Gas Price Hike Impact

GAS PRICE HIKE: IMPACT ANALYSIS
Analyst Contacts
K. Ravichandran
ravichandran@icraindia.com
+91-44-4596 4301
Girishkumar Kadam
girishkumar@icraindia.com
+91-22-6179 6341
Prashant Vasisht
prashant.vasisht@icraindia.com
+91-124-4545 322
Pranav Awasthi
pranav.awasthi@icraindia.com
+91-124-4545 373
Ankit Patel
ankit.patel@icraindia.com
+91-79-4027 1562
Website
www.icra.in
 Positive for the upstream sector’s earnings and sentiments;
however, domestic gas availability is unlikely to show
material improvement in the next 4-5 years
 Negative for Power, Fertilizer and CGD sectors
 Positive for LNG marketers as consumers will start
experiencing high cost gas; potential for gas pooling
through additional domestic gas production
Background
The Government of India appointed a committee in May 2012 under the
Chairmanship of Dr. C Rangarajan, Chairman, Economic Advisory
Council to the Prime Minister, to look into several aspects relating to the
Production Sharing Contract (PSC) mechanism in petroleum industry,
including approach to domestic gas pricing. This followed several
contentious developments on the interpretations of PSC clauses,
concerning the industry players, Ministry of Petroleum & Natural Gas
(MoPNG), Directorate General of Hydrocarbons (DGH) and Comptroller
& Auditor General (CAG) of India. After deliberations, the Rangarajan
Committee submitted its report to the GoI in December 2012. As per the
Committee-recommended formula for natural gas, the domestic gas
price would be computed based on the trailing 12-month average of
(a) Volume-weighted net-back pricing of Indian LNG imports
(b) Volume-weighted price of US's Henry Hub, UK's NBP and Japan's
JCC linked price1
The MoPNG had sent the proposal on the new uniform gas price to the
Cabinet Committee of Economic Affairs (CCEA), based on the
recommendations made by the Rangarajan Committee and on June 27,
2013, the latter approved the gas pricing formula which will be applicable
from April 1, 2014 for a period of 5 years. The pricing is for all natural gas
domestically produced – conventional, shale, or coal bed methane
1
The Henry Hub is a distribution hub on the natural gas pipeline system, Louisiana,
USA and lends its name to the pricing point for natural gas futures contracts traded on
the New York Mercantile Exchange and the OTC Swaps traded on the Intercontinental
Exchange (ICE).
The National Balancing Point (NBP), is a virtual trading location for the sale and
purchase and exchange of UK natural gas. It is the pricing and delivery point for the
ICE natural gas futures contract.
The Japan Customs-cleared Crude (JCC) is the average price of customs-cleared
crude oil imports into Japan as reported in customs statistics. It is a commonly used
index in long term LNG contracts in Japan, Korea and Taiwan
ICRARatingFeatureJuly2013

ICRA Special Comment Gas Price Hike: Impact Analysis
ICRA Rating Services Page 2
Chart 1: Movement of INR vs. US$
Source: OANDA and ICRA Analysis
48
50
52
54
56
58
60
62
Rs/US$
(CBM) — with a few exceptions2
and will be reviewed every quarter.
As per the aforementioned formula, the current gas price works out to $8.4/mmbtu as against domestically
produced gas prices of $4.2-5.75/mmbtu (ex-wellhead), spot LNG prices of $13-14/mmbtu (ex-terminal)
and term LNG price of $11.5/mmbtu (ex-terminal). Accordingly, the gas prices for most of the domestically
produced gas that sells at $ 4.2/mmbtu are expected to double. However even if the price of Henry Hub,
NBP and JCC were to remain stagnant, the net-back price for LNG imports in India will increase as the
price of the long term LNG imported into the country gets progressively aligned to the last 12 month
average crude oil prices. Accordingly, the price of domestically produced gas is estimated to increase
progressively.
Additionally, the Indian Rupee has depreciated sharply by about 10.5% against the US dollar since the
beginning of the FY14 and has even plummeted past the Rs. 60/$ mark in recent times. As gas purchase
contracts are denominated in US dollars,
weakening of the rupee increases the INR
purchase price, which benefits gas
producers as the formula driven revenues
increase in INR. However, several
consumers sell in INR, in which case they
remain vulnerable to exchange rate
movements unless they pass on the
burden to consumers.
ICRA believes the recent announcement
on the gas pricing front has wide
ramifications across several sectors and
this article analyses the impact of the
same on some of the important sectors.
Upstream Sector
Hike in gas price to incentivise investment in upstream sector on the back of improved economics;
however, material upside to domestic gas production is at least 5-6 years away
The upstream companies had been demanding revision in gas prices as i) the last revision was about 3
years back — with effect from June 1, 2010, and ii) price of APM gas, which accounts for bulk of the
domestic gas produced, was raised to $4.2/mmbtu in the last revision, which the upstream companies
claimed, left very low margin for the major players in light of sharp rise in the cost of services and materials.
Due to this, upstream companies claimed that they were unable to justify the viability of developing
discoveries made in deepwater and frontier areas, which consequently were not developed. This situation
had exacerbated in the recent years due to sharp run up in the cost of oil field services, contractors and
manpower on account of elevated international crude oil prices that had led to heightened exploration
activities globally due to improved economics.
While some of the domestic upstream companies were demanding domestic gas prices on par with
imported LNG prices, the Dr. Rangarajan Committee formula where the computed prices would fall
somewhere in between the prevailing domestic prices and imported LNG prices. With this price
announcement, ICRA expects the sentiments in the domestic upstream, which was besieged by several
issues such as falling domestic production, limited interest by the major oil companies in India, tax-related
ambiguities, significant delays in regulatory approvals for the NELP projects and uncertainty over the
powers of CAG to audit PSV JVs, to improve. While many of the operational issues remain, ICRA expects
the upstream companies to show more interest to develop discovered fields.
E&P activities get progressively more challenging and cost intensive for onshore, onshore-frontier areas,
offshore-shallow waters, offshore-deep waters and offshore-ultra deep waters — in that order due to
increasing scale of difficulty in accessing the reserves and higher cost of equipments and services on
2
The new pricing guidelines will not be applicable in respect of gas for which prices have been fixed contractually for a certain
period of time, till the end of such period. These guidelines will also not be applicable where the contract provides a specific
formula for natural gas price indexation/fixation e.g. Panna-Mukta-Tapti, Ravva, PY-1 and RJ-ON/6

Table 1: Estimated additional production
Particulars
Estimated increase in reserves (tcf) 35
Proportion of reserves recoverable 70%
Life of field (years) 20
Rate of production (mmscmd) 95
Source: ICRA Estimates
account of higher degree of complexity, technical challenge and specialisation. Therefore according to
upstream companies, progressively higher prices signals are necessary for incentivising E&P activity in the
aforementioned areas. As per IHS Cera, a renowned consultant in the Oil & Gas sector, which has mapped
the various Indian geological basins, while Indian onshore gas is economical to develop between US$6-
8/mmbtu realisation, ultra-deep water requires gas price of US$10-12/mmbtu and beyond for commercial
exploitation with other categories falling in between these extremes. As most of the conventional and
unconventional resources in the country are endowed in the more challenging and higher cost offshore
areas, the increase in gas price to US$8.4/mmbtu improves the viability of a limited percentage of total
resources (estimated at an additional 35 tcf) — mostly onshore and offshore shallow water with very limited
deep sea and no ultra-deep resources becoming viable. From the estimated 35 tcf of gas becoming viable,
if 70% is assumed to be recoverable, then an additional 95 mmscmd gas is expected to be produced as
shown in table below.
Consequent to the price revision, several large discoveries such as by ONGC (in KG Basin block KG-
DWN-98/2, Mahanadi Basin block MN-DWN-98/3) are expected to be developed post regulatory approvals.
Moreover, it is expected that RIL would also attempt to increase production from its KG-D6 fields by
undertaking production enhancement programmes. Besides, the company is likely to go ahead with the
development of KG satellite fields and NEC field.
While the exploration and development activities should pick up and the future NELP rounds should see
relatively better response, ICRA is of the opinion that material upside to domestic gas production will be
only after 5-6 years in view of the regulatory approval delays, which are endemic in this sector, and long
lead time for development of the projects.
Bottom lines of upstream companies to see a boost; however increased subsidy burden by GoI
could negate some benefits for PSU companies
The upstream sector would be a key gainer of the gas price hike. The impact on the net profits of ONGC is
expected to be Rs. 20 billion and for OIL Rs. 2.4 billion for every $1/mmbtu rise in gas prices. For RIL the
impact at PBIT level is expected to be about US$ 400 million on account of gas price hike. Additionally, as
the sales of upstream companies are dollar-denominated, weakening of the Indian Rupee versus the US
Dollar would benefit these companies in terms of higher INR revenues. However, the upside for ONGC and
OIL would be limited if GoI decides to impose a higher subsidy burden or levy a higher cess. In view of the
anticipated rise in gross under-recoveries due to depreciation of the rupee, the subsidy sharing burden for
upstream companies would remain elevated in FY14 and FY15. Furthermore, GoI has aggressive fiscal
deficit reduction targets, which might entail that upstream companies share a higher share of subsidy, as
they will be benefited by INR weakening as well as rise in natural gas prices.
Petrochemicals / LPG Sector
Adverse impact on GAIL’s financials; subsidy burden, however, could be reduced which would
alleviate the pain
The petrochemicals sector, notably GAIL, uses 8-9 mmscmd of rich gas for i) extraction of C2 which is
used for the production of polyethylene and ii) extraction of C3/C4 for production of LPG. As raw material
costs account for ~80% of the manufacturing costs, the same are set to double with increase in gas prices.
Accordingly, the profits of GAIL are expected to be impacted to the tune of Rs. 13 billion at pre-tax level.
GAIL may, however, get a relief from the GoI on account of subsidy sharing. GAIL was asked to share the
gross under-recoveries of PSU OMCs as part of the overall upstream sector contribution, as it was getting
cheaper domestic gas, while selling its products (polymers, LPG and various liquid hydrocarbons) on

Table 2: Fertiliser Sector Gas Requirements
Particulars Units Value
Gas required by existing units mmscmd 47.0
Gas required for conversion of naphtha / FO
/ LSHS based units
mmscmd 9.93
(5.03 currently)^
Current supply of domestic gas to fertiliser
industry
mmscmd 30.0
Source: DoF, ICRA Analysis; ^ Includes plants which have already converted to natural gas: Three plants of National
Fertilizers, Gujarat Narmada Valley Fertilizers & Chemicals Ltd. and Zuari Agro Chemicals Ltd.
Chart 2: Variation in Cost of Production and RP with Increase in Gas
Prices
(Source: ICRA Analysis; Assumptions: 1.27 MMTPA urea plant; energy efficiency of 5.5
GCal/MT at USD 57/INR; calorific value of 8,200 KCal/scm. Capex of Rs. 4,200 crore.
Contribution margins remain stable.)
import parity basis. With gas prices moving to market-determined levels from subsidised levels earlier,
GAIL may request for waiver or reduction of subsidy burden which stood at Rs. 27 billion in FY13.
Fertiliser Sector
Increase in domestic gas cost to increase cost of production of urea and increase subsidy
requirements; currency fluctuations to impact subsidy as well
Natural gas is used as feedstock and fuel in the fertiliser sector. It is used as a feedstock in the production
of ammonia, which is an intermediate in urea production and certain NPK fertilisers. Urea is the main
fertiliser produced in the country, accounting for ~55-60% of domestic production of fertilisers. Besides,
natural gas is also used by certain fertiliser-chemical complexes to produce certain chemicals, such as
ammonia and its derivatives (ammonium nitrate, nitric acid, caprolactum and ammonium bicarbonate),
methanol and its derivatives (acetic acid, formic acid, methyl formate and methyl amines), etc.
The domestic fertiliser industry has a requirement of 47.8 mmscmd of gas presently. Further, there is an
additional requirement of gas to the extent of 9.93 mmscmd to convert the naphtha / FO / LSHS-based
units to natural gas. ~85% of the natural gas requirement currently is for production of urea. Of this
requirement, domestic gas is being utilised to the extent of 30 mmscmd currently.
The major impact on the fertiliser industry would be in the form of an increase in subsidy receivables and
would lead to an increase in the working capital requirements. Further, it would impact the profitability of
revamped urea capacities earning IPP-based pricing and those of non-urea fertilisers under NBS such as
ammonium nitro-phosphate, which are produced using domestic gas. Subsidy flow from the GoI will also
depend on the currency
fluctuations, since gas prices are
determined in US Dollars. Further,
it may lead to an increase in
interest cost due to higher working
capital intensity in case of delays
in subsidy payments as has been
observed in the recent past,
thereby impacting net profitability.
Impact on Urea Industry
Impact on urea production
costs and retention prices for a
typical plant: The retention prices
of urea depend on cost of
production, which in turn is
dependent on gas price. GoI
would compensate the increase in
cost of production on account of
increase in gas prices. Under the
current subsidy framework for
urea, since gas price is a pass-
through, use of higher cost gas does not impact absolute operating profits, although operating margins will
decrease due to high base effect of higher cost gas leading to higher product realisations. For a typical
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
0
5,000
10,000
15,000
20,000
25,000
30,000
5.50 7.00 8.50 9.50 11.00 12.50 14.00 15.50
Rs/MT
US$/mmbtu
Variable Cost Retention Prices
Gas Cost as % of RP

plant having energy consumption of 5.5 GCal/MT of urea, energy costs are estimated at ~70% of retention
prices currently. Given that contribution margins would not increase and the GoI would only increase the
subsidy for the increased cost of production, the energy costs would increase to 79-84% of the retention
prices (depending on rupee fluctuations). However operating profits in absolute terms might not be
impacted in case of timely subsidy flows.
Table 3: Retention Price of 1 MT of urea at delivered gas price of USD 5.5/mmbtu
Energy Efficiency
(GCal/MT)
Currency Rates (Rs/US$)
48 51 54 55 57 60 63 65
5.00 9,760 10,159 10,558 10,691 10,958 11,357 11,756 12,022
5.25 10,079 10,498 10,918 11,057 11,337 11,756 12,175 12,455
5.50 10,399 10,838 11,277 11,423 11,716 12,155 12,594 12,887
5.75 10,718 11,177 11,636 11,789 12,095 12,554 13,014 13,320
6.00 11,037 11,516 11,996 12,155 12,475 12,954 13,433 13,752
6.25 11,357 11,856 12,355 12,521 12,854 13,353 13,852 14,185
6.50 11,676 12,195 12,714 12,887 13,233 13,752 14,271 14,617
6.75 11,996 12,535 13,074 13,253 13,612 14,151 14,690 15,050
7.00 12,315 12,874 13,433 13,619 13,992 14,551 15,110 15,482
7.25 12,634 13,213 13,792 13,985 14,371 14,950 15,529 15,915
7.50 12,954 13,553 14,151 14,351 14,750 15,349 15,948 16,347
7.75 13,273 13,892 14,511 14,717 15,130 15,748 16,367 16,780
8.00 13,593 14,231 14,870 15,083 15,509 16,148 16,786 17,212
Table 4: Retention Price of 1 MT of urea at delivered gas price of USD 9.7/mmbtu
Energy Efficiency
(GCal/MT)
48 51 54 55 57 60 63 65
5.00 14,638 15,342 16,046 16,281 16,750 17,454 18,158 18,628
5.25 15,201 15,940 16,680 16,926 17,419 18,158 18,898 19,391
5.50 15,764 16,539 17,313 17,572 18,088 18,863 19,637 20,153
5.75 16,328 17,137 17,947 18,217 18,757 19,567 20,376 20,916
6.00 16,891 17,736 18,581 18,863 19,426 20,271 21,116 21,679
6.25 17,454 18,334 19,215 19,508 20,095 20,975 21,855 22,442
6.50 18,018 18,933 19,848 20,153 20,764 21,679 22,594 23,205
6.75 18,581 19,531 20,482 20,799 21,433 22,383 23,334 23,967
7.00 19,144 20,130 21,116 21,444 22,102 23,087 24,073 24,730
7.25 19,708 20,728 21,749 22,090 22,770 23,791 24,812 25,493
7.50 20,271 21,327 22,383 22,735 23,439 24,496 25,552 26,256
7.75 20,834 21,926 23,017 23,381 24,108 25,200 26,291 27,019
8.00 21,397 22,524 23,651 24,026 24,777 25,904 27,030 27,781
As can be seen from the tables, the key determinants of subsidy would be currency rates and the energy
efficiencies of the plants. Better energy efficiency would lead to lower cost of production and lower subsidy
outflow for the GoI. Weakening of rupee would lead to higher cost of production, thereby increasing subsidy
outflow.
Source: ICRA Analysis; Base retention price at delivered gas price of US$ 5.5/mmbtu and currency rate of Rs. 55/US$ is Rs.
11,423/MT, which increases to Rs. 12,155 at Rs. 60/US$
Source: ICRA Analysis; Assuming no change in contribution margins

Table 5: Increase in Retention Prices on account of a USD 4.2/mmbtu increase in delivered gas prices
Energy Efficiency
(GCal/MT)
48 51 54 55 57 60 63 65
5.00 4,878 5,183 5,488 5,589 5,793 6,098 6,402 6,606
5.25 5,122 5,442 5,762 5,869 6,082 6,402 6,723 6,936
5.50 5,366 5,701 6,037 6,148 6,372 6,707 7,043 7,266
5.75 5,610 5,960 6,311 6,428 6,662 7,012 7,363 7,597
6.00 5,854 6,220 6,585 6,707 6,951 7,317 7,683 7,927
6.25 6,098 6,479 6,860 6,987 7,241 7,622 8,003 8,257
6.50 6,341 6,738 7,134 7,266 7,530 7,927 8,323 8,587
6.75 6,585 6,997 7,409 7,546 7,820 8,232 8,643 8,918
7.00 6,829 7,256 7,683 7,825 8,110 8,537 8,963 9,248
7.25 7,073 7,515 7,957 8,105 8,399 8,841 9,284 9,578
7.50 7,317 7,774 8,232 8,384 8,689 9,146 9,604 9,909
7.75 7,561 8,034 8,506 8,664 8,979 9,451 9,924 10,239
8.00 7,805 8,293 8,780 8,943 9,268 9,756 10,244 10,569
Impact on subsidy requirements for urea and industry profitability: ICRA estimates that an increase of
US$1/mmbtu increases the domestic cost of production of urea by Rs. 31.2 billion. Depreciation of the
rupee by Rs. 1/US$ further increases gas costs by Rs. 0.6 billion. An increase of ~US$4.2/mmbtu would
increase the cost of production for the urea industry by ~Rs. 131 billion (assuming a currency rate of Rs.
57/US$). While gas price remains a pass-through for urea under the current subsidy regime, the additional
cost would increase the subsidy payable to that extent and correspondingly, the working capital
requirements of the urea players in case of delays in payment of subsidy as observed in the recent past,
also entailing additional interest costs.
Impact on profitability of urea beyond cut-off quantity linked to IPP-based realisations: A significant
impact of increase in gas prices would be on the profitability of players having undertaken revamp projects
under the Urea Investment Policy of 2008, which are eligible to earn realisations based on import parity
based (IPP) for the incremental urea production. Many players who had undertaken the revamp projects
were earning significant profits under this scheme. Following the increase in gas prices, these players will
have to face higher cost of production, while the realisations would continue to be based on IPP-based
prices. This would have a significant impact on the profitability of these players. ICRA estimates that the
profitability of the industry would be affected to the extent of ~Rs. 12.14 billion (at a currency rate of Rs.
57/US$).
Table 6: Impact on profitability from urea beyond cut-off quantity earning IPP-based realisations
Particulars
Gas at
US$5.5/mmbtu
Gas at
US$9.7/mmbtu
Exchange Rate (Rs/US$) 57
Energy Consumption (GCal/MT of urea) 5.50
Calorific Value (KCal/scm) 8200
Gas Cost (Rs/MT) 8,344 14,413
Urea IPP (US$/MT) 350 400 350 400
Urea Realisation – 85% of IPP (Rs/MT) 16,958 19,380 16,958 19,380
Contribution Margin (Rs/MT) 8,614 11,036 2,545 4,967
% decline in contribution margin - - 70% 55%
Decline in industry profitability (Rs. Cr.)
(Assuming 2 MMT IPP-linked production)
- - 1,214
Source: ICRA Analysis

Impact on profitability of surplus ammonia produced by urea manufacturers: In case of surplus
ammonia produced by a few urea players (such as Krishak Bharati Cooperative Ltd. (KRIBHCO), Rashtriya
Chemicals & Fertilizers Ltd. (RCF)), 35% of the gains are shared with the GoI in case of urea production at
100% of re-assessed capacity and beyond., As the cost of production of ammonia would increase on
account of increase in gas prices and ammonia is sold in the market at import parity prices (IPP), their
margins will get compressed. This would lead to a decline in profits (depending on IPP of ammonia) that
some of the urea units were earning from surplus ammonia sales.
Table 7: Impact on profitability from surplus ammonia production in case of urea production of >100% of
re-assessed capacity
Particulars
Gas at
US$5.5/mmbtu
Gas at
US$9.7/mmbtu
Energy Consumption (GCal/MT of ammonia) 7.80
Gas Cost (Rs/MT) 11,834 20,870
Ammonia IPP (US$/MT) 550 650 550 650
Ammonia Realisation (90% of IPP) (Rs/MT) 28,215 33,345 28,215 33,345
Impact on profitability of non-urea fertilisers and industrial chemicals
Impact on profitability of non-urea fertilisers: The profitability of some of the players (such as Deepak
Fertilisers & Petrochemicals Ltd. (DFPCL), Gujarat Narmada Valley Fertilizers & Chemicals Ltd. (GNFC),
Gujarat State Fertilizers Corporation Ltd. (GSFC) and Rashtriya Chemicals & Fertilizers Ltd. (RCF)), which
manufacture certain non-urea fertilisers from domestic gas, may be impacted to that extent – unless the
GoI revises the subsidies payable for these fertilisers to account for the increase in production costs. When
international ammonia prices are subdued (<$400-420/MT), importing ammonia could be a cost effective
option rather than producing in-house for these fertilisers.
Impact on production costs of industrial chemicals: Chemicals manufactured by various players having
fertilisers-cum-chemicals complexes (such as DFPCL, GNFC, GSFC and RCF) are largely through gas
procured at APM / RIL, so the profitability of these companies from chemicals manufacturing will be
modestly impacted. In case of ammonia manufactured by these companies for the production of P&K
fertilisers, the gas cost would increase to the extent of 76% (at a currency rate of Rs. 57/US$) as indicated
above. The DoF is working out a mechanism to mop up benefits from ammonia manufactured by these
companies vis-a-vis imported ammonia. While the benefits will reduce vis-a-vis imported ammonia, any
recovery of the past benefits enjoyed will continue to be an event-based regulatory risk.
Table 8: Impact on profitability of methanol
Particulars
Gas at
US$5.5/mmbtu
Gas at
US$9.7/mmbtu
Natural Gas Requirement (scm/MT of methanol) 695
Gas Cost (Rs/MT) 8,646 15,249
Methanol IPP (US$/MT) 350 400 350 400
Methanol Realisation (100% of IPP) (Rs/MT) 19,950 22,800 19,950 22,800

Chart 3: Subsidy Outflow for Fertilisers
(Source: FAI, DoF, ICRA Analysis)
Further, profitability from production of methanol, nitric acid, etc. would be impacted. Since realisations in
the case of these chemicals are dependent on IPP-based pricing, the increase in production costs has a
direct impact on profitability. As can be seen from the Table 8 above, the increase in gas cost would lead to
severe compression of the contribution margins of methanol. Further, given that methanol prices have
remained low in the international market on account of significant capacities having low-cost gas as
feedstock having come onstream in the recent past, domestic production of methanol may be affected
following the increase in gas prices. This may also have an impact on profitability of downstream products,
such as acetic acid, formic acid, methyl amines, etc.
The silver lining: Improved prospects of domestic gas availability in the medium-to-long term
The positive aspect of the increase in gas price is that it will improve the viability of exploration for oil and
gas producers, which may lead to an increase in domestic gas production. Given that the fertiliser sector
enjoys the top priority for gas allocation, any increase in gas production will be positive for the industry.
Over the medium-to-long term, it may decrease the dependence of the industry on higher cost R-LNG,
which may reduce the subsidy requirement to that extent.
Overall, negative for the fertiliser industry in terms of dependence on subsidy and impact on
profitability; timeliness of subsidy payment to determine impact on individual entities
Overall, in ICRA‘s opinion, the increase in gas prices is negative for the fertiliser industry from the credit
perspective, given that dependence of the industry on subsidy would increase, which exposes the industry
profitability and cash flows to timeliness of
subsidy receipts. Further, operating
profitability may also be impacted on
account of reasons mentioned above.
ICRA expects that the working capital
requirements of the players will increase
substantially and may impact the net
profitability, in case of delays in subsidy
payments. Some of the players with a
highly leveraged capital structure might
be more affected than the others.
Further, the profitability of companies
manufacturing non-urea fertilisers and
having dependence on gas may decline
in case subsidies are not provided to that
extent. Overall, ICRA believes that
timeliness of subsidy payments will be an even more critical variable going forward in assessment of
creditworthiness of the fertiliser industry.
Power Sector
Cost of power generation to rise significantly and also, remains highly sensitive to both volatility in
international gas price & INR-USD exchange rate
As shown in Chart 4, overall cost of gas based power generation (at delivered cost of ~9.5 USD/mmbtu) is
estimated at 5.5 Rs./kwh which reflects a sharp increase of about 47% over that power generated with gas
at currently prevailing delivered cost of ~5.5 USD/mmbtu. For every 1 USD/mmbtu increase in cost of gas,
cost of generation shows an increase of 44 paise/unit, under the assumption of prevailing exchange rate at
60 INR-USD, while for depreciation of INR against USD by 1 INR, cost of generation shows an increase of
5-7 paisa/unit. As a result, cost of power generation will remain vulnerable to volatility in gas prices
internationally as well as the INR-USD exchange rate.
In case domestic gas availability3
were to remain at the current level for the power sector, hike in the gas
price would lead to additional cost impact of 10-12 paise/kwh for the distribution utilities on all India basis at
3
Average PLF for gas based capacity on all India basis in FY 2012-13 stood at 40.3% for the installed capacity of 20,100 MW,
which has further come down to 29.6% in the month of May 2013. Gas based generation accounted for 6% of overall electricity
generation in the country in FY 2012-13.
119 159 231 310 246 243
378 354
66
103
169
656
395 415
364
306
0
200
400
600
800
1000
1200
FY06 FY07 FY08 FY09 FY10 FY11 FY12 FY13
(RE)
Rs.Billion
Urea P&K

higher gas cost (i.e. at 9.5 USD/mmbtu) &at prevailing exchange rate. This rise will constitute about 3-4%
of overall cost of power generation. However, the impact on cost of power purchase for the utilities would
be relatively more in case of states in southern and western region which account for about 35% and 40%
of the gas based capacity (both the operational & under implementation) respectively.
Majority of the gas based capacity is cost-plus based through long term PPAs with the state-owned
distribution utilities wherein the fixed capacity charges are paid by the off-taker at a normative plant
availability of 80%. For the power sector, while the cost of generation will thus go up, profitability may not
be impacted for the generators who have signed ―normative cost plus return PPA‖ with discoms in case of
gas availability at normative levels, although their cost-competitiveness will be affected. However, given the
sharp decline in domestic gas availability in the past 12 months & reluctance of off-takers/distribution
utilities to allow the declared availability using costlier R-LNG source, there remains a risk of under-
recovery in fixed capacity charges. Further, the operations for certain companies, who operate on either
merchant mode or on fixed tariff under short term PPAs, will be adversely affected. Moreover, such plants
would also be exposed to the lowest priority in domestic gas availability.
Gas to be less competitive compared to domestic coal; although increased fuel supply risks with
dependence on coal imports as well as high competitively bid tariffs as observed in recent past,
alleviate pressures to some extent
As seen from Chart 5, cost of gas based power generation at delivered cost of 9.5 USD/mmbtu is higher by
about 85% as against the cost based on 100% domestic coal linkage, and the same is aided by the fact
that price of domestic coal is still at a considerable discount (~65%) of the prevailing international prices.
Further, cost of generation based on 100% imported coal for a coastal plant as well as for a plant located at
a hinterland location with a blending mix of 1:14
for domestic and imported coal, is estimated in the range of
Rs. 3.8~4.0/kwh. This leads to the gas-based power at delivered cost beyond 7 USD/mmbtu at prevailing
exchange rate, not remaining cost-competitive.
ICRA however notes that, despite the constraints in the paying capacity of the discoms in many states,
average quoted tariffs by IPPs in the ‗Case 1‘ bidding procurement done by state owned utilities in the few
states (such as in Tamil Nadu, Rajasthan & Uttar Pradesh in last six month period) have increased sharply
and stood in the range of Rs. 5-6/kwh. As a result, gas with delivered cost ranging between 9~10
USD/mmbtu could be viable given the competitively bid tariffs (based on coal) as observed recently.
However, tie-up of PPAs on long term basis by utilities with IPPs at a higher tariff level (ranging between
4
Actual coal imports for the power sector has increased to 104 MMT in FY 2012-13, an increase of 84% over the previous year
and accounted for about 20% the overall coal consumption by the sector. The dependence on coal imports is estimated to
increase to about 210 MMT by FY 2016-17. While Coal India Ltd expects to supply 65% of linkage quantity for the power plants
commissioned after March 2009 till March 2015, actual coal availability could remain in the range of 50~60% of linkage
quantity.
Chart 4: Sensitivity of Cost of Power Generation to Cost
of Gas
Gas
Price
Exchange Rate
48 51 54 57 60 63 66
6 3.4 3.5 3.7 3.8 3.9 4.1 4.2
7 3.8 3.9 4.1 4.2 4.4 4.5 4.7
8 4.1 4.3 4.5 4.6 4.8 5.0 5.2
9 4.5 4.7 4.9 5.1 5.3 5.5 5.7
10 4.8 5.0 5.3 5.5 5.7 5.9 6.1
11 5.2 5.4 5.7 5.9 6.1 6.4 6.6
12 5.5 5.8 6.1 6.3 6.6 6.9 7.1
13 5.9 6.2 6.5 6.7 7.0 7.3 7.6
14 6.2 6.5 6.9 7.2 7.5 7.8 8.1
15 6.6 6.9 7.2 7.6 7.9 8.2 8.6
16 6.9 7.3 7.6 8.0 8.3 8.7 9.1
[Source : ICRA Estimates; Assumptions : Cost of Power Generation = Fixed Cost + Variable Cost; Fixed Cost = 1.35 Rs./kwh estimated based on
CERC‘s normative principles & Capital Cost at Rs. 45 million/MW; Variable cost is estimated based on GCV of 9500 Kcal/Scm, and Station Heat Rate
of 1850 Kcal/kwh; Exchange rate at 60 INR/USD]
5.5 7 8 9.5 10 12 14 16
3.72
4.38
4.82
5.48 5.70
6.59
7.47
8.35
0
2
4
6
8
10
0.0
3.0
6.0
9.0
12.0
15.0
18.0
I II III IV V VI VII VIII
CostofGeneration
DeliveredCostofGas
Delivered GasCost(LHS)USD/MMBTU Overall Cost ofGeneration(RHS)Rs./kwh
Table 9: Sensitivity for Overall Cost of Power Generation to
Exchange Rate (INR/USD) & Cost of Gas (USD/mmbtu)

Rs. 5~6/kwh) remains to be seen due to currently constrained financial position of the state owned utilities
in many states.
Timeliness in fuel & power purchase cost adjustment (FPPCA) recovery & tariff revision would be
critical to improve cash flows for distribution utilities; Subsidy dependence for the utilities is also
expected to rise further
With increasing cost of supply for the utilities and slow progress in tariff rationalisation over the period,
overall subsidy dependence for the sector for FY2013-14 is now estimated to have increased to about Rs.
600 billion from that of Rs. 340 billion in FY2009-10. This is likely to go up further, if the progress on tariff
rationalization continues to remain slow so as to avoid tariff shock for the subsidized categories
(domestic/below poverty line/agriculture) even while cost of power purchase is expected to rise with
increasing dependence on costlier imports & exposure to volatility in international fuel prices (coal & gas).
Also as observed, in states (such as in Rajasthan, Uttar Pradesh, Andhra Pradesh & Tamil Nadu) where
tariffs for subsidized categories have been increased recently by SERCs for FY 2013-14, incremental tariff
burden on such consumers has been borne by state governments through additional subsidy support, for
FY 2013-14;, similar support cannot be ruled out in other states as well. Further, delays continue by utilities
in many states with respect to filing for FPPCA petitions and recovery on periodic basis, despite the
principles of FPPCA framework already being approved by SERCs. Overall, ICRA notes that timeliness in
tariff revision along-with periodic FPPCA, adequate subsidy releases from State Governments as well as
efficiency improvements in line with the regulatory targets would remain critical to improve their cash flows,
for the viability of entire power sector.
CGD Sector
Steep hike in CNG and PNG prices likely by players having a high allocation of APM gas; CNG has
the ability to absorb the price increase; however, PNG domestic segment would be rendered
uncompetitive against LPG
Higher APM gas prices are likely to result in an increase in gas sourcing costs for CGD players having a
higher APM gas allocation. CGD players like - Indraprastha Gas Limited (IGL) and Mahanagar Gas Limited
(MGL) have the maximum allocation of domestic gas are likely to pass on the gas price increase to
maintain their contribution margins once the gas price hike is in place from April 1, 2014.
In the case of CNG, the current prices of NCR region operator – IGL, who has about 70% of its total gas
requirements being met through APM gas supply, are Rs 41.9/Kg and if IGL maintains its contribution
margins at the same absolute levels as it has been doing in the past, then its CNG prices are likely to be
raised by 14-15 Rs/kg. ICRA believes that though an increase in price would reduce the overall cost
competitiveness of CNG as compared to the liquid fuels – MS and HSD, at a likely revised price of Rs
Chart 5: Comparison for overall cost of power generation under different fuel-mix Scenarios
Source: ICRA Estimates & CERC Market Monitoring Report for Average Short Term bilateral tariff; Assumptions : Domestic Coal Linkage based
plant assumed at a hinterland location with about 900 km distance from linked mine & about 1200 km distance from port; domestic coal price assumed
(i.e. 660 Rs./MT at pit-head) as per CIL‘s pricing notification for GCV range of 3700-4000 Kcal/Kg; Inland rail transportation cost at Rs. 1/km/MT;
Station Heat rate = 2250 Kcal/kwh; GCV for Imported Coal = 4200 Kcal/Kg; FOB – Indonesia for GCV of 4200 Kcal/Kg = 46 USD/MT (as per notified
Price Index for June 2013); Levellised fixed cost of generation inclusive of return on equity = 1.7 Rs./kwh based on CERC‘s normative tariff principles
& capital cost at Rs. 55 million/MW; Exchange rate at 60 INR/USD
2.9
3.8 3.8
5.5
4.2
5.5
8.4
0
1
2
3
4
5
6
7
8
9
100% domestic coal at
current price which is
about 65% discount to
CIF
50% domestic coal at
65% discount to CIF +
50% Imported coal
100% imported coal for
coastal plant
Competitivelybid tariff
(Case 1 bids during Dec
2012- May 2013)
Short term - bilateral
tradedtariff in FY 2013
Gas at delivered cost of
9.5 USD/mmbtu
R-LNG at deliveredcost
of 16 USD/mmbtu
Rs./kwh

56.6/Kg, the time taken to break even would still remain attractive for vehicle owners to convert to CNG
considering the prevailing prices of these liquid fuels. An illustration of the same is shown in the tables
below:
Table 10: Break even time for conversion to CNG for vehicle owners at current prices for NCT consumers
Running Costs (Rs/km)
Conversion
Costs (Rs)
Break
Even
Km
Avg
km/day
Break
Even
MonthsCNG MS HSD LPG
Car on MS 2.00 4.57 25,000 9,702 50 6.4
Car on Auto LPG 2.00 2.95 17,000 17,799 50 11.7
Taxi on HSD 2.00 3.14 25,000 21,827 150 4.8
Bus 6.98 14.36 180,000 24,411 200 4.0
Auto 1.20 2.66 25,000 17,053 100 5.6
Table 11: Break even time for conversion to CNG for vehicle owners at hiked prices for NCT consumers
Running Costs (Rs/km)
Conversion
Costs (Rs)
Break
Even Km
Avg
km/day
Break
Even
MonthsCNG MS HSD LPG
Car on MS 2.70 4.57 25,000 13,321 50 8.8
Car on Auto LPG 2.70 2.95 17,000 66,632 50 43.8
Taxi on HSD 2.70 3.14 25,000 56,131 150 12.3
Bus 9.43 14.36 180,000 36,557 200 6.0
Auto 1.62 2.74 25,000 22,201 100 7.3
Table 12: Cost competitiveness of PNG (domestic) over LPG for NCT consumers
Fuel
Selling Price
(Rs /
Cylinder)
Energy Cost
(Rs / million
Kcal)^
Fuel
Selling Price
(Rs / m3)
Energy Cost
(Rs / million
Kcal)^
Benefit/ Loss
of PNG (D)
over LPG
At current prices
LPG 410.50 2677 PNG (d) 24.50 2,634 2%
After April 1, 2014
LPG 410.50 2677 PNG (d) 34.50 3,710 -39%
Source: ICRA Estimates; ^Assumptions: GCV of LPG taken at 10,800 Kcal/Kg, GCV of PNG taken at 9,300 Kcal/m3
However, with a near doubling of the cost to the suppliers, which is likely to be passed on, PNG- domestic
segment will lose its competitiveness against domestic LPG which continues to draw subsidy.
The PNG -Industrial & Commercial segment, which has been mostly serviced through sourcing of higher
priced RLNG, would not be impacted by the hike in domestic gas price. Despite moderation in the overall
cost competitiveness due to the increasing prices of R-LNG based CNG, PNG continues to remain
competitive to service the industrial and commercial segments at the existing prices of most alternative
liquid fuels.
In regions with predominant mix of RLNG in the total sourcing – like SGL, GSPC Gas, Gujarat Gas, Adani
Gas, etc, the hike in prices would not significantly impact the operations as their CNG prices are already at
much higher rates since their majority/entire sourcing is R-LNG based.
Further, with the cost of sourcing being dollar denominated, the CGD operators have been under pressure
due to the sharp depreciation in the rupee and most of them have been revising the their prices
periodically. Going forward, the threat of further depreciation in the rupee remains an overhang for the
favourability of the economics of CNG and PNG as energy sources.
Impact on R-LNG marketers
ICRA believes the deregulation process being initiated in the domestic gas sector through higher gas prices
will be positive for the R-LNG marketers. Notwithstanding the upside expected from the incremental

exploration and development efforts, domestic gas production will be far short of domestic demand-both
current unmet and latent demand. Hence, R-LNG is here to stay, whose share in the overall gas
consumption is bound to increase over the long term. While intent to set up at least 10 new R-LNG
terminals have been announced by few sponsors, ICRA believes at least 4-5 terminals by financially strong
sponsors, could materialise over the next 5-6 years. As consumers would have got used to high priced gas
through price adjustments in the economy by the time these terminals come up, it should help the cause of
R-LNG marketers. Moreover, higher domestic gas production will help pool high cost R-LNG with domestic
gas and making it competitive for the sensitive sectors.
Conclusion
The CCEA approval of the Rangarajan gas pricing formula is expected to improve the viability of a modest
proportion of gas resources though any meaningful addition to gas production is some years away due to
the long and complex approvals processes endemic in the sector. However the impact on the bottom lines
of the producers would be immediate once the gas price comes into effect from April 1, 2014 which
however would be tempered for the PSU players if the GoI decides to increase the subsidy burden.
The impact would be negative for all categories of consumers. While the GoI has clarified that pricing
formula has been fixed for the producers of gas, consumer prices could be lower for certain category of
consumers, possibly power & fertiliser sectors, through additional support/subsidy, the timeliness and
quantum of such support remains uncertain at this juncture. For the power sector, while the cost of
generation will go up, profitability may not be impacted for the generators who have signed ―normative cost
plus return PPA‖ with discoms in case of gas availability at normative levels. Further the operations for
certain companies, who operate on either merchant mode or on fixed tariff under short term PPAs, will be
adversely affected. Also, merit order position of gas based power generators will be weakened especially
against coal based power. As regards discoms, those with functioning FPPCA adjustments will be able to
pass on the hike to consumers. However, cost base for other category of discoms will go up and result in
modest pressure on profits.
For the fertilizer sector, while gas price remains a pass-through for urea under the current subsidy regime,
the additional cost would increase the subsidy payable to that extent and correspondingly, the working
capital requirements of the urea players in case of delays in payment of subsidy as observed in the recent
past. Further, the profitability of urea players manufacturing urea beyond the cut-off quantity, which are
eligible to get import parity price (IPP)-based realizations, will also be substantially impacted. Additionally
the profitability of some of the players manufacturing non-urea fertilizers from gas will be impacted unless
the GoI increases the subsidies on these fertilizers to compensate for higher production costs. Cost
structure of companies producing chemicals in integrated fertiliser complexes, will deteriorate and will result
in sharp fall in profits from these products. Overall, the additional subsidy burden would upset the
aggressive fiscal deficit reduction targets of GoI.
With regard to the CGD sector the impact is expected to be relatively muted given that the industrial and
commercial segments of the sector are already catered to by RLNG and only the consumers of APM gas
viz. the domestic and CNG segments would be impacted. While the PNG domestic segment would be
rendered unviable due to unfavourable economics with the highly subsidized competing fuel- LPG, the
CNG segment would remain viable due to economics remaining favourable vis-à-vis auto fuels- petrol and
diesel with the latter getting gradually deregulated. The experience of CGD players, most notably in Gujarat
who have been operating largely on R-LNG, reinforces this view, although margins of CGD companies
could show some correction.
The domestic gas price deregulation process should help the cause of R-LNG marketers as the market
would get used to high cost gas. Besides, additional domestic gas production should enable pooling of high
cost R-LNG with domestic gas, to make the blended cost competitive for the sensitive sectors.
While the CCEA has gone ahead with approval of the new gas pricing regime, its implementation will be
mostly left to the new government formed post general elections scheduled in early 2014 given the huge
impact on the fertilizer and power sectors and the politically sensitive nature of the issue. Additionally the
GoI is also considering lowering the input cost for the sensitive sectors - Fertilizer and Power; hence the
implementation of the new gas pricing formula remains subjected to regulatory risk.
July 2013

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