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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
VISHNU KUMAR A S [email protected] +91 44 4344 0069
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
Page 2
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
Page 3
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
Page 4
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
Page 5
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
Page 6
$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
Page 7
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
Page 8
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
Page 9
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
Page 10
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
Page 11
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
Page 12
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
Page 13
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
Page 14
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
Page 15
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
Page 16
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
Page 17
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
Page 18
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
VISHNU KUMAR A S [email protected] +91 44 4344 0069
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-$1.5/mmbtu) assuming deliveries to India.
Tariff hikes in Transmission to boost earnings: Expect tariff hikes of at least 10% (with upside risks) as PNGRB
undertakes the tariff revision process for all pipelines; completed only for 2 smaller networks (>40% hike). Though hikes are
a near certainty there could be timing delays of 6-9months on PNGRB’s side.
Deleveraging could materially boost Mcap: GAIL is set to generate FCF of Rs. 30-35bn pa (after capex of Rs. 16-18bn)
over the next 2 years we see a case for netdebt to turn positive by end Mar’18, leading to a EV to Mcap movement to the
tune of 12.5% on CMP
LNG Risks overblown – Earnings revival on the cards; Top pick
Page 20
Particulars ($/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 $300mn @ current prices – but highly unlikely !
Key things that matter for pricing in risks for US LNG
Page 21
Based on the recent commentary by
Cheniere Energy, the commissioning
process for Train 4 will start by Aug
2017 and “DFCD” – Date of First
Commercial Delivery notified to GAIL is
March 2018 – post which the contract
comes into force
GAIL’s US LNG starts only from March 2018 – at least 21 months away !
Delivery of first cargoes from Cheniere energy will start only from March 2018 onwards. The “DFCD” – The date of First Commercial delivery” is
in March 2018 – post which the contract come into force – At least 21 months away !
Particulars Date Train
Annual
contract Qty
(mmt)
LNG CostFixed fees
($/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
Page 22
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
Page 23
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
Page 24
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) @ ~$55/bbl.
We believe oil prices are headed higher
over the next 18-24 months. With US LNG
flow likely from March 2018, we do not see
much risks on this front
Page 25
From ToShipping
($/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
Page 26
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
Page 27
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
Page 28
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)
Page 29
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
Page 30
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
Page 31
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%
Page 32
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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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
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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
Page 33
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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