will be able to import more power from the

grid from Mid 2017. This also will have a

negative impact on the Southern Region’s

bilateral power prices and short-term power

prices (likely to fall).

Takeaways from our Power Analysts' recent visit to Power Grid’s Load Dispatch Centre

Power Grid is undertaking various

transmission projects to Southern

Grid – which is currently not

adequately connected to the pan

India Grid. Commissioning of a few

projects in May’17 would add

additional 2500MW of power

capacity and could potentially

reduce the merchant rates by Rs.

1/kwh to ~Rs. 3.0 – Rs. 4.0/kwh. At

such price it would be difficult for

gas power plants in AP/ Telangana

to enter into short term contracts

with the State Electricity Boards as

they would not be willing to buy

gas based power, which would cost

atleast Rs. 4/kwh @ current prices

Merchant power rates in South could crash from 2HCY17– not good for AP gas power plants !

Source: Spark Capital Research

Centre again offers LNG supply for Delhi’s power plant

The Centre is committed to making available CNG across the country so that clean fuel is

accessible at the doorstep, Oil Minister Dharmendra Pradhan said. (Reuters)

As Delhi battles the tag of being one of the most polluted cities in the world, the Centre

today renewed its offer to supply natural gas to the city’s stranded power plant to help

switch from the polluting coal-generated electricity.

Oil Minister Dharmendra Pradhan said his ministry had offered to supply natural gas to

the Bawana power plant at a price of $ 7.5-8 per million British thermal unit, that will help

generate power at less than Rs 5-6 per unit Delhi pays for getting electricity from the

coal-based Badarpur power station.

“I had written to the Delhi Chief Minister offering him to supply LNG. He wrote back to me

but did not address the core issue (of taking gas),” he said.

The minister further said: “If they shut (coal-based) Badarpur power station, it will help cut

pollution equivalent to not plying cars for 17 years.”

Delhi, he said, has a power demand of 6,500 to 7,000 MW. Decades-old Badarpur power

plant supplies 350 MW.

The 1,500 MW Bawana power plant in Delhi has been operating at less than a fifth

of its capacity for the past four years. The plant was to be commissioned before the

2010 Commonwealth Games but was delayed by an year. “Even buying LNG from spot

market would be more cost effective for Delhi,” he said. The slump in international energy

prices has meant that liquefied natural gas (LNG) in international market is available at

$5-6 per mmBtu. The price after including shipping cost, taxes and pipeline transportation

comes to $7.5-8 per mmBtu.

Source: Financial Express June 2016

Pollution concerns in Delhi could boost demand by ~5mmscmd (peak potential)

Various agencies have been asking for shutting down Old Coal plants in Delhi, which could benefit gas based power (currently idle)

State Delhi

Coal Capacity (MW) 5002

Gas Capacity (MW) 2208

Generation

Mar'16 168

Apr'16 268.4

May'16 417.9

Gas Demand (mmscmd)

Mar'16 1.2

Apr'16 2.0

May'16 3.1

Current PLF 31.1

Generation @85% PLF 1143.1

Gas Demand (mmscmd) 8.5

Pollution concerns have been rising in Delhi and various agencies

have called for closure of old coal power plants. Assuming all the

gas based stations in Delhi are run @ 85% PLF we see a peak

potential of 5mmscmd. Though it is difficult to predict whether such

an event will pan out.

Source: CEA, Spark Capital Research

Gas demand in fertilizer sector peaked out ! See incremental demand only by 2020

The current gas demand (indicative) from fertilizer segment is

flat at ~44mmscmd

40 43 42

44

-

10

20

30

40

50

2013 2014 2015 Current

mm

scm

d

Plants likely to be taken up for Revival Capacity

Unit State MMT mmscmd

Talcher Unit Odisha 1.2 2.4

Sindri unit Jharkhand 1.3 2.3

Ramagundam Unit Telangana 1.2 2.4

Currently being undertaken (COD 2020) 3.7 7.1

Gorakhpur unit Uttar Pradesh 1.3 2.6

Korba unit Chhattisgarh 0.5 1.0

Barauni unit Bihar 1.3 2.6

Proposed 3.1 6.2

Company Fuel TypeUrea Capacity

(MMT/year)

Gas Requirement

(mmscmd)

BVFCL - Namrup-III Gas 0.3 1.34

IFFCO - Aonla-I Gas 0.9 1.64

Indo-Gulf -Jagdishpur Gas 0.9 1.60

Kribhco - Hazira Gas 1.7 3.44

NFL - Vijaipur-I Gas 0.9 1.72

RCF-Trombay-V Gas 0.3 1.06

NFCL-Kakinada-I Gas 0.6 1.14

CFCL Gadepan-I Gas 0.9 1.62

TCL-Babrala Gas 0.9 1.56

KSFL-Shahjahanpur Gas 0.9 1.65

NFCL-Kakinada-II Gas 0.6 1.14

IFFCO-Aonla-II Gas 0.9 1.60

NFL-Vijaipur-II Gas 0.9 1.65

KFCL-Kanpur (*) Gas 0.7 1.90

SFC-Kota Gas 0.4 0.99

IFFCO-Phulpur-I Gas 0.6 1.40

ZIL-Goa Gas 0.4 0.97

IFFCO-Phulpur-II Gas 0.9 1.70

CFCL-Gadepan-II Gas 0.9 1.64

GSFC-Baroda Gas 0.4 0.86

IFFCO-Kalol Gas 0.5 1.20

RCF-Thal Gas 1.7 3.96

BVFCL - Namrup-II Gas 0.2 1.01

GNVFC-Bharuch Gas 0.6 1.70

NFL-Nangal Gas 0.5 1.52

NFL-Bhatinda Gas 0.5 1.75

NFL-Panipat Gas 0.5 1.65

Total- Gas 19.3 43.4

MCFL-Managalore Naphtha / FO 0.4 0.93

MFL-Madras Naphtha / FO 0.5 1.36

SPIC-Tuticorin Naphtha / FO 0.6 1.53

Total- Naphtha/FO (Not on grid) 1.5 3.8

Total Urea Capacity 20.8 47.2

Fertiliser sector currently has been drawing 42-44 mmscmd – almost

near to full capacity

New projects being taken up could add 7mmscmd of demand but

volumes are likely only from FY21 onwards

Source: FAI, Industry, Spark Capital Research

4.0

5.0

6.0

7.0

8.0

Jan Feb Mar Apr May June

$/m

mb

tu

Avg = ~$6.0/mmbtu

LNG Import Prices have inched towards ~$6/mmbtu for June deliveries and are expected to go up further in the imminent months.

Avg = $5.1/mmbtuAvg = $6.7/mmbtu Avg = $5.8/mmbtu Avg = $4.9/mmbtu Avg = $5.4/mmbtu

6.2

2.0

6.0

10.0

14.0

18.0

22.0

Jun

13

Dec 1

3

Jun

14

Dec 1

4

Jun

15

Dec 1

5

Jun

16

FO - Import Parity ($/mmbtu)

Spot LNG- ex terminal ($/mmbtu)

Gap between FO & Spot LNG has narrowed significantlyIndia’s DES LNG price has historically been higher than JKM Asia’s LNG

0.00

4.00

8.00

12.00

16.00

Oct-

14

Dec-1

4

Fe

b-1

5

Ap

r-15

Jun

-15

Au

g-1

5

Oct-

15

Dec-1

5

Fe

b-1

6

Ap

r-16

Jun

-16

$/m

mb

tu

JKM Asia LNG

India DES LNG

LNG prices have started inching higher – Avg $6/mmbtu for June deliveries in India

Source: Bloomberg, Platts, Industry data, Spark Capital Research

Start up of Mundra & RIL’s Petcoke gasifier could impact Dahej volumes

Mundra terminal - jointly owned by GSPC & Adani group is scheduled for start up in 2HCY17.

Currently GSPC is sourcing LNG to the tune of 2.7mmt from Dahej / Hazira terminals. Once the

new plant starts up we believe GSPC may shift some volumes from Dahej / Hazira to its Mundra

terminal. We believe it could be to the tune ~1.5mmt or more

GSPC Mundra

Petronet Dahej

Shell - Hazira

1

RIL is currently drawing 2.6mmt of volumes (FY16). Post the start up of Petcoke Gassifier (likely

by 2HFY17E), we see RIL to stop drawing LNG of atleast 2mmt from Hazira. Also there could be a

potential case for the balance 0.5-0.6mmt to move from Hazira to GSPC Mundra given the

reduction in transmission distance, though regas rates between these two terminals would also

play a key consideration for the same

2

Particulars Throughput (mmt) Utilisation2016 Throughput by Buyer

(mmt)Shift in Volumes Adjusted*

Existing + New Location 2015 2016 2015 2016PLL/GAIL/

OthersGSPC RIL GSPC RIL Total Volumes Utilisation

Petronet Dahej 10.2 11.1 102% 111% 9.4 1.7 0 -0.9 - -0.9 10.3 103%

Shell Hazira 3 3.6 59% 72% 0.1 1 2.6 -0.5 -2.0 -2.5 1.1 22%

GSPC Adani Mundra 1.4 - 1.4 1.4 27%

Total (mmt) 13.2 14.7 9.5 2.7 2.6 12.7

1 2

Start up of GSPC’s Mundra terminal could result in GSPC moving its LNG regasification (1.7mmt) to its Mundra terminal potentially impacting

volumes to the tune of 1-1.5mmt in both Dahej & Hazira. Start up of Petcoke gasifier by RIL could lead to 2mmt of volume loss to Hazira potentially

bringing down its utilisation from 70-80% to ~20%. For PLNG’s Dahej terminal there could be loss of ~1mmt decline and could see further

competition from Shell’s Hazira terminal

Source: Company, News sources, Industry data, Spark Capital Research

29.0

33.0

37.0

41.0

Q1 1

1

Q2 1

1

Q3 1

1

Q4 1

1

Q1 1

2

Q2 1

2

Q3 1

2

Q4 1

2

Q1 1

3

Q2 1

3

Q3 1

3

Q4 1

3

Q1 1

4

Q2 1

4

Q3 1

4

Q4 1

4

Q1 1

5

Q2 1

5

Q3 1

5

Q4 1

5

Q1 1

6

Q2 1

6

Q3 1

6

Q4 1

6

Dahej - Regas margins ( Rs./mmbtu)

Dahej - Regas margins (adj for Boil off from LT) ( Rs./mmbtu)

-

4.0

8.0

12.0

16.0

Q1 1

1

Q2 1

1

Q3 1

1

Q4 1

1

Q1 1

2

Q2 1

2

Q3 1

2

Q4 1

2

Q1 1

3

Q2 1

3

Q3 1

3

Q4 1

3

Q1 1

4

Q2 1

4

Q3 1

4

Q4 1

4

Q1 1

5

Q2 1

5

Q3 1

5

Q4 1

5

Q1 1

6

Q2 1

6

Q3 1

6

Q4 1

6

Rasgas price ($/mmbtu) Boil Off Costs ( Rs./mmbtu)

We think there are risks to existing re-gas tariff rates – as Regas (adj for Boil Off) has

materially spiked on low LNG costs

Regas rates adjusted for Boil Off Costs has spike in Q4’16

… led by a substantial drop in Boil Off costs

Petronet LNG has been taking an annual escalation in

tariffs to the tune of 5% every year – we understand

that such increase in rates are approved by the key

offtakers GAIL/BPCL & IOCL (who are also the

promoter entities). In the past despite the price hike,

the regas rates adjusted for boil off has largely been to

the tune of Rs. 31-33/mmbtu (net increase of 2%

CAGR). Post the revision in Qatar gas prices in

December 2016, the boil off costs has significantly

dropped leading to a substantial increase in adjusted

regas rates to Rs. 37-38/mmbtu. We believe this

would cushion PLNG’s earnings materially for FY17E,

however we do see risks of downward revision in tariff

(~5) in Jan 2017 as PLNG would be required to

transfer some part of the benefits, which could bring

down the adjusted tariffs to Rs. 35/scm, still better

than the previous average.

Though regas rates has been increasing at ~5% every year,

the regas rate adjusted for boil off has increased only by

~2% CAGR in the last 5yrs excluding the spike in Mar’16

Source: Company, Spark Capital Research

Take or Pay on Capacity expansion may not be completely watertight

PLNG’s new take or pay contracts for 7.3mmt may have a staggered take or pay contract; we see a worst case volume of 13mmt on the expanded capacity

4.50 GAIL 2.50

2.00 IOCL 1.50

1.00 BPCL 1.00

GSPC 2.25

7.50 Total 7.25

1

Contract has provisions to lower offtake by 10%Take or pay clause may be for 50-60+% of the volumes with a

potential ramp up

Capacity set to increase by 50% over the next 2 years

21Downside

Source:

2

PLNG’s brownfield capacity expansion is scheduled for

completion in Nov’16 and FY18 would see the benefit of

this asset. PLNG has contracted most of the volumes of the

expanded capacity under Take or Pay agreements.

However if the volumes fall short of the contracted capacity

we do not see a case of 100% take or pay being imposed.

While management has not commented clearly on this, we

believe the Take or Pay could potentially be a staggered

ramp up with 50-60+% of initial take or pay. Also we believe

that short volumes on any given year could be

compensated in the ensuing years by the offtakers and

hence there is a case for not imposing the same.

This presents a risks to expected earnings as we do not

see the terminal @ full capacity by FY18, given the bleak

demand potential from priority sectors.

10.0 10.0

5.0

2.5

7.5

12.5

17.5

Current FY18

Current Capacity Expansion underway (COD - Nov'16)

7.5 7.3

14.8

11.1 13.0

0.3

-

6.0

10.0

14.0

18.0

Long Term - Qatar Take or Pay Dec 2017 Capacity FY16 Worst case volumes

Committed Uncommitted

Source: Company, Spark Capital Research

ROCE (Post Tax) Regas Tariffs (Rs. /mmbtu)

0.25 33.00 35.00 37.00 40.00 42.60

Uti

lis

ati

on

50% 7% 8% 9% 10% 11%

60% 9% 10% 11% 13% 14%

70% 11% 13% 14% 15% 17%

80% 13% 15% 16% 18% 19%

90% 15% 17% 18% 20% 22%

100% 18% 19% 21% 23% 25%

ROE (Post Tax) Regas Tariffs (Rs. /mmbtu)

0.50 33.00 35.00 37.00 40.00 42.60

Uti

lis

ati

on

50% 15% 16% 18% 20% 22%

60% 19% 21% 23% 25% 28%

70% 23% 25% 27% 31% 33%

80% 27% 29% 32% 36% 39%

90% 31% 34% 37% 41% 44%

100% 35% 38% 41% 46% 50%

PLNG has historically targeted an Equity IRR of 16-18% on its new projects. We believe it is likely that PLNG has contracted its capacity to various offtakers

like GAIL / BPCL / IOCL etc (also its promoter entities) with similar or a slightly higher rate of returns profile. Based on our workings we note that at the

current tariff levels of Rs. 42.6/mmbtu and 80-90% utilisation the ROCE & ROE would be around 22% & 45% respectively, which is quite high in our view.

Given the fact that 65% of the funding for the project was given by the offtakers (to be adjusted against future revenues), we believe the tariffs for the new

terminal could be lower. Also the key difference between the current re-gas tariff and the re-gas rate would be that PLNG bears the risk of Boil off costs (Rs.

4-5/mmbtu) in the former while it doesn’t bear the same costs on the latter and hence we believe the pricing could be lower. We model Rs. 40/mmbtu,

however the tariff could be much lower.

Regas Tariff for new terminal could be lower !

Details of capacity expansion

Capcity 5MMT

COD Nov'16

Capex Rs. 22 bn

Funding

-Adv from customers Rs. 14bn

-PLNG (Mix of Equity / Debt) Rs. 8 bn

Note: Advances to be adjusted against future receivables

Break down of estimates

EBITDA Throughput for new terminal (excl 11.5MMT for old)

Reg

as R

ate

fo

r n

ew

term

ina

l 22.9 1.5 2.0 2.5 3.0 3.5 4.0

37 21.7 22.6 23.6 24.5 25.5 26.4

38 21.8 22.7 23.7 24.7 25.6 26.6

39 21.8 22.8 23.8 24.8 25.8 26.8

40 21.9 22.9 24.0 25.0 26.0 27.0

41 22.0 23.0 24.1 25.1 26.2 27.2

42 22.1 23.1 24.2 25.3 26.4 27.4

PAT Throughput for new terminal (excl 11.5MMT for old)

Reg

as R

ate

fo

r n

ew

term

ina

l

14.2 1.5 2.0 2.5 3.0 3.5 4.0

37 13.3 14.0 14.7 15.4 16.1 16.8

38 13.3 14.1 14.8 15.5 16.2 17.0

39 13.4 14.1 14.9 15.6 16.4 17.1

40 13.4 14.2 15.0 15.7 16.5 17.3

41 13.5 14.3 15.1 15.9 16.6 17.4

42 13.6 14.4 15.2 16.0 16.8 17.6

Volumes Sold- MMT FY13 FY14 FY15 FY16 FY17 FY18 FY19

Dahej - Old 10.3 9.6 10.2 11.1 11.1 11.5 11.5

Dahej - New terminal 2.0 3.0

Kochi 0.0 0.1 0.2 0.3 0.4 0.5 0.6

Total- MMT 10.3 9.7 10.5 11.4 11.5 14.0 15.1

Dahej Utilisation 103% 96% 102% 111% 111% 90% 97%

Kochi Utilisation 0% 2% 5% 6% 8% 10% 12%

Regas Rates

Dahej- Existing (10 MMT) 35.5 37.2 39.1 41.0 42.6 42.6 42.6

Dahej- New (5MMT) 0.0 0.0 0.0 0.0 0.0 40.0 40.0

Kochi 0.0 62.3 68.1 68.0 65.0 65.0 65.0

Per unit Financials

Gross profit 41.2 38.3 35.5 35.4 40.5 39.8 39.9

Employee Costs 0.7 0.9 1.1 1.2 1.3 1.2 1.2

-Power & Fuel 2.9 3.8 3.6

-Repairs & Maintenance 0.6 0.6 1.1

-Others 1.9 2.6 2.7

OPEX 5.4 7.0 7.4 6.8 6.9 6.5 6.5

EBITDA (Rs./ mmbtu) 37.0 30.3 27.0 27.4 32.3 32.1 32.3

EBITDA (Rs.Bn) 19.4 15.0 14.4 15.9 18.9 22.9 24.8

PAT (Rs.Bn) 11.5 7.1 8.8 9.1 11.4 14.2 15.5

EPS (Rs) 15.3 9.5 11.8 12.2 15.2 18.9 20.7

We believe the key delta between street and our estimates

We model utilisation of 90% or 13.5mmt of the expanded

capacity in FY18E vs street @ 100%+ or 15mmt

We estimate the tariff for the new terminal @ Rs. 40/mmbtu

(5% lower than the extant terminal) vs street at Rs. 42/mmbtu

in line with current terminal regas rates.

Our estimates Street estimates

Valuation and key model estimates

Particulars FY14 FY15 FY16 FY17E FY18E FY19E FY20E FY21E Valuation Mar-17

Dahej - Regas (incl. LT) 8.4 8.8 9.6 10.6 11.5 11.5 11.5 11.5 Total of PV of CF 57

Dahej - Short term /spot 1.2 1.4 1.5 0.5 0.0 0.0 0.0 0.0 Terminal Value 149

Dahej - New terminal 2.0 3.0 3.5 5.0 Total firm Value 206

Kochi 0.1 0.2 0.3 0.4 0.5 0.6 0.7 1.7 Net debt / (cash) -4

Volume (mmt) 9.7 10.5 11.4 11.5 14.0 15.1 15.7 18.2 Other liabilities 14

Dahej - utilisation 96% 102% 111% 111% 90% 97% 100% 110% Equity Value (Rs. Bn) 196

Kochi - utilisation 2% 5% 6% 8% 10% 12% 14% 34% Target Price (Rs. /sh) 261

Dahej - Regas 37.2 39.1 41.0 42.6 42.6 42.6 42.6 42.6 CMP 290

Dahej - Mktg margins 50.6 7.4 -22.7 5.0 0.0 0.0 0.0 0.0 Key Multiples FY18E

Dahej - New terminal 0.0 40.0 40.0 40.0 40.0 EV 227

Kochi - Regas 62.3 68.1 68.0 70.0 70.0 70.0 70.0 70.0 EV/EBITDA 9.9

Blended Tariff (Rs. /mmbtu) 38.3 35.5 35.4 40.7 40.0 40.1 40.3 41.9 PE 15.4

Gross Profit (Rs. bn) 19.0 18.9 20.6 23.9 28.6 30.9 32.3 38.9 PB 2.7

EBIT (Rs. bn) 11.9 11.2 12.7 15.5 18.8 20.6 21.3 27.5 WACC 10.0%

Tax 3.9 1.5 3.8 4.8 6.2 6.7 8.6 10.6 FY 16-18E

NOPAT (Rs. bn) 8.0 9.7 8.9 10.7 12.6 13.8 12.8 16.9 Avg. ROE 16.0%

Depreciation 3.1 3.2 3.2 3.6 4.2 4.4 4.6 4.6 Avg. FCF Yield 8.2%

FCFF (Rs. bn) 2.4 4.9 2.8 7.3 11.8 13.2 17.4 21.5

Financials

Abridged Financial Statements Key metrics

Rs. mn FY14 FY15 FY16E FY17E FY18E FY14 FY15 FY16E FY17E FY18E

Profit & Loss Growth ratios (%)

Revenues 377,476 395,010 271,334 243,528 339,086 Sales 20.0% 4.6% -31.3% -10.2% 39.2%

EBITDA 14,985 14,390 15,903 19,047 23,065 EBITDA -22.7% -4.0% 10.5% 19.8% 21.1%

Depreciation 3,081 3,154 3,216 3,596 4,228 Adj. Net Profit -38.1% 24.0% 3.6% 25.4% 22.9%

EBIT 11,904 11,236 12,687 15,451 18,837 Margin ratios (%)

Other Income/Exp 838 1,548 1,704 1,500 1,500 EBITDA 4.0% 3.6% 5.9% 7.8% 6.8%

Interest 2,196 2,935 2,388 1,674 1,044 EBIT 3.2% 2.8% 4.7% 6.3% 5.6%

PBT 10,545 9,849 12,004 15,278 19,293 Adj. Net Profit 1.9% 1.9% 3.4% 4.7% 4.2%

Net Profit 7,119 8,825 9,140 11,458 14,084 Performance ratios

Adjusted Net Profit 7,119 7,325 9,140 11,458 14,084 RoIC (%) 19% 13% 12% 15% 16%

Balance Sheet RoE (%) 15% 14% 15% 17% 19%

Shareholders Equity 49,861 56,886 63,764 71,623 80,307 RoCE (%) 11% 14% 13% 15% 17%

Total debt 28,965 26,225 23,097 14,097 9,097 Sales / Total Assets (x) 4.5 4.2 2.6 2.2 3.1

Total Networth & Liabilities 87,394 99,424 109,628 108,486 112,170 Fixed Assets Turnover (x) 5.5 5.3 3.4 2.9 3.9

Net fixed assets 62,650 69,426 67,392 86,014 81,786 Financial stability ratios

CWIP 8,799 7,469 16,218 1,020 6,020 Total Debt to Equity (x) 0.6 0.5 0.4 0.2 0.1

Investments 1,399 900 900 900 900 Inventory & Debtor days 29 21 17 17 17

Current assets 46,278 33,392 39,970 35,041 44,093 Creditor days 28 9 17 17 17

Current liabilities 31,733 11,762 14,853 14,490 20,630 Valuation metrics

Net current assets 14,545 21,630 25,117 20,551 23,463 Current Share Price (Rs.) 290

Total Assets 87,394 99,424 109,628 108,485 112,170 Market Cap (Rs.mn) 217,500 217,500 217,500 217,500 217,500

Cash Flows Fully Diluted Shares (mn) 750 750 750 750 750

Cash flows from Operations 9,636 (150) 29,031 15,267 17,721 Adjusted EPS (Rs.) 9.5 9.8 12.2 15.3 18.8

Cash flows from Investing (8,028) (6,452) (7,646) (5,500) (3,500) P/E (x) 30.6 29.7 23.8 19.0 15.4

Cash flows from Financing (1,966) (2,084) (3,218) (13,374) (9,644) P/B (x) 4.4 3.8 3.4 3.0 2.7

Cash Generated (358) (8,687) 18,168 (3,607) 4,577 EV (Rs.mn) 233,237 239,185 217,868 212,495 202,918

Opening Cash 12,685 12,327 3,641 21,809 18,202 EV/ EBITDA (x) 15.6 16.6 13.7 11.2 8.8

Closing Cash 12,327 3,641 21,809 18,202 22,779 Dividend Yield (%) 0.9% 1.0% 1.0% 1.4% 2.1%

GAIL (INDIA) CMP

Rs. 380

Target

Rs. 440

Rating

BUY

Page 19

Stock performance

1m 3m 12m

GAIL 0% 6% -5%

Sensex -1% 4% -5%

BSEOG 1% 5% -4%

Date 28 June 2016

Market Data

SENSEX 26403

Nifty 8095

Bloomberg GAIL IN

Shares o/s 1,268mn

Market Cap Rs. 482bn

52-wk High-Low Rs. 401-260

3m Avg. Daily Vol Rs. 602mn

Index member NIFTY

Promoters 56.1

Institutions 40.4

Public 3.5

Initiating Coverage


Financial summary - Standalone

Year Revenues (Rs. bn) EBITDA (Rs. bn) Adj PAT (Rs. bn) EPS (Rs.) P/E (x) EV/EBITDA (x) ROE %

FY15 565.7 45.2 29.9 24.0 11.9 8.8 10.7%

FY16 516.1 39.7 23.0 18.1 15.4 9.4 7.7%

FY17E 527.1 59.2 34.5 27.2 10.3 5.7 10.8%

FY18E 564.5 65.2 39.7 31.3 8.9 4.7 11.3%

Gas Authority of India Ltd.’s (GAIL) long term LNG (5.8mmt or 21mmscmd) is a key worry for market, despite a

healthy earnings growth trajectory as the potential impact (worst case) could be $300mn or Rs. 10/sh (~30% of FY16

EPS). We believe the case for risks are overblown and do not see any material impact due to1) The “Date of first

commercial delivery” – DFCD starts only from Mar’18 for its Cheniere contract – 3.5mmt and a similar timeline for its

Dominion contract of 2.3mmt – at least 21 months away, 2) We believe the break even cost for US LNG vs Oil linked

spot gas would turn in the former’s favour if Oil goes past $55/bbl a high likelihood by FY19, 3) >80% of all new LNG

terminals would have oil indexation and hence more costlier than GAIL’s contracts and 4) Potential for swapping

volumes with other suppliers could save ~$1/mmbtu (for deliveries to India) making US gas more competitive.

Net/net we believe GAIL’s US LNG contracts are unlikely to impact consol earnings. On the core earnings front, we

see a revival led by 1) likelihood of tariff increase in the transmission biz (atleast 10%, with upside risks), 2) reversal

of Petchem earnings led by ramp up in volumes from PATA II expansion (doubling capacity), lower input costs and

steady margins, 3) LPG biz to benefit from lower gas prices (From $3.4/mmbtu to $2.8) from 2HFY18 onwards and 4)

volumes in gas transmission & trading should gradually improved led by new LNG terminals. Overall, rising oil

prices (though slow) would lead to higher earning trajectory & removal of uncertainity. Expect EPS to increase from

31% CAGR over FY16- 18E (albeit form a low base). Also substantial FCF generation (Rs. 30-35bn pa) should aid for

deleveraging. Initiate coverage with an SOTP based TP of Rs. 440 with a BUY rating

US LNG Contracts – too early to worry? – GAIL has two US LNG contracts with Cheniere & Dominion Cove Point for

3.5mmt & 2.3mmt respectively. Bot the terminals are scheduled for start up in 2HCY17E, however we see contractual

obligations for delivery starting from FY19 onwards. While GAIL has resold only 0.5mmt of volumes (~10%), we do not see

much risk as despite the LNG glut, we see Oil indexed LNG to be slightly higher priced and with Oil prices >$55/bbl US LNG

would remain competitive. Also a potential volume swap with Qatar for its supplies to Europe, could lessen transportation

costs by almost ($1-$1.5/mmbtu) assuming deliveries to India.

Tariff hikes in Transmission to boost earnings: Expect tariff hikes of at least 10% (with upside risks) as PNGRB

undertakes the tariff revision process for all pipelines; completed only for 2 smaller networks (>40% hike). Though hikes are

a near certainty there could be timing delays of 6-9months on PNGRB’s side.

Deleveraging could materially boost Mcap: GAIL is set to generate FCF of Rs. 30-35bn pa (after capex of Rs. 16-18bn)

over the next 2 years we see a case for netdebt to turn positive by end Mar’18, leading to a EV to Mcap movement to the

tune of 12.5% on CMP

LNG Risks overblown – Earnings revival on the cards; Top pick

Particulars ($/mmbtu) Cheniere Contract Current Spot LNG Contracts

Low High Low High

Henry Hub (HH) 2.5 3.0

115% of HH (A) 2.9 3.5

Liquefaction costs (B) 3.0 3.0

FOB Costs (A+B) 5.9 6.5 5.0 5.5

Shipping Costs 1.5 3.0 0.2 0.4

Delivered to Asia 7.4 9.5 5.2 5.9

Delta between LNG Deliveries (US & Asia)

FOB Costs -0.9 -0.9

Delivered Costs -1.3 -2.6

GAIL’s US Long term LNG contracts @ risks if delivered today – Potential impact of $300mn – but unlikely to materialise

Using the current differentials on FOB costs (between US Long term

& Spot contracts for India) the potential loss on GAIL’s US LNG

contracts stands at $300mn or Rs. 13bn of loss on PAT or Rs. 10/sh

impact (30% to 40% impact on current earnings).

Seller TerminalVolumes

(mmt)

Period

(yrs.)Status

Cheniere Sabine Pass 3.5 20 Under Construction

Dominion Cove Point 2.3 20 Under Construction

Gazprom Shtokman 2.5 20 Currently on hold

Total (mmt) 8.3

Total (mmscmd) 29.88

Contracts Terms

Cheniere 115% of Henry Hub + Liquefaction Charge of $3/mmbtu

Dominion Gas to sourced by GAIL + Liquefaction costs

Long term LNG Contracts entered by GAIL US LNG imports to India would be a loss making proposition @ current price

Timeline of Start up of the Liquefaction units

Commodity prices post start up & differentials between Oil linked &

gas linked contracts by then

% of new capacities that would be gas linked vs Oil ?

Whether Spot contracts & Oil linked Long term contracts would

materially diverge

Potential for swapping LNG volumes

US Long term potential impact of $300mn @ current prices – but highly unlikely !

Key things that matter for pricing in risks for US LNG

Based on the recent commentary by

Cheniere Energy, the commissioning

process for Train 4 will start by Aug

2017 and “DFCD” – Date of First

Commercial Delivery notified to GAIL is

March 2018 – post which the contract

comes into force

GAIL’s US LNG starts only from March 2018 – at least 21 months away !

Delivery of first cargoes from Cheniere energy will start only from March 2018 onwards. The “DFCD” – The date of First Commercial delivery” is

in March 2018 – post which the contract come into force – At least 21 months away !

Particulars Date Train

Annual

contract Qty

(mmt)

LNG CostFixed fees

($/mmbtu)

Annual Fixed

fees $Mn

Sabine Pass Liquefaction SPAs

BG Group Oct-11 T1 3.5 115% of HH 2.3 460.1

Gas Natural Fenosa Nov-11 T2 3.5 115% of HH 2.5 454.0

GAIL Dec-11 T4 3.5 115% of HH 3.0 548.0

BG Group Jan-12 T2/3/4 2.0 115% of HH 3.0 262.9

Kogas Jan-12 T3 3.5 115% of HH 3.0 548.0

Total Dec-12 T5 2.0 115% of HH 3.0 314.0

Centrica Mar-13 T5 1.8 115% of HH 3.0 274.0

Country Terminal Trains Start YearCapacity

(MTPA)Status Linkage

2016 23.9

Australia GLNG T1 2016 3.9 Commissioned in Oct 2015 Oil

Australia GLNG T2 2016 3.9 Commissioned in May 2016 Oil

Australia APLNG T1 2016 4.5 On track for start up Oil

Australia Gorgon LNG T1 2016 5.4 Commissioning Phase / Commercial start up in 2H Oil

US Sabine Pass T1 2HCY16 4.5 Commissioning Phase / Commercial start up in 2H Gas

Indonesia Senkang LNG T1 2016 0.5 On track for start up Oil

Malaysia PFLNG 1 T1 2016 1.2 On track for start up Oil

2017 46.0

Australia Wheatstone T1 1HCY17 4.5 Scheduled for CY16 now delayed to CY17 Oil

US Sabine Pass T2 2HCY17 4.5 Under Constrn. /Commercial start up in 1H Gas

Malaysia PL9SB / 9th Train T9 2016 3.6 Under Construction Oil

Australia Gorgon LNG T2 1HCY17 5.2 Under Construction Oil

Australia Gorgon LNG T3 2HCY17 5.2 Under Construction Oil

Australia APLNG T2 2HCY17 4.5 Under Construction Oil

Australia Prelude FLNG 2017 3.6 Under Construction Oil

US Cove Point 2HCY17 5.3 Under Construction Gas

US Sabine Pass T3 2017 4.5 Under Constrn. /Commercial start up in 2H Gas

Australia Gorgon LNG T3 2017 5.2 Under Construction Oil

2018 28.9

Australia Wheatstone T2 2018 4.5 Under Construction Oil

US Sabine Pass T4 2018 4.5 Under Construction Gas

Australia Ichthys T1 1HCY18 4.5 Under Construction Oil

Australia Ichthys LNG T2 2HCY18 4.5 Under Construction Oil

Russia Yamal LNG T1/2 2HCY18 11.0Progressing slow due to sanctions & funding

constraintsOil

2019 / 20 45.7

US Cameron LNG T1-3 2019 12.0 Commercial operations expected to start in 2019 Gas

Russia Yamal LNG T3 2019 5.5 Under Construction Oil

US Freeport LNG T1/2/3 2019 13.2 Commissioning in CY19 in phases Gas

US Sabine Pass T5 2019 4.5 Target end CY19 for first gas Gas

US Corpus Christi T1-2 CY19/20 9.0 T1 in CY19 & T2 in CY20 Gas

Malaysia PFLNG 2 T2 2018 1.5 Scheduled for CY18 / now delayed Oil

Sizeable LNG additions on the way (~100MT in 3years) but most would still be linked to Oil

Expect 140MMT of LNG Capacity

additions over the next 5 years

especially from Australia & US

which would cause a substantial

glut in the LNG market, however

delays in some of the projects with

start up post 2018 could soften the

blow.

The only gas linked project with

start up over CY16-18 is Sabine

pass, the rest would start only in

CY19/20

Will the Oil linkage break soon ? Will Long term and spot diverge materially ? We think not so soon

19%

31%

16%

85%

81%

69%

84%

15%

2016

2017

2018

2019/2020

Split up of new Liquefaction terminals by Oil / Gas linkage

Gas linked LNG Capacity additions Oil linked LNG Capacity additions

>80% of new capacities that are coming up are still linked to Oil and only in

CY19/20 will gas index based LNG capacities overtake the Oil indexed ones

Spot / shot term trade contributes ~30% of the trade while 70% still runs

through long termNotable new contracts Medium / Long term contracts signed in 2015 & 2016

continue to be on Oil Indexed

Contract Status

Volume

(mmtpa)

Price

(US$/mmbtu) Duration

Chevron – ENN HOA 0.50 12.3% + 0.3 10 years

Chevron – Huadian HOA 1.00 12.4% + 0.3 10 years

BP –Huadian SPA 1.00 13.0% + 0.5 5 years

Qatargas –PSO SPA 3.00 13% 15 years

Perenco -Gazprom SPA 1.20 11% 8 years

RasGas –Petronet SPA 1.00 12.7% + 0.6 12 years

CPC tender -2016 60 cargoes thought to have been awarded at

11.50% + $0.5 for lean specification gas

2017-

2021

5%

15%

25%

35%

0

20

40

60

80

2005 2007 2009 2011 2013 2015

% S

ha

re

MT

PA

Spot / ST Trade % of Total LNG Trade (RHS)

Both Aussie & US projects are ~90% contracted. Most of them are picked by

consuming countries. Portfolio buyers are <25% and they source mostly

from US LNG – a chunk off which will come only in CY19/20

13

20

14.5

1.5 22

21

86.5

22.5

0

5

10

15

20

25

China Japan SK / Taiwan / Malaysia India Others

Australia US

A material divergence between Spot vs Long term is unlikely in our view as such

an event would lead to potential renegotiation of the 70% volumes sold by the

same seller who is also in the spot market. Hence it is not in the interest of the

sellers to aggressively sell in the spot market

LNG from US would break even with Long term LNG @ ~$50/bbl & Spot / ST Oil linked LNG @ ~$55/bbl

Crude Price ($/bbl) 40.0 50.0 60.0 70.0 90.0

Henry Hub (HH) 2.0 2.5 3.0 3.5 4.0

115% of HH (A) 2.3 2.9 3.5 4.0 4.6

Liquefaction costs (B) 3.0 3.0 3.0 3.0 3.0

FOB Costs (A+B) = (1) 5.3 5.9 6.5 7.0 7.6

Oil Linked LNG Price (Long term) @12.5% (2) 5.0 6.3 7.5 8.8 11.3

US LNG Premium / (Discount) to Oil indexed LNG (1)-(2) 0.3 -0.4 -1.1 -1.7 -3.7

Oil Linked LNG Price (Spot / ST) @11% (3) 4.4 5.5 6.6 7.7 9.9

US LNG Premium / (Discount) to Oil indexed LNG (1)-(3) 0.9 0.4 -0.2 -0.7 -2.3

Oil Linked LNG Price (Spot / ST) @10% (4) 4.0 5.0 6.0 7.0 9.0

US LNG Premium / (Discount) to Oil indexed LNG (1)-(4) 1.3 0.9 0.4 0.0 -1.4

Divergence between LT & Spot / ST

Oil Linkage @ 11% 0.6 0.8 0.9 1.1 1.4

Oil Linkage @ 10% 1.0 1.3 1.5 1.8 2.3

If Oil trades between $50-$60/bbl US LNG could turn cheaper than LT LNG & even ST

LNG (linked @ 11% on Oil)

LNG from US would break even with Long

term LNG @ ~$50/bbl & Spot / ST Oil

linked LNG (11% indexation) @ ~$55/bbl.

We believe oil prices are headed higher

over the next 18-24 months. With US LNG

flow likely from March 2018, we do not see

much risks on this front

From ToShipping

($/mmbtu)Nautical Miles

Trinidad Belgium 0.5 5,461

Qatar Spain 0.9 6,255

Qatar UK 1.0 7,044

Qatar US East 1.1 7,300

Qatar S Korea 0.7 7,367

Qatar US Gulf 1.3 7,410

Indonesia UK 1.4 9,627

Indonesia US Gulf 1.4 11,363

Nigeria Japan 1.2 12,286

Indonesia US East 1.3 16,804

Sabine Pass India 13,776

Sabine Pass UK 5,440

Sabine Pass Belgium 5,994

Sabine Pass Spain 4,820

Cost of Shipping could dent profitability, however there are ample scope to swap volumes & reduce costs

by atleast $1/mmbtu for deliveries to India

Middle East LNG exports by importing region

Qatar exports 25% of its LNG volumes (~20MMT) to Europe (UK, Spain,etc) at an estimated shipping costs of $1/mmbtu for a distance of 6k-7k nautical miles.

Shipping costs from Qatar to S Korea however is markedly lower @ $0.6 - $0.7/mmbtu for a similar distance as they do not involve Canal charges. We believe

GAIL could negotiate a deal whereby Qatar volumes to Europe and GAIL’s volumes to India could be swapped there by potentially saving around $1/mmbtu as

the cost of shipping directly from US to Europe (<5k nautical miles) would at max result in $0.5/mmbtu of costs

Total Shipping Costs from US to India Current 2013/14

Charter Costs ($/mmbtu) 0.5 1.1

Boil Off Costs ($/mmbtu) 0.2 0.2

Fuel Costs 0.5 1.4

Port / Others 0.2 0.2

Total ($/mmbtu) 1.4 3.0

Shipping Costs have halved led by lower crude price & day rates

Indicative Shipping Costs & Distances between key LNG importing /

Exporting regions

49.4

20.815.5

6.9

0

20

40

60

APAC Europe Asia Others

MM

T

Source: Spark Capital Research

Petrochem Segment to turn profitable again led by volume; costs & margins

Expect Petchem segment to return to previous glories from FY17

onwards

13.5

16.4 17.115.5

2.2

-4.3

14.515.9

11.9

14.7 15.313.6

1.3

-8.1

10.511.9

-10

-5

0

5

10

15

20

FY11 FY12 FY13 FY14 FY15 FY16 FY17E FY18E

Rs. B

n

EBITDA EBIT

420 448 427 445 441

334

710778

FY11 FY12 FY13 FY14 FY15 FY16 FY17E FY18E

MM

T

5.8

6.3

4.53

6

9

12

15

18

Fe

b-1

5

Ap

r-15

Jun

-15

Au

g-1

5

Oct-

15

Dec-1

5

Fe

b-1

6

Ap

r-16

Jun

-16

$/m

mb

tu

Petronet Qatar Rasgas Price India DEA Spot Price JKM

1 Volumes set to expand on PATA II Expansion; Ramp up to 80%+ by FY18

Key reason for earnings decline in FY15/16 was costly Qatar gas – the

cost of which is now @ par with Spot gas2

3Petrochemical (PE) margin near 5 year highs; we remain +ve on the

outlook

400

600

800

1,000

FY

10

FY

11

FY

12

FY

13

FY

14

FY

15

FY

16

$/M

MT

HDPE - Naphtha

RIL & GAIL’s capacity additions would only partially bring down India’s PE imports and India would continue to remain net importer of the product

0

500

1000

1500

2000

2500

3000

2014 2015 2016 2017 2018 2019 2020

India PE net trade

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

10.0

2014 2015 2016 2017 2018 2019 2020

MM

T

India Ethylene Capacity vs Total Downstream demand

Production Demand

Imports

Exports

PE chain margins have been the highest in the last 5 years. We expect the same continue over the next 12-18 months.

85%

86%

87%

88%

89%

2011

2012

2013

2014

2015

2016

Global Ethylene Cracker Operating Rates

0

5000

10000

0

10000

20000

30000

2011

2012

2013

2014

2015

2016

2017

2018

'000t

'000t

Production

Demand

Import (RH scale)

300

400

500

600

700

800

900

FY

10

FY

11

FY

12

FY

13

FY

14

FY

15

FY

16

HDPE - Naphtha

HDPE Margins are near 5yr highs Global Ethylene Cracker utilization to remain >87%China would continue to remain an

importer of PE even by CY18

Petrochemical margins are quite strong for PE chains as China & India continues to remain importers

Network/Region Length Capacity

(mmscmd) Average Flow (mmscmd) % Capacity utilisation

Tariff

finalised

Proposed

Tariff by

GAIL

Tariff

approved

by

PNGRB

%

Reduced

Propose

d Tariff

by GAIL

Tariff

approved

by

PNGRB

%

Reduced

(Kms) Mar'16 FY14 FY15 FY16 FY14 FY15 FY16 Provisional Final

HVJ /GREP /DVPL 4,658 53 43 39 33 81% 73% 62% Provisional 35.4 25.5 -28%

DVPL- GREP Up-grade 1,119 54 15 20 26 28% 38% 47%

DUPL/DPPL 875 20 9 9 10 45% 43% 48% Provisional 40.2 24.5 -39%

Mumbai 129 7 23 9 6 138% 128% 88% Provisional 10.7 3.5 -68%

KG Basin 881 16 6 3 5 37% 22% 31% Finalised 11.8 5.6 -53% 180.8 45.3 -75%

Dadri- Bawana- Nangal 835 31 2 4 4 22% 13% 13% Provisional 27.7 11.9 -57%

Cauvery Basin 278 9 4 3 3 41% 38% 32% Finalised* 43.6 17.4 -60%

Gujarat 538 15 2 4 2 32% 25% 11%

Tripura (Agartala) 61 2 1 1 1 65% 64% 65% Provisional 11.5 5.8 -50%

Rajasthan 152 2 1 1 1 46% 56% 60%

Dabhol -Bangaluru 1,097 16 1 1 1 6% 5% 6% Provisional 73.5 44.7 -39%

Chainsa- Jhajjar 265 5 1 1 1 14% 16% 15% Provisional 13.3 4.2 -69%

Kochi-Mangalore 48 6 0 0 1 5% 7% 10%

Assam (Lakwa) 8 3 1 1 0 23% 21% 16%

Ahmedabad 133 3 0 0 0 13% 11% 9%

*Only for Narimanam and Kuthalam sub-network

Tariff revision on the cards; Expect at least 10% with upside risks

Tariffs for GAIL’s piplines are currently being undertaken and the company has received orders for KG Basin & Cauvery Basin both off which has seen

substantial increase in the provisional tariffs approved and the final tariff. We believe tariffs on a blended level could increase by 10%+ with upside risks.

While the tariff hikes are a near certainty there could be delays on PNGRB’s side for approval (likely within 6-9 months)

Particulars

Henry

NBP Russia Alberta

Volume

weighted

avg. price

Gross gas

price

Adjustment

s

Gas price

on GCV

Gas price

on NCV Reset from

Hub

Quarter / Volume

Weights42% 30% 23% 6% 100%

Jun'14 4.6 7.6 3.2 4.3 5.1 5.6 0.5 5.0 5.6

Sep'14 3.9 7.0 3.0 3.7 4.6

Dec'14 3.7 8.4 2.2 3.2 4.7 5.2 0.5 4.7 5.2 Mar'15

Mar'15 2.9 7.3 1.7 2.2 3.9

Jun'15 2.7 6.9 2.1 2.2 3.8 4.3 0.4 3.8 4.2 Sep' 15

Sep'15 2.7 6.4 1.7 2.2 3.6

Dec'15 2.1 5.5 1.7 1.9 3.0 3.6 0.5 3.1 3.4 Mar'16

Mar'16 2.0 4.4 1.7 1.3 2.6

Jun'16 2.1 4.5 1.7 1.1 2.7 3.0 0.5 2.5 2.8 Sep'16

Gas price reduction to aid earnings in LPG / Petchem & Transmission

We expect domestic gas price to decline from $3.4/mmbtu (NCV basis) to

$2.7-$2.8/mmbtu by Sep’16 which couls aid earnings for GAIL;s various

business segments. GAIL sources approximately ~3.5mmscmd of domestic

gas (LPG – 2.5mmscmd; Transmission – 1mmscmd and <0.2mmscmd in

Petchem). We see these three segments benefitting from lower gas prices

Key model assumptions

Particulars FY14 FY15 FY16 FY17E FY18E

Natural gas transmission Mmscmd 95.9 92.1 92.1 93.0 97.5

Natural gas trading Mmscmd 81.5 72.1 73.7 75.9 81.9

LPG Transmission Mmt 3.1 3.1 2.8 3.0 3.0

Petrochemical Mtpa 0.4 0.4 0.3 0.7 0.8

Liquid and HC Mtpa 1.3 1.3 1.1 1.2 1.2

Gas Transmission Tariff Rs./scm 1.2 1.0 1.2 1.2 1.2

Avg Marketing margin Rs./scm 0.5 0.2 0.5 0.3 0.3

LPG transmission tariff Rs./tonne 1.3 1.4 1.7 1.6 1.6

Petrochemical realisation $/mt 1702.2 1750.4 1403.7 1326.9 1439.8

Liquid HC Price $/mt 927.0 773.9 456.9 457.3 596.8

Valuation

Particulars FY18 EBITDA MultipleRs. Mn Rs/share

NG Transmission 30 8.0x 241 190

LPG Transmission 3 8.0x 25 19

Gas Trading 10 5.0x 50 39

Petrochemical 16 6.0x 95 75

LPG and Liquid HC 15 5.0x 73 58

Core business 484 382

Investments 124 98

Total EV 479

Net Debt 30 38

Target Price 441

CMP 380

GAIL has been trading in the band of ~6-8x EV/EBITDA since Jun’13

4.0

6.0

8.0

10.0

12.0

Jun

-09

Dec-0

9

Jun

-10

Dec-1

0

Jun

-11

Dec-1

1

Jun

-12

Dec-1

2

Jun

-13

Dec-1

3

Jun

-14

Dec-1

4

Jun

-15

Dec-1

5

Jun

-16

Average P/B is 1.7x vs current P/B of ~1.2x

Average PB, 1.7

-

0.5

1.0

1.5

2.0

2.5

3.0

Oct-

10

Ap

r-11

Oct-

11

Ap

r-12

Oct-

12

Ap

r-13

Oct-

13

Ap

r-14

Oct-

14

Ap

r-15

Oct-

15

Valuation and Key estimates

Financial Summary

Abridged Financial Statements Key metrics

Rs. mn FY14 FY15 FY16 FY17E FY18E FY14 FY15 FY16 FY17E FY18E

Profit & Loss Growth ratios (%)

Revenues 5,72,451 5,65,695 5,16,143 5,27,140 5,64,476 Sales 20.9% -1.2% -8.8% 2.1% 7.1%

EBITDA 64,383 45,237 39,684 59,200 65,173 EBITDA 2.5% -29.7% -12.3% 49.2% 10.1%

Depreciation 11,762 9,743 13,131 13,520 14,279 Adj. Net Profit -4.3% -27.7% -23.2% 50.3% 15.0%

EBIT 52,622 35,494 26,553 45,680 50,894 Margin ratios (%)

Other Income/Exp 15,063 10,963 11,576 11,328 11,328 EBITDA 11.2% 8.0% 7.7% 11.2% 11.5%

Interest 3,662 3,613 6,400 5,453 2,925 EBIT 9.2% 6.3% 5.1% 8.7% 9.0%

PBT 64,023 42,844 31,728 51,556 59,298 Adj. Net Profit 7.2% 5.3% 4.5% 6.6% 7.0%

Net Profit 43,752 30,392 22,989 34,542 39,729 Performance ratios

Adjusted Net Profit 41,395 29,946 22,989 34,542 39,729 RoIC (%) 11.3% 6.9% 5.0% 8.0% 9.0%

Balance Sheet RoE (%) 16.1% 10.7% 7.7% 10.8% 11.3%

Shareholders Equity 2,70,723 2,91,195 3,05,849 3,35,939 3,66,763 RoCE (%) 12.7% 8.6% 7.1% 10.0% 10.9%

Total debt 95,261 95,559 81,180 40,000 25,000 Sales / Total Assets (x) 1.5 1.3 1.2 1.2 1.3

Total Networth & Liabilities 4,03,400 4,46,424 4,44,487 4,36,490 4,55,873 Fixed Assets Turnover (x) 1.9 1.8 1.6 1.6 1.7

Net fixed assets 2,21,959 2,85,111 2,97,980 3,00,461 2,92,182 Financial stability ratios

CWIP 90,086 36,086 22,443 22,443 32,443 Total Debt to Equity (x) 0.4 0.3 0.3 0.1 0.1

Investments 41,030 43,224 45,467 45,467 45,467 Inventory & Debtor days 32.3 33.4 31.6 31.6 31.6

Current assets 1,12,503 1,05,953 1,07,435 1,01,045 1,25,048 Creditor days 51.2 46.3 53.4 55.0 55.0

Current liabilities 94,713 82,508 85,456 89,542 95,884 Valuation metrics

Net current assets 17,790 23,445 21,979 11,502 29,163 Current Share Price (Rs.)

380

Total Assets 4,03,400 4,46,424 4,44,487 4,35,421 4,54,803 Market Cap (Rs.mn) 4,82,021 4,82,021 4,82,021 4,82,021 4,82,021

Cash FlowsFully Diluted Shares (mn) 1,268 1,268 1,268 1,268 1,268

Cash flows from Operations 47,675 8,622 34,779 47,715 49,898 Adjusted EPS (Rs.) 32.6 23.6 18.1 27.2 31.3

Cash flows from Investing (44,387) (10,755) (3,024) (4,672) (4,672)P/E (x) 11.6 16.1 21.0 14.0 12.1

Cash flows from Financing (357) (12,961) (25,232) (51,085) (26,830)P/B (x) 1.8 1.7 1.6 1.4 1.3

Cash Generated 2,931 (15,094) 6,522 (8,042) 18,396 EV (Rs.mn) 5,09,743 5,22,941 4,99,796 4,66,658 4,33,261

Opening Cash 23,579 26,510 11,416 17,939 9,897 EV/ EBITDA (x)

7.9 11.6 12.6 7.9 6.6

Closing Cash 26,510 11,416 17,939 9,897 28,293 Dividend Yield (%) 2.5% 1.6% 1.4% 2.4% 2.6%

Disclaimer

Spark Disclaimer

Spark Capital Advisors (India) Private Limited (Spark Capital) and its affiliates are engaged in investment banking, investment advisory and institutional equities and

infrastructure advisory services. Spark Capital is registered with SEBI as a Stock Broker and Category 1 Merchant Banker.

We hereby declare that our activities were neither suspended nor we have defaulted with any stock exchange authority with whom we are registered in the last five years. We

have not been debarred from doing business by any Stock Exchange/SEBI or any other authorities, nor has our certificate of registration been cancelled by SEBI at any point of

time.

Spark Capital has a subsidiary Spark Investment Advisors (India) Private Limited which is engaged in the services of providing investment advisory services and is registered

with SEBI as Investment Advisor. Spark Capital has also an associate company Spark Infra Advisors (India) Private Limited which is engaged in providing infrastructure

advisory services.

This document does not constitute or form part of any offer or solicitation for the purchase or sale of any financial instrument or as an official confirmation of any transaction.

This document is provided for assistance only and is not intended to be and must not alone be taken as the basis for an investment decision. Nothing in this document should

be construed as investment or financial advice, and nothing in this document should be construed as an advice to buy or sell or solicitation to buy or sell the securities of

companies referred to in this document.

Each recipient of this document should make such investigations as it deems necessary to arrive at an independent evaluation of an investment in the securities of companies

referred to in this document (including the merits and risks involved), and should consult its own advisors to determine the merits and risks of such an investment. This

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and/or its affiliates to any registration or licensing requirement within such jurisdiction. The securities described herein may or may not be eligible for sale in all jurisdictions or to

a certain category of investors. Persons in whose possession this document may come are required to inform themselves of and to observe such applicable restrictions. This

material should not be construed as an offer to sell or the solicitation of an offer to buy any security in any jurisdiction where such an offer or solicitation would be illegal.

Spark Capital makes no representation or warranty, express or implied, as to the accuracy, completeness or fairness of the information and opinions contained in this

document. Spark Capital , its affiliates, and the employees of Spark Capital and its affiliates may, from time to time, effect or have effected an own account transaction in, or

deal as principal or agent in or for the securities mentioned in this document. They may perform or seek to perform investment banking or other services for, or solicit

investment banking or other business from, any company referred to in this report.

This report has been prepared on the basis of information, which is already available in publicly accessible media or developed through an independent analysis by Spark

Capital. While we would endeavour to update the information herein on a reasonable basis, Spark Capital and its affiliates are under no obligation to update the information.

Also, there may be regulatory, compliance or other reasons that prevent Spark Capital and its affiliates from doing so. Neither Spark Capital nor its affiliates or their respective

directors, employees, agents or representatives shall be responsible or liable in any manner, directly or indirectly, for views or opinions expressed in this report or the contents

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or reliance on this report.

Absolute

Rating

Interpretation

BUY Stock expected to provide positive returns of >15% over a 1-year horizon REDUCEStock expected to provide returns of <5% – -10% over a 1-year

horizon

ADDStock expected to provide positive returns of >5% – <15% over a 1-year

horizonSELL Stock expected to fall >10% over a 1-year horizon

Disclaimer (Cont’d)

Spark Capital and/or its affiliates and/or employees may have interests/positions, financial or otherwise in the securities mentioned in this report. To enhance transparency,

Spark Capital has incorporated a disclosure of interest statement in this document. This should however not be treated as endorsement of views expressed in this report:

Disclosure of interest statement Yes/No

Analyst financial interest in the company No

Group/directors ownership of the subject company covered No

Investment banking relationship with the company covered No

Spark Capital’s ownership/any other financial interest in the company covered No

Associates of Spark Capital’s ownership more than 1% in the company covered No

Any other material conflict of interest at the time of publishing the research report No

Receipt of compensation by Spark Capital or its Associate Companies from the subject company covered for in the last twelve months:

Managing/co-managing public offering of securities

Investment banking/merchant banking/brokerage services

products or services other than those above

in connection with research report

No

Whether Research Analyst has served as an officer, director or employee of the subject company covered No

Whether the Research Analyst or Research Entity has been engaged in market making activity of the Subject Company; No

Analyst Certification of Independence

The views expressed in this research report accurately reflect the analyst’s personal views about any and all of the subject securities or issuers; and no part of the research

analyst’s compensations was, is or will be, directly or indirectly, related to the specific recommendation or views expressed in the report.

Additional Disclaimer for US Institutional Investors

This research report prepared by Spark Capital Advisors (India) Private Limited is distributed in the United States to US Institutional Investors (as defined in Rule 15a-6 under

the Securities Exchange Act of 1934, as amended) only by Auerbach Grayson, LLC, a broker-dealer registered in the US (registered under Section 15 of Securities Exchange

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to you. You should satisfy yourself before reading it that Auerbach Grayson, LLC and Spark Capital Advisors (India) Private Limited are permitted to provide research material

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