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Focus Shifts To Affordability From Availability
We believe India’s gas sector growth will hinge upon the pricing of
regasified liquefied natural gas (RLNG) rather than being a function of the
widely accepted notion of supply constraint. The sector, which set a new
paradigm in the energy space on the back of domestic gas in 2010, will now
be driven by RLNG until domestic supply perks up. We believe that despite
the euphoria over surging domestic gas supply fading, the earnings of
players in this sector are fairly intact. We assign Buy rating to Gujarat State
Petronet, Petronet LNG and GAIL (India) who are direct beneficiaries of the
RLNG play in India, while we have Sell rating on city gas distribution (CGD)
companies such as Indraprastha Gas and Gujarat Gas Company as they
seem to be entering a phase of margin contraction.
Gradual soft pricing of LNG in the offing: We have assumed average LNG free-onboard
(FOB) spot price of US$15/mmBtu for FY13E as well as FY14E compared to an
average of US$16.18/mmBtu in the first nine months of FY12, implying the cost
economics of natural gas will continue to be favoured by the non-core sectors. We
believe the current trend of softening spot LNG prices will continue on account of
companies preferring to rely more on spot/medium term cargo rather than on longterm
contracts due to price distortion caused by the advent of shale gas. Our
interaction with industry stalwarts indicated that ~35mtpa of RLNG capacity is being
withheld by suppliers as they feel current spot prices are depressed and ~8.2mtpa of
contracts will be available for renewal from 2014.
Pricing to drive medium-term consumption growth: In the wake of dwindling
production of domestic gas, consumption growth will hinge upon the ability of
midstream companies to source LNG at US$15/mmBtu FOB in the medium term. Our
analysis reveals that gas consumption can post a 9% CAGR over FY11-16E if noncore
sectors remain dependent on RLNG with the core sector continuing to rely on
domestic gas. Average LNG cost of US$15/mmBtu is vital for consumption growth as
historical evidence shows that this level acts as a threshold limit for oil refineries,
petrochemicals and CGD companies to determine their propensity to consume natural
gas or switch to other liquid fuels.
Slim chances of across-the-board limit on marketing margin: The oil ministry has
asked the regulator, PNGRB (Petroleum & Natural Gas Regulatory Board) to set the
quantum of marketing margin that can be charged by a gas marketer. Our interaction
with PNGRB officials indicated that as per the PNGRB Act, the regulator has no legal
standing to limit marketing margin unless under Section 11(a) it finds concrete
evidence of profiteering, or unless natural gas gets a notified status.
Upcoming gas infrastructure to allay fears of tight gas supply: Indian companies
will be investing US$28-37bn in gas infrastructure over the next four-five years. With
the infrastructure in place, gas supply potential over this period is expected to increase
to 336mmscmd from 185mmscmd currently by FY16, of which ~40% will be
accounted for by RLNG terminals.
Gradual soft pricing of LNG in the offing
We have assumed average LNG spot price (FOB) at US$15.00/mmBtu for FY13E and FY14E compared to
an average of US$16.18/mmBtu in the first nine months of FY12, implying the cost economics of natural gas
will continue to be favoured by the non-core sectors. We believe the current trend of softening spot LNG
prices will continue on account of the following factors: (1) ~35mtpa of LNG capacity having been kept
of out of the market by LNG producers to sustain prices. (2) Out of 80mtpa of Qatar capacity, ~8.3mtpa
of capacity is likely to be renewed. Contracts between western buyers and Middle East suppliers will
expire by 2014 and onwards and are likely to be placed in Asian markets with varying degrees.
Contract renewal will come around the same time as new capacity addition coming on stream, which
is likely to contribute to softening of the market. (3) Asian companies are pushing for implementation
of the S-Curve mechanism to hedge themselves against the vicissitudes of oil prices; recently Kogas
signed a contract with Shell based on the S-curve mechanism. (4) Lower-than-normal discount of 6%
currently compared to ~20% discount at which Japanese LNG has historically traded to JCC
(Japanese crude cocktail). (5) Likelihood of rising contribution of natural gas in electricity generation,
thereby adding to the buyers’ bargaining power. (6) Rising supply of unconventional gas from the US
weakening the clout wielded by conventional gas companies, which caused BG, Fenosa, Kogas and
GAIL to sign contracts based on the Henry Hub pricing mechanism.
Electricity generation by usage of fuels
China, in its 12th Five Year Plan, has set a target for cutting energy intensity (primary energy consumption per
unit of GDP) by 16% by the end of 2015. Consequently, energy from natural gas, nuclear and renewable
sources will be aggressively promoted. China aims to achieve 8.3% share for natural gas in the overall
primary energy mix by 2015, up from 3.8% in 2008.
With the rising contribution of unconventional gas in the total energy mix (from 12% currently to 24%
in 2035), we believe the pricing clout exercised by sellers of natural gas will diminish in the medium to
long-term. There have been recent cases of companies de-linking gas from oil indexation in Russia
and Algeria. Russia has come close to being arm-twisted by its European counterparts into accepting
lower prices for gas supplied and is now allowing a portion of its sales in Europe to be indexed to spot
gas markets, or regional market hubs, rather than crude oil prices. The change in pricing terms
indicates a paradigm shift in international gas pricing contracts in coming months.
GAIL is also persuading its LNG suppliers, including Qatar-based producer Rasgas, to reduce the impact of
high crude oil price on its gas deliveries. GAIL wants to introduce price caps to limit its exposure to rising oil
prices besides introducing a formula known as the S-Curve. Such a mechanism imposes limits on price spikes
and floors on price drops, thus ironing out volatility and giving the buyers more clarity on future costs.
Favourable cost economics of US shale gas may lead to long-term supply pacts
The advent of US shale gas as an LNG alternative, with long-term prices suitable for the high growth gas user
segment (i.e. CGDs, petrochemical units and refineries) could be a game changer for India with the possibility
of accessing US LNG in the price range of US$9-11/mmBtu. We see a structural shift in the LNG market after
the US Department of Energy allowed exports of upto 16mmtpa of gas. Recently, GAIL signed an agreement
to buy 3.5mmtpa of US LNG from Cheniere, but the benefits to Indian companies will percolate only after
2015. Over 50mmtpa of US shale gas will be explored in North America, of which applications for regulatory
approval of nearly 40mmtpa of exports have been made.
Asia-based gas utilities have an upper hand in striking deals with Cheniere Energy on account of three
reasons: 1) Cheniere is currently financially strained, with its cash and cash equivalents having
slipped to US$131mn as of end September 2011 and is on the verge of default as per rating agency
S&P. (2) Panama canal is being widened with a capex of US$5.25bn, which allows large LNG carriers
to pass through it for the first time. The expansion of Panama canal will give a US Gulf coast LNG
exporter direct access to Asia and thereby foster healthy competition with Australian LNG mega
projects coming up in 2014-15.(3) US LNG exports are expected to have only a modest impact on US
natural gas prices, according to Deloitte MarketPoint. A study conducted by it indicated that LNG exports
of 6bcfd from the US will carry a weighted average price impact of US$0.12/mmBtu on US natural gas prices
during 2016-35. Their findings also dispel concerns that LNG exports would result in US LNG prices rising to
global levels.
Pricing to drive medium-term consumption growth
In the wake of dwindling production of domestic gas, consumption growth will hinge upon the ability of
midstream companies to source LNG at US$15/mmBtu (FOB) in the medium term. Our analysis reveals that
gas consumption can witness a 9% CAGR over FY11-16E if the non-core sectors remain dependent on
RLNG while the core sector continues to rely on domestic gas. Average LNG cost of US$15/mmBtu is
vital for consumption growth as historical evidence shows the US$15/mmBtu mark acts as a threshold
limit for oil refineries, petrochemical units and city gas distribution companies to determine their
propensity to consume natural gas or switch to other liquid fuels.
We believe the growth of the natural gas sector in India will be a function of blended gas pricing. In the wake
of flat-to-muted production growth of cheap domestic gas coupled with the subdued growth in all associated
verticals (re-gasification, transportation or distribution), the key determinant of earnings growth in the medium
term would be the propensity to consume high-priced RLNG by end-users like power and fertiliser units,
refineries and city gas distribution companies. Our analysis suggests that if Indian companies can source LNG
at an average price of US$15/mmBtu (FOB), there may be significant traction in all verticals of the segment in
varying degrees. With the price of US$15/mmBtu, we expect gas consumption to touch 246 mmscmd in FY16
from 157mmscmd in FY11 - a CAGR of 9% over the next five years. LNG contribution will increase to 30-35%
of total supply of gas over the same period
Our channel checks across various segments of gas users indicate that gas demand in India will be more a
function of the price at which it will be sold to various consumers rather than its supply, as users’ consumption
propensity of gas at different price points will depend on the extent to which they will be able to pass on higher
prices to consumers. Sectors with lower proclivity to pass on gas price hike like power and fertiliser would be
largely dependent on cost economics and therefore rely on cheaper domestic gas. In contrast, growth in other
sectors such as refineries, CGDs, sponge iron units, captive power and petrochemical units - all key
consumers of imported gas with ability to pass on higher costs - would be instrumental in increasing the scope
of RLNG usage in India.
Asian LNG prices have soared and remained at an elevated level post the Japanese quake-tsunami. Surging
LNG prices in Asia reduce its competitive advantage vis-a-vis imported coal, naptha, LSHS and fuel oil, which
in turn diminishes the role of natural gas as a preferred fuel for refineries, city gas distribution companies and
petrochemical industries. Our analysis reveals that LNG price of US$15 (FOB) would be most favoured
by gas consuming sectors (except power and fertilisers) in the long term. If prices remain in this
range, we believe RLNG consumption in India would increase to 91.36mmscmd in FY16E from
33.0mmscmd in FY11, a CAGR of 22.36%, of which RLNG’s contribution to total supply expected to
increase to ~37% in FY16E from 21% in FY11.
Why spot LNG price of US$15/mmBtu remains essential for growth?
In the past six months, we have observed that soaring LNG prices made substitution to oil-based fuels viable,
which led refineries of Essar Oil to shift to naptha and those of Reliance Industries to reduce their exposure to
natural gas. The two Gujarat-based refineries have a potential to draw natural gas up to ~13-14mmscmd,
subject to their prices continuing to remain in the range of US$9-15/mmBtu. As per media reports, two private
power plants in Gujarat reduced power generation when spot LNG prices touched US$16-17/mmBtu in
September 2011.
Gas supply (excluding power and fertiliser sectors) is expected to show 10% CAGR over the next five years,
at 88.87mmscmd from 54.21mmscmd in FY11. Gas demand from power generation and fertiliser sectors will
be largely catered to by cheap domestic gas with an assured pro-rata allocation. The government has
formulated a gas allocation policy to ensure moderate prices for power tariffs in peak shaving times as well as
to ensure lower feedstock prices to contain fertiliser subsidy bill. We believe nearly ~76-77% of domestically
produced gas in the next five years would be allocated to power and fertiliser sectors, while the remaining gas
consuming segments would be principally dependent on high-priced LNG.
Refineries: Emission norms to drive gas consumption
Refineries, which constitute ~8-10% of gas demand growth, can switch to other fuels depending on gas prices.
On an energy equivalence level, ~20-25% of process-based requirement can be fulfilled with LSHS
(low sulphur heavy stock) and fuel oil if LNG prices breach the current level of US$17-18/mmBtu. The
remaining demand (~75-80%) from refineries could be met through hydrogen generation and power
plants, which can alternatively run on naptha and diesel, respectively. Cost economics thus tilt in
favour of refineries using alternative fuel like naptha or diesel if LNG spot prices surpass the level of
US$23-26/mmBtu.
Based on our interaction with industry veterans, we found the entire quantum of liquid fuels cannot be
displaced by gas as there is a requirement for process and start-up fuels. We have assumed 80% of liquid fuel
consumption in refineries can be displaced by gas. Of a total installed capacity of 193mtpa, ~62% of the
refineries are gas-based, which implies a consumption of up to 20mmscmd of gas. We estimate gas demand
from refineries to increase to 19.31mmscmd in FY16 as against 12.55mmscmd in FY11, showing a five-year
CAGR of 9%. Growth in refinery gas consumption will receive impetus from: i) Existing gas-based refineries
which currently use only 39% of their capacity, ii) Conversion opportunity for refineries with capacity of 73mtpa
(which can consume gas of up to 20mmscmd), and iii) Consumption from new refineries/expansion of existing
refineries in Nagarjuna, Bhatinda, Bina and Kochi.
City gas distribution: Catapulting gas into new orbit
The city gas distribution sector is expected to witness higher growth among gas consumption verticals on
account of favourable cost economics and stricter emission norms to reduce CO2 emission/unit of GDP by 20-
25% during 2005-20. The key driver of CGD growth would be operating cost savings emerging from using
different fuels like diesel and LPG. We believe that in the current environment, where the government has
managed to de-regulate only petrol prices so far, CNG vehicles will predominantly drive growth in the CGD
segment. Though the running costs of domestic LPG and diesel vehicles still make it viable to switch to CNG,
blending of high-cost LNG decreases cost savings on those fuels.
We estimate demand in the CGD space to register 18% CAGR over the next five years (highest among
gas consumer verticals) at 31mmscmd in FY16E compared to 13mmscmd in FY11. The CGD
consumption pie out of total gas supply is expected to increase to ~12% from 9% currently. A switchover
from petrol to CNG vehicles results in cost savings of 60-70% if 80-90% domestic gas is blended, but the
savings would drop to 30-35% on switching fully to imported gas. However, transition from other fuels like
diesel and LPG will depend entirely upon the availability of cheap domestic gas as a complete switch-over to
gas at market-determined rates would make the proposition unviable given the fact that the prices of diesel
and LPG continue to be regulated.
Currently, the transportation sector consumes less than 2% of natural gas in the country. As the domestic gas
grid expands and reaches more cities, its prospects in the transportation sector will also brighten. There are
currently 1.6mn natural gas vehicles in the country which are expected to increase to 5.8mn over the next 10
years. Delhi alone accommodates more than 0.4mn vehicles. Around 30 cities have access to CNG with the
pipeline network expected to increase to 15,000km and city gas distribution network to cover around 150-200
cities by 2014. On the back of marketing and infrastructure exclusivity, CGD will continue to remain an
attractive proposition. Although network tariff is regulated, there is no cap on marketing margin. Our interaction
with PNGRB suggests there will be no intervention from the regulator unless it suspects the possibility of
profiteering. Under the gas utilisation policy, the CGD sector is given priority after fertiliser, power generation
and LPG. Growth prospects of CGD can be gauged from the fact that companies which are entirely reliant on
imported LNG have shown tremendous growth despite surging prices. In December 2011, GSPC’s gas
supply overtook all central government and private sector-controlled CGD companies by topping the
4.4mmscmd of supply through distribution.
CNG roadmap
2009-14
No of potential cities 298
Investment required (US$bn) 7.43
Likely gas requirement (mmscmd) 74.34
Potential households (mn) 14.87
Potential vehicles (mn) 3.71
2015-20
New cities added 117.00
Estimated demand (mmscmd) 16.30
Capex (US$bn) 1.63
2020-25
New cities added 69.00
Estimated gas demand (mmscmd) 10.32
Capex (US$bn) 1.32
Source: GAIL
Power sector groping in darkness
After RIL’s discovery of gas in the Krishna Godavari Basin D6 block (with initial peak production reaching 61
mmscmd), a plethora of private and government power utilities announced gas-based capacity addition in
anticipation of cheap domestic gas. In his backdrop, the petroleum and natural gas ministry had, in March
2010, estimated gas-based capacity to touch 36,617MW by end of FY15. Today, however, caught between
the pincer of dwindling gas volumes from KG-D6 block and the absence of alternative domestic supplies
before FY14, we forecast moderation in the construction of gas-based power stations unless there is a
significant ramp-up in domestic supply or policy making undergoes an overhaul. Recently, Rural Electrification
Corporation (REC) and Power Finance Corporation (PFC) agreed to resume giving short-term loans to the
discoms of Rajasthan Uttar Pradesh, Punjab, Haryana, and Tamil Nadu after revising the lending guidelines,
key among them being submission of audited accounts, regular tariff revision and timely payment by
respective state governments on account of the subsidy provided to agriculture and retail segments.
Slim chances of across-the-board limit on marketing margin
The oil ministry has asked the gas regulator, PNGRB to establish the quantum of marketing margin
chargeable by a gas marketer. Our interaction with PNGRB officials indicated that as per the established law,
it has no legal standing in capping margin unless under Section 11(a) it finds concrete evidence of profiteering
or unless natural gas gets a notified status. We believe companies having direct exposure to domestic gas will
be at risk if the margin is capped. GAIL’s FY13E EPS could erode by ~3-3.5% if the marketing margin is
capped on domestic gas. Marketing earnings of Petronet LNG, of late, should be construed as a cyclical factor
on tight supply conditions and increased efficiency. CGD companies like Gujarat Gas & Indraprastha Gas are
not entitled to show margin/price breakdown unless natural gas is notified, although we feel the higher RoCE
they currently enjoy will gradually moderate on diminishing pricing power.
Our interaction with ex-PNGRB chairman and the management of various companies in the gas chain
revealed the following:
• As per the PNGRB Act, there is no provision for the gas regulator to decide the marketing margin and the
legality of capping marketing margin can be challenged in a court of law.
• The gas regulator can take recourse to intervention under Section 11(a) of the PNGRB Act to protect the
interests of consumers by fostering fair trade and competition among the entities. The regulator, through
an in-built clause, can intervene in pricing if it finds concrete evidence of profiteering.
• Under Section 11(f) of the PNGRB Act, the regulator can monitor prices and take corrective measures to
prevent restrictive trade practices by the entities, but until now, neither any of the petroleum products nor
natural gas has been notified.
• Petronet’s management believes that the matter relating to marketing margin primarily relates to domestic
gas whose price is regulated by the government. Prices of spot RLNG are subject to global dynamics and
marketing efforts on each cargo varies, thus leaving little room for regulating margins on spot cargo.
Customers subscribing to RLNG are the ones who have switched from liquid fuel after realising
favourable cost economics and if they are willing to fork out higher prices, there should be no cause for
concern from the regulator’s end.
We believe the concern over marketing margin on gas will gradually ease. We believe the cap on marketing
margins should be limited to domestic gas, as the agenda note of MOPNG dated 21 December 2011 clearly
stated that the marketing margin pertains to KG-D6 gas so as to keep the price for end consumers
reasonable.
(a) Difficulty in determining the marketing cost of individual transactions as decided between buyers and
sellers. It may be recalled that prior to the domestic gas supply crunch in FY10, Petronet charged zero
marketing margin on spot RLNG cargo. (Even nowadays, clients with whom the supplier enjoys
favourable relations have access to zero marketing charges). Thus, high marketing margin enjoyed by
GAIL and PLNG, supported by spot RLNG cargo, is not the result of overcharging but of scarce supply.
The possibility of Petronet charging abnormally high marketing margin seems to be remote as Shell’s
terminal in Hazira is operational and if prices appear too high for buyers, they can switch to the other
terminal. The genesis of the concern on marketing margin arose from the disputes over overcharging the
core sector (fertiliser); as Petronet caters to non-core customers who invariably inspect RLNG’s cost
economics before subscribing, it should not attract the regulator’s scrutiny under Section 11(f) of the
PNGRB Act.
(b) Distribution companies like Gujarat Gas and IGL are likely to catch the regulator’s attention on account of
historically high RoCE (more than 20%) earned; nonetheless we believe that because of weakening
pricing power, the return ratios of these companies will decline in the next three-four years. Given that
IGL’s marketing exclusivity period has come to an end in December 2011, the possibility of super normal
profit has automatically eased in the wake of upcoming competition.
(c) GAIL earns a fixed marketing margin on gas from all sources: APM gas margin is fixed at
US$0.11/mmBtu, PMT, RLNG (Ras Gas) margin at US$0.17/mmBtu and spot cargo marketing margin
works in same way like that of Petronet LNG. While the market harbours serious reservations on the
sustainability of GAIL’s marketing margin, we would like to point out that the inventory and price risk
borne by GAIL warrants a leeway in deciding the marketing margin.
(d) The gas regulator already has a backlog of pending decisions that are crucial for the development of the
gas sector (award of CGD third and fourth rounds, final tariff decision on GSPL). Given the long-drawn
process of the gas regulator inviting the companies to present their case, build a framework and then put
a paper out for discussion, the exercise could take more than year to complete, even in a fast-track mode.
Upcoming gas infrastructure to allay tight gas supply fears
Indian companies are investing US$28-37bn in gas infrastructure over the next four-five years. With the
infrastructure in place, gas supply potential over next five years will increase to 336mmscmd from 185
mmscmd, of which ~40% would be accounted for by RLNG terminals. With Petronet’s Kochi terminal likely to
be operational from 3QFY13 and GAIL’s partial capitalisation of DVPL, the Dabhol-Bangalore and Kochi
pipeline would reap the benefits of the huge capex incurred in FY13.
An underdeveloped pipeline infrastructure remains a key impediment that threatens to distort the demandsupply
equation. PNGRB plans to build a national grid (on the lines of US and Europe) to supply gas at major
hubs in India. As per the draft report on natural gas by the oil ministry, total gas pipeline length is likely to
touch 30,000km (822mmscmd) in the next five years from the current length of 13,508km (339mmscmd).
Further, investments in this space are likely to be in the range of US$28-37bn (midstream and downstream) in
the same period. We feel demand growth will be a function of timely completion of the infrastructure laid for
the gas sector on the back of gas assuming a higher proportion in the energy mix (21% in 2020 from 11%
currently).
India Equity Research Reports, IPO and Stock News
Visit http://indiaer.blogspot.com/ for complete details �� ��
Focus Shifts To Affordability From Availability
We believe India’s gas sector growth will hinge upon the pricing of
regasified liquefied natural gas (RLNG) rather than being a function of the
widely accepted notion of supply constraint. The sector, which set a new
paradigm in the energy space on the back of domestic gas in 2010, will now
be driven by RLNG until domestic supply perks up. We believe that despite
the euphoria over surging domestic gas supply fading, the earnings of
players in this sector are fairly intact. We assign Buy rating to Gujarat State
Petronet, Petronet LNG and GAIL (India) who are direct beneficiaries of the
RLNG play in India, while we have Sell rating on city gas distribution (CGD)
companies such as Indraprastha Gas and Gujarat Gas Company as they
seem to be entering a phase of margin contraction.
Gradual soft pricing of LNG in the offing: We have assumed average LNG free-onboard
(FOB) spot price of US$15/mmBtu for FY13E as well as FY14E compared to an
average of US$16.18/mmBtu in the first nine months of FY12, implying the cost
economics of natural gas will continue to be favoured by the non-core sectors. We
believe the current trend of softening spot LNG prices will continue on account of
companies preferring to rely more on spot/medium term cargo rather than on longterm
contracts due to price distortion caused by the advent of shale gas. Our
interaction with industry stalwarts indicated that ~35mtpa of RLNG capacity is being
withheld by suppliers as they feel current spot prices are depressed and ~8.2mtpa of
contracts will be available for renewal from 2014.
Pricing to drive medium-term consumption growth: In the wake of dwindling
production of domestic gas, consumption growth will hinge upon the ability of
midstream companies to source LNG at US$15/mmBtu FOB in the medium term. Our
analysis reveals that gas consumption can post a 9% CAGR over FY11-16E if noncore
sectors remain dependent on RLNG with the core sector continuing to rely on
domestic gas. Average LNG cost of US$15/mmBtu is vital for consumption growth as
historical evidence shows that this level acts as a threshold limit for oil refineries,
petrochemicals and CGD companies to determine their propensity to consume natural
gas or switch to other liquid fuels.
Slim chances of across-the-board limit on marketing margin: The oil ministry has
asked the regulator, PNGRB (Petroleum & Natural Gas Regulatory Board) to set the
quantum of marketing margin that can be charged by a gas marketer. Our interaction
with PNGRB officials indicated that as per the PNGRB Act, the regulator has no legal
standing to limit marketing margin unless under Section 11(a) it finds concrete
evidence of profiteering, or unless natural gas gets a notified status.
Upcoming gas infrastructure to allay fears of tight gas supply: Indian companies
will be investing US$28-37bn in gas infrastructure over the next four-five years. With
the infrastructure in place, gas supply potential over this period is expected to increase
to 336mmscmd from 185mmscmd currently by FY16, of which ~40% will be
accounted for by RLNG terminals.
Gradual soft pricing of LNG in the offing
We have assumed average LNG spot price (FOB) at US$15.00/mmBtu for FY13E and FY14E compared to
an average of US$16.18/mmBtu in the first nine months of FY12, implying the cost economics of natural gas
will continue to be favoured by the non-core sectors. We believe the current trend of softening spot LNG
prices will continue on account of the following factors: (1) ~35mtpa of LNG capacity having been kept
of out of the market by LNG producers to sustain prices. (2) Out of 80mtpa of Qatar capacity, ~8.3mtpa
of capacity is likely to be renewed. Contracts between western buyers and Middle East suppliers will
expire by 2014 and onwards and are likely to be placed in Asian markets with varying degrees.
Contract renewal will come around the same time as new capacity addition coming on stream, which
is likely to contribute to softening of the market. (3) Asian companies are pushing for implementation
of the S-Curve mechanism to hedge themselves against the vicissitudes of oil prices; recently Kogas
signed a contract with Shell based on the S-curve mechanism. (4) Lower-than-normal discount of 6%
currently compared to ~20% discount at which Japanese LNG has historically traded to JCC
(Japanese crude cocktail). (5) Likelihood of rising contribution of natural gas in electricity generation,
thereby adding to the buyers’ bargaining power. (6) Rising supply of unconventional gas from the US
weakening the clout wielded by conventional gas companies, which caused BG, Fenosa, Kogas and
GAIL to sign contracts based on the Henry Hub pricing mechanism.
Electricity generation by usage of fuels
China, in its 12th Five Year Plan, has set a target for cutting energy intensity (primary energy consumption per
unit of GDP) by 16% by the end of 2015. Consequently, energy from natural gas, nuclear and renewable
sources will be aggressively promoted. China aims to achieve 8.3% share for natural gas in the overall
primary energy mix by 2015, up from 3.8% in 2008.
With the rising contribution of unconventional gas in the total energy mix (from 12% currently to 24%
in 2035), we believe the pricing clout exercised by sellers of natural gas will diminish in the medium to
long-term. There have been recent cases of companies de-linking gas from oil indexation in Russia
and Algeria. Russia has come close to being arm-twisted by its European counterparts into accepting
lower prices for gas supplied and is now allowing a portion of its sales in Europe to be indexed to spot
gas markets, or regional market hubs, rather than crude oil prices. The change in pricing terms
indicates a paradigm shift in international gas pricing contracts in coming months.
GAIL is also persuading its LNG suppliers, including Qatar-based producer Rasgas, to reduce the impact of
high crude oil price on its gas deliveries. GAIL wants to introduce price caps to limit its exposure to rising oil
prices besides introducing a formula known as the S-Curve. Such a mechanism imposes limits on price spikes
and floors on price drops, thus ironing out volatility and giving the buyers more clarity on future costs.
Favourable cost economics of US shale gas may lead to long-term supply pacts
The advent of US shale gas as an LNG alternative, with long-term prices suitable for the high growth gas user
segment (i.e. CGDs, petrochemical units and refineries) could be a game changer for India with the possibility
of accessing US LNG in the price range of US$9-11/mmBtu. We see a structural shift in the LNG market after
the US Department of Energy allowed exports of upto 16mmtpa of gas. Recently, GAIL signed an agreement
to buy 3.5mmtpa of US LNG from Cheniere, but the benefits to Indian companies will percolate only after
2015. Over 50mmtpa of US shale gas will be explored in North America, of which applications for regulatory
approval of nearly 40mmtpa of exports have been made.
Asia-based gas utilities have an upper hand in striking deals with Cheniere Energy on account of three
reasons: 1) Cheniere is currently financially strained, with its cash and cash equivalents having
slipped to US$131mn as of end September 2011 and is on the verge of default as per rating agency
S&P. (2) Panama canal is being widened with a capex of US$5.25bn, which allows large LNG carriers
to pass through it for the first time. The expansion of Panama canal will give a US Gulf coast LNG
exporter direct access to Asia and thereby foster healthy competition with Australian LNG mega
projects coming up in 2014-15.(3) US LNG exports are expected to have only a modest impact on US
natural gas prices, according to Deloitte MarketPoint. A study conducted by it indicated that LNG exports
of 6bcfd from the US will carry a weighted average price impact of US$0.12/mmBtu on US natural gas prices
during 2016-35. Their findings also dispel concerns that LNG exports would result in US LNG prices rising to
global levels.
Pricing to drive medium-term consumption growth
In the wake of dwindling production of domestic gas, consumption growth will hinge upon the ability of
midstream companies to source LNG at US$15/mmBtu (FOB) in the medium term. Our analysis reveals that
gas consumption can witness a 9% CAGR over FY11-16E if the non-core sectors remain dependent on
RLNG while the core sector continues to rely on domestic gas. Average LNG cost of US$15/mmBtu is
vital for consumption growth as historical evidence shows the US$15/mmBtu mark acts as a threshold
limit for oil refineries, petrochemical units and city gas distribution companies to determine their
propensity to consume natural gas or switch to other liquid fuels.
We believe the growth of the natural gas sector in India will be a function of blended gas pricing. In the wake
of flat-to-muted production growth of cheap domestic gas coupled with the subdued growth in all associated
verticals (re-gasification, transportation or distribution), the key determinant of earnings growth in the medium
term would be the propensity to consume high-priced RLNG by end-users like power and fertiliser units,
refineries and city gas distribution companies. Our analysis suggests that if Indian companies can source LNG
at an average price of US$15/mmBtu (FOB), there may be significant traction in all verticals of the segment in
varying degrees. With the price of US$15/mmBtu, we expect gas consumption to touch 246 mmscmd in FY16
from 157mmscmd in FY11 - a CAGR of 9% over the next five years. LNG contribution will increase to 30-35%
of total supply of gas over the same period
Our channel checks across various segments of gas users indicate that gas demand in India will be more a
function of the price at which it will be sold to various consumers rather than its supply, as users’ consumption
propensity of gas at different price points will depend on the extent to which they will be able to pass on higher
prices to consumers. Sectors with lower proclivity to pass on gas price hike like power and fertiliser would be
largely dependent on cost economics and therefore rely on cheaper domestic gas. In contrast, growth in other
sectors such as refineries, CGDs, sponge iron units, captive power and petrochemical units - all key
consumers of imported gas with ability to pass on higher costs - would be instrumental in increasing the scope
of RLNG usage in India.
Asian LNG prices have soared and remained at an elevated level post the Japanese quake-tsunami. Surging
LNG prices in Asia reduce its competitive advantage vis-a-vis imported coal, naptha, LSHS and fuel oil, which
in turn diminishes the role of natural gas as a preferred fuel for refineries, city gas distribution companies and
petrochemical industries. Our analysis reveals that LNG price of US$15 (FOB) would be most favoured
by gas consuming sectors (except power and fertilisers) in the long term. If prices remain in this
range, we believe RLNG consumption in India would increase to 91.36mmscmd in FY16E from
33.0mmscmd in FY11, a CAGR of 22.36%, of which RLNG’s contribution to total supply expected to
increase to ~37% in FY16E from 21% in FY11.
Why spot LNG price of US$15/mmBtu remains essential for growth?
In the past six months, we have observed that soaring LNG prices made substitution to oil-based fuels viable,
which led refineries of Essar Oil to shift to naptha and those of Reliance Industries to reduce their exposure to
natural gas. The two Gujarat-based refineries have a potential to draw natural gas up to ~13-14mmscmd,
subject to their prices continuing to remain in the range of US$9-15/mmBtu. As per media reports, two private
power plants in Gujarat reduced power generation when spot LNG prices touched US$16-17/mmBtu in
September 2011.
Gas supply (excluding power and fertiliser sectors) is expected to show 10% CAGR over the next five years,
at 88.87mmscmd from 54.21mmscmd in FY11. Gas demand from power generation and fertiliser sectors will
be largely catered to by cheap domestic gas with an assured pro-rata allocation. The government has
formulated a gas allocation policy to ensure moderate prices for power tariffs in peak shaving times as well as
to ensure lower feedstock prices to contain fertiliser subsidy bill. We believe nearly ~76-77% of domestically
produced gas in the next five years would be allocated to power and fertiliser sectors, while the remaining gas
consuming segments would be principally dependent on high-priced LNG.
Refineries: Emission norms to drive gas consumption
Refineries, which constitute ~8-10% of gas demand growth, can switch to other fuels depending on gas prices.
On an energy equivalence level, ~20-25% of process-based requirement can be fulfilled with LSHS
(low sulphur heavy stock) and fuel oil if LNG prices breach the current level of US$17-18/mmBtu. The
remaining demand (~75-80%) from refineries could be met through hydrogen generation and power
plants, which can alternatively run on naptha and diesel, respectively. Cost economics thus tilt in
favour of refineries using alternative fuel like naptha or diesel if LNG spot prices surpass the level of
US$23-26/mmBtu.
Based on our interaction with industry veterans, we found the entire quantum of liquid fuels cannot be
displaced by gas as there is a requirement for process and start-up fuels. We have assumed 80% of liquid fuel
consumption in refineries can be displaced by gas. Of a total installed capacity of 193mtpa, ~62% of the
refineries are gas-based, which implies a consumption of up to 20mmscmd of gas. We estimate gas demand
from refineries to increase to 19.31mmscmd in FY16 as against 12.55mmscmd in FY11, showing a five-year
CAGR of 9%. Growth in refinery gas consumption will receive impetus from: i) Existing gas-based refineries
which currently use only 39% of their capacity, ii) Conversion opportunity for refineries with capacity of 73mtpa
(which can consume gas of up to 20mmscmd), and iii) Consumption from new refineries/expansion of existing
refineries in Nagarjuna, Bhatinda, Bina and Kochi.
City gas distribution: Catapulting gas into new orbit
The city gas distribution sector is expected to witness higher growth among gas consumption verticals on
account of favourable cost economics and stricter emission norms to reduce CO2 emission/unit of GDP by 20-
25% during 2005-20. The key driver of CGD growth would be operating cost savings emerging from using
different fuels like diesel and LPG. We believe that in the current environment, where the government has
managed to de-regulate only petrol prices so far, CNG vehicles will predominantly drive growth in the CGD
segment. Though the running costs of domestic LPG and diesel vehicles still make it viable to switch to CNG,
blending of high-cost LNG decreases cost savings on those fuels.
We estimate demand in the CGD space to register 18% CAGR over the next five years (highest among
gas consumer verticals) at 31mmscmd in FY16E compared to 13mmscmd in FY11. The CGD
consumption pie out of total gas supply is expected to increase to ~12% from 9% currently. A switchover
from petrol to CNG vehicles results in cost savings of 60-70% if 80-90% domestic gas is blended, but the
savings would drop to 30-35% on switching fully to imported gas. However, transition from other fuels like
diesel and LPG will depend entirely upon the availability of cheap domestic gas as a complete switch-over to
gas at market-determined rates would make the proposition unviable given the fact that the prices of diesel
and LPG continue to be regulated.
Currently, the transportation sector consumes less than 2% of natural gas in the country. As the domestic gas
grid expands and reaches more cities, its prospects in the transportation sector will also brighten. There are
currently 1.6mn natural gas vehicles in the country which are expected to increase to 5.8mn over the next 10
years. Delhi alone accommodates more than 0.4mn vehicles. Around 30 cities have access to CNG with the
pipeline network expected to increase to 15,000km and city gas distribution network to cover around 150-200
cities by 2014. On the back of marketing and infrastructure exclusivity, CGD will continue to remain an
attractive proposition. Although network tariff is regulated, there is no cap on marketing margin. Our interaction
with PNGRB suggests there will be no intervention from the regulator unless it suspects the possibility of
profiteering. Under the gas utilisation policy, the CGD sector is given priority after fertiliser, power generation
and LPG. Growth prospects of CGD can be gauged from the fact that companies which are entirely reliant on
imported LNG have shown tremendous growth despite surging prices. In December 2011, GSPC’s gas
supply overtook all central government and private sector-controlled CGD companies by topping the
4.4mmscmd of supply through distribution.
CNG roadmap
2009-14
No of potential cities 298
Investment required (US$bn) 7.43
Likely gas requirement (mmscmd) 74.34
Potential households (mn) 14.87
Potential vehicles (mn) 3.71
2015-20
New cities added 117.00
Estimated demand (mmscmd) 16.30
Capex (US$bn) 1.63
2020-25
New cities added 69.00
Estimated gas demand (mmscmd) 10.32
Capex (US$bn) 1.32
Source: GAIL
Power sector groping in darkness
After RIL’s discovery of gas in the Krishna Godavari Basin D6 block (with initial peak production reaching 61
mmscmd), a plethora of private and government power utilities announced gas-based capacity addition in
anticipation of cheap domestic gas. In his backdrop, the petroleum and natural gas ministry had, in March
2010, estimated gas-based capacity to touch 36,617MW by end of FY15. Today, however, caught between
the pincer of dwindling gas volumes from KG-D6 block and the absence of alternative domestic supplies
before FY14, we forecast moderation in the construction of gas-based power stations unless there is a
significant ramp-up in domestic supply or policy making undergoes an overhaul. Recently, Rural Electrification
Corporation (REC) and Power Finance Corporation (PFC) agreed to resume giving short-term loans to the
discoms of Rajasthan Uttar Pradesh, Punjab, Haryana, and Tamil Nadu after revising the lending guidelines,
key among them being submission of audited accounts, regular tariff revision and timely payment by
respective state governments on account of the subsidy provided to agriculture and retail segments.
Slim chances of across-the-board limit on marketing margin
The oil ministry has asked the gas regulator, PNGRB to establish the quantum of marketing margin
chargeable by a gas marketer. Our interaction with PNGRB officials indicated that as per the established law,
it has no legal standing in capping margin unless under Section 11(a) it finds concrete evidence of profiteering
or unless natural gas gets a notified status. We believe companies having direct exposure to domestic gas will
be at risk if the margin is capped. GAIL’s FY13E EPS could erode by ~3-3.5% if the marketing margin is
capped on domestic gas. Marketing earnings of Petronet LNG, of late, should be construed as a cyclical factor
on tight supply conditions and increased efficiency. CGD companies like Gujarat Gas & Indraprastha Gas are
not entitled to show margin/price breakdown unless natural gas is notified, although we feel the higher RoCE
they currently enjoy will gradually moderate on diminishing pricing power.
Our interaction with ex-PNGRB chairman and the management of various companies in the gas chain
revealed the following:
• As per the PNGRB Act, there is no provision for the gas regulator to decide the marketing margin and the
legality of capping marketing margin can be challenged in a court of law.
• The gas regulator can take recourse to intervention under Section 11(a) of the PNGRB Act to protect the
interests of consumers by fostering fair trade and competition among the entities. The regulator, through
an in-built clause, can intervene in pricing if it finds concrete evidence of profiteering.
• Under Section 11(f) of the PNGRB Act, the regulator can monitor prices and take corrective measures to
prevent restrictive trade practices by the entities, but until now, neither any of the petroleum products nor
natural gas has been notified.
• Petronet’s management believes that the matter relating to marketing margin primarily relates to domestic
gas whose price is regulated by the government. Prices of spot RLNG are subject to global dynamics and
marketing efforts on each cargo varies, thus leaving little room for regulating margins on spot cargo.
Customers subscribing to RLNG are the ones who have switched from liquid fuel after realising
favourable cost economics and if they are willing to fork out higher prices, there should be no cause for
concern from the regulator’s end.
We believe the concern over marketing margin on gas will gradually ease. We believe the cap on marketing
margins should be limited to domestic gas, as the agenda note of MOPNG dated 21 December 2011 clearly
stated that the marketing margin pertains to KG-D6 gas so as to keep the price for end consumers
reasonable.
(a) Difficulty in determining the marketing cost of individual transactions as decided between buyers and
sellers. It may be recalled that prior to the domestic gas supply crunch in FY10, Petronet charged zero
marketing margin on spot RLNG cargo. (Even nowadays, clients with whom the supplier enjoys
favourable relations have access to zero marketing charges). Thus, high marketing margin enjoyed by
GAIL and PLNG, supported by spot RLNG cargo, is not the result of overcharging but of scarce supply.
The possibility of Petronet charging abnormally high marketing margin seems to be remote as Shell’s
terminal in Hazira is operational and if prices appear too high for buyers, they can switch to the other
terminal. The genesis of the concern on marketing margin arose from the disputes over overcharging the
core sector (fertiliser); as Petronet caters to non-core customers who invariably inspect RLNG’s cost
economics before subscribing, it should not attract the regulator’s scrutiny under Section 11(f) of the
PNGRB Act.
(b) Distribution companies like Gujarat Gas and IGL are likely to catch the regulator’s attention on account of
historically high RoCE (more than 20%) earned; nonetheless we believe that because of weakening
pricing power, the return ratios of these companies will decline in the next three-four years. Given that
IGL’s marketing exclusivity period has come to an end in December 2011, the possibility of super normal
profit has automatically eased in the wake of upcoming competition.
(c) GAIL earns a fixed marketing margin on gas from all sources: APM gas margin is fixed at
US$0.11/mmBtu, PMT, RLNG (Ras Gas) margin at US$0.17/mmBtu and spot cargo marketing margin
works in same way like that of Petronet LNG. While the market harbours serious reservations on the
sustainability of GAIL’s marketing margin, we would like to point out that the inventory and price risk
borne by GAIL warrants a leeway in deciding the marketing margin.
(d) The gas regulator already has a backlog of pending decisions that are crucial for the development of the
gas sector (award of CGD third and fourth rounds, final tariff decision on GSPL). Given the long-drawn
process of the gas regulator inviting the companies to present their case, build a framework and then put
a paper out for discussion, the exercise could take more than year to complete, even in a fast-track mode.
Upcoming gas infrastructure to allay tight gas supply fears
Indian companies are investing US$28-37bn in gas infrastructure over the next four-five years. With the
infrastructure in place, gas supply potential over next five years will increase to 336mmscmd from 185
mmscmd, of which ~40% would be accounted for by RLNG terminals. With Petronet’s Kochi terminal likely to
be operational from 3QFY13 and GAIL’s partial capitalisation of DVPL, the Dabhol-Bangalore and Kochi
pipeline would reap the benefits of the huge capex incurred in FY13.
An underdeveloped pipeline infrastructure remains a key impediment that threatens to distort the demandsupply
equation. PNGRB plans to build a national grid (on the lines of US and Europe) to supply gas at major
hubs in India. As per the draft report on natural gas by the oil ministry, total gas pipeline length is likely to
touch 30,000km (822mmscmd) in the next five years from the current length of 13,508km (339mmscmd).
Further, investments in this space are likely to be in the range of US$28-37bn (midstream and downstream) in
the same period. We feel demand growth will be a function of timely completion of the infrastructure laid for
the gas sector on the back of gas assuming a higher proportion in the energy mix (21% in 2020 from 11%
currently).
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