Gas Price Hike Impact

GAS PRICE HIKE: IMPACT ANALYSIS

Analyst Contacts

K. Ravichandran

[email protected]

+91-44-4596 4301

Girishkumar Kadam

[email protected]

+91-22-6179 6341

Prashant Vasisht

[email protected]

+91-124-4545 322

Pranav Awasthi

[email protected]

+91-124-4545 373

Ankit Patel

[email protected]

+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

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mailto:[email protected]


http://www.icraindia.com/

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/M

T

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.

Bill

ion

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

4.384.82

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

Co

st o

f G

en

era

tio

n

De

liv

ere

d C

ost

of

Ga

s

Delivered Gas Cost (LHS) USD/MMBTU Overall Cost of Generation (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

Competitively bid tariff (Case 1 bids during Dec

2012- May 2013)

Short term - bilateral traded tariff in FY 2013

Gas at delivered cost of 9.5 USD/mmbtu

R-LNG at delivered cost of 16 USD/mmbtu

Rs.

/kw

h



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

Months CNG 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

Source: ICRA Estimates 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

Months CNG 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

Source: ICRA Estimates

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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An Associate of Moody’s Investors Service

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Gas Price Hike Impact

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