Oil&Gas Sector 4 April'11 New

Please refer to important disclosures at the end of this report

Oil&Gas and Petrochemicals

Play for value

Equity Research April 4, 2011 BSE Sensex: 19420


Reliance Industries (Rs1,035 – Buy) Target price Rs1,197 ONGC (Rs293 – Buy) Target price Rs338

Cairn India (Rs354 – Buy) Target price Rs384 GAIL (Rs464 – Buy) Target price Rs572 GSPL (Rs102 – Buy) Target price Rs130 Petronet LNG (Rs125 – Hold) Target price Rs116 BPCL (Rs606 – Hold) Target price Rs562 HPCL (Rs352 – Sell) Target price Rs298

Rohit Ahuja [email protected] +91 22 6637 7274 Prolin Nandu [email protected] +91 22 6637 7386

Prefer Upstream and Midstream

over Downstream

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Oil&Gas and Petrochemicals Play for value



Reliance Industries (Rs1,035 – Buy) Target price Rs1,197 ONGC (Rs293 – Buy) Target price Rs338

Cairn India (Rs354 – Buy) Target price Rs384 GAIL (Rs464 – Buy) Target price Rs572 GSPL (Rs102 – Buy) Target price Rs130 Petronet LNG (Rs125 – Hold) Target price Rs116 BPCL (Rs606 – Hold) Target price Rs562 HPCL (Rs352 – Sell) Target price Rs298


The recent scenario of rising crude prices is a déjà-vu for the domestic oil & gas industry, as marketing under-recoveries for oil marketing companies (OMCs) surge, while on the other hand refining margins expand. Private refining and petrochemical companies are expected to see their profitability surge as rising global demand for products trigger a margin expansion. Oil PSUs are likely to show a contrarian trend as their losses mount on surging under-recoveries. We reinitiate coverage on the oil & gas sector with a positive bias towards strong value generating companies that can withstand crude cyclicality and are able to generate stable profitability. We recommend BUY on Reliance Industries (RIL), Oil and Natural Gas Corporation (ONGC), GAIL and Gujarat state Petronet (GSPL), but advice caution on PSU OMCs.

Surging under-recovery, a brewing whirlwind…The Government’s inability to pass on the crude price increase is pushing oil PSUs back to pre partial de-regulation days, as their under-recoveries surge to Rs770bn in FY11 and the subsidy sharing remains uncertain. The only certain factor, as per the Government, is that the upstream companies’ contribution will be capped at 33% – which supports our positive bias for ONGC. However, we expect the OMCs to continue to underperform, as the hope for reforms fades in with rise in crude prices.

…even as E&P aims to steer clear…for the hydrocarbon chain in India with potential for oil & gas production to grow aggressively in the next 5-10 years. India currently offers one of the best E&P investment opportunities as it still meets >70% of its crude requirements through imports. The apparent success of the New Exploration Licensing Policy (NELP) rounds has proved that India has world-class hydrocarbon assets such as the KG Basin. But concerns persist on loss of tax benefits from discontinued gas production and disputes for approvals from the Directorate General of Hydrocarbons (DGH). However, the RIL-British Petroleum (BP) deal envisages that such issues would be eventually resolved and would not be a major hindrance for investments in the NELP blocks.

Sail safe anchored on midstream value bets…Natural gas pipeline companies have announced aggressive capex plans to support the incremental gas production from KG D6 and other prolific blocks in the east coast. Although there have been delays in volume ramp-up from the east coast, we believe the long-term story is still intact. We expect an incremental gas production potential of ~100mmscmd from the east coast in the next 5-10 years, which provides an excellent volume ramp-up opportunity to midstream players (GAIL and GSPL) and makes their expansion plans value generating proposition for long-term.

… guided by fair winds, ‘robust GRMs & Petchem’..Gross Refining Margins (GRMs), off late, have improved gradually due to improving demand from the USand Europe. We believe that complex GRMs will continue to improve as crude prices sustain at higher levels, with additional triggers from expansion in light-heavy spreads as the OPEC production increases. Petchem margins are expected to be strong as higher-than-expected incremental demand from Asia neutralises the impact of low-cost Middle East ethylene capacities. Hence, we strongly recommend RIL and GAIL (for Petchem) as ideal play on improving industry fundamentals.

Oil&Gas sector, April 4, 2011 ICICI Securities

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TABLE OF CONTENTS

Stock views.......................................................................................................................5 Surging under-recoveries – A déjà-vu for oil PSUs .....................................................6

Oil PSUs are back to square one....................................................................................7 E&P, the key valuation driver .........................................................................................9

Energy demand growth in India on a long-term trajectory… ..........................................9 …but rising dependence on oil imports needs to be curbed.........................................10 East coast development, a major boost through D6.....................................................12

Midstream players – Defensive bets............................................................................14 Acceleration in gas production requires supporting infrastructure................................14 Gas transmission infrastructure shaping up for increased supplies .............................16 Downstream gas trading margins to be under pressure...............................................18 LNG imports to surge, but pricing an issue...................................................................18 Domestic gas preferable for incremental demand ........................................................19 CGD demand potential to take 4-5 years to fructify......................................................20

GRMs and Petchem spreads to be robust ..................................................................21 GRMs to improve ..........................................................................................................21 Auto fuels to drive product demand ..............................................................................21 Light-heavy spreads to trigger complex premiums .......................................................23 Significant change in Petchem outlook .........................................................................25 India’s petrochemicals business to outperform.............................................................29

Annexure 1: Disruption in MENA props high crude price regime ............................31 Libya unrests escalate ..................................................................................................31 Support from Saudi Arabia spare capacity? .................................................................31 Algeria adds to the tension ...........................................................................................32 Developments in other MENA regions..........................................................................33 Positive impact on GRMs..............................................................................................34

Annexure 2: NELP transformed India into an attractive E&P destination ...............35 Favourable fiscal policies support strong investments .................................................37

Annexure 3: Index of Tables and Charts .....................................................................39


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COMPANIES Reliance Industries ........................................................................................................41 ONGC ..............................................................................................................................65 Carin India.......................................................................................................................83 GAIL...............................................................................................................................103 Gujarat State Petronet .................................................................................................121 Petronet LNG................................................................................................................137 BPCL .............................................................................................................................153 HPCL .............................................................................................................................169 Annexure 4: International financial reporting standards – Impact on oil & gas sector ............................................................................................................................183

Likely impact on Indian companies uncertain........................................................... 183 Prices and Sensex as on April 1, 2011


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Stock views

Company Reco Valuation Methodology Comments

Target price 1,197 E&P valuation concerns addressed to a major extent by the BP deal

CMP 1,035 Strong refining and Petchem margins outlook Reliance Industries

Buy

Upside 16%

SOTP

Cash rich balance sheet provides multiple avenues of growth

Target price 338 Strong reserve accretion potential

CMP 293 Sustained RoEs despite high subsidies ONGC Buy

Upside 15%

SOTP

Attractive valuations at 7.6 x FY13E earnings

Target price 384 Reserve accretion potential from Rajasthan Block

CMP 354 Peak production will held leverage lower operating cost Cairn India Buy

Upside 8%

DCF, EV/Boe

Royalty risk in the price, hence the stock offers an excellent risk-reward

Target price 572 Dominance in gas transmission to continue, expansion to add significant value

CMP 464 Possible triggers from Petchem expansion in high-margin environment GAIL Buy

Upside 23%

SOTP

Valuation indicate attractive risk-reward

Target price 130 Ramp up in D6 volumes to benefit GSPL

CMP 102 Scope of expansion in Gujarat for power and fetiliser client GSPL Buy

Upside 27%

DCF

New pipeline if found commercially viable adds to target price

Target price 116 Spot volume led profit expansion unsustainable

CMP 125 Kochi terminal utilisation threatened by surging LNG prices Petronet LNG

Hold

Upside (8%)

DCF

Valuations capture the best case, hence risk-reward unfavourable

Target price 562 Significant long-term triggers from E&P business possible

CMP 606 Rising under-recoveries threaten short-term profitability BPCL Hold

Upside (7%)

Price to Book, EV/Boe

Upsides from Bina refinery commissioning in the price

Target price 298 High contribution from marketing business a major threat

CMP 352 Bhatinda refinery commissioning, the only short-term positive HPCL Sell

Upside (15%)

Price to Book Valuation hinges entirely on Government support, strong sell in current environment


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Surging under-recoveries – A déjà-vu for oil PSUs We are getting increasingly cautious over oil PSUs, as the Government’s subsidy sharing mechanism remains unclear with continuing rise in under-recoveries, leading them to be rightly undervalued vis-à-vis international peers by the domestic markets. And the situation is worsening day by the day, as crude continues to trade strong. Under-recoveries for oil PSUs are expected to swell past Rs100bn in FY12E and FY13E. Further, the current high inflation scenario leaves the Government with limited legroom to protect the profitability of OMCs. We see the overall policy scenario as a throwback to pre partial de-regulation days, which will continue to hamper the valuations of the OMCs.

On the other hand, we are bullish on upstream PSUs such as ONGC as they stand out in terms of valuations and their ability to maintain stable profitability in a high crude price scenario. These companies have been able to maintain strong return ratios in the past 2-3 years, even during the high subsidy scenario of FY09. Though the Government has still not finalised a policy framework that caps upstream contribution of under-recoveries to one-third of the total quantum, historical data suggests that this is unlikely to undergo any major change.

Chart 1: RoE comparisons of oil PSUs

0

5

10

15

20

25

30

FY09 FY10 FY11E FY12E FY13E

(%)

50

60

70

80

90

100

110

(US$

/bbl

)

ONGC GAIL HPCL BPCL Brent (RHS)

Source: Company data, I-Sec Research

Table 1: Share of subsidy contribution across categories (Rs mn) FY08 FY09 FY10 FY11E FY12E FY13EPetrol 73,320 51,810 51,510 22,059 29,260 31,016Diesel 351,660 522,860 92,790 321,047 599,396 635,360Kerosene 191,020 282,250 173,640 186,671 223,076 221,960LPG 155,230 176,000 142,570 246,067 264,009 271,930Total 77,123 1,032,920 460,510 775,845 1,115,741 1,160,266

Source: Infraline, I-Sec Research

Upstream PSUs will maintain the RoE within 19-24%


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Oil PSUs are back to square one

The OMCs are currently losing ~Rs4/litre in petrol, Rs10.5/litre in diesel, Rs356/cylinder in LPG and Rs21/litre in kerosene. We hereby analyse the various options that the Government can deploy in the next 1-2 years to reduce or sustain the under-recoveries of OMCs.

• Raising fuel prices. After de-regulation of petrol in June ’10, OMCs have been raising petrol prices periodically. However, with crude flirting with US$100/bl, the OMCs are finding it hard to hike petrol prices to risk upsetting the Government’s effort to contain inflation. What perhaps seemed to be the easiest step for the Government has turned the other way round. As for diesel, LPG and kerosene – the current high level of food inflation leaves little, if any, scope for the Government to take any substantial price hikes. Even if the Government manages marginal hikes in diesel and LPG prices, the overall quantum of under-recoveries on these fuels would be large enough to cross FY09 levels.

• Subsidy sharing formula. Despite all talks about a fixed subsidy sharing formula since June ’10, the Government is yet to come to anything concrete ever since crude prices have started to climb. However, in the current scenario of high crude prices, we believe, this is what the Government could to do to spice up the valuations of OMC stocks. As is evident from the pattern over the past 3-4 years, the Government can incorporate a percentage sharing formula, capping the contribution of upstream companies at 33% and OMCs at 17%, which can lead to a strong visibility in the earnings of these stocks. The Government’s contribution can be in the form of cash or oil bonds, depending on the quantum. We believe that in the present situation, where crude is displaying lot of volatility, a fixed percentage sharing would be an ideal option for oil PSUs.

Chart 2: Under-recoveries – Contribution from oil PSUs and the Government

0%10%20%30%40%50%60%70%80%90%

100%

FY08 FY09 FY10 FY11E FY12E FY13EYear

Dow nstream Government Upstream


Inability to pass on the increase in crude prices has almost reversed the benefits of partial deregulation kick-started last year


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• Tweaking the tax structure. The overall contribution of the oil companies in the form of taxes, royalties and profit petroleum is far higher than the under-recoveries of OMCs (Table 2). As these under-recoveries are ultimately borne by the Government either directly (in the form of cash and oil bonds) or indirectly (subsidy contribution from upstream oil PSUs), there is no rationale for ad-hoc contribution from the upstream oil companies.

In FY09, >70% of the contribution from the oil companies was in the form of excise and sales tax, a reduction in which would have been sufficient to reduce or completely provide for the under-recoveries. However, as sales tax reduction would be a hard bargain – considering it’s a state subject, hence requires consent of the state governments – the central Government could achieve the same through excise reforms. But we haven’t seen any initiative for change in the excise structure in this year’s union budget, which is a concern

Table 2: Oil companies’ contribution much higher than under-recoveries (Rs bn) Particulars FY05 FY06 FY07 FY08 FY09 FY10 Central exchequer Customs duty 117 92 100 126 63 46 Cess 49 49 69 69 68 66 Excise duty 382 472 519 548 541 625 Royalty 22 23 28 31 31 39 Corporate tax 112 109 122 163 120 179 Dividend 76 72 80 76 45 81 Tax on dividend 15 13 14 19 11 19 Petroleum profit - - 35 42 47 55 Others (includes service tax) 4 3 7 9 9 10 Sub total 777 833 938 1,041 935 1,118 State exchequer Sales tax (389) 469 539 564 633 650 Royalties 23 32 36 42 25 33 Dividend to state govt. 0 0 0 0 0 0 Octroi, duties (incl. electricity duty) 13 22 19 17 19 19 Others 7 2 5 11 5 18 Sub total 432 525 600 634 683 721 Total contribution 1,209 1,358 1,538 1,676 1,618 1,839 OMC under-recoveries 201 400 494 771 1,032 460 Surplus 1,008 958 1,044 905 586 1,378

Source: Industry

Under-recoveries more or less a zero-sum game for the Government


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E&P, the key valuation driver

Energy demand growth in India on a long-term trajectory…

Over the past decade, India has turned out to be one of the fastest growing economies in the world, along with China. This has led to a huge demand for primary energy – with India’s share of global primary energy consumption rising to 4.2% in ’09 from 2.9% in 1997 (Table 3).

Table 3: Global and Indian primary energy consumption

Indian consumption Global

Oil Natural gas Coal Nuclear

powerHydro power

Total primary energy

consumption

Primary energy

consumption

India’s share of global primary

energy consumption

‘000

barrels per day

Billion cubic

meters

Mnteoil

equivalent

Mn teoil eqv.

Mn teoil eqv

Mn te oil eqv

Mn te oil eqv. %

1997 1,828 22.3 135.9 2.3 15.9 260.6 8,880.1 2.931998 1,963 24.5 136.1 2.6 18.9 272.1 8,888.5 3.061999 2,134 25.1 135.8 2.9 18.6 280.1 9,021.5 3.102000 2,254 26.4 144.2 3.6 17.4 295.1 9,262.6 3.192001 2,284 26.4 145.2 4.3 16.3 296.5 9,323.1 3.182002 2,374 27.6 151.8 4.4 15.5 307.8 9,502.8 3.242003 2,420 29.5 156.8 4.1 15.7 316.2 9,810.5 3.222004 2,573 31.9 172.3 3.8 19 343.9 10,258.8 3.352005 2,569 35.7 184.4 4 22 362.2 10,555.3 3.432006 2,580 37.3 195.4 4 25.4 378.8 10,820.8 3.502007 2,748 40.2 212.9 4 27.7 409.2 11,104.4 3.692008 2,882 41.4 231.4 3.5 26.2 433.3 11,294.9 3.842009 2,982 42.0 245.8 3.8 24.0 468.9 11,164.3 4.19

Source: BP Statistical Review ‘10 In ‘10, where the global economy was expected to stutter and global demand growth to slow down, India has continued its growth trajectory with its share of global primary energy consumption going up.

The Indian Government has set a sustained GDP growth target of over 9% in the near future. Historically, India’s energy growth to GDP growth ratio has stood at ~0.7 (Table 4). With GDP growth target of 9%+ in the next few years, India’s energy demand is likely to grow at ~6% (a correlation of ~0.7). This, coupled with the current global economic scenario, which has hit demand in some of the major developed countries, should see India’s share of global energy consumption rising to 5% in the next few years.

India offers an aggressive long-term growth potential; hence energy consumption is expected to surge


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Table 4: Energy demand growth – A close proxy of GDP growth

Total primary energy consumption (India)

Growth over previous year

Gross domestic product at constant (1999-00) prices

GDP growth rate Ratio

Mn. tonne oil eqv % % 1997 260.6 - 1,508,378 - - 1998 272.1 4.41 1,573,263 4.3 1.0 1999 280.1 2.94 1,678,410 6.68 0.4 2000 295.1 5.36 1,786,526 6.44 0.8 2001 296.5 0.47 1,864,301 4.35 0.1 2002 307.8 3.81 1,972,606 5.81 0.7 2003 316.2 2.73 2,048,286 3.84 0.7 2004 343.9 8.76 2,222,758 8.52 1.0 2005 362.2 5.32 2,388,768 7.47 0.7 2006 378.8 4.58 2,616,101 9.52 0.5 2007 409.2 8.03 2,871,118 9.75 0.8 2008 433.3 5.89 3,129,717 9.01 0.7 2009 468.9 8.22 3,389,484 8.30 1.0 C.A.G.R. 4.62 C.A.G.R. 6.43 0.7 Source: BP Statistical Review 2010 and CMIE

…but rising dependence on oil imports needs to be curbed

Though the past few years have been exciting for India in terms of large discoveries, these have largely been of natural gas. And what the country is looking for is oil – with the current demand at huge 3.2mbpd and rising, of which less than a third, 0.9mbpd, is met through domestic production, it is dependent on imports in a big way. The large imports also ensure that the Indian demand-supply dynamics continue to remain unfavourable in the long term. It is thus natural for Indian E&P companies to add more oil reserves, domestically or internationally, to secure long-term supplies.

Factors that justify strong investments in oil exploration • Surging oil import bill. Over a period of eight years, ’00-01 to ’08-09, the oil bill

has grown about eight fold to US$100bn (189mmtpa) in ’08-09 from US$12.9bn (74.09mmtpa) in ’00-01. In addition, the Government incurred a subsidy of US$18bn on supply of petroleum products within the country.

• Rising energy needs. According to industry observers, to deliver a sustained growth of 8% through ’31-32, India needs to:

− Increase its primary energy supply 3-4x from present levels

− Raise its electricity generation capacity/supply 5-6x the present levels to nearly 800,000MW from ~160,000MW, inclusive of all captive plants

− Expand coal requirement to over 2bnte/annum based on domestic quality of coal

− International Energy Outlook (IEO) projects that India’s oil consumption would grow by more than double to 5mnbopd by ’30.

Based on above, as per investment projections, India’s energy sector would need US$120-150bn worth of investments in the next few years to meet the demand growth.

High dependence on import has increased the necessity to raise domestic production


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Table 5: Domestic crude balance (mbpd) 2007 2010E 2012E Refining throughput (a) 3.0 4.1 5.2 Domestic demand (b) 2.5 3.2 3.4 Net exports (a-b) 0.5 0.9 1.8 Domestic production (c ) 0.7 0.9 0.9 Net imports (b-c) 1.8 2.3 2.5 % demand 72.0 71.9 73.5 Source: Industry

Table 6: Declining oil production, a concern (mbpd) Year Pvt./JV ONGC OIL Total 2009-10 0.13 0.52 0.07 0.72 2010-11 0.24 0.51 0.08 0.83 2011-12 0.26 0.54 0.08 0.87 2012-13 0.25 0.60 0.08 0.92 2013-14 0.22 0.58 0.08 0.88 2014-15 0.19 0.55 0.07 0.82 2015-16 0.16 0.51 0.07 0.74 2016-17 0.13 0.47 0.07 0.67 2017-18 0.11 0.44 0.07 0.62 2018-19 0.10 0.40 0.06 0.57 2019-19 0.08 0.37 0.06 0.52 2020-21 0.02 0.34 0.06 0.42 Source: Infraline

Table 7: Oil import details

Imports Products

Imports Gross

Imports Product Exports Net Imports

Year (mn bbls) (mn mmbls) (mn bbls) (mn bbls) (mn bbls) 2004-05 702.66 64.71 767.37 133.49 633.88 2005-06 728.67 98.52 827.19 171.96 655.24 2006-07 817.31 129.45 946.76 246.46 700.29 2007-08 891.86 164.65 1056.50 298.91 757.59 2008-09 973.24 149.00 1122.24 282.73 839.51 2009-10 1167.37 107.47 1274.84 373.64 901.20 2010-11 (April ’10 - Dec ’10) 845.00 95.05 940.04 268.71 671.33

Source: Infraline The discovery of Mangala oil field (in Rajasthan by Cairn India) has been touted as India’s biggest after ONGC’s Mumbai High discovery, back in 1981. Production from the Mangala oil field is expected to touch the peak of 240,000bpd – equivalent to the current oil production from Mumbai High – in the next three years. In spite of Mangala oil field pitching in full pelt, India would still need to import ~70% of its 3.2mbpd oil requirement. We therefore expect India’s E&P investments to continue to be more focused towards garnering oil producing assets either organically or inorganically.

Rajasthan remains a strong hope for India in terms of further oil reserves. Also, RIL has announced some oil discoveries in the KG and the Cambay basins, which offer some of the best potentials for expansion of domestic oil production. We believe that the company may deploy its excess cashflow, primarily in acquiring E&P assets (predominantly oil) as well as accelerating the development of its oil discoveries.

More discoveries such as Mangala and Mumbai High needed


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Table 8: Domestic oil production details (bpd)

Oil production 1. ONGC 495,996 Onshore 151,731 Gujarat 118,013 Assam 22,967 Andhra Pradesh 6,353 Tamil Nadu 4,398 Mumbai High Offshore 344,265 Oil 300,041 Condensates 44,224 2. Oil India 73,373 Assam 72,860 Arunachal Pradesh 513 3. Private/JVC 214,694 Onshore 130,694 Arunachal Pradesh 2,004 Assam 367 Rajasthan 125,000 Gujarat 3,323 Offshore 84,000 Grand total (1+2+3) 784,063 Onshore 282,425 Offshore 501,638

As on December ’10, Source: Infraline

East coast development, a major boost through D6

The Krishna Godavari (KG) Basin has been the outstanding success story of the NELP rounds (introduced in 1999). By the end of ’09, a total of 35 blocks had been awarded in the basin. The success of the new policy is perhaps best measured by the increased level of drilling activity in shallow and deepwater acreage in the past 10 years. Over 80 offshore exploration and appraisal wells have been drilled, resulting in a series of gas discoveries. The likes of the Dhirubhai (D) 1 and 3, and the KG-DWN-98/2 have established the KG basin as a deepwater province with giant field potential. Despite several initiatives to attract broader participation in the exploration, the acreage has largely been secured by major indigenous operators such as ONGC and RIL (which hold over 76% of total net acreage and operating 20 of 25 active licences).

Over 80 exploration and appraisal wells have been drilled since the introduction of the NELP. From a peak of around 20 wells in ’07, the activity has dropped by two-thirds in ’09, particularly in deepwater areas. Overall, it has been a major success story. The drilling success rate (commercial plus technical) has remained consistently high with an average of 60% plus. Most of the discoveries have been gas based, some small scale fields and some super giant fields such as D6.

The discovery of D6 has been the highlight of the NELP experience so far with an estimated 11tcf (P1) reserves confirmed till date. Since its discovery, RIL has gone on to discover a string of smaller gas discoveries in the KG-DWN-98/3 block, which could yield an additional 2-3tcf of incremental commercial reserves by ’16. The 60mnbls oil discovery – MA – made in ’06 was brought on-stream in ’08.

Despite a series of large gas discoveries, KG Basin still offers a high undiscovered potential


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Chart 3: Acreage holdings in KG Basin blocks (dominated by ONGC and RIL)

Source: Wood Mackenzie

Chart 4: Reserve additions in the KG Basin


Chart 5: World’s top exploration provinces (1999-2009) by number of discoveries

Egypt_Western DesertAustralia_Eromanga

US (GoM Deepwater)_East Gulf CoastAustralia_North Carnarvon

Egypt_Nile DeltaAngola_Lower Congo

US (GoM Deepwater)_West Gulf CoastArgentina_Neuquen

Netherlands_Southern North SeaPakistan_Indus

Nigeria_Niger DeltaIndia_Krishna - GodavariAlgeria_Illizi - Ghadames

India_CambayMexico_Salinas - Sureste

Norway_Northern North SeaChina_North ChinaOman_Rub al Khali

Turkey_ThraceIndonesia_South Sumatra



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Midstream players – Defensive bets We consider the midstream natural gas space to be the best long-term defensive bet, as the business is independent of price fluctuation in the underlying commodity – natural gas. Also, the existing regulations provide long-term investment viability for pipeline infrastructure. GAIL, the largest player in the space, with >9,000Kms of pipeline infrastructure would be the key beneficiary of the trend. Further, with the Petroleum and Natural gas regulatory board (PNGRB) notifying the pipeline tariffs for GAIL at higher-than-expected levels, we believe that GAIL is one of the best defensive bets in the oil & gas space. GSPL’s valuations look extremely attractive considering it is at discount to GAIL’s. However, we believe that due to the company’s aggressive growth plans, the stock offers the highest potential upside in absolute terms.

Natural gas pipeline companies have announced aggressive capex plans to support the incremental production of gas from the KG D6 and other prolific blocks on the east coast. We expect incremental volume potential of ~100mmscmd from the east coast in the next 5-10 years. And the transportation of this gas would require additional pipeline infrastructure.

Acceleration in gas production requires supporting infrastructure

India has seen its domestic gas supply surge on the back of aggressive investments in exploration and production of natural gas. Production, which was almost negligible at the time of India’s independence, presently stands ~132.83mmsmcd. The main producers being ONGC, OIL, JVs of Panna-Mukta, Tapti and Ravva and RIL (which is producing gas from its KG D6 block in the east coast of Andhra Pradesh).

Of the total domestic gas production of 132mmscmd, RIL is the biggest player – contributing ~43% to the total production (as of July ’10) with the remaining producers contributing ~57%. Apart from the KG D6, the gas is mainly produced from onshore fields in Assam, Andhra Pradesh and Gujarat with smaller quantities coming in from oil fields in Tripura, Tamil Nadu and Rajasthan. OIL is operating in Assam and Rajasthan, whereas ONGC is operating in the western offshore fields along with some other states. Gas produced by ONGC and a part of the gas produced by the JV consortiums is marketed by GAIL. Gas produced by OIL is marketed by the company itself, except in Rajasthan where GAIL is authorised to market its gas. Gas produced by Cairn Energy from Lakshmi fields in Gujarat and GSPCL from Hazira fields is sold directly by the companies at market determined prices.

Table 9: Domestic gas supply scenario in FY11 Volume (mmscmd) ONGC and OIL 54.3 *RIL KG D6 54.0 PMT/ Ravva/Ravva Satellite 18.7 Long term RLNG 30.0 Shell spot 3.5 Other gas 2.7 Total 164 Source: Industry

Strong long-term potential seen for midstream investments, as domestic blocks offer ~100mmscmd incremental production potential


15

Power and fertiliser continue to drive demand

Power generation and fertiliser industries are the biggest consumers of natural gas, accounting for two-thirds of the total domestic consumption. As per the working group report on petroleum and natural gas sector for the XI Five Year Plan period, the demand for natural gas would grow to 170mmscmd in ’11-12; the power and fertiliser sectors together are expected to account for 76-80% of the total natural gas consumed in the country. As per industry estimates, the demand for power is expected to grow at 30% and demand for fertiliser at 10% over the next five years.

Table 10: Domestic gas demand-supply scenario (mmscmd) Gas supply Current FY13 FY16 % share (FY16) Existing sources ONGC 54 46 40 13.1 Petronet LNG 30 34 36 11.8 Shell Hazira 4 9 18 5.9 Dabhol LNG 18 18 5.9 Others (including OIL and Pvt JVs) 19 20 20 6.5 New sources - RIL KG D6 54 80 80 26.1 RIL Mahanadi basin 7 9 9 2.9 GSPC KG basin 0 10 20 6.5 ONGC KG basin 0 0 20 6.5 CBM 3 5 15 4.9 RIL others (D6 satellite, NEC 25,etc) 30 9.8 Total supply 170 231 306 Gas demand Power 74 100 150 46.9 Fertiliser 39 54 70 21.8 Sponge iron plants 6 8 10 3.1 Refineries 30 35 45.5 14.2 City gas distribution 14 18 23.4 7.3 Industrial 14 18 21 6.6 Total demand 177 232 320 Demand-Supply 6.7 1.1 13.6 Source: Industry


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Gas transmission infrastructure shaping up for increased supplies

The present gas trunk pipeline grid is ~10,000Kms and supplies gas to 0.8mn households and 0.4mn CNG vehicles in 25 cities, mainly in the northern and western India. GAIL owns more than 67% (6,800km) of the network, followed by RIL at 14% (1,400Kms) and GSPL at 11% (1,152Kms). The remaining is owned by Assam Gas Company, OIL and Gujarat Gas Company.

In Assam, the Assam Gas Company has a network of 560Kms trunk pipeline and 1,150Kms of distribution pipeline. Gujarat Gas Company owns 116Kms of transmission lines and 1,900Kms of distribution lines. GSPL has a pipeline network of 1,670Kms along Hazira-Vadodara-Ahmedabad-Kalol-Himmatnagar-Mehsana-Rajkot-Morbi-Vapi, which transports 38mmscmd gas, including a large volume of LNG. This is enhanced significantly by new transmission pipelines traversing the state. The network will be connected to the east-west pipeline of RIL through its 30-inch Bharuch-Jamnagar pipeline. Overall, the planned capex of pipeline networks across the country amounts to more than Rs300bn over the next 4-5 years.

GAIL is in the process of doubling its transmission infrastructure to more than 16,000Kms over the next four years. Also, GSPL plans to extend its presence out of Gujarat through three major trunk pipelines (~2000 kms, Rs180 bn gross capex) -- Mehsana-Bhatinda, Mallavaram-Bhilwara and Bhatinda-Srinagar. The Paradip pipeline is under the approval stage and the bids have been submitted. Reliance Gas Transmission Infrastructure (RGTIL) plans to develop more pipelines of 2,875Kms across India.

Major expansion in pipeline capacities underway


17

Chart 6: Pipeline infrastructure in India

Source: PNGRB


18

Downstream gas trading margins to be under pressure

Gas marketing companies, traditionally, have been scouting for gas supplies due to limited availability and lack of adequate infrastructure to transport the domestically produced gas. Both these concerns are now being addressed and the segment has seen renewed fervour in terms of expansion. However, a major concern in this segment is its exposure to trading margins. Regulations in CGD business allow only three years of exclusivity for existing players. We believe that post this exclusivity period, the competition will probably be skewed in favour of large players which have an assured source of gas supply.

Though this segment is expected to see robust growth over the next few years, we believe it will see pressure on margins on account of increased competition from new entrants. We therefore remain neutral to negative on the companies in this segment.

LNG imports to surge, but pricing an issue

Among the various fuel alternatives, coal is expected to continue to retain its cost competitiveness vis-à-vis gas and is likely to remain the cheapest source of fuel in the future. However, gas is expected to continue to remain economical as compared to liquid fuels such as LPG, naphtha and fuel oil. Among the various categories of natural gas available, price of domestic gas produced by oil PSUs would be the lowest.

RIL’s schedule to ramp up D6 gas has been delayed, but over the long term, production potential of KG basin remains robust. Though RIL gas is currently costlier than contracted LNG, the situation is expected to reverse in the near future. This is because the price of contracted LNG (by Petronet LNG) is expected to increase owing to its progressive linkage to Japanese Crude Cocktail (JCC). This is expected to make domestic gas even more competitive versus contracted-LNG during FY12 and FY13.

Chart 7: Price comparison – KG-D6 gas vis-à-vis LNG

0

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40

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FY09 FY10 FY11E FY12E

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LPG Naphtha Contracted LNG Spot LNG RIL - KG D6 PMT APM

Source: I-Sec Research

High prices of LNG to be a major deterrent for incremental power demand


19

Delay in volume ramp-up of the KG D6 gas will lead to a surge in LNG imports to India over the short term, primarily in the form of term contracts and spot volumes from regasification terminals on the west coast. The 10-20mmscmd shortfall in D6 gas (vis-à-vis targeted production of 80mmscmd in FY12E and FY13E) provides India an opportunity to fill this gap through LNG import. The key target for procuring LNG would be the Middle East countries, primarily Qatar, where major portion of incremental capacities are coming up. As per the table below, LNG supplies are expected to be in surplus over the next four-five years, which provides India enough leeway to capture the new LNG contracts.

However, the constraint would be spare re-gasification capacities available domestically and the increasing costs of spot LNG and term contracts. Currently, Petronet’s Dahej and Shell’s Hazira are the only LNG terminals operating with the combined capacity of 13.6mmtpa (can be lower since Hazira is unable to operate at its full capacity). The Dabhol LNG terminal is expected to be commissioned in ‘11 with a 5mmtpa capacity, but will initially operate at around 2mmtpa. Hence, throughout ‘11, the available spare LNG re-gasification capacity would be around 2.5-3mmtpa, which represents a potential supply of 10-12mmscmd.

Table 11: Global LNG demand-supply (MMT)

Region 2010 2011 2012 2013 2014 2015 2020 2025 Asia Pacific 62 67 67 66 67 77 85 68 Europe 3 3 3 3 3 3 3 3 Middle East 57 70 73 73 73 73 73 73 North Africa 23 23 24 26 27 31 32 32 North America 1 0 0 0 0 0 0 0 South America 12 14 14 14 14 14 12 7 West Africa 16 18 19 21 22 22 22 18 Total 174 195 199 202 206 221 227 201 LNG Demand Asia Pacific 90 98 105 108 116 124 138 168 Europe 45 51 53 53 56 60 110 125 North America 26 33 32 29 20 19 15 13 South & East Africa 0 0 0 0 0 0 0 0 South America 2 3 3 3 3 3 4 4 Total 163 185 193 194 195 207 267 311 Surplus/(Deficit) 11 9 6 8 12 13 (41) (110)


Domestic gas preferable for incremental demand

Power tariffs based on RIL gas will be cost competitive with respect to liquid fuels, contracted LNG and imported coal (Chart 8). Power generation through contracted LNG will turn uncompetitive from ‘09-10 as compared to RIL gas, given the contracted LNG-crude oil price linkage. With regard to imported coal, most of the new power projects are coming up in coastal areas and given that they have long-term contracts for sourcing coal, the cost of power generation is far less than our projections. However, the power tariff based on domestic coal will continue to remain the cheapest, followed by APM gas-based tariff.

For fertiliser sector, natural gas is used both as a feedstock as well as a fuel for urea production. Due to non-availability of natural gas, expensive alternatives such as naphtha and fuel oil were used in fertiliser production. The cost of production of urea

Domestic gas is the most cost-effective and thus most preferred alternative for power generation


20

varies significantly with the type of feedstock and fuel used. As shown in the following chart, the cost of production is the lowest with natural gas. The Government of India has, therefore, given top priority to fertiliser sector in the allocation of KG D6 gas.

Chart 8: Cost of producing urea through different fuels

0100200300400

500600700800

Nap

tha

Fuel

oil

RIL

.gas

Nap

tha

Fuel

oil

RIL

.gas

Nap

tha

Fuel

oil

RIL

.gas

Nap

tha

Fuel

oil

RIL

.gas

2008-09 2009-10P 2010-11P 2011-12P

(US$

/te)

Source: Industry Currently, there are 21 gas-based urea plants (with an aggregate capacity of 19mnte) and four other plants (with cumulative capacity of 4.0mt) based on naphtha and fuel oil. The Government has mandated all fuel oil and naphtha-based plants to switch over to natural gas. However, due to non-availability of pipeline connectivity, there will be some delay in switching over to gas-based platform at these remaining plants.

CGD demand potential to take 4-5 years to fructify

With gas availability being taken care of domestically, the clear potential for downstream business is the City Gas Distribution (CGD) business model. Though the business carries strong potential in terms of satisfying the end-user demand, which is on account of the inherent economical and environmental benefit of natural gas, the expansion in volumes is bottlenecked by the lack of infrastructure in terms of end-user pipeline connectivity. The lead time for laying CGD pipelines is longer than for cross-country pipelines since the former requires additional local municipal approvals.

Going forward, given the Government’s thrust on developing cross-country as well as regional gas pipeline grids and the additional gas supply coming up in the near future (RIL gas) many major trunk pipelines are expected to be commissioned in the medium term. This is expected to boost the development of CGD throughout the country. Moreover, the Government’s thrust on CGD development is reaffirmed, with CGD getting higher priority over the greenfield power plants in the gas utilisation policy framework.


21

GRMs and Petchem spreads to be robust

GRMs to improve

Downstream profitability has seen a sharp improvement in the past four quarters, led by improved demand from Asian countries and stabilisation of the US and European economies. We believe that the current recovery in GRMs will sustain led by improved demand for transportation fuels and improving light-heavy spreads, We expect average complex Singapore GRMs to improve to US$7/bl levels in FY12E and to US$7.5/bl in FY13E. We also expect rising crude prices to eventually lead to increase in light-heavy spreads, which will bode well for complex refineries owned by RIL and upcoming greenfield refineries of Bharat Petroleum Corporation (BPCL), Hindustan Petroleum Corporation (HPCL) and Indian Oil Corporation (IOC).

Auto fuels to drive product demand

Global GRMs have been on a recovery path off lately, primarily led by HSD, petrol and jet kerosene cracks. We expect this segment to continue to be a long-term demand driver for these fuels. We believe that Incremental demand would continue to be driven by transportation fuels, with diesel being the most critical demand driver from the Asian and European regions.

Chart 9: Global GRM trends over the year

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)

Rotterdam Complex Singapore Complex Mediterranean Complex WTI Crack

Note: Average yearly GRMs; Source: Reuters

GRMs to improve and sustain at higher levels


22

Chart 10: Global Petroleum liquids consumption by end-use sector

50

75

100

125

150

2007 2015 2020 2025 2030 2035

(qua

drilli

on B

tu)

Transportation Other

Source: EIA HSD (Gas oil) would be the key demand driver for refining products in the next 20 years, with its share in the petroleum demand expected to rise to >30%, while that of the gasoline slated to decline (Chart 11). The incremental push for middle distillates is clearly coming in from Asian economies such as India and China. In these countries, diesel finds a strong industrial use other than for transportation. The other strong demand driver for diesel in Asian countries is expected to be the robust growth in car sales, as consumers in this region have a preference for low-cost diesel variants as this fuel is more subsidised there.

Chart 11: Product-wise demand growth

0%

5%

10%

15%

20%

25%

30%

35%

Etha

ne/L

PG

Nap

htha

Gas

olin

e

Jet/K

eros

ene

Gas

oil/D

iese

l

Res

idua

l fue

l

Oth

er

2009 2030 2015

Source: OPEC, World Oil Outlook, 2010


23

Table 12: Robust passenger car sales growth Cars per 1000 Cars million 2007 2010 2020 2030 2007 2010 2020 2030

Car growth % p.a.2007-2030

North America 575 555 581 601 261 259 295 326 1Western Europe 442 436 462 489 238 238 259 277 0.7OECD Pacific 428 437 484 517 86 88 97 101 0.7OECD 490 482 513 540 585 585 651 704 0.8Latin America 133 138 163 187 55 60 78 98 2.5Middle East & Africa 27 31 41 52 22 27 45 68 5South Asia 10 12 26 50 15 20 48 104 8.7Southeast Asia 50 57 88 127 32 38 64 100 5.1China 22 30 80 147 30 41 114 214 9OPEC 58 59 80 106 22 24 38 59 4.4Developing Countries 34 39 64 96 177 209 388 642 5.8Russia 207 200 296 379 29 28 39 47 2.1Other trans. Economies 158 176 239 302 31 35 47 59 2.9Transition economies 178 186 262 332 60 62 86 106 2.5World 123 124 147 174 821 856 1,126 1,452 2.5

Source: OPEC, World Oil Outlook, 2010

Light-heavy spreads to trigger complex premiums

Light-heavy crude oil spreads in the past two years have been low due to sluggish demand for light crude products (from the US and Europe as the slowdown intensified). This was followed production cut of mainly heavy crude by the OPEC and commissioning of new complex refining capacities that resulted in increased demand for heavy crude. However, the situation is starting to reverse with demand from the US improving and economic stabilisation in European countries expected to improvise the product demand scenario.

However, we can expect triggers from light-heavy spreads once OPEC starts raising its production. With current crude prices at close to US$100/bl, the OPEC will eventually raise its production levels by increasing the output of heavy crude, which will consequently impact the light-heavy spreads on the higher side. An improvement in light-heavy spread back to its long-term average of US$4.2/bl in the next 4-8 quarters can be a trigger for expansion in the premium for complex refiners such as RIL. However, due to increased demand from new complex refinery additions, we do not foresee light-heavy spreads to touch its peak of US$10/bl and expect it to hover around its long-term average of US$4-5/bl.

Chart 12: Arabs and Maya crude spreads

(4)

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Light-Heavy (Arab) Mean (Arab)WTI Vs Maya Mean (WTI-Maya)

Source: Bloomberg


24

Chart 13: OPEC spare capacity

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Note: Bloomberg figures vary with IEA figures which put ‘effective’ spare capacity, excl. Libya at 4.08mb/d. Source: Bloomberg, the February ‘11 number for spare capacity excludes Libya’s spare capacity

Chart 14: Product spreads over Brent

(8)

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Diesel Petrol Naphtha

Source: Bloomberg

Chart 15: Refinery utilisation rates inching up

73

76

79

82

85

88

Q1FY10 Q2FY10 Q3FY10 Q4FY10 Q1FY11 Q2FY11 Q3FY11

(%)

USA Europe Asia

Source: Reliance Q3FY11 Presentation


25

Significant change in Petchem outlook

Petchem margins (especially olefins), in the past few quarters, have grown strong. A major surprise, this indicates strong demand pull despite more than 10mmtpa capacity addition in the Middle East. The incremental demand primarily comes from Asian economies, mainly China and India. Many large Petchem players expect a strong business cycle over the next 2-3 years as demand in the US and Europe revives. Limited capacities coming up in the Middle East and across the world post ’11 will only help the cause. However, we have assumed margins to remain at the current levels and wait for better times.

Chart 16: Demand for basic chemical & plastics Global demand for plastics North American demand

0

100

200

300

400

500

600

1990 1995 2000 2005 2010 2015

(MM

T)

5.2% 4.2%

-7.1

%

5.3%

0

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60

1990 1995 2000 2005 2010 2015

(MM

T)

4.6% 0.1%

-16.

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Western Europe demand Asian demand

0

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(MM

T)

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1990 1995 2000 2005 2010 2015

(MM

T)

9.2% 7.1%

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%

6.6%

Source: CMAI


26

Ethylene capacity addition would be comfortably absorbed An additional 13mmtpa low-cost ethylene capacity is expected to come up in the Middle East over the next four years. Over the same period, Asia is expected to come up with another 12mmtpa (led by China at 9mmtpa). However, this will be partially offset by the closure of inefficient capacities of 10mmtpa in the developed economies, especially North America and Europe (Chart 17). Hence, the net capacity addition in the next three years is expected to be ~13-15mmtpa. The global feedstock mix will tilt marginally towards ethane – from 27% in ’10 to 32% in by ’13 – resulting in pressure on naphtha-based crackers.

Chart 17: Ethylene capacity addition

-4.0

-2.0

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4.0

6.0

8.0

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2010 2011E 2012E 2013E 2014E

MM

T

North America Middle East Southeast AsiaWest Europe Northeast Asia Others

Source: CMAI However, most of the incremental capacities coming up in the Middle East are expected to be absorbed by the demand growth in Asia. As per CMAI estimates, incremental Poly-Ethylene (PE) demand in China and India is expected to be at least 10.4mmtpa in the next two years, enough to absorb incremental capacities coming up in the Middle East assuming 80% utilisation.

Chart 18: Ethylene demand trend

-30

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)Annual demand chg. in volumesAnnual demand chg. in % (RHS)

Source: CMAI


27

However, the trigger for Petchem margins is expected to come when demand growth from the US and Europe resumes in the next two years, expected to be at 4.2mmtpa. We see a possibility of re-rating of Petchem business if the margins fall in line with the forecast. Back home, RIL’s recent margins do justify this argument to some extent.

Chart 19: Middle East PE capacity addition

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Current View 2008 View

Delays helped keepthe market tight in 2009

Source: CMAI Poly-Propylene to show a similar trend CMAI indicates that the operating rates for current capacities of PP are steadily reviving, led by strong demand growth in Asia. Asia is the largest consumer of PP products, followed by the Middle East, North America and West Europe. As is the case of Ethylene, there are indications that global demand for PP will exceed expectations, which can trigger expansion in PP margins.

Operating rates are critical for profitability in the petrochemicals business. Higher operating rates reflect increased demand for products, hence higher bargaining power for producers. During price negotiation, besides inventory levels, plant operating rates is an important metric that determines the relative bargaining power of producer vis-à-vis consumer. As depicted below, cracker operating rates globally have declined sharply over the past two years and expected to bottom out in ’10 (at 80%). Post ’10, it is expected to revive sharply till ’14, as excess low cost capacities in the Middle East are absorbed by the market (Chart 21).


28

Chart 20: PP demand-supply dynamics

Source: CMAI

Chart 21: Expected consumption pattern of propylene

(4,000)(3,000)

(2,000)(1,000)

01,0002,000

3,0004,000

5,0006,000

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

('000

met

ric te

)

China North America West EuropeAsia Middle East / Africa South America

Source: CMAI As the Middle East capacities are predominantly based on low-cost gas-based feedstock, they enjoy a significant advantage over crackers in other regions. The cost advantage for non-integrated crackers world over would fade on the back of supplies from the Middle East. This could also lead to possible capacity shutdowns, especially in high-cost regions such as North America and Europe.


29

Chart 22: Ethylene production cash costs

Source: CMAI

Chart 23: Naphtha cracks

0150300450600750900

1,0501,2001,3501,5001,650

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MEG PTAHDPE LLDPEPropylene Polypropylene-propylenePVC

Source: Bloomberg

India’s petrochemicals business to outperform

Domestic demand for basic petrochemicals is expected to grow at a CAGR of 10-12% IN the next five years, with ethylene and propylene products constituting the major chunk. Capacity additions in India are expected to match the demand growth, led by RIL, OPAL (the JV between ONGC, GAIL, Petronet and the Gujarat government) and GAIL. The domestic operating levels have remained consistently above 90% throughout the entire down-cycle in the past two years, led by strong domestic demand. We expect the operating rates for Indian players to remain consistently above 95% as demand continues to outstrip supply.

Operating costs lowest in the Middle-East


30

Chart 24: Domestic polymer demand growth

Chart 25: Domestic chemical demand growth

Industry 9M FY11 (YoY)

0%

4%

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20%

PP PE

PVC

All

Poly

mer

s

Industry 9M FY11 grow th (YoY)

0%

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15%

PBR

LAB

Benz

ene

BD

Source: RIL presentation Source: RIL presentation

Chart 26: Overall domestic plastics and chemicals demand trend

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1990 1995 2000 2005 2010 2015

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+1.1%2008

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Source: CAMI


31

Annexure 1: Disruption in MENA props high crude price regime Recent unrests in the Middle East North African (MENA) region, along with economic recovery in the developed markets, strengthen our argument for a high crude price regime and indicate an upward risk to our long-term assumption of US$100/bl Brent crude. Due to the current and potential supply disruptions in the MENA region, prices of crude may continue to remain robust at current levels of US$116/bl, or may even rise further in the medium to long term. This can aggravate the under recoveries to be borne by the oil marketing companies.

Libya unrests escalate

Due to the recent unrest in Libya, the oil production from the country has dropped by one-third from 1.6mb/d to 0.4mb/d. Libya had the production capacity of 1.8mb/d. There seems to be no immediate resolution to the aggravating dispute between the Gaddafi loyalists and the rebels even as the NATO (including the US, the UK and France) have started military action against Gaddafi.

After these disputes end, it will still take some months before Libya gets back to the original levels of production, considering the bombings have affected the oil producing and exporting infrastructures. However, there are indications that things may get far worse before they improve, threatening the remaining 0.4mmbod production.

Support from Saudi Arabia spare capacity?

Saudi Arabia has 3.1mb/d spare capacity at present, which accounts for 57% of OPEC’s overall spare capacity (excluding Iraq and Libya). Hence, it seems the country has enough spare capacity to make up for the decline in production from Libya.

Chart 27: Spare capacity

Algeria, 0.14

Qatar, 0.08

Saudi Arabia, 2.80

Ecuador, 0.04

Kuwait, 0.35

Venezuela, 0.19

UAE, 0.30

Nigeria, 0.50

Angola, 0.41 Iran, 0.35

Source: Bloomberg


32

However, Saudi Arabia has never produced >9.6mb/d (maximum in July ’08). Hence, their ability to make up for Libya’s shortfall completely can be suspected. Also, Saudi Arabia’s capability to tap into its spare capacities in the short term has not been tested.

Chart 28: Saudi Arabia – Oil production

Saudi Arabia Production

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Source: Bloomberg

Algeria adds to the tension

Another country in OPEC which has substantial oil production to affect the global demand supply dynamics and is currently facing internal unrest is Algeria. Algeria has current oil production of 1.25mb/d and exports ~60% of its production. The Algerian capital is witnessing clashes. In an effort to restore calm and avoid uprisings similar to those that led to the ousting of authoritarian rulers in Tunisia and Egypt earlier this year, the Algerian Government has said it will move faster in tapping funds from Algeria's rich oil and gas resources to build more houses, roads and schools. Algeria lifted a 19-year-old state of emergency last month in a concession to the opposition.

Assuming that together with Libya, Algeria’s oil production is also curbed and Saudi Arabia’s tries to compensate the loss of Algeria’s production as well; this will leave the OPEC major with hardly any spare capacity.


33

Chart 29: OPEC production

Libya5%

Ecuador2%

Algeria4%

Iraq9%

Kuw ait8%

Angola6% Iran

11%Nigeria7%

UAE8%

Qatar3%

Saudi Arabia29%

Venezuela8%

Source: Bloomberg

Developments in other MENA regions

Bahrain, Syria, Yemen and Morocco are the ones which are facing some uprisings at present. Although the production from these countries is not enough to change the global oil supply dynamics, these regions would just add on to the situation in Libya and Algeria. There is also a possibility that the disruption in any of the small producers might happen.

Table 13: Developing crisis in other

Country Productionmb/d Recent events

Syria 0.40 At least six people were killed recently when Syrian security forces attacked protesters who had taken refuge in a mosque in the centre of the southern city of Dara’a, Reuters reported.

Yemen 0.28 Yemen's parliament enacted sweeping emergency laws after President Ali Abdullah Saleh tried to curb a popular uprising demanding his resignation. The move suspends the constitution, allows media censorship, bars street protests and gives security forces 30 days of far-reaching powers.

Total 1.16 Source: EIA, BBC News, Other News sources


34

Positive impact on GRMs

About 85% of Libyan oil exports go to Europe, including Italy, Germany, France and Spain. Due to Libyan unrest, the shortfall in production has to be met by Saudi Arabia by releasing spare capacity. Libya exports nine grades of crude oil. API gravities range from 26o to 43.3o, with a sulphur content as low as 0.2-0.3%. Because of the low sulphur content, the sweet crude can easily be turned into transport fuel. While the lighter, sweeter grades are generally sold to Europe, the heavier crude oils are often exported to Asian markets.

Saudi oil is generally more dense and sulphurous than the Libyan crude it will replace. Europe’s old refineries will not be able to process the heavier Saudi crude, and fuel regulations there are less tolerant of sulphur content than elsewhere in the world. So the Middle East oil will have to be shipped to Asia’s newer refineries, which are designed to deal with a wide variety of grades of oil. This will help increase light-heavy spreads, thus strengthening GRMs of complex Asian refiners.

Chart 30: Crude exports from Libya

Greece5%

United States3%

Spain10%

Italy28%

France15%

Other14%

China11%

Germany10%

United Kingdom4%

Source: EIA


35

Annexure 2: NELP transformed India into an attractive E&P destination Over the past 11 years, exploration of hydrocarbon potential of the sedimentary basins has been carried in a big way (Chart 28), bringing down the unexplored areas to 15% from 89% in 1995-96.

Chart 31: India’s exploration history and outlook (in-place reserves)

Source: BP Statistical Review 2010 and CMIE

NELP – Key highlights • Increased private sector participation

• 100% FDI encourages foreign investment

• Cost recovery up to 100%

• Competitive and fair bidding

• Seven-year income tax holiday (MAT applicable)

The NELP has resulted in reducing the unexplored area from 89% to 15%.

Early Stage Nationalisation Gol small fields policy NELP era Open policy

Dominated by National Oil companies

Improved terms & large discoveries

Continued liberalisation

Emergence of Indian Private Companies (Reliance) &

reinvigorated PSUs

Onset of Liberalisation

NELP Rounds

Small Fields Policy

Nationalisation of Burmah

Formation of State

companies

Era dominated by Burmah Oil

& other companies

Indian Independence Expected

Accretion rate?

Fledging liberalization Partial privatisations e.g. ONGC/OIL/IOC

0

1880 1847 1980 1991 1999 2009

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erve

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Recent Exploration success Reliance / GSPC /

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6 Fields e.g. Enron,

Command/CaimNiko & Hardy

ONGC’s major discoveries


36

Table 14: Blocks offered under the NELP NELP I NELP II NELP III NELP IV NELP V NELP VI NELP VII NELP VIII

Blocks offered 48 25 27 24 20 55 57 70 Deepwater 12 8 9 12 6 25 29 24 Shallow 26 8 7 1 2 6 9 28 Onland 10 9 11 11 12 24 19 18 PSC signed 24 23 23 20 20 52 41 36 Deepwater 7 8 9 9 6 21 11 8 Shallow 16 8 6 1 2 6 7 13 Onland 1 7 8 10 12 25 23 15 Area awarded (sq km) 1,94,735 2,63,050 2,04,588 1,92,810 1,15,180 3,06,200 1,17,000 60,200Percentage of acreage awarded (%) 7.4 8.5 6.5 6.1 3.7 9.7 3.6 1.9Planned investment (US$ mn) 1,150 775 1,038 1,135 917 3,317 1,700 3,900Source: Infraline, I-Sec Research

Despite one of the biggest gas discoveries at the KG D6, India’s share of global gas reserves stands at an insignificant 0.6%. Its share of global oil reserves also comes in at just 0.5%. To achieve energy security, the Government is willing to encourage more investments in the sector; we believe India is at the beginning of a huge wave of E&P investments.

Table 15: India still a minnow in the global E&P stage (bn bbls) Oil: proved reserves 1989 1999 2008 2009 % of total R/P ratioAustralia 3.1 4.7 4.2 4.2 0.3 20.7Brunei 1.2 1.3 1.1 1.1 0.1 17.6China 16 15.1 14.8 14.8 1.1 10.7India 4.3 5 5.8 5.8 0.4 21.1Indonesia 5.1 5.2 3.7 4.4 0.3 11.8Malaysia 3.7 5 5.5 5.5 0.4 20.4Thailand 0.2 0.4 0.5 0.5 0.0 3.8Vietnam 0.1 1.8 4.7 4.5 0.3 35.7Other Asia Pacific 0.9 1.4 1.4 1.3 0.1 11.2Total Asia Pacific 34.7 39.9 41.7 42.2 3.2 14.4 Total World 1,006.4 1,085.6 1,332.4 1,333.1 100.0 45.7of which: European Union # 7.7 9.0 6.1 6.3 0.5 8.2

OECD 116.4 93.3 91.3 90.8 6.8 13.5OPEC 763.2 831.9 1,028.8 1,029.4 77.2 85.3Non-OPEC £ 175.8 166.4 180.6 180.9 13.6 14.7Former Soviet Union 67.3 87.2 123.0 122.9 9.2 25.5

Canadian oil sands NA 163.3 143.3 143.3 Proved reserves and oil sands NA 1,248.9 1,475.7 1,476.4 Source: BP statistical review 2010


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Table 16: Gas reserves – India versus world Natural gas: Proved reserves 1989 1999 2008 2009 % Share R/P TCM TCM TCM TCM of total ratio Australia 1.0 2.0 3.1 3.1 1.64 72.7 Bangladesh 0.7 0.3 0.3 0.4 0.19 18.0 Brunei 0.3 0.4 0.4 0.4 0.19 30.7 China 1.0 1.4 2.5 2.5 1.31 28.8 India 0.7 0.6 1.1 1.1 0.59 28.4 Indonesia 2.6 2.6 3.2 3.2 1.70 44.3 Malaysia 1.6 2.5 2.4 2.4 1.27 38.0 Myanmar 0.3 0.3 0.6 0.6 0.30 49.4 Pakistan 0.7 0.7 0.8 0.9 0.48 23.9 Papua New Guinea 0.2 0.4 0.4 0.4 0.24 * Thailand 0.2 0.3 0.3 0.4 0.2 11.6 Vietnam - 0.2 0.6 0.7 0.36 85.2 Other Asia Pacific 0.3 0.3 0.4 0.4 0.19 20.9 Total Asia Pacific 9.5 12.1 16.0 16.2 8.66 37.0 Total World 122.4 148.6 185.3 187.5 100.00 62.8 of which: European Union 3.4 4.0 2.5 2.4 1.29 14.1

OECD 15.6 14.3 16.4 16.2 8.6 14.4 Former Soviet Union 47.1 50.9 57.5 58.5 31.2 84.2

Source: BP statistical review 2010

Favourable fiscal policies support strong investments

PSC, the most favoured agreement. Every E&P project is based on an agreement, wherein the operator takes the responsibility of drilling, production and other oil field services and the Government seeks to protect the public interest.

Of the various types of agreement operational globally such as joint ventures, production and sharing contracts (PSC), concessions, services and hybrids, PSC is favoured in India.

Table 17: Types of agreement prevailing across the world Type of agreements Contractor Government Number of countries using

Concession All risk All reward

Reward is a function of production & price 59

Joint venture Share in risk & reward Share in risk & reward 31

Service contract No risk All risk All reward 2

Hybrid Mixed Mixed 16

PSC Exploration risk Share in reward Share in reward 40

Source: DGH

Table 18: India’s policy vis-à-vis other countries INDIA

Malaysia Indonesia Philippines Australia New

Zealand Shallow

waterDeep

WaterType of system PSC PSC SA R/T* R/T PSC PSCContractor take (%) 32 30 46 46 56 Biddable Royalty (%) 10.50 3 7.5 0 5 10 5 & 10Cost rec. limit (%) 75 80 70 100 100 100 100Access to gross revenue (%) 87 91 87 100 95 100 100

Govt. Carry (%) 15 0 0 0 0 0 0Ring fence (%) Yes Yes Yes No Yes Yes Yes

Source: DGH

PSC is one of the most widely accepted forms of agreement, striking the right balance between investor and Government interests


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Chart 32: Framework PSC fiscal terms

Source: DGH

Contractor’s share

Government’s share

d. Development

c. Exploration

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a. Royalty

Cost Petroleum

Profit Petroleum

Production Value

Government’s Take

Income Tax

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Annexure 3: Index of Tables and Charts Tables Table 1: Share of subsidy contribution across categories ....................................................6 Table 2: Oil companies’ contribution much higher than under-recoveries ...........................8 Table 3: Global and Indian primary energy consumption .....................................................9 Table 4: Energy demand growth – A close proxy of GDP growth ......................................10 Table 5: Domestic crude balance .......................................................................................11 Table 6: Declining oil production, a concern.......................................................................11 Table 7: Oil import details ...................................................................................................11 Table 8: Domestic oil production details .............................................................................12 Table 9: Domestic gas supply scenario in FY11.................................................................14 Table 10: Domestic gas demand-supply scenario..............................................................15 Table 11: Global LNG demand-supply ...............................................................................19 Table 12: Robust passenger car sales growth ...................................................................23 Table 13: Developing crisis in other....................................................................................33 Table 14: Blocks offered under the NELP ..........................................................................36 Table 15: India still a minnow in the global E&P stage.......................................................36 Table 16: Gas reserves – India versus world .....................................................................37 Table 17: Types of agreement prevailing across the world ................................................37 Table 18: India’s policy vis-à-vis other countries ................................................................37 Charts Chart 1: RoE comparisons of oil PSUs.................................................................................6 Chart 2: Under-recoveries – Contribution from oil PSUs and the Government....................7 Chart 3: Acreage holdings in KG Basin blocks (dominated by ONGC and RIL) ................13 Chart 4: Reserve additions in the KG Basin .......................................................................13 Chart 5: World’s top exploration provinces (1999-2009) by number of discoveries ...........13 Chart 6: Pipeline infrastructure in India...............................................................................17 Chart 7: Price comparison – KG-D6 gas vis-à-vis LNG......................................................18 Chart 8: Cost of producing urea through different fuels......................................................20 Chart 9: Global GRM trends over the year .........................................................................21 Chart 10: Global Petroleum liquids consumption by end-use sector..................................22 Chart 11: Product-wise demand growth .............................................................................22 Chart 12: Arabs and Maya crude spreads ..........................................................................23 Chart 13: OPEC spare capacity..........................................................................................24 Chart 14: Product spreads over Brent ................................................................................24 Chart 15: Refinery utilisation rates inching up ....................................................................24 Chart 16: Demand for basic chemical & plastics ................................................................25 Chart 17: Ethylene capacity addition ..................................................................................26 Chart 18: Ethylene demand trend.......................................................................................26 Chart 19: Middle East PE capacity addition........................................................................27 Chart 20: PP demand-supply dynamics .............................................................................28 Chart 21: Expected consumption pattern of propylene ......................................................28 Chart 22: Ethylene production cash costs ..........................................................................29 Chart 23: Naphtha cracks ...................................................................................................29 Chart 24: Domestic polymer demand growth .....................................................................30 Chart 25: Domestic chemical demand growth....................................................................30 Chart 26: Overall domestic plastics and chemicals demand trend.....................................30 Chart 27: Spare capacity ....................................................................................................31 Chart 28: Saudi Arabia – Oil production .............................................................................32 Chart 29: OPEC production ................................................................................................33 Chart 30: Crude exports from Libya....................................................................................34 Chart 31: India’s exploration history and outlook (in-place reserves).................................35 Chart 32: Framework PSC fiscal terms ..............................................................................38


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Market Cap Rs3,389bn/US$76bn Year to Mar FY10 FY11E FY12E FY13EReuters/Bloomberg RELI.BO/RIL IN Revenue (Rs bn) 2,037 2,233 2,568 2,648 Shares Outstanding (mn) 3,273 Net Income (Rs bn) 159.0 203.1 248.4 266.8 52-week Range (Rs) 1,187/841 EPS (Rs) 48.0 61.3 75.0 80.6 Free Float (%) 54.5 % Chg YoY 113.9 27.8 22.3 7.4 FII (%) 18.3 P/E (x) 21.6 16.9 13.8 12.8 Daily Volume (US$/'000) 131,670 CEPS (Rs) 81.1 96.2 111.3 121.3 Absolute Return 3m (%) (1.9) EV/E (x) 11.3 8.2 7.4 6.7 Absolute Return 12m (%) (8.1) Dividend Yield (%) 0.7 0.7 0.7 0.7 Sensex Return 3m (%) (5.6) RoCE (%) 9.2 10.8 11.4 11.5 Sensex Return 12m (%) 8.3 RoE (%) 13.2 13.4 13.6 12.9

Reliance Industries BUY

On a cyclical upturn Rs1,035Reason for report: Reinitiating coverage



Target price Rs1,197

Shareholding pattern

Jun ’10

Sep ’10

Dec ’10

Promoters 46.5 46.5 46.5 Institutional investors 29.0 28.2 29.2 MFs and UTI 2.7 2.1 2.4 FIs/ Banks 0.3 0.3 0.3 FIIs 17.9 17.5 18.3 Others 24.5 25.3 24.3

Source: www.nseindia.com

Price chart

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Reliance Industries’ (RIL) valuations will be led by its traditional businesses,refining and petrochemicals. Global refining margin will likely be robust (RILUS$11/bl in FY13E) as product demand from Asia surges and European and theUS markets stabilise. In petchem, the demand drivers from emerging markets are expected to be strong enough to absorb incremental capacities from the MiddleEast. E&P will also chip in as key concerns have been addressed through theBritish Petroleum (BP) deal, indicating a strong bottom for its E&P valuations at US$24bn. We value RIL at Rs1,197 on sum of the parts (SOTP), which yields 15% upside from the current levels. We reinitiate coverage on RIL with a BUY and viewit among one of the best value picks in the oil & gas sector.

Refining – GRM outlook supports our bullish view. We expect refining to contribute significantly to profitability. The recent revival in global GRMs will improve with positive demand drivers from the developed economies. RIL’s GRMs will likely be robust at current levels (US$11/bl in FY12E-13E), in tandem with the rise in benchmark Singapore GRMs. Improvement in light-heavy spreads and setting up of a petcoke gasification unit can provide further upside to RIL’s GRMs. We value refining at 7x FY13E EV/EBITDA, implying Rs458/share fair value for the segment.

E&P – BP deal assuages valuation concerns. The BP deal has valued RIL’s 23 E&P blocks (30% stake acquired) at US$24bn, indicating a bottom for its E&P valuations. The concerns on volume ramp-up in KG D6 still continue, but the dealhas generated strong expectations that such issues will be resolved soon. We,however, continue to expect that D6 production will peak at 87mmscmd by end-FY13E, in line with the recent comments from the Ministry of Petroleum and Natural Gas (MoPNG). We value E&P at Rs354/share, almost in line with the BP deal. Strong portfolio of exploratory blocks and BP’s technical expertise can lead to significant reserve upside from most KG Basin blocks.

Petrochemicals – Margins to be stable. We expect RIL’s petchem margin to be robust at the current levels – till now, margins have surpassed Street estimates. Theindustry now expects incremental low-cost ethylene capacities to be comfortably absorbed by the strong Asian demand, specifically from China and India. RIL’s predominantly domestic focus is a key advantage, which will ensure >95% petchemutilisation. RIL’s planned capacity expansion is expected to result in significantvaluation trigger as it is expected to start during a potentially higher margin scenario.

Reinitiate with BUY. Increased contribution from the high-margin oil & gas business along side gradual expansion in refining and petchem margins would drive RIL’s EPS over FY11-13E. Reinitiate with BUY.

Reliance Industries, April 4, 2011 ICICI Securities

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TABLE OF CONTENTS

Refining – GRM outlook supports our bullish view ...................................................43 Room for further premium expansion ...........................................................................43 Refining to contribute significantly to overall valuations ...............................................45 Refining – Valuation assumptions.................................................................................46 Valuations highly sensitive to GRMs.............................................................................46

E&P – BP deal assuages valuation concerns.............................................................47 BP deal creates a bottom for E&P valuations...............................................................47 Volume ramp-up schedule still unclear .........................................................................48 Key issues yet to be resolved .......................................................................................49 E&P valued at US$24bn ...............................................................................................49 Key assumptions for DCF – KG D6 block.....................................................................50 Strong portfolio of exploratory blocks offer high reserve accretion potential ................50

Petrochemicals – Margins to be stable .......................................................................53 Strong domestic demand & integration, key differentiators ..........................................53 Contribution from petchem at Rs294/share ..................................................................54 Expansion projects, revival of off-gas based crackers – Next big trigger .....................55

Valuations.......................................................................................................................56 Profitability expansion to drive valuations .....................................................................56 Reinitiate with BUY .......................................................................................................56 Rising cash reserves to be invested into core businesses ...........................................57 Key risks to our call .......................................................................................................58

Annexure 1: Consolidated financials...........................................................................59 Annexure 2: Index of Tables and Charts .....................................................................63


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Refining – GRM outlook supports our bullish view Refining has to be upbeat to support our bullish view on the stock given the reduced contribution from E&P after the BP deal. RIL’s 62mmtpa refining capacity at Jamnagar is contributing 35% to its EBITDA, which will likely improve to >40% in FY12E-13E as GRMs scale up to US$11/bl levels.

RIL’s GRMs are currently averaging at US$10/bl and are expected to strengthen further in Q1FY12 as the driving season begins in the US. We conservatively estimate RIL’s FY12E GRMs to be US$10.5/bl, considering the increased volatility in crude based on the political crisis in the Middle East and North Africa.

Chart 1: GRM trend

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Room for further premium expansion

A key advantage that RIL enjoys due to its high complexity is its premium over benchmark Singapore GRMs. We expect the recent revival in global GRMs to sustain – they are expected to improve with the global economic recovery. We expect RIL’s premium over Singapore GRM to stabilise at ~US$4/bl. Historically, the premium has touched US$8/bl, led by strong expansion in gas-oil spread along with the increase in Arab light-heavy spread. Hence, there is room for further premium expansion, primarily from increase in light-heavy spread, if long-term crude price sustains above US$100/bl.

RIL’s GRMs will continue to be on an uptrend, driven by increased demand for middle distillates and widening light-heavy spreads


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Chart 2: Light-heavy spreads

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Source: Bloomberg A key long-term catalyst to trigger the expansion of RIL’s premium over benchmark Singapore complex GRM is RIL’s petcoke gasification project (commissioning planned at the Jamnagar refining complex). Post the commissioning of the project (expected in three years), the Nelson complexity of the Jamnagar complex will likely increase beyond 14 (from 12.8 for the 62mntpa combined capacity), leading to higher spreads over benchmark Singapore margins. We await more clarity in the next 2-3 months, after which we will factor it in our valuations.

Chart 3: RIL’s premium over Singapore Complex GRM

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Light-heavy spread expected to rise further because of the MENA region unrest

RIL’s premium over Singapore complex can retest previous highs


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Chart 4: OPEC spare capacity

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Refining to contribute significantly to overall valuations

We have valued RIL’s refining business at 7x FY13E EV/EBITDA, in line with Asian and global peers. The global multiples for refining companies have been averaging at ~6.6x, but Asian peers have been averaging at 7.4x. We expect the Asian refiners to continue to command a premium due to strong local demand and higher utilisation.

Although RIL’s refining business can command a premium over global peers considering higher profitability due to economies of scale and the fully-integrated facility at Jamnagar, we still ascribe 7x FY13E EBITDA (more than the global average, but lower than the Asian average) considering RIL’s focus on exports and vulnerability to the global demand-supply environment. Historically, RIL’s operating rate for its refinery has been at ~100%, way higher than the global average.

We ascribe Rs458/share value to refining, ~38% of RIL’s fair value. The company’s superior operational efficiency vis-à-vis international peers make the refining business an excellent play on the global economic recovery.

Table 1: Refinery – Snapshot (Rs mn, Year ending March 31)

FY11E FY12E FY13E Refining sales 1,771,555 2,080,222 2,132,930 % growth 8.03 17.42 2.53 EBITDA 136,737 182,291 196,033 EBITDA (%) 7.72 8.76 9.19 EBIT 99,125 139,679 148,421 EBIT (%) 5.60 6.71 6.96


Table 2: Refinery – Valuations (Rs mn)

FY13E EBITDA 196,033 EV (7x EBITDA) 1,372,231 EV (Rs/share) 458


Reduction in OPEC spare capacity due to MENA unrest could add more heavy crude supplies in the market

Asian refiners trade at a premium to global refiners


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Table 3: Valuations for international peers – Refinery (Rs mn, Year ending March 31)

EV/EBITDA (x) P/BV (x) P/CF (x) P/E (x)

FY12E/CY11E

FY13E/CY12E

FY12E/CY11E

FY13E/CY12E

FY12E/ CY11E

FY13E/ CY12E

FY12E/CY11E

FY13E/CY12E

Valero Energy Corp 4.64 4.52 1.05 0.95 5.17 4.94 10.51 8.90S-Oil Corp 9.58 8.79 3.22 2.74 12.14 10.98 12.84 11.75Sunoco Inc 7.90 6.62 1.72 1.59 8.77 6.99 25.50 16.98Cosmo Oil 6.42 5.91 0.68 0.64 2.86 2.64 9.09 8.10Thai Oil PCL 8.00 7.52 2.13 1.93 8.22 7.95 12.42 11.77Tesoro Corp 4.80 4.54 1.13 0.97 4.93 4.37 12.27 10.73Frontier Oil Corp 5.29 5.85 2.41 2.14 7.43 8.30 10.83 11.85Motor Oil Hellas Corinth Refineries SA 6.22 5.94 2.26 1.98 5.48 4.92 8.14 7.54New Zealand Refining 6.39 5.91 2.00 1.86 7.08 6.33 12.70 10.86Chennai Petroleum 4.64 4.52 1.05 0.95 5.17 4.94 10.51 8.90Average 6.58 6.18 1.84 1.64 6.90 6.38 12.70 10.94

Source: Bloomberg, I-Sec Research

Refining – Valuation assumptions

• FY12E and FY13E Singapore GRMs at US$6.5/bl and US$7/bl respectively

• RIL’s premium to Singapore GRM increased to US$4/bl for both FY12E & FY13E

• Overall refinery utilisation at 98% through FY12E-13E

• Average GRMs – US$10.5/bl in FY12E and US$11/bl in FY13E

Valuations highly sensitive to GRMs

Refining valuations are highly sensitive to GRMs, which move in tandem with the global demand-supply dynamics. Lower-than-expected average GRMs can significantly impact refining valuations and hence, the stock. Our sensitivity analysis captures the impact on refining valuations (Table 4). We have factored in FY12E-13E US dollar-rupee rate of Rs46.

Table 4: Sensitivity – Refining value (Rs/share)

GRMs (US$/bbl) US$/Rupee 10.0 10.5 11.0 11.5 12.0 44.0 389.4 411.8 434.1 456.4 478.7 45.0 400.6 423.4 446.3 469.1 492.0 46.0 411.8 435.1 458.5 481.8 505.2 47.0 422.9 446.8 470.6 494.5 518.4 48.0 434.1 458.5 482.8 507.2 531.6


Every US$1 change in RIL’s GRMs impacts our fair value Rs46/share


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E&P – BP deal assuages valuation concerns BP bought 30% stake in RIL’s 23 NELP blocks for US$7.2bn, indicating a bottom to RIL’s E&P valuation at US$24bn. E&P concerns still exist, but the deal has generated strong expectations that such issues will be resolved soon. We, however, expect D6 production to peak at 87mmscmd by end-FY13E, in line with the recent comments by the MoPNG. We value E&P at Rs354/share, in-line the BP deal valuation. However, BP’s technical expertise might aid further reserve upside from the KG Basin.

BP deal creates a bottom for E&P valuations.

BP will buy 30% in RIL’s 23 blocks, mostly on the East Coast – this will also include the producing KG D6 block. Also, a 50:50 joint venture (JV) will be formed between the two companies for sourcing and marketing gas in India. The JV will partner in creating infrastructure for receiving, transporting and marketing natural gas in India. The partnership will combine BP’s proven deepwater exploration and development capabilities with RIL’s project management and operations expertise.

BP will pay RIL US$7.2bn and completion adjustments for the 30% interests to be acquired in the 23 production sharing contracts. Future performance payments of up to US$1.8bn could be paid based on exploration success (that will result in development of commercial discoveries). These payments and combined investment could amount to an overall commitment of US$20bn for BP over the next 10-20 years.

Hence, a 30% stake at US$7.2bn values the entire stake for the 23 blocks at US$24bn. If we add the performance payment of US$1.8bn, the overall value goes up to US$30bn. The net value attributable to RIL for the transaction is ~US$23.8bn.

BP deal valuations Assuming that the value is generated through all the 23 prospective blocks, including D6, RIL’s net stake in these blocks post this transaction would average at 66.7%. Grossing up the entire valuation based on cash consideration of US$7.2bn, the value attributable to RIL would be US$23.2bn. If we include the discounted value (over 10 years) of US$1.8bn cash incentives, the overall valuations stand at US$23.8bn.

Table 5: BP valuation for RIL’s 23 blocks (US$ bn)

RIL's average stake in the blocks before the deal (%) 97 RIL's average stake in the blocks after the deal (%) 67 Cash payment for 30% stake by BP 7.2 Gross valuation for these 24 blocks 24 Net value for RIL 16.0 Add cash 7.2 Total value for RIL 23.2 Performance linked cash incentive 1.8 Discounted value of incentives over 10 years 0.6 Net value for RIL incentives 23.8


We value E&P at US$24bn, inline with the BP deal. The deal creates a strong bottom for E&P valuations


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Table 6: Block details for transaction

Basin Block Exploration rounds

Acreage (Sqkms)

RIL stake (%)

BP stake (%)

Hardy (%)

Niko (%)

KG-DWN-98/1 (D4) NELP I 6,700 70 30KG-DWN-98/3 (D6) NELP I 7,645 60 30 10KG-DWN-2001/1 (D9) NELP III 11,605 60 30 10KG-DWN-2003/1 (D3) NELP V 3,280 60 30 10KG-DWN-2004/4 (D13) NELP VI 11,904 70 30

KG Basin KG-DWN-2004/7 (D16) NELP VI 11,856 70 30 30

MN-DWN-98/2 (MND10) NELP I 7,195 70 30MN-DWN-2003/1 (MNDV4) NELP V 17,050 55 30 15MN-DWN-2004/1 (MND17) NELP VI 9,885 70 30MN-DWN-2004/2 (MND18) NELP VI 11,813 70 30MN-DWN-2004/3 (MND19) NELP VI 11,316 70 30MN-DWN-2004/4 (MND20) NELP VI 8,822 70 30MN-DWN-2004/5 (MND21) NELP VI 10,454 70 30NEC-OSN-97/2 (NEC25) NELP I 9,461 60 30 10

Mahanadi Basin / North East Coast NEC-DWN-2002/1 D9 NELP IV 25,565 70 30

CY-DWN-2001/2 (D5) NELP III 14,325 70 30CY-PR-DWN-2001/3 (D6) NELP III 8,600 70 30CY-PR-DWN-2001/4 (D7) NELP III 10,590 60 30 10

Cauvery/ Palar Basin PR-CY-DWN-2001/1 (PRD8) NELP III 8,255 70 30 Cambay Onland CB-ONN 2003/1 (CB10) NELP V 635 70 30 Upper Assam Basin AS-ONN-2000/1 (AS17) NELP II 6,215 60 30 10

KK-DWN-2001/1 (D1) NELP III 27,315 70 30Kerala Konkan KK-DWN-2001/2 (D2) NELP III 31,515 70 30 Total 272,001

Source: RIL, BP plc

Volume ramp-up schedule still unclear

RIL’s flagship deepwater KG-D6 block in the Krishna-Godavari Basin was awarded to RIL and Niko Resources (NIKO) under NELP-1. RIL, as the operator of the block, holds 60% of the participating interest, whereas BP holds 30% and NIKO the remaining. Although the successful commissioning of this block was another proof of RIL’s impeccable project execution skills, the recent production decline has raised serious skepticism on block prospects. At a peak production of 87mmscmd, gas from KG D6 was to address ~50% of India’s gas demand. The timeline of achieving this peak production is unclear and the management’s inability to provide any guidance adds to the uncertainty. Although the BP deal has addressed a major concern on block prospectivity, the management is still to provide clarity on gas volume ramp-up schedule.

Timeline for D-6 production ramp-up to peak is critical


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Key issues yet to be resolved

• Pricing freedom. As per the management, RIL is awaiting clarity on pricing for incremental production from the KG Basin blocks. The company believes that incremental production from other blocks will not be viable at the price of US$4.2/mmbtu approved by the Government for the D6 block. We expect RIL to come out with clarity on most pending issues – the production ramp-up at D6 or the timelines for developing NEC 25 and D6 satellite discoveries post the approval of higher gas pricing.

• Approval delays. RIL has been facing approval delays as regards some of its filings with the Directorate General of Hydrocarbons (DGH), given the revised capex plans for D6, notification of discoveries in some exploratory blocks and development plans of some blocks. The company has filed a formal complaint to the MoPNG. We believe the formal settlement of such issues will take time, which could add to the uncertainty over development plans.

• Tax benefits. The Government had rolled back the tax benefits on gas production in the FY09 Budget. The Government also changed the definition for mineral oil to exclude natural gas, due to which RIL lost on tax benefits on gas production from the D6 block. As per the industry, the NELP contracts promise tax benefits for exploration of hydrocarbons, which include both crude oil and natural gas. Hence, RIL expects some clarification in the short term before it commits further development capex towards the other blocks.

E&P valued at US$24bn We value E&P at Rs355/share using DCF given strong cashflows from the D6 block and reserve upsides from other prospective blocks such as NEC 25, D6 Satellite, D3, D4, D9 and CBM. The KG-D6 block forms a major portion of RIL’s overall E&P valuation of Rs355/share, contributing ~62% to the overall value (Table 7). Other blocks can generate an overall upside of Rs135/share, assuming reserve estimates from NIKO, Hardy Oil reports (NELP blocks) and DGH estimates for the CBM blocks.

Table 7: Block-wise valuations

Block RIL’s share

(mboe)Total EV

(US$ mn)EV/boe

(US$)Value/

share (Rs) Comments D6 (KG-DWM-98/3) 2,548 12,735 5.0 177 DCF value Possible upsides (gas) from D6 679 2,366 3.5 36 EV/boe multiple Possible upsides (oil) from D6 52.2 470 9.0 7.2 EV/boe multiple D6 total 3,279 15,571 4.7 220 Potential upsides D4 247.5 863 3.5 13 EV/boe multiple NEC – 25 717 3,021 4.2 34 DCF and EV/boe multiple D9 270 941 3.5 14.5 EV/boe multiple GS-O1 offshore 43.2 151 3.5 2.3 EV/boe multiple Cauvery basin 315 1,098 3.5 16.9 EV/boe multiple Total 1,278 4,976 3.9 81 CBM (5 Blocks) Sohagpur east 173 603 3.5 9.3 EV/boe multiple Sohagpur west 153 533 3.5 8.2 EV/boe multiple Sonhat North 107 372 3.5 5.7 EV/boe multiple Barmer 1 299 1,043 3.5 16.0 EV/boe multiple Barmer 2 276 962 3.5 14.8 EV/boe multiple CBM total 1,007 3,512 3.5 54 Total 5,564 24,058 4.3 354



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Key assumptions for DCF – KG D6 block

• Cost of equity at 13.3%

• Peak production of 87mmscmd from end-FY13E

• Gas price at US$4.2/mmbtu till FY14E and at US$5.2/mmbtu thereafter

• Cumulative capex at US$12bn

Strong portfolio of exploratory blocks offer high reserve accretion potential

NEC 25. RIL is the operator of the block with 60% working interest and BP and Niko hold the remaining 30% and 10% respectively. This block covers 9,461 sqkms in the Mahanadi Basin, off the East Coast of India. The company has fulfilled its capital commitments for the block and is currently drilling under a six well programme. A development plan was previously submitted for six of the discoveries. A separate commerciality report for the successful AJ wells will be prepared when drilling is completed. RIL has 13 gas discoveries in the NEC 25 block, which have been declared commercial by the DGH. The company has submitted the development plan for six of these discoveries to the DGH, which would be disclosed on approval.

As per Niko Resources, the initial estimate for production from this block was ~8.2mmscmd. However, based on the later presentation, after factoring in the incremental four discoveries, Niko now expects the production to spike 2-3x. The Niko management has sounded extremely positive on the block and expects significant reserve upside.

Mahanadi D4. RIL is the operator with 55% stake, while BP and Niko hold the remaining 30% and 15% interests. The block is currently in the exploration phase, and covers more than 17,000 sqkms on the east coast. The commitment for Phase I exploration includes seismic work and drilling three exploration wells. Originally, the work was to be completed by September ’09. However, the Government has approved a blanket extension of up to three years for this and other deepwater blocks, under the three-year drilling moratorium for the deepwater blocks. The seismic work has been completed and drilling has commenced from Q2FY11.

D3 block – Filing for commerciality expected in FY12. The D3 block was awarded to the RIL (90%) and HEPI (10%) consortium under NELP V. RIL is the operator for the block. The company has four gas discoveries in the block (Dhirubai 39, 41, 44 and 52). Four of the six commitment wells have now been drilled on the D3 exploration block. Several material undrilled prospects exist and the timing of drilling the two remaining commitment wells will be determined by the operator of the block. Although early indications are encouraging, the potential extent and commerciality of the discoveries are yet to be established. However, in the recent reserve evaluation conducted by Gaffney, cline and associates (GCA) in December ’10, the gross risked resource estimates (best estimates) for this block are at 3.7tcf.

Potential upsides from approval of FDP for NEC25 and higher reserve accretion from D4, D3 & D6 satellite blocks


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Table 8: D3 reserve estimates Gross prospective resources

bcf

Prospects Low estimate Best estimate High estimate RIL’s share

(%)

Gross prospective resources *

GCoS(%)

Net to RIL

(BCF) Pleistocene Sand 2 (Central & Northern) 103 382 944 60% 305 183 Pleistocene 500 1279 2559 60% 993 595 Plicene 790 1492 2592 60% 1,044 626 Miocene 766 1609 2898 60% 1,126 675 Oligocene 423 1140 2344 60% 273 164 Total (bcf) 3,743 2,246

GCoS: Geological Chance of Success Source: GCA competent Person Report, Hardy Oil

D9 block – Disappointing drilling results. D9 is a deepwater block in the KG Basin covering 11,605 sqkms of area. RIL holds 60% in the block, while BP and Hardy Oil hold 30% and 10% respectively. RIL has started phase II exploration work in the block and has till date drilled two wells. Both the wells failed to deliver any significant hydrocarbon potential and were abandoned. The resource estimates on the Hardy Oil website have been significantly reduced to 4.7tcf from 10.8tcf (estimated in ’09). It is unclear what strategy will RIL adopt as an operator for further drilling programme in this block, to maximise the commercial potential of the block.

Table 9: D9 reserve estimates (BCF)

Gross prospective resources

Prospects Low

estimate Best

estimate High

estimate

RIL's share

(%) GCoS (%)

Gross prospective resources GCoS (%)

Net to RIL

(BCF) C1 Pliocene 210 630 1,540 60 25% 158 95 Northern Anticline (NW Flank B1)/U. Miocene 900 2,500 5,600 60 20% 500 300 Central Anticline (NW Flank)/U. Miocene 400 1,100 2,100 60 20% 220 132 Central Anticline (Near B3)/U. Miocene 1,000 2,500 5,300 60 20% 500 300 Southern Anticline (SE Flank C1) /U. Miocene 1,100 2,900 6,200 60 10% 290 174 Northern Anticline B1/M. Miocene 1,300 2,500 4,500 60 20% 500 300 Central Anticline (Near B2)/M. Miocene 1,300 1,900 2,700 60 20% 380 228 Southern Anticline C1 /M. Miocene 1,300 1,900 2,600 60 15% 285 171 Northern Anticline (near B1)/L. Miocene 1,800 6,300 15,000 60 15% 945 567 Central Anticline (Near B2)/L. Miocene 1,300 2,800 5,500 60 19% 532 319 Central Anticline (Near A2)/L. Miocene 900 2,300 4,900 60 15% 345 207 Prospective Total (bcf) 4,655 2,793 Leads (bcf) 35.0 21 Prospective + Lead (bcf) 4,690 2,814

GCoS: Geological Chance of Success Source: GCA competent Person Report, Hardy Oil

Coal-bed methane blocks. RIL has a portfolio of five coal-bed methane (CBM) blocks awarded in the past three rounds. The company plans to begin production from the Sohagpur CBM block by end-’11 and expects a peak production of 5mmscmd from these blocks over the next two-three years (Table 10).

Table 10: Reserve estimates of CBM blocks Block Stake (%) In place reserves (mboe) CBM (five blocks) Sohagpur west 100 233 Sohagpur east 100 308 Sonhat North 100 213 Barmer 1 100 598 Barmer 2 100 552 Total 1,904 Source: DGH


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International blocks – Still in the initial stages of exploration. RIL has a portfolio of 11 international blocks with 80,000 sqkms acreage distributed across Yemen (three blocks), Oman (two blocks), Kurdistan (two blocks), Colombia (two blocks), East Timor (one block) and Australia (one block). A block in Yemen is the only producing block, with oil production of 4,500bpd (Table 11).

Table 11: RIL’s portfolio of international blocks Block Country Location Acreage Operator Block K East Timor Deepwater 2,384 RIL Block 9 Yemen Onland 2,234 Calvalley Block 18 Oman Deepwater 21,140 RIL Rovi Kurdisthan Onland 516 RIL Sarta Kurdisthan Onland 607 RIL Block 41 Oman Deepwater 23,850 RIL Block 34 Yemen Onland 7,016 RIL Block 37 Yemen Onland 6,894 RIL W-06-05 Australia Shallow water 5,760 RIL Borojo North Columbia Deepwater 4,000 RIL Borojo South Columbia Deepwater 4,000 RIL Block 39 Peru Onland 8,903 Repsol Block 108 Peru Onland 12,000 Plus Petro Block 141 Peru Onland 5,169 RIL Source: Company


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Petrochemicals – Margins to be stable We expect petrochemicals margins to be robust at the current levels, which have till now surpassed Street estimates. The industry now expects incremental low cost ethylene capacities to be absorbed comfortably by the strong Asian demand, specifically by China and India. RIL’s predominantly domestic focus is a key advantage, which will ensure >95% utilisation for its petchem capacity. The company’s planned capacity expansion will act as a significant trigger for valuations, as the capacities will get commissioned during a favourable margin scenario.

Strong domestic demand & integration, key differentiators

RIL’s operating levels have remained consistently >90% throughout the entire downcycle in the past 4-5 quarters, led by strong domestic demand. Domestic demand has been resurgent, led by increased investments in infrastructure. Also, product cracks for RIL have been strong, led by integrated operations. The overall Indian polymer industry has grown 13%, led by strong 17% & 9% demand growth in PP & PE respectively (Charts 5-7).

Chart 5: Domestic demand for basic chemicals and plastics

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Domestic plastic and chemical markets to enter into high growth


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Chart 6: Domestic polymer demand growth

Chart 7: Domestic chemical demand growth

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Contribution from petchem at Rs294/share

We expect EBIT margin from petrochemicals to be stable at 14% in FY12E-13E, led by improved global outlook on polyolefin margins given the strong demand pull from the domestic and Chinese markets. Significant upside to the global margin outlook exists as the European and US markets revive, leading to more-than-expected absorption of Middle East capacities.

We have valued the petrochemicals business at 7x FY13E EBITDA, in line with international peers (Table 14). We expect average multiples to expand globally over the next 2-3 years as demand recovery from the developed economies trigger a margin expansion. However, when compared with global peers (naphtha-based crackers), RIL would continue to earn superior returns on account of its fully-integrated operations and robust domestic demand. RIL will continue to be a dominant player in the domestic petrochemicals industry and would garner >90% of the domestic market share post its planned capacity expansion.

Table 12: Petrochemicals – Snapshot (Rs mn. year ending March 31)

FY11E FY12E FY13E Petrochemicals sales 599,896 687,520 703,222 % growth 8.91 14.61 2.28 EBITDA 120,073 119,142 125,508 EBITDA (%) 20.02 17.33 17.85 EBIT 85,152 83,220 88,586 EBIT (%) 14.19 12.10 12.60


Table 13: Petrochemicals – Valuations (Rs mn)

FY13E EBITDA 125,508 EV (7x EBITDA) 878,553 EV (Rs/share) 294


RIL enjoys dominance in the fast-growing polypropylene segment

Petchem multiples can command a premium based on outperformance vis-à-vis peers


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Table 14: Petrochemicals – Valuations of international peers EV/EBITDA (x) P/BV (x) P/CF (x) PE (x)

FY12E/CY11E

FY13E/CY12E

FY12E/CY11E

FY13E/ CY12E

FY12E/ CY11E

FY13E/CY12E

FY12E/CY11E

FY13E/CY12E

SABIC 13.47 12.94 2.30 2.23 12.78 12.82 11.80 11.20Sinopec Shanghai Petrochemical 11.93 14.29 1.28 1.21 6.40 11.37 8.55 12.00LG Chem 7.84 7.04 3.37 2.67 11.31 9.66 12.78 11.32Asahi Kasei 4.53 4.41 1.17 1.08 5.37 5.05 13.10 11.06Toray Industries Inc 8.61 7.87 1.58 1.44 7.59 7.10 17.39 15.39Kuraray 4.37 4.20 1.11 1.04 6.23 5.90 13.52 11.98Teijin 6.25 5.93 1.30 1.18 4.37 4.30 14.85 12.36Mitsui Chemicals 7.06 6.56 0.75 0.73 3.12 3.16 11.44 13.64Honam Petrochemical 13.47 12.94 2.30 2.23 12.78 12.82 11.80 11.20Average 8.01 7.91 1.61 1.45 7.15 7.42 12.93 12.37

Source: Bloomberg

Expansion projects, revival of off-gas based crackers – Next big trigger

RIL had announced plans to set up an off-gas based cracker and downstream units at Jamnagar. The cracker with ~1.8mntpa ethylene capacity will probably be one of the largest crackers globally, providing economies of scale. Also, since the cracker is off-gas based, we expect EBITDA margin to reach GAIL’s current EBITDA margin at >50%. However, the cracker is expected to start operations only after three years from the announcement date (more clarity to emerge from April FY12).

RIL intends to expand its polyester capacity – by 1.4mmtpa in PX, 2.3mmtpa in PTA, 0.54mmtpa in PET and by 0.36mmtpa in PFY. The overall investment in these expansion projects is ~US$12bn – the projects are expected to get commissioned in FY14. We are waiting for RIL to announce precise details for the investments in these projects (probably by May ’11), after which we will capture it in our valuations.

The timing of the projects seems strategic and RIL expects to benefit from a potential super-cycle in petchem (expected to start in FY14).


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Valuations

Profitability expansion to drive valuations

Increased contribution from the high-margin oil & gas business along side gradual expansion in refining and petchem margins would drive RIL’s EPS CAGR to 24% over FY10-13E. Led by the divestment of 30% stake to BP in its 24 key E&P blocks, RIL’s refining business will continue to contribute the most to overall EBIT in the next 2-3 years and will likely touch a peak of 42% in FY13E as the company’s GRMs expand to US$11/bl. Also, petchem capacity expansion, post FY14, will likely lead to increased contribution from the segment to overall EBIT. Therefore, the cyclical upturn in the refining and petrochemicals businesses is critical for RIL’s valuation expansion, while E&P would continue to provide cashflow expansion triggers for the company.

Table 15: Segment-wise EBIT contribution (Rs mn, year ending March 31)

FY10 FY11E FY12E FY13E Petrochemicals 85,520 85,152 83,220 88,586 % total 43.12 29.52 24.86 25.36 Refining 58,270 99,125 139,679 148,421 % total 29.38 34.37 41.72 42.48 Oil & Gas 54,130 103,849 111,497 111,887 % total 27.29 36.00 33.30 32.03 Others 430 320 400 480 % total 0.22 0.11 0.12 0.14 Total 198,350 288,445 334,796 349,374


Reinitiate with BUY

We have valued RIL on SOTP at 1,197/share, indicating a 16% upside from the current levels. We have valued the cyclical businesses, petchem and refining, at 7x FY13E EBITDA. The KG D6 block has been valued using DCF and potential reserve upside (as per the data available) through EV/boe.

RIL’s key cyclical businesses – refining and petchem – are expected to drive the company’s profitability in the next 2-3 years as the developed economies stabilise and converge back to demand growth scenarios. In our view, the current stock price is not pricing in the revival in GRMs and additional triggers from the E&P assets post the RIL-BP deal. We expect global GRMs to remain robust and with ~40% of RIL’s EBIT accruing from refining, the company’s overall profitability is expected to be robust over the next 2-3 years.

Also, triggers exist in the form of faster-than-expected ramp-up in KG D6 gas production as technical and regulatory issues get addressed. RIL’s US$7.2bn cash compensation from BP and its technical expertise provides its E&P business with tremendous flexibility to accelerate the development of other prospective discoveries in the KG Basin.

Investment in RIL will provide a unique combination of an ideal long-term play on the global economic recovery through refining and petchem and robust domestic consumption story through oil&gas production and retail businesses. Reinitiate with BUY.


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Table 16: RIL – SOTP valuations

(Rs mn) Per share

value Comment Refining 1,372,231 458 FY13E EV/E of 7x Oil and gas production 140,343 47 FY13E EV/E of 7x Petrochemicals 878,553 294 FY13E EV/E of 7x Core business enterprise val 2,391,126 799 Reliance Retail 60,000 20 Total investments made till date Marcellus Shale Acquisition 16,317 5 Eagle ford shale 8,015 3 E&P business KG D6 valuation 657,635 220 DCF Other blocks 401,374 134 Valuation of risked reserves E&P business valuation 1,059,009 354 Enterprise value 3,534,467 1,181 Net debt (net of warrants inflow, investments made in E&P assets) (5,195) (2) Adjusted FY12 net debt Value per share (on existing business) 1,183 SEZ 40,000 13 Total investment made till date Total value per share 1,197


Rising cash reserves to be invested into core businesses

We expect RIL’s >US$8bn annual cashflows to be invested in its core businesses – Petchem, Refining and E&P. Concerns exist as reportedly, RIL is unable to finalise new investment avenues for its burgeoning cash reserves, especially after its failed Lyondell Basell bid and delays in E&P investments. However, the company now plans to build on its investment plan announced in Petchem and Refining.

RIL intends to expand its polyester capacity – by 1.4mmtpa in PX, 2.3mmtpa in PTA, 0.54mmtpa in PET and by 0.36mmtpa in PFY. The overall investment in these expansion projects is ~US$12bn – the projects are expected to get commissioned in FY14. The company would implement the Petcoke regasification project (~US$1bn) at its Jamnagar refining complex, which would help raise its complexity.

Also, RIL has committed US$5-7bn investments in the Shale gas businesses in the US (JVs in Marcellus and Eagle Ford shale acreages), which would contribute to its consolidated EBITDA from FY14-15.

However, we believe RIL’s biggest investment outgo would be in developing its discoveries on the east coast. Together these discoveries have the potential to eat away at least US$20-30bn investments in the next 5-10 years, since most of these exist in high-cost deepwater basins. These investment estimates can change significantly (on the higher side) over the course of time, as the size of reserves and development plans undergo drastic changes.

Table 17: RIL’s cashflows (Rs bn)

FY09 FY10 FY11E FY12E FY13E Operating cashflow 198.3 200.3 291.2 330.9 368.9 Working capital changes 230.2 (155.0) (7.6) (6.2) (7.5) Capital commitments (688.8) (168.1) (91.9) (346.2) (320.0) Free cashflow (260.3) (122.8) 191.7 (21.5) 41.4



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Key risks to our call

• If crude prices continue to rise, demand for refined products could come under downward pressure and affect RIL’s GRMs.

• Slowdown in global economic growth, either due to high crude prices or from other factors could impact RIL’s refining and petrochemical margins.

• Major changes in estimation of hydrocarbon reserves in the companies E&P blocks can have a significant impact on the valuations.

• Change in government levies like Royalty or taxation policies for the blocks that the company is currently producing from can have a major impact on valuations.

Chart 8: Rolling Price/EPS trend

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Annexure 1: Consolidated financials Table 18: Profit & Loss statement (Rs mn, year ending March 31)

FY09 FY10 FY11E FY12E FY13E Gross Sales 1,823,834 2,428,741 2,537,692 2,926,890 3,015,292 Less: Interdivisional sales 265,949 311,470 225,638 266,883 273,791 Less: Excise Duty 45,645 79,874 78,863 91,709 93,860 Net Sales 1,512,240 2,037,397 2,233,191 2,568,298 2,647,641 of which Export Sales 625,823 857,775 1,844,122 2,126,386 2,191,074 of which Domestic Sales 1,198,011 1,570,966 693,570 800,504 824,218 Other Operating Income - - - - - Total Operating Income 1,512,240 2,037,397 2,233,191 2,568,298 2,647,641 Less: Raw Material Consumed 1,124,261 1,546,027 1,684,208 1,983,273 2,020,248 Other Manufacturing Expenses 48,557 56,430 42,678 36,769 42,395 Power and Fuel 38,489 31,408 32,481 32,541 32,603 Personnel Expenses 30,176 27,909 26,320 27,205 28,340 Selling and Distribution Expenses 33,725 44,526 46,760 46,928 48,596 Other Expenses 36,616 34,338 25,046 24,524 24,035 Less Amounts Capitalised 33,805 12,179 - - - Total Operating Expenses 1,278,019 1,728,458 1,857,493 2,151,241 2,196,217 EBITDA 234,222 308,939 375,698 417,057 451,424 Depreciation & Amortisation 56,510 109,458 115,597 120,203 134,948 Other Income 19,142 21,858 28,344 37,941 32,898 Net Other Income 19,142 21,858 28,344 37,941 32,898 EBIT 196,854 221,339 288,445 334,796 349,374 Less: Net Interest 18,163 20,596 33,758 24,447 16,395 Recurring Pre-tax Income 178,691 200,743 254,688 310,349 332,979 Add: Extraordinary Income/exp(+)/(-) - 86,056 - - - Less: Taxation --Current Tax 12,734 31,249 50,759 61,852 66,363 --Deferred Tax 16,454 11,314 836 209 9 Add share of inc of Associates - 135 225 minority interest (184) (796) - - - Net Income (Reported) 149,687 245,031 203,093 248,423 266,832 Recurring Net Income 149,687 158,976 203,093 248,423 266,832



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Table 19: Balance sheet (Rs mn, year ending March 31)

FY09 FY10 FY11E FY12E FY13EASSETS Current Assets, Loans & Advances Cash & Bank balance 227,421 138,908 464,242 352,171 199,714 Inventory 201,096 343,933 385,489 441,433 450,779 Sundry Debtors 48,450 100,829 113,230 134,822 139,605 Loans and Advances 110,018 106,472 108,599 109,606 110,460 Other Current Assets 476 914 3,658 4,162 4,588 Total Current Assets 587,461 691,057 1,075,217 1,042,194 905,146 Current Liabilities & Provisions Current Liabilities Sundry Creditors 345,011 381,256 425,334 497,106 506,228 Other Current Liabilities 12,559 7,650 16,600 19,412 19,782 Provisions 31,150 36,950 35,167 33,474 31,865 Total Current Liabilities and Provisions 388,720 425,856 477,102 549,992 557,875 Net Current Assets 198,741 265,201 598,115 492,202 347,271 Investments Strategic & Group Investments 25,964 24,043 39,298 61,244 86,776 Other Marketable Investments 38,391 107,079 107,079 107,079 107,079 Total Investments 64,355 131,123 146,378 168,323 193,855 Fixed Assets Gross Block 1,571,824 2,241,253 2,398,713 2,520,378 2,814,816 Less Accumulated Depreciation 501,382 639,340 754,937 875,140 1,010,088 Net Block 1,070,442 1,601,913 1,643,776 1,645,238 1,804,728 Add: Capital Work in Progress 738,460 170,337 89,492 292,113 292,113 Less: Revaluation Reserve 122,298 94,137 94,137 94,137 94,137 Total Fixed Assets 1,686,604 1,678,113 1,639,131 1,843,214 2,002,705 Total Assets 1,949,700 2,074,436 2,383,623 2,503,739 2,543,831 LIABILITIES AND SHAREHOLDERS' EQUITY Borrowings Short Term Debt 84,396 80,550 80,550 80,550 80,550 Long Term Debt 678,170 565,506 485,506 373,506 163,428 Total Borrowings 762,566 646,055 566,055 454,055 243,977 Deferred Tax Liability 95,513 106,776 107,611 107,820 107,829 Share Capital Paid up Equity Share Capital 14,439 29,780 29,862 29,944 30,026 No. of Shares outstanding (mn) 1,444 2,978 2,986 2,994 3,003 Face Value per share (Rs) 10 10 10 10 10 Minority Interest 1,389 5,735 5,735 5,735 5,735 Reserves & Surplus Share Premium 453,644 453,941 464,398 474,855 485,312 General & Other Reserve 744,482 926,309 1,304,121 1,525,490 1,765,111 Less: Misc. Exp. not written off 36 23 23 23 23 Less: Revaluation Reserve 122,298 94,137 94,137 94,137 94,137 Net Worth 1,091,621 1,321,605 1,709,956 1,941,864 2,192,025 Total Liabilities & Shareholders' Equity 1,949,700 2,074,436 2,383,623 2,503,740 2,543,832



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Table 20: Cashflow statement (Rs mn, year ending March 31)

FY09 FY10 FY11E FY12E FY13ECash Flow from Operating Activities Reported Net Income 153,093 145,045 203,093 248,287 266,607 Add: Depreciation & Amortisation 51,953 111,828 115,597 120,203 134,948 Provisions Deferred Taxes 18,605 12,000 836 209 9 Less: Other Income 20,599 25,236 28,344 37,941 32,898 Net Extra-ordinary income - - - - - Operating Cash Flow before Working Capital chg (a) 203,053 243,638 291,181 330,757 368,666 Changes in Working Capital (Increase) / Decrease in Inventories (5,892) (125,523) (41,555) (55,945) (9,346) (Increase) / Decrease in Sundry Debtors 16,562 (72,925) (12,400) (21,593) (4,783) (Increase) / Decrease in Operational Loans & Adv. 49,784 27,743 (2,126) (1,008) (853) (Increase) / Decrease in Other Current Assets 247 (435) (2,744) (504) (427) Increase / (Decrease) in Sundry Creditors 109,886 45,096 44,078 71,772 9,121 Increase / (Decrease) in Other Current Liabilities 6,752 2,364 7,168 1,119 (1,239) Working Capital Inflow / (Outflow) (b) 177,339 (123,679) (7,580) (6,158) (7,526) Net Cash flow from Operating Activities (a) + (b) 380,391 119,958 283,601 324,599 361,140 Cash Flow from Capital commitments Purchase of Fixed Assets (267,947) (223,075) (76,615) (324,286) (294,438) Purchase of Investments 4,571 (16,221) (15,255) (21,946) (25,532) Cash Inflow/(outflow) from capital commitments (c) (263,376) (239,296) (91,870) (346,232) (319,970) Free Cash flow after capital commitments 117,015 (119,338) 191,731 (21,633) 41,170 (a) + (b) + (c) Cash Flow from Investing Activities Sale of Investments (105,336) 201,571 Other Income 20,599 25,235 29,019 39,775 35,216 Net Cash flow from Investing Activities (d) 20,599 (80,101) 230,590 39,775 35,216 Cash Flow from Financing Activities Issue of Share Capital during the year 286,499 8,613 10,539 10,539 10,539 Proceeds from fresh borrowings 374,248 6,174 (80,000) (112,000) (210,078) Dividend paid including tax (22,195) (23,949) (26,852) (26,919) (26,986) Net Cash flow from Financing Activities (e) 41,351 129,784 (96,312) (128,380) (226,525) Net Extra-ordinary Income (f) - - - - Total Increase / (Decrease) in Cash 178,965 (69,654) 325,334 (112,072) (152,457) (a) + (b) + (c) + (d) + (e) + (f) Opening Cash and Bank balance 42,801 221,765 152,270 477,604 365,532 Closing Cash and Bank balance 221,765 152,270 477,604 365,532 213,075 Increase/(Decrease) in Cash and Bank balance 178,965 (69,495) 325,334 (112,072) (152,457)



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Table 21: Key ratios (Year ending March 31)

FY09 FY10 FY11E FY12E FY13E Per Share Data (in Rs.) EPS(Basic Recurring) 45.6 48.6 61.9 75.6 81.0 Diluted Recurring EPS 44.9 48.0 61.3 75.0 80.6 Recurring Cash EPS 61.8 81.1 96.2 111.3 121.3 Dividend per share (DPS) 5.8 7.0 7.0 7.0 7.0 Book Value per share (BV) 327.3 399.1 516.4 586.4 662.0 Growth Ratios (%) Operating Income 10.3 34.7 9.6 15.0 3.1 EBITDA 1.2 31.9 21.6 11.0 8.2 Recurring Net Income 1.2 6.2 27.8 22.3 7.4 Diluted Recurring EPS (2.7) 7.0 27.8 22.3 7.4 Diluted Recurring CEPS 0.1 31.1 18.7 15.7 9.0 Valuation Ratios (x) P/E 23.1 21.6 16.9 13.8 12.8 P/CEPS 16.7 12.8 10.8 9.3 8.5 P/BV 3.2 2.6 2.0 1.8 1.6 EV / EBITDA 14.9 11.3 8.2 7.4 6.7 EV / Operating Income 2.3 1.7 1.4 1.2 1.2 EV / Operating FCF 8.1 76.9 10.9 9.5 8.4 Operating Ratio Raw Material/Sales (%) 63.2 65.8 68.5 70.0 69.2 SG&A/Sales (%) 1.9 1.9 1.9 1.7 1.7 Other Income / PBT (%) 10.7 10.9 11.1 12.2 9.9 Effective Tax Rate (%) 16.3 21.2 20.3 20.0 19.9 NWC / Total Assets (%) (1.5) 6.1 5.6 5.6 5.8 Inventory Turnover (days) 59.1 60.9 75.7 73.5 77.7 Receivables (days) 10.9 11.2 15.4 15.5 16.6 Payables (days) 93.0 85.7 87.4 84.9 90.6 D/E Ratio (x) 78.6 57.0 39.4 28.9 16.0 Return/Profitability Ratio (%) Recurring Net Income Margins 9.8 7.7 9.0 9.5 10.0 RoCE 10.2 9.2 10.8 11.4 11.5 RoNW 15.2 13.2 13.4 13.6 12.9 Dividend Payout Ratio 14.8 15.1 13.2 10.8 10.1 Dividend Yield 0.6 0.7 0.7 0.7 0.7 EBITDA Margins 15.5 15.2 16.8 16.2 17.1



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Annexure 2: Index of Tables and Charts

Tables Table 1: Refinery – Snapshot .............................................................................................45 Table 2: Refinery – Valuations............................................................................................45 Table 3: Valuations for international peers – Refinery........................................................46 Table 4: Sensitivity – Refining value...................................................................................46 Table 5: BP valuation for RIL’s 23 blocks ...........................................................................47 Table 6: Block details for transaction..................................................................................48 Table 7: Block-wise valuations............................................................................................49 Table 8: D3 reserve estimates............................................................................................51 Table 9: D9 reserve estimates............................................................................................51 Table 10: Reserve estimates of CBM blocks......................................................................51 Table 11: RIL’s portfolio of international blocks ..................................................................52 Table 12: Petrochemicals – Snapshot ................................................................................54 Table 13: Petrochemicals – Valuations ..............................................................................54 Table 14: Petrochemicals – Valuations of international peers............................................55 Table 15: Segment-wise EBIT contribution ........................................................................56 Table 16: RIL – SOTP valuations .......................................................................................57 Table 17: RIL’s cashflows ...................................................................................................57 Table 18: Profit & Loss statement.......................................................................................59 Table 19: Balance sheet .....................................................................................................60 Table 20: Cashflow statement ............................................................................................61 Table 21: Key ratios ............................................................................................................62

Charts Chart 1: GRM trend.............................................................................................................43 Chart 2: Light-heavy spreads..............................................................................................44 Chart 3: RIL’s premium over Singapore Complex GRM.....................................................44 Chart 4: OPEC spare capacity............................................................................................45 Chart 5: Domestic demand for basic chemicals and plastics .............................................53 Chart 6: Domestic polymer demand growth .......................................................................54 Chart 7: Domestic chemical demand growth ......................................................................54 Chart 8: Rolling Price/EPS trend.........................................................................................58 Chart 9: Rolling EV/EBITDA trend ......................................................................................58


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Market Cap Rs2505.5bn/US$56.2bn Year to March FY10 FY11E FY12E FY13EReuters/Bloomberg ONGD.BO/ONGC IN Revenue (Rs mn) 1,017,546 1,255,153 1,353,801 1,392,136 Shares Outstanding (mn) 8555.49 Net Income (Rs mn) 193,458 259,419 308,876 331,305 52-week Range (Rs) 368/249 EPS (Rs) 22.6 30.3 36.1 38.7 Free Float (%) 25.9 % Chg YoY 0.4 34.1 19.1 7.3 FII (%) 4.7 P/E (x) 13.0 9.7 8.1 7.6 Daily Volume (US$'000) 30,130 CEPS (Rs) 44.5 48.9 54.8 57.4 Absolute Return 3m (%) (9.4) EV/E (x) 5.6 4.7 4.0 3.6 Absolute Return 12m (%) 6.8 Dividend Yield 2.8 3.4 4.0 4.2 Sensex Return 3m (%) (5.6) RoCE (%) 15.0 18.4 19.2 18.3 Sensex Return 12m (%) 8.3 RoE (%) 20.1 23.9 24.5 22.7

ONGC BUY

Value buy Rs293Reason for report: Reinitiating coverage



Target price Rs338


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Oil and Natural Gas Corporation (ONGC) is India’s largest oil & gas producer with most of its production coming in from the west coast. Hinged by a cash-rich balance sheet, ONGC can comfortably explore inorganic growth opportunities outside India. The company enjoys an excellent E&P portfolio and volume and reserve growth triggers exist. The company’s reserves in the KG Basin can see further upside in the short term. ONGC is an excellent defensive play, primarily due to resilient RoE despite subsidy rising to the highest ever levels of US$43/bl. We reinitiate with BUY and a target price of Rs338.

Strong reserve accretion potential. The current consolidated reserve base of 9.8bboe offers strong visibility to ONGC’s long-term revenues. Though in the past six years, the company has announced >115 discoveries, its large reserve accretions have been through acquisitions. We expect this to change given its discoveries in the prolific KG Basin, indicating major triggers in the next 2-3 years. Also, a strong balance sheet with US$3bn net cash provides flexibility to take the inorganic route.

Volume triggers beyond FY13. We expect ONGC’s sluggish project execution to change as it starts implementing major projects in the next 2-5 years. The first phase will start in Q1FY12 as ~7mmscmd additional gas production from marginal fields flow in. The next round will be from FY14 as oil production from Project Manik (offshore blocks in KG Basin) starts. Production from these fields is expected at ~15,000bl/day, rising to 100,000bl/day in three phases by FY17E-18E. Gas production from the KG-DWN-98/2 block will start by end-FY17E and is expected to be ~25mmscmd. The reserve potential of this block is being evaluated – reserve upside and production triggers likely in the next 2-3 years. ONGC expects production from ONGC Videsh (OVL, the Caraboco project in Venezuela) in FY14, initially at 40,000bl/day (this will fund most of the US$19bn development costs for the block). Post the development, the production is expected to scale up to 400,000bl/day.

Excellent defensive play. We expect ONGC’s subsidy contribution to be at itshighest at US$45/bl in FY12E-13E. Despite this, ONGC should maintain stable RoE at 22-23%, highlighting the excellent defensive nature of its profitability. The stock, therefore, is a value play, especially in a scenario of high crude prices and subsidies.

ONGC, April 4, 2011 ICICI Securities

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TABLE OF CONTENT Strong reserve accretion potential ..............................................................................67

Domestic blocks – Upside to reserves likely.................................................................67 Potential triggers from KG-DWN-98/2...........................................................................68 Low success rate, a concern ........................................................................................69

Volume triggers beyond FY13 ......................................................................................71 Excellent defensive play ...............................................................................................72

Subsidies have limited impact on profitability ...............................................................72 Improved profitability led by APM dismantling ..............................................................72 Cashflows support aggressive capex ...........................................................................73

Valuations.......................................................................................................................74 Value buy ......................................................................................................................74 Key risks to our call .......................................................................................................75 International comparison...............................................................................................75

Annexure 1: Financials (consolidated)........................................................................77 Annexure 2: Index of Tables and Charts .....................................................................81


67

Strong reserve accretion potential

Domestic blocks – Upside to reserves likely

ONGC has a portfolio of 164 blocks under various stages of exploration and development, 85 of which were awarded in the NELP rounds. In the past six years, the company has announced >120 discoveries and 45 of these are under production. The company has 12 discoveries in the prolific KG Basin, appraisals for which are underway. These discoveries can provide significant upside to ONGC’s reserves in the next 2-3 years.

Table 1: NELP performance Status

NELP discoveries Operated Phase 1 Phase 2 Phase 3 Comment I 5 5 7 in KG-DWN-98/3

2 in MN-DWN-98/3 II 2 1 1 1 in MN-OSN-2000/2 III 11 3 8 1 in AA-ONN-2001/1 IV 11 8 3 1 in CB-ONN-2002/2 V 3 2 1 VI 24 24 VII 18 16 VIII 14 Total 88 53 13

Source: Company data

ONGC has been able to maintain a reserve-replacement ratio (RRR) of >1 in the past five years. This has been due to investments in international blocks through OVL and more recently the acquisition of Imperial Energy. The company’s current RRR at 1.74 (including the imperial acquisition), based on 3P reserve estimates though, offers some comfort on production growth visibility.

However, the RRR is high due to lack of development in some major discoveries. We expect this to change due to better rig availability. ONGC would now be able to accelerate its drilling and development programme, primarily for its blocks in the east coast. In the next 1-2 years, as some of these fields start producing, the decline in overall production will be arrested and will help drive growth.

ONGC’s KG Basin gas discovery (block KG DWN 98/2) holds tremendous potential. Although the Director General of Hydrocarbons (DGH) has approved 3.2tcf gas reserve as the potential, industry sources expect it to be higher. ONGC has also associated oil discoveries in the other shallow water blocks in the KG basin, from which it expects to start oil production in ’11. However, oil production from these discoveries will result in only a marginal increase in production and would more or less arrest the decline in its ageing fields on the west coast (Mumbai High).

ONGC had a lower success rate of 41%, mainly due to high number of blocks under exploration


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Chart 1: Increasing reserve replacement

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Potential triggers from KG-DWN-98/2

The KG-DWN-98/2 block sits next to the prolific KG-D6 block of Reliance Industries off the east coast. ONGC has 65% interest in KG-DWN-98/2, Cairn India 10%, Petrobras 15% and Statoil 10%. Petrobras and Statoil have, however, decided to exit the block. ONGC has so far drilled a total of 13 exploratory wells in the 7,294 sqKms block that is divided into northern and southern appraisal areas.

As per industry sources, the nine gas discoveries in the northern discovery area (NDA) of this block may hold >3.2tcf of recoverable gas reserves and can yield much more than estimated 25-30mmscmd (post FY17). ONGC has submitted a proposal for declaring these gas discoveries commercially viable. Post approval of commerciality, ONGC would submit a detailed field development plan (FDP) for the discoveries in the northern appraisal areas. The initial estimate for capex is >US$5bn, primarily for production from the Padmawati, Kanakadurga, Annapurna, N-1, D/KT, U, A, W and E gas finds in the NDA. As the discoveries are not independently viable, the firm plans to combine these with finds in the neighboring acreage and develop them as a cluster.

An investment requirement of US$4bn is estimated to develop ultra-deep sea UD-1 discovery in the southern part of the KG-DWN-98/2 block. UD-1 is to be developed separately from the NDA. Together with NDA fields, ONGC’s total spend would be ~US$10bn. However, DGH is yet to approve the commerciality of UD-1, which is expected to hold >1.9tcf of recoverable gas reserves.

The NDA consists of Padmawati, Kanakadurga, Annapurna, N-1, D/KT, U, A, W and E gas finds in water depths ranging from 594 meters to 1,283 metres. The Southern Discovery Area consisting of UD-1 discovery in Ultra deepwater has a depth of 2,841 metres.

The KG-DWN-98/2 block can add >6tcf recoverable reserves for ONGC and produce >25mmscmd gas by ’17E


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Low success rate, a concern

ONGC’s average success rate over the past seven years has been at ~41%, lower than its PSU peer Oil India (OIL) at 57%, as more blocks come under ONGC’s exploration programme, making it difficult to manage rig procurements on time, especially for offshore shallow and deep water blocks. Therefore, ONGC has struggled to meet its minimum work programme (MWP) commitments for many blocks, resulting in cost over-runs and relinquishment of prospective blocks. The company has drilled 780 wells in the past seven years, 10x more than OIL and higher than any other domestic private company.

Table 2: Status of wells drilled (number of wells) Year Wells drilled Hydrocarbon-bearing wells % of Hydrocarbon-bearing wells 2002-03 150 66 44.0 2003-04 124 51 41.1 2004-05 109 43 39.4 2005-06 106 45 42.5 2006-07 87 32 36.8 2007-08 98 50 51.0 2008-09 106 32 30.2 Total 780 319 40.9 Source: Infraline

Recently, ONGC addressed rig availability concerns by hiring three deepwater rigs for the long term. The current scenario of high spare capacity in jack-ups offers ONGC a good opportunity to accelerate its drilling programme.

ONGC had acquired UK-based Imperial Energy with assets in Western Siberia, Russia, in FY09. Imperial was acquired at US$1.9bn (Rs42/share for ONGC shareholders), at an EV/boe of US$2.06. Given the risks associated with reserve development in Russia and the unfriendly Russian tax regime, the lower multiple for the acquisition is well justified. Current production of Imperial Energy is at 18,000bopd and will likely rise to >45,000bopd in the next 3-5 years.

Chart 2: Reserve accretion trend (3P)

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Table 3: Reserve break-up (excluding KG Basin blocks) (mmboe)

ONGC's earlier estimate Audited estimates Absolute change % chg 1P 2P 3P 1P 2P 3P 1P 2P 3P 1P 2P 3PMumbai High 916.9 995.5 1,393.2 983.7 1,757.0 1,975.4 66.8 761.5 582.2 7.3 76.5 41.8Other 63 fields 1,618.3 1,896.3 2,101.8 1,426.7 1,706.3 2,117.6 (191.6) (190.1) 15.8 (11.8) (10.0) 0.8Total 2,535.2 2,891.8 3,495.0 2,410.4 3,463.3 4,093.1 (124.8) 571.5 598.1 (4.9) 19.8 17.1 Domestic gas (mmtpa) Mumbai High 356.8 436.9 542.2 311.8 500.2 589.3 (45.0) 63.3 47.1 (12.6) 14.5 8.7Other 63 fields 1,817.3 2,541.8 3,044.9 1,767.8 2,545.9 3,098.5 (49.5) 4.1 53.6 (2.7) 0.2 1.8Total 2,174.1 2,978.7 3,587.1 2,079.6 3,046.1 3,687.8 (94.5) 67.4 100.7 (4.3) 2.3 2.8 Total Oil Equivalent 4,709.3 5,870.5 7,082.1 4,490.0 6,509.3 7,780.9 (219.3) 638.8 698.8 (4.7) 10.9 9.9Uncertified reserves 667.5 1,181.2 1,468.3 667.5 1,181.2 1,468.3 - - - - - -Domestic JV 273.6 305.5 321.2 273.6 305.5 321.2 - - - - - -Total 5,650.4 7,357.2 8,871.6 5,431.1 7,996.0 9,570.3 (219.3) 638.8 698.8 (3.9) 8.7 7.9 OVL Fields audited 1,311.4 2,557.6 2,847.5 1,246.1 2,492.3 2,760.2 (65.3) (65.3) (87.3) (5.0) (2.6) (3.1)Not audited 14.6 404.9 418.8 14.6 404.9 418.8 - - - - - -Total OVL 1,326.1 2,962.5 3,266.3 1,260.8 2,897.2 3,179.0 (65.3) (65.3) (87.3) (4.9) (2.2) (2.7)Consolidated total 6,976.5 10,319.7 12,137.9 6,691.8 10,893.2 12,749.4 (284.6) 573.5 611.5 (4.1) 5.6 5.0

Source: Company data; recent reserves audit


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Volume triggers beyond FY13 We expect ONGC’s volume growth to be 1-2% in FY12E-13E as production from new fields in Brazil, Russia and KG Basin primarily neutralise the production decline from existing fields. Volume expansion for ONGC would kick-in from FY14.

ONGC expects production from OVL (the Caraboco project in Venezuela) to be at 40,000bl/day initially (which will fund most of the development costs of US$19bn for the block). Post the development project, the production is expected to scale up to 400,000bl/day.

Table 4: Sales volume assumptions (MMT) FY09 FY10 FY11E FY12E FY13E Crude oil 22.879 22.330 22.553 22.779 23.234 Natural Gas (BCM) 20.533 20.598 20.712 21.033 21.454 LPG 1.029 1.108 1.130 1.153 1.176 Natural Gasoline / Naphtha 1.544 1.598 1.630 1.663 1.696 Crude oil (US$/bl) 88.5 69.9 86.8 100 100 Net realisation post subsidies (US$/bl) 45.8 54.5 56.8 62.2 62.3


Table 5: Sales profile (Rs mn) FY09 FY10 FY11E FY12E FY13E

Crude oil 407,837 460,471 436,766 466,609 470,254 Natural Gas 80,355 73,797 150,532 151,722 154,757 LPG 22,752 21,924 36,426 42,104 42,946 Natural gasoline / Naphtha 48,406 47,137 58,385 68,101 69,463 Ethane / propane 9,890 10,249 12,446 14,232 14,232 Superior kerosene oil 16,702 3,256 4,033 4,704 4,798 Others 1,526 463 - - - MS/HSD 72,972 183 233 272 278 Total 660,439 617,480 698,821 747,745 756,728


Table 6: Estimated production plan Crude oil production (MMT) Natural gas production (mmscmd) 2009-10 (actual) 24.86 63 2012E-13E (likely) >28 72 2015E-16E (envisaged) 100 Additions from Cluster 7, WO Series, B-193, D-1

Additional, B-22 Cluster 7, WO Series, B Series, North

Tapti, B-193, B-22 Source: Company data

Volume growth is expected to be within 1-2% till FY13E.


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Excellent defensive play

Subsidies have limited impact on profitability

A key positive for PSU upstream companies is that their returns continue to be strong despite varying levels of under-recoveries. In FY09, when the subsidy contribution was the highest for ONGC at US$36/bl, its RoE was still stable at 20% (Table 7). Going forward, in FY12E-13E, we expect ONGC’s subsidy contribution to be at its highest, at US$43/bl. Despite this, we expect ONGC to maintain stable RoE of 22-23%, highlighting the excellent defensive nature of ONGC’s profitability. The stock, therefore, is a value play, especially in a scenario of high crude price and subsidies. Profitability is expected to improve as oil production from OVL (insulated from subsidies) improves in the next 3-4 years. Gas production from the company’s KG blocks would also help expand the company’s RoEs.

Table 7: Key ratios and subsidies Y/E March FY09 FY10 FY11E FY12E FY13E ONGC's share (Rsmn) 319,996 143,681 258,615 323,565 328,742 ONGC's share (US$mn) 7,054 3,030 5,580 7,034 7,147 Sales (mn bl) 165.0 161.0 162.6 164.2 167.5 US$/bl 42.8 18.8 34.3 42.8 42.7 RoCE (%) 17.1 15.0 18.4 19.2 18.3 RoE (%) 22.8 20.1 23.9 24.5 22.7 Net realisation post subsidy (US$/bl) 45.8 54.5 56.8 62.2 62.3 Source: Company data, I-Sec Research

Improved profitability led by APM dismantling

ONGC’s profitability has always been capped by the subsidy burden (Table 8). The company has consistently generated net post tax realisation within US$9-15/bl, independent of crude price movement. In a rising crude environment, ONGC’s profitability is affected by an increase in subsidies, capping its net realisation. However, on the back of revision in APM gas prices to US$4.2/mmbtu, we expect the company’s net realisations to rise to US$17/bl.

However, going forward, we expect ONGC’s profitability to improve sharply due to the gas price hike being captured fully into the numbers. We expect net realisation to improve to US$16-17/bl consistently. The implementation of the Kirit Parikh recommendations can further boost profitability and lead to a re-rating for ONGC.

Table 8: ONGC – P&L structure (standalone) (US$/boe)

FY09 FY10 FY11E FY12E FY13E Revenues 44.26 40.37 46.52 50.44 50.53 Net crude realisation (US$/bl) 45.76 54.53 56.82 62.17 62.34 Gas realisation (Rs/scm) 3.9 3.6 7.3 7.2 7.2 Crude oil subsidies (US$/bl) 42.77 18.82 34.32 42.83 42.66 Costs 23 16 18 19 18 EBITDA 21.41 23.87 28.74 31.94 32.04 PBT 16.62 16.83 21.98 25.39 26.09 PAT 10.77 11.28 14.73 17.01 17.48


RoEs to be robust at 23% levels

Profitability to improve to US$17/bl from FY12E owing to a revision in APM gas price


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Cashflows support aggressive capex

ONGC’s consolidated balance sheet enjoys a steady cashflow visibility and zero leverage. With an estimated cash balance of >US$9.2bn in FY13E, the company is well placed to capitalise on organic and inorganic expansion opportunities. The regulatory delays associated with being a PSU company are the only major hindrance for ONGC for tracing a path of aggressive growth.

Table 9: Cashflow overview (Rs mn)

FY10 FY11E FY12E FY13E Operating cashflow 378,882 427,091 510,810 529,155 Working capital changes 18,956 (36,874) 6,250 2,369 Capital commitments (347,883) (386,114) (342,035) (301,266) Free cashflow 30,999 40,977 168,775 227,889



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Valuations

Value buy

Our fair value for ONGC implies a multiple of 5.9x FY13E cash earnings, after capturing in Rs323bn subsidies based on the average Brent crude price of US$100/bl in FY12E-13E. Our fair value is derived based on a 5x FY13E cash earnings, at a 30% discount to global peers and then adding value of its investments and reserve upsides. We believe that a discount to international peers is justified based on the uncertainty associated with the subsidy sharing mechanism and company’s inability to undertake aggressive inorganic growth opportunities. Our fair value still offers a 24% upside, which indicates the CMP capture the worst case for the company, and hence we believe the stock is an excellent value pick.

We prefer using a cash-flow multiple, considering ONGC’s matured production portfolio and steady capex in the next 5-10 years. The cashflow method provides an ideal comparison parameter with international peers, nullifying the impact of variable depreciation and depletion structures and tax structure. Also, given the lack of clarity on production profile and PSC for many of the company’s domestic and international blocks, valuing the company using DCF becomes difficult.

Table 10: Valuations (Rs mn)

Consolidated Cash earnings 491,130 Equity value (@ 5x) 2,455,650 Core value (Rs/share) 287 Probable reserves 24 Value of holdings 27 Total 338 Reserves - 2P (mmboe) 10,320 Implied EV/boe 6.1

Source: I-Sec Research ONGC will likely enjoy a potential reserve upside of Rs24/share or 2.2bboe – over its current reserve base of 10.2bboe. We have valued these reserves at US$2/boe, assuming a sharp discount to our implied multiple of US$6.1/boe.

Table 11: Probable reserves valuations Probable reserves (mmboe) 2,255 Valuation multiple (US$/boe) 2.0 Probable reserves value (US$ mn) 4,511 Probable reserves value (Rs mn) 202,988 Probable reserves value (Rs/share) 24

Source: I-Sec Research ONGC’s implied EV/boe multiple of 6.1x at our fair value indicates a sharp discount to global average of 17x, reflecting the negative impact from uncertain subsidy sharing. This discount can reduce if the Government can formulate a subsidy sharing mechanism that can yield strong visibility to ONGC’s cashflows.

ONGC value pick based on stable profitability despite surging subsidies


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• Sharp variation in Brent prices, which can influence Government’s policy, and skew it towards or against upstream players as far as the subsidy calculations are concerned

Table 12: Valuation sensitivity to crude Crude (US$/bl) 80 90 100 110 120 Value (Rs/share) 285 312 338 363 386


• Implementation of any major reforms like a subsidy sharing formula or diesel deregulation can be a major upside risk

• Major changes in estimation of hydrocarbon reserves in the companies E&P blocks can have a significant impact on the valuations.

• Change in government levies like Cess or Royalty for the blocks that the company is currently producing from can have a major impact on valuations – Especially for the Rajasthan block operated by Cairn (ONGC – 30% stake). We have not factored any valuation upside in case the royalty is made cost recoverable – this would be a positive for ONGC

International comparison

Table 13: Global E&P – Valuation comparison P/CF (US$) E&P companies

FY12/CY11 FY13/CY12 Rosneft Oil Co 5.69 6.01 CNOOC Ltd 7.60 7.20 EnCana Corp 6.39 5.72 Canadian Natural Resources Ltd 8.12 6.56 Woodside Petroleum Ltd 13.93 9.71 Apache Corp 5.44 4.95 Anadarko Petroleum Corp 6.71 5.67 Devon Energy Corp 7.09 5.89 EOG Resources Inc 7.45 5.79 Chesapeake Energy Corp 5.12 4.68 Southwestern Energy Co 9.42 7.41 PTT Exploration & Production PCL 7.13 5.97 Murphy Oil Corp 5.47 5.00 Oil India Ltd 8.09 7.05 Cairn India Ltd 7.00 6.15 Average 7.38 6.25

Source: Bloomberg

Table 14: Global E&P – Reserve/boe Pure E&P EV (US$ mn) P2 reserves (mmboe) US$ EV/boe Rosneft Oil Co 111,407 13,970 7.97 EnCana Corp 32,391 2,309 14.03 Apache Corp 59,344 2,953 20.09 Anadarko Petroleum Corp 50,741 2,422 20.95 Devon Energy Corp 41,950 2,874 14.60 EOG Resources Inc 36,180 1,949 18.56 Talisman Energy Inc 27,886 1,149 24.26 Chesapeake Energy Corp 37,647 2,849 13.21 Southwestern Energy Co 16,021 823 19.47 Nexen Inc 17,292 919 18.83 Average 17.20

Source: Bloomberg


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Table 15: Global integrated – Reserve/boe

Integrated EV

(US$ mn) P2 reserves

(mmboe) US$

EV/boe PetroChina Co Ltd 364,621 21,803 16.72 Exxon Mobil Corp 430,194 24,809 17.34 Petroleo Brasileiro SA 285,875 12,093 23.64 BP PLC 156,639 25,188 6.22 Chevron Corp 213,772 10,545 20.27 Total SA 163,825 10,695 15.32 Gazprom OAO 230,203 221,700 1.04 ENI SpA 138,928 6,502 21.37 Statoil ASA 102,522 2,124 48.27 ConocoPhillips 127,884 8,310 15.39 Occidental Petroleum Corp 87,468 3,363 26.01 BG Group PLC 91,831 2,893 31.74 Lukoil OAO 69,459 13,029 5.33 Suncor Energy Inc 81,418 3,897 20.89 Husky Energy Inc 31,016 1,046 29.64 TNK-BP Holding 46,813 8,557 5.47 Hess Corp 32,869 1,537 21.39 Average 19.18

Source: Bloomberg

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Annexure 1: Financials (consolidated) Table 16: Profit and loss statement (Rs mn, year ending March 31)

FY09 FY10 FY11E FY12E FY13EGross Sales 1,094,129 1,061,688 1,313,898 1,412,651 1,450,881 Less: Excise Duty 48,246 44,143 58,746 58,851 58,745Net Sales 1,045,884 1,017,546 1,255,153 1,353,801 1,392,136 Total Operating Income 1,045,884 1,017,546 1,255,153 1,353,801 1,392,136 Less: Raw Materials Consumed (incld stock adj) 289,746 253,390 360,577 360,876 361,191Royalty and Cess 167,335 158,131 180,312 202,324 210,705 Other Manufacturing Expenses 58,932 64,511 81,714 83,609 86,230 Power and Fuel 1,469 1,347 2,041 2,221 2,268 Personnel Expenses 11,619 14,071 16,576 17,037 17,626 Other Expenses 99,883 82,601 78,590 80,412 81,794 Total Operating Expenses 628,985 574,050 719,811 746,480 759,814EBITDA (margin %) 39.9 43.6 42.7 44.9 45.4EBITDA 416,899 443,496 535,342 607,321 632,322 Recouped costs 154,304 187,188 158,706 159,830 159,825Add: Other Income 50,721 52,728 27,649 31,026 38,867 EBIT 313,316 309,035 404,284 478,517 511,365 Less: Gross Interest 2,385 5,022 15,467 15,455 14,175 Recurring Pre-tax Income 310,931 304,013 388,817 463,062 497,190 Add: Extra Ordinary income/ (expense) 763 401 - - - Add: Prior period adjustments 4,464 176 - - -Less: Taxation Current Tax 111,056 95,757 110,648 133,058 144,032 Deferred Tax 3,501 11,558 17,310 19,874 20,647 Less: Minority interest 3,747 3,319 1,518 1,331 1,284 Add: Earnings from Associate Companies 99 78 78 78 78 Net Income 197,953 194,035 259,419 308,876 331,305 Consolidated Recurring Net Income 192,726 193,458 259,419 308,876 331,305



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FY09 FY10 FY11E FY12E FY13EASSETS Current Assets, Loans & Advances Cash & Bank balance 225,956 223,842 220,142 299,967 437,544 Inventory 65,424 82,400 74,563 75,019 76,277 Sundry Debtors 71,814 71,424 85,923 93,682 96,950 Loans and Advances 132,644 120,567 120,567 120,567 120,567 Other Current Assets 11,309 7,431 7,431 7,431 7,431Total Current Assets 507,146 505,664 508,627 596,666 738,769 Current Liabilities & Provisions Current Liabilities Sundry Creditors 117,772 140,882 112,404 117,742 119,112 Other Current Liabilities 82,460 85,937 83,205 91,704 96,509 Provisions 82,158 75,158 76,158 77,158 78,158 Total Current Liabilities and Provisions 282,390 301,977 271,766 286,603 293,779 Net Current Assets 224,757 203,687 236,861 310,063 444,990 Investments Strategic & Group Investments 17,083 17,083 17,083 17,083 17,083Other Marketable Investments 17,720 34,510 34,510 34,510 34,510Total Investments 34,803 51,593 51,593 51,593 51,593 Goodwill (On consolidation) 114,039 95,385 95,385 95,385 95,385 Fixed Assets Gross Block 1,697,482 1,933,001 2,147,706 2,386,796 2,605,256 Less Accumulated Depreciation 1,059,546 1,177,574 1,267,161 1,390,414 1,529,166 Net Block 637,936 755,427 880,545 996,382 1,076,090 Add: Capital Work in Progress 247,580 256,164 299,354 308,344 301,865 Less: Revaluation Reserve Total Fixed Assets 885,517 1,011,591 1,179,899 1,304,726 1,377,955 Total Assets 1,259,116 1,362,257 1,563,739 1,761,768 1,969,924 LIABILITIES AND SHAREHOLDER'S EQUITY Borrowings Short Term Debt 56,466 21,604 21,554 21,554 21,554 Long Term Debt 9,125 41,065 66,065 56,065 41,065Total Borrowings 65,591 62,669 87,620 77,620 62,620 Deferred Tax Liability (net) 92,231 102,912 115,783 130,722 146,380Liability for abandonment 171,451 174,590 174,868 177,817 177,387Minority Interest 14,114 16,432 16,706 17,808 18,872 Share Capital Paid up Equity Share Capital 21,389 21,389 42,778 42,778 42,778 Reserves & Surpluses Share Premium 312 312 312 312 312 General & Other Reserve 900,534 992,365 1,134,086 1,323,123 1,529,987 Less: Misc. Exp. not written off 6,506 8,413 8,413 8,413 8,413Net Worth 915,729 1,005,653 1,168,763 1,357,800 1,564,664 Total Liabilities & Shareholder's Equity 1,259,116 1,362,257 1,563,738 1,761,768 1,969,924



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FY09 FY10 FY11E FY12E FY13Ea) Cash Flow from Operating Activities Consolidated Net Income 201,700 197,354 260,937 310,208 332,590Add: Depreciation & Amortisation 191,431 205,019 217,805 217,209 228,036 Deferred Tax 4,855 10,681 12,871 14,939 15,658Less: Other Income 50,721 52,728 27,649 31,026 38,867 Net Extra-ordinary income 763 401 - - -Operating Cash Flow before Working Capital chg (a) 346,502 359,926 463,964 511,330 537,416 Changes in Working Capital (Increase) / Decrease in Inventories 7,561 (16,976) 7,837 (456) (1,258)(Increase) / Decrease in Sundry Debtors (1,344) 390 (14,500) (7,759) (3,268)(Increase) / Decrease in Operational Loans & Adv. (61,964) 12,077 - - -(Increase) / Decrease in Other Current Assets (657) 3,878 - - -Increase / (Decrease) in Sundry Creditors 19,438 23,110 (28,478) 5,338 1,370Increase / (Decrease) in Other Current Liabilities 27,826 (3,523) (1,732) 9,499 5,805 Working Capital Inflow / (Outflow) (b) (9,141) 18,956 (36,874) 6,623 2,650 Net Cash flow from Operating Activities (a) + (b) 337,361 378,882 427,091 517,953 540,066 Cash Flow from Capital commitments Purchase of Fixed Assets (376,045) (331,093) (386,114) (342,035) (301,266)Purchase of Investments 10,018 (16,790) - - -Cash Inflow/(outflow) from capital commitments (c) (366,027) (347,883) (386,114) (342,035) (301,266) Free Cash flow after capital commitments (28,666) 30,999 40,977 175,917 238,800(a) + (b) + (c) Cash Flow from Investing Activities Other Income 50,721 52,728 27,649 31,026 38,867 - - - - -Net Cash flow from Investing Activities (d) 50,721 52,728 27,649 31,026 38,867 Cash Flow from Financing Activities Proceeds from fresh borrowings 56,147 (2,922) 24,950 (10,000) (15,000)Dividend paid including tax (80,076) (82,198) (100,894) (117,110) (122,742)Others (23,492) (1,120) 3,618 (8) (2,349)Net Cash flow from Financing Activities (e) (47,421) (86,240) (72,326) (127,118) (140,091) Net Extra-ordinary Income (f) 763 401 - - - Total Increase / (Decrease) in Cash (24,603) (2,113) (3,700) 79,825 137,577(a) + (b) + (c) + (d)+ (e) + (f) Opening Cash and Bank balance 250,558 225,956 223,842 220,142 299,967Closing Cash and Bank balance 225,956 223,842 220,142 299,967 437,544Increase/(Decrease) in Cash and Bank balance (24,603) (2,113) (3,700) 79,825 137,577



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FY09 FY10 FY11E FY12E FY13EPer Share Data (in Rs.) Diluted Recurring Earning per share (DEPS) 22.5 22.6 30.3 36.1 38.7Diluted Earnings per share 23.1 22.7 30.3 36.1 38.7Recurring Cash Earnings per Share (CEPS) 40.6 44.5 48.9 54.8 57.4Free Cash flow per share (FCPS - post capex) 84.5 80.8 99.4 99.7 98.0Book Value (BV) 107.0 117.5 136.6 158.7 182.9Adjusted Book Value (ABV) 107.0 117.5 136.6 158.7 182.9Dividend per Share 8.0 8.2 10.1 11.7 12.3

Valuation Ratios (x) Diluted Price Earning Ratio 13.0 13.0 9.7 8.1 7.6Price to Recurring Cash Earnings per share 7.2 6.6 6.0 5.3 5.1Price to Book Value 2.7 2.5 2.1 1.8 1.6Price to Adjusted Book Value 2.7 2.5 2.1 1.8 1.6EV / EBITDA 6.0 5.6 4.7 4.0 3.6EV / Total Operating Income 0.5 0.5 0.4 0.4 0.4EV / Operating Free Cash Flow (Pre-Capex) 7.5 6.6 5.9 4.9 4.7EV / Net Operating Free Cash Flow (Post-Capex) (87.7) 81.1 61.3 14.3 10.5Dividend Yield (%) 2.7 2.8 3.4 4.0 4.2 Growth Ratios (% YoY) Diluted Recurring EPS Growth (7.9) 0.4 34.1 19.1 7.3Diluted Recurring CEPS Growth (0.3) 9.7 9.8 12.1 4.8Total Operating Income Growth 8.1 (2.7) 23.4 7.9 2.8EBITDA Growth (2.1) 6.4 20.7 13.4 4.1Recurring Net Income Growth (7.9) 0.4 34.1 19.1 7.3 Operating Ratios (%) EBITDA Margins 39.9 43.6 42.7 44.9 45.4EBIT Margins 30.0 30.4 32.2 35.3 36.7Recurring Pre-tax Income Margins 28.4 28.4 30.3 33.4 34.7Recurring Net Income Margins 17.6 18.1 20.2 22.3 23.2Other Income / Pre-tax Income 16.3 17.3 7.1 6.7 7.8Effective Tax Rate 36.8 35.3 32.9 33.0 33.1 Return / Profitability Ratios (%) Return on Capital Employed (RoCE)-Overall 17.1 15.0 18.4 19.2 18.3Return on Invested Capital (RoIC) 17.9 14.9 20.3 21.3 21.0Return on Net Worth (RoNW) 22.8 20.1 23.9 24.5 22.7Dividend Payout Ratio 34.6 36.4 33.2 32.4 31.7 Solvency Ratios / Liquidity Ratios (%) Debt Equity Ratio (D/E) 17.2 16.5 17.4 15.3 13.4Net Working Capital / Total Assets (0.1) (1.5) 1.1 0.6 0.4Interest Coverage Ratio-based on EBIT 13,137 6,154 2,614 3,096 3,608Debt Servicing Capacity Ratio (DSCR) 19,569 9,846 3,607 4,097 4,702Current Ratio 110.5 119.0 132.3 154.5 196.0Cash and cash equivalents / Total Assets 17.9 16.4 14.1 17.0 22.2 Turnover Ratios Inventory Turnover Ratio (x) 5.2 4.5 5.9 6.2 6.2Assets Turnover Ratio (x) 1.0 0.8 0.9 0.8 0.8Working Capital Cycle (days) 81 77 64 74 99Average Collection Period (days) 24 25 22 23 24Average Payment Period (days) 136 186 128 116 120



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Tables Table 1: NELP performance ...............................................................................................67 Table 2: Status of wells drilled ............................................................................................69 Table 3: Reserve break-up (excluding KG Basin blocks) ...................................................70 Table 4: Sales volume assumptions ...................................................................................71 Table 5: Sales profile ..........................................................................................................71 Table 6: Estimated production plan ....................................................................................71 Table 7: Key ratios and subsidies.......................................................................................72 Table 8: ONGC – P&L structure (standalone) ....................................................................72 Table 9: Cashflow overview................................................................................................73 Table 10: Valuations ...........................................................................................................74 Table 11: Probable reserves valuations .............................................................................74 Table 12: Valuation sensitivity to crude ..............................................................................75 Table 13: Global E&P – Valuation comparison...................................................................75 Table 14: Global E&P – Reserve/boe.................................................................................75 Table 15: Global integrated – Reserve/boe........................................................................76 Table 16: Profit and loss statement ....................................................................................77 Table 17: Balance sheet .....................................................................................................78 Table 18: Cashflow statement ............................................................................................79 Table 19: Key ratios ............................................................................................................80

Charts Chart 1: Increasing reserve replacement............................................................................68 Chart 2: Reserve accretion trend (3P) ................................................................................69 Chart 3: Rolling price/EPS trend.........................................................................................76 Chart 4: Rolling EV/EBITDA trend ......................................................................................76


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Market Cap Rs673bn/US$15.1bn Year to March FY10 FY11E FY12E FY13EReuters/Bloomberg CAIL.BO/CAIR IN Revenue (Rs mn) 22,627 96,366 207,767 219,330 Shares Outstanding (mn) 1901.77 Net Income (Rs mn) 12,734 54,414 127,270 139,590 52-week Range (Rs) 368/266 EPS (Rs) 6.7 28.7 67.1 73.6Free Float (%) 37.7 % Chg YoY 35.3 327.3 133.9 9.7FII (%) 10.8 P/E (x) 52.7 12.3 5.3 4.8Daily Volume (US$'000) 18,328 CEPS (Rs) 7.5 31.3 73.9 80.7Absolute Return 3m (%) 5.5 EV/E (x) 68.2 9.2 3.7 3.1Absolute Return 12m (%) 14.2 Dividend Yield 0.0 3.5 8.1 8.9Sensex Return 3m (%) (5.6) RoCE (%) 3.4 14.5 30.2 29.4Sensex Return 12m (%) 8.3 RoE (%) 3.8 15.5 32.0 30.1

Cairn India BUY

Risk-reward favourable Rs354Reason for report: Reinitiating coverage



Target price Rs384


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Cairn India is a rare, pure oil production play in India and should be viewed more as a reserve growth story given the high potential of its Rajasthan assets. Thestock recently underperformed the Sensex in spite of a 30% crude price hike dueto a dispute with ONGC on royalty sharing post the announcement of the Cairn-Vedanta deal. Notwithstanding, the current market price offers good risk-reward and more or less discounts the royalty risk. The stock is currently trading at 4.8x FY13E EPS and 3.1x FY13E EBITDA. We value Cairn on sum of the parts (SOTP) toarrive at Rs384 target price, implying a 16% upside from the current levels.Reinitiate with BUY. Key risks are lower-than-expected crude price, delay in the production ramp-up schedule.

Rajasthan – Royal gains for Cairn. Rajasthan assets have witnessed reserve accretion & upgrades in the past three years. Cairn had announced a 51% upgrade in its overall reserve estimates in Rajasthan. Cairn raised its gross peak productionestimates 37% to 240,000bpd. With just ~20-30% of the Rajasthan block being explored and as four discoveries are at the appraisal stage, further reserve upgradeis likely. Thus, Cairn is a strong long-term bet – Vedanta’s bid can be considered as a testimony to our view.

Rajasthan blocks to yield high profitability. Cairn’s Rajasthan operation offers higher net realisation versus peers as it is an onshore block and given the economiesof scale. The completion of the pipeline infrastructure offers Cairn a uniqueconnectivity advantage (to service PSUs and private refiners). We expect a sharpjump in profitability as Rajasthan gross production ramps up to 150,000bopd (plan yet to be approved) by July ’11 and later to 210,000bopd by June ’13E, while therecently upgraded peak production will likely kick in post ’13.

Cess litigation can be a trigger. Cairn has challenged the Government on cess payment for Rajasthan production. As per Cairn, it is not liable to pay cess, but it pays ~Rs2,500/te in protest. We factor in continued cess payment of Rs2,500/te. Hence, if the court ruling favours Cairn, Rs23/share upside exists to our target price.

Reinitiate with BUY. We value Cairn on SOTP – assets are separately valued to yield a target price of Rs384/share. Also, Rajasthan assets have been evaluated onDCF. For reserve upsides through additional recovery from 3P reserve estimates in Rajasthan, we assume a value of 10x EV/boe (similar to that derived from DCF), dueto lack of clarity on the production profile.

Cairn India, April 4, 2011 ICICI Securities

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TABLE OF CONTENT Rajasthan – Royal gains for Cairn ...............................................................................85

Rajasthan blocks – Strong execution track record .......................................................85 Crude sales from Rajasthan supported by pipeline advantage ....................................86

Vedanta deal – Outcome uncertain..............................................................................88 Vedanta Group – Lower gearing makes the acquisition viable.....................................89

Rajasthan blocks to yield high profitability ................................................................91 Cairn enjoys one of the lowest lifting costs ...................................................................91 Strong cashflows...........................................................................................................92 Improved profitability .....................................................................................................93

Valuations.......................................................................................................................94 Implied valuation gap offers opportunity .......................................................................94 Reinitiate with BUY .......................................................................................................94 EV/boe comparison indicates undemanding valuations ...............................................95 Key risks to our call .......................................................................................................96

Annexure 1: Financials (consolidated)........................................................................97 Annexure 2: Index of Tables and Charts ...................................................................101


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Rajasthan – Royal gains for Cairn

Rajasthan blocks – Strong execution track record

Cairn’s Rajasthan asset has witnessed reserve accretion and upgrade in the past three years. Cairn had announced 51% upgrade in its reserve estimates in Rajasthan in FY10. The company had consequently increased its gross peak production estimates 37% to 240,000bpd, primarily led by 150,000bpd upside from Mangala and additional production of 30,000bpd from Barmer Hill and other discoveries. Cairn has successfully achieved its earlier targeted peak production of 125,000bpd and is awaiting approval from the Directorate General of Hydrocarbons (DGH) to expand its peak production to 150,000bpd.

We estimate peak production from Mangala-Bhagyam-Aishwarya (MBA) to be 210,000bpd by end-’11E. However, Cairn has not clarified the timelines for 240,000bpd peak production due to ongoing appraisal studies for the Barmer discoveries. We estimate peak production to kick in by end-’14.

Table 1: Reserve estimate upgrade in the past three years (3P) Gross Initial Reserve in Place mboe Blocks

2010 2008 % chg Mangala 1,293 1,206 7.2 Bhagyam 468 557 (16.0) Aishwarya 293 281 4.3 Total 2,054 2,044 0.5 Saraswati & Raageswari Oil - STOIIP 78 - Total 2,132 2,044 4.3 20 additional discoveries, including Barmer Hill Oil STOIIP 1,603 1,443 11.1 GAS STOIIP 270 298 (9.4) Total 4,005 3,785 5.8 35+ prospects resources 2,500 - Total 6,505 3,785 71.9

Government is yet to approve; Source: Company data

Table 2: Reserve estimate upgrade in the past three years (2P) Blocks Gross Reserve, Resources & Potential (mboe) 2P+2C 2010* 2008 % chg Mangala 477 418 14.1 Bhagyam 151 140 7.9 Aishwarya 66 56 17.9 Saraswati & Raageswari Oil 12 8 50.0 Total 706 622 13.5 MBA EOR 308 308 - Barmer Hill + Other 140 0 - Risked prospective resources 250 0 - Total 1,404 930 51.0

* Government is yet to approve; Source: Company data

Table 3: Gross production details

Bpd Earlier Updated* Net to Cairn (70% stake) % chg

Mangala 125,000 150,000 105,000 20.0Bhagyam 40,000 40,000 28,000 0.0Aishwarya 10,000 20,000 14,000 100.0Others - 30,000 21,000 Total 175,000 240,000 168,000 37.1*Government is yet to appove this incremental production; Source: Company data

Timely execution of Mangala project, ready to pump 150,000bpd

Cairn has revised 2P reserves for its Rajasthan block by 51% in 2010, thereby making a case for future upgrades


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Chart 1: Estimated production profile

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Crude sales from Rajasthan supported by pipeline advantage

Cairn’s 590Kms pipeline from Mangala to Salaya, implemented at a cost of US$800mn, offers the company a unique advantage of selling its crude production from Rajasthan – this is crucial as it provides marketing access to India’s refining infrastructure. Considering the waxy nature of Rajasthan crude (pour point at 40oC), it requires a heated pipeline infrastructure, which would ensure efficient low-cost delivery to the refineries. The expected operating cost for the pipeline is ~US$1.5/bl. The commissioning of the pipeline infrastructure is a major relief for Cairn, both in terms of cost and the ability to ramp up production.

The Government has allowed Cairn to recover the cost of the pipeline expenditure for the block. This gives it an edge in terms of marketing crude (without transportation charges). Complex refiners, especially Reliance Industries (RIL) and Essar Oil would prefer buying this crude instead of importing, considering the US$1-1.5/bl GRM advantage (as Cairn will exclude this cost from crude sale price).

The completion of the pipeline will help Cairn deliver crude at a low cost and have supporting infrastructure to enable production ramp-up


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Chart 2: Mangala – Salaya pipeline

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Table 4: Diversified portfolio of E&P blocks

Blocks Basin Participating Interest (%)

Net Production (bpd) Operator Status / Plan

RJ-ONN-2003/1 Rajasthan 30 ENI India 1-3 exploratory wells RJ-ON-90/1 Rajasthan 70 87,500 Cairn India Two exploration wells CB-OS-2 Cambay 40 5,392 Cairn India - Ravva - 22.5 9,161 Cairn India Appraisal & exploration plans

GS-OSN-2003/1 Gujarat 49 Oil & Natural Gas Corp. (ONGC) Well GSA-1 plugged & abandoned

MB-DWN-2009/1 Mahanadi 40 - - -

KK-DWN-2004/1 Kerala - Konkan 100 ONGC 300 sqKms of 3D acquisition is being planned.

KG-DWN-98/2 Krishna Godavari 10 ONGC Two appraisal wells ’10

KG-ONN-2003/1 Krishna Godavari 49 Cairn Five prospects identified - Two wells drilled

KG-OSN-2009/1 Krishna Godavari 100 - - -

PR-OSN-2004/1 Palar Basin 35 Cairn 3D 800Kms Two completed in Q1CY10; drilling in ’11

SL 2007-01-001 - 100 - Cairn The 3D seismic data has been processed. Drilling to commence soon

Source: Company, I-Sec Research


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Vedanta deal – Outcome uncertain

• Cairn Energy plc would sell its 40-51% stake in Cairn India to Vedanta Group plc at Rs405/share, which comprises Rs355/share valuation for Cairn India and Rs50/share non-compete fee. However, the open offer by Sesa Goa would be at Rs355/share, at ~Rs50/share discount for minority shareholders.

• The overall valuation for the deal is US$16bn (US$11.8/boe based on our estimate of 1.35bboe overall recoverable reserves), at an average price of Rs387/share. Our valuation for Cairn yields a similar value. Hence, Vedanta intends to acquire Cairn at an implied crude price of US$100/bl as per our calculations.

• Cairn plc plans to pass on a major portion of the US$6.5-8.5bn cash to its shareholders in the UK, widely comprised of institutional investors. The company would use a minor component of the cash for exploration in Greenland.

Table 5: Cairn-Vedanta deal valuation

Case I Case II Cairn Energy's current holding in Cairn India (%) 62.4 62.4 Stake sale (%) 51.0 40.0 Amount considered (US$ bn) 8.4 6.6 Cairn Energy's holding in Cairn India after dilution (%) 11 22 Price per share ( Rs for buy out from Cairn plc) 405 405 Open offer by Sesa Goa@Rs355/share 2.9 2.9 Total stake post open offer (%) 71.0 60.0 Total consideration (US$ bn) 11.3 9.5 Implied Valuation (US$ bn) 16.0 15.9 Implied Valuation (Rs/share) 387 385

Source: I-Sec Research What does the deal change? • Cairn India’s exploration activities in India will change perceptibly. Cairn has a

strong proven record in India, indicated through robust recovery at its Ravva oil field and timely execution of its Rajasthan development project. Although both the Cairn plc and Vedanta managements have assured that the Cairn India team will be intact, some changes in the long term are likely (future development and exploration activities).

• ONGC’s royalty payment arrangement in Rajasthan for 100% production is a key concern for the company, especially the expanding scale of production. The Government has been trying hard to coax Vedanta-Cairn towards a compromise on the royalty arrangement. As per the production sharing contract, it is clear that ONGC will have to pay royalty. However, it is unclear if the royalty expenditure will be considered as cost recoverable.

• The Cairn India management has assured that there will be no compromise on the royalty arrangement, and hence, this concern may persist even after the deal is approved by the Government. However, the current stock price is capturing in the impact of royalty; so Cairn offers good risk-reward.

Vedanta deal matches our value of US$16 bn for Cairn


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Vedanta Group – Lower gearing makes the acquisition viable

The Vedanta Group is a diversified FTSE-100 natural resources group, with primary operations in India. As on March 31, ’10, Vedanta was India’s largest non-ferrous metals and mining company based on revenues, with its business primarily located in India and other assets and operations in Zambia and Australia. The Group is engaged in zinc, copper, aluminium and iron ore businesses and is developing a commercial power generation business. Vedanta’s subsidiaries, Sterlite Industries (India), Hindustan Zinc & Sesa Goa are listed on the BSE and the NSE in India.

Chart 3: Vedanta Group – Holding structure

2NOV201016450883

29.5% 3.1%

VedantaResources plc(Listed on LSE)

Konkola CopperMines plc

(Copper Business)

VedantaAluminium

Limited(AluminiumBusiness)

Sterlite Industries(India) Limited(Listed on BSE,

NSE andNYSE�

Copper Business)

The MadrasAluminium

Company Limited(AluminiumBusiness)

Sesa Goa Limited(Listed on BSE

and NSE�Iron Business)

BharatAluminium

Company Limited(AluminiumBusiness)

Hindustan ZincLimited

(Listed on BSEand NSE�

Zinc Business)

Sterlite EnergyLimited

(Power Business)

Copper Minesof Tasmania

Pty. Ltd.(Copper Business)

79.4% 70.5% 54.6% 94.5% 55.7%

51.0% 64.9% 100% 100%

Source: Company The Vedanta Group has access to debt facility of up to US$6.5bn to fund its 40-51% stake buyout in Cairn India. The open offer by Sesa Goa for a further 20% stake can be funded through Sesa Goa’s US$3bn cash reserves (56% subsidiary of Vedanta). If Sesa Goa’s open offer is not fully subscribed, the company can purchase shares from Vedanta plc to reach 20%. As per estimates from the Vedanta Group, the company’s consolidated net gearing post the deal would be below 25% in FY11E, indicating balance sheet strength.

Table 6: Indicative financials for Vedanta post deal (US $ mm)

Net Debt EBITDA Net Debt/EDITDA (x)

Net Gearing(%)

Vedanta FY 2010 947 2,296 0.4 8 Pro forma FY 2010 11,030 2,459 4.5 37 Pro forma FY 2011E1,2 <2 <25 Pro forma FY 2012E1,2 <1 <20

Note: 1 – Pro-forma for Vedanta Group and Cairn India, 2- Vedanta estimates Source: Vedanta Presentation

Vedanta’s balance sheet indicates high comfort levels to complete the deal


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Table 7: P&L highlights (US$ mn)

Table 8: Balance sheet highlights (US$ mn)

H1FY11 FY10 H1FY11 FY10 Revenues 4,582 7,931 Total assets 25,815 24,060 Operating profits 990 1,473 Total debt 8,983 8,174 Operating profit margin (%) 21.61 18.57 Cash plus investment 7,342 7,239 EBITDA 1349 2036 Net debt 1,641 935 EBITDA margin (%) 29.43 25.67 Total shareholders’ equity 12,459 11,440 Net profits 337 602 Net debt to equity (x) 0.13 0.08 Net profit margin (%) 7.36 7.59 RoE (%) 16.12 15.40 EBITDA/Interest Exp (x) 5.43 3.78 RoCE (%) 13.31 10.45

Note: Half yearly returns are annualised Source: Company, Bloomberg

Chart 4: Revenue break-up

Zinc19% Copper-Zambia

19%

Iron Ore15%

Aluminium14%

Energy and Gold4%

Copper29%

Source: Company, Bloomberg


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Rajasthan blocks to yield high profitability

Cairn enjoys one of the lowest lifting costs

Cairn’s lifting cost is the lowest among global peers owing to production commencement from Rajasthan. We expect its lifting cost to be US$4.4/bl from FY12E, well below the global average of US$10/bl (for similar sized companies) in ’11. Cairn enjoys cost advantage owing to bulk production from onshore Rajasthan blocks, as lifting costs onshore are much lower than offshore costs.

Chart 5: International lifting costs

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Source: Industry Based on low cost structure, we estimate Cairn to enjoy among the highest EBIT realisations at US$60/bl in FY12E, well above the global average of US$25-30/bl. As the company expands its production in the next 2-3 years, the cost structure will improve. This will provide Cairn with a sustainable cost advantage over peers, which is crucial, especially during a low crude price scenario. This cost advantage will ensure that the company would enjoy higher P/CF multiple compared with peers, once the peak production threshold is crossed. We, therefore, consider Cairn to be an excellent long term bet.

Cost advantage in terms of low lifting cost of US$5/bl, well below the world average of US$10-14/bl, due to onshore production

Cost advantage will translate into higher EBIT levels at US$60/bl in FY13 viz-a-via global average of US$12-15/bl


92

Chart 6: International E&P cost structure

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Table 9: Cairn’s cost structure at Rajasthan (US$/bl)

Income statement FY11E FY12E FY13E Net realisation 87 82.7 87 Total expenditure 15.9 14.8 14.5 EBIDTA 66.9 72.2 64.6 EBIT 63.5 67.6 59.9


Strong cashflows

We expect Cairn to generate steady cashflow of US$2.5bn from FY13E. High incremental cashflows provide Cairn a strong bandwidth to aggressively explore in prospective basins. As is true for any exploration company, cash generation ultimately decides the risk-taking abilities as regards exploring frontier basins and generating maximum returns. Post FY11, Cairn would aggressively expand its exploration activities to diversify its reserves portfolio outside Rajasthan.

Table 10: Expected cashflows (Rs mn)

FY09 FY10 FY11E FY12E FY13E Operating cashflow 6,632 2,562 57,159 151,337 145,243 Working capital changes 4,460 (8,956) (1,394) (7,126) (2,705) Capital commitments (33,543) (49,169) (25,832) (22,395) (12,680) Free cashflow (23,908) (55,564) 29,933 121,816 129,858


Strong cashflow generation of US$2.5bn likely from FY13, giving financial muscle for aggressive exploration activities


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Improved profitability

As Cairn’s production expands, its profitability will likely improve in the next two years. However, once the profit petroleum component kicks in from FY13, it will drop. Post FY13, we expect Cairn’s profitability to be stable and to be contingent on the successful implementation of extended oil recovery (EOR) and expansion of peak production through additional contribution from other potential prospects.

Hence, Cairn’s key strategy would be to continue to develop incremental discoveries in Rajasthan, which would require continuous infusion of capex.

Table 11: Key ratios (%) FY09 FY10 FY11E FY12E FY13E RoCE 2.8 3.4 14.3 33.2 28.6 RoIC 121.7 24.8 68.0 185.3 364.8 RoE 3.0 3.8 15.2 35.3 29.2 Source: I-Sec Research Table 12: Key assumptions

FY11E FY12E FY13E Brent (US$/bl) 84 100 100 Cess (Rs/te) 2500 2500 2500 Gross MBA production (bpd) 79,000 195,000 210,000 Net overall production (mmboe) 31 57 59 Source: I-Sec Research

Improved profitability in the next two years is likely, followed by a drop from FY13 as profit petroleum kicks in


94

Valuations

We value Cairn on SOTP to capture its cashflows from the Rajasthan block and reserve upsides. Risk-reward is favourable at the current levels and Cairn is a superb long-term pick. We reinitiate coverage with BUY at Rs384/share target price.

Implied valuation gap offers opportunity

Based on our calculation, current crude prices capture long-term average crude at US$80/bl levels, below the current crude price and our long-term average Brent assumption of US$100/bl. Cairn offers an upside based on the current reserve and production estimates.

In our view, the stock price will reflect its then prevailing gross realisation on achieving peak production from Rajasthan fields in FY14. Based on our assumption of Brent crude at US$100/bl for FY12E-13E, we expect the stock to be valued in line with its gross realisation of US$100/bl (Brent), rather than at the current discounted value of US$80/bl. We value the company’s core assets on DCF, assuming a peak production of 240,000bopd in FY14E and EOR implementation ensuring that the production is constant in the next 10 years.

Reinitiate with BUY

We value Cairn on SOTP – assets are separately valued to yield a target price of Rs384/share. Rajasthan assets have been evaluated on DCF. For reserve upsides through additional recovery from 3P reserve estimates in Rajasthan, we assume a value of 10x EV/boe (similar to that derived from DCF), due to lack of clarity on the production profile.

Key assumptions

• WACC at 13%

• EOR implementation from FY13; peak production with EOR for 10 years

• Long-term average brent at US$100/bl

Table 11: Valuations (Rs mn)

Valuation of Cairn’s E&P Assets - MBA, Ravva, Cambay FCFE based valuations Present value of future cashflows 546,581 Number of shares 1,897 Value per share (Rs /share) 288 Exploration upside per share 23 Exploration upside(Rs mn) 44,059 Total EV 727,446 Total reserves considered for valuation 1,350 EV/boe (US$/bl) 11.7 Overall value (Rs/share) 384



95

EV/boe comparison indicates undemanding valuations

Based on a global comparison, Cairn seems attractive on this parameter. Though the average EV/boe has risen in tandem with crude price, Cairn’s current EV/boe of 10.5x is at a discount to global peers. At our SOTP of Rs384, Cairn will trade at 11.7x EV/boe, still at a discount to 17x, the average for international peers. However, a discount to global peers is justified given that the peak production is still two years away.

Post-’13, there is a possibility that Cairn may get re-rated to trade at a premium to the international average (most likely if the concerns on royalty and cess are taken care of), based on the successful implementation of its EOR programme and precise production profile estimates from its other Barmer discoveries. This indicates a strong long-term potential offered by the stock.

Table 12: EV/boe comparison Pure E&P EV (US$ mn) P2 reserves (mmboe) USD EV/boe Rosneft Oil Co 111,407 13,970 7.97 EnCana Corp 32,391 2,309 14.03 Apache Corp 59,344 2,953 20.09 Anadarko Petroleum Corp 50,741 2,422 20.95 Devon Energy Corp 41,950 2,874 14.60 EOG Resources Inc 36,180 1,949 18.56 Talisman Energy Inc 27,886 1,149 24.26 Chesapeake Energy Corp 37,647 2,849 13.21 Southwestern Energy Co 16,021 823 19.47 Nexen Inc 17,292 919 18.83 Average 17.2

Source: Bloomberg, I-Sec Research

At our target price of Rs386/share, Cairn will trade at an EV/boe of ~12x, lower than the global average of 17x


96


Crude price movement, a major risk Crude price movement has a direct correlation to Cairn’s cash flows. The stock price has always reacted to crude price movement. However, the long-term impact has been muted due to reserve upgrades by Cairn. Therefore, going forward, the correlation with crude price movement may further sharply reduce in case there are further reserve upgrades.

Table 13: Crude price sensitivity Crude Price (US$/bbl)

(Rs/US$) 80 90 100 110 120 44 306 336 373 398 433 45 312 343 381 406 434 46 315 350 384 415 443 47 321 357 391 423 452 48 324 364 393 431 461


Chart 7: Cairn versus Brent crude

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Source: Bloomberg Cess litigation – Favourable ruling can trigger upsides Cairn has challenged the Government on cess payment for Rajasthan production. As per Cairn, it is not liable to pay cess, but it pays ~Rs2,900/te in protest. We factor in continued cess payment of Rs2,500/mt. Hence, if the court ruling favours Cairn, Rs23/share upside exists to our target price.

Reserve upgrades have led to Cairn’s stock price outperforming versus crude price movement


97


FY09 FY10 FY11E FY12E FY13ENet Sales 25,156 22,627 96,366 207,767 219,330 Total Operating Income 25,156 22,627 96,366 207,767 219,330Less: Government's share of profit petroleum 10,829 6,397 5,855 5,447 3,954Production costs 1,190 1,131 6,036 10,605 11,141 Staff costs 1,145 1,102 700 661 526Administrative expenses 2,166 3,031 2,980 6,485 6,763Decrease in inventories 222 (366) - - -Royalty & Cess 940 1,390 7,598 17,634 18,775 Total Operating Expenses 16,493 12,684 23,170 40,833 41,159 EBITDA 8,663 9,943 73,196 166,935 178,171 Depreciation & Amortisation 2,698 1,485 4,921 12,822 13,460Add: Other Income 5,945 4,077 733 1,997 4,862 EBIT 11,910 12,534 69,008 156,110 169,573 Less: Gross Interest 64 148 2,641 1,961 680 Recurring Pre-tax Income 11,846 12,386 66,367 154,149 168,893Unsuccessful exploration costs 1,179 2,085 221 202 171Extra Ordinary income / (expense) (198) - - - Less: Taxation Current Tax 1,811 2,216 11,964 26,904 29,330 Deferred Tax 623 (2,564) (11) (25) (28) Net Income (Reported) 8,035 10,649 54,193 127,069 139,420EBIT*(1-t) 9,462 12,886 56,579 128,889 140,153Consolidated Recurring Net Income 9,411 12,734 54,414 127,270 139,590



98


FY09 FY10 FY11E FY12E FY13EASSETS Current Assets, Loans & Advances Cash & Bank balance 65,271 9,294 11,652 45,412 93,492 Inventory 1,683 2,909 8,560 8,081 8,081 Sundry Debtors 1,516 3,067 7,920 17,077 18,027 Loans and Advances 3,505 8,318 8,318 8,318 8,318 Other Current Assets 704 145 145 145 145 Total Current Assets 72,679 23,734 36,595 79,031 128,063 Current Liabilities & Provisions Current Liabilities Sundry Creditors 8,648 8,652 17,693 21,474 17,369 Other Current Liabilities 1,400 22 93 201 212Other liabilities 1,747 1,194 1,194 1,194 1,194Provisions 4,337 4,937 4,937 4,937 4,937 Total Current Liabilities and Provisions 16,132 14,806 23,918 27,806 23,712 Net Current Assets 56,548 8,928 12,678 51,225 104,351 Investments Strategic & Group Investments 1,713 17,124 17,124 17,124 17,124 Total Investments 1,713 17,124 17,124 17,124 17,124 Deferred Tax Asset 84 166 478 766 1,010 Fixed Assets Gross Block 1,435 2,228 3,228 3,978 4,478 Less Accumulated Depreciation 802 958 1,140 1,385 1,672 Net Block 633 1,270 2,088 2,593 2,805 Producing properties 16,812 20,170 44,477 65,578 77,195Less: Depletion 13,799 15,175 19,915 32,491 45,664Net producing properties 3,014 4,995 24,562 33,086 31,531Exploratory & Development assets 62,027 91,635 92,160 92,703 93,266 Total Fixed Assets 65,674 97,899 118,810 128,382 127,602Goodwill 253,193 253,193 253,193 253,193 253,193Total Assets 377,211 377,310 402,282 450,691 503,280 LIABILITIES AND SHAREHOLDERS’ EQUITY Borrowings Long Term Debt 43,564 34,007 32,007 17,007 -Total Borrowings 43,564 34,007 32,007 17,007 - Deferred Tax Liability 5,624 4,619 4,609 4,583 4,555 Paid up Equity Share Capital 18,967 18,967 18,967 18,967 18,967 No. of Shares outstanding (mn) 1,897 1,897 1,897 1,897 1,897 Face Value per share (Rs) 10 10 10 10 10 Reserves & Surplus Share Premium 309,057 309,057 309,057 309,057 309,057 General & Other Reserve - 10,657 37,643 101,077 170,701Net Worth 328,023 338,680 365,667 429,100 498,725 Total Liabilities & Shareholders’ Equity 377,211 377,307 402,283 450,691 503,280



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FY09 FY10 FY11E FY12E FY13Ea) Cash Flow from Operating Activities Profit/Loss before taxation 11,846 10,649 54,193 127,069 139,420Add: Depreciation & Amortisation 2,698 1,533 4,921 12,822 13,460 Provisions Deferred Tax 623 (2,564) (11) (25) (28) - Less: Other Income 5,945 4,077 733 1,997 4,862 Net Extra-ordinary income 1,967 2,979 315 288 244Other Adjustments Op Cash Flow before Working Capital change (a) 6,632 2,562 58,055 137,580 147,746 Changes in Working Capital (Increase) / Decrease in Inventories (467) (1,227) (5,651) 480 (1)(Increase) / Decrease in Sundry Debtors (168) (1,551) (4,853) (9,156) (950)(Increase) / Decrease in Operational Loans & Adv. 1,362 (4,813) - - -(Increase) / Decrease in Other Current Assets (570) 560 - - -Increase / (Decrease) in Sundry Creditors 5,060 5 9,041 3,781 (4,105)Increase / (Decrease) in Other Current Liabilities 2,042 (1,930) 71 108 11Other Adjustments (2,801) Working Capital Inflow / (Outflow) (b) 4,460 (8,956) (1,392) (4,788) (5,045)Current Tax/FBT paid(net of refunds) (1,458) Net Cash flow from Operating Activities (a) + (b) 9,634 (6,395) 56,663 132,792 142,701 as a % of Operating Cash Flow Cash Flow from Capital commitments Purchase of Fixed Assets (342) (33,758) (25,832) (22,395) (12,680)Purchase of Investments 5,416 (15,411) - - -Consideration paid for acquisition of undertaking Exploration & Development Capex (38,617) Cash Inflow/(outflow) from capital commitments (c) (33,543) (49,169) (25,832) (22,395) (12,680) Free Cash flow after capital commitments (23,908) (55,564) 30,831 110,398 130,021(a) + (b) + (c) Cash Flow from Investing Activities Other Income 5,945 4,077 733 1,997 4,862Other Adjustments (3,533) Net Cash flow from Investing Activities (d) 2,412 4,077 733 1,997 4,862 Issue of Share Capital during the year 33,208 - - - -Proceeds from fresh borrowings 40,440 (9,557) (2,000) (15,000) (17,007)Dividend paid including tax - - (27,207) (63,635) (69,795)Others 5,068 Net Cash flow from Financing Activities (e) 73,648 (4,489) (29,207) (78,635) (86,802) Net Extra-ordinary Income (f) (198) - - - - Total Increase / (Decrease) in Cash 51,953 (55,976) 2,357 33,760 48,081(a) + (b) + (c) + (d)+ (e) + (f) Opening Cash and Bank balance 13,318 65,271 9,294 11,652 45,412Closing Cash and Bank balance 65,271 9,295 11,652 45,412 93,492Increase/(Decrease) in Cash and Bank balance 51,953 (55,976) 2,357 33,760 48,081



100


FY09 FY10 FY11E FY12E FY13EPer Share Data (in Rs.) Diluted Recurring Earning per share (DEPS) 5.0 6.7 28.7 67.1 73.6 Diluted Earnings per share 4.2 5.6 28.6 67.0 73.5 Recurring Cash Earnings per share (CEPS) 6.4 7.5 31.3 73.9 80.7 Free Cashflow per share (FCPS-post capex) (12.6) (29.3) 16.3 58.2 68.6 Reported Book Value (BV) 162.9 168.6 182.8 216.2 252.9 Adjusted Book Value (ABV) ** 162.9 168.6 182.8 216.2 252.9 Dividend per share 0.0 0.0 12.3 28.7 31.4 Valuation Ratios (x) Diluted Price Earning Ratio 71.3 52.7 12.3 5.3 4.8 Price to Recurring Cash Earnings per share 83.5 63.0 12.4 5.3 4.8 Price to Book Value 2.2 2.1 1.9 1.6 1.4 Price to Adjusted Book Value 2.2 2.1 1.9 1.6 1.4 Price to Sales Ratio 26.7 29.6 7.0 3.2 3.1 EV / EBITDA 74.7 68.2 9.2 3.7 3.1 EV / Total Operating Income 54.3 54.1 9.8 4.0 3.3 EV / Operating Free Cash Flow (Pre-Capex) 67.2 (106.1) 11.9 4.7 3.9 EV / Net Operating Free Cash Flow (Post-Capex) (27.1) (12.2) 21.9 5.7 4.3 Dividend Yield (%) 0.0 0.0 3.5 8.1 8.9 Growth Ratios (% YoY) Diluted Recurring EPS Growth 242.8 69.1 327.3 133.9 9.7 Diluted Recurring CEPS Growth 119.6 46.8 317.3 136.1 9.2 Total Operating Income Growth 108.1 31.6 450.6 126.2 8.6 EBITDA Growth 30.0 43.5 636.2 128.1 6.7 Recurring Net Income Growth 265.6 69.1 327.3 133.9 9.7 Operating Ratios (%) EBITDA Margins 34.4 43.9 76.0 80.3 81.2 EBIT Margins 47.3 55.4 71.6 75.1 77.3 Recurring Pre-tax Income Margins 47.1 54.7 68.9 74.2 77.0 Recurring Net Income Margins 31.9 47.1 56.2 61.2 63.6 Effective Tax Rate 20.6 (2.8) 18.0 17.4 17.3 Return / Profitability Ratios (%) Return on Capital Employed (RoCE)-Overall 2.8 3.4 14.5 30.2 29.4 Return on Net Worth (RoNW) 3.0 3.8 15.5 32.0 30.1 Dividend Payout Ratio 0.0 0.0 50.0 50.0 50.0



101


Tables Table 1: Reserve estimate upgrade in the past three years (3P) .......................................85 Table 2: Reserve estimate upgrade in the past three years (2P) .......................................85 Table 3: Gross production details .......................................................................................85 Table 4: Diversified portfolio of E&P blocks........................................................................87 Table 5: Cairn-Vedanta deal valuation ...............................................................................88 Table 6: Indicative financials for Vedanta post deal ...........................................................89 Table 7: P&L highlights .......................................................................................................90 Table 8: Balance sheet highlights.......................................................................................90 Table 9: Cairn’s cost structure at Rajasthan.......................................................................92 Table 10: Expected cashflows ............................................................................................92 Table 11: Valuations ...........................................................................................................94 Table 12: EV/boe comparison.............................................................................................95 Table 13: Crude price sensitivity.........................................................................................96 Table 14: Profit and loss statement ....................................................................................97 Table 15: Balance sheet .....................................................................................................98 Table 16: Cashflow statement ............................................................................................99 Table 17: Key ratios ..........................................................................................................100

Charts Chart 1: Estimated production profile .................................................................................86 Chart 2: Mangala – Salaya pipeline....................................................................................87 Chart 3: Vedanta Group – Holding structure ......................................................................89 Chart 4: Revenue break-up.................................................................................................90 Chart 5: International lifting costs .......................................................................................91 Chart 6: International E&P cost structure ...........................................................................92 Chart 7: Cairn versus Brent crude ......................................................................................96


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103

Market Cap Rs588bn/US$13.2bn Year to March FY10 FY11E FY12E FY13EReuters/Bloomberg GAIL.BO/GAIL IN Revenue (Rs mn) 282,212 346,108 371,559 389,408Shares Outstanding (mn) 1268.5 Net Income (Rs mn) 31,395 38,778 48,160 48,94352-week Range (Rs) 538/401 EPS (Rs) 24.8 30.6 38.0 38.6Free Float (%) 42.1 % Chg YoY 4.5 23.5 24.2 1.6FII (%) 13.0 P/E (x) 18.7 15.2 12.2 12.0Daily Volume (US$'000) 14,500 CEPS (Rs) 29.2 35.5 45.6 50.8Absolute Return 3m (%) (10.0) EV/E (x) 8.1 7.0 6.0 6.2Absolute Return 12m (%) 11.1 Dividend Yield 1.6 1.5 1.8 1.8Sensex Return 3m (%) (5.6) RoCE (%) 17.2 17.3 16.6 13.2Sensex Return 12m (%) 8.3 RoE (%) 19.9 21.3 22.4 19.5

GAIL BUY

An ideal defensive play Rs464Reason for report: Reinitiating coverage



Target price Rs572


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GAIL is an excellent defensive bet in the oil&gas sector underpinned by two key catalysts. In the natural gas transmission space, GAIL is embarking on an aggressive expansion spree to double its network to >16,000Kms in the next 3-4 years. Already, it owns India’s largest pipeline infrastructure and transmits 70% of the natural gas production. Hinged by secure, long-term earnings visibility and dominance in the high-margin pipelines space, GAIL is in a safe spot in transmission. Also, petchem valuations can double in the next 4-5 years as the capacities ramp-up and ethylene margin improves. However, niggling concerns exist in the form of delayed volume-ramp-up and rising subsidy. Nonetheless, we recommend GAIL as an ideal play in the domestic gas sector. Reinitiate with BUY and sum-of-the-parts (SOTP) target price of Rs572/share.

Transmission – GAIL’s supremacy to continue. GAIL is set to double its transmission network to >16,000Kms in the next 3-4 years at Rs200bn capex to absorb the incremental 60-100mmscmd gas supply. Also, the high-margin pipelines business is a cash cow for GAIL and forms 49% of its valuations. GAIL’s transmission business offers a good defensive play given the high cashflow visibility and as transmission is independent of inherent commodity (gas) price movement. New tariff regulations have been a positive for GAIL. We value transmission at Rs286/share based on DCF.

Petchem – Hidden ace. Petchem valuations, in the next 4-5 years, can double as GAIL’s Pata gas cracker expands to 0.8mntpa – this can boost long-term valuations multifold led by economies of scale and improved ethylene margin globally. Also, GAIL’s petchem profitability will always be higher than the industry average as it is gas-based. GAIL’s petchem operating margin should be +55% in the next 2-3 years versus the global average of ~25%. We value petchem at Rs144/share on EV/E.

Key risks. In our view, LPG will be a drag due to rise in subsidy. We estimate subsidy to rise to Rs25bn annually in the next two years as the net under-recoveries for oil marketing companies (OMCs) likely cross Rs100bn in FY12E-13E on the rise in crude price. Transmission is also exposed to the risk of delayed volume ramp-up.

Reinitiate with BUY. We value GAIL on SOTP at Rs572/share. At the current market price, GAIL is attractively valued at 9x FY13E CEPS. Reinitiate with BUY.

GAIL, April 4, 2011 ICICI Securities

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TABLE OF CONTENT Transmission – GAIL’s supremacy to continue .......................................................105

Expansion spree to spur valuations ............................................................................105 Gas volumes to swell, led by on-track expansion.......................................................105 Pipelines – Long-term earnings visibility provides an upper hand..............................106 Pipelines – A cash cow ...............................................................................................106 New tariff regulations, a positive .................................................................................108

Petchem – An ace up GAIL’s sleeve ..........................................................................109 Petchem margin to continue to be robust ...................................................................109

Higher subsidies to pressurise LPG..........................................................................110 CGD provides volume scalability in the long term...................................................110 E&P development long drawn ....................................................................................111 Valuations – GAIL, an ideal defensive bet.................................................................112

Improved profitability from debt raising.......................................................................112 Key risks to our call .....................................................................................................113

Financials – Transmission, the backbone.................................................................114 Annexure 1: Financials (consolidated)......................................................................116 Annexure 2: Index of Tables and Charts ...................................................................120


105

Transmission – GAIL’s supremacy to continue

Expansion spree to spur valuations

GAIL owns India’s largest pipeline infrastructure, spanning more than 7,200Kms – it transmits 70% of the country’s natural gas production. The company is on a major expansion spree to ensnare a large chunk of incremental gas volumes expected from the east coast of India. We expect GAIL to continue with its dominance in the gas transmission segment and recommend it as one of the best defensive bets in the oil & gas space. Our SOTP value is at Rs572/share. We reinitiate coverage with a BUY.

Gas volumes to swell, led by on-track expansion

The expected surge in gas supply from the east coast would beef up transmission volumes in the next four years. Also, GAIL will double its gas transmission network to >16,000Kms in the next 3-4 years from 7,200Kms at present. GAIL has recently placed the order for the 610Kms Dadri-Bawana-Nangal pipeline and has invited expression of interests for the Jagdishpur-Haldia and Kochi-Mangalore- Bangalore pipelines. The company is also ramping up the existing capacity of its GREP pipeline grid to 78mmscmd from 56mmscmd in Q1FY12. Based on the above, we expect overall gas transmission volumes to increase to 160mmscmd by ’13E-14E from 120mmscmd at present.

GAIL plans to raise an additional debt of Rs4.5bn in FY11E and Rs7bn in FY12E to fund the pipeline capex. This is a deviation from the policy of low debt as earlier, the tariffs were RoE based. Current regulations, which compute tariff on an RoCE basis, provide incentive to fund the pipeline capex at a higher debt-to-equity. This can sharply improve RoEs in the next 3-4 years once the new pipelines start contributing to revenues.

Table 1: Pipeline infrastructure – Overall snapshot FY10 FY14E

NG Trans Pipeline (km) ~7,200 ~160,00 NG Trans Capacity (MMS CMD) ~150 ~300 Source: Company, I-Sec Research

Table 2: Pipeline capex – Status

Pipeline projects Approved

cost (Rs mn)Capacity

(mmscmd)Length(Kms) Completion schedule (status)

DVPL Pipelines – Phase II Incl. Compressor At Jhabua & Vijaipur

58,370 24 to 78 610 June ’11 (one compressor at Jabhua and Vijaipur commissioned)

Vijaipur Dadri Pipelines (Incl. Compressor At Kailaras & Chainsa)

49,270 20 to 80 499 June ’11 (VijaipurDadri Pipeline commissioned in January ’10, compressor stations remaining)

Dadri Bawana Nangal Pipeline 23,580 31 594 August ’11 (commissioned up to Bawana in March ’10)

Chainsaj - Hajjar - Hissar Pipeline 13,150 35 349 April ’11 (commissioned up to Sultanpur in March ’10 and Neemrana in September ’10) *

Jagdishpur Haldia Pipeline 75,960 32 2,050 On hold Dhabol - Bangalore Pipeline 49,940 16 1,414 Phase I –March ’12

Phase II – December ’12 Kochi - Koottanad - Mangalore / Bangalore 32,630 16 1,126 Phase I –March ’12

Phase II – December ’12 Total 302,900 6,642

Source: Company Presentation

GAIL’s transmission capacity to double in next 3-4 years and the use of leverage for the projects will be RoE-accretive


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Pipelines – Long-term earnings visibility provides an upper hand

GAIL’s transmission business offers good long-term earnings visibility, given the high entry barriers and the nascent stage of the domestic gas industry. GAIL’s 7,200Kms pipeline network connects most power and fertiliser units across the western and northern corridors in India. Due to limited gas availability and infrastructure constraints, customers once tied up would retain the supplier. This yields a first-mover advantage for GAIL and a sustained, long-term revenue source.

Also, post the recently announced pipeline expansion plan, GAIL would operate across the 16,000Kms national pipeline grid, connecting all the major demand centres. Thus, most of the gas (produced domestically or imported) will have to use GAIL’s pipeline infrastructure.

Pipelines – A cash cow

Pipelines is a high-margin business as it yields more than 85% operating margins, and is independent of any movements in the natural gas price as revenues are based on regulated tariffs. GAIL enjoys domestic dominance in the space and most of its valuations come from pipelines –– GAIL’s pipeline business contributes 49% to overall valuations. Hence, this business makes GAIL one of the most defensive bets in the oil & gas space.

Cashflows from the new pipelines will likely contribute significantly to GAIL’s EV (Rs207/share). Pipeline volumes are expected to increase ~40% to ~160mmscmd in the next 2-3 years from 120mmscmd at present, led by increased supply from the east coast and Rs200bn overall capex. On the back of Reliance Industries’ (RIL) KG-D6 volumes, GAIL’s existing pipelines are already operating at ~75% utilisation (HVJ/DVPL operating at ~100%). We prefer to value GAIL’s pipeline business on DCF given long-term cash flow visibility and a regulated tariff regime.

We have capped volume estimates for LPG pipelines at the current levels as waning LPG demand domestically does not justify any need to augment LPG pipeline capacity. Based on DCF, LPG transmission should form Rs10/share of GAIL’s overall EV.

Table 3: Transmission – Valuations Pipelines EV (Rs mn) % of total EV Rs/share Existing pipelines 87,098 11.8 68.6 LPG transmission 13,045 1.8 10.3 New pipelines (includes GREP expansion) 263,229 35.6 207.4 Total EV of transmission business (A) 363,372 49.1 286.3


High-margin pipeline business contributes 49% to overall valuations


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Table 4: Domestic demand-supply situation Gas supply Current FY13 FY16 % share (FY16) Existing sources ONGC 54 46 40 13.1 Petronet LNG 30 34 36 11.8 Shell Hazira 4 9 18 5.9 Dabhol LNG 18 18 5.9 Others (including OIL and Pvt JVs) 19 20 20 6.5 New sources - RIL KG D6 54 80 80 26.1 RIL Mahanadi basin 7 9 9 2.9 GSPC KG basin 0 10 20 6.5 ONGC KG basin 0 0 20 6.5 CBM 3 5 15 4.9 RIL others (D6 satellite, NEC 25, etc) 30 9.8 Total supply 170 231 306 Gas demand Power 74 100 150 46.9 Fertiliser 39 54 70 21.8 Sponge iron plants 6 8 10 3.1 Refineries 30 35 45.5 14.2 City gas distribution 14 18 23.4 7.3 Industrial 14 18 21 6.6 Total demand 177 232 320 Demand-Supply 6.7 1.1 13.6 Source: Industry

Chart 1: Pipelines – GAIL’s expansion plans

Transmission Pipelines

Existing Gas pipelinesLPG PipelineGAIL’�s Planned PipelineRIL’�s East West Pipeline

LNG Terminal

JAGDISHPUR

PHOOLPUR

BHATINDA

BAREILLY

DISPUR

DELHI

AGARTALA

BARODA

LUCKNOW

PATNA

AHMEDABAD

RAJKOT

KOTA

MATHANIA

GWALIOR

UJJAIN

AGRA

KOLKATA

GAYA

BOKARO

VARANASIJHANSI

DAHEJ I & II10 mmtpa*

COIMBATORE

MANGALORE

MUMBAI BHUBANESHWAR

KRISHNAPATNAM

NELLORE

BANGALORE

KOLHAPUR

SOLAPURKAKINADA

VIJAYAWADA

DABHOL5 mmtpa

KANJIKKOD

AURAIYA

GOA

CUTTACK

VIJAYPUR

KANPUR

NANGAL

GURGAUN

PUNE

BHARUCH

SURAT

HYDERABAD

RAJAMUNDRY

BHOPAL

BARMER

Hisar

Jhajjarr

DADRI –�BAWANA –�NANGAL P/L

CHAINSA –�JHAJJAR –�HISAR P/L

DVPL PH-II

GREP II

EWPL

KOCHI5 mmtpa

DABHOL-BANGALORE P/L

KOCHI-KANJIKKOD-BANGALORE-MANGALORE P/L

HALDIA-JAGDHISPUR P/L

CHENNAI

TUTICORIN

TIRUCHCHIRAPALLI

DAMRA

JABALPUR

BHILAI

JAISALMER

IPI PLFROM PAKISTAN

TAPI P/L FROM PAKISTAN

MALLAVARAM BHILWARA P/L

HAZIRA3.6 mmtpa

Source: Company presentation


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New tariff regulations, a positive

The Petroleum and Natural Gas Regulatory Board (PNGRB) had notified Rs33.4/mmbtu average pipeline tariff for GAIL’s GREP/DVPL grid pipeline post expansion, which had come as a positive surprise compared to an earlier expectation of Rs30/mmbtu. This has indicated that regulations in general can offer a positive surprise compared to our calculations, due to lack availability of precise operating cost structure for individual pipelines. The tariff revision will be applicable post completion of the GREP expansion, scheduled by June ’11.

The PNGRB tariff notification is a positive for GAIL’s existing and upcoming GREP pipeline grid, as it’s a critical asset for GAIL transmitting ~80% of the company’s current volumes. However, there is no clarity on the tariffs for new pipelines which will get commissioned in the next 2-3 years. Hence, we have factored in tariffs from them at the levels fixed for the DVPL-GREP upgradation, i.e., at ~Rs53.6/mmbtu.

These regulations provide long-term visibility to GAIL’s cashflow, which leaves gas supply as the only concern that can hamper the company’s valuation upside. However, with the recent optimism built in post the RIL-BP deal on the KG Basin gas volume ramp-up, this risk will gradually subside over the next 1-2 years.

Table 5: Tariff recommendations as per PNGRB (Rs/mmbtu)

Particulars DUPL/DRPL Existing HVJ-

GREP-DVPL DVPL-GREP upgradation

As per proposal of GAIL (levelised) 40.2 35.4 Moderation/reduction by Board Inflation change to 4.5% against 5% (0.6) (0.5) Unaccounted gas not allowed (2.9) (1.2) Number of operating days changed to 355 days (1.0) - Volumes (divisor) considered as per regulation (10.7) (2.8) Corporate FBT disallowed (0.0) - O&M capex reduced to 70% (0.1) (6.4) Others (0.3) 0.9 Total moderation/reduction by Board (15.7) (9.9) 0 Levelised tariff after moderations by the Board 24.5 25.5 53.65 Existing levelised tariff 26.1 25.5 53.65

Source: Company Presentation

Tariffs based on PNGRB notifications for the existing pipelines have surprised on the upside


109

Petchem – An ace up GAIL’s sleeve

Petchem margin to continue to be robust

GAIL operates a gas cracker at Pata, Uttar Pradesh, which can produce 450,000tpa of ethylene. GAIL’s Board has recently approved plans to double the ethylene capacity at Pata to 800,000tpa in the next 3-4 years. Initially, the company plans to increase the capacity to 510,000tpa by the next year. We, however, exclude the expansion from our estimates as GAIL has not disclosed details on capex and timelines. Petchem valuations, in the next 4-5 years, can double as the Pata gas cracker expansion gets completed and the ethylene margin scenario improves; hence, Petchem can boost valuations multifold in the long term.

Average ethylene product (hdPE/lldPE) realisations have risen along with the crude prices (though with a lag), led by global economic recovery. Going forward, we expect the impact of excess ethylene capacity additions globally (predominantly in the Middle East) to be muted as demand growth from the emerging markets should be strong enough to absorb global ethylene capacity addition (up to 26mmtpa additions expected). Also, GAIL’s Petchem profitability will always be higher than the industry average as it is purely gas-based. We expect GAIL’s Petchem operating margin to be +55% in the next 2-3 years versus the global average of ~25%.

Table 6: Ethylene capacities

Year Capacity

(MMT) YoY chg

Demand (MMT)

YoY chg

Required Utilisation (%)

2010 137 12.5 115 83.9 2011 142 4.8 119 4 84.0 2012 143 0.8 123 4 86.3 2013 147 4.8 130 7 88.2 2014 151 4.0 136 6 89.9 Total 26.8 21

Source: CMAI With gas being a primary feedstock for GAIL’s Petchem business and given the estimated robustness in hdPE/lldPE prices, we expect Petchem margin to be continue to expand from current levels of 55%. Accordingly, we estimate GAIL’s Petchem EBITDA to expand to Rs26bn levels by FY13E. We value the business at 7x FY13E EBITDA (at a marginal discount to global peers), which yields a fair value of Rs144/share.

Table 7: Petchem – Overview (Rs mn, year ending March 31)

FY10 FY11E FY12E FY13E Revenue 29,907 37,927 40,297 42,668 Revenue Growth (%) 9.9 26.8 6.2 5.9 EBITDA 15,537 21,519 23,698 26,039 EBITDA Margin (%) 52.0 56.7 58.8 61.0 EBIT 13,988 19,969 22,148 24,488 EBIT Margin (%) 46.8 52.7 55.0 57.4


Table 8: Petchem – Valuations FY13E EBITDA (Rs mn) 26,039 EV (7x EBITDA) (Rs mn) 182,270 EV (Rs/share) 144


GAIL enjoys a strong cost advantage as it has a pure gas-based cracker


110

Higher subsidies to pressurise LPG GAIL’s LPG and liquid hydrocarbon business has run into tough terrain in the past few years, mostly due to the Government’s ad hoc subsidy-sharing policy. GAIL operates a 1.3mmtpa gas-based LPG extraction unit, which is sold to PSU OMCs. However, because GAIL produces LPG, the Government has involved it in upstream subsidy sharing. The company’s LPG business has been continuously impacted by subsidies, fluctuating between profits and losses in the past 4-5 years. Considering that the OMCs’ net under-recoveries will likely breach the Rs100bn mark in FY12E-13E in wake of the sharp crude price spike, we expect GAIL’s subsidy to rise to Rs25bn annually in the next two years. Going forward, we expect the LPG margin to decline, led by increased costs. We have valued the business at 6x FY13E EBITDA, which yields a fair value of Rs63/share.

Table 9: LPG – Overview (Rs mn, year ending March 31)

FY10 FY11E FY12E FY13E Revenue 28,791 26,561 33,678 33,903 Revenue growth (%) -3.16 -7.75 26.79 0.67 EBITDA 7,435 6,033 13,075 13,300 EBITDA margin (%) 25.82 22.71 38.82 39.23 EBIT 6,589 5,170 12,194 12,402 EBIT margin (%) 22.88 19.46 36.21 36.58


Table 10: LPG – Valuations FY13E EBITDA (Rs mn) 13,300 EV (6x EBITDA) (Rs mn) 79,801 EV (Rs/share) 63


CGD provides volume scalability in the long term GAIL, to encompass the entire gas value chain (from production to marketing), has forayed into city gas distribution (CGD) by floating a state-wise, dedicated SPV with OMCs to supply gas to households, commercial users and the transport sector. And given that its maiden venture through Indraprastha Gas (IGL) has been a success, the company has floated eight SPVs in respective states to tap in the potential of natural gas as a key alternative to conventional fuels such as petrol, diesel and LPG. The company plans to create ~40 more SPVs across India as a part of the Government of India’s ‘Blue Sky’ initiative to promote clean fuels. GAIL has ventured into other countries in this business by investing strategically (Rs1,500mn) in gas distribution companies (two companies in Egypt and one in China). We have valued GAIL’s various investments in CGD business at Rs17/share.

High subsidies continue to pressurise LPG valuations

The CGD segment of GAIL completes its presence in entire value chain


111

E&P development long drawn GAIL, in consortium with exploration majors such as ONGC/GSPC, has diversified into the high-risk exploration business and has succeeded in some blocks. The company currently holds 10-80% participating interest in 30 exploration blocks (in different phases of exploration). These blocks are located in basins such as Mahanadi, Bengal, Gujarat-Saurashtra, Mumbai, Cambay, Assam-Arakan and Cauvery. The development in such businesses takes time and hence, is long drawn in nature. As is true with any E&P business, a significant discovery in any block can completely change the E&P valuations, which can exponentially raise fair value.

We have factored in just GAIL’s net interest in Cambay and Myanmar blocks to ascribe Rs4.5/share (net) fair value to E&P. We have not factored in the CBM blocks as exact development plans have not been disclosed yet. However, inclusive of the CBM blocks, the overall value for E&P shoots up to Rs16/share.

Cambay block. GSPC and GAIL have struck oil in the Cambay basin (Block CB-ONN-2000/1 – recoverable reserve of 3.5mmbbl) and are currently in the production stage. The production is planned for 10 years and we have valued the block at Rs420mn (Rs0.10/share)

CBM blocks. The GAIL consortium has been awarded three CBM blocks in the third round of CBM bidding in India recently (at Chhattisgarh and Jharkhand). GAIL's share in the above blocks is within 35-45% (net share of reserves at 127Bcm). We have valued the blocks at an EV/boe of 2x and a recovery of 35%, implying Rs11/share gross value.

Myanmar blocks. GAIL has 10% stake in two blocks in Myanmar (Block A1 & A3), with an estimated in-place reserves of ~20Tcf (as per the Myanmar Government). At a 10% recovery factor and an EV/boe of 3x, its value stands at Rs9.1/share (gross value).

Table 11: E&P valuations Block Stake

(%)Reserves

(mboe)GAIL’s share

(mboe)Total

discounted EV (Rsmn)

EV/boe(US$)

Value/share (Rs)

CB - ONN - 2000/1 50 3.5 0.4 165 8.0 0.1Myanmar Block – A1,A3 7.5 1,800 55.35 10,406 3.0 9.1

35 990 121 10,915 2.0 4.935 342 42 3,771 2.0 1.7

CBM (3 Blocks)

45 756 111 10,002 2.0 4.5CBM total 2,081 286 14,115 4.0 11.1Write-offs (6,472) Total 20,049 15.8


We have valued E&P business Rs4.5/share, but has potential to add Rs16/share if we include the CBM blocks


112

Valuations – GAIL, an ideal defensive bet We reinitiate coverage on GAIL with a BUY rating – At the current market price of Rs464, GAIL is trading at 12x FY13E earnings. Based on cash earnings, the company is attractively valued at ~9x FY13E CEPS. We have used SOTP, which yields Rs572/share value for GAIL – we have valued each business separately, incorporating the value of GAIL’s investments in companies such as ONGC, Petronet LNG etc. At our 12-month target price of Rs572, GAIL would be trading at a comfortable 11.3x FY13E cash earnings. Even in a scenario of changing dynamics (surge in gas supply from the east coast), GAIL will continue to dominate domestic gas transmission and hence, is an ideal defensive play in the domestic oil & gas space. Reinitiate coverage with a BUY.

Table 12: SOTP valuations (Rs mn)

Particulars Enterprise value

Rs/share Method

Natural gas transmission (Existing pipelines) 87,098 68.6 DCF LPG transmission 13,045 10.3 DCF New pipelines (includes GREP expansion) 263,229 207.4 DCF Total EV of transmission business (A) 363,372 286.3 Natural gas trading (B) 49,967 39.4 7x FY13E EBITDA LPG production business (C) 79,801 62.9 6x FY13E EBITDA Petrochemicals business (D) 182,270 143.6 7x FY13E EBITDA Total EV (D) 675,409 532.2 2.4% stake in ONGC 30,703 24.2 20% discount to market price 12.5% stake in Petronet LNG 7,456 5.9 20% discount to market price 22.5% stake in Indraprastha Gas 7,862 6.2 20% discount to market price Total portfolio stake (E) 46,021 36.3 8.45% stake in Myanmar A-1 block 11,486 9.1 EV/boe 50% stake in Cambay offshore block 920 0.7 EV/boe Possible write-offs in the next three years (6,462) E&P value (F) 5,944 4.7 Stakes in city gas distribution projects (India and abroad) (G) 21,660 17.1

Firm value 749,034 590.3 Less: Net debt (FY12E) 22,575 17.8 Equity value 726,459 572.0


Improved profitability from debt raising

GAIL’s current low leverage at 32% strongly boosts its overall capex plans of Rs250bn in the next 4-5 years. The company plans to raise its debt to Rs200bn over the next two years through a combination of ECBs and borrowings from domestic banks to fund its pipeline capex. This would raise GAIL’s debt-to-equity to 82% in FY13E, which is comfortable and would fund the overall Rs250bn capex (including E&P and petrochemicals spend). The company can also dilute its holding in ONGC worth Rs76bn (Rs60/share) to fund its capex.

Table 13: Overall capex projections Projected capex FY11 FY12 FY13 Pipeline 38,500 37,500 37,500 E&P 4,600 7,670 7,670 Petrochemicals 2,300 3,830 3,830 Others 13,180 27,390 27,390 Total 58,580 76,390 76,390


Strong long-term defensive play

Debt equity would still be comfortable at 82% in FY13E after pipeline capex


113

Traditionally, GAIL has avoided the debt route as earlier, the tariffs were annual RoE-based. On the other hand, the current tariff regulations, based on RoCE, incentivise high debt funding for incremental pipeline capex. GAIL has, therefore, rightly opted for an aggressive debt raising plan, based on which we expect its RoEs to improve markedly from the current 22% once the new pipelines start generating revenues post FY13. GAIL might witness a re-rating (as future cashflows indicate higher incremental returns) and a possible P/BV expansion (FY13E P/BV of 2.2x).

Chart 2: Planned borrowings through FY11-13

0

25

50

75

100

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Table 14: Return ratios FY07 FY08 FY09 FY10 FY11E FY12E FY13E

RoCE 15.66 17.81 18.63 17.25 17.30 16.56 13.18 RoNW 19.25 21.20 21.64 19.89 21.27 22.45 19.53



• Execution risks such as delays or cost escalation in pipeline expansion could affect the IRR upside from the project.

• Global ethylene margin contraction could mar GAIL’s petchem margins.

• Inability of the Government to pass on the increase in LPG price to the customer could affect GAIL in the form of higher subsidy burden.

• Delay in ramp-up D6 production could lower transmission volumes, thereby affecting the total tariff.


114

Financials – Transmission, the backbone GAIL’s revenue growth would be primarily led by gas transmission volumes as the other businesses seem lacklustre at present. We expect the company to cross 150mmscmd volumes in FY13E, led by expansion in RIL’s KG D6 production to ~87mmscmd and incremental production from ONGC fields.

Table 15: Revenue profile (Rs mn, year ending March 31)

FY10 FY11E FY12E FY13E Gas transmission volumes (mmscmd) 106.70 115.28 139.30 159.00 Tariffs (Rs/('000 scm) 813.55 803.49 927.63 1,019.06 Gas transmission 31,684 33,809 47,165 59,141 % Tot 11.7 12.5 17.4 21.9 % grth 27.6 6.7 39.5 25.4 LPG transmission 4,472 4,472 4,472 4,472 % Tot 1.7 1.7 1.7 1.7 % grth 17.6 0.0 0.0 0.0 Petchem 29,122 37,927 40,297 42,668 % Tot 10.8 14.0 14.9 15.8 % grth 2.2 30.2 6.2 5.9 LPG & LHC 28,330 26,561 33,678 33,903 % Tot 10.5 9.8 12.5 12.5 % grth -4.5 -6.2 26.8 0.7 Gas trading 188,029 242,368 244,766 248,013 % Tot 69.5 89.6 90.5 91.7 % grth 2.7 28.9 1.0 1.3 Others (GAIL Telecom, E&P) 533 972 1181 1211 % Tot 0.2 0.4 0.4 0.4 Total 282,170 346,108 371,559 389,408 % grth 4.4 22.7 7.4 4.8

Source: I-Sec Research Also, as gas transmission is a high-margin business, we expect GAIL’s EBITDA to grow faster to ~US$2bn by FY13E. Other businesses will continue to be a drag.

Table 16: EBITDA contribution from businesses (Rs mn, year ending March 31)

FY10 FY11E FY12E FY13EGas transmission 23,792 25,610 36,097 46,406% Tot 54.58 58.75 82.80 49.33% sales 75.09 75.75 76.53 78.47Gas Trading 4,038 7,089 7,091 7,138% Tot 8.65 11.56 8.74 7.59% sales 2.15 2.92 2.90 2.88LPG transmission 3,422 3,477 3,477 3,477% Tot 7.85 7.98 7.98 3.70% sales 76.53 77.75 77.75 77.75Petchem 14,667 21,519 23,698 26,039% Tot 33.64 49.36 54.36 27.68% sales 50.36 56.74 58.81 61.03LPG & LHC 7,435 6,033 13,075 13,300% Tot 17.06 13.84 29.99 14.14% sales 26.24 22.71 38.82 39.23Others (GAIL telecom, E&P write-offs, etc) (6,666) (2,414) (2,283) (2,280)% Tot (15.29) (5.54) (5.24) (2.42)Total 46,688 61,569 81,456 94,500% grth 7.10 31.33 32.36 15.93


GAIL’s revenues and profitability will led by gas transmission


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FY09 FY10 FY11E FY12E FY13EGross Sales 245,729 253,302 312,493 337,530 355,097 Less: Excise Duty 5,163 3,794 1,188 1,288 1,343Net Sales 240,566 249,508 311,305 336,243 353,755 of which Export Sales - - - - - of which Domestic Sales 240,566 249,508 311,305 336,243 353,755Telecom revenues 243 124 311 341 371Other Operating Income 31,405 32,248 33,831 34,136 34,443E&P revenues - 332 661 840 840Total Operating Income 272,214 282,212 346,108 371,559 389,408 Less: Raw Material Consumed 203,442 208,336 260,950 263,713 267,286 Power and Fuel 8,695 9,104 9,319 10,727 12,044 Personnel Expenses 5,767 6,212 6,678 7,685 8,640 Selling and Distribution Expenses 6,212 6,955 3,130 3,397 2,288 Other Expenses 855 1,417 1,331 1,398 1,468

E&P business expenses 3,651 3,500 3,131 3,183 3,183Total Operating Expenses 228,621 235,523 284,539 290,103 294,909 EBITDA 43,593 46,688 61,569 81,456 94,500 Depreciation & Amortisation 5,599 5,618 6,199 9,710 15,475Other Income 7,966 5,411 3,471 3,186 3,272 EBIT 45,960 46,481 58,841 74,933 82,297 Less: Gross Interest 870 700 1,133 4,122 10,099 Recurring Pre-tax Income 45,090 45,781 57,709 70,811 72,198 Add: Extraordinary Income (2,013) 4 - - -Less: Extraordinary Expenses Less: Taxation --Current Tax 14,977 13,750 18,850 22,552 23,153--Deferred Tax 62 636 81 100 102 Net Income (Reported) 28,037 31,398 38,778 48,160 48,943 Recurring Net Income 30,050 31,395 38,778 48,160 48,943



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FY09 FY10 FY11E FY12E FY13EASSETS Current Assets, Loans & Advances Cash & Bank balance 34,562 41,718 22,107 26,310 23,902 Inventory 6,014 6,317 8,452 8,477 8,863 Sundry Debtors 15,033 12,950 15,545 15,792 16,559 Loans and Advances 31,117 33,240 35,508 37,931 40,520 Other Current Assets 546 83 87 91 96Total Current Assets 87,272 94,308 81,700 88,601 89,939 Current Liabilities & Provisions Current Liabilities Sundry Creditors 19,725 20,318 25,449 25,718 26,067 Other Current Liabilities 22,054 34,165 34,165 34,165 34,165 Provisions 4,675 6,479 6,479 6,479 6,479 Total Current Liabilities and Provisions 46,455 60,962 66,093 66,363 66,711 Net Current Assets 40,818 33,346 15,606 22,238 23,228 Investments Strategic & Group Investments 17,217 20,634 30,134 41,002 42,002Other Marketable Investments 156 96 96 96 96Total Investments 17,373 20,730 30,230 41,098 42,098 Goodwill Fixed Assets Gross Block 176,040 210,377 227,522 364,489 524,650 Less Accumulated Depreciation 85,537 91,066 97,242 106,926 122,376 Net Block 90,503 119,311 130,280 257,563 402,274Add: Capital Work in Progress 20,825 19,570 77,047 23,180 9,365Exploratory wells in progress 3,438 3,735 7,310 10,885 14,460Less: Revaluation Reserve Total Fixed Assets 114,767 142,616 214,638 291,628 426,099 Total Assets 172,957 196,692 260,474 354,965 491,425 LIABILITIES AND SHAREHOLDERS' EQUITY Borrowings Short Term Debt 1,001 - - - - Long Term Debt 11,000 14,804 49,804 108,501 208,383Total Borrowings 12,001 14,804 49,804 108,501 208,383 Deferred Tax Liability 13,259 13,896 13,977 14,077 14,178 Share Capital Paid up Equity Share Capital 12,685 12,685 12,685 12,685 12,685 No. of Shares outstanding (mn) 1,268 1,268 1,268 1,268 1,268 Face Value per share (Rs) 10 10 10 10 10 Reserves & Surplus Share Premium 3 3 3 3 3 General & Other Reserve 135,009 155,305 184,006 219,699 256,176Net Worth 147,696 167,992 196,693 232,387 268,864 Total Liabilities & Shareholders' Equity 172,957 196,692 260,474 354,965 491,425



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FY09 FY10 FY11E FY12E FY13ECash Flow from Operating Activities Reported Net Income 28,037 31,398 38,778 48,160 48,943Add: Depreciation & Amortisation 5,291 5,529 6,176 9,684 15,450 Deferred Taxes 62 636 81 100 102Less: Other Income 7,966 5,411 3,471 3,186 3,272 Net Extra-ordinary income (2,013) 4 - - -Op. Cash Flow before Working Capital change (a) 27,437 32,149 41,564 54,757 61,222 Changes in Working Capital (Increase) / Decrease in Inventories (316) (303) (2,135) (25) (386)(Increase) / Decrease in Sundry Debtors (4,298) 2,083 (2,595) (246) (768)(Increase) / Decrease in Operational Loans & Adv. (8,245) (2,123) (2,268) (2,423) (2,588)(Increase) / Decrease in Other Current Assets 22 464 (4) (4) (5)Increase / (Decrease) in Sundry Creditors 1,747 593 5,131 269 348Increase / (Decrease) in Other Current Liabilities 3,599 13,915 - - - Working Capital Inflow / (Outflow) (b) (7,490) 14,628 (1,871) (2,429) (3,398) Net Cash flow from Operating Activities (a) + (b) 19,947 46,777 39,693 52,328 57,824 Cash Flow from Capital commitments Purchase of Fixed Assets (22,558) (33,379) (78,198) (86,675) (149,921)Purchase of Investments (2,464) (3,358) (9,500) (10,868) (1,000)Cash Inflow/(outflow) from capital commitments (c) (25,022) (36,736) (87,698) (97,543) (150,921) Free Cash flow after capital commitments (a) + (b) + (c) (5,075) 10,041 (48,005) (45,214) (93,097) Cash Flow from Investing Activities Other Income 7,966 5,411 3,471 3,186 3,272Net Cash flow from Investing Activities (d) 7,966 5,411 3,471 3,186 3,272 Cash Flow from Financing Activities Proceeds from fresh borrowings (657) 2,803 35,000 58,697 99,882Dividend paid including tax (10,388) (11,102) (10,077) (12,466) (12,466) Net Cash flow from Financing Activities (e) (11,046) (8,300) 24,923 46,231 87,416 Net Extra-ordinary Income (f) (2,013) 4 - - - Total Increase / (Decrease) in Cash (10,167) 7,156 (19,611) 4,203 (2,408)(a) + (b) + (c) + (d)+ (e) + (f) Opening Cash and Bank balance 44,730 34,562 41,718 22,107 26,310Closing Cash and Bank balance 34,562 41,718 22,107 26,310 23,902Increase/(Decrease) in Cash and Bank balance (10,168) 7,156 (19,611) 4,203 (2,408)



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FY09 FY10 FY11E FY12E FY13EPer Share Data (in Rs.) EPS(Basic Recurring) 23.7 24.8 30.6 38.0 38.6 Diluted Recurring EPS 23.7 24.8 30.6 38.0 38.6 Recurring Cash EPS 28.1 29.2 35.5 45.6 50.8 Dividend per share (DPS) 7.0 7.5 6.8 8.4 8.4 Book Value per share (BV) 116.4 132.4 155.1 183.2 212.0 Growth Ratios (%) Operating Income 32.4 3.7 22.6 7.4 4.8 EBITDA 10.8 7.1 31.9 32.3 16.0 Recurring Net Income 16.2 4.5 23.5 24.2 1.6 Diluted Recurring EPS 16.2 4.5 23.5 24.2 1.6 Diluted Recurring CEPS 12.9 3.8 21.5 28.7 11.3 Valuation Ratios (x) P/E 19.6 18.7 15.2 12.2 12.0 P/CEPS 16.5 15.9 13.1 10.2 9.1 P/BV 4.0 3.5 3.0 2.5 2.2 EV / EBITDA 8.8 8.1 7.0 6.0 6.2 EV / Operating Income 1.4 1.3 1.3 1.3 1.5 EV / Operating FCF 29.0 12.3 15.9 13.1 13.6 Operating Ratio Raw Material/Sales (%) 84.6 83.5 83.8 78.4 75.6 Other Income / PBT (%) 17.7 11.8 6.0 4.5 4.5 Effective Tax Rate (%) 33.4 31.4 32.8 32.0 32.2 NWC / Total Assets (%) 3.6 (4.3) (2.5) (1.1) (0.1)Inventory Turnover (days) 36.2 35.3 36.6 32.4 32.2 Receivables (days) 19.1 20.2 16.6 16.9 16.6 Payables (days) 33.8 35.1 32.0 35.4 35.4 D/E Ratio (x) 17.1 17.1 32.4 52.7 82.8 Return/Profitability Ratio (%) Recurring Net Income Margins 10.7 10.9 11.1 12.9 12.5 RoCE 18.6 17.2 17.3 16.6 13.2 RoNW 21.6 19.9 21.3 22.4 19.5 Dividend Payout Ratio 31.7 30.3 22.2 22.1 21.8 Dividend Yield 1.5 1.6 1.5 1.8 1.8 EBITDA Margins 16.0 16.5 17.8 21.9 24.3



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Tables Table 1: Pipeline infrastructure – Overall snapshot ..........................................................105 Table 2: Pipeline capex – Status ......................................................................................105 Table 3: Transmission – Valuations..................................................................................106 Table 4: Domestic demand-supply situation.....................................................................107 Table 5: Tariff recommendations as per PNGRB .............................................................108 Table 6: Ethylene capacities .............................................................................................109 Table 7: Petchem – Overview...........................................................................................109 Table 8: Petchem – Valuations.........................................................................................109 Table 9: LPG – Overview..................................................................................................110 Table 10: LPG – Valuations ..............................................................................................110 Table 11: E&P valuations..................................................................................................111 Table 12: SOTP valuations ...............................................................................................112 Table 13: Overall capex projections .................................................................................112 Table 14: Return ratios .....................................................................................................113 Table 15: Revenue profile.................................................................................................114 Table 16: EBITDA contribution from businesses..............................................................114 Table 17: Profit and loss statement ..................................................................................116 Table 18: Balance sheet ...................................................................................................117 Table 19: Cashflow statement ..........................................................................................118 Table 20: Key ratios ..........................................................................................................119

Charts Chart 1: Pipelines – GAIL’s expansion plans....................................................................107 Chart 2: Planned borrowings through FY11-13 ................................................................113 Chart 3: Rolling price/EPS trend.......................................................................................115 Chart 4: Rolling price/book trend ......................................................................................115 Chart 5: Rolling EV/EBITDA trend ....................................................................................115

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Market Cap Rs57.3bn/US$1.3bn Year to Mar FY10 FY11E FY12E FY13EReuters/Bloomberg GSPT.BO/GUJS IN Revenue (Rs bn) 9,920 11,049 12,319 12,859 Shares Outstanding (mn) 562.58 Net Income (Rs bn) 4110 5646 6287 6901 52-week Range (Rs) 128/82 EPS (Rs) 7.3 10.0 11.2 12.7 Free Float (%) 62.3 % Chg YoY 232.4 37.4 11.4 13.9 FII (%) 11.3 P/E (x) 13.9 10.1 9.1 8.0 Daily Volume (US$/'000) 1,870 CEPS (Rs) 11.5 12.3 13.9 15.9 Absolute Return 3m (%) (13.5) EV/E (x) 7.3 7.1 5.9 5.1 Absolute Return 12m (%) 12.4 Dividend Yield (%) 1.0 1.0 1.0 1.0 Sensex Return 3m (%) (5.6) RoCE (%) 17.4 18.4 16.8 16.6

Sensex Return 12m (%) 8.3 RoE (%) 29.6 31.1 26.8 23.5

Gujarat State Petronet BUY

Moving into higher growth orbit Rs102Reason for report: Reinitiating coverage



Target price Rs130


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Gujarat State Petronet (GSPL) is the largest transmission network operator inGujarat, connecting all the major demand centres in the state through its1,700Kms long pipeline infrastructure. GSPL’s transmission volumes have surgedto 38mmscmd in the past two years, led by KG-D6 supply and LNG from PetronetLNG (PLNG). GSPL is mulling expanding aggressively beyond Gujarat – it has wonthree bids for inter-state trunk pipelines, spanning 4,000Kms. The growth thrustmakes GSPL an aggressive long-term play, offering a possible Rs44/share upsideif the pipelines are found to be commercially viable – we have excluded this in ourvaluations. We reinitiate coverage on GSPL with a BUY. We value GSPL on DCF,which yields a target price of Rs130/share. The stock offers excellent risk-rewardin the long term. Reinitiate with a BUY.

Gujarat, still a golden opportunity. GSPL has benefited from Reliance Industry’s(RIL) gas production from the KG-D6 basin – its transmission volumes have risen to38mmscmd in the past two years. We expect GSPL to transmit >50mmscmdvolumes in the next three years as gas supplies ramp up from RIL and ONGC. Thecompany now intends to move beyond Gujarat. With ~27mmscmd incrementaldemand to come up from gas-based power plants in Gujarat, the state offers amplevolume growth opportunity for GSPL.

Expanding horizons. GSPL has bid for four new cross-country pipelines in a JV withoil marketing companies (OMCs, GSPL has 52% stake), which would expand itsreach beyond Gujarat. The company has won three bids, but the official licenceshave not been awarded by the PNGRB due to a stay by the Supreme Court onPNGRB’s authority to award licences. The three pipelines would span 4,000Kms inIndia at a capex of Rs180bn in the next 3-4 years. In our view, these pipelines canadd up to Rs44/share upside to GSPL’s target price if they are found to becommercially viable – we have not captured this in our target price.

Key concerns – Tariffs and volume ramp-up. Some key concerns are the long-pending authorisation from the Petroleum and Natural Gas Regulatory Board(PNGRB) for GSPL’s Gujarat pipelines and the approval of tariffs. We expect theseto be addressed by Q2FY12 as GSPL files for its tariff notification by March end. Aswas the case for GAIL, it is unlikely that GSPL’s current tariffs would decline post thenotification (also assured by the management).

Reinitiate with a BUY. At our target price of Rs130/share, GSPL would trade at acomfortable 8.2x FY13E cash earnings. Reinitiate with a BUY.

Gujarat State Petronet, April 4, 2011 ICICI Securities

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TABLE OF CONTENT Gujarat, still a golden opportunity .............................................................................123

Volume rise in Gujarat to be led by domestic gas supplies ........................................123 Expanding horizons.....................................................................................................126

Upsides from new pipelines back-ended ....................................................................126 Financial overview .......................................................................................................129

Volume growth on track ..............................................................................................129 Debt raising to sustain RoEs.......................................................................................129

Valuations attractive....................................................................................................130 Reinitiate with a BUY ..................................................................................................130 DCF – Key assumptions .............................................................................................130 Key risks to our call .....................................................................................................130

Annexure 1: Financials (standalone) .........................................................................132 Annexure 2: Index of Tables and Charts ...................................................................136


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Gujarat, still a golden opportunity Volume rise in Gujarat to be led by domestic gas supplies Gujarat is one of the largest natural gas demand centres in India and GSPL has been pivotal in developing the gas market in the state. The company has until recently primarily focused on connecting prominent demand centres in the state. The power sector is a major gas demand driver in Gujarat; hence, we expect incremental gas volume growth for GSPL to be sensitive to pricing. This makes the increase in low-cost domestic gas supply critical to propel volume growth in Gujarat – gas supply will rise mostly due to the ramp-up in RIL’s KG D6 volumes. High cost LNG will have a limited role to play in terms of satiating future power demand. Post the RIL-British Petroleum deal, the ramp-up schedule for the KG D6 field is perking up and can surprise on the upside by achieving peak production sooner than expected.

Table 1: Upcoming gas-based power plants in Gujarat Company Location Capacity

(MW) Gas utilisation

(mmscmd) Comments

GSPC Hazira, Pipavav

1050 5.3 Hazira plant of 350MW to come up in April FY12 Pipavav plant of 350MW to come up in June FY12 Another 350MW expansion at Pipavav to come up in Q3FY12

Torrent Sujen, Dahej

1583 7.9 UNOSUGEN project(brownfield) of 382.5MW at Sugen, for which EPC contract has been awarded DGEN project at Dahej SEZ (1,200MW) likely by FY14E

Gujarat State Electricity Corporation

Dhuvarna 375 1.9 L&T has been awarded the EPC contract for the project

Delhi-Mumbai Industrial Corridor (DMIC)

2300 11.5 Two projects by DMIC (1,000MW & 1,300MW) likely to come in ’13-14

Total 5308 26.5 Source: Industry

GSPL has benefited from RIL’s D6 gas production – its transmission volumes have risen to 38mmscmd in the past two years. The company’s 1,700Kms long infrastructure in Gujarat connects all the major gas demand centres to the supply sources. Also, connectivity to the LNG terminals of Shell and Petronet LNG and the HVJ pipeline in the West and with the Reliance Gas Transmission Infrastructure (RGTIL) pipeline in the east coast offers GSPL a unique advantage of giving its customers the option to source gas from all the major sources.

Chart 1: Gas demand source in Gujarat Chart 2: Supply source in Gujarat

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GSPL has significant presence in Gujarat – the gas hub of India and a major recipient of east coast gas

Major volume growth in Gujarat will come from Power and Fertilizer companies, priority sectors in terms of gas allocation


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Chart 3: GSPL’s network in Gujarat

Source: Company

Optimism of growth in domestic supply has re-emerged based on the recent RIL-BP deal for the KG basin blocks. Consequently, we see a possible expansion in GSPL’s volumes based on the following phases:

• Phase I – D6 volume ramp up to 65-67mmscmd from 51mmscmd. This would add 4-5mmscmd to GSPL’s volumes, which would be mainly supplied to power projects in Gujarat. Thus, overall volumes would rise to 42-43mmscmd from 38mmscmd.

• Phase II – D6 volumes to ramp up to 87mmscmd by end FY13E from 67mmscmd. This would add ~6-7mmscmd to GSPL’s volumes and overall volumes would move up to 50mmscmd in FY14E. Additional infrastructure is required to ramp up beyond 50mmscmd.

However, we have factored in delay in ramp-up of gas production from KG D6 and believe that expansion to 87mmscmd would happen only by end FY13. Volume growth for GSPL would be primarily driven by LNG in FY12. Addition from RIL kicks in only from FY13 as per our estimates.

D6 production ramp-up will push GSPL volumes towards 50mmscmd


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Table 2: Domestic demand-supply (mmscmd) Gas supply Current FY13E FY16E % share (FY16E) Existing sources ONGC 54 46 40 13.1 Petronet LNG 30 34 36 11.8 Shell Hazira 4 9 18 5.9 Dabhol LNG 18 18 5.9 Others (including OIL and Pvt JVs) 19 20 20 6.5 New sources - RIL KG D6 54 80 80 26.1 RIL Mahanadi basin 7 9 9 2.9 GSPC KG basin 0 10 20 6.5 ONGC KG basin 0 0 20 6.5 CBM 3 5 15 4.9 RIL others (D6 satellite, NEC 25, etc) 30 9.8 Total supply 170 231 306 Gas demand Power 74 100 150 46.9 Fertiliser 39 54 70 21.8 Sponge iron plants 6 8 10 3.1 Refineries 30 35 45.5 14.2 City gas distribution 14 18 23.4 7.3 Industrial 14 18 21 6.6 Total demand 177 232 320 Demand-supply 6.7 1.1 13.6 Source: Industry

Chart 4: Gas, most competitive versus other alternate fuels

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Expanding horizons

Upsides from new pipelines back-ended

In a regulated tariff scenario, the only way to expand valuations is to continuously incur capex. GSPL has won three bids of the four cross-country pipeline bids, which would expand its reach beyond Gujarat.

Mallavram-Vijaipur-Bhilwara (1,585Kms) – Rs60-70bn capex & 30mmscmd capacity. GSPL has won the bid for the Mallavram-Vijaipur-Bhilwara pipeline, in consortium with OMCs, Indian Oil Corporation (IOC), Hindustan Petroleum Corporation (HPCL) and Bharat Petroleum Corporation (BPCL). GSPL will own 52%, while IOC, HPCL and BPCL will 24%, 12% & 12% respectively.

GSPL is planning to supply gas from the east coast to tap in the demand potential in Central India and East Rajasthan. The overall demand potential from this region is expected to be ~20mmscmd. However, this pipeline will compete with RGTIL and GAIL’s pipeline infrastructure. Hence, the key to success is excess supply from the east coast in the next 4-5 years.

Mehsana-Bhatinda (1,670Kms) – Rs65-80bn capex & 30mmscmd capacity. GSPL has won the bid for the Mehsana-Bhatinda pipeline together with OMCs. GSPL would own 52%, while IOC, HPCL and BPCL would own 24%, 12% and 12% respectively.

GSPL wants to tap in gas demand centres in Bhatinda (from the upcoming HPCL-Mittal 9mmtpa Bhatinda refinery) and other demand centres en route to Rajasthan. The company sees a demand of 10mmscmd in Bhatinda, with other areas in Rajasthan potentially generating 10-20mmscmd demand.

Bhatinda-Srinagar (740Kms) – Rs30-40bn capex & 30mmscmd capacity. GSPL has won the bid for the pipeline in consortium with OMCs. GSPL would own 52%, while IOC, HPCL and BPCL would 24%, 12% and 12% respectively.

The infrastructure for the pipeline would be difficult to implement and operate given its passage through the strife-ridden Jammu & Kashmir state. GSPL sees a demand potential of ~10mmscmd in Jammu and Srinagar. However, we are guarded in valuing the capex of the pipeline even if GSPL wins the bid as the route is prone to terrorism.

Surat-Paradip (1,680Kms) – Rs70-80bn capex & 30mmscmd capacity. The PNGRB has set March 28, ’11 as the deadline for submitting the bids, the outcome of which will be declared by end-April or May ’11.

This pipeline runs parallel to RGTIL’s Kakinada-Bharuch pipeline, which is surprising. However, with >50-100mmscmd incremental gas production expected from the east coast in the next 5-10 years, GSPL probably envisages lack of pipeline capacity by RGTIL and other pipelines connecting the east coast. The company sees a potential demand of 20mmscmd in Paradip (from the upcoming 15mmtpa Paradip refinery and the proposed petrochemical complex).

New pipeline bids, if commercially viable, offer an upside of Rs44/share to our target price


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GSPL has won three bids for the new pipelines, but the official licences have not been issued by the PNGRB due to a stay by the Supreme Court on PNGRB’s authority to award licences. The three pipelines span 4,000Kms in India and entail a capex of Rs180bn in the next 3-4 years. We believe the pipelines can add up to Rs44/share upside to GSPL’s target price if they are found to be commercially viable.

Table 3: Valuations for new pipelines (Rs mn)

New pipeline capex (gross) 180,000 New pipeline capex (net to GSPL) 93,600 Debt (70%) 65,520 Equity 28,080 Book value/Share (x) 50 Discounted book value (four years) 32 Project IRR (RoCE) 12% P/BV valuation (@implied RoE of 17%, 1.4x) (x) 44

Source: I-Sec Research Clarity is required on the biddable tariff component for the new pipelines before we factor it in our target price.

• RoCE. GSPL has won three pipeline bids, but there is no clarity on financial parameters, the most prominent being the RoCE at which the bids were made. Since RoCE is a biddable component, any variation can significantly impact the expected valuation upside from these pipelines.

• Volume ramp-up schedule. For the new pipeline bids, this portion is biddable. While for existing pipelines or those authorised by the PNGRB, the utilisation moves in the following sequence annually – 60%, 70%, 80%, 90% and 100%, for bidding, this can be flexible with the fastest sequence to 100% winning the bid. Assuming a 30mmscmd capacity, a company which has bid 80% in the first year will have to start with an average volume of 24mmscmd in the first year. Assuming lack of clarity on any firm gas supplies post ’15, offering a high utilisation can be a major risk and can hamper the company’s actual project IRR.

• Capex. A lower capex assumed would translate into competitive tariffs, on which the outcome of the financial bid will be based. A major risk to this assumption is cost overrun due to delays or run-up in raw material costs.

Commercial viability of new pipelines assessable only after bid details are disclosed


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Chart 5: Proposed pipeline bids by GSPL

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Financial overview

Volume growth on track

We expect GSPL’s revenue growth to depend on its volume ramp-up in Gujarat. The company’s gas transmission volumes will likely touch 50mmscmd in FY13E as RIL’s production from KG-D6 ramps up along with incremental volumes from the Petronet LNG terminal. Based on the volume rise, we expect average transmission tariffs for GSPL to decline to Rs0.7/scm in FY13E from Rs0.8/scm at present. However, post FY13, GSPL’s revenue growth would depend on the commissioning of the recently bid cross-country pipelines and the ramp-up in domestic gas production.

We have assumed nil contribution from GSPL to the Gujarat Socio Economic Development Scheme (GSEDS), the tax scheme implemented by the Gujarat Government – PBT would have been eroded 30% if contribution was made to GSEDS (the Gujarat Government has made no clarifications on GSEDS). Also, as per industry sources, the Gujarat Government has informally withdrawn the order owing to the impact on the future IPOs proposed by the state entities, most prominent being the proposed issue of Gujarat State Petroleum Corporation (GSPC).

Table 4: Key financials and assumptions (Rs mn, year ending March 31)

FY10 FY11E FY12E FY13E Volumes (mmscmd) 32.59 37.39 42.15 50.39 Average tariffs (Rs/scm) 848.47 809.72 823.22 718.82 Average tariffs (Rs/mmscmd) 0.85 0.81 0.82 0.72 Revenues 9,920 11,049 12,319 12,859 YoY growth (%) 103.48 11.39 11.49 4.39 EBITDA 9,297 10,391 11,613 12,023 YoY growth (%) 118.79 11.77 11.75 3.53 EBITDA margin 93.73 94.05 94.27 93.50 PAT (adjusted) 4,110 5,617 6,249 6,897 YoY growth (%) 232.62 36.66 11.25 10.37 PAT margin 41.44 50.84 50.73 53.63


Debt raising to sustain RoEs

We expect GSPL’s leverage to decline to 0.3x levels in FY13E, which will provide good financial bandwidth to GSPL while funding its share of the capex for the three new cross-country pipelines (overall Rs180bn). The company is expected to fund these pipelines in a debt-to-equity ratio of 70:30. As the regulated tariffs are independent of the funding structure, we believe GSPL would be able to maintain its current RoE over the long-term.


FY10 FY11E FY12E FY13E RoCE (%) 7.68 17.38 19.11 18.18 RoNW (%) 29.62 31.01 26.71 23.53 D/E ratio (x) 0.90 0.81 0.51 0.29


Debt-to-equity of 0.3x in FY13E gives GSPL financial flexibility to fund capex for new pipelines


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Valuations attractive

Reinitiate with a BUY

At the current market price of Rs102, GSPL is attractively valued at FY13E P/E of 8x. Based on cash earnings too, the company is appealing at 6.4x FY13E CEPS. We value the company on DCF, which yields Rs130/share target price. At this target price, GSPL would trade at a comfortable 8.2x FY13E cash earnings. As the dynamics of the domestic midstream gas industry is changing with regulations and as significant supplies commence from the east coast, we believe GSPL is one of the most aggressive growth plays in this space. Reinitiate with a BUY.

Table 6: DCF valuations (Rs mn)

PV of FCF to FY24E 56,763 Terminal value 112,909 PV of terminal value 27,490 EV 84,253 Less: Net debt 11,407 Value for shareholders 72,846 Number of shares (mn) 562.1 GSPL – Value for extant business (Rs/share) 130


Table 7: Sensitivity of DCF value (Rs/share)

WACC (%) Terminal growth (%) 10.50 11 11.48 12 12.50

1 118 112 106 101 96 2 132 124 117 110 104 3 148 138 130 121 114 4 169 157 146 136 127 5 199 181 167 154 143


DCF – Key assumptions

• Average volumes at 53mmscmd beyond FY13E

• Average tariffs to decline to Rs0.7/scm from FY13E

• WACC at 11.5% and terminal growth at 3%

• Capex assumed only for infrastructure which is being implemented at present

• No capex or revenue contribution factored in from the recently bid pipelines


• Delay in ramp-up D6 production could lower transmission volumes, thereby affecting the total tariff.

• Delay in resolution of the litigation on formally announcing the winners of the three trunk pipeline bids can escalate project cost.

• Cost escalation in GSPL’s trunk pipeline network could affect the IRR of the project.

We recommend GSPL as one of the most aggressive plays in the oil & gas sector


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Annexure 1: Financials (standalone)Table 8: Profit & Loss statement (Rs mn, year ending March 31)

FY09 FY10 FY11E FY12E FY13E Total Operating Income 4,875 9,920 11,049 12,319 12,859 Less:

Employee cost 109 99 122 153 176 Gas transportation cost 36 4 3 3 2 Connectivity charges 91 - - - - Admin & other expense 390 519 533 551 659

Total Operating Expenses 626 622 658 706 836 EBITDA 4,249 9,297 10,391 11,613 12,023 EBIDTA Margin (%) 87.2 93.7 94.0 94.3 93.5 Depreciation & Amortisation 1,705 2,365 1,258 1,558 1,730 Other Income 243 247 189 361 581 EBIT 2,788 7,180 9,322 10,415 10,874 Less: Gross Interest 870 938 1,257 1,447 1,210 Recurring Pre-tax Income 1,918 6,241 8,064 8,969 9,665 Add: Extraordinary Income - 27 - - - Less: Extraordinary Expenses 2 - - - Less: Taxation CSR tax - - - - --Current Tax 537 1,870 2,081 2,306 2,359 --Deferred Tax 145 261 338 376 405 Net Income (Reported) 1,234 4,137 5,646 6,287 6,901 Recurring Net Income 1,236 4,110 5,646 6,287 6,901



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FY09 FY10 FY11E FY12E FY13E ASSETS Current Assets, Loans & Advances Cash & Bank balance 975 1,742 2,037 5,989 8,536 Inventory 926 1,327 1,493 1,664 1,737 Sundry Debtors 544 753 929 1,036 1,082 Loans and Advances 3018 3600 4571 3408 1796 Operational 3,018 3,600 4,571 3,408 1,796 Other Current Assets 153 129 129 129 129 Total Current Assets 5,615 7,549 9,158 12,226 13,280 Current Liabilities & Provisions Current Liabilities Sundry Creditors 3,700 4,765 4,905 3,781 2,890 Other Current Liabilities 42 83 87 92 96 Provisions 1,590 3,486 3,486 3,486 3,486 Tax 2,794 Dividend 656 Others 36 Total Current Liabilities and Provisions 5,331 8,334 8,478 7,358 6,472 Net Current Assets 284 (785) 681 4,868 6,809 Investments Strategic & Group Investments 356 666 666 666 666 Total Investments 356 666 666 666 666 Fixed Assets Gross Block 24,212 33,255 43,014 51,438 53,383 Less Accumulated Depreciation 6,526 8,887 10,146 11,704 13,434 Net Block 17,686 24,368 32,869 39,734 39,949 Add: Capital Work in Progress 6,446 5,387 6,993 430 514 Less: Revaluation Reserve Total Fixed Assets 24,132 29,755 39,862 40,164 40,463 Total Assets 24,772 29,635 41,209 45,698 47,938 LIABILITIES AND SHAREHOLDERS' EQUITY Borrowings Short Term Debt 430 30 - - - Long Term Debt 11,079 12,565 18,839 17,324 12,916 Total Borrowings 11,509 12,595 18,839 17,324 12,916 Deferred Tax Liability 1,144 1,405 1,743 2,119 2,523 Share Capital Paid up Equity Share Capital 5,621 5,624 5,624 5,624 5,624 No. of Shares outstanding (mn) 562 562 562 562 562 Face Value per share (Rs) 10 10 10 10 10 Reserves & Surplus Share Premium 4,009 4,011 4,011 4,011 4,011 General & Other Reserve 2,521 6,003 10,991 16,620 22,863 Less: Misc. Exp. not written off 33 3 - - - Net Worth 12,119 15,635 20,626 26,255 32,498 Total Liabilities & Shareholders' Equity 24,772 29,636 41,209 45,698 47,938



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FY09 FY10 FY11E FY12E FY13ECash Flow from Operating Activities Reported Net Income 1,234 4,137 5,646 6,287 6,901Add: Depreciation & Amortisation 1,706 2,362 1,258 1,558 1,730 Provisions

Taxes 145 261 338 376 405Less: Other Income 243 247 189 361 581 Net Extra-ordinary income (2) 27 - - -Op Cash Flow before Working Capital change (a) 2,844 6,486 7,053 7,860 8,454 Changes in Working Capital (Increase) / Decrease in Inventories (529) (401) (166) (172) (73)(Increase) / Decrease in Sundry Debtors (127) (209) (177) (107) (45)(Increase) / Decrease in Operational Loans & Adv. (1,138) (581) (971) 1,162 1,612(Increase) / Decrease in Other Current Assets 81 24 - - -Increase / (Decrease) in Sundry Creditors (394) 1,065 139 (1,124) (891)Increase / (Decrease) in Other Current Liabilities 619 1,937 4 4 5Working Capital Inflow / (Outflow) (b) (1,488) 1,836 (1,170) (236) 607 Net Cash flow from Operating Activities (a) + (b) 1,356 8,322 5,883 7,624 9,061 Cash Flow before Capital commitments Purchase of Fixed Assets (4,579) (7,984) (11,366) (1,860) (2,029)Purchase of Investments (0) (310) - - -Consideration paid for acquisition of undertaking Cash Inflow/(outflow) from capital commitments (c) (4,579) (8,294) (11,366) (1,860) (2,029) Free Cash flow after capital commitments (3,223) 28 (5,483) 5,764 7,032(a) + (b) + (c) Cash Flow from Investing Activities Other Income 243 247 189 361 581 Net Cash flow from Investing Activities (d) 243 247 189 361 581 Cash Flow from Financing Activities Proceeds from equity issue 2 5 - - -Proceeds from fresh borrowings 1,849 1,086 6,244 (1,515) (4,408)Dividend paid including tax (493) (658) (658) (658) (658)Other items 31 32 3 0 (0)Net Cash flow from Financing Activities (e) 1,388 465 5,589 (2,173) (5,066) Net Extra-ordinary Income (f) (2) 27 - - - Total Increase / (Decrease) in Cash (1,594) 767 295 3,952 2,547(a) + (b) + (c) + (d) + (e) + (f) Opening Cash and Bank balance 2,569 975 1,742 2,037 5,989Closing Cash and Bank balance 975 1,742 2,037 5,989 8,536Increase/(Decrease) in Cash and Bank balance (1,595) 767 295 3,952 2,547



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FY09 FY10 FY11E FY12E FY13EPer Share Data (Rs) Diluted Rec. Earning per share (DEPS) 2.2 7.3 10.0 11.2 12.7 Diluted Earnings per share 2.2 7.3 10.0 11.2 12.7 Recurring Cash Earnings per share (CEPS) 5.2 11.5 12.3 13.9 15.9 Free Cashflow per share (FCPS-post capex) (5.7) 0.0 (9.7) 10.2 13.0 Reported Book Value (BV) 21.6 27.8 36.7 46.7 59.9 Adjusted Book Value (ABV) 28.6 37.4 46.4 56.5 70.3 Dividend per share 0.7 1.0 1.0 1.0 1.0

Valuation Ratios (x) Diluted Price Earning Ratio 46.3 13.9 10.1 9.1 8.0 Price to Recurring EPS 19.5 8.8 8.3 7.3 6.4 Price to Book Value 4.7 3.7 2.8 2.2 1.7 Price to Adjusted Book Value 3.6 2.7 2.2 1.8 1.4 Price to Sales Ratio 11.74 5.77 5.18 4.65 4.45 EV / EBITDA 15.9 7.3 7.1 5.9 5.1 EV / Total Operating Income 13.9 6.9 6.7 5.6 4.8 EV / Op Free Cash Flow (Pre-Capex) 50.0 8.2 12.6 9.0 6.8 EV / Net Operating FCF (Post-Capex) (21.0) 2,454.6 (13.5) 11.9 8.8 Dividend Yield (%) 0.7 1.0 1.0 1.0 1.0 Growth Ratios (% YoY) Diluted Recurring EPS Growth 21.1 232.4 37.4 11.4 13.9 Diluted Recurring CEPS Growth 10.8 120.1 6.6 13.6 14.1 Total Operating Income Growth 16.7 103.5 11.4 11.5 4.4 EBITDA Growth 16.6 118.8 11.8 11.8 3.5 Recurring Net Income Growth 21.1 232.6 37.4 11.4 9.8 Operating Ratios (%) EBITDA Margins 87.2 93.7 94.0 94.3 93.5 EBIT Margins 57.2 72.4 84.4 84.5 84.6 Recurring Pre-tax Income Margins 39.3 62.9 73.0 72.8 75.2 Recurring Net Income Margins 25.3 41.4 51.1 51.0 53.7 SGA Expenses / Sales 8.0 5.2 4.8 4.5 5.1 Other Income / Pre-tax Income 12.7 4.0 2.3 4.0 6.0 Effective Tax Rate 35.6 34.1 30.0 29.9 28.6 Return / Profitability Ratios (%) Return on Capital Employed (RoCE)-Overall 7.7 17.4 18.4 16.8 16.6 Return on Invested Capital (RoIC) 7.6 17.7 19.1 17.9 18.6 Return on Net Worth (RoNW) 10.5 29.6 31.1 26.8 23.5 Dividend Payout Ratio 34.2 13.6 10.0 8.9 8.2 Normalised RoCE (as per PNGRB) 9.3 20.4 23.8 20.4 19.1 Solvency Ratios / Liquidity Ratios (%) Debt Equity Ratio (D/E) 104.4 89.5 99.8 74.1 47.5 Long Term Debt / Total Debt 87.6 89.7 91.5 89.1 83.7 Net Working Capital / Total Assets (2.8) (8.5) (3.3) (2.5) (3.6) Interest Coverage Ratio-based on EBIT (x) 3.2 7.7 7.4 7.2 9.0 Debt Servicing Capacity Ratio (DSCR) (x) 4.0 7.6 6.2 6.1 7.8 Current Ratio (x) 1.0 0.9 1.1 1.7 2.1 Cash and cash equivalents / Total Assets 3.9 5.9 4.9 13.1 17.8 Turnover Ratios Assets Turnover Ratio (x) 0.2 0.4 0.3 0.3 0.3 Working Capital Cycle (days) (107.4) (59.2) (64.1) (36.7) (40.4) Average Collection Period (days) 35.9 23.8 27.8 29.1 30.1 Average Payment Period (days) 145.9 77.9 79.9 64.3 47.3



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Tables Table 1: Upcoming gas-based power plants in Gujarat....................................................123 Table 2: Domestic demand-supply ...................................................................................125 Table 3: Valuations for new pipelines ...............................................................................127 Table 4: Key financials and assumptions .........................................................................129 Table 5: Key ratios ............................................................................................................129 Table 6: DCF valuations ...................................................................................................130 Table 7: Sensitivity of DCF value......................................................................................130 Table 8: Profit & Loss statement.......................................................................................132 Table 9: Balance sheet .....................................................................................................133 Table 10: Cashflow statement ..........................................................................................134 Table 11: Key ratios ..........................................................................................................135

Charts Chart 1: Gas demand source in Gujarat ...........................................................................123 Chart 2: Supply source in Gujarat.....................................................................................123 Chart 3: GSPL’s network in Gujarat..................................................................................124 Chart 4: Gas, most competitive versus other alternate fuels............................................125 Chart 5: Proposed pipeline bids by GSPL ........................................................................128 Chart 6: Rolling Price/EPS trend.......................................................................................131 Chart 7: Rolling PBV trend................................................................................................131 Chart 8: Rolling EV/EBITDA trend ....................................................................................131

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Market Cap Rs93.9bn/US$2.1bn Year to Mar FY10 FY11E FY12E FY13EReuters/Bloomberg PLNG.BO/PLNG IN Revenue (Rs bn) 106,491 130,827 167,288 215,760Shares Outstanding (mn) 750 Net Income (Rs bn) 4,045 6,024 6,212 6,57052-week Range (Rs) 132/77 EPS (Rs) 5.4 8.0 8.3 8.8Free Float (%) 50.0 % Chg YoY (22.0) 48.9 3.1 5.8FII (%) 10.8 P/E (x) 23.2 15.6 15.1 14.3Daily Volume (US$/'000) 6,639 CEPS (Rs) 8.3 11.6 13.3 15.1Absolute Return 3m (%) (0.1) EV/E (x) 13.2 9.9 9.8 7.5Absolute Return 12m (%) 56.1 Dividend Yield (%) 1.4 1.6 1.7 1.7Sensex Return 3m (%) (5.6) RoCE (%) 11.0 12.2 10.1 10.9Sensex Return 12m (%) 8.3 RoE (%) 19.2 24.6 21.6 19.8

Petronet LNG HOLD

Positives in the price Rs125Reason for report: Initiating coverage



Target price Rs116


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Petronet LNG, with ONGC, GAIL, Bharat Petroleum Corporation (BPCL) andIndian Oil Corporation (IOC) holding 12.5% each in it, operates India’s largestregasification terminal at Dahej, Gujarat. Its business model is led by regas margins from long-term gas contracts and additional marketing margin fromterm/spot contracts. Petronet’s profitability has surged on further spot LNGvolumes, which will likely make up for the recent dip in KG D6 volumes. In our view, this is a short-term upside, while in the long term as domestic supplies risePetronet’s earnings will mostly be led by long-term LNG contracts. Based on our analysis, Petronet’s current valuations capture most positives (volume & margin upside). Recommend HOLD with a DCF target price of Rs116. Current surge in profitability unsustainable. Petronet has always benefited from

the demand-supply gap in natural gas, bridging it from high-margin LNG spot volume and term contracts. The dip in gas production from KG-D6 has been a sweetener for Petronet (KG-D6 gas is preferred due to cost advantage and long-term availability), triggering a shift to spot LNG volume. With the current gas demand-supply gap favourable, Petronet should continue to import spot volumes, at least till D6 volumes ramp up to 87mmscmd. RoE should dip to ~20% by FY13E from 25% in FY11.

Kochi terminal, a concern. Petronet is setting up a greenfield LNG regasification capacity of 5mmtpa at Kochi (to start by December ’12). The feasibility of 1.4mmtpa LNG supply contract with Gorgon for the terminal is a worry as the delivered gaswould cost ~US$12-14/mmbtu. This is unviable for its anchor customer, NTPC’sKayamkulam power plant. The power sector has preferred low-cost domestic gas production and the viability of any incremental LNG regasification capacity would be threatened by a sharp rise in domestic gas supply. As Petronet is incurring Rs40bncapex for the terminal, the viability of the project is crucial to Petronet’s valuations.

Long-term LNG pricing decisive. LNG would help bridge the demand-supply gap in the domestic gas industry, but as incremental demand is power sector led, price is a concern. Long-term LNG contracts, at a lower cost, would aid high utilisation. Led by excess LNG capacity of 25-30mmtpa globally in the next three years, Petronet should be able to tie up long-term supply and maintain >80% utilisation.

Fairly valued; initiate with HOLD. At the current market price, the stock trades at 14.3x FY13E EPS. We value Petronet on DCF at Rs116/share. The planned diversification into gas-based power business at Dahej and Kochi is a key valuationtrigger. However, we are skeptical on the competitiveness of LNG import-based power plants vis-à-vis coal.

Petronet LNG, April 4, 2011 ICICI Securities

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TABLE OF CONTENTS Profitability unsustainable ..........................................................................................139

Business model low risk, sans marketing margin component ....................................139 Surge in profitability from spot volumes, but not sustainable......................................140

Kochi contract, a concern...........................................................................................141 Long-term LNG pricing decisive ................................................................................142 Financials & valuations ...............................................................................................144

Earnings to trace volume growth ................................................................................144 Fairly valued; initiate with HOLD.................................................................................144 Key risks to our call .....................................................................................................145

Annexure 1: Financials (standalone) .........................................................................147 Annexure 2: Index of Tables and Charts ...................................................................151


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Profitability unsustainable

Business model low risk, sans marketing margin component

Petronet has contracted 7.5mmtpa LNG volumes over the long-term (25-year contract) from Rasgas of Qatar, which is backed by a similar sales arrangement (with a take-or-pay clause) with three of its four promoters – GAIL, IOC and BPCL – in the ratio of 60:30:10. The company’s gross operating income is derived from regasification charge (Rs33.5/mmbtu at present) for these volumes. These margins are built as a mark-up over the cost of LNG for calculating revenues, along with other central and state taxes. Petronet therefore operates a low-risk business model as far as these contracted volumes are concerned, with extremely limited exposure change in associated gas price and forex risks, as the overall cost for procuring these LNG volumes (including shipping charges) is passed on to the offtakers.

However, from January ’09, Petronet’s gas purchase cost from Rasgas is being revised monthly until December ’13 and would then be aligned to prevailing crude prices. As per estimates, the LNG price from Rasgas for Petronet would increase to ~US$12/mmbtu by ’13E at an average JCC crude price of US$100/bl. In terms of the contract signed between Petronet and Rasgas, the LNG price formula is monthly LNG FOB price = 1.90/15 * JCC.

The JCC price would be the average of the preceding 12 months, excluding the last three months and including the pricing month. This price is subject to a floating ceiling and floor price linked to a JCC price. The price for the period commencing from January 1, ’09, shall be subject to a floating cap and ceiling, defined as follows:

(60-N) * 20 + (N*A60) Floating cap = ------------------------------------ + 4 60 (60-N) * 20 + (N*A60) Floating floor = ------------------------------------ - 4 60

Where N = 1 for January ’09, increasing by 1 each month until it reaches 60 in December ’13, up to the end of the term of this agreement. A60 is the arithmetic average of JCC over the period of sixty months. As these volumes are backed by a purchase agreement with the offtakers, we do not see any major risk to volumes.

Petronet insulated from increase in LNG price for long-term contracts


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Chart 1: Petronet – Business model

Source: Company

Surge in profitability from spot volumes, but not sustainable

Spot volumes strongly boost Petronet’s profitability as in addition to the regas margin, Rs5-10/mmbtu marketing margins kick in, which contribute to the bottomline. Petronet has traditionally benefited from the demand-supply gap in natural gas by bridging it through high-margin LNG spot volumes and term contracts. The company started procuring spot volumes from ’07, led by a sudden pick-up in gas demand from industrial consumers in Gujarat. This led to almost full utilisation of its then debottlenecked capacity of 6.5mmtpa, leading to 27-32% RoE during FY07-09.

Table 1: RIL’s gas production from KG-D6 Basin changing the dynamics FY06 FY07 FY08 FY09 FY10 FY11E FY12E FY13E

Return/Profitability Ratio (%) RoCE 13.5 14.4 17.0 14.7 11.0 12.2 10.1 10.9 RoIC 24.4 27.4 30.5 25.8 19.7 22.6 19.7 22.1 RoNW 20.0 26.7 32.8 28.8 19.2 24.6 21.6 19.8

Source: I-Sec Research We see a similar situation developing in FY11 as Petronet has capitalised on the drop in KG D6 volumes to garner spot volumes. The company’s RoE will likely rise again to 25% levels in FY11E. However, as volumes from RIL’s KG-D6 and other domestic blocks expand over FY12-13, RoEs will gradually drop to stabilise at 20% in the long term. The ramp-up in gas production from the KG-D6 Basin had affected Petronet’s spot volumes (gas produced from the KG-D6 Basin is preferred due its cost advantage and long-term availability) in FY10, leading to a sudden drop in RoE. Therefore, it is likely that Petronet’s spot volumes will sharply reduce in the next two years.

RoE will dip to 20% by FY13E as spot volumes decline


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Kochi contract, a concern Petronet is setting up a 5mmtpa greenfield capacity at Kochi, to be commissioned by December ’12, at an overall capex of Rs32bn. Through a provision, the capacity can be raised to 5mmtpa at an additional capex of Rs4bn. The LNG terminal will be connected to GAIL’s Kochi-Mangalore-Bangalore pipeline to service consumers in Mangalore. GAIL would also build a 100Kms underwater pipeline to connect the terminal with NTPC’s upcoming 1,100MW Kayamkulam power plant.

Petronet has entered into a 1.5mmtpa LNG import contract with Exxon Mobil’s Gorgon project, starting ’14. The contract would be based on similar lines as the Rasgas contract as far as volume offtake is concerned – the offtake ratio will be slightly different (40:30:30 for GAIL: BPCL: IOC). However, we are concerned over the feasibility of the contract as the expected gas cost reportedly is at ~US$14-16/mmbtu at an average crude price of US$100/bl. The price is definitely unviable for power plants as its anchor customer, NTPC’s Kayamkulam power plant, is finding it difficult to enter into a PPA with any state electricity board (SEB) in the South.

The power sector will always prefer low-cost domestic gas production; hence, the viability of any incremental LNG regasification capacity would be threatened by any sharp rise in domestic gas supply. As Petronet is incurring Rs40bn capex on this terminal, the viability of the project is of importance to Petronet so as to sustain its valuations. With ~100mmscmd incremental domestic gas production likely (primarily from east coast) over the next 5-10 years, we are skeptical over volume saleability from the Kochi terminal.

Chart 2: Gas pricing – Kochi contract rate more than current spot rate

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Long-term LNG pricing decisive LNG would continue to be a key source for bridging the demand-supply gap in the domestic gas industry. However, since incremental demand is led by the power sector, pricing will be a key issue in the sector. Hence, long-term LNG contracts, at a lower cost, are crucial to sustain high utilisation.

Surplus LNG capacity of 25-30mmtpa would be available globally in the next three years (Table 2). This offers a good opportunity for Petronet to tie up long-term supplies and maintain >80% utilisation at its terminals. However, since most of the LNG contracts are linked to crude price, gas pricing for these contracts would be a major deterrent for Petronet to enter into long-term contracts.

Table 2: Global LNG demand-supply (bcm)

Region 2010 2011 2012 2013 2014 2015 2020 2025 Liquefaction Capacity Asia Pacific 84.2 90.4 90.2 88.7 90.7 104.6 115.3 92.1 Europe 4.1 4.1 4.1 4.1 4.1 4.1 4.1 4.1 Middle East 76.9 94.5 98.1 98.1 98.1 98.3 98.3 98.3 North Africa 31.3 31.3 31.9 35 36.4 41.4 42.8 42.8 North America 0.8 0.2 - - - - - - South America 16.2 18.7 19.4 19.4 19.4 19.4 16.2 9.4 West Africa 21.7 23.8 25 27.9 30.1 30.3 29.7 24.6 Total: 235.2 263 268.6 273.2 278.7 298.1 306.3 271.2 LNG Demand Asia Pacific 122.1 132.2 141.9 145.9 156.3 168.1 186.6 227.5 Europe 60.4 69.4 71.2 72.2 75.3 81.1 148.1 169 North America 34.6 44.8 43.6 39.3 26.9 26 20.7 17.3 South & East Africa - - - 0.3 0.3 0.3 0.4 0.4 South America 3.2 4 4.2 4.2 4.3 4.4 5.5 5.9 Total: 220.2 250.4 260.9 261.8 263.2 279.9 361.3 420.2 Surplus/Deficit 15 12.6 7.7 11.4 15.5 18.2 -55 -149

Source: Wood Mackenzie At present, India is the sixth largest LNG importing nation after Japan, South Korea and Spain. India primarily competes against Japan and South Korea for most LNG contracts. Both Japan and South Korea can absorb high LNG prices as the gas consumption in these countries is more to meet the peak power demand (mostly an alternative to nuclear power) and industry demand. On the other hand, the gas demand from the Indian power sector is highly sensitive to price since domestic power tariffs are predominantly derived from low-cost, coal-based plants. Hence, pricing is a major constraint for Petronet to enter into long-term contracts.

Hence, if crude price continues to sustain at >US$100/bl, Petronet’s long-term utilisation at its terminals, especially Kochi, will be exposed to risk. Rasgas contract signed by Petronet for its Dahej terminal was a one-off in the LNG industry and current contracts are based on 14-16% linkage to crude, mostly without a floor or a cap.

Difficult to see the economics behind substituting coal with LNG in power sector

Challenge would be pricing rather than sourcing


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Table 3: LNG importing nations 2005 2006 2007 2008 2009

North America Imports

(bcm) % of total

Imports (bcm)

% of total

Imports (bcm)

% of total

Imports (bcm)

% of total

Imports (bcm)

% of total

US 17.87 9.46 16.56 7.85 21.82 9.64 9.94 4.39 12.80 5.27 Canada - - - - - - 3.61 1.59 0.98 0.40 Mexico - - 0.94 0.45 2.17 0.96 0.00 3.55 1.46 S. & Cent. America Argentina - - - - 0.41 0.18 0.96 0.39 Brazil - - - - - - - 0.35 0.14 Chile - - - - - - - 0.65 0.27 Dominican Republic 0.25 0.13 0.25 0.12 0.36 0.16 0.47 0.21 0.56 0.23 Puerto Rico 0.67 0.35 0.72 0.34 0.74 0.33 0.81 0.36 0.76 0.31 Europe Belgium 2.98 1.58 4.28 2.03 3.17 1.40 2.49 1.10 6.53 2.69 France 12.83 6.80 13.88 6.58 12.97 5.73 12.59 5.56 13.07 5.38 Greece 0.46 0.24 0.49 0.23 0.81 0.36 0.94 0.41 0.74 0.31 Italy 2.50 1.32 3.10 1.47 2.43 1.07 1.56 0.69 2.90 1.19 Portugal 1.58 0.84 1.97 0.93 2.31 1.02 2.63 1.16 2.82 1.16 Spain 21.85 11.57 24.42 11.57 24.18 10.68 28.73 12.68 27.01 11.12 Turkey 4.88 2.58 5.72 2.71 6.01 2.65 5.31 2.34 5.71 2.35 United Kingdom 0.52 0.28 3.56 1.69 1.46 0.64 1.04 0.46 10.24 4.22 Middle East Kuwait - - - - - - - - 0.89 0.37 Asia Pacific China 0.00 1.00 0.47 3.87 1.71 4.44 1.96 7.63 3.14 India 6.04 3.20 7.99 3.79 9.98 4.41 10.79 4.76 12.62 5.20 Japan 76.32 40.42 81.86 38.78 88.82 39.23 92.13 40.67 85.90 35.38 South Korea 30.45 16.13 34.14 16.17 34.39 15.19 36.55 16.14 34.33 14.14 Taiwan 9.61 5.09 10.20 4.83 10.92 4.82 12.07 5.33 11.79 4.86 Total 188.81 211.08 226.41 226.51 242.77

Source: BP Statistical Review 2010


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Financials & valuations

Earnings to trace volume growth

Petronet’s business model highly depends on volumes contracted in the long term and regas tariffs. The company’s current earnings will likely be volatile as there could be significant variance in marketing margins on spot volumes.

We expect Petronet to raise regas tariffs 5% every year in the long term, as per its contractual agreement with offtakers, GAIL, IOC and BPCL. We expect the company to start generating volumes from Kochi from Q4FY13, with regas tariffs at Rs70/mmbtu. However, it will likely be difficult to implement these regas tariffs at Kochi, considering the high cost of contracted volumes.

We believe that in the long-term, Petronet’s earnings model would be primarily driven by LNG volumes and re-gas margins, as marketing margins are non-sustainable due to increasing cost of LNG. We have, although, assumed utilisation to be stable at 80% post FY15E for both Dahej & Kochi terminals (which would be the best case for the company considering high prices for incremental LNG volumes).

Table 4: Volume snapshot & assumptions TBTU FY10 FY11E FY12E FY13E Long-term contracts 299 385 411 411 % tot 75.4 87.7 87.0 83.3 Spot volumes 98 54 62 82 % tot 24.6 12.3 13.0 16.7 Total 397 439 473 493 % growth 23.5 10.7 7.6 4.3


Fairly valued; initiate with HOLD

At the current market price, the stock trades at 14.3x FY13E EPS. We value Petronet on DCF at Rs116/share. The planned diversification into gas-based power business at Dahej and Kochi could offer some valuation trigger. However, we are skeptical on the competitiveness of LNG import-based power plants vis-à-vis coal.

Key assumptions • Long-term utilisation at Dahej and Kochi at 80%

• WACC at 13.4%

• Starting regas tariff for Kochi at Rs70/mmbtu

Table 5: DCF valuations (Rs mn) Particulars Rsmn PV of FCFF during the explicit forecast period 71,515 Net debt (14,421) Solid cargo 900 Overall value 86,836 No of shares (mn) 750.0 Value per share 116 Source: I-Sec Research

DCF valuation of Rs116/share indicates that Petronet is fairly valued at the current levels


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Higher-than-expected increase in domestic gas production Petronet’s profitability has already been hit due to increased domestic gas production. More-than-expected increase in production from the prospective discoveries of RIL and ONGC on the East Coast can threaten the feasibility of its long-term contracted gas volumes. Although the company has >20 years of offtake agreement for contracted volumes at both Dahej and Kochi terminals, the inability of its offtakers to sell these volumes due to abundant domestic gas can threaten Petronet’s regas tariffs (higher probability in case of the Kochi terminal).

Regulations At present, regasification tariffs charged by Petronet are not being regulated by the Petroleum and Natural Gas Regulatory Board (PNGRB). However, the PNGRB is evaluating a proposal to regulate regas tariffs, on similar lines as the transmission tariffs. This can lead to a possible decline in its tariffs.

Higher-than-expected domestic gas production from RIL and ONGC could impact Petronet’s profitability


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Annexure 1: Financials (standalone)Table 6: Profit & Loss statement (Rs mn, year ending March 31)

FY09 FY10 FY11E FY12E FY13E Net Sales 84,287 106,491 130,827 167,288 215,760 Total Operating Income 84,287 106,491 130,827 167,288 215,760 Less:

Raw Material 73,756 96,648 117,243 152,344 196,893 Staff Cost 196 204 245 294 530 Power, utilities and chemicals 375 480 576 651 739 Insurance & other variable costs 364 451 531 588 668 Other expenses 583 244 268 281 322

Total Operating Expenses 75,274 98,026 118,862 154,158 199,151 EBITDA 9,013 8,465 11,965 13,130 16,609 EBIDTA Margin (%) 10.7 7.9 9.1 7.8 7.7 Depreciation & Amortisation 1,025 1,609 1,858 2,906 3,954 Other Income 765 978 808 1,345 1,481 EBIT 8,753 7,834 10,914 11,569 14,136 Less: Gross Interest 1,012 1,839 1,990 2,365 4,402 Recurring Pre-tax Income 7,740 5,995 8,924 9,203 9,734 Less: Taxation 2,556 1,950 2,900 2,991 3,163 --Current Tax 2,526 1,410 2,099 2,165 2,358 --Deferred Tax 30 540 801 826 805 Net Income (Reported) 5,184 4,045 6,024 6,212 6,570 Recurring Net Income 5,184 4,045 6,024 6,212 6,570



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FY09 FY10 FY11E FY12E FY13E ASSETS Current Assets, Loans & Advances Cash & Bank balance 6,578 3,405 11,255 10,211 14,289 Inventory 3,856 2,223 2,187 2,605 4,633 Sundry Debtors 6,712 5,035 6,133 7,839 10,118 Loans and Advances Operational 783 1,523 1,855 2,371 3,060 Other Current Assets 168 31 31 31 31 Total Current Assets 18,097 12,216 21,461 23,056 32,131 Current Liabilities & Provisions Current Liabilities Sundry Creditors 5,715 6,043 4,248 5,129 6,870 Other Current Liabilities 1,650 1,406 1,705 2,211 2,857 Provisions 1,557 1,557 1,557 1,557 1,557 Total Current Liabilities and Provisions 8,922 9,006 7,509 8,897 11,283 Net Current Assets 9,175 3,211 13,952 14,158 20,848 Investments Other Marketable Investments 2722 4210 4210 4210 4210 Strategic & Group Investments 321 1,176 1,176 1,513 1,986 Total Investments 3,043 5,386 5,386 5,724 6,196 Fixed Assets Gross Block 19,748 35,495 36,035 75,840 76,380 Less Accumulated Depreciation 5,062 6,667 8,525 11,431 15,385 Net Block 14,686 28,829 27,511 64,410 60,996 Add: Capital Work in Progress 18,470 13,184 23,314 458 2,332 Less: Revaluation Reserve Total Fixed Assets 33,156 42,012 50,824 64,868 63,328 Total Assets 45,373 50,609 70,163 84,750 90,372 Liabilities & Shareholders’ Equity Borrowings Long Term Debt 22,817 24,998 39,520 48,919 49,087 Total Borrowings 22,817 24,998 39,520 48,919 49,087 Deferred Tax Liability 2,722 3,262 4,063 4,890 5,695 Share Capital Paid up Equity Share Capital 7,500 7,500 7,500 7,500 7,500 Reserves & Surplus Share Premium 1,555 1,555 1,555 1,555 1,555 General & Other Reserve 10,780 13,294 17,524 21,887 26,535 Net Worth 19,834 22,349 26,579 30,941 35,590 Total Liabilities & Shareholders’ Equity 45,373 50,609 70,163 84,750 90,372



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FY09 FY10 FY11E FY12E FY13ECash Flow from Operating Activities Reported Net Income 5,184 4,045 6,024 6,212 6,570Add: Depreciation & Amortisation 1,024 1,605 1,858 2,906 3,954 Deferred Taxes 30 540 801 826 805Less: Other Income 765 978 808 1,345 1,481Op.Cash Flow before Working Capital change (a) 5473 5211 7875 8600 9848 Changes in Working Capital (Increase) / Decrease in Inventories (2,946) 1,633 36 (418) (2,029)(Increase) / Decrease in Sundry Debtors (3,382) 1,677 (1,098) (1,705) (2,279)(Increase) / Decrease in Operational Loans & Adv. (143) (740) (332) (516) (689)(Increase) / Decrease in Other Current Assets (127) 138 - - -Increase / (Decrease) in Sundry Creditors 2,327 328 (1,795) 882 1,740Increase / (Decrease) in Other Current Liabilities 976 (244) 299 506 645Working Capital Inflow / (Outflow) (b) (3,295) 2,791 (2,891) (1,251) (2,611) Net Cash flow from Operating Activities (a) + (b) 2,178 8,002 4,984 7,349 7,237 Cash Flow from Capital commitments Purchase of Fixed Assets (7,887) (10,461) (10,670) (16,950) (2,414)Purchase of Investments 2,431 (2,344) - (338) (473)Consideration paid for acquisition of undertaking Cash Inflow/(outflow) from capital commitments (c) (5,456) (12,804) (10,670) (17,287) (2,887) Free Cash flow after capital commitments (3,278) (4,802) (5,686) (9,938) 4,350(a) + (b) + (c) Cash Flow from Investing Activities Other Income 765 978 808 1,345 1,481 Net Cash flow from Investing Activities (d) 765 978 808 1,345 1,481 Cash Flow from Financing Activities Proceeds from fresh borrowings 7,041 2,181 14,522 9,398 168Dividend paid including tax (1,536) (1,531) (1,794) (1,850) (1,922)Other items (0) (0) (0) 0 0Net Cash flow from Financing Activities (e) 5,505 651 12,729 7,549 (1,754) Total Increase / (Decrease) in Cash 2,992 (3,173) 7,850 (1,045) 4,078(a) + (b) + (c) + (d)+ (e) + (f) Opening Cash and Bank balance 3,586 6,578 3,405 11,255 10,211Closing Cash and Bank balance 6,578 3,405 11,255 10,211 14,289Increase/(Decrease) in Cash and Bank balance 2,992 (3,173) 7,850 (1,045) 4,078



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FY09 FY10 FY11E FY12E FY13EPer Share Data (Rs) Diluted Recurring Earning per share (DEPS) 6.9 5.4 8.0 8.3 8.8Diluted Earnings per share 6.9 5.4 8.0 8.3 8.8Recurring Cash Earnings per share (CEPS) 8.3 8.3 11.6 13.3 15.1Free Cashflow per share (FCPS-post capex) (4.4) (6.4) (7.6) (13.3) 5.8Reported Book Value (BV) 26.4 29.8 35.4 41.3 47.5Adjusted Book Value (ABV) ** 26.4 29.8 35.4 41.3 47.5Dividend per share 1.8 1.8 2.0 2.1 2.2

Valuation Ratios (x) Diluted Price Earning Ratio 18.1 23.2 15.6 15.1 14.3Price to Recurring Cash Earnings per share 15.1 15.2 10.8 9.4 8.3Price to Book Value 4.7 4.2 3.5 3.0 2.6Price to Adjusted Book Value 4.7 4.2 3.5 3.0 2.6Price to Sales Ratio 0.0 0.0 0.0 0.0 0.0EV / EBITDA 11.9 13.2 9.9 9.8 7.5EV / Total Operating Income 1.3 1.0 0.9 0.8 0.6EV / Operating Free Cash Flow (Pre-Capex) 49.3 13.9 23.7 17.5 17.2EV / Net Op. Free Cash Flow (Post-Capex) (32.8) (23.2) (20.8) (12.9) 28.6Dividend Yield (%) 1.4 1.4 1.6 1.7 1.7 Growth Ratios (% YoY) Diluted Recurring EPS Growth 9.2 (22.0) 48.9 3.1 5.8Diluted Recurring CEPS Growth 4.2 (0.7) 40.2 14.5 13.9Total Operating Income Growth 28.6 26.3 22.9 27.9 29.0EBITDA Growth 4.1 (6.1) 41.3 9.7 26.5Recurring Net Income Growth 9.2 (22.0) 48.9 3.1 5.8 Operating Ratios (%) EBITDA Margins 10.7 7.9 9.1 7.8 7.7EBIT Margins 10.4 7.4 8.3 6.9 6.6Recurring Pre-tax Income Margins 9.2 5.6 6.8 5.5 4.5Recurring Net Income Margins 6.2 3.8 4.6 3.7 3.0Raw Material Consumed / Sales 87.5 90.8 89.6 91.1 91.3 Other Income / Pre-tax Income 9.9 16.3 9.1 14.6 15.2Other Operating Income / EBITDA - - - - -Effective Tax Rate 33.0 32.5 32.5 32.5 32.5 Return / Profitability Ratios (%) Return on Capital Employed (RoCE)-Overall 14.7 11.0 12.2 10.1 10.9Return on Invested Capital (RoIC) 25.8 19.7 22.6 19.7 22.1Return on Net Worth (RoNW) 28.8 19.2 24.6 21.6 19.8Dividend Payout Ratio 25.3 32.4 25.4 25.4 25.0 Solvency Ratios / Liquidity Ratios (%) Debt Equity Ratio (D/E) 1.2 1.1 1.5 1.6 1.4Net Working Capital / Total Assets 5.7 (0.4) 3.8 4.7 7.3Interest Coverage Ratio-based on EBIT 8.6 4.3 5.5 4.9 3.2Current Ratio 2.0 1.4 2.9 2.6 2.8 Turnover Ratios Inventory Turnover Ratio (x) 31.0 31.9 53.3 63.7 54.6Assets Turnover Ratio (x) 2.1 2.2 2.2 2.2 2.5Working Capital Cycle (days) 26.1 21.2 23.9 30.7 29.6Average Collection Period (days) 21.7 20.1 15.6 15.2 15.2Average Payment Period (days) 22.5 22.2 16.0 11.2 11.1



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Tables Table 1: RIL’s gas production from KG-D6 Basin changing the dynamics.......................140 Table 2: Global LNG demand-supply ...............................................................................142 Table 3: LNG importing nations ........................................................................................143 Table 4: Volume snapshot & assumptions .......................................................................144 Table 5: DCF valuations ...................................................................................................144 Table 6: Profit & Loss statement.......................................................................................147 Table 7: Balance sheet .....................................................................................................148 Table 8: Cashflow statement ............................................................................................149 Table 9: Key ratios ............................................................................................................150

Charts Chart 1: Petronet – Business model .................................................................................140 Chart 2: Gas pricing – Kochi contract rate more than current spot rate ...........................141 Chart 3: Rolling Price/EPS trend.......................................................................................146 Chart 4: Rolling PBV trend................................................................................................146 Chart 5: Rolling EV/EBITDA trend ....................................................................................146


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Market Cap Rs219bn/US$4.9bn Year to March FY10 FY11E FY12E FY13EReuters/Bloomberg BPCL IN/BPCL IN Revenue (Rs mn) 1,238,167 1,582,589 1,809,775 1,814,905Shares Outstanding (mn) 361.54 Net Income (Rs mn) 17,387 15,971 8,572 9,94252-week Range (Rs) 840/488 EPS (Rs) 48.1 44.2 23.7 27.5Free Float (%) 45.1 % Chg YoY 167.8 (8.1) (46.3) 16.0FII (%) 7.6 P/E (x) 12.7 13.8 25.7 22.2Daily Volume (US$'000) 12,550 CEPS (Rs) 88.0 87.5 70.2 75.9Absolute Return 3m (%) (8.2) EV/E (x) 11.8 9.4 10.2 9.4Absolute Return 12m (%) 19.1 Dividend Yield 2.5 2.5 1.3 1.5Sensex Return 3m (%) (5.6) RoCE (%) 5.9 6.0 4.1 4.4Sensex Return 12m (%) 8.3 RoE (%) 12.7 10.9 5.6 6.2

Bharat Petroleum Corporation HOLD

Déjà vu Rs606Reason for report: Reinitiating coverage



Target price Rs562


Jun '10

Sep '10

Dec ’10

Promoters 54.9 54.9 54.9 Institutional investors

27.7 27.6 27.7

MFs and UTI 7.4 8.2 8.5 Insurance Company

0.1 0.1 0.2

FIIs 7.4 8.2 7.6 Others 17.4 17.4 17.4


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Bharat Petroleum Corporation (BPCL) is one of the largest integrated oil marketing companies (OMCs) in India, enjoying >21% share in the domesticmarket. It is commissioning a greenfield Bharat Oman Refinery (BORL) at Bina,which will raise its overall refining capacity to ~30mmtpa. BPCL has struck gold inthe E&P space with prolific oil & gas discoveries in Mozambique and Brazil,appraisals for which can yield strong, long-term valuation upside. However, under-recovery concerns override the positives as we estimate crude price to average at US$100/bl in the next two years. The Government’s inability toundertake subsidy reforms has hit BPCL’s profitability hard, threatening itsvaluation outlook. We reinitiate coverage on BPCL with HOLD (target price of Rs562/share, at 1.1x BV) since E&P triggers provide some respite in the long term.

Subsidy concerns override positives. The subsidy-sharing mechanism continuesto be uncertain for OMCs. BPCL is losing ~Rs10.5/litre on diesel, Rs4.25/litre on petrol, Rs21/litre on SKO and Rs290/cylinder on LPG. BPCL’s gross under-recovery is expected to be Rs165bn in FY11E based on the current crude price. BPCL’s net under-recovery share is expected at a lower~Rs28bn (will increase to Rs43bn inFY13E), given the likely compensation from the Government at Rs83bn and upstream assistance of Rs55bn. However, the precise contribution from the Government is still uncertain, which can hurt earnings going forward.

E&P to be a long-term trigger. BPCL’s E&P business is on a good wicket throughits stakes in prolific exploration blocks in Brazil & Mozambique. In the past three years, BPCL has made hydrocarbon discoveries in Brazil (Wahoo I-II) and significant gas finds in Mozambique (Windjammer, Lagosta, Bargentine & Tubaroa fields). These discoveries are in the appraisal stage, so limited information is available onthe reserve potential. However, as these discoveries are appraised and developed inthe next 3-5 years, significant long-term valuation triggers will come into play.

Commissioning of the Bina refinery, a positive. BPCL is expected to commission the 6mmtpa Bina refinery by April ’11. The refinery will likely boost BPCL’s marketingplans for the North and the North East, where it has limited presence. Though the overall refinery cost has slightly increased to Rs110bn, its high complexity of 9.1would ensure a premium of at least US$2-3/bl over Singapore Complex’s GRMs in the long term.

Bharat Petroleum Corporation, April 4, 2011 ICICI Securities

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TABLE OF CONTENT Subsidy concerns override positives ........................................................................155

Profitability under pressure .........................................................................................156 E&P upsides long-drawn.............................................................................................157

Encouraging discoveries in Mozambique ...................................................................157 High potential in Brazil ................................................................................................159

Bina refinery to bridge the refining-marketing gap..................................................160 Flexibility to process different qualities of crude .........................................................160 Fiscal incentives by the Madhya Pradesh government ..............................................161

Valuations – Positives factored in .............................................................................162 Key assumptions.........................................................................................................163 Key risks to our call .....................................................................................................163

Annexure 1: Financials (consolidated)......................................................................164 Annexure 2: Index of Tables and Charts ...................................................................168


155

Subsidy concerns override positives Brent crude price surging beyond US$100/bl is a déjà-vu for OMCs. Concerns on surging under-recoveries and ad-hoc compensation by the Government makes BPCL’s profitability event based rather than fundamental. Hence, valuations are volatile, both short term and long term.

At present, BPCL enjoys a comfortable refining-to-marketing ratio of ~1, which makes its marketing under-recoveries less volatile. BPCL is losing ~Rs10.5/litre on diesel, Rs4.25/litre on petrol (apparently de-regulated), Rs21/litre on SKO and Rs290/cylinder on LPG.

The overall under-recovery for BPCL is expected to be Rs165bn in FY11E based on the current crude price. BPCL’s share in subsidy sharing is expected at a lower ~Rs28bn, due to likely compensation from the Government at Rs83bn and upstream assistance of Rs55bn. However, the precise contribution from the Government is still uncertain, which can hurt BPCL’s earnings going forward.

Table 1: Surging under-recoveries (Rs mn)

FY08 FY09 FY10 FY11E FY12E FY13E Total Upstream 257,080 320,000 144,300 258,615 371,914 386,755 % total 33.3 31.0 31.3 33.3 33.3 33.3 Total Government 352,900 712,920 260,000 387,922 557,871 580,133 % total 45.8 69.0 56.5 50.0 50.0 50.0 Total Downstream 161,250 334 56,210 129,308 185,957 193,378 % total 20.9 - 12.2 16.7 16.7 16.7 Total Under Recoveries 771,230 1,032,920 460,510 775,844 1,115,741 1,160,266 Petrol 73,320 51,810 51,510 22,059 29,260 31,016 Diesel 351,660 522,860 92,790 321,047 599,396 635,360 Kerosene 191,020 282,250 173,640 186,671 223,076 221,960 LPG 155,230 176,000 142,570 246,067 264,009 271,930 Total 771,230 1,032,920 460,510 775,845 1,115,741 1,160,266

Source: Infraline, I-Sec Research Under-recoveries should hit the roof in FY12 – we expect Brent prices to average around US$100/bl. The Government’s inability to undertake any major price revision on subsidised products spiked under-recoveries as a whole to Rs1,111bn, crossing FY09 levels of Rs1,030bn. BPCL’s share is expected to be at a lower Rs41bn, given Rs122bn compensation by the Government and upstream assistance of Rs82bn.

Table 2: Under-recovery sharing (Rs mn)

FY09 FY10 FY11E FY12E FY13E IOC 149 23,784 74,700 107,158 111,692 % total 44.6 58.1 57.8 57.6 57.8 BPCL 96 8,540 27,608 40,802 42,557 % total 28.8 20.9 21.4 21.9 22.0 HPCL 89 8,602 26,999 37,997 39,129 % total 26.6 21.0 20.9 20.4 20.2 Total downstream 334 40,926 129,307 185,957 193,378 Upstream assistance ONGC 273,740 114,560 206,373 304,782 315,239 OIL 29,319 15,267 32,129 44,988 46,823 GAIL 16,937 13,854 19,170 22,143 24,694 Total 319,996 143,681 257,672 371,914 386,755



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Profitability under pressure

BPCL’s profitability is expected to take a hit from FY12E as RoEs decline to sub 6%, among the lowest for the company. This is almost a repeat of FY09, indicating that the company’s valuations can retest the low levels of FY09.

Table 3: Pressure on profitability (%)

FY09 FY10 FY11E FY12E FY13E Recurring net income margin 0.83 2.26 1.46 0.79 0.90 RoCE 6.16 5.93 5.99 4.06 4.40 RoNW 5.0 12.7 10.9 5.6 6.2

Source: I-Sec Research BPCL’s profitability in the next 2-3 years is a major concern as it is highly dependent on the Government’s subsidy sharing mechanism and product pricing policy.

We expect BPCL’s cashflows to witness pressure from FY12, led by higher-than-expected working capital requirement. The company would find it difficult to manage inventories, leading to pressure on short-term debt levels and interest payments.

Table 4: Pressure on cashflow (Rs mn)

FY09 FY10 FY11E FY12E FY13E Operating cashflow (140,133) (10,705) 16,435 17,002 20,238 Working capital changes 26,111 (39,399) 13,598 (25,445) (34,988) Capital commitments (57,902) (62,627) (38,612) (19,377) (15,000) Free cashflow (171,925) (112,731) (8,579) (27,820) (29,750)



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E&P upsides long-drawn BPCL has witnessed major successes in the E&P space through its stakes in prolific exploration blocks in Brazil and Mozambique. The company operates through its subsidiary, Bharat Petro Resources (BPRL) and has a 50:50 JV with Videocon Industries for investments in these blocks. In the past three years, the company has struck hydrocarbon discoveries in Brazil in Wahoo I-II and made significant gas finds in Mozambique at Windjammer, Lagosta and Bargentine fields. These discoveries are in the appraisal stage; hence, limited information is available on the reserve potential. However, as these discoveries are appraised and developed in the next 3-5 years, significant long-term valuation triggers will emerge.

Encouraging discoveries in Mozambique

In the Rovuma Basin in offshore Mozambique, BPCL has made four major discoveries – Windjammer, Barquentine, Lagosta and Tubarao. Anadarko is the operator with 36.5% working interest in Offshore Area 1. Co-owners of the block are Mitsui E&P Mozambique Area 1 (20%), BPRL Ventures Mozambique B.V. (10%), Videocon Mozambique Rovuma (10%) and Cove Energy Mozambique Rovuma Offshore (8.5%). Empresa Nacional de Hidrocarbonetos, ep’s 15% interest is carried through the exploration phase.

Windjammer was the first to hit a natural gas net feet pay of 550ft in February ’10, indicating the start of a major success in terms of exploration potential. The deepwater discovery lies at a depth of 14,000ft, 30 miles east of the Mozambique coastline. Barquentine was the next to follow in October ’10, hitting 416ft of natural gas pay. The Barquentine exploration well was drilled to a total depth of ~16,880ft, in a water depth of ~5,200ft.

The third major discovery in the block, at Lagosta was the largest providing 550ft net pay of natural gas. This discovery is located ~16miles to the south of the previously announced Barquentine discovery and 14miles to the southeast of the Windjammer discovery. Tubarao was the latest discovery to be announced, offering 110ft of net pay, the smallest of them all.

Though it is too early to ascertain the total size of the discoveries announced till the appraisal programme is completed, initial results indicate that this could be one of the largest natural discoveries globally, which augurs well for BPCL in the long term. However, as per our interaction with the industry, it would be difficult to assess the reserve potential based on the initial net feet pay, as the actual recovery of the reserves is critical to determine the precise commercially viable reserve.


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Chart 1: Mozambique discoveries

Four major discoveries

Lagosta - 550 Net Feet of Pay

Barquentine - 416 Net Feet of Pay

Windjammer - 555 Net Feet of Pay

Tubarão - 110 Net Feet of Pay

Planned activity in ’11

Dedicated Rig

Add Second Rig in Q4

Appraise Discoveries

Source: Anadarko Presentation We are positive over BPCL’s Mozambique prospects and there is a strong possibility of major reserve accretion from the block, which could be a huge trigger for valuations. The JV plans to drill further exploratory wells so as to estimate the reserve.

We conservatively factor in 30% chances of the Mozambique find to be of 20tcf size and ascribe a 50% recovery factor to this estimate. We value these reserves at US$4/bl and discount it to arrive at a fair value of Rs38/share.

Chart 2: Mozambique development plan

Source: Anadarko Presentation


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Table 5: Mozambique block valuation Initial estimate (tcf) 20 Gross recoverable reserves (mn bl) 1,080 BPCL stake (%) 10.00 BPCL share of recoverable reserves (mn bl) 108 Ev/bl 4.0 Value (US$ mn) 432 Value (Rs mn) 19,872 Present value 10,197 Value/share (Rs) 31

Source: I-Sec Research High potential in Brazil

BPCL’s JV in Brazil has made discoveries in the BM-C-30 block. Anadarko is the operator of the block, holding 30% stake, while BPCL holds 12.5%. The company has announced two major discoveries in the block – Wahoo I and II. While in Wahoo I, gross recoverable reserves estimates are at 200mnbl, Wahoo II is still under the appraisal stage. Therefore, significant upsides exist as the JV will drill two more exploratory wells in the block in the next six months. The JV has further acreage in three more blocks in Brazil, which could add value in the long term.

Table 6: Valuation of BPCL’s stake in Wahoo Gross recoverable reserves (mn bl) 200 BPCL stake (%) 12.50% BPCL share of recoverable reserves (mn bl) 25 EV/bl valuation multiple (US$/bl) 19.0 EV/bl basis Discount on valuation multiple due to higher royalties & taxes in Brazil (%) 30 Effective EV/bl multiple for valuing E&P assets in Brazil (US$/bl) 13.3 Value (US$ mn) 333 Value (Rs mn) 15,295 Rs46/US$ exchange rate assumed Present value of Wahoo discovery to BPCL (Rs mn) 9,497 10% discount rate Value/share (Rs) 29 Shares outstanding adjusted for treasury stocks


Chart 3: Brazil discoveries Country Brazil

Region Presalt

Field Wahoo

Block BM-C-30

Discovery date Nov 08

Reserve type Oil

Current status Discovery (Appraised)

Water depth 1,417 m / 4,676 ft

Operator Anadarko

Anadarko 30%

BP 25%

IBV Brazil Petroleo 25%

BPRL 12.50%

Videocon 12.50%

Maersk 20% Source: Anadarko Presentation


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Bina refinery to bridge the refining-marketing gap BPCL’s marketing-to-refining ratio (in volumes terms) is just above 1, with marketing volumes being 2.7mmtpa higher than the refining capacity of 23mmtpa. Hence, BPCL’s profitability is slightly sensitive to marketing margin fluctuation. HPCL, with a ratio of ~2, is the most sensitive of all the three companies, while IOC, with a refining capacity of 64mmt and sales of 62mmt has a marketing-to-refining ratio of <1.

Table 7: Refining-marketing volumes through Q4FY09-Q3FY11 Q4FY09 Q1FY10 Q2FY10 Q3FY10 Q4FY10 Q1FY11 Q2FY11 Q3FY11Crude throughput (MT) 4.87 4.17 5 5.55 5.69 5.57 5.6 5.03Market sales (MT) 7.09 6.94 6.5 7 7.25 7.34 6.6 7.4Throughput to Sales 0.7 0.6 0.8 0.8 0.8 0.8 0.8 0.7

Source: Company, I-Sec Research The commissioning of BPCL’s greenfield refinery, BORL, would help it bridge the refining-marketing gap, thus curtailing profit volatility due to crude price movement. BORL would be a 6mmtpa refinery with a Nelson complexity of 9. The refinery would be commissioned by Q1FY12 and would primarily target Euro IV compliant products (in 11 cities in India). We value BPCL’s investment in BORL at 1x P/BV, which provides an upside of Rs73/share.

Flexibility to process different qualities of crude

The Nelson complexity index (NCI) of BORL’s new refinery is expected to be 9.1, one of the highest in India. The only comparable domestic refineries are that of Reliance Industries (RIL) at Jamnagar (NCI of 11.1), RIL’s SEZ refinery (NCI of 14) and Essar’s refinery (NCI of 9). The configuration of BORL’s proposed refinery will facilitate the processing of a wide variety of low-cost Middle Eastern and other kinds of crude. This will help the refinery benefit from the cost differentials between low sulphur, low residue crudes and sour high residue crudes, while simultaneously allowing it to produce high quality Euro III and Euro IV auto fuels.

All of BORL’s refined products are intended to conform to the Bureau of Indian Standards (BIS) specifications. The refinery’s output of auto fuels will meet Euro III and Euro IV standards, currently proposed for ’10 and beyond (Table 8).

Table 8: Product slate Products TMTPA % of total LPG 222 3.7 Naphtha 241 4.0 Euro III Regular Motor Spirit 385 6.4 Euro IV Regular Motor Spirit 400 6.7 Aviation Turbine Fuel 550 9.2 Superior Kerosene Oil 487 8.1 Euro III High Speed Diesel (1) 1610 26.8 Euro IV High Speed Diesel 1181 19.7 Sulphur 109 1.8 Petroleum Coke 410 6.8 Fuel & Loss (2) 405 6.8



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Fiscal incentives by the Madhya Pradesh government

BORL has entered into a Memorandum of Understanding (MoU) with the Madhya Pradesh (MP) Government to enjoy the following fiscal incentives:

• Exemption from the Central Sales Tax (CST) on product sale from the refinery outside Madhya Pradesh for 15 years from the date of commercial production. The maximum CST exemption will be limited to the project cost of Rs75bn (as per the MoU). This positively impacts BORL’s GRMs by ~US$0.5/bl.

• BORL’s crude supply is exempted from entry tax for 15 years from the commercial operation date of the refinery.

• Exemption from entry tax of capital goods and work contract tax during the project implementation period.

Other financial incentives are:

• A concession in basic customs duty for capital goods import

• Exemption from paying income tax for seven years from the date of commercial operation of the refinery.

The MP Government will have the first right of refusal on Naphtha sale from the refinery.


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Valuations – Positives factored in We value BPCL at 1.1x FY13E BV, at a discount to long-term mean P/BV of 1.2x – after adding its investments in the BORL refinery at 1x book value and in OIL/Petronet/IGL at a 80% discount to the current market price, we arrive at a target price of Rs562. BPCL’s core business book multiple of 0.6x is derived from its normalized RoEs of 10%, considering some support from the government to maintain these RoEs over the long-term. We prefer to value BPCL on BV, especially in the current environment of high crude price and considering that the Government would disallow erosion in BPCL’s net worth, mainly through cash subsidy (oil bonds) and upstream discounts.

The stock had seen a sharp re-rating in the past year to ~1.8x due to partial de-regulation of subsidised product prices undertaken by the Government. However, this scenario should change as the quantum of cash support from the Government for limiting BPCL’s under-recoveries is uncertain. In our view, BPCL’s valuations should come under threat in the next two years, as ad-hoc price revision by the Government would at best provide marginal support.

BPCL’s valuations are hit by a sharp decline in its RoE to 6% from 11% in FY11E, lower than its five-year mean RoE of 11%. As long as crude price is high, we assume a lower profitability environment for BPCL and expect its multiples to 1.1x, below its five-year mean.

Chart 4: Rolling price-book trend

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Table 9: P/BV valuations Particulars Rs/share FY13E BV 495 Core business multiple (x) 0.6 Core business value 317 Add: Brazilian discoveries 29 Mozambique discovery 31 OIL stake 17 Indraprastha Gas 23 Petronet LNG 28 BORL (Rs mn) 43 Other investments 73 Total value 562 Implied P/BV 1.1


Key assumptions

• Average Brent prices in FY12E-13E at US$100/bl

• Marginal revision in diesel and LPG prices

• Under-recovery sharing. 50% of under-recoveries would be compensated by the Government, 33% by upstream (ONGC, OIL and GAIL) and the rest will likely be borne by BPCL


• Sharp variation in Brent prices, which can influence Government’s policy

• Lower crude price can encourage implementation of a subsidy sharing formula or freeing up of diesel price, which can be very positive for BPCL

• Major changes in estimation of hydrocarbon reserves in Wahoo or Mozambique blocks can impact valuations


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FY09 FY10 FY11E FY12E FY13EGross Sales 1,311,204 1,284,841 1,617,354 1,819,664 1,819,516 Less: Excise Duty 107,797 99,324 117,590 132,294 132,283Net Sales 1,203,407 1,185,517 1,499,763 1,687,370 1,687,233Oil bonds 162,164 52,650 82,825 122,405 127,672 Total Operating Income 1,365,571 1,238,167 1,582,589 1,809,775 1,814,905 Less: Raw Materials Consumed 1,235,642 1,099,836 1,435,338 1,661,404 1,659,172 Power and Fuel 736 2,448 2,623 2,884 3,171 Personnel Expenses 19,813 22,522 22,294 22,982 23,671 Selling & Distribution Expenses 75,647 82,823 84,450 85,902 87,307 Total Operating Expenses 1,331,838 1,207,629 1,544,705 1,773,172 1,773,322 EBITDA (incl bonds) 33,733 30,539 37,884 36,603 41,583 Depreciation & Amortisation 12,617 14,446 15,652 16,799 17,505Add: Other Income 14,358 23,652 14,985 8,545 7,446 EBIT 35,474 39,745 37,217 28,349 31,524 Less: Gross Interest 24,043 11,247 13,820 13,986 15,114 Recurring Pre-tax Income 11,431 28,498 23,397 14,363 16,410 Add: Extra Ordinary income (156) (1,064) - - -Less: Extra Ordinary expenses Less: Taxation 4,034 10,235 6,704 4,979 5,639 Current Tax 6,885 13,248 6,907 4,803 5,401 Deferred Tax (2,851) (3,013) (203) 176 237 Less: Minority interest 904 876 722 812 830 Net Income (Reported) 6,338 16,324 15,971 8,572 9,942 Consolidated Recurring Net Income 6,494 17,387 15,971 8,572 9,942



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FY09 FY10 FY11E FY12E FY13EASSETS Current Assets, Loans & Advances Cash & Bank balance 13,486 7,690 7,964 5,785 951 Inventory 78,706 141,092 115,060 148,368 182,377 Sundry Debtors 15,059 26,009 23,404 26,682 26,680 Loans and Advances 29,782 36,468 36,468 36,468 36,468 Other Current Assets 31,026 38,012 38,228 39,102 39,976Total Current Assets 168,058 249,271 221,123 256,405 286,452 Current Liabilities & Provisions Current Liabilities Sundry Creditors 69,009 90,969 76,146 88,161 88,054 Other Current Liabilities 53,741 69,948 69,948 69,948 69,948 Provisions 18,209 27,652 27,652 27,652 27,652 Total Current Liabilities and Provisions 140,960 188,568 173,745 185,760 185,653 Net Current Assets 27,099 60,702 47,378 70,645 100,799 Investments Strategic & Group Investments 25,891 33,550 38,550 43,550 48,550Other Marketable Investments 138,109 85,773 80,773 60,773 55,773Total Investments 164,000 119,323 119,323 104,323 104,323 Goodwill (On consolidation) 3,855 3,855 3,855 3,855 3,855 Fixed Assets Gross Block 263,546 302,023 330,511 347,202 359,008 Less Accumulated Depreciation 120,483 134,929 150,581 167,380 184,885 Net Block 143,062 167,094 179,930 179,823 174,123 Add: Capital Work in Progress 61,727 78,217 83,341 81,026 79,221Total Fixed Assets 204,789 245,311 263,271 260,849 253,343 Total Assets 399,742 429,190 433,826 439,671 462,320 LIABILITIES AND SHAREHOLDER'S EQUITY Borrowings Short Term Debt 209,143 222,468 227,468 227,467 243,253 Long Term Debt 33,249 44,453 34,254 34,254 34,254Total Borrowings 242,392 266,921 261,722 261,720 277,507 Deferred Tax Liability 15,257 11,477 11,274 11,450 11,688 Minority Interest 9,015 9,396 9,839 10,338 10,847 Share Capital Paid up Equity Share Capital 3,615 3,615 3,615 3,615 3,615 Reserves & Surpluses General & Other Reserve 129,497 137,814 147,408 152,579 158,695 Less: Misc. Exp. not written off 33 33 33 33 33Net Worth 133,079 141,396 150,991 156,162 162,277 Total Liabilities & Shareholder's Equity 399,742 429,190 433,826 439,670 462,319



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FY09 FY10 FY11E FY12E FY13Ea) Cash Flow from Operating Activities Consolidated Net Income 6,338 16,324 15,971 8,572 9,942Add: Depreciation & Amortisations 12,093 14,446 15,652 16,799 17,505 Deferred Tax (2,851) (3,780) (203) 176 237Less: Other Income 155,869 38,759 14,985 8,545 7,446 Net Extra-ordinary income (156) (1,064) - - -Operating Cash Flow before Working Capital chg (a) (140,133) (10,705) 16,435 17,002 20,238 Changes in Working Capital (Increase) / Decrease in Inventories 36,544 (62,386) 26,032 (33,308) (34,009)(Increase) / Decrease in Sundry Debtors 1,621 (10,950) 2,605 (3,278) 2(Increase) / Decrease in Operational Loans & Adv. (11,829) (6,685) - - -(Increase) / Decrease in Other Current Assets 18,340 (6,986) (216) (874) (874)Increase / (Decrease) in Sundry Creditors (28,424) 21,960 (14,823) 12,015 (107)Increase / (Decrease) in Other Current Liabilities 9,858 25,649 - - - Working Capital Inflow / (Outflow) (b) 26,111 (39,399) 13,598 (25,445) (34,988) Net Cash flow from Operating Activities (a) + (b) (114,023) (50,104) 30,033 (8,443) (14,750) Cash Flow from Capital commitments Purchase of Fixed Assets (48,914) (54,967) (33,612) (14,377) (10,000)Purchase of Investments (8,988) (7,659) (5,000) (5,000) (5,000)Cash Inflow/(outflow) from capital commitments (c) (57,902) (62,627) (38,612) (19,377) (15,000) Free Cash flow after capital commitments (171,925) (112,731) (8,579) (27,820) (29,750)(a) + (b) + (c) Cash Flow from Investing Activities Sale of Investments 72,898 68,536 5,000 20,000 5,000Other Income 14,358 23,652 14,985 8,545 7,446 Net Cash flow from Investing Activities (d) 87,255 92,188 19,985 28,545 12,446 Cash Flow from Financing Activities Proceeds from fresh borrowings 81,733 24,529 (5,199) (1) 15,786Dividend paid including tax (3,504) (6,450) (6,377) (3,401) (3,826)Others 4,192 (1,175) 443 499 510Net Cash flow from Financing Activities (e) 82,422 16,904 (11,132) (2,904) 12,470 Net Extra-ordinary Income (f) (156) (2,157) - - - Total Increase / (Decrease) in Cash (2,404) (5,796) 274 (2,179) (4,834)(a) + (b) + (c) + (d)+ (e) + (f) Opening Cash and Bank balance 15,889 13,486 7,690 7,964 5,785Closing Cash and Bank balance 13,486 7,690 7,964 5,785 951Increase/(Decrease) in Cash and Bank balance (2,404) (5,796) 274 (2,179) (4,834)



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FY09 FY10 FY11E FY12E FY13EPer Share Data (Rs) Diluted Recurring Earning per share (DEPS) 18.0 48.1 44.2 23.7 27.5Diluted EPS (adjusted for treasury stock) 19.3 49.8 48.7 26.1 30.3Recurring Cash Earnings per Share (CEPS) 52.9 88.0 87.5 70.2 75.9Free Cash flow per share (FCPS - post capex) (475.5) (311.8) (23.7) (76.9) (82.3)Book Value (BV) 368.1 391.1 417.6 431.9 448.8Dividend per Share 8.2 15.2 15.0 8.0 9.0 Valuation Ratios (x) Diluted Price Earning Ratio 34.0 12.7 13.8 25.7 22.2Price to Recurring Cash Earnings per share 11.5 6.9 7.0 8.7 8.0Price to Book Value 1.7 1.6 1.5 1.4 1.4EV / EBITDA 8.5 11.8 9.4 10.2 9.4EV / Total Operating Income 0.2 0.3 0.2 0.2 0.2EV / Operating Free Cash Flow (Pre-Capex) (2.0) (33.7) 21.6 21.9 19.4EV / Net Operating Free Cash Flow (Post-Capex) (1.4) (2.9) (37.0) (12.0) (11.9)Dividend Yield (%) 1.3 2.5 2.5 1.3 1.5 Growth Ratios (% YoY) Diluted Recurring EPS Growth (60.5) 167.8 (8.1) (46.3) 16.0Diluted Recurring CEPS Growth (34.9) 66.6 (0.7) (19.8) 8.2Total Operating Income Growth 22.8 (9.3) 27.8 14.4 0.3EBITDA Growth (5.5) (9.5) 24.1 (3.4) 13.6Recurring Net Income Growth (60.5) 167.8 (8.1) (46.3) 16.0 Operating Ratios (%) (73.9) (0.4) (7.3) (37.1) 26.9EBITDA Margins 2.47 2.47 2.39 2.02 2.29EBIT Margins 2.60 3.21 2.35 1.57 1.74Recurring Pre-tax Income Margins 0.83 2.26 1.46 0.79 0.90Recurring Net Income Margins 0.47 1.38 1.00 0.47 0.55Raw Material Consumed / Sales 102.7 92.8 95.7 98.5 98.3SGA Expenses / Sales 6.3 7.0 5.6 5.1 5.2Other Income / Pre-tax Income 125.6 83.0 64.0 59.5 45.4Other Operating Income / EBITDA 480.7 172.4 218.6 334.4 307.0Effective Tax Rate 35.3 35.9 28.7 34.7 34.4 Return / Profitability Ratios (%) Return on Capital Employed (RoCE)-Overall 6.2 5.9 6.0 4.1 4.4Return on Invested Capital (RoIC) 5.9 3.6 5.0 3.8 4.4Return on Net Worth (RoNW) 5.0 12.7 10.9 5.6 6.2Dividend Payout Ratio 42.3 30.5 30.8 30.6 29.7 Solvency Ratios / Liquidity Ratios (%) Debt Equity Ratio (D/E) 194 197 181 175 178Long Term Debt / Total Debt 19 20 17 17 16Net Working Capital / Total Assets 3 12 9 15 22Interest Coverage Ratio-based on EBIT 148 353 269 203 209Debt Servicing Capacity Ratio (DSCR) 165 446 354 288 290Current Ratio 39 52 46 53 58Cash and cash equivalents / Total Assets 38 22 20 15 12 Turnover Ratios Inventory Turnover Ratio (x) 12.7 10.0 11.2 12.6 10.1Assets Turnover Ratio (x) 3.9 3.0 3.7 4.2 4.0Working Capital Cycle (days) 11.1 12.9 12.5 11.9 17.2Average Collection Period (days) 4.4 5.8 5.6 5.0 5.4Average Payment Period (days) 24.6 26.5 21.2 18.0 19.4



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Tables Table 1: Surging under-recoveries ...................................................................................155 Table 2: Under-recovery sharing ......................................................................................155 Table 3: Pressure on profitability ......................................................................................156 Table 4: Pressure on cashflow..........................................................................................156 Table 5: Mozambique block valuation ..............................................................................159 Table 6: Valuation of BPCL’s stake in Wahoo..................................................................159 Table 7: Refining-marketing volumes through Q4FY09-Q3FY11.....................................160 Table 8: Product slate .......................................................................................................160 Table 9: P/BV valuations...................................................................................................163 Table 10: Profit and loss statement ..................................................................................164 Table 11: Balance sheet ...................................................................................................165 Table 12: Cashflow statement ..........................................................................................166 Table 13: Key ratios ..........................................................................................................167

Charts Chart 1: Mozambique discoveries ....................................................................................158 Chart 2: Mozambique development plan ..........................................................................158 Chart 3: Brazil discoveries ................................................................................................159 Chart 4: Rolling price-book trend ......................................................................................162

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Market Cap Rs119.2bn/US$2.7bn Year to March FY10 FY11E FY12E FY13EReuters/Bloomberg HPCL.BO/HPCL IN Revenue (Rs mn) 1,013,475 1,355,766 1,665,419 1,671,494 Shares Outstanding (mn) 338.63 Net Income (Rs mn) 20,633 7,215 6,717 8,458 52-week Range (Rs) 556/292 EPS (Rs) 60.9 21.3 19.8 24.9Free Float (%) 48.9 % Chg YoY 372.9 (65.0) (6.9) 25.9FII (%) 8.3 P/E (x) 5.8 16.5 17.8 14.1Daily Volume (US$'000) 10,850 CEPS (Rs) 72.7 59.9 60.9 69.0Absolute Return 3m (%) (11.1) EV/E (x) 6.0 9.2 6.1 6.2Absolute Return 12m (%) 13.8 Dividend Yield 3.4 2.0 2.0 2.3Sensex Return 3m (%) (5.6) RoCE (%) 7.8 4.3 4.2 4.3Sensex Return 12m (%) 8.3 RoE (%) 18.5 6.1 5.5 6.7

Hindustan Petroleum Corporation SELL

Subsidised value Rs352Reason for report: Reinitiating coverage



Target price Rs298


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Promoters 51.1 51.1 51.1 Institutional investors 35.9 36.6 36.0 MFs and UTI 12.4 12.6 11.3 Insurance Company 0.0 0.4 0.9 FIIs 6.5 8.7 8.3 Others 13.0 12.3 12.9


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Hindustan Petroleum Corporation (HPCL) is among the most focused oil marketing companies (OMCs) in India, enjoying >20% share in the domesticmarket. The company is currently commissioning a greenfield refinery atBhatinda, which will raise its overall refining capacity to ~26mmtpa. This would be a key asset for the company as its refining-marketing ratio is the lowest amongOMCs. However, under-recovery concerns impact HPCL the most as we estimatecrude price to average at US$100/bl in the next two years. The Government’sinability to undertake subsidy reforms hits HPCL’s profitability hard, threatening its valuation outlook. We reinitiate with SELL (target price of Rs298, at 0.8x FY13E BV) as HPCL is impacted the most among OMCs from rising under-recoveries.

Derailed by rising under-recovery. The subsidy-sharing mechanism continues to be a swinger for HPCL as there is no firm decision by the Government on the sharing formula. HPCL has a low refining-marketing ratio, which hits it the most among OMCs, when crude price rises. At present, HPCL is losing ~Rs10.5/litre on diesel, Rs4.25/litre on petrol, Rs21/litre on SKO and Rs290/cylinder on LPG. The overall under-recovery is expected to be Rs171bn in FY11E based on the current crude prices. Of this, we expect HPCL tobear ~Rs36bn (Rs42bn in FY12E), supported by the Government compensation at Rs81bn and an upstream assistance of Rs54bn. However, there is still uncertaintyon the precise contribution from the Government, which can hurt HPCL’s valuationoutlook going forward.

Commissioning of Bhatinda refinery crucial. HPCL will likely commission the 9mmtpa Bhatinda refinery by December ’11. The refinery is expected to trigger thecompany’s marketing plans in North India, where it has limited presence. The overallcost for the refinery is expected at Rs190bn, the refinery’s high complexity of 9.1would ensure a premium of at least US$2-3/bl over Singapore Complex GRMs in the long term. This refinery contributes Rs63/share to HPCL’s valuations; hence, itscommissioning is critical.

Valuations impacted the most; reinitiate with SELL. HPCL’s profitability will likely dip sharply in the next two years, leading to a sharp drop in RoE to ~7% by FY13E. Based on the current uncertain environment, valuing the company on book value would be appropriate. High sensitivity to under-recovery entails a 0.8x implied multiple for HPCL, leading to a fair value of Rs298. Reinitiate with SELL.

Hindustan Petroleum Corporation, April 4, 2011 ICICI Securities

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TABLE OF CONTENT Derailed by rising under-recovery .............................................................................171

Profitability under pressure .........................................................................................172 Commissioning of Bhatinda refinery important .......................................................174

High complexity advantage.........................................................................................174 Bhatinda project – Details ...........................................................................................175 Key assumptions.........................................................................................................175

Valuations – Strong downside....................................................................................176 Key assumptions.........................................................................................................177 Key risks to our call .....................................................................................................177

Annexure 1: Financials (consolidated)......................................................................178 Annexure 2: Index of Tables and Charts ...................................................................182 Annexure 4: International financial reporting standards – Impact on oil & gas sector ............................................................................................................................183

Likely impact on Indian companies .............................................................................183


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Derailed by rising under-recovery Brent crude price has surged beyond US$100/bl, in a repeat of the situation in FY09. Surging under-recoveries and ad-hoc compensation by the Government makes HPCL’s profitability event based rather than fundamental. Hence, HPCL’s valuations can be volatile, both in the short term and the long term. At present, HPCL is losing ~Rs10.5/litre on diesel, Rs4.25/litre on petrol (apparently deregulated), Rs21/litre on SKO and Rs290/cylinder on LPG.

HPCL’s current refining-to-marketing ratio is the lowest among OMCs at 0.6, which makes its marketing under-recovery the most volatile among OMCs. Hence, HPCL’s profitability is hit the most in case of a major fluctuation in crude. HPCL is the most risky bet among OMCs and can hit a rock bottom in a sustained high crude price scenario.

Table 1: Refining-to-marketing volumes Q4FY09 Q1FY10 Q2FY10 Q3FY10 Q4FY10 Q1FY11 Q2FY11 Q3FY11Crude throughput (MT) 4.17 4.10 4.02 3.73 3.91 3.29 3.04 4.10Market sales (MT) 6.83 6.84 6.26 6.66 6.51 6.73 6.03 7.05Throughput to sales 0.6 0.6 0.6 0.6 0.6 0.5 0.5 0.6


Chart 1: HPCL’s stock price vis-à-vis Brent

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Table 2: Surging under-recovery (Rs mn)

FY08 FY09 FY10 FY11E FY12E FY13E Total upstream 257,080 320,000 144,300 258,615 371,914 386,755 % total 33.3 31.0 31.3 33.3 33.3 33.3 Total government 352,900 712,920 260,000 387,922 557,871 580,133 % total 45.8 69.0 56.5 50.0 50.0 50.0 Total downstream 161,250 334 56,210 129,308 185,957 193,378 % total 20.9 - 12.2 16.7 16.7 16.7 Total under-recovery 771,230 1,032,920 460,510 775,844 1,115,741 1,160,266 Petrol 73,320 51,810 51,510 22,059 29,260 31,016 Diesel 351,660 522,860 92,790 321,047 599,396 635,360 Kerosene 191,020 282,250 173,640 186,671 223,076 221,960 LPG 155,230 176,000 142,570 246,067 264,009 271,930 Total 771,230 1,032,920 460,510 775,845 1,115,741 1,160,266


The under-recovery should hit the roof from FY12, when we expect Brent prices to average above US$100/bl. The Government’s inability to undertake any major price revisions for subsidised products will spike overall under-recovery to Rs1,111bn, crossing the FY09 levels of Rs1,030bn. HPCL’s share in FY13E is expected to be at Rs44bn, which is reduced by the Government’s compensation of Rs132bn and upstream assistance of Rs88bn.

Table 3: Sharing of under-recovery (Rs mn)

FY09 FY10 FY11E FY12E FY13E IOC 149 23,784 74,700 107,158 111,692 % total 44.6 58.1 57.8 57.6 57.8 BPCL 96 8,540 27,608 40,802 42,557 % total 28.8 20.9 21.4 21.9 22.0 HPCL 89 8,602 26,999 37,997 39,129 % total 26.6 21.0 20.9 20.4 20.2 Total downstream 334 40,926 129,307 185,957 193,378 Upstream assistance ONGC 273,740 114,560 206,373 304,782 315,239 OIL 29,319 15,267 32,129 44,988 46,823 GAIL 16,937 13,854 19,170 22,143 24,694 Total 319,996 143,681 257,672 371,914 386,755


Profitability under pressure

HPCL’s profitability will take a hit FY12E onwards, as RoEs decline to sub 6% levels, one of the lowest for the company. This is worse than FY09, indicating that valuations can retest all-time lows.

Table 4: Pressure on profitability (%)

FY09 FY10 FY11E FY12E FY13E RoCE 5.6 5.7 7.8 4.3 4.2 RoNW 7.4 4.1 18.5 6.1 5.5

Source: I-Sec Research HPCL’s profitability in the next 2-3 years is a major concern as it is highly dependent on the Government’s subsidy sharing mechanism and product pricing policy.


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We expect BPCL’s cashflows to witness pressure from FY12, led by higher-than-expected working capital requirement. The company would find it difficult to manage inventories, leading to pressure on the company’s short term debt levels and interest payments.

Table 5: Pressure on cashflows (Rs mn)

FY09 FY10 FY11E FY12E FY13E Operating cashflow (55,198) (131,702) 3,039 (60,688) (106,023) Working capital changes 53,113 (29,411) 2,151 (28,774) 632 Capital commitments 30,515 32,086 48,047 (35,418) (103,432) Free cashflow (138,825) (134,377) (47,158) 3,503 (3,223)



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Commissioning of Bhatinda refinery important As HPCL has one of the lowest refining-marketing ratios, commissioning of its 9mmtpa greenfield Bhatinda refinery is crucial for its valuations. We expect HPCL’s profitability to become less volatile as this ratio moves closer to 0.9 from 0.6 currently. Post commissioning of its expansion project at Vizag refinery over the next 3-4 years, this ratio is expected to move closer to 1. BPCL, with a ratio close to 0.9, is the second highest, followed by IOC at >1.

The Bhatinda refinery is expected to be commissioned by Q1FY12 and would primarily target Euro IV (Euro V from ’13) compliant products (in 11 cities in India). We value HPCL’s investment in this refinery on DCF, which provides an upside of Rs63/share.

High complexity advantage

The Nelson complexity index (NCI) of the Bhatinda refinery is expected to be 9.1, one of the highest in India. The only comparable domestic refineries are that of Reliance Industries (RIL) at Jamnagar (NCI of 11.1), RIL’s SEZ refinery (NCI of 14) and Essar’s refinery (NCI of 9). The configuration of the proposed refinery will facilitate the processing of a wide variety of low cost Middle Eastern and other crudes. This flexibility to be able to process sour crudes will enable the refinery to take advantage of the cost differentials between low sulphur, low residue crudes and sour high residue crudes whilst simultaneously allowing it to produce high quality Euro IV and Euro V auto fuels. All of Bhatinda’s refined products are intended to conform to the Bureau of Indian Standards (BIS) specifications. The refinery’s output of auto fuels will meet Euro IV-V standards.

Table 6: Product slate Products % slate ’000mmt PP 4.00 360 LPG 7.58 682 Naphtha 4.49 404 MS- Regular 8.33 750 MS- Premium 2.78 250 SKO 1.00 90 ATF 5.56 500 HSD 42.42 3818 MTO 0.28 25 Sulphur 2.24 202 Pet Coke 10.36 932 Hexane 0.06 5 Fuel & Loss 10.92 983



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Bhatinda project – Details

• HPCL would hold 49% stake

• Grass root refinery of 9mmtpa

• Cross-country crude oil pipeline (~1,014Kms) from Mundra to Bhatinda, traversing through the states of Gujarat, Rajasthan and Haryana

• Crude receipt facilities – Single point mooring (SPM) buoy capable of handling very large crude carriers (VLCC) for crude import located at Mundra, Gujarat

• Crude oil terminal (COT) ~6Kms away from the sea shore at Mundra, Gujarat

• Captive power plant of 165MW for refinery power and steam requirements

Table 7: Valuations Particulars Value (Rs mn) PV of FCF to FY2020E 88,295 Terminal value 227,120 PV of terminal value 81,868 Firm Value 170,163 Less Net Debt 126,377 NPV 43,786 Value for HPCL 21,455 Value/share for HPCL 63


Key assumptions

• Commissioning by Q2FY12

• Long-term average GRMs at US$9/bl

• WACC 9.6%, terminal growth 2%


176

Valuations – Strong downside We value HPCL at 0.8x FY13E book value, at a discount to long-term mean P/BV of 1x. We have factored in HPCL’s investments in the Bhatinda refinery based on DCF and OIL/MRPL at 80% discount to the current market price to arrive at a target price of Rs298. BPCL’s core business book multiple of 0.5x is derived from its normalized RoEs of 8%, considering some support from the government to maintain these RoEs over the long-term. We prefer BV to value HPCL, especially in the current environment of high crude price considering that the Government would disallow the erosion in HPCL’s net worth (HPCL will report some profits), primarily through support in the form of cash subsidies (or oil bonds) and upstream discounts.

The stock had seen a sharp re-rating in the past year to ~1.5x due to partial de-regulation of subsidised product prices undertaken by the Government. However, this scenario should change as the quantum of cash support from the Government for limiting BPCL’s under-recoveries is uncertain. We see a major threat to company’s valuations in the next two years, as ad-hoc price revisions by the Government would provide at best provide marginal support.

HPCL’s valuations are hit by a sharp decline in its RoE to 7% from 11% in FY11E, lower than its five-year mean RoE of 9%. As long as crude prices are high, we can assume a lower profitability environment for HPCL. We expect BPCL’s multiples to decline to 1.1x, below its five-year mean.

Chart 2: Rolling price/book trend

0

200

400

600

800

Apr-

02

Oct

-02

May

-03

Dec

-03

Jun-

04

Jan-

05

Aug-

05

Mar

-06

Sep-

06

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07

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08

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Jul-0

9

Feb-

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-11

(Rs)

0.5x

1.0x

1.5x

2.0x

Source: I-Sec Research Table 8: P/BV valuations

Particulars Value (Rs/share) FY13E BV 381 Core business multiple 0.5 Core business value 173 Add MRPL stake (Rs mn) 45 OIL stake (Rs mn) 17 Bhatinda refinery 63 Total value 298 Implied PBV 0.8



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Key assumptions

• Average Brent prices in FY12E-13E at US$100/bl

• Marginal revision in diesel and LPG prices

• Under-recovery sharing. About 50% of under-recoveries will likely be compensated by the Government, 33% by Upstream (ONGC, OIL and GAIL) and the rest by HPCL.


• Sharp variation in Brent prices, which can affect the Government’s policy decision

• Lower crude price can encourage implementation of a subsidy sharing formula or freeing up of diesel prices. This can be positive for HPCL.


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FY09 FY10 FY11E FY12E FY13EGross Sales 1,017,351 1,030,356 1,369,646 1,654,848 1,655,647 Less: Excise Duty 70,502 72,512 96,389 116,461 116,517Net Sales 946,848 957,844 1,273,257 1,538,387 1,539,131 Other Operating Income 146,928 55,631 82,509 127,032 132,364 Total Operating Income 1,093,776 1,013,475 1,355,766 1,665,419 1,671,494 Less: Raw Materials Consumed 274,572 281,877 398,563 566,850 564,705

Purchase of products for resale 733,946 626,778 861,402 985,048 985,048 Power and Fuel 190 2,482 2,730 3,003 3,304 Personnel Expenses 11,372 13,011 16,556 17,053 17,564 Selling & Distribution Expenses 44,990 53,164 53,948 59,342 65,277 Total Operating Expenses 1,065,070 977,312 1,333,198 1,631,297 1,635,897EBITDA (excl bonds) (118,221) (19,468) (59,941) (92,910) (96,767)EBITDA (incl bonds) 28,707 36,163 22,568 34,122 35,597 Depreciation & Ammortisation 9,813 11,644 13,095 13,939 14,926Add: Other Income 9,057 16,462 12,263 350 608 EBIT 27,951 40,981 21,736 20,533 21,279 Less: Gross Interest 20,828 9,038 10,888 10,432 8,559 Recurring Pre-tax Income 7,122 31,943 10,848 10,101 12,719 Add: Extra Ordinary income - (7,044) - - - Less: Taxation 2,759 11,310 3,633 3,384 4,261 Current Tax 2,416 9,264 3,633 3,030 3,816 Deferred Tax 343 2,046 - 354 445

Prior period tax paid/(write back) (1,387) 575 - - - Net Income (Reported) 5,750 13,014 7,215 6,717 8,458 Consolidated Recurring Net Income 4,363 20,633 7,215 6,717 8,458



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FY09 FY10 FY11E FY12E FY13EASSETS Current Assets, Loans & Advances Cash & Bank balance 6,083 2,432 4,561 7,600 5,655 Inventory 87,932 125,792 136,455 168,072 191,065 Sundry Debtors 22,409 24,373 23,143 37,933 37,951 Loans and Advances 41,691 52,585 22,244 22,244 22,244 Other Current Assets 1,812 1,237 1,237 1,237 1,237Total Current Assets 159,927 206,419 187,640 237,086 258,152 Current Liabilities & Provisions Current Liabilities Sundry Creditors 56,439 73,913 81,778 127,553 127,377 Other Current Liabilities 48,944 70,586 70,586 70,586 70,586 Provisions 12,176 21,052 21,052 21,052 21,052 Total Current Liabilities and Provisions 117,558 165,551 173,416 219,191 219,015 Net Current Assets 42,369 40,868 14,224 17,895 39,138 Investments Strategic & Group Investments 14,903 26,289 34,278 38,278 38,278Other Marketable Investments 127,062 87,584 67,584 57,584 47,584Total Investments 141,965 113,872 101,862 95,862 85,862 Fixed Assets Gross Block 202,088 249,884 285,162 314,343 347,486 Less Accumulated Depreciation 85,541 96,817 109,912 123,851 138,777 Net Block 116,548 153,067 175,250 190,493 208,708 Add: Capital Work in Progress 50,011 38,876 41,188 31,607 7,879Total Fixed Assets 166,558 191,943 216,438 222,099 216,588 of which intangibles Total Assets 350,892 346,683 332,524 335,856 341,587 LIABILITIES AND SHAREHOLDER'S EQUITY Borrowings Short Term Debt 195,824 177,415 159,780 159,780 169,781 Long Term Debt 31,728 35,609 34,646 33,684 23,684Total Borrowings 227,552 213,024 194,426 193,464 193,465 Deferred Tax Liability 16,034 18,080 18,080 18,433 18,878 Share Capital Paid up Equity Share Capital 3,390 3,390 3,390 3,390 3,390 Reserves & Surpluses Share Premium 11,538 11,538 11,538 11,538 11,538 General & Other Reserve 92,379 100,652 105,090 109,031 114,316Net Worth 107,306 115,580 120,018 123,958 129,244 Total Liabilities & Shareholder's Equity 350,892 346,683 332,524 335,856 341,587



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FY09 FY10 FY11E FY12E FY13Ea) Cash Flow from Operating Activities Consolidated Net Income 6,093 15,060 7,215 7,071 8,903Add: Depreciation & Amortisations 9,133 11,276 13,095 13,939 14,926Less:

Oil bonds 146,928 30,341 80,998 127,032 132,364 Other Income 9,057 16,462 12,263 350 608 Net Extra-ordinary income - (7,044) - - -Op.Cash Flow before Working Capital change (a) (140,759) (13,422) (72,951) (106,372) (109,142) Changes in Working Capital (Increase) / Decrease in Inventories (32,270) 37,860 10,663 31,617 22,994(Increase) / Decrease in Sundry Debtors 5,303 1,964 (1,231) 14,790 18(Increase) / Decrease in Operational Loans & Adv. (10,539) 10,894 (30,341) - -(Increase) / Decrease in Other Current Assets 1,317 (574) - - -Increase / (Decrease) in Sundry Creditors 12,536 (17,475) (7,865) (45,775) 176Increase / (Decrease) in Other Current Liabilities (5,757) (30,519) - - - Working Capital Inflow / (Outflow) (b) 29,411 (2,151) 28,774 (632) (23,188) Net Cash flow from Operating Activities (a) + (b) (111,348) (15,573) (44,178) (107,004) (132,330) as a % of Operating Cash Flow Cash Flow from Capital commitments Purchase of Fixed Assets 23,239 36,661 37,590 19,600 9,415Purchase of Investments 8,847 11,386 (73,009) (123,032) (132,364)Consideration paid for acquisition of undertaking Cash Inflow/(outflow) from capital commitments (c) 32,086 48,047 (35,418) (103,432) (122,949) Free Cash flow after capital commitments (143,434) (63,620) (8,760) (3,572) (9,381)(a) + (b) + (c) Cash Flow from Investing Activities Sale of Investments 82,180 69,819 20,000 10,000 10,000Other Income 9,057 16,462 12,263 350 608 Net Cash flow from Investing Activities (d) 91,237 86,281 32,263 10,350 10,608 Cash Flow from Financing Activities Proceeds from fresh borrowings 59,685 (14,528) (18,597) (963) 1Dividend paid including tax (2,080) (4,738) (2,776) (2,776) (3,173)Others (2,265) - - - -Net Cash flow from Financing Activities (e) 55,340 (19,266) (21,374) (3,739) (3,172) Net Extra-ordinary Income (f) - (7,044) - - - Total Increase / (Decrease) in Cash 3,143 (3,649) 2,130 3,038 (1,945)(a) + (b) + (c) + (d)+ (e) + (f) Opening Cash and Bank balance 2,940 6,083 2,432 4,561 7,600Closing Cash and Bank balance 6,083 2,432 4,561 7,600 5,655Increase/(Decrease) in Cash and Bank balance 3,143 (3,651) 2,130 3,038 (1,945)



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FY09 FY10 FY11E FY12E FY13EPer Share Data (Rs) Diluted Recurring Earning per share (DEPS) 12.9 60.9 21.3 19.8 24.9Diluted Reported Earnings per share 17.0 38.4 21.3 19.8 24.9Recurring Cash Earnings per Share (CEPS) 41.8 72.7 59.9 60.9 69.0Free Cash flow per share (FCPS - post capex) (423.1) (187.7) (25.8) (10.5) (27.7)Book Value (BV) 316.5 340.9 354.0 365.6 381.2Adjusted Book Value (ABV) 316.5 340.9 354.0 365.6 381.2Dividend per Share 5.2 12.0 7.0 7.0 8.0

Valuation Ratios (x) Diluted Price Earning Ratio 27.4 5.8 16.5 17.8 14.1 Price to Recurring Cash Earnings per share 8.4 4.8 5.9 5.8 5.1 Price to Book Value 1.1 1.0 1.0 1.0 0.9 Price to Adjusted Book Value 1.1 1.0 1.0 1.0 0.9 EV / EBITDA 6.9 6.0 9.2 6.1 6.2 EV / Total Operating Income 0.2 0.2 0.2 0.1 0.1 EV / Operating Free Cash Flow (Pre-Capex) (1.4) (16.1) (2.8) (2.0) (2.0)EV / Net Operating Free Cash Flow (Post-Capex) (1.4) (3.4) (23.7) (58.6) (23.6)Dividend Yield (%) 1.5 3.4 2.0 2.0 2.3 Growth Ratios (% YoY) Diluted Recurring EPS Growth (41.7) 372.9 (65.0) (6.9) 25.9Diluted Recurring CEPS Growth (11.3) 73.9 (17.6) 1.7 13.2Total Operating Income Growth 13.4 (7.3) 33.8 22.8 0.4EBITDA Growth 82.2 26.0 (37.6) 51.2 4.3Recurring Net Income Growth (41.7) 372.9 (65.0) (6.9) 25.9 Operating Ratios (%) EBITDA Margins 2.6 3.6 1.7 2.0 2.1EBIT Margins 2.6 4.0 1.6 1.2 1.3Recurring Pre-tax Income Margins 0.6 3.1 0.8 0.6 0.8Recurring Net Income Margins 0.4 2.0 0.5 0.4 0.5Raw Material Consumed / Sales 106.5 94.9 99.0 100.9 100.7SGA Expenses / Sales 4.8 5.6 4.2 3.9 4.2Other Income / Pre-tax Income 127.2 51.5 113.0 3.5 4.8Other Operating Income / EBITDA 511.8 153.8 365.6 372.3 371.8Effective Tax Rate 38.7 35.4 33.5 33.5 33.5 Return / Profitability Ratios (%) Return on Capital Employed (RoCE)-Overall 5.3 7.6 4.3 4.1 4.2Return on Invested Capital (RoIC) 5.5 7.3 2.8 5.9 5.7Return on Net Worth (RoNW) 4.1 18.5 6.1 5.5 6.7Dividend Payout Ratio 30.9 31.2 32.9 35.3 32.1 Solvency Ratios / Liquidity Ratios (%) Debt Equity Ratio (D/E) 227.0 200.0 177.1 170.9 164.3Long Term Debt / Total Debt 19.6 23.2 24.8 24.6 20.0Net Working Capital / Total Assets 10.3 11.1 2.9 3.1 9.8Interest Coverage Ratio-based on EBIT 134.2 453.5 199.6 196.8 248.6Debt Servicing Capacity Ratio (DSCR) 142.6 546.9 286.4 296.9 389.5Current Ratio 37.7 44.9 49.6 56.7 60.7Cash and cash equivalents / Capital employed 37.9 26.0 21.7 19.4 15.6 Turnover Ratios Inventory Turnover Ratio (x) 9.7 8.5 9.6 10.2 8.6Assets Turnover Ratio (x) 3.4 3.0 4.0 5.0 4.9Working Capital Cycle (days) 18.5 15.0 7.4 3.5 6.2Average Collection Period (days) 7.1 8.3 6.3 6.7 8.4Average Payment Period (days) 83.4 84.4 71.3 67.4 82.4



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Tables Table 1: Refining-to-marketing volumes ...........................................................................171 Table 2: Surging under-recovery ......................................................................................172 Table 3: Sharing of under-recovery ..................................................................................172 Table 4: Pressure on profitability ......................................................................................172 Table 5: Pressure on cashflows........................................................................................173 Table 6: Product slate .......................................................................................................174 Table 7: Valuations ...........................................................................................................175 Table 8: P/BV valuations...................................................................................................176 Table 9: Profit and loss statement ....................................................................................178 Table 10: Balance sheet ...................................................................................................179 Table 11: Cashflow statement ..........................................................................................180 Table 12: Key ratios ..........................................................................................................181

Charts Chart 1: HPCL’s stock price vis-à-vis Brent......................................................................171 Chart 2: Rolling price/book trend ......................................................................................176


183

Annexure 4: International financial reporting standards – Impact on oil & gas sector Compiled by: Structured Finance Group, ICICI Securities, Headed by Mr Charanjit Attra

Likely impact on Indian companies uncertain

The following companies have been reviewed on the basis of quantifiable and non-quantifiable differences:

ONGC Under IFRS, the net worth of ONGC, as of March 31, ’10, could be positively impacted by the following:

• Amortisation of goodwill in the current year to be written back. As per IFRS, goodwill is not subject to amortisation but is to be tested annually for impairment. Such amortised amount of goodwill has been written back.

• Foreign exchange translation reserve (negative balance) being added back to the net worth.

Offset by:

• Foreign exchange loss, which has been capitalised, would be written off in the profit & loss account under IFRS.

• Unamortised miscellaneous expenditure would be charged to profit & loss account under IFRS.

• Capital reserve on consolidation would be charged to profit & loss account.

The following differences have not been considered due to lack of information in the public domain.

• Successful method of accounting is followed for oil & gas accounting. However as per IFRS 6, only costs that qualify to be treated as E&E assets are capitalised. All other costs are to be charged to profit and loss.

• The liability towards cost of dismantling & restoration is recognised when wells are complete. As per IFRS, decommissioning/restoration costs are to be provided for at the restoration cost of present value of such expenses, the cost being included in the gross block

• Loans are provided to employees. If such loans are provided at lower interest rates, the same are to be fair valued and such unrealised gains/ losses are to be taken to CIS.

• The company has doubtful debts of more than six months, which are to be tested for impairment annually.

• Fixed assets are to be depreciated over their estimated useful life on the basis of each components of the asset


184

Bharat Petroleum Corporation Under IFRS, the net worth of BPCL, as of March 31, ’10, would be positively impacted by the following:

• Foreign exchange translation reserve (negative balance) being added back to the net worth

Offset by:

• Accounting of capital reserves on acquisition of subsidiaries

• Unamortised miscellaneous expenditure would be charged to profit & loss account under IFRS

• Indirect expenditures capitalised would be charged to profit & loss account under IFRS

• Deferred Government grant would be charged to profit & loss account under IFRS


• The company has booked goodwill on consolidation, which is not subject to amortisation but is to be tested annually for impairment.

• Successful method of accounting is followed for oil & gas accounting and all acquisition, exploration & development costs are treated as CWIP initially; once ready for commercial production such costs are capitalised. As per IFRS only such costs which can be classified as E&E assets can be capitalised, all other costs are charged to profit & loss. The company, however, can follow either successful cost or full cost method.

• Decommissioning/restoration costs are to be provided for at the restoration cost of the present value of such expenses, the cost being included in the gross block.

• Where loans are provided at lower interest rates, the same are to be fair valued and such unrealised gain/ loss are to be taken to CIS.

• Long-terms (unquoted) investments are valued at cost. Such investments are to be fair valued by effective interest method any change being accounted through CIS.


• Fixed assets are to be depreciated over their estimated useful life on the basis of each components of the asset.


185

Hindustan Petroleum Corporation Under IFRS, the net worth of HPCL, as of March 31, ’10 would be negatively (marginal) impacted by the following:

• Unamortised miscellaneous expenditure would be charged to profit & loss account under IFRS

• Government grant would be charged to profit & loss account under IFRS

• Borrowing cost capitalised on exploration assets would be charged to profit & loss account

Offset by:

• Market development reserve taken to profit & loss account


• The company has the right to use intangible assets, which are not amortised due to its perpetual nature. Such intangible assets are to be tested annually for impairment and in case of an impairment loss, such are to be charged to profit and loss.

• Successful method of accounting is followed for oil & gas accounting and all acquisition, exploration & development costs are treated as CWIP initially; once ready for commercial production such costs are capitalised. As per IFRS, only such costs which can be classified as E&E assets can be capitalised all other costs are charged to profit & loss. The company, however, can follow either successful cost or full cost method.

• Decommissioning/restoration costs are to be provided for at the restoration cost of present value of such expenses, the cost being included in the gross block.

• Where loans are provided at lower interest rate, the same are to be fair valued and such unrealised gain/ loss are to be taken to CIS.

• Long-terms (unquoted) investments are valued at cost. Such investments are to be fair valued by effective interest method any change being accounted through CIS.



186

GAIL (India) Under IFRS, the net worth of GAIL India, as of March 31, ’10, would be positively impacted by the following:

• Deferred Government grant taken to profit & loss account

Offset by:

• Accounting for foreign exchange translation reserve

• Sales tax deferral account charged to profit & loss account


• The company has the right to use intangible assets, which are not amortised due to its perpetual nature. Such intangible assets are to be tested annually for impairment and in case of an impairment loss, such are to be charged to profit and loss account.

• The company has booked goodwill on consolidation, which is not subject to amortisation but is to be tested annually for impairment.

• Decommissioning/restoration costs are to be provided for at the restoration cost of the present value of such expenses, the cost being included in the gross block.

• Loans are provided to employees. If such loans are provided at lower interest rates, the same are to be fair valued and such unrealised gains/losses are to be taken to CIS

• Long-term (unquoted) investments are valued at cost. Such investments are to be fair valued by effective interest method, any change being accounted through CIS.


Gujarat State Petronet Under IFRS, the net worth of GSPL, as of March 31, ’10, would be negatively (marginal) impacted by the following:

• Indirect and other unidentifiable costs, which have been capitalised, would be charged to the profit & loss account

• Unamortised balance of miscellaneous expenditure charged to profit & loss account


• CWIP includes other costs whose nature is not identifiable. On assumption that such costs do not qualify as either tangible/intangible/financial assets, they have been charged to CIS.


187

• The company treats all expenditure on project till commissioning as CWIP, post which the same are transferred to the gross block. However, the maximum period of treating it as CWIP is not clarified nor the treatment if such a project is unsuccessful.

• Long-term (unquoted) investments are valued at cost. Such investments are to be fair valued by effective interest method, any change being accounted through CIS.

• Gas transmission pipeline are depreciated over an average period of 12 years, useful life being 30 years. All assets are to be mandatorily depreciated over their useful lives on each & every component of the asset.

Impact on group company policies

• Its holding company Gujarat State Petroleum Corporation (GSPC) applies the full cost method for its exploratory business. However, as per IFRS 6, only costs which qualify as E &E assets can be capitalised when incurred and all other costs are to be charged to the profit and loss account.

• Provision for dismantling & restoration is made as per technical assessment made by the company. However, such provisions are to be made at the restoration costs for the present value of the cost of dismantling, removal or restoration as a result of legal or construction obligation is recognised and corresponding costs are included a part of related property plant & equipment.

Reliance Industries Under IFRS, the net worth of RIL, as of March 31, ’10 would be negatively impacted by the following: • Accounting for capital reserve on consolidation

• Unamortised balance of miscellaneous expenditure written off to profit & loss account

Offset by:

• Capitalisation of exchange gain taken to profit & loss account

• Accounting of exchange fluctuation reserve

The following differences have not been considered due to lack of information in the public domain

• The company follows full cost method for Oil & gas activity. However, only costs which can be classified as E&E assets as per IFRS 6 can be capitalised; all other costs are to be charged to profit and loss account. Development costs are to be accounted as per IAS 29 (intangible assets).

• Long-term (unquoted) investments are valued at cost. Such investments are to be fair valued by effective interest method any change being accounted through CIS.



188


• No decommissioning costs have been provided. However as per IFRS, provisions are to be made at the restoration costs for the present value of the cost of dismantling; removal or restoration as a result of legal or construction obligation is recognised and corresponding costs are included a part of related property plant & equipment


189



190

ICICI Securities Limited has been mandated to act as one of the Book Running Lead Managers to manage the IPO of the group company of Gujarat State Petronet Limited, viz., Gujarat State Petroleum Corporation Limited. This report is prepared on the basis of publicly available information.

I-Sec investment ratings (all ratings relative to Sensex over next 12 months) BUY: +10% outperformance; HOLD: -10% to +10% relative performance; SELL: +10% underperformance

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Oil&Gas Sector 4 April'11 New

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Transcript of Oil&Gas Sector 4 April'11 New