Institutional Equities
Petronet LNG 1 October 2019
Reuters: PLNG.NS; Bloomberg: PLNG IN Numero uno in Indian LNG space with steady annuity business BUY We are initiating coverage on Petronet LNG (PLNG), India’s leading liquefied natural Sector: Oil & Gas gas (LNG) company, with a Buy based on our DCF-based target price of Rs312 ( +21% from CMP). PLNG is India’s market leader in LNG imports and distribution of Re- CMP: Rs258 gasified LNG (RLNG) with a capacity of 22.5mn tonne/year. The company’s growth is driven by India’s voracious energy appetite that is forcing the country to import close Target Price: Rs312 to 83% of its oil and 47% of its gas requirement. We expect the prospects for natural
gas demand to get a further fillip based on the wide support for gas as one of the key Upside: 21%
options as a clean energy source. PLNG’s growth drivers include: (i) 15% increase in Amit Agarwal LNG imports and re-gasification capacity at Dahej from 15-17.5mn tonne/year in June 2019 (ii) to be enhanced by another 2mn tonne by end-FY23 at a cost of Rs23bn (on Research Analyst additional tanks, Jetty) (iii) the potential upside in utilization of its 5mn tonne per [email protected] annum Kochi LNG terminal once gas major GAIL starts the connecting Kochi- +91-22-6273 8145 Mangalore gas pipeline (expected by Q3FY20) that will help transport the RLNG from this facility to gas consumers across southern states, including Karnataka and Kerala. Key Data We also believe that the stock offers a favourable risk reward at CMP, as it trades close Current Shares O/S (mn) 1,500 to SD-1 on 5 year median PE of 14.2x. Mkt Cap (Rsbn/US$bn) 387/5.48 ● We estimate 14% CAGR in FY19-22E earnings based on 6% CAGR in overall RNLG volume growth- Dahej volume growth of 5% CAGR and Kochi volume to grow by 36% 52 Wk H / L (Rs) 302/203 CAGR over FY19-FY22E based on ramp up of capacity utilization from 10% to 25% over Daily Vol. (3M NSE Avg.) 3,845,084 FY19-FY22E ● Healthy free cash flows – FCCF in the range of Rs21.6bn to Rs30.6bn over FY19-22E to Initiating Coverage Initiating Share holding (%) 1QFY20 4QFY19 3QFY19 increase net cash from Rs30.5bn to Rs50.4bn over FY19-FY22E. This is post capex worth Rs23bn over FY19-22E Promoter 50.0 50.0 50.0 ● Our TP based on DCF valuation of Rs312 implies Sept 21E PE of 15.4x. This is based on Public 50.0 50.0 50.0 cash flow estimates over FY21-30E, terminal growth of 3%, ramp up in Dahej volume to Others - - - 19.5mn tonne by FY24E and Kochi utilization to 50% by FY25E and further to 75% from FY27E. The stock trades at 12.8x FY21E and 11.8x FY22E PE. Our TP implies a Sep 21E One Year Indexed Stock Performance PE of 15.4x, a 8.5% premium to the SD-1 on 5 year median PE of 14.2x. ● Risks include: (i) reduction in contracted off-take of RLNG by existing buyers if they are 130 unable to place the gas with downstream customers (ii) increase in global oil prices that 120 will increase the Brent crude- linked delivered cost of RLNG contracted with RasGas 110 (Qatar) and Gorgon (Australia) (iii) dramatic increase in cheaper domestic field gas output 100
from KG deepwater development underway by ONGC and Reliance Industries (RIL) that 90 could hurt demand for RLNG, especially in sensitive sectors like fertilizers and power (iv) 80 Lower-than-expected capacity utilization at Kochi and potential exposure to the high risk Sep-18 Nov-18 Jan-19 Mar-19 May-19 Jul-19 Sep-19 Tellurium LNG project. PETRONET LNG LTD Nifty 50
Y/E March (Rsmn) FY18 FY19 FY20E FY21E FY22E Price Performance (%) Revenues 305,986 383,954 363,545 447,914 481,540 EBITDA 33,124 32,935 40,801 43,609 45,001 1-M 6-M 1-Yr Consolidated Net Profit Adj 21,104 22,306 24,537 30,306 32,817 PLNG (3.3) 2.6 17.7 EV/FCF (x) 721 (455) 818 363 683 Nifty Index 3.7 (1.6) 4.6 EPS (Rs) 14.07 14.87 16.75 20.20 21.88 EPS gr (%) 22.5 5.7 12.6 20.6 8.3 Source: Bloomberg EBITDA Margin (%) 10.8 8.6 11.2 9.7 9.3 P/E (x) 18.3 17.3 15.4 12.8 11.8 EV/EBITDA (x) 10.8 10.8 8.7 8.2 7.9 Net Debt (cash)/Equity (x) (0.3) (0.3) (0.3) (0.4) (0.4) Pre-tax RoCE (%) 13.6 16.3 17.8 14.8 14.3 RoE (%) 23.5 22.3 23.0 26.4 26.2 Source: Company, Nirmal Bang Institutional Equities Research
Institutional Equities
Rating rationale Key drivers underpinning our rating rationale: Healthy demand growth in Indian natural gas demand Concomitant expansion in Indian gas transportation infrastructure by GAIL, Gujarat Petronet and Indian Oil Corp (IOC) to help move imported gas to bulk consumers and city gas distribution (CGD) networks being set up across India at an estimated aggregate cost of Rs700bn PLNG’s early mover advantage and market leadership in Indian LNG market (accounts for 40% of the gas supplied in India) PLNG’s competitive positioning close to India’s gas hub on the west region with a lower capital cost of Rs6600/tonne vs. new LNG terminals at Rs10,000-10,500/tonne Benefits of recent capacity expansion at Dahej and potential ramp up in Kochi terminal volume once the latter is hooked up to GAIL’s Kochi-Mangalore pipeline expected in 3QFY20 Healthy financials and attractive valuation: EPS growth at 14% CAGR over FY19-FY22 and FCFF of Rs21.6bn to Rs30.6bn and sustained returns – RoE 22.3% in FY19 to 26.2% in FY22E. Trades at 12.8x PE on FY21E and 11.8x FY22E. Our DCF based TP of Rs312 offers 21% upside from CMP. This implies Sept 21E PE of 15.4x and P/BV of 3.9x. Our worst case analysis assuming Kochi utilization rate gets capped at 30% implies a DCF value of Rs282, which still offers 8.4% upside. The stock offers a low risk entry point at CMP as it is trading at close to SD-1 on 5 year median PE of 14.2x. Gas consumption boom amidst limited domestic production to boost LNG demand We see healthy demand growth in natural gas as a competitive green energy source getting an added fillip from government of India’s long-term goal to increase the share of gas in the country’s energy basket from the current 6.2% to 15% over the next 15-20 years.
Exhibit 1: Current mix of fuel consumption across countries Region Oil% Natural Gas% Coal% Nuclear Energy% Hydro electric % Renewable % MTOE World 34.2 23.4 25.4 4.40 6.80 3.60 13,511 OECD 39.4 25.7 15.9 7.9 5.6 5.4 5,605 Non OECD 30.5 21.7 35.9 1.9 7.6 2.3 7,906 Asia Pacific 28.6 11.5 48.4 1.9 6.5 3 5,744 China 19.4 6.6 60.4 1.8 8.3 3.4 3,132 India 29.5 6.2 56.3 1.1 4.1 2.9 754 Bangladesh 22.7 69.4 7 - 0.6 0.3 33 Pakistan 36.1 43.3 8.8 2.2 8.7 1 81 Source: BP Statistical World Energy Review, 2018; MTOE – million tonne of oil equivalent
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Exhibit 2: Sector-wise share of total demand in India
22 16 19 5 6 5 13 11 10 13 15 17
21 25 20
28 26 28
FY17 FY20E FY23E
Fertiliser % Power % CGD % Refinery % Petrochemicals % Others %
Source: Crisil Research, Nirmal Bang Institutional Equities Research
Growth in pipeline infrastructure to link LNG import terminals to consumption points Prospects for growth in LNG imports to meet India’s growing gas demand will get an added boost based on supporting investments in cross country pipelines for transportation of imported gas to key consumption centres across India and meet the growing demand for gas across key segments – fertilizers, power, city gas, industries and others. Robust gas demand outlook led by CGD, fertilizers and power segments: The award of new CGD licenses across 138 geographic areas in 402 districts spread over 27 States and Union Territories, covering approx. 70% of India’s population by Indian upstream regulator PNGRB over the 9th and 10th rounds of bidding will likely lead to expansion of CGD networks across the country. This would lead to a 2.4x increase in the no. of CNG stations from 1,491 (as of 2017) to 5,069, 5.6x growth in domestic PNG connections from 3.6mn to 23.9m nos. and steel pipeline by 58,177 km over the next 10 years. The expansion of city gas infrastructure and its hook up with the national gas transportation grid (under GAIL and GSPL) as well as LNG import terminals supports a healthy outlook for long term growth in natural gas demand from the CGD segment. Industry and government estimates reveal that gas demand from CGD segment will likely rise from 26mmscmd to 33mmscmd over the next four years, implying close to 7% CAGR in this segment alone Demand from fertilizers is estimated to increase from 42.8mmsmcd to 53mmsmcd over the same period (5.5% CAGR)
Exhibit 3: Gas demand estimates across segments Inc in gas demand Inc in gas demand Gas consumers CAGR% 3 years mmscmd 3 years –Mn Tonne/yr of LNG FY19E# FY20E FY23E FY20-23E
Fertilizer 42.8 44.3 53.0 8.7 2.4 5.5% Power 40.9 42.3 38.8 (3.5) (1.0) -1.3% City Gas 25.5 26.4 33.2 6.8 1.9 6.8% Refineries 21.2 21.9 21.3 (0.6) (0.2) 0.2% Petchem 8.9 9.2 9.6 0.4 0.1 1.9% others Incl. losses 27.1 28.0 35.1 7.1 2.0 6.7% Total gas consumption 166.4 172.0 191.0 19.0 5.3 3.5% Source: Crisil Research, CEA, Nirmal Bang Institutional Equities Research; Notes: #Others include miscellaneous uses and losses/internal consumption; Others estimated as reconciled figure = TOTAL consumption estimate from PPAC less consumption in each segment
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Exhibit 4: Impact of revival of gas-based power plants on RLNG demand Gas -Power Inc in RLNG RLNG Utilization Gas demand RLNG Share Increase in RLNG Capacity Mn consumption % MMSCMD MMSCMD demand MMSCMD utilized MW Tonne/yr Mn Tonne/yr Base case 39.5 9837 44.3 23 0 0 6.4 Case 1 50 12441 56.0 34.6 11.7 3.25 9.6 Case 2 60 14929 67.2 45.8 22.9 6.37 12.7 CASE 3 75 18662 84.0 62.6 39.7 11.03 17.4 CASE 4 100 24882 112.0 90.6 67.7 18.81 25.2 Source: Nirmal Bang Institutional Equities Research; current gas consumption taken from petroleum ministry (PPAC) data and Dept. of Power (CEA) data on gas-based power operations for June/ July 2019 Demand from existing gas based power plants of 24,882MW capacity - currently underutilized due to gas shortage – is estimated to rise from current 44.3mmscmd at 39.5% plant load factor (PLF) to 56mmscmd assuming PLF of 50% and blended gas price of US$6/mmbtu. This implies 8% CAGR assuming this takes another five years. To put this in perspective, the potential revival of the estimated 15,045MW of idle gas-based power projects (vs. installed capacity of 24,882MW according to government data) is likely to boost gas demand by another 11.7-22.9mmsmcd assuming increase in PLF to 50%-60% from 39.5%. (The average annual PLF quoted in many government studies for gas based power plants is at ~23%; we have used a more recent figure to make a more realistic estimate of incremental demand from reviving gas-based power plants.) Demand for natural gas from other user segments in industries like steel, cement and other manufacturing units is also likely to get boost based on (a) gas getting widely accepted as a cleaner alternative to other fossil fuels that cause pollution, including coal and petroleum products. This process will get further momentum based on policy advocacy through bans imposed on polluting fuels by state agencies as well as through court orders. Delhi Pollution Control Board banned all polluting fuels in 2015 that has directed industries in Delhi/NCR to switch to single fuel mode – natural gas Supreme Court order has banned fuel oil and petcoke as industrial fuel in Delhi
Persistent dependence on imported LNG at 46% of Indian gas demand This is due to the limited domestic gas reserves in ageing fields of PSU oil giant ONGC that continue to decline and the lack of progress in developing new gas reserves. We expect the share of imported LNG to sustain at 46% of demand over the next five years. Our estimates indicate that the gas shortage is likely to persist even after adding new gas supplies from ONGC and Reliance from their KG deep water gas development projects. ONGC is expecting peak gas production of 15mmscmd from KG DW 98/2, with first gas likely by FY22 and Reliance is indicating potential peak production of 1bcf/day(27-28mmscmd) of gas by FY24 based on 2P reserves of 3.5TCF, according to plans underway in alliance with BP to develop its KG deep water gas field.
Exhibit 5: Domestic and RLNG consumption across sectors FY18 and FY23E (mmscmd) FY18 FY23E
domestic gas RLNG TOTAL domestic gas RLNG TOTAL CAGR
Fertilizer 18.6 21.5 40.1 25.5 27.5 53.0 5.7% Power 26.1 6.8 32.9 30.4 8.4 38.8 3.4% City Gas 12.8 10.8 23.6 18.2 15 33.2 7.1% Refineries 3.2 15.9 19.1 2.8 18.5 21.3 2.2% Petchem 1.7 9.1 10.8 1.5 8.1 9.6 -2.3% #Others incl. losses 24.5 11.1 35.6 24.6 10.5 35.1 -0.3% Total 86.9 75.2 162.1 103 88 191.0 3.3% LNG imports/Consumption % 46.4% 46.1% Source: CRISIL, PPAC Note: FY23E Sector consumption as per CRISIL estimates. #Others include miscellaneous uses and losses/internal consumption; PPAC’s aggregated net consumption data in xl files is based on gross production plus imported LNG. Actual consumption will be lower to the extent of losses and internal use which is reported as “others” by agencies like CRISIL. We have adjusted this aspect to reconcile gross consumption with figures reported by PPAC for past periods and CRISIL estimates.
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Exhibit 6: Major RLNG contracts signed by Indian companies Buyer Supplier Project Mn Tonne/yr Price linked to GAIL Cheneire Energy Sabina Pass 3.5 Henry Hub GAIL Gazprom Shtokman 2.5 Crude Oil /JCC GAIL Dominion Energy Cove point 2.3 Henry Hub Petronet Ras Gas Qatar 8.5 Brent Crude Petronet Exxon Gorgon 2.44 Brent Crude Petronet United LNG Main Pass 4 Henry Hub GSPC BG NA 1.25 NA Total 24.49 Source: Crisil Research, Nirmal Bang Institutional Equities Research LNG cost may not be too steep vs. price of gas delivered to west coast from KG Our calculations show that the price of KG gas at well head may not be less than US$7-8.5/mmbtu to give reasonable returns for these projects located in difficult fields - ultra deep waters operating under high temperature and pressures. Indian gas pricing formula provides for free pricing of gas from such complex fields subject to a cap of US$9.32 (for April-September 2019). Given that gas from coal bed methane projects (CBM) is being offered at above US$7/mmbtu, we believe that KG gas is likely to be offered at a well head price of around US$7-8.5/mmbtu. Please note Reliance in its recent call for bids to purchase its KG/DW gas is reported to have set the floor price for prospective bids at US$5-5.5/mmbtu, which in our view is partly to align with the weak spot LNG market and also to elicit interest from bulk users in the price sensitive fertilizer/power sectors. The remaining gas is likely to be sold at higher prices closer to the ceiling to price-taker segments, which should move the blended selling price closer to our estimate as above. This implies a delivered price of US$8.4/mmbtu to US$9.9/mmbtu (including pipeline tariff plus 18% GST on the tariff plus marketing margin) for KG gas transported to the western region to gas consumers on the HVJ, DVPL and DUPL networks who currently depend on RLNG imported at Dahej or Shell’s Hazira terminal at contract prices of cUS$8.5-9/mmbtu (ex-ship).
Exhibit 7: KG gas price delivered to west coast (US$/mmbtu) East -West pipeline Add GST @18% on Gas price delivered at KG well head price Marketing margin tariff tariff West coast 5.00 1.00 0.18 0.1-0.25 6.28-6.43 6.00 1.00 0.18 0.1-0.25 7.28-7.43 7.00 1.00 0.18 0.1-0.25 8.28-8.43 7.50 1.00 0.18 0.1-0.25 8.78-8.93 8.50 1.00 0.18 0.1-0.25 9.78-9.93 Source: NBIE
Admittedly, the KG gas could be priced cheaper on a blended basis if the well head price is reduced to US$5- 6/mmbtu for more than 50% of its customers to capture market share.
We believe this is unlikely to impact the viability of LNG imports for the following reasons: a) KG deep water gas projects may require well head prices >US$7-7.5/mmbtu to generate adequate returns on the capital cost of these projects b) In case the KG gas is priced at the lower end of the above range, customers in Andhra and along the east west pipeline may absorb most of the gas, leaving little surplus for customers on the west coast c) As supply of gas increases from KG and IOC’s Ennore terminal, it will result in latent demand getting converted to actual consumption on the ground by consumers in the southern states of AP and TN, including CGD networks, especially once the GAIL gas grid network expansion hooks up these gas supply sources to main gas consumption centres in these regions d) As a result, we believe that the gas consumption growth rate could exceed current estimates of 3.6%- 4.1% CAGR
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Competitive market leadership as India’s pioneer LNG import terminal operator PLNG enjoys the early mover advantage of setting up and expanding India’s first ever LNG import terminal at Dahej in Gujarat from its initial 5mn tonne to 17.5mn tonne over the last 15 years. As a result, PLNG is India’s market leader in LNG imports and regasification with 69% share in a 24mn tonne market valued at ~US$9.5-11bn (@US$8-9mmbtu gas price) The company’s Dahej terminal is located at one of the main gas hubs in India that is linked to GAIL’s DVPL and DUPL trunk gas pipelines. These two pipelines help transport the imported gas across key demand centres in Gujarat (among the top three gas consuming states), Maharashtra, Madhya Pradesh, Rajasthan and Uttar Pradesh. This is based on the fact that DVPL links up with the HVJ network, India’s first ever gas pipeline that was routed through the above states, initially to meet the demand for gas from bulk segments, fertilizer and power. Over the last two decades, this cross-country network has supported the development and robust growth in India’s third largest demand segment for natural gas, CGD with CNG stations and PNG infrastructure spread across 27 states. (Pl refer Exhibit 3 and Annexure 1) Volume growth from Dahej expansion and ramp up in Kochi operations: This includes a) The benefits of the 2.5mn tonne expansion at Dahej from 2QFY20 and b) The likely surge in volume handled at the Kochi terminal, which is currently underutilized at ~10% - with a potential 1.5x to 2x ramp up in volume over FY21-23E and 4x increase in volume by FY25E. The low utilization at Kochi is due to lack of infrastructure for gas transportation from the latter location. We understand that GAIL is likely to start the Kochi-Mangalore pipeline in 3QFY20, which will be hooked up with the Kochi terminal. This will help PLNG increase the volume of LNG imports at Kochi and evacuate RLNG from this terminal to customers like ONGC -MRPL Petrochemicals, Mangalore Fertilizers & Chemicals and eventually MRPL in the next six months. Based on company guidance and our own assessment, we expect the above three customers to boost Kochi volume by another 1mn tonne or 3.6mmscmd, which implies increase in utilization to 30% of Kochi’s capacity. We see healthy prospects for further demand growth over the next 5-10 years from the 7 CGD networks and other industrial users that have access to the Kochi-Mangalore pipeline. We also believe that further extension of this pipeline to Bengaluru as per the approved plan could create additional demand for LNG imported at Kochi from other CGD and industrial customers on this route. In our view, this could materialize (a) based on the existing approved plan (stalled due to public opposition to the stretch passing through Tamil Nadu) or (b) through an alternative route linking Mangalore directly with Bengaluru, which offers another possible option according to the company. This underpins our longer term assumptions (for our DCF model) on the increase in Kochi terminal’s operating rate from 30% to 50% FY23-FY25E and 75% by FY27E (vs. the company’s conservative guidance of 30% by FY22-23E and 40% utilization over the next 7-8 years based on new CGD projects). Risks/concerns:
1. PLNG’s lower capital cost to offset competition from new LNG terminals We believe that LNG marketing will be a regional business and competition at least over the next 5-10 years needs to be viewed on a regional basis. PLNG at Dahej will face competition from a combined capacity of 15mn tonne on the west coast - from existing LNG terminals at Hazira and Dhabhol (to the extent it operates) and the new one completed at Mundra. There are three more projects for an aggregate capacity of 14mn under construction – two in Gujarat and one in Rajasthan. Further, HPCL is planning a 5mn tonne/year LNG terminal project through its JV HPCL Shapoorji Energy Private Limited at Chhara port in Gujarat. This has received environmental clearance and is scheduled for completion by FY23E. As a result, the annual capacity in the western region will increase by 34mn tonne to 51.5mn tonne/year (including PLNG’s 17.5mn tonne over the next four years. Overall, India’s LNG terminal capacity will increase to 56.5mn tonne, including IOC’s Ennore facility completed in FY19.
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Exhibit 8: LNG import terminals and re-gasification projects in India Capacity Developers Terminal State (mn Tonne per annum) Petronet LNG Ltd. Dahej Gujarat 17.5 Petronet LNG Ltd. Kochi Kerala 5 Petronet LNG Ltd. Total 22.5 Royal Dutch Shell Hazira Gujarat 5 GAIL, NTPC Dabhol Maharashtra 5 IOCL Ennore Chennai 5 Total LNG capacity in operation 37.5
GSPC, Adani Mundra Gujarat 5 Total construction completed
H Energy Jaigarh Rajasthan 4 Adani Dhamra Bengal 5 Swan Energy Jafrabad Maharashtra 5 Total under construction 14
Total 56.5
Source: Crisil Research, Petronet LNG Ltd. June 19, Nirmal Bang Institutional Equities Research
Based on the overall gas demand and supply, we see room for growth in LNG imports from 22mn tonne to 26.3mn tonne over the next four years compared to the total capacity of 51.5mn tonne expected by the year FY23E. Although this is likely to create excess capacity, PLNG offers the most competitive asset based on its capital cost of Rs6,600/te FY23E( total assets less net cash/19.5mn tonne) vs that of competition estimated at Rs10,000-10,500/tonne. This is likely to sustain PLNG as a cost leader in terms of the most competitive regasification charges compared to the new entrants and hence any situation of excess capacity in PLNG’s markets is unlikely to hurt its volume or margin.
PLNG’s Kochi terminal also well placed to face competition from the east coast: Eventually, the terminals on the east coast may also be hooked up to the national gas grid and hence could potentially compete with PLNG. The limiting factor as in the case of KG gas will be the delivered cost of LNG. If we take the case of IOC’s Ennore LNG facility, the cost of RLNG from this location to any user in PLNG’s current market along HVJ and DVPL pipeline is likely to be more expensive than PLNG’s gas. This argument to some extent may get tempered if PNGRB were to have a single tariff for the whole network once all the major links are hooked up, which is likely in the next 7-10 years. Also, IOC’ Ennore and PLNG’s Kochi terminals may compete for common customers in the bulk segments located at mid points on their supply chain. This may hamper Kochi’s ramp up plans if IOC decides to settle for lower tariffs to match that of Kochi (Rs104/mmbtu that is likely to decline to around Rs65-70/mmbtu with the ramp up in volume) in order to capture market share. Even under this assumption, we believe that PLNG will be able to sustain a competitive edge based on its lower capital cost of Rs8,400/tonne vs IOC’s cost of Rs10,600/tonne for the Ennore project.
2. Sensitivity of fertilizer and power segments to gas price This is an issue that has plagued the gas sector and the growth of LNG in India until a few years ago. The steep increase in oil prices to US$100-120/bbl (FY11-FY14) made LNG imports attractive even at US$14- 17/mmbtu (US$80-100/boe) and boosted LNG spot and short term contracts in addition to the long term deals with Rasgas of Qatar. Past studies have shown that demand estimates for gas in fertilizer and power tend to be lower at higher prices of natural gas. This is because the pass-through of higher gas prices in subsidized urea fertilizer would entail an increase in government’s fertilizer subsidy bill. In the regulated power sector, this will raise power tariffs, which again causes problems in offtake of such power by state utilities. The situation is relatively better today in the fertilizer segment following the government’s introduction of gas price pooling mechanism to arrive at urea subsidies and still provide normative returns of 12-20% as per the retention pricing formula in vogue for urea producers. Under this, fertilizer companies that depend on RLNG are compensated for gas prices of up to US$14/mmbtu.
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In the case of power sector, the higher cost of gas will increase the cost of delivered power. There have been attempts in the past to offer a pooled gas price that sought to lower the impact of more expensive LNG with the lower price of domestic APM gas. This has not been very successful because of the persistent decline in production of domestic gas sold at APM price and hence increased the share of imported LNG in the basket. This and the reluctance of state utilities to buy power from gas-based projects linked to the grid at higher tariffs often led to lower utilization and resulted in several gas based assets facing a cash crunch and saddled with unused capacity. The highest variable cost of Rs5.4/kwh of power has rendered LNG as the least preferred choice among all alternative fuels for the power sector.
Exhibit 9: Variable cost of power from LNG Vs. other alternative fuels (Rs/Kwh)
Rs/Kwh 5.4
4 3.0-5.0 3.3
1.2- 3.0
Domestic Imported Domestic LNG LNG - Current Price Coal Natural Gas
Source: Crisil Research, Nirmal Bang Institutional Equities Research 3. Potential risk of regulations capping LNG margins by PNGRB – unlikely in our view The PNGRB had many years ago proposed to regulate the regas tariff charged by LNG importers, but did not pursue this as the industry requested that such a decision will hamper the development of the LNG import infrastructure at a time when the country was facing a gas shortage. Given that LNG is not sold directly in the B-C segment, the government or the regulator have not shown a perceived sense of the “need to protect consumer interest” – a key driver for any regulatory reforms in utilities in most countries, including India. It is possible that PLNG’s plans to enter retail sales of LNG as auto fuel for trucks and buses may attract such scrutiny as and when it becomes a sizable market and PLNG shows visible earnings from this activity similar to what CGD companies earn at present. This may take at least 3-5 years to be develop to such scales. The regas tariff as a proportion of the selling price of gas is only about 7-10% of the gas price and hence unlikely to raise the alarm, especially because PLNG’s EBITDA margin is still modest at 9-11% unlike the 25% plus margin earned by CGD companies. The sensitive industrial and bulk buyers among power and fertilizer companies may resist paying marketing margins. In our view, PLNG is likely to be in a position to recover any discount offered on marketing margins to such customers by charging a higher price from non-sensitive segments who can afford to pay. 4. EVs hurting CNG demand – robust growth in gas demand as a green fuel offsets this The CNG segment is unlikely to suffer as much as petrol and diesel once Electric Vehicles (EV) become popular and increase in numbers. We expect CNG vehicles, especially cars, and EVs to coexist and grow in tandem over the next 10-15 years with CNG growth likely to be front ended and EVs following with a lag and catching up over a 10-15 year period. Moreover, initially, we see EVs getting the momentum from public transport as a result of high cost of EV vehicles and charging infrastructure costs as well as access that is likely to deter the growth of private EVs unless there are massive government subsidies. Hence, CNG growth is unlikely to suffer at least over the next 10-15 years. In fact, given the massive Rs700bn in investments approved by PNGRB on CGD projects across the country, and policy support favouring gas as a clean green fuel, we see healthy growth rates in underlying demand for gas over the next few years.
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5. Potential fall in oil prices plus increase in gas prices – Policy advocacy/lower taxes to mitigate this This is a longer term concern that in our view the government policy on gas allocation and pricing and end users of gas must come to terms with. We expect the gas sector to be affected as follows: a) The price of oil itself could soften in periods of global demand slowdown as we witnessed today or due to excess production, especially among the OPECPLUS group. b) As we see increasing substitution of petrol and diesel by gas and EVs in the auto segment, the spreads and prices of petrol and diesel could fall. c) Meanwhile, gas prices could rise in response to increased demand for this cleaner alternative. We expect higher demand for gas on a global scale as a result of all industries switching from polluting fossil fuels to natural gas. d) For gas consumers in India, this means that the price of petroleum alternatives like petrol, diesel and naphtha (that are unlikely to be banned) could fall, while that of gas could rise. This could reduce the pricing power of CGD companies and also LNG importers and eventually put pressure on margins for the industry. However, this could be mitigated by (i) higher growth in gas demand and (ii) any differential taxation policy favouring gas as a fuel that is likely to be considered by the Indian government, which is betting on gas and EVs to reduce emissions and resultant pollution and meet the overall goals of reduction in India’s carbon footprint. 6. Tellurium investment proposal 7. We understand that the company is proceeding cautiously on the MOU to invest in a US$2.5bn equity stake in Tellurium Inc.’s Darwood LNG liquefaction project of 16mn tonne/year to be expanded to 27.6mn tonne/year. The project is to be set up by 2023 and is in the process of firming up sales agreements and financing. According to the latest MOU signed a few days ago during the recent US visit of Indian Prime Minister Narendra Modi, PLNG had agreed to buy up to 5mn tonne/year of LNG from the project in return for a 20% stake worth US$2.5bn. The company has clarified in an analyst call on September 23 that it shall seek to minimize all risks by (a) tying up back to back off-take contracts with buyers for the volume PLNG picks up from the Drawood LNG project (b) reducing its exposure to a maximum of 1-2mn tonne/year of the committed purchase of LNG from Tellurium and (c) keep its capital commitment between US$500mn to US$1bn by roping in its promoters GAIL, IOC, ONGC and BPCL as affiliates and co-investors in the project. The company said that it is seeking new sources of LNG supplies to replace the volume of 7.5mn tonne/year that will cease to be available once the RasGas contract expires in 2028. Management cited this as a key rationale for their interest in the Tellurium project. (Pl refer to the highlights of this call in the Annexure 6). We do not believe that this is a material risk for investors based on the above clarifications, much as any potential financial exposure to this project could pose some concerns based on the impact in the company’s balance sheet and cashflows. Our concerns are the following: Financial returns not visible: It requires (i) high margins of the order of US$2.5/mmbtu on the volume to be purchased from this project that it will import and distribute in India even if gets back to back offtake agreements and (ii) some visibility on share of profits from the investments on the LNG project to generate RoE of even 10% and the question is - why should PLNG take financial risk in an upstream project in a buyers’ market for LNG given the current surplus capacity and huge capacity addition visible over the next two–three years? We appreciate the merits of locking in LNG supplies for the longer term and the need to replace the RasGas volume. In our view, the company should be able to secure good deals for LNG supplies at a reasonable price for Indian consumers, without taking significant financial risk that the Tellurium deal entails.
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Financials Exhibit 10: Operating assumptions FY19 FY20E FY21E FY22E DAHEJ LNG TERMINAL
Dahej terminal Regasification Capacity Mn Tonne 15 15 17.5 17.5 Additional Capacity Mn Tonne - 2.5 0 0.5 Dahej Capacity Post expansion Mn Tonne 15 17.5 17.5 18 Dahej - LNG imports/throughput Mn Tonne 15.97 17.05 18.38 18.64 Dahej Capacity Utilized % 106% 97% 105% 105% Dahej - RLNG supplied -throughput TBTU -D 820 874 944 955 KOCHI LNG TERMINAL
Kochi Nameplate Capacity Mn Tonne 5 5 5 5 Additional Capacity Mn Tonne - 0 0 0 Kcohi Capacity Post expansion Mn Tonne 5 5 5 5 Kochi - LNG imports/throughput Mn Tonne 0.50 0.75 1.25 1.25 Kochi Capacity Utilized % 10.0% 15% 25% 25% Kochi -RLNG throughput TBTU - K 24.00 36 60.00 60.00 PLNG aggregate RLNG throughput TBTU – D+K 844 910 1004 1015 Financials/unit volume Revenue Rs/MMBTU 454.84 399.50 446.28 474.34 COST OF GAS Rs/MMBTU 407.71 346.64 395.00 421.63 COST OF GAS $/MMBTU 5.83 4.81 5.49 5.74 Blended Margin Rs/MMBTU 47.13 52.86 51.28 52.71 EBITDA Rs/MMBTU 39.01 44.84 43.45 44.33 Source: Nirmal Bang Institutional Equities Research Earnings CAGR of 13.6% based on volume CAGR of 7.8% over FY19-22E We estimate revenue CAGR of 6.4% on aggregate volume CAGR of 7.8% over FY19-22E. We expect blended margin of Rs51-53/mmbtu over our forecast period vs. FY19 margin of Rs47.13/mmbtu. Our margin estimates are based on 5% annual increase for Dahej and gradual downward adjustment for Kochi, which the company expects to do in line with increase in volume. These assumptions underpin our CAGR expectations of 10.9% in EBITDA and 13.6% in earnings over FY19-22E. Exhibit 11: Capital expenditure plan (Rsmn) Total Capex FY20E FY21E FY22E Rs Mn Current 2.5 Mn Tonne Expansion* Dahej - 290 - - Dahej additional storage tanks -2 Dahej 13,000 5,200 3,900 3,900 Dahej- 1 Jetty Dahej 10,000 4,000 3,000 3,000 Total Capex-Dahej 23,000 9,490 6,900 6,900
Source: Nirmal Bang Institutional Equities Research; *capitalized at Rs 3,770mn These estimates support a healthy return profile with RoE above 25% and RoIC of 13%. We expect the company to remain in net cash based on FCFF increasing from Rs21.6bn in FY19 to Rs30.8bn in FY20E and Rs30.6bn in FY22E. This is after Rs 23bn in capex on additional facilities being created in Dahej- two new storage tanks and one additional jetty.
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Valuation DCF based September 20E TP of Rs312 We are valuing PLNG based on our DCF model, estimating FCFF between FY21E (September 20E-March 21E to adjust valuations based on Sept 21E) and FY30E and estimating the terminal value of FCFF at the end of this period, assuming a terminal growth of 3% in line with our expectation of long-term rate of inflation. Based on this DCF model, we estimate the PV of FCFF at Rs207.5bn, PV of terminal value at Rs230bn, EV at Rs437.6bn and equity value at Rs468bn. This underpins our TP of Rs312 for September FY21E. Exhibit 12: DCF valuation summary WACC calculation Valuation parameters Risk free rate % 6.5 WACC % 10.8 Market return % 11.5 Terminal Multiple 4.6 Beta of the Stock 0.8 Terminal growth % 3 Terminal value Rs Mn 6,39,414 PV of terminal value Rs Mn 2,30,078 PV of FCFF Rs Mn 2,07,517
Enterprise Value Rs Mn 4,37,595 Net Debt Rs Mn (30,518) Equity Value Rs Mn 4,68,112 Shares outstanding Mn 1,500 Equity value Rs per share 312 CMP (Rs) 258 Upside % 21 Source: Company, Nirmal Bang Institutional Equities Research If we value PLNG based on its 5 year median PE of 14.2x on September 21E EPS of Rs21.04, it is worth Rs299, which implies a 15.9% upside from CMP The stock also offers reasonable downside protection considering it is trading close to the SD-1 on 5 year median PE It offers FCFF yield of 8.67%/8.58% (FCFF to EV) on FY21E/22E Based on these aspects, we believe that the following risks are priced in at CMP: the lingering concerns on the Tellurium deal if any and the risk of being forced to take on more expensive LNG supply contracts, once the RasGas contract ends in 2028 (we are valuing it on DCF over FY20-30 and terminal growth of 3% thereafter) We believe that the low risk business model based on back to back off-take arrangements limits market risk as all costs are pass-through based a 16% IRR framework it follows to negotiate margins with its buyers (off- takers). The downside to volume is also limited to the extent that off-takers are unable to sell due to extraneous factors or the bulk buyers in the fertilizer or power sectors seek to cut their volume. We expect the outlook for gas demand to improve over the next 1-2 years. This and the visibility on volume growth - including the 1.5-2x ramp up in Kochi volume over FY19-23E - and the steady annuity nature of its earnings gives comfort on the prospects for sustained free cash flow generation.
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Exhibit 13: DCF model assumptions and cash flows FY20 *FY21E FY22E FY23E FY24E FY25E FY26E FY27E FY28E FY29E FY30E
LNG Volumes - MMBTU Dahej 874.00 943.66 955.17 970.62 999.38 1,001.44 999.38 1,001.44 999.38 1,001.44 999.38 LNG Volumes - MMBTU Kochi 36.00 60.00 60.00 72.00 72.00 120.00 144.00 180.00 180.00 180.00 180.00 LNG Total Volumes - MMBTU 910.00 1,003.66 1,015.17 1,042.62 1,071.38 1,121.44 1,143.38 1,181.44 1,179.38 1,181.44 1,179.38 Blended Margin Rs/MMBTU 52.86 51.28 52.71 54.28 55.85 58.65 61.01 63.55 65.66 67.85 70.15 Net Revenue Rs Mn 3,63,545 4,47,914 4,81,540 5,24,573 5,60,996 6,21,877 6,70,533 7,32,761 7,65,261 7,95,703 8,19,501 Gross contribution Rs Mn 48,103 51,464 53,515 56,596 59,834 65,770 69,761 75,078 77,436 80,163 82,735 Operating cost Rs Mn 3,22,744 4,04,305 4,36,539 4,77,205 5,11,165 5,66,950 6,12,527 6,70,427 7,01,641 7,30,520 7,53,009 EBITDA Rs Mn 40,801 43,609 45,001 47,368 49,831 54,927 58,007 62,335 63,619 65,183 66,492 EBIT Rs Mn 33,064 37,539 39,373 41,608 44,017 49,086 52,085 56,304 57,467 58,903 60,080 EBIT*(1-T) Rs Mn 24,335 27,629 28,978 30,623 32,397 36,127 38,334 41,440 42,296 43,352 44,219 Associates Income Rs Mn 676 676 676 676 676 676 676 676 676 676 676 Add Depreciation Rs Mn 7,737 6,070 5,628 5,761 5,814 5,841 5,922 6,030 6,152 6,280 6,412 Net Operating Profit after Tax Rs Mn 32,748 34,375 35,283 37,060 38,887 42,645 44,933 48,147 49,124 50,309 51,307 (Increase)/Decrease in working Capital Rs Mn (1,638) 1,173 129 (722) (357) 197 (223) (385) (113) (25) (122) Capex Rs Mn (10,578) (8,400) (8,900) (3,000) (3,000) (3,000) (3,000) (3,000) (3,000) (3,000) (3,000) Free Cash Flow Rs Mn 20,532 *13,574 26,512 33,339 35,529 39,841 41,710 44,761 46,011 47,284 48,186 Present Value of future cash flows Rs Mn 20,532 *12,898 21,610 24,534 23,606 23,899 22,589 21,886 20,311 18,845 17,338 Source: Nirmal Bang Institutional Equities Research; Notes to DCF assumptions: * the FCFF and PV arre adjusted for half year September 20-March 21E to adjust our DCF valuatiuon as on September 20E. Full year FCFF for FY21E is Rs27148mn.
Implied EV/E and PE on TP and how it compares with benchmarks: Our DCF-based TP implies FY21E PE of 15.4x, EV/E of 10x and P/BV of 3.9x. The implied PE is 8.5% above the 5-year median PE of 14.2x. This compares with Indian peer group average of 10.6x on FY22E.
Sensitivity and impact analysis We have analyzed the impact of changes in WACC and terminal assumptions on our TP estimate.
Exhibit 14: Impact of terminal growth/WACC on DCF model (Equity Value per share in Rs) WACC Base case Base case Base case
(%) Terminal Growth (TG) 3% TG less 1% = 2% TG + 1% = 4% Base case WACC 10.8 312 293 336 Base case WACC 11.8 292 274 314 + 1% Base case WACC 9.8 333 312 359 -1% Source: Company, Nirmal Bang Institutional Equities Research Exhibit 15: Impact of Kochi utilization on PLNG valuation Kochi utilization DCf value FY21E EPS FY22E EPS Upside % from
# post FY25 Rs/sh Rs Rs CMP Base case 60%-75% 312 20.20 21.88 21 case 1 ( FY25-FY30) 50% 296 20.20 21.88 13.9 case 2 (FY23-FY30) 30% 282 20.20 21.88 8.4 case 3 (FY21-FY30) 15% 268 18.50 21.06 3.3 Blue sky case from FY27-30 100% 327 20.20 21.88 25.9 Source: Company, Nirmal Bang Institutional Equities Research # Note: Base case- Kochi utilization rises from 15% to 25% in FY21, to 30% in FY23, 50% in FY25, 60% in FY26 and 75% from FY27
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Exhibit 16: Sensitivity analysis on gross margins and gas volumes DCF value FY20E FY21E FY22E Rs/sh
Base case EPS (Rs) 16.75 20.20 21.88 312 Changed EPS/DCF value Rs/sh 14.39 17.68 19.25 275 10% Hit on Gross Impact on EPS/ DCF value % Margins -14.1 -12.5 -12.0 -11.9 +/(-) Changed EPS/DCF value Rs/sh 14.75 18.06 19.67 282 10% Hit on gas volumes Impact on EPS/ DCF value % -12.0 -10.6 -10.1 -9.6 +/(-) Source: Company, Nirmal Bang Institutional Equities Research
Exhibit 17: Five year median PE band trend
Median P/E = 14.2
Source: Company, Nirmal Bang Institutional Equities Research
Exhibit 18: Domestic Peer comparison Revenue Mn Net Profit Mn EPS Rs/Sh PE (x)
CMP Mkt.cap Stock/rating FY20E FY21E FY22E FY20E FY21E FY22E FY21E FY22E FY21E FY22E Rs $bn Petronet LNG 261 5.5 3,63,545 4,47,914 4,47,914 25,121 30,306 32,817 20.20 21.88 12.9 11.9 (B) GAIL India Ltd 134 8.6 7,54,407 7,85,768 7,88,925 65,183 68,875 69,411 15.73 16.73 8.5 8.0 (NR)
HPCL (S) 306 6.6 27,40,281 29,57,692 30,87,968 49,519 52,491 53,170 40.05 41.05 7.6 7.4 BPCL (A) 470 14.4 31,84,674 34,38,384 37,41,208 95,136 1,00,875 1,02,842 51.29 52.29 9.2 9.0 IGL (A) 347 3.4 73,334 84,248 98,458 10,855 13,323 16,244 19.03 23.21 18.2 14.9 MGL (S) 917 1.3 33,727 36,991 39,459 6,039 6,674 7,270 67.56 73.60 13.6 12.5 Average 35.64 38.13 11.7 10.6
Source: Company, Nirmal Bang Institutional Equities Research; B-Buy, S-Sell, A-Accumulate, NR- Not rated
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ANNEXURE 1 Exhibit 19: Gas Grid Map
Annexure 2
Natural gas overview Natural gas when burned releases up to 50% less CO2 than coal and 20-30% less than oil, and when used in power generation, it emits as much as 50% less CO2 than coal, according to IEA data. The global transition to clean energy makes natural gas a clean energy alternative.
Exhibit 20: Natural gas vs. other fuels as a cleaner fuel fuel Emissions LPG Diesel Gas CO2 (Kg / MMBTU) 61.71 70.22 53.07 N2O (g / MMBTU) 0.6 0.6 0.1 Methane (Kg / MMBTU) 3 3 1 Source: USEPA, Nirmal Bang Institutional Research Four basic forms of natural gas: Liquefied Natural Gas (LNG) - Natural gas liquefied at (Minus) 161 degree celsius is used as transportation fuel for road and marine transport. LNG is also being considered for railway transport in its liquid form after a successful experimental run with CNG conducted on 21 trains. Trains running on CNG can result in 8-11% savings against diesel but the gas storage cylinders are as large as 1/3rd of a coach. LNG is preferred over CNG as it occupies less storage space and offers higher mileage for the same quantity of fuel. Re-gasified Liquefied Natural Gas (RLNG) - Imported LNG is re-gasified before transporting to consumers through pipelines and used as fuel, feedstock and raw material. The re-gasified LNG is the same as the gas produced in offshore and onshore oil & gas fields – either associated or free. Please note that irrespective of the source, the gas produced in fields or LNG may initially contain mainly lean methane gas or contain higher hydrocarbon gas fractions – ethane, propane or butane that can be extracted and used as petrochemical feedstock offering higher value. Compressed Natural Gas (CNG) – Natural gas compressed to a pressure of 200-250 kg/cm2 used as fuel for transportation.
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Piped Natural Gas (PNG) – Natural gas distributed through a pipeline network to the domestic sector for cooking and heating/cooling applications. India is the fourth largest importer of LNG after Japan, China and Korea, and imported 26.11bcm in FY18, up 6.6% yoy in FY18. Government has allowed 100% FDI in the natural gas segment of the energy sector to reduce its dependence on imported crude oil. Prime Minister Narendra Modi has set a target to reduce dependency on imported oil by 10% by 2022. India is the third largest energy consumer in the world after US and China. It is expected that India will increase its share in global energy basket but not all the increase in demand will be satisfied from traditional fuels; share of natural gas for India is expected to go up from 6% to 15% in the coming years. Exhibit 21: Current mix of fuel consumption across countries Region Oil% Natural Gas% Coal% Nuclear Energy% Hydro Electric % Renewable % MTOE World 34.2 23.4 25.4 4.40 6.80 3.60 13,511 OECD 39.4 25.7 15.9 7.9 5.6 5.4 5,605 Non OECD 30.5 21.7 35.9 1.9 7.6 2.3 7,906 Asia Pacific 28.6 11.5 48.4 1.9 6.5 3 5,744 China 19.4 6.6 60.4 1.8 8.3 3.4 3,132 India 29.5 6.2 56.3 1.1 4.1 2.9 754 Bangladesh 22.7 69.4 7 - 0.6 0.3 33 Pakistan 36.1 43.3 8.8 2.2 8.7 1 81 Source: BP Statistical World Energy Review, 2018; MTOE – million tonne of oil equivalent
Annexure 3 – LNG Overview
LNG LNG is natural gas in liquid form by cooling the gas to minus 161 degree celsius. This is done for easier transportation of gas from one region to another where pipeline connectivity is not viable. The conversion of natural gas into LNG reduces its volume by 600 times. Exhibit 22: LNG chain
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Exhibit 23: LNG liquefaction process
Exhibit 24: LNG regasification process
LNG supply is expected to increase in coming years as a result of the increase in global LNG receiving terminals and liquefaction capacity.
Exhibit 25: LNG supply across regions Mn Tonne 2017 2018 Change % Asia-Pacific 127.9 136.5 6.72 Middle East 90.5 94 3.87 Africa 41.5 40.6 -2.17 N. America 23.7 33.3 40.51 S. America 4.1 3.6 -12.20 Europe 4.3 12 179.07 Total 292 320 9.59 Source: Petronet Annual Report 2019
Exhibit 26: Major additions in LNG global supply CY17-18 Mn Tonne 2017 2018 Change % Australia 59.37 71.59 20.58 USA 14.54 22.43 54.26 Russia 11.66 19.65 68.52 Total 85.57 113.67 32.84 Source: Petronet Annual Report 2019
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Exhibit 27: Global liquefaction capacity additions forecast Mn Tonne/yr 2013-18 2019-23 Australia 59 4 Africa 17 5 APAC (Excl. Australia) 30 8 Europe 0 0 US 32 47 Others 0 15 Total 138 79 Source: Crisil Research, Nirmal Bang Institutional Equities Research
As of February 2019, global LNG re-gasification capacity stood at 824 Mn Tonne per year across 36 markets. Global LNG regasification capacity is estimated to increase by another 129.7 Mn Tonne per year.
By 2024, India’s re-gasification capacity is expected to increase to ~56.5Mn Tonne in India, aided by the expansion projects mentioned in Exhibit 8
Exhibit 28: Receiving terminal capacity additions Thailand added 1.5 Mn Tonne at its Map Ta Phut Terminal in January 2019 129.7 Mn Tonne per year of new re-gasification capacity is under construction including- A. Seventeen new onshore terminals B. Twelve FSRU's (Floating, Storage and Re-gasification units) C. Thirteen expansion projects to existing receiving terminals D. Six under construction projects expected to be added to Russia, Bahrain, Philippines, El Salvador, Ghana, and Croatia E. China has nine terminals under construction, along with eight expansion projects F. India has five new terminal projects and an expansion project under construction G. Brazil has two forthcoming FSRU projects in development H. Terminal construction and re-gasification capacity expansion projects are underway in Jamaica, Bangladesh, Belgium, South Korea, Japan, Kuwait, Poland, Indonesia, United States (Puerto Rico), and Thailand I. An FSRU, the Golar Freeze, arrived at Old Harbour in Jamaica in December 2018, with operations expected to begin in early 2019 Source: IGU Annual Report 2019, Nirmal Bang Institutional Equities Research Exhibit 29: LNG import forecast Mn Tonne/yr 2019 2020 2025 2030 CAGR 2020-30 % China 60 65 80 97 4 India 24 26 27 43 5 Other Asia 25 31 68 103 13 Japan, South Korea and Taiwan 142 141 139 143 0 Europe 77 93 83 98 2 North & South America 18 19 25 30 4 Middle East & North Africa 10 10 17 21 7 Sub Saharan Africa 0 0 2 6 7 Other 0 0 24 12 -5 Total 356 385 465 553 4 Source: Petronet Annual Report 2019 Exhibit 30: Country-wise share of LNG exports in 2018 Country % Qatar 25 Australia 21 US 7 Russia 6 Others 41 Total 100 Source: Petronet Annual Report 2019
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Exhibit 31: Trend in FID for LNG projects CY16-18 Year Project Mn Tonne 2016 4 8.96 2017 2 4.34 2018 4 21.5 2019 14 43.0 Source: Petronet Annual Report 2019
Exhibit 32: Trend in FID for LNG projects FID in 2019 Liquefaction Train Mn Tonne Expected FID Date Rovuma LNG T1 7.6 Nov-19 Rovuma LNG T2 7.6 Nov-19 Sabine Pass LNG T6 4.5 July-19 Mozambique LNG 6.44 May-19 T1 (Area 1) Mozambique LNG 6.44 May-19 T2 (Area 1) Calcasieu Pass 1.11 Feb-19 LNG T11-12 Calcasieu Pass 1.11 Feb-19 LNG T1-2 Calcasieu Pass 1.11 Feb-19 LNG T13-14 Calcasieu Pass 1.11 Feb-19 LNG T15-16 Calcasieu Pass 1.11 Feb-19 LNG T17-18 Calcasieu Pass 1.11 Feb-19 LNG T3-4 Calcasieu Pass 1.11 Feb-19 LNG T5-6 Calcasieu Pass 1.11 Feb-19 LNG T7-8 Calcasieu Pass 1.11 Feb-19 LNG T9-10 Total 43.00 Source: Petronet Annual Report 2019
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Annexure -4 Indian Natural Gas overview
Indian natural gas market Exhibit 33: Natural gas demand in India
In MMSCMD
300
252
250
219
194
190
200 183
168
167
152
144 144
139 139 130
150 130
116 116
100
50
0 FY15 FY16 FY17 FY18 FY19E FY20E FY21E FY22E Normalized Bull Source: PNGRB, PPAC Domestic natural production has been on a decline from 46,453MMSCM in FY12 to 30,056MMSCM in FY19. As a result, there is an increase in the share of LNG imports in India’s natural gas supply from 28% in FY12 to 47% in FY19. With the inclination of government towards the usage of natural gas, a cleaner fuel, the demand for natural gas fuelled by CGD and fertiliser sector is expected to be on the rise at 3.6-4.1% CAGR over the next five years. Dependence on LNG is expected to continue at the same rate of 46-50% despite the expected improvement in domestic gas supply mainly coming from CGD (Industrial) and Fertilizer given their high priority status in domestic gas supply and favourable government policy. Exhibit 34: Existing natural gas pipelines Name of Entity Name of pipeline Length in KM % share Capacity (MMSCMD) HVJ-GREP-DVPL 4,554 27.9 53 GREP DVPL Upgradation 1,385 8.5 54 CJHPL 310 1.9 5 DUPL-DPPL 928 5.7 19.9 DBNPL 852 5.2 31 DHABOL-BANGALORE PIPELINE 1,116 6.8 16 GAIL KKBMPL 48 0.3 6 Tripura 60 0.4 2.3 Rajasthan 151 0.9 2.35 Gujarat# 685 4.2 15.42 Mumbai 131 0.8 7.03 KG Basin (including RLNG+RIL) 884 5.4 16 Cauvery Basin 306 1.9 8.66 Reliance East- West Pipeline (RGTIL) 1,480 9.1 80 Reliance Shahdol-Phulpur Pipeline (RGPL) 304 1.9 3.5 GSPL GSPL network including spur lines 2,692 16.5 43 AGCL/DNPL Assam Regional Network 297 1.8 3.24 IOCL Dadri-Panipat 140 0.9 10 Total 16,324 100.0 356 Source: PPAC Monthly Reckoner June, 2019 #GAIL's Ahmedabad, Bharuch and Vadodara pipelines have been clubbed under Gujarat network Uran -Trombay of ONGC is for internal consumption (24km);
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Exhibit 35: Trend of natural gas consumption in India
70,000 50% 45% 60,000 40% 50,000 35%
40,000 30% 25% 30,000 20% 20,000 15% 10% 10,000 5% - 0% FY12 FY13 FY14 FY15 FY16 FY17 FY18 FY19* LNG import MMSCM 17,997 17,614 17,801 18,607 21,388 24,849 27,439 28,692 Net Production MMSCM 46,453 39,753 34,574 32,693 31,129 30,848 31,731 32,056 Total Consumption MMSCM 64,451 57,367 52,375 51,300 52,517 55,697 59,170 60,747 Share of LNG imports% (RHS) 28% 31% 34% 36% 41% 45% 46% 47%
Source: PPAC, Nirmal Bang Institutional Equities Research; Note: Internal consumption is included
At present, there are 31 urea units in the country of which 28 units are gas-based and connected to natural gas grid while the remaining three units use naphtha as feedstock for the purpose of manufacturing urea. Daily requirement of gas for these manufacturing units is 40.8MMSCMD (in FY19), although less than 50% (17MMSCMD) of the requirement is supplied to the units due to limited availability of domestic natural gas. The government policy gives preferential allocation of cheap domestic gas at government price (APM gas) for CNG and PNG for households and has provided an upper limit of 31.5MMSCMD to the fertiliser sector. Hence, the gap is filled by imported LNG.
Exhibit 36: Gas based urea plants pipeline
Type Plant State Capacity MTPA Connectivity Expected Greenfield/Expansion CFCL-III Rajasthan 1.3 Commissioned Jan 19 Conversion MCFL-Mangalore Karnataka 0.4 Expected by Sept 19 Conversion SPIC-Tuticorin Tamil Nadu 0.6 Fiscal 2021/2022 Conversion MFL-Manali Tamil Nadu 0.5 Fiscal 2020 Revival Barauni Bihar 1.2 Connected Revival Gorakhpur UP 1.2 Connected Revival Sindri Jharkhand 1.2 Fiscal 2022 Total 6.5 Source: Crisil Research, Nirmal Bang Institutional Equities Research
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Indian Natural gas pricing:
Exhibit 37: Contracted LNG price and spot LNG price
13.7
10.9 9.8 9.95 11.3 9.05 7.9 7 8.9 8 7.4 6.75 6.6 6.25
FY15 FY16 FY17 FY18 FY19 FY20E FY21E
Contracted LNG Price $/MMBTU Spot LNG Price $/MMBTU Source: Crisil Research, Nirmal Bang Institutional Equities Research
Exhibit 38: Trend in domestic natural gas price and gas price ceiling for HT/DW fields
9.32
7.67 6.78 6.61 6.3 5.56 5.05 5.3 4.66 3.82 3.36 3.69 3.06 2.89 3.06
2.5 2.48
Mar 15 Mar
-
H1FY16 H2FY16 H1FY17 H2FY17 H1FY18 H2FY18 H1FY19 H2FY19 H1FY20 Nov Domestic Natural Gas Price (US$/MMBTU) Gas Price Ceiling (US$/MMBTU) Source: PPAC, Nirmal Bang Institutional Equities Research; note: HT- High temparature/DW- Deep water
Exhibit 39: PLNG gross realization
11.97
6.90 6.21 5.31 4.79
FY15 FY16 FY17 FY18 FY19
PLNG Ex Terminal Gross Realization Excluding Taxes (US$/MMBTU) Source: Company, Nirmal Bang Institutional Equities Research
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Exhibit 40: Domestic gas supply and LNG affordability across sectors Priority In Domestic Gas Supply LNG Affordability CNG & Domestic 100% demand met through domestic gas Significant savings compared to alternate fuels such as Petrol, LPG PNG Fertilizer Second in line after CNG & Domestic PNG segment Fuel cost pass through permits 100% LNG usage Low cost of coal/ renewable, however LNG subsidy support is Power It is third in the priority list for domestic gas supply available No incremental supply is expected. Existing supply diverted to core Refining & Petchem LNG cheaper than Naptha which is the primary competition sectors CGD- Small No incremental supply is expected. Existing supply diverted to core Spot LNG is price competitive vs. furnace oil Industries sectors Source: Crisil Research, Nirmal Bang Institutional Equities Research
City gas network With the Government’s focus to expand natural gas grid with the help of PNGRB, more cities will get access to natural gas. Therefore, the outlook for CNG used in transportation and PNG used in households/industries will get better. Currently, there are 3.4mn CNG vehicles, 1,730 no. of CNG stations and 5.1mn PNG connections in the country (June 2019). PNGRB’s focus is to take this number to 3,578 no. of CNG stations and 20mn PNG connections by 2029.
Exhibit 41: Details of CNG stations and vehicles across states in India State Company name No. of CNG stations No. of CNG vehicles Bhagyanagar Gas Ltd, Godavari Gas Pvt.Ltd., Megha Engineering & Andhra Pradesh 44 19,794 Infrastructures Ltd. Bihar GAIL (India) Ltd. 2 0 Chandigarh Indian Oil-Adani Gas Pvt. Ltd. 5 7,500 Daman and Diu Indian Oil-Adani Gas Pvt. Ltd. 3 1,000 Delhi/NCR Indraprastha Gas Ltd . 482 10,65,603 Sabarmati Gas Ltd, Gujarat Gas Ltd, Adani Gas Ltd, Vadodara Gas Gujarat & Dadra Nagar Haveli Ltd,Hindustan Petroleum Corporation Ltd, Charotar Gas Sahakari 548 9,25,286 Mandal Ltd,IRM Energy Ltd. Haryana City Gas Distribution Ltd, Adani Gas Limited,GAIL Gas Haryana 66 1,59,783 Ltd.,Indraprastha Gas Ltd. , Indian Oil-Adani Gas Pvt. Ltd. Karnataka Gail Gas Ltd., Megha Engineering & Infrastructures Ltd. 13 1,093 Kerala Indian Oil-Adani Gas Pvt. Ltd. 4 900 Madhya Pradesh Aavantika Gas Ltd, GAIL Gas Ltd 43 35,996 Mahanagar Gas Ltd, Maharashtra Natural Gas Ltd, Gujarat Gas Maharashtra 313 9,22,439 Limited,Mahesh Gas Ltd, Unison Enviro Private Limited Odisha GAIL (India) Ltd. 6 2,640 Punjab IRM Energy Pvt. Ltd., GSPL 6 2,202 Rajasthan Rajasthan State Gas Limited 5 8,438
Telangana Bhagyanagar Gas Ltd. 45 24,980 Tripura Tripura Natural Gas Co. Ltd 9 11,688 GAIL Gas Ltd, Sanwariya Gas Ltd, Green Gas Ltd, Central U.P. Gas Ltd, Uttar Pradesh Siti Energy Ltd, Adani Gas Ltd, Indian Oil-Adani Gas Pvt. Ltd.,Torrent 128 1,54,091 Gas Pvt Ltd., GAIL (India) Ltd. Uttarakhand Indian Oil-Adani Gas Pvt. Ltd. 1 100 West Bengal Great Eastern Energy Corporation Ltd. 7 3,756 All India - 1,730 33,47,289 Source: PPAC Monthly Reckoner June, 2019
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Exhibit 42: Trend in CNG sales across key states in India CNG sales in India (TMT) No. of Cos. FY19 FY15 FY16 FY17 FY18 FY19P No. of CNG Vehicles AP/Telangana 3 26 27 29 32 31 44,774 Chandigarh 1 - - 0 5 15 7,500 Daman and Diu 1 - - 1 2 1,000
Delhi/NCR 1 717 738 804 1016 1144 10,65,603 Gujarat & Dadra Nagar Haveli 7 476 503 546 612 662 9,25,286 Haryana 5 72 75 109 144 179 1,59,783 Karnataka 2 - - 0 0 0.3 1,093 Kerala 1 - - - - - 900 MP 2 17 19 22 25 31 35,996 Maharashtra 5 531 565 593 630 702 9,22,439 Odisha 1 - - - 0 1 2,640 Punjab 2 - - - 1 2,202
Rajasthan 1 3 4 4 5 7 8,438 Tripura 1 10 11 12 13 15 11,688 UP 9 185 212 245 153 282 1,54,091 Uttarakhand 1 - - - - 0.1 100 West Bengal 1 1 1 2 2 3 3,756 Total 2038 2155 2366 2638 3075 33,47,289 Source: Ministry of Petroleum and Natural Gas June 2019 P=Provisional
Exhibit 43: Details of PNG customers (nos.) across segments in various states in India PNG connections State Geographical area/city covered Entity Domestic Commercial Industrial Vijaywada Bhagyanagar Gas Limited 5,658 10 0 Kakinada Bhagyanagar Gas Limited 20,573 85 1 Andhra West /East Godavari Godavari Gas Pvt.Ltd. 322 6 0 Pradesh Megha Engineering Krishna District excl. area already authorized 2,882 19 3 &Infrastructures Ltd. Total 29,435 120 4
Assam Gas Company Assam Upper Assam GA 32,469 1,074 402 Limited Total 32,469 1,074 402
Bihar Patna district GAIL (India) Ltd. 0 0 0 Total 0 0 0
Indian Oil-Adani Gas Pvt. Chandigarh Chandigarh GA 9,598 0 1 Ltd. Total 9,598 0 1
Indian Oil-Adani Gas Pvt. Daman and Diu Daman 506 22 9 Ltd. Total 506 22 9
Delhi/NCR National Capital Territory of Delhi (including Noida & Ghaziabad) Indraprastha Gas Limited 10,92,223 2,561 1,751
Total 10,92,223 2,561 1,751
Gujarat and Dadra & Nagar Ahmedabad City & Daskroi area excl. Already authorized area Adani Gas Ltd. 3,73,525 2,490 821 Haveli Vadodara rural Adani Gas Ltd. 561 1 90 Charotar Gas Sahakari Anand area incl. Kanjari and Vadtal villages GA 27,994 641 118 Mandali Ltd
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Surat-Bharuch-Ankleswar GA, Nadiad GA, Navsari GA, Rajkot GA, Surendranagar GA, Hazira GA, Valsad GA, Jamnagar GA, Bhavnagar GA, Kutch (West) GA, Amreli District GA, Dahej Vagra Taluka GA, Dahod Gujarat Gas Limited 13,51,340 12,275 3,523 District GA, Panchmahal District GA, Anand (excluding area authorised) district GA
Ahmedabad district GA HPCL (Only CNG) 0 0 0 Banaskantha / Palanpur district IRM Energy Pvt. Ltd. 9,250 31 4
Gandhinagar, Mehsana & Sabarkantha GA Sabarmati Gas Ltd. 1,51,309 725 326 Patan district GA Sabarmati Gas Ltd. 3,629 0 0 Vadodara Gas Limited (Previously Vadodara Vadodara District 1,21,273 2,538 0 Mahanagar Seva Sadan) VMSS Dadra & Nagar Haveli GA Gujarat Gas Limited 2,676 18 15 Total 20,41,557 18,719 4,897
Haryana Faridabad district Adani Gas Limited 61,468 115 281 Sonipat district Gail Gas Limited 8,252 27 87 Haryana City Gas Gurugram district 17,801 133 68 Distribution Ltd Indian Oil-Adani Gas Pvt. Panipat district 1,484 1 5 Ltd. Gurugram district Indraprastha Gas Limited 6,209 5 1 Rewari district Indraprastha Gas Limited 3,679 0 19 Nuh and Palwal districts Adani Gas Limited 0 0 25 Total 98,893 281 486
Karnataka Bengaluru rural and urban district GA Gail Gas Ltd. 11,076 84 61 Megha Engineering Tumkur district GA 3,676 25 9 &Infrastructures Ltd. Megha Engineering Belgaum district GA 2,108 15 5 &Infrastructures Ltd. Indian Oil-Adani Gas Pvt. Dharwad district 0 0 0 Ltd. Total 16,860 124 75
Indian Oil-Adani Gas Pvt. Kerala Ernakulam district 1,032 10 1 Ltd. Total 1,032 10 1
Madhya Indore GA incl. Ujjian city Aavantika Gas 37,967 77 157 Pradesh Gwalior GA Aavantika Gas 13,236 36 2 4,907 20 30 Dewas Gail Gas Ltd.
Vijaipur Gail Gas Ltd. 0 0 0 Total 56,110 133 189
Pune City including Pimpri Chinchwad along with adjoining contiguous Maharashtra Natural Gas Maharashtra 1,69,407 302 185 areas of Hinjewadi,Chakan &Talegaon GA Limited
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Mumbai, Greater Mumbai, Thane Urban, Mira Bhayender, Navi Mumbai, Ambernath,Bhiwandi,Kalyan, Dombivli, Badlapur, Ulhasnagar, Mahanagar Gas Limited 12,83,284 3,754 71 Panvel,Kharghar & Taloja, Raigarh District GA excl area already authorized
Palghar district and Thane rural GA Gujarat Gas Limited 188 8 3
Pune excluding areas already authorized Mahesh Gas Ltd. 0 0 1 Ratnagiri Unison Enviro Pvt Ltd. 23 0 0 Total 14,52,902 4,064 260
Odisha Khorda district GA GAIL (India) Ltd. 225 0 0 Cuttack district GA GAIL (India) Ltd. 0 0 0 Total 225 0 0
Punjab Fatehgarh Sahib district IRM Energy Pvt. Ltd. 400 1 11 Amritsar GSPL 0 0 0 Total 400 1 11
Rajasthan State Gas Kota 2,160 11 14 Limited Rajasthan Rajasthan State Gas Neemrana & Kukas 0 1 0 Limited Total 2,160 12 14
Telangana Hyderabad Bhagyanagar Gas Limited 10,579 12 17 Total 10,579 12 17
Tripura Natural Gas Tripura Agartala 39,743 415 49 Company Limited Total 39,743 415 49
Khurja GA Adani Gas Ltd. 11,309 3 139 Kanpur GA Central UP Gas Ltd 39,316 140 55 Bareilly GA Central UP Gas Ltd 17,290 102 15 Meerut Gail Gas Ltd. 8,243 20 31 Firozabad (TTZ) GA Gail Gas Ltd. 916 0 340 Lucknow district Green Gas Ltd 34,917 45 10 Uttar Pradesh Agra Green Gas Ltd 32,442 50 19 Indian Oil-Adani Gas Pvt. Allahabad GA 2,778 1 0 Ltd. Mathura Sanwaria Gas Ltd 4,345 67 36 Moradabad GA SITI Energy Limited 3,847 59 6 Dibiyapur Gail Gas Ltd. 0 0 0 Varanasi district GAIL (India) Ltd. 2,100 8 0 Auraiya,Kanpur Dehat & Etawah districts Torrent Gas Pvt Ltd 0 0 0 Total 1,57,503 495 651
Indian Oil-Adani Gas Pvt. Uttarakhand Udham Singh Nagar district 773 3 6 Ltd. Haridwar district GA HNGPL 220 0 0 Total 993 3 6
Great Eastern Energy West Bengal Kultora, Asansol, Raniganj, Durgapur 0 0 0 Corporation Limited Total 0 0 0
Grand Total 50,43,188 28,046 8,823 Source: PPAC Monthly Reckoner June, 2019
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Annexure -5 Company overview Petronet LNG Limited is one of the pioneers in India for setting up country’s first LNG receiving and re- gasification terminal at Dahej, Gujarat, and another terminal at Kochi, Kerala. It was founded in the year 1998 as a joint venture between the Government of India and India’s leading oil and natural gas industry players. Petronet’s terminals today account for around 40% gas supplies in the country and handle around 80% of LNG imports in India. Exhibit 44: Promoters Bharat Petroleum Corporation Limited (BPCL) GAIL (India) Ltd Indian Oil Corporation Limited (IOCL) Oil and Natural Gas Corporation Limited Source: Company, Nirmal Bang Institutional Equities Research
Exhibit 45: Key management
Chairman Shri M. M. Kutty
Managing Director & CEO Shri Prabhat Singh
Director (Finance) & CFO Shri Vinod Kumar Mishra Source: Company, Nirmal Bang Institutional Equities Research Business and future plans 1. Three LNG ships Disha, Raahi and Aseem carry LNG volume from RasGas under a long-term contract to Dahej terminal 2. PLNG has taken a 26% equity stake in LNG ship Prachi to transport gas from Gorgon, Australia to Dahej terminal 3. Dahej terminal’s nameplate capacity is 17.5MMTPA (2.5MMTPA commissioned by June 2019) operating at 105% capacity utilization 4. Kochi terminal’s nameplate capacity is 5MMTPA operating at 10% capacity utilization 5. PLNG signed MoU for doing pre feed studies along with Japanese consortium and Sri Lanka Gas Terminal Company Limited for setting up a Floating Storage & Regasification Terminal at Colombo Sri Lanka. The validity of MoU is extended till April 2020 6. Company may submit an Expression of Interest for the construction of land-based LNG re-gasification terminal at Matarbari, Bangladesh 7. Company is planning to bid for the gas supply to NTPC who has been recently awarded the 50MW RLNG based power plant by the Ministry of Power 8. Pilots for testing LNG as auto-fuel and setting up highway LNG filling stations
Exhibit 46: Top shareholders % Share GAIL India Ltd 12.5 Indian Oil Corp Ltd 12.5 Bharat Petroleum Corp Ltd 12.5 Oil & Natural Gas Corp Ltd 12.5 Kotak Mahindra Asset Management Co 2.21 Fidelity Management & Research Co 1.84 Aditya Birla Sun Life Asset Manage 1.44 Motilal Oswal Asset Management Co 1.01 Source: Bloomberg, Nirmal Bang Institutional Equities Research
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Exhibit 47: Quarterly results Consolidated Rs. Mn Q1 FY19 Q1 FY20 Ch YoY % Q4FY19 Ch YoY % Net Revenue 91,692 86,134 (6.1) 83,832 2.7 Cost of Natural Gas and Traded Items 80,844 74,182 (8.2) 75,387 (1.6) Contribution 10,848 11,953 10.2 8,445 41.5 Employee Benefits Expense 224 293 30.8 340 (13.7) Other Expenses 1,280 1,421 11.0 1,833 (22.5) Total Expenses 82,347 75,895 (7.8) 77,560 (2.1) EBITDA 9,344 10,239 9.6 6,272 63.2 Depreciation and Amortization Expenses 1,022 1,899 85.7 1,016 86.9 EBIT 8,322 8,340 0.2 5,256 58.7 Other Income 990 1,044 5.5 1,514 (31.0) Finance Costs 300 1,005 235.4 225 346.4 PBT Reported 9,012 8,379 (7.0) 6,545 28.0 Current 1,940 2,880 48.5 2,158 33.5 Deferred 1,202 -104 (108.6) (14) 618.8 total tax -T 3,142 2,777 (11.6) 2,143 29.6 PAT reported-X-T+Y 5,870 5,603 (4.5) 4,402 27.3 Associates inc/loss(+/-) 186 17 (91.0) 252 (93.4) Consolidated Net Profit reported 6,056 5,619 (7.0) 4,654 20.7 Source: Company, Nirmal Bang Institutional Equities Research
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Annexure – 6: Highlights of analyst call by PLNG on Tellurium MOU
Key features shared by management: PLNG MOU: This is a non binding deal with Tellurian Inc.US with the option to purchase 1mn to 5mn TPA LNG and up to US$2.5bn equity investment in the Driftwood LNG project PLNG does not want to take more than 1-2mn TPA of LNG, Also capping exposure to equity stake of US$500mn – US$1bn, the rest will be offered to PLNG promoters who can be brought in as affiliates to the deal The Tellurian LNG project will be in two phases – 16mn TPA going up to 27.6 MnTPA Gas sourcing from Permian and Marcellus shale gas reserves with prices in the range of US$2.5-4 MMBTU likely to be capped at Henry Hub Spot Natural Gas price ($2.6/MMBTU)
Commercial aspects: Pending due diligence of the transaction and commercial returns by PLNG management and to be discussed by its Board before taking a final decision. The call did not reveal much beyond this on questions regarding commercial returns on the fairly large investment required Looking to buy the equity gas at max US$6/MMBTU- ex -ship Indian port See good demand from power and CGD at this price CGD demand to double in 5-8 years and will overtake fertilizer and power, thereby moving up from third to the largest segment in terms of gas demand in India
Strategy: The deal is part of company strategy to tie up with new supplies as Rasgas contract is ending by 2028 PLNG is looking for zero risk deal to buy Tellurian gas with 100% back to back sales contracts in India with existing buyers GAIL, BPCL and IOC Also open to B-2-C sales for small volumes if there is a shortfall in off take by the above three buyers
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Financials -Consolidated Exhibit 48: Income statement Exhibit 49: Cash flow Y/E March (Rsmn) FY18 FY19 FY20E FY21E FY22E Y/E March (Rsmn) FY18 FY19 FY20E FY21E FY22E Net Revenue 3,05,986 3,83,954 3,63,545 4,47,914 4,81,540 PBT 30,877 33,087 33,187 40,257 43,669 y/y 24.30 25.48 -5.32 23.21 7.51 Add depreciation 4,117 4,112 7,737 6,070 5,628 Other expenses (1,016) (3,130) (122) (2,718) (4,296) Raw Material Expenses 2,66,902 3,44,170 3,15,441 3,96,450 4,28,025 Change in W/C-inc./(dec.) 3,430 (3,649) (1,638) 1,173 129 RM/Sales % 87.2 89.6 86.8 88.5 88.9 Op. cash flow after W/C change 37,407 30,421 39,162 44,782 45,130 Employee cost 912 1,259 1,370 1,507 1,658 Income tax 6,968 8,133 8,742 10,628 11,529 Other expenses 5,049 5,592 5,932 6,348 6,855 Cash flow from Operations (A) 30,439 22,288 30,420 34,154 33,601 EBITDA 33,124 32,935 40,801 43,609 45,001 Capex (1,753) (1,628) (10,578) (8,400) (8,900) y/y 27.78 -0.57 23.88 6.88 3.19 Ch in Equity Accounted Investees - 45 - - - Depreciation 4,117 4,112 7,737 6,070 5,628 Ch in Investments (9,508) 34,622 - - - EBIT 29,007 28,822 33,064 37,539 39,373 Net movement in fixed deposits (1,519) (33,755) - - - Other Income 3 1 4,820 5,125 5,884 Interest Expense 1,630 989 4,021 1,731 911 Free cash Flow 17,663 21,573 24,662 30,880 30,585 Other Income 3,174 4,458 4,143 4,449 5,207 Cash flow from Investing (B) (12,776) (715) (5,758) (3,275) (3,016) PBT (adjusted) 30,551 32,291 33,187 40,257 43,669 Increase/(Decrease) in Long term (7,052) (6,202) (1,003) - - Income Tax Expense 9,773 10,782 9,326 10,628 11,529 borrowings Ch in Current Maturity (483) (874) - (6,322) - Associates inc/loss(+/-) 326 796 676 676 676 Dividends (including tax) paid (4,513) (18,083) (18,056) (19,861) (21,667) Consolidated Net Profit Adj. 21,104 22,306 24,537 30,306 32,817 Interest expense (1,782) (1,191) (4,021) (1,731) (911) EPS (Rs) 14.07 14.87 16.75 20.20 21.88 Cash flow from Financing (C) (13,830) (26,351) (23,079) (27,914) (22,578) y/y 22.48 5.69 12.62 20.64 8.29 Ch in Cash and Cash equiv 3,833 (4,778) 1,583 2,966 8,007 Source: Company, Nirmal Bang Institutional Equities Research opening cash 3,210 7,043 2,265 3,848 6,814 closing cash 7,043 2,265 3,848 6,814 14,821 Exhibit 50: Balance sheet Source: Company, Nirmal Bang Institutional Equities Research Y/E March (Rs Mn) FY18 FY19 FY20E FY21E FY22E Exhibit 51: Key ratios Equity Share Capital 15,000 15,000 15,000 15,000 15,000 Y/E March FY18 FY19 FY20E FY21E FY22E Reserves and Surplus 83,113 87,306 94,371 1,04,816 1,15,966 Profitability & return ratios Net worth 98,113 1,02,306 1,09,371 1,19,816 1,30,966 EBITDA margin (%) 10.8 8.6 11.2 9.7 9.3 Long Term Borrowings 7,334 1,012 9 9 9 EBIT margin (%) 9.5 7.5 9.1 8.4 8.2 Other long term liab. 12,914 10,972 10,972 10,972 10,972 Net profit margin (%) 6.9 5.8 6.9 6.8 6.8 Deferred Tax Liabilities [Net] 10,482 13,360 13,360 13,360 13,360 RoE (%) 23.5 22.3 23.0 26.4 26.2 Trade Payables 15,699 12,952 12,125 16,419 17,866 Pre-tax RoCE (%) 13.6 16.3 17.8 14.8 14.3 Other Financial Liab. 1,118 532 1,928 1,891 1,855 RoIC (%) 11.5 14.6 17.4 13.9 13.4 Current Maturity of Long term Working capital ratios 7,196 6,322 6,322 - - Loans Receivables (days) 16.8 14.2 15.0 15.0 15.0 Other current liab. 4,589 5,038 4,381 5,747 6,368 Inventory (days) 6 5 6 6 6 Total Capital And Liabilities 1,57,445 1,52,493 1,58,469 1,68,213 1,81,396 Payables (days) 15 14 12 13 14 Net Asset 80,296 76,651 72,772 69,202 79,676 Cash conversion cycle 7.9 5.6 9.0 7.4 7.2 Capital Work-In-Progress 2,203 3,482 10,202 16,102 8,900 Leverage ratios Investments in Joint Venture 2,552 3,289 3,289 3,289 3,289 Net debt/(cash) (Rsmn) -33,673 -30,518 -33,103 -42,391 -50,398 Net Debt/(cash)/Equity (X) -0.34 -0.30 -0.30 -0.35 -0.38 Other Noncurrent assets 2,217 9,454 9,454 9,454 9,454 Net Debt/EBITDA -1.02 -0.93 -0.81 -0.97 -1.12 Current Investments 39,578 8,249 8,249 8,249 8,249 Valuation ratios Inventories 4,911 5,694 6,130 7,111 7,633 EV/sales (x) 1.16 0.93 0.98 0.80 0.74 Trade Receivables 16,008 13,825 14,940 18,407 19,789 EV/EBITDA (x) 10.76 10.82 8.73 8.17 7.92 Cash And Cash Equivalents 7,043 2,266 3,848 6,814 14,821 EV/FCF 721.03 -454.85 818.29 363.02 683.00 Bank balances other than cash 1,582 27,337 27,337 27,337 27,337 P/E (x) 18.33 17.34 15.40 12.76 11.79 Other financial assets 508 1,737 1,737 1,737 1,737 P/BV (x) 3.94 3.78 3.54 3.23 2.95 Other Current Assets 548 511 511 511 511 FCF Yield (%) 4.96 6.05 6.92 8.67 8.58 Dividend Yield (%) 0.97 3.88 3.88 4.27 4.65 Total Assets 1,57,445 1,52,493 1,58,469 1,68,213 1,81,396 Per share ratios Source: Company, Nirmal Bang Institutional Equities Research EPS 14.07 14.87 16.75 20.20 21.88 Cash EPS 16.81 17.61 21.91 24.25 25.63 BVPS 65.41 68.20 72.91 79.88 87.31 DPS 2.50 10.00 10.00 11.00 12.00 Source: Company, Nirmal Bang Institutional Equities Research
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DISCLOSURES
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