jp morgan - global downstream - global refining - a long and painful sunset for many

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Global Equity Research08 September 2011

Global downstreamGlobal refining - a long and painful sunset for many

European Oil & Gas

Fred Lucas AC

(44-20) 7155 6131

[email protected]

J.P. Morgan Securities Ltd.

Nitin Sharma

(44-20) 7155 6133

[email protected]


Asian Oil & Gas

Brynjar Eirik Bustnes, CFA

(852) 2800-8578

[email protected]

J.P. Morgan Securities (Asia Pacific) Limited

Indian Oil & Gas

Pradeep Mirchandani, CFA

(91-22) 6157-3591

[email protected]

J.P. Morgan India Private Limited

LatAm Oil & Gas

Caio M Carvalhal

(55-11) 4950-3946

[email protected]

Banco J.P. Morgan S.A.

South African Oil & Gas

Alex Comer

(44-20) 7325-1964

[email protected]


For Specialist Sales advice, please contact

Hamish W Clegg

(44-20) 7325-0878

[email protected]

See page 198 for analyst certification and important disclosures, including non-US analyst disclosures.J.P. Morgan does and seeks to do business with companies covered in its research reports. As a result, investors should be aware that the firm may have a conflict of interest that could affect the objectivity of this report. Investors should consider this report as only a single factor in making their investment decision.

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Fred Lucas(44-20) 7155 [email protected]

Equity Ratings and Price Targets

Mkt Cap Price Rating Price TargetCompany Symbol ($ mn) CCY Price Cur Prev Cur PrevBP BP.L 112,353 GBp 372 OW n/c 575 n/cRoyal Dutch Shell B RDSb.L 196,675 GBp 1,993 N n/c 2,400 n/cENI ENI.MI 66,011 EUR 13.02 OW n/c 22.50 n/cEssar Energy ESSR.L 5,061 GBp 241 OW n/c 570 n/cGalp Energia GALP.LS 15,191 EUR 13.00 OW n/c 20.00 n/cOMV OMVV.VI 10,751 EUR 25.80 N n/c 29.00 n/cRepsol YPF REP.MC 31,546 EUR 18.46 N n/c 25.00 n/cStatoil STL.OL 71,247 NOK 121.00 UW n/c 145.00 n/cTOTAL TOTF.PA 99,585 EUR 31.69 N n/c 47.00 n/cPETROBRAS ON PETR3.SA 177,193 BRL 22.51 N n/c 35.00 n/cPETROBRAS ON ADR PBR 178,805 USD 27.42 N n/c 41.00 n/cPetroChina 0857.HK 344,831 HKD 9.69 UW n/c 9.00 n/cSinopec Corp - H 0386.HK 107,050 HKD 7.73 OW n/c 9.40 n/cIndian Oil Corporation IOC.BO 16,697 INR 317.10 N n/c 420.00 n/cReliance Industries Ltd RELI.BO 59,191 INR 833.50 OW n/c 1,200.00 n/cSasol SOLJ.J 29,017 ZAc 31,115 OW n/c 39,800 n/cSource: Company data, Bloomberg, J.P.Morgan estimates. n/c = no change. All prices as of 06 Sep 11 except for 0857.HK [07 Sep 11] 0386.HK [07 Sep 11] IOC.BO [07 Sep 11] RELI.BO [07 Sep 11].

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Table of ContentsStock specific summary ................................................................ 4

Global theme – refining capacity surplus ................................. 12

Alternative investment strategies to play the theme ............... 17

Why we might be wrong .............................................................. 21

Origin of downstream competitive advantages........................ 24

Refining capacity growth outlook .............................................. 31

Future imperfect ........................................................................... 38

The science and art of separation.............................................. 42

Downstream performance assessment..................................... 48

BP ................................................................................................... 54

Royal Dutch Shell B ..................................................................... 61

ENI .................................................................................................. 67

Essar Energy................................................................................. 71

Galp Energia.................................................................................. 76

OMV................................................................................................ 80

Repsol YPF.................................................................................... 84

Statoil ............................................................................................. 88

TOTAL ............................................................................................ 93

Petrobras ....................................................................................... 98

China: Refining and Marketing structure ................................ 106

PetroChina................................................................................... 108

Sinopec Corp – H........................................................................ 114

India: Refining and Marketing structure.................................. 121

Indian Oil Corporation................................................................ 123

Reliance Industries Ltd.............................................................. 127

Sasol............................................................................................. 133

AppendicesAppendix I: Downstream performance analysis .................... 146

Appendix II: Refinery transactions........................................... 156

Appendix III: Refinery projects data......................................... 159

Appendix IV: Global Integrated Valuation Update ................. 163

Appendix V: Downstream glossary of terms.......................... 164

Appendix VI: Valuation Methodology and Risks.................... 174

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Stock specific summary

We have analyzed the global refining capacity growth outlook 2011 to 2016 and conclude that any potential for a meaningful cyclical recovery in gross refining margins will be suppressed by excessive spare capacity that looks set to build as National Oil Companies aggressively add new capacity and incumbent International Oil Companies refuse to retire marginal capacity. Of the aggregate new capacity identified 2011-16 (up to+ 27.4 million bopd), we estimate that NOCs are sponsoring 67% (c.18.5 million bopd). We see a risk that a significant refining glut will materialize that will flatten regional refining margins on a 'bath-tub' bottom for some years to come. The outlook is ominously similar to the late 1970s when surplus refining capacity destroyed refining economics for several years – 40 years on, history may be about to repeat itself. With this as backdrop, we have also reviewed the downstream performance and strategies of 14 of the world’s largest oil & gas companies over the last 11 year period 2000 to 2010 in order to show which companies are best positioned for what could be a ‘long and painful sunset for many’, albeit not all refiners.

OECD – 9 focus names

BP - OVERWEIGHT - BP’s downstream business scores very well on a number of key efficiency parameters. BP has a well above-average refinery size (2010 167 kbopd), a below-average refinery throughput to equity oil output ratio (2010 102%) and its downstream business generates a consistently high return on downstream net fixed assets (2010 14%, 2000-10 average 15%). This measure of capital productivity is enhanced by a ‘capital lite’ fuels retailing model, a very strong lubricants franchise (Castrol) and a very efficient trading function. BP has delivered an average rate of network shrinkage (2000-10 -2.7%). BP’s historical refinery utilization has improved following the Texas City accident (2007 low of 77% has risen to a 2010 utilization rate of 91%). BP’s downstream free cash flow generation is also improving as capital expenditure normalizes and operating performance remains very robust (2010 $0.9 per barrel refining throughput). Consistent with BP's high scores and overall peer ranking (it ranks second of nine companies, see Table 7), BP’s downstream business continues to perform well, unlike its share price, which has generated a YTD 2011 return of -15% (7 September), following a 2010 return of -21%. We now measure an extreme 50%+ discount to our SOTP of around 800 pence (unchanged). Of this, we estimate that an ungeared BP Downstream has an EV of around $59bn (189 pence, 24% of our SOTP) – this implies a 2012E EV/EBITDA multiple of 6.5x, which compares to a global downstream median multiple of 5.6x (based on 27 companies).This multiple seems to us very reasonable given BP’s distinctive downstream scale and reach. We also note that the full year cash flow (EBITDA) benefits of the Whiting Coker will not be seen until 2013. We are convinced that the quality and value of BP’s downstream business has been completely overwhelmed by Macondo-related issues. Whilst the disposal of the Texas City and Carson refineries will help to demonstrate this value, we continue to believe that BP is one of the few companies that is best suited to pursue a more radical upstream-downstream dis-integration strategy and, importantly, in our view this would be a welcomed remedy to recover some of the substantial intrinsic value that is missing from BP's share price. BP’s CEO said after Q2 2011 results that all strategic options are under consideration. We hope that further consideration by BP’s board will lead to more radical corporate restructuring.

Refining industry may be about to press the ‘self-destruct’

button……as it did in the 1970s

BP’s downstream business scores and performs very well

on most metrics and ranks

second overall

See Table 7: Downstream

corporate scores and peer group ranking to see how each

company rates

We estimate BP Downstream is worth $59bn, 2012E EV/EBITDA

6.5x

Value of BP’s downstream has

been lost completely from the share price given 50% discount

to 800p SOTP

BP is a prime candidate to spin-

off its downstream business

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RD SHELL - NEUTRAL – RD Shell’s downstream business scores well on some, but not all of the same efficiency parameters. At just 100 kbopd, RD Shell’s average refinery size is below the peer group’s average of 128 kbopd. RD Shell has been slow to sell disadvantaged plants and also slow to shrink its global retailing network (2000-10 CAGR -1.3%) as management has only recently turned its ‘restructuring eye’ to RS Shell’s country retailing empires. On capital productivity, RD Shell also scores well below average (2010 6%, 2000-10 13%). RD Shell’s refinery utilization was average in 2010 at 82% (2000-10 average 88%) and its refining throughput to equity oil ratio too high, in our view (2010 172%). The one parameter where RD Shell scores well is downstream free cash flow generation when measured across the period 2000-2010, but we note that its performance on this metric in 2010 was mediocre (2010 $0.7 per barrel refining throughput). Similarly, RD Shell’s profit per barrel of refining throughput was slightly better than average when measured across the 11-year period, but it deteriorated notably in the more challenging period end 2009-10, highlighting its embedded high refining costs. On this basis, RD Shell ranks 3rd equal, alongside TOTAL. We acknowledge, however, that refinery sales in 2011 and further cost reductions will improve RD Shell's competitive positioning going forward. We would encourage management to go another step and reduce its refining capacity much further. Compared to BP’s 50% discount, RD Shell suffers a less extreme 20% discount to our SOTP of around 2600 pence. Our downstream EV for RD Shell is approximately $68bn or 685 pence per share (22% of our total SOTP). So, our estimated value of RD Shell’s downstream portfolio is 15% larger than our value of BP’s downstream portfolio ($59bn). We note that our RD Shell value of $68bn equates to a 2010 EV/EBITDA multiple of almost 10x assuming a 35% downstream tax rate. This seems fair enough, if not generous. Even if we assume that more recent refinery and retailing divestments add $1bn to downstream EBITDA, add $1bn of downstream cost reductions by 2012 and assume that both are fully retained, the implied 2012E EV/EBITDA multiple is 7.7x. This is higher than our implied multiple for BP’s downstream business of 6.5x.

ENI - OVERWEIGHT - ENI ranks 'middle of the pack' (5th) despite weak downstream operational performance - mainly due to the good progress made by the company in shrinking its retail network (-7% CAGR 2000-10) and its high refinery throughput to equity oil ratio, which improved from 104% in 2000 to 70% in 2010. On the operational front, ENI’s refinery utilization declined to a weak 75% in 2010 and the business reported an operating loss in both 2009 and 2010. ENI’s downstream business has also failed to generate free cash flow in last two years. We believe that given its ‘national’ status, ENI is unlikely to aggresively divest its loss-making refining business – but carrying these loss-making assets does not helpmanagement’s credibility, in our view. However, given the very small size (as a % of company EV) of this business, its performance has limited bearing on the overall valuation of ENI. We estimate that ENI's Downstream has an EV of around €1.9bn (2% of our SOTP EV of €111bn) – this implies a 2012E EV/EBITDA multiple of 3.8x, which compares to a global downstream median multiple of 5.6x. This seems reasonable given the very challenging outlook for this business. In our view, ENI's weak downstream performance is a fact that is well known by investors and most likely already factored in to the market’s views on the name. The ENI investment case continues to look compelling – the stock trades at a discount of 50%+ to our SOTP of c.€27 and it offers a safe and secure dividend yield of more than 7.5% - the highest in our European coverage universe. We maintain our bullish view on this name.

RD Shell downstream

performance ranks it third equal

alongside TOTAL

We would like to see more refinery and network

divestments

We estimate RD Shell

Downstream is worth $68bn, 2012E EV/EBITDA 7.7x

More of RD Shell’s downstream

value is in the share price given

20% discount to 2600p SOTP

ENI downstream performance

ranks 5th – weak operational

performace

Small downstream exposure is positive

Agressive divestment of

downstream assets is not on

management’s agenda

We estimate ENI Downstream is worth €1.9bn, 2012E EV/EBITDA

3.8x

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ESSAR ENERGY - OVERWEIGHT – Essar Energy's downstream business is defined by the company’s world-scale Vadinar refinery – this plant has delivered very high utilisation rates (2009-10 average of 127%) relative to its nameplate capacity. Vadinar has numerous and sustainable competitive advantages – a coastal location that can accommodate very large crude carriers (for large-scale oil imports) and product vessels (exports), below peer plant operating costs, a secure domestic market for its product output, the ability to reach overseas demand centres profitably and valuable local tax incentives. Essar Energy’s profit per barrel of refining throughput was healthy through the down cycle at $2.4/bbl (average 2009 and 2010) and it generated a 2009-2010 post tax average return of 9% on its net fixed assets. The ongoing expansion programme will double the refinery's complexity (NCI from 6.1 to 11.8) and increase its nameplate capacity from 230 kbopd to a world class 405kbopd in a two-staged process (expansion and optimisation) by end March 2013. Essar Energy has recently expanded its international refining footprint by acquiring Stanlow refinery in the UK (296 kbopd) – this asset will provide Essar Energy with storage/terminal facilities for product export from the Vadinar refinery. Our downstream EV (as included in our Essar Energy's sum-of-the-parts) is approximately $5.3bn. Given the aforementioned ramp up in the refining capacity and complexity by end March 2013, we see downstream EBIT potential in 2013E of approximately $1.2bn. Adding downstream depreciation of around $0.2bn, this implies a 2013E EBITDA of $1.4bn and an EV/EBITDA multiple of only 3.8x –which is conservative. The stock trades at a discount of c.50%+ to our SOTP. Essar Energy has declined more than 58% from its peak at the end of last year and now trades 41% below its listing price – this is despite significant progress by the company on its growth agenda. We believe that the market is now pricing in excessively high 'execution risk' in all its businesses and much of the value of its high quality refining business has been lost from the share price.

GALP - OVERWEIGHT – Galp ranks at the bottom of the peer group. In our view, its poor performance is largely due to its low complexity refining base, exposure to a challenging operating environment in Iberia (particularly Portugal) and aggressiveinvestment in low margin marketing assets in the up-cycle. Galp’s refinery utilization was significantly below average in 2010 at 75% (2000-10 average 80% vs peer group average of 87%). Also, given Galp's very low production base, its refining throughput to equity oil ratio is amongst the highest in peer group (2010 - 21x).Galp's retail network has grown by 1% CAGR 2000-10 (so no shrinkage) – mostly reflecting the company's acquisition of the Iberian marketing assets from ENI and ExxonMobil. Galp’s downstream business has also failed to generate free cash flow in the last three years, primarily due to heavy capex on upgrade projects. Similarly, Galp’s profit per barrel of refining throughput is significantly below the average when measured across the 11-year period. However, we do not believe that the performance of the downstream business has been or will be a primary stock price driver. We continue to believe that the weaknesses in the company’s downstream business are more than offset by the upside from its world class pre-salt assets in Brazil. We flag again the near-term potential trigger for this name - the capital increase in Brazil via a third-party buyer – which is still expected by end Q3. We estimate that Galp's Downstream has an EV of around €3.2bn (15% of corporate EV of €20.9bn) – this implies a 2012E EV/EBITDA multiple of 5.1x, which compares to a global downstream median multiple of 5.6x and seems fair.

Essar Energy – refining asset in

India has numerous and

sustainable competitive advantages

Refining capacity will grow 25%+

CAGR 2010-13

We estimate Essar Downstream

is worth $5.3bn, 2013E

EV/EBITDA 3.8x

Galp ranked at the bottom –

performance ought to improve

Investment in refining

complexity should be a plus for

the margins

We estimate Galp's Downstream

is worth €3.2bn, 2012E

EV/EBITDA 5.1x

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OMV - NEUTRAL – OMV ranks 7th or second last in the peer group. OMV’sdownstream business scores low on a number of key metrics. At just 88 kbopd,OMV’s average refinery size (own account) is significantly below the peer group’s average of 128 kbopd. OMV's refinery throughput to equity oil output ratio (2010 193%) is unattractively high, in our view. OMV's downstream business also generated a very low return on total downstream assets (2010 3%, average 2000-10 5%). Given the high capex spend (partially to fund acquisitions), OMV’s downstream business failed to generate free cash flow in 2009 and 2010. OMV'sretail network has grown by 5% CAGR 2000-10 (so no shrinkage as per GALP). We believe that the outlook for OMV’s downstream business remains challenging – the return on recent downstream investments (Petrol Ofisi) has already been shown to be very weak. We estimate that OMV's Downstream has an EV of around €4bn (26% of corporate SOTP of €16.2bn) – this implies a 2012E EV/EBITDA multiple of 4.9x,which compares to a global downstream median multiple of 5.6x. This is fair enough, if not generous, given the margin pressure that OMV's marketing business is facing in Turkey. It is clear that OMV has allocated a significant percentage of capital to the downstream business – so the challenging outlook for this business does not augur well for OMV's valuation. We also do not believe that management is looking to downsize the company's exposure to its downstream business. We retain our cautious stance on this name.

REPSOL YPF - NEUTRAL – Repsol YPF's performance is weak on a number of key downstream efficiency benchmarks. Given declining production in Argentina, Repsol YPF's 2010 refinery throughput to equity oil ratio was 236% - amongst the highest in its peer group. Repsol YPF’s refinery utilization has declined significantly in recent years and has averaged c.80% in 2009-10. Repsol YPF's downstream business has generated a below-average return – which has declined significantly in 2009 and 2010 (2010 6% versus 2000-10 average 11%). Consistent with Repsol YPF's low scores, it ranks sixth of the nine companies in our peer group. Whilst we concede that the investment in refinery upgrade projects will be a positive for the margins of the company's Spanish refining system, we also believe that given Repsol YPF's much improved credentials in its upstream business, the company avoid any other major downstream projects. As a reminder, Repsol YPF's earnings are more sensitive to refining margins than the oil price, especially given the upstream price regulations in Argentina – a fact that is unlikely to change in the near to medium term. We estimate that Repsol YPF's Downstream has an EV of around €11.5bn (31% of corporate SOTP of €36.5bn) – this implies a 2012E EV/EBITDA multiple of 4.2x which compares to a global downstream median multiple of 5.6x. This is fair enough, if not a shade conservative.

OMV ranks low – challenging

outlook

Downstream exposure has

grown, backed by acquisitions

We estimate OMV Downstream

is worth €4bn, 2012E EV/EBITDA

4.9x

Repsol ranks sixth – big

downstream footprint

Earnings exposure to European

refining will remain high

We estimate Repsol Downstream is worth €11.5bn, 2012E

EV/EBITDA 4.2x

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STATOIL - UNDERWEIGHT – Statoil ranks first, scoring very well on a number of key downstream efficiency metrics. Statoil’s historical refinery utilisation rate is the highest amongst its peers – its niche refining base has clearly been well operated (2000-10 average utilisation of 92%). The company also scores very well (top) on the 2010 refining throughput to equity production ratio given its small refining capacity is backed by such a sizeable upstream production base (2010 23%). Statoil has also delivered an above-average rate of network shrinkage – the divestment of a 46%stake in its marketing/fuel & retail business was a key step forward (2000-10 CAGR-5%). Statoil’s downstream financial performance is very robust (2010 Nkr35.6 or$5.9 per barrel refining throughput). Statoil’s downstream free cash flow generation is also very strong. We estimate that Statoil Downstream has an EV of around Nkr24bn (4% of our corporate SOTP of Nkr683bn) – this implies a 2012EEV/EBITDA multiple of 3.7x, which compares to a global downstream median multiple of 5.6x.This is fair, if not slightly conservative, in our view. Investor focus on this segment has been understandably limited given the company’s lack of meaningful exposure to the downstream business – we do not believe this is likely to change. We continue to believe that upstream operational performance needs to improve – this is key for a positive re-rating of this name and was addressed in our global upstream note last year (Global Integrateds, Upstream – the shape of things to come). We maintain our relatively bearish stance on Statoil given the lack of near-term catalysts and the risks of further disappointments on the operational front (e.g field outages).

TOTAL - NEUTRAL –TOTAL scores well on a number of key parameters and ranks 3rd alongside RD Shell. TOTAL's downstream business has consistently delivered a high return on capital (average 2000-10 ROFA 22%) and high refinery utilization (average 2000-10 89%). TOTAL scores well on downstream free cash flow generation when measured across the period 2000-2010, with only one year of negative cash flow. However, TOTAL's profit per barrel of refining throughput is below average when measured across the 11-year period, with a notable deterioration in 2009-2010 – like RD Shell, TOTAL’s downstream performance deteriorated notably into the downturn. TOTAL's refining throughput to equity oil ratio is also too high, in our view (2010 155%). Further, at just 98 kbopd, TOTAL’s average refinery size (own account) is significantly below the peer group’s average of 128 kbopd . We believe that the overall quality of TOTAL’s downstream business may beunderappreciated - the business has more often than not delivered good results.We expect further momentum from TOTAL in shrinking its downstream business in Europe – we note that the company has already announced a number of divestments YTD 2011 (CEPSA stake, divestment of UK marketing business etc). We estimate that TOTAL's downstream has an EV of around €18.6bn (14% of corporate SOTP of €129bn) – this implies a 2012E EV/EBITDA multiple of 5.9x, which compares to a global downstream median multiple of 5.6x. This is fair enough in our view, given the consistently strong performance of TOTAL's downstream business.

Statoil downstream ranks first –

very good operational

performance

Limited investor focus on the

company's downstream business

We estimate Statoil's

Downstream is worth Nkr24bn, 2012E EV/EBITDA 3.7x

TOTAL downstream

performance ranks 3th –

delivered healthy return on capital

Ongoing divestment will be a plus for overall performance

We estimate TOTAL's

Downstream is worth €18.6bn, 2012E EV/EBITDA 5.9x

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Table 1: Downstream earnings exposure of OECD names

Downstream earnings as % of group earnings 2003 2004 2005 2006 2007 2008 2009 2010 2011E 2012EBP 25 30 21 20 17 10 20 19 23 24ENI 8 10 10 6 3 5 -4 -1 0 1Essar Energy - - - - - - 71 67 69 55GALP - 50 62 65 41 131 19 38 31 52OMV 46 47 33 16 13 29 -16 15 5 14Repsol YPF 41 40 57 45 54 68 53 62 41 44RD Shell 24 37 33 28 26 19 14 12 16 20Statoil - - - 11 10 11 6 7 5 4TOTAL 19 26 25 22 21 18 12 11 10 13Group average % 23 28 25 22 21 16 11 13 12 15

Source: J.P. Morgan. * We have estimated post-tax downstream earnings as a percentage of clean group earnings.

Non-OECD – 5 focus names

SINOPEC - OVERWEIGHT - Given price controls during most of the last decade (period under study), refining in China scores very badly in this study. Sinopec ranks mostly 4th among the five emerging market companies, with a couple of third place ranks (not surprisingly in average refinery size and capex/DD&A ratio). With the change in pricing policy in early 2009, 2009-10 showed improvements on returns (Sinopec showing strongest returns in entire space in 2009-10) and profitability, and this is the environment we expect for the future (as long as crude doesn’t increase too fast, or even better, levels off or goes down). Sinopec has strong leverage to this environment and relatively high quality assets that should ensure good financial performance (its high reinvestment ratio has improved complexity in the system, allowing more heavy/sour crude intake). On the marketing side, Sinopec already has prime locations in the major consuming regions, and is adding non-fuel revenues to further improve overall R&M profitability. Our R&M EV (as included in our Sinopec’s PT) is approximately $50 billion or HK$3.5 per share. This represents 40% of our total sum-of-the-parts value of around HK$9.40 per share. Under normalized circumstances (ie GRM of around $5.5-6.5/bbl), we see downstream EBIT potential in 2012E of approximately $8 billion assuming stable profitability in marketing. Adding annual downstream depreciation of around $3bn, this implies a 2012E EBITDA of $11bn and an implied downstream EV/EBITDA multiple of 4.5x.

PETROCHINA - UNDERWEIGHT – Given price controls throughout most of the past decade (period under study), PetroChina’s downstream in China scores very badly in this study. PetroChina ranks 5th among the five emerging market companies across all parameters. With the change in pricing policy in early 2009, 2009-10 showed improvements on returns (PetroChina also showing stronger returns than non-EM refiners in this period) and profitability, and this is the environment that we expect for the future (as long as crude doesn’t increase too fast, or even better, levels off or goes down). PetroChina has less leverage to this environment than Sinopec (PetroChina is more integrated) and somewhat lower quality assets will require further investments to bring up quality (capex ratio has been low for PetroChina, with more focus upstream historically). On the marketing side, PetroChina is however ramping up to take market share versus Sinopec, although this requires expanding refining capacity in regions where it has no presence (higher consuming areas South/South-East). Our R&M EV (as included in our PetroChina DCF value) is approximately $40 billion or HK$1.40 per share. This represents 19% of our total sum-of-the-parts value of around HK$7.50 per share. Under normalized circumstances (ie gross refining margin of around $5-6/bbl), we see downstream EBIT potential in 2012E of approximately $3.5bn assuming stable profitability in

Price controls in China main

reason for weak ranking for Sinopec, with recent price de-

control changing the

environment

PetroChina needs to invest to improve asset quality

downstream after

underinvesting last decade

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marketing. Adding annual downstream depreciation of around $3bn, this implies a 2012E EBITDA of $6.5bn and an EV/EBITDA multiple of 6.2x.

RELIANCE INDUSTRIES - OVERWEIGHT - RIL's downstream segment is amongst the strongest globally, ranking 1st among emerging market players. World-leading refinery scale (1.24 million bopd, at a single location) and high complexity (14 NCI for its new refinery; 11.3 NCI for old), allow for lower than peer operating costs, and consistently enable RIL to deliver refining margins higher than Singapore benchmarks, and ensure high capacity utilization. Its location in Jamnagar, with easy access to port facilities that can handle VLCCs and large product carriers, conveniently places it to serve major Asian demand centres. A skew towards diesel in the product slate allows RIL to cater to a high-EM demand product. Labour costs in India are low, and coupled with high GRMs, have allowed RIL to deliver higher than normal returns on assets, and superior free cash flows. The refinery is ideally integrated with RIL’s petrochemicals business (naphtha, PX and propylene), with an off-gas cracker now planned as well. We estimate an EV of $30.6bn for RIL’s refining business, and an EV of $21.5bn for the petrochemicals business, for a per share value of Rs717 ($16/share) – which represents ~60% of our SOTP of Rs1200.

INDIAN OIL CORP - NEUTRAL – IOC is a large state-owned refiner in India that ranks second in the emerging market list. IOC has a total refining capacity of ~1.1million bopd, across 8 refineries, and also has a controlling stake in Chennai Petroleum. Its spread gives it ideal proximity to key product demand centres across India, and the company also has an extensive network of pipelines. Low capital and labour costs help to make returns competitive. The marketing business operates in a challenging environment, with prices of key auto (diesel) and cooking (LPG/Kerosene) fuels subsidized by the government. A portion of the subsidy loss is borne by the state-owned retailers, impacting profitability. An element of uncertainty on the extent of losses to be shared, coupled with high crude prices is particularly difficult, impacting the ability of these R&M companies to make significant investment plans. Our EV for IOC is $19.6bn ($8.1/share) – which includes value for the R&M, petrochemical and pipeline businesses. IOC also has a net cash/investments position of $1.2/share, for a fair value of Rs420 ($9.3/share). The uncertainty over timing/direction of fuel reform initiatives and lack of clarity on subsidy loss-sharing are key issues facing the company. However, with stable refining, pipeline and petrochemical income, IOC is relatively less impacted by these issues than its SOE peers.

PETROBRAS - NEUTRAL – Petrobras’ downstream segment is sometimes considered the ugly duckling of its business units, as the company does not automatically pass through international oil price variations to its domestic market. Given the historical dependence on diesel imports, and recent requirements to import gasoline (driven by high ethanol prices and increased demand), the segment now faces the undesirable contingency of domestically selling those fuels at prices cheaper than their acquisition costs. However, when expanding the horizon of analysis to the last ten years, we notice that Petrobras scores second among the National Oil Companies on net income per refinery throughput barrel (an average of $3.7/bbl), and would end up in the first half if we also included the OECD names. Its performance has been helped by Petrobras’s long-term policy – this has been not to pass through international oil price variations until the price reaches (and stabilizes) at what could be considered a “new standard” – this applies both for oil prices hikes and drops. In 2008, when international prices dropped from $140/bbl in June to

RIL’s scale, complexity and

location allow it to maintain higher than normal margins, and

service major Asian demand

centres

While IOC’s refining, pipeline

and petrochemical businesses

have performed well, uncertainty over sharing of subsidy losses,

coupled with high crude levels,

has impacted the marketing business, and stock sentiment

We value Petrobras’ downstream

segment in our SOTP valuation

at an EV of $24 bn, about 9% of our total NAV

11



$40/bbl in December, Petrobras kept selling its gasoline and diesel at stable prices.Looking forward, the short-term future does not look too bright for Petrobras’downstream segment in our view. Petrobras’ last new plant was completed in the early 1980’s, and in the past few years, average growth per year in refining capacity was no more than 1%. With the company running today at more than 90% utilization rate, if international prices do not fall and/or there is no increase in dometic ex-refinery prices for gasoline and diesel, we can expect the segment’s profitability to keep declining. There are two ways to overcome this issue: increase refining capacity or increase domestic prices. The first is already addressed, although we see no significant new capacity onstream until 2013. However, we see no room for domestic price adjustments until mid-2012, at the earliest. Nevertheless, we expect returns from the segment to improve, particularly after the new capacity is commissioned. We value Petrobras’ downstream segment in our SOTP valuation at an EV of $24 bn, about 9% of our total NAV.

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Global theme – refining capacity surplus

Global structural refining capacity excess may be sustained for many years –Our analysis confirms that the global refining industry is only entering the middle (not the end) of another period of very significant capacity growth 2010-16, led by regional additions in Asia (notably India and China), the Middle East (notably Saudi Arabia and the UAE) and Latin America (primarily Brazil). The risk of a growing capacity glut is very real given the following six factors. The net effect of this surplus will be reduced utilization rates – a primary driver of refining margins. Ergo, we expect refining margins to remain weak for some years to come.

1. National Oil Companies (NOCs) are less return sensitive - NOCs have government-sponsored mandates to build domestic refining capacity regardless of near-term commercial returns. They are motivated to create employment and inward investment, whilst controlling and capturing more of the barrel’s value and, in certain instances e.g. Brazil, to avoid exporting new domestic sources of crude only to then import more refined products.

2. Refineries never die, but they are often where capital goes to die – We detect International Oil Company (IOC) reluctance to retire capacity given a preferenceto ‘sit it out’ and find maverick buyers for marginal plants. The oil field depletion phenomenon which challenges global oil supply growth (Figure 1) simply does not exist in the refining sector – indeed, many refineries are like super giant oil fields…with adequate asset maintenance, they simply never die.

3. New owners have strategies that sustain marginal plant operations - Some of these new owners reset the depreciation base for the refineries and often have different strategic objectives and time horizons – either way, they sustain plant operations. We categorize such new owners as:

a. Private equity buyers – this class of buyer is now featuring much more prominently. They are not subject to short-term capital market performance imperatives and may see other option value in a refinery (terminal capacity, deep water port access, real estate conversion options etc). Example companies which have already bought refineries include Hyesta Energy and PBF Investments LLC.

b. New market entrants – these are not new players, they are existing refiners looking to access new markets, either to secure processing capacity for their crude or to secure market access for domestic product exports. An example is Essar Energy that has recently entered the UK market via its Stanlow refinery purchase from RD Shell.

4. Mega-refineries are the new greenfield facility scale of choice – We expect larger unit size additions, to create so-called mega-refineries, as the industry continues to up-scale green field sizes. This mirrors the trend to mega-liquefaction trains that have appeared in the LNG market in order to maximize scale economies. These much larger unit additions will more easily upset the capacity / demand equilibrium in any given year.

Capacity binge is set to

continue, led by Asian and

Middle East

13



5. Sluggish global demand growth looking more likely than not – For now, more sluggish global growth as fiscal austerity measures in OECD continue to bite deeper is looking more likely than not. J.P. Morgan’s US economist now sees a 30-40% probability of a second US recession. The IEA (August 2011 Monthly Report) has also warned that any reduction in the growth outlook for 2012 could have a big impact on expected oil consumption – it currently assumes 4.4% global GDP growth and forecasts demand growth of 1.61 million bopd (+1.8%), but if GDP growth softens to 3%, it estimates that demand growth will more than halve to 0.63 million bopd (+0.7%).

6. Fuel substitution and conventional refinery by-passes – Many governments are actively encouraging the development of bio-fuels, to promote local agriculture and domestic fuel supply security. Certain governments (e.g. US) are also looking to promote the expansion of gas-fuelled vehicles. A couple of industry players (Sasol and RD Shell) are also developing gas-to-liquids (GTL). The overall effect of these factors is to reduce the requirement for conventional refining and to reduce demand for refined product therefrom.

NOCs are driving refining capacity growth for reasons other than direct commercial returns - NOCs are the primary sponsors of this wave of capacity growth in order to maximize national energy security (minimize imports) and the total returns from domestic oil output (‘own the entire barrel’ strategy). Of the aggregate new capacity identified 2011-16 (c.27.4 million bopd), we estimate that NOCs are sponsoring around 67% (c.18.5 million bopd). NOCs are also being used by governments to extend foreign policy reach e.g. by using Chinese labor and financial capital to build refineries in Africa, China is extending its overseas positioning and influence. Low refining margins are therefore not necessarily an effective deterrent to new capacity formation, which may thus continue regardless of sub-optimal return expectations. Furthermore, we expect that continued investment in upgrading capacity will boost the supply of light, clean products and thus pressure upgrading margins.

Figure 1: 24 countries past oil output peak (kbopd) – 43% of 2010 global oil output

Source: J.P. Morgan, BP 2011 Statistical Review of World Energy.

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NOCs are driving capacity

growth, not IOCs

14



Figure 2: Refining capacity – net additions by region (kbopd)

Source: J.P. Morgan

Capacity growth data points to prolonged cycle bottom - Our global capacity model indicates that, under a BEAR case scenario (net capacity growth as identified coupled to 0% throughput growth in Europe and USA and 3% throughput growth in Asia and the Middle East), crude distillation capacity could rise from 91.8 milllion bopd at end 2010 to almost 109 million bopd by end 2015, 17% growth or almost 16million bopd (up to 3.2 million bopd per annum on average). Combined with sluggish product demand growth (more likely given the recent directional risk to regional GDP growth estimates), this will cause capacity utilization rates in the US and Europe to continue to decline and could cause the utilization rates in Asia + Middle East to collapse 2014-15. Low capacity utilization rates are synonymous with low margins, so under this scenario or an environment close to it, we believe that regional refining margins will remain depressed for some years to come.

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Figure 3: Regional utilization - BEAR case

Source: J.P. Morgan.

Figure 4: Regional utilization - BULL case


Capacity growth options are a real threat, the situation has an ominous similarity with the 1970s – During the 1970s, NOCs reasserted their industrypositioning via upstream asset expropriation, most notably in the Middle East. We now see some of the same NOCs and some new NOCs pushing for greater downstream influence and oil value chain control via the build-out of their domestic refinery systems and beyond. Given government backing and above-average investment time horizons, there is a good chance that numerous projects scheduled for start dates in 2015+ that have yet to be sanctioned or fully defined will progress.The potential scale of growth looks ominously similar to the situation in the 1970s which cratered refining profitability and enforced substantial capacity retirement. So, 40 years on (a time that is perhaps beyond corporate memories and is certainly longer than the career span of most oil company executives), history may be about to repeat itself.

The situation also has one ominous difference to the 1970s - Refining capacity growth during the 1970s created massive over-capacity which was followed by substantial capacity closures in the 1980s. Unfortunately, we see little desire amongst IOCs and NOCs to close capacity this decade. NOCs are less sensitive to low financial returns and are used by many governments that control them to protect the end consumer from free-market product prices. In addition, some IOCs are playing a risky game of brinkmanship, hoping for NOCs and other new entrants to buy and continue to operate their marginal facilities. These aspects of the current refining binge will only extend the cycle bottom for many years, in our view.

The situation reminds us of the marginalization of OECD vehicle manufacturing – In 1980 PR China produced 0.4% of total worldwide new vehicles. In 2010, PR China produced 24% of all new vehicles. In 1950, the US and Western Europe produced 98% of all new vehicles; by 2010 this had fallen to just 31%. We suspect that without changes to government policy to encourage domestic refining, OECD refining will follow the marginalization trajectory of US and European vehicle manufacturing, as it is gradually displaced by lower cost, lower taxed refining centers in Asia and the Middle East. Indeed, our capacity growth forecasts show that OECD refining may fall from 49% of worldwide capacity at end 2010 (54% in 2000) to 39% by end 2016. We see a future where Asia and the Middle East could become major product export hubs that supply the West. Under this scenario, less efficient coastal refineries in Europe and OECD may become attractive

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Ominous similarities to capacity

growth in 1970s….

….and some equally ominous

differences

OECD refining could follow

OECD vehicle manufacturing

16



infrastructure gateways for non-OECD refiners to access this import sink. So their strategic value will not be lost altogether, but it may change.

Refining capacity will sensibly co-locate close to new demand centers i.e. the vehicle parks - Refineries are best located closest to product demand centers i.e. closest to the car park. In 1986, PR China had 3.6 million passenger vehicles and trucks. By end 2010, that figure had increased to 80.0 million, a CAGR of 14%. If this rate of fleet expansion is sustained and the US vehicle park sustains its comparable rate of historical growth of just 1% per annum, PR China's vehicle park will be larger than the park in the US by 2021. Unattractive domestic pricing regimes and aggressive, government-mandated NOC growth strategies have deterred IOC participation in China's refining boom. IOC refinery growth options are thus paralyzed whilst prospective returns face mounting pressure as NOCs shift their strategies to a refined product export orientation. Some IOC refiners have responded to this threat by retrenching from refining, but many have yet to respond adequately to this threat.

Consequences for players that fail to act may be severe – IOCs can still mitigate the direct threat by divesting or joint venturing more disadvantaged capacity – it is not too late to act. In our view, some companies can and should consider replicating the disintegration strategies of Marathon Oil (enacted) and ConocoPhillips(proposed). From those companies that fail to respond, we see a risk of asset impairments, a higher frequency of negative earnings surprises and greater earnings volatility. As integrated entities, such companies carry the additional risk that persistently weak downstream performance contaminates the rating of the whole entity. Industry participants are often commended for taking a 'long-term view' of price and margin cycles. Our note presents a risk that we believe will play out over the long term – it is not too late to act.

New refineries will follow

demand

IOCs should divest more

capacity

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Alternative investment strategies to play the theme

Given our secular negative outlook on refining margins in all regions, perhaps the most obvious investment strategy is to avoid equities that are directly exposed to this specific activity in the industry value chain. However, we present investors with another six distinct investment strategies, as below, with particular listed names highlighted in Figure 8.

1) AVOID DOWNSTREAM ALTOGETHER - Focus on downstream ‘lite’, if not pure upstream players.

One of the easiest ways to play a negative trend is to avoid it altogether. In this instance, this may be done by investing in names with a zero exposure to refining, such as certain E&P names. In the integrated space, BG Group has zero exposure to refining and Statoil has a very small, high quality exposure.

2) INVEST IN REFINING CAPACITY GROWTH FACILITATORS – Focus on Engineering, Procurement & Construction (EPC) providers.

As is so often the answer, one of the best ways to play capacity formation in the oil & gas industry is not via its owners or its sponsors, but rather by the contractors that help to put the capital on the ground. In this instance, certain oilfield service names provide EPC services to the refining industry e.g. Tecnicas Reunidas and Technip.Given aggregate new refining capacity 2011-16 of 27.4 million bopd and assuming an average construction cost of $23,000 per bopd (Figure 5), the potential capital investment over this period could reach a staggering $630bn.

Figure 5: Refining capital costs


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Seven ways to play the negative

refining theme

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3) INVEST IN REFINERY SOFTWARE PROVIDERS – Focus on software & consultancy providers.

There are a few specialist technology providers that provide software, automation and management consultancy services to the refining community. These services can help to debottleneck refineries and enhance profitability. Examples include Aspen Technology and Honeywell International.

4) ANTICIPATE CORPORATE RESPONSE – Look for consolidation options.

We believe that a prolonged cycle bottom will necessitate consolidation amongst a large population of smaller, disadvantaged players - this may encourage opportunistic bids from better capitalized, more advantaged players. In the US, we note the recently completed merger between Holly Corp and Frontier Oil, to create the enlarged HollyFrontier Corp. Similarly, we suspect that certain crude producers may look to anchor processing rights in parts of the OECD by purchasing refineries e.g. Rosneft’s recent purchase of PDVSA’s 50% stake in Ruhr Oel - the owner of stakes in four refineries in Germany. Furthermore, certain refined product exporters may look to use refineries as terminal gateways to enable their product exports to reach new demand centers e.g. Essar Energy's recent acquisition of RD Shell's UK Stanlow refinery.

5) ANTICIPATE CORPORATE RESPONSE – Look for vertical disintegration candidates.

Following the well received and successful upstream-downstream split by Marathon and the intended split by ConocoPhillips, we see few other potential candidates who might be prepared to follow this radical corporate restructuring option. However, one name that could logically follow this break-up option with strong shareholder support is BP. We note that the CEO commented following its Q2 2011 results that all strategic options are under consideration.

6) TRADE THE MARGIN VOLATILITY, EXPLOIT EXCESSIVE MARKET OPTIMISM – Focus on pure play trading options.

Notwithstanding our negative outlook for refining margins, we do not doubt that there will be periods when refining margins in certain regions will spike due to one or more of the following factors. These factors will inevitably trigger margin spikes accompanied by bouts of optimism that the ‘cycle is turning’. There are a number of listed pure play refiners that may be traded for short-term benefits.

unexpected plant outages – e.g. Asian margins are currently benefitting from the closure of Taiwan’s 540 kbopd Mailiao refinery, one of the world’s largest refineries, following the seventh fire in 12-months. Formosa Petrochemical Corp. declared force majeure on its product exports for August. JPM’s analyst (Brynjar Bustnes) notes that FPCC will essentially have all its units up and running by October. It is in the process of starting up its #2 and #3 CDU while #3 Olefins will re-start by end September. The company expects average Q3 refining utilization rate to be 52% (vs. 74% in QQ) and Olefins utilization rate to be 65% (vs. 85% in Q2). The conflict in Libya has also led to much reduced throughput at the Tobruk and Zawiya refineries.

crude evacuation bottlenecks – e.g. PADD 2 refineries in the USA continue to benefit from depressed WTI feedstock costs due to rising oil shale output and

19



limited pipeline evacuation capacity Which have elevated PADD 2 oil inventories (Figures 6-7). This has been cited as a key benefit by HollyFrontier (created with effect 1 July 2011) that could endure until the Keystone Pipeline (which will transport crude oil from Cushing to the Gulf Coast) opens in mid-to-late 2013. As such, this is a durable and investable theme. We note that of the European names featured in this note, BP has the highest exposure to WTI costed oil feedstock (c.485 kbopd or 20% of 2010 global refining throughput via 50% owned Toledo refinery and 100% owned Whiting refinery).

price distortion effects – e.g. in PR China, government pricing controls have pushed mainland refineries into losses (the Ministry of Industry and Information Technology released a report in August stating that the Chinese refining industry recorded a loss in May, its first since 2009). This has encouraged reduced throughput and inventory consumption.

tax distortion effects – e.g. changes to Russia’s complex export duties can encourage upstream producers to export more refined products rather than crude; this flow of products can impact European refining margins both positively and negatively.

seasonal effects – e.g. if certain US refineries do not return from maintenance as expected ahead of the US summer driving season.

weather effects - e.g. hurricane damage to refineries on the Gulf Coast or an interruption to refinery crude supplies and related demand destruction due to curtailment of industrial activity and reduced transportation requirements.

Figure 6: PADD II oil inventories - million barrels

Source: US DoE

Figure 7: Brent less WTI oil price differential ($/bbl)


7) PICK SOME REGIONAL WINNERS – Look for sustainable competitive advantage.

Notwithstanding our bearish view on global refining margins, there are a few advantaged regional refiners that ought to survive a prolonged downturn very well. Such players must be located in structurally high growth, product deficit markets. They must have very large coastal facilities, ideally with high plant complexity and integration synergies with adjacent petrochemical facilities that were built at low cost, often with the additional benefit of special tax incentives. We identify two such advantaged names with refining operations in India - Reliance India and Essar Energy.

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Figure 8: Seven possible investment strategies to play refining capacity surplus theme

Source: J.P. Morgan - not all of these names are covered by J.P. Morgan.

GLOBAL INVESTMENT THEME Refining capacity growth

SOFTWARE PROVIDERSEuropeKBC Advanced Technologies [KBC LN]USAAspen Technology [AZPN US]Honeywell International [HON US]

EPC PROVIDERSEurope & North AmericaFluor Corp [FLR US]SNC-Lavalin Group Inc [SNC CN]Technip SA [TEC FP]Tecnicas Reunidas SA [TRE SM]AsiaChiyoda Corp [6366 JP]Daelim Industrial Co. Ltd [000210 KS]Samsung C&T Corp [000830 KS]Worley Parsons Ltd [WOR AU]

DOWNSTREAM ‘LITE’EuropeBG Group [BG/ LN]ENI [ENI IM]Statoil [STL NO]

CONSOLIDATION OPTIONSEuropeERG SPA [ERG IM]Petroplus Holding AG [PPHN SW]Saras SPA [SRS IM]

DISINTEGRATION POTENTIALEuropeBP [BP/ LN]USAConocoPhillips [COP US]

(1) AVOID Strategy

(4-5) CORPORATE RESPONSE Strategies

(2-3) INDIRECT PLAY Strategies

PURE PLAY TRADING OPTIONSEuropeNeste Oil [NES1V FH]USAAlon USA Energy [ALJ US]Delek US Holdings [DK US]Marathon Petroleum Corp [MPC US]Tesoro Corp [TSO US]Valero Energy Corp [VLO US]Western Refining [WNR US]AsiaBangchak Petroleum [BCP TB]Caltex Australia Ltd [CTX AU]S-OIL Corp [010950 KS]SK Innovation Co. Ltd [096770 KS]

(6) TRADINGStrategy

(7) REGIONAL WINNERS Strategy

ADVANTAGED PLAYERSUSAHollyFrontier Corp [HFS US] AsiaReliance Industries [RIL IB]Essar Energy [ESSR LN]

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Why we might be wrong

The foundation of our cautious refining margin outlook rests upon an analysis of the outlook for the global refining capacity balance. This analysis hinges on an assessment of over 200 greenfield and brownfield refinery projects for 2011-16 spread around the world, involving numerous sponsors (IOCs, NOCs, governments and smaller independents and investment consortia), many of which have poor track records delivering major facility construction on time and on budget. Furthermore, the oil & gas industry has numerous economic feedback loops (prices, margins and costs) that can constrain the pace of investment, both upstream and downstream.

So, we are the first to acknowledge that the rate of refining capacity growth could be lower than we forecast. We cite five specific factors that could reduce the rate of net capacity additions.

1. Delays to government approval, construction and commissioning –Most new refining projects require government approval of one sort or another. In the current sovereign debt crisis, we have been reminded of how weak coalition governments can be slow, if not fail outright, to take appropriate, albeit tough decisions. The same problem can apply to the approval process for major energy projects, especially if they are seen to be controversially expensive. An example of this can be seen in Kuwait – its 615 kbopd new refinery near Az-Zour was first conceived in 2005, yet the country’s Supreme Petroleum Council still has yet to approve it. Costs for this project, originally estimated at $7bn, have since risen to $15bn ($24,400 per bopd). Every new refinery in China must be approved by the central government, which is increasingly aware of environmental impact and the risks of local labour inflation. In India, the early stage state approval for land allotment (as per the coal mining sector) can also take much longer than expected. Furthermore, refining projects are no different to upstream projects – they tend to take longer than scheduled to build and commission.

2. Political uncertainty – Many new refinery builds require foreign participation with local players, either via direct equity co-ownership or via the provision of loans. Such foreign-sourced capital may withdraw if countries exhibit excessive political instability. Three examples of countries with ‘tenuous’ refinery projects that are exposed to political uncertainties include: (i) Egypt - a 200 kbopd greenfield project has been proposed by a group of Saudi and UAE investors (Citadel Capital) (ii) Libya – Tamoil (100% government-owned) had proposed a 200 kbopd greenfield project at Zuwara; this is an unlikely priority for the National Transitional Council(iii) Nigeria – NNPC is looking to build two new refineries, one in Lagos (300 kbopd) and one in Central Kogi State (150 kbopd).

3. Unexpected changes to government policy – We believe that energy security will remain a top strategic priority for all countries, OECD and non-OECD, for decades to come. This is a key factor that is encouraging countries to ‘in-source’ oil processing – they want to develop a captive refining system to reduce, if not extinguish refined product import needs. We cannot see any reason for this core policy driver to change, but that does not mean that such a reason may not exist. No one anticipated the

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catastrophic Fukushima earthquake / tsunami and its impact (negative) on government desires to build energy dependency on nuclear power and itssecond order impact (positive) on global LNG demand.

4. Sovereign liquidity constraints – Many of the greenfield refinery projects rely on direct (via wholly owned NOCs) or indirect (via partially owned NOCs) sovereign funding. Although it looks unlikely, given the current buoyant oil price, certain petrodollar wealthy governments may face budgetary pressures, especially if social budgets escalate post-the Arab Spring. Potential examples in the Middle East may be Iran (where access to capital is further constrained by economic sanctions) and the UAE. Iran has aspirations to build at least 6 new refineries to add a total capacity of 1.2 million bopd and ADNOC (via Abu Dhabi Oil Refining Co.) is also adding a 400 kbopd refinery at Ruwais. In Latin America, PDVSA (Venezuela), Ecuador (Petroecuador) and Cuba (Cupet) are all effectively financially isolated and all three countries face similar budgetary challenges. Mexico is not financially isolated, but the ability of its dominant NOC (Pemex) to deliver the country’s first new refinery in over 30 years (200 kbopd project in Tula, Hindalgo) must be questioned given the government’s high dependency on dividends from the nation’s only substantial ‘cash cow’.

5. Persistently weak refining margins could trigger more capacity closures– As we have highlighted, refinery capacity closure can often prove all too temporary as plants are mothballed rather than dismantled, leaving their owners (current or future) the tactical option to re-start should margins ever improve. However, a very prolonged period of very weak margins (as we expect will occur) could encourage more commercially driven owners of marginal plants to consider closure, either temporary or permanent. We note, however, that we require a very substantial increase to the current closure schedule (Table 2), to really make a difference to the global capacity balance, especially in Europe. Excluding plants that have been closed and then re-opened (Delaware City and Wilhelmshaven), we estimate a total potential capacity closure of less than 2.3 million bopd 2009-2016. To avoid a capacity glut, this amount of capacity would have to be closed almost every year from 2011 to 2016 to negate capacity growth. At present, there is just no evidence that this is at all likely to occur as participants hold out for ‘better times ahead’ or maverick buyers and hope to avoid politically controversial plant closures.

These ‘upside risks’ to the global capacity balance are real enough - we therefore address them in our BULL case scenario analysis. However, we note that a common feature to all these factors is that they can only really influence the picture in 2014 and beyond i.e. they are unlikely to make a material difference to the capacity excess that will persist in 2011-13 – not least because we start with a significant capacity excess in 2011.

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Table 2: Refinery capacity retirement

PlantCapacity

kbopd Owner Comment

2009 Eagle Point, USA -145 Sunoco Closed October 2009Teesside, UK -117 Pluspetrol Closed March 2009Bakersfield, California -60 Flying J Closed February 2009Delaware City, Delaware -210 Valero Closed November 2009, but re-opened by PBF in Q2 2011Dunkirk, France -137 TOTAL Closed September 2009Normandy, France -80 TOTAL Closed August 2009

2010 Yorktown, Virginia -128 Western Refining Closure completed Q4 2010 - converted to a storage terminalWilhelmshaven, Germany -260 ConocoPhillips Closed after fire in May 2010, but recently sold to Hyesta Energy that intends to open it

2011 Montreal, Quebec -130 Shell Operated as terminal since November 2010Toa Keihin Ohgimachi -120 Showa Shell To close Sept 2011 when next turnaround is scheduledMizushima, Negeshi, Oita, Kashima -225 JX Holdings Mizushima closed July 2009Texas City, Texas -76 MarathonReichstett, France -78 Petroplus Closed April 2011 - to be converted to terminalHonolulu, Hawaii 0 Chevron Still running as a refinery following renegotiated contractKurnell, Australlia 0 Caltex Plant under review (announced 22 Aug 2011)Arpechim, Austria -70 OMV Romanian government is now supportive of closure

2012 Cremona, Italy -80 Tamoil Final closure in H2 2011 - conversion in to storage siteHarburg, Germany -108 RD Shell Failed to find a buyer - to stop processing crude Q1 2012

2013 Clyde, Australia -80 RD Shell Converting it to a fuel import terminal to avoid $106m maintenance mid-2013Various -100 IdemitsuBerre L'Etang -105 LyondellBasell Under reviewCartagena, Colombia -40 Ecopetrol Mothballed to support new refinery

2014 Toyama -60 JX HoldingsOthers -115 JX Holdings

2016 Shuaiba, Kuwait -200 KNPC To continue to use infrastructure and loading jettiesCAPACITY RETIREMENT -2,724


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Origin of downstream competitive advantages

As per Table 3, we believe that it is possible for the ‘best in class’ players to derive acceptable returns from the downstream suite of businesses across multiple cycles provided they possess and sustain all the key competitive advantages that we cite for each of the three key streams (refining, retailing and lubricants – see Appendix IV for glossary of terms).

Table 3: Origin of downstream competitive advantage


Plant scale Respected brand Established power brand

- > 150 kbopd - customer loyalty - customer loyalty

Plant complexity Incumbency Brand support

- crude diet flexibility - ideally top 3 market share - effective advertising

Location Location Streamlined product suite

- coastal for VLCC imports - high throughput zones - capture trading up

Location Location Synthetic lube offering

- low cost labour, tax concessions - real estate option value - premium priced market

Location Market dynamic Global reach

- close to demand centres - growing car park / fuels demand - scale economies

Market dynamic Differentiated fuels R & D program

- product deficit - premium pricing - sustained product development

Construction timing Non-petroleum merchandise OEM relationships

- in to cycle bottom - higher margin, lower tax - first fill, OEM endorsement

Asset integrity / reliability Ownership Blending capacity

- maximize availability - dealer not company owned - less vital to produce base oil

Integration to petrochemicals Regulation

- feedstock & facilities planning - no pricing controls

Storage / terminal capacity Planning controls

- maximise arbitrage - restrict new entrants

Trading function Biofuels capability

- feedstock routing / product placement - future growth option

Energy Intensity

- on site cogeneration capacity

Emissions

- minimise carbon footprint

------> ACCEPTABLE RETURN BUSINESS <-------

------> GLOBAL OR NICHE <-------

<-------------------------------------------------- Ownership flexbility -------------------------------------------------->

- optimise capital redeployment across cycle

KEY VALUE DRIVERS

REFINING RETAILING LUBRICANTS

- exercised efficiently

<-------------------------------------------------- Corporate planning -------------------------------------------------->

- long term horizon, staying power

<--------------------------------------------------------- Best people -------------------------------------------------------->

- correctly incentivised for operational & HSE excellence

<------------------------------------------------------ Best contractors ----------------------------------------------------->

- incentivised for operational excellence, adequately supervised with clear policies & procedures

<-------------------------------------------------------- Asset control ------------------------------------------------------->

Downstream competitive

advantage is hard to retain

25



As per Figure 9 and Figure 10, the industry’s conventional suite of downstream businesses bears a range of capital intensity and return variability across the cycle. We prefer the specific businesses which consume low levels of capital and which generate the least volatile returns e.g. fuels retailing (especially if through dealer-owned as opposed to company-owned sites) and lubricants (especially if exposure is limited to lubricant blending and marketing as opposed to base oil refining and chemical additive production). The capital requirements of other businesses e.g. shipping, may be reduced by chartering as opposed to owning vessels and e.g. Trading may be reduced by disciplined risk management. Unfortunately, the only practical way to reduce capital exposure to refining is by selling assets – no oil company dare outsource the operations of a refinery to a third party.

Figure 9: Downstream businesses - capital intensity versus return variability


Figure 10 further categorizes these downstream businesses according to market entry barriers and the potential for large, unexpected (low probability) losses (a risk that the equity capital market tends not to price efficiently). Again, refining is located in the least favorable place with low entry barriers (typically limited to capital access which is an easily surmountable obstacle for NOCs) and the high impact potential for large unexpected losses due to plant outages, if not facility damage due to industrial accidents.

COMMERCIAL, MARINE, AVIATION

REFINING

VO

LA

TIL

ITY

OF

RE

TU

RN

S

CAPITAL INTENSITY

SHIPPING

SPECIALITY CHEMICALS

TRADING

RETAILING

LUBRICANTS

Low Medium High

Lo

wM

ed

ium

Hig

h

Least desirable exposure

Most desirable exposure

Charter

Risk Mgt

Blend only

Dealer owned

Refining is capital intensive with very volatile returns

26



In our view, the return profile from refining is thus asymmetrical – we see zero prospects of very high returns, a high probability of prolonged low returns and a sustained small probability of large losses – a very unattractive risk-reward mix, in our view. In contrast, businesses such as fuels retailing and lubricants are protected by more substantial entry barriers related to corporate branding, protected / concealed product formulation and market positioning. Although these businesses have limited real pricing power, they benefit from superior cost pass-through capabilities.

Figure 10: Downstream businesses – potential for large losses versus segment entry barriers


So, on all key dimensions, we consider refining to be the least attractive component of the downstream value chain. In contrast, we see fuels retailing and lubricants as superior businesses.

As this note goes on to show, we believe that refining returns will continue to deteriorate, leaving certain incumbents with some tough strategic options. However, we must also highlight that certain regional refiners bear many of the competitive advantages that we have highlighted in Table 3. We give two specific examples in Table 4 - Reliance Industries and Essar Energy.

COMMERCIAL, MARINE, AVIATION

REFINING

PO

TE

NT

IAL

FO

R L

AR

GE

LO

SS

ES

ENTRY BARRIERS

SHIPPING

SPECIALITY CHEMICALS

TRADING

RETAILING LUBRICANTS

Low Medium High

Lo

wM

ed

ium

Hig

h

Least desirable exposure

Most desirable exposure

Risk of major industrial accident

Risk of rogue trader

Branding, positioning

Risk of major industrial accident

Risk of major oil spill

Refining has low entry barriers

and bears the risk of large

losses

Refining is the least attractive

link in the downstream chain

27



Table 4: Competitive positioning of two advantaged niche refiners

Reliance Industries Essar EnergyPlant scale World leading -

Jamnagar I - 660 kbopd Jamnagar 2 - 580 kbopd

Vadinar refineryPost phase 1- 375kbopd (Mar'12) Post optimisation - 405kbopd (Mar'13)

Plant complexity Jamnagar I NCI - 11.3 Jamnagar II NCI - 14.0

Vadinar post phase 1 NCI - 11.8

Location Coastal - adjacent to Jamnagar port (Sikka) which can handle VLCCs and large product carriers

Also located on west coast of India - in the refining hub of Jamnagar

Location Advantaged by low cost labour in India Special tax consessions in Gujarat

Also benefits from low labour costs and sales tax concessions in Gujarat

Location Close to domestic &Middle East crude supply sources and well located for certain key export markets

Close to domestic crude supply sources and well located for certain key export markets

Market dynamic India is a product deficit market for LPG and is experiencing high growth in diesel demand

High growth in diesel demand in India augurs well for Essar Energy - higher middle distillate yield post expansion

Construction timing Built ahead of inflationary up-cycle with low unit capex

Vadinar construction experienced significant delays and cost overruns

Asset integrity / reliability

Consistently runs above 100% of nameplate capacity

Average utilisation for 2009-2010 was an impressive 127%

Integration to petrochemicals

Integrated to petrochemicals facilities which are being expanded to take more refinery gas

No petrochemicals facilities

Storage / terminal capacity

Rights to various storage sites, particularly East Africa via GAPCO

Recent acquisition of Stanlow refinery (UK)- flexibility following acquisition ofstorage/terminal faciltities in Europe

Trading function Well developed in-house trading capabilities

Competent in-house trading capabilities

Energy intensity Low energy costs On-site power generation

Low energy costs On-site power generation (Vadinar power plant - under construction)

Emissions Looking to use more refinery gases for petrochemicals and to reduce carbon footprint further

Going through a carbon emissions accounting process - plans to come up with a carbon management action plan

Overall competitive positioning

VERY STRONGLY POSITIONED STRONGLY POSITIONED


28



Sources of refining return erosion

Unfortunately, very few companies possess all the aforementioned competitive advantages and too many companies ‘kid’ themselves that they do, which sustains an inefficient downstream presence. Too much optimism and insufficient realism has long dogged this industry, in our view - the downstream is a challenged business, especially refining. We continue to believe that it faces a number of very tough years ahead given growing excess refining capacity and ever more onerous operating and environmental conditions. In the schematic below, we highlight some of the key factors that will erode downstream returns (in addition to capacity growth), most specifically from refining, which is the most capital intensive downstream activity.

From a supplier perspective, we see three key risks to the outlook for asset returns:

Very slow IOC capacity retirement – IOCs have been reluctant to retire marginally profitable / loss-making refining capacity, preferring instead to try and sell it to another player who will sustain operations. Sunk costs are forgotten, the capital base is reset and such plants are run to be cash flow positive, if not for strategic reasons e.g. to help to develop a presence in new markets.

NOC-sponsored capacity growth – The entry barriers to refining are very lowe.g. the technology has been commoditized. NOCs are the primary participants that are sponsoring capacity growth – they have easy access to abundant and relatively cheap capital. They have several motives – national product supply security, local employment, inward investment – but commercial returns do not typically feature that prominently.

Rising cost of asset maintenance - The costs of asset maintenance continue to rise given underlying inflation in labor, software systems and hardware (steel pipes and units) and ever tighter regulatory scrutiny following some high profile accidents e.g. Texas City.

Figure 11: Factors eroding downstream returns


OECD and non-OECD governments also play an important role in accelerating the decline in refinery returns:

Tighter product specifications – Governments push for lower sulfur content fuels. This increases the burden on refiners to add de-sulfurization units, thus

STRUCTURAL & SUSTAINED PRESSURES ON DOWNSTREAM RETURNS

Slow IOC capacity retirement

NOC sponsored capacity growth

OECD fuel efficiencies

Biofuel substitution

Costing of carbon emissions

Rising cost of asset maintenance

Tighter product specifications

Actions of suppliers Actions of government Actions of consumers

Implicit-explicit retail price control

Product price sensitivity

Refining has all the hallmarks of

a ‘bad industry’

Pressure from suppliers

Pressure from governments

29



increasing their costs of ‘staying in the game' without providing any incremental pricing advantage. As product specifications are raised around the world, they also tend to converge. This will remove an element of protection that has hitherto protected some markets from ‘product dumping’.

Mandates for improved vehicle energy efficiency - As per Figure 14, the US (the country with the world's largest number of vehicles), has set a federal fuel standard (Corporate Average Fuel Economy – CAFE – sales-weighted combined city/highway miles per gallon, for new car sales) which requires a very substantial improvement in the engine efficiency of new cars by the beginning of the next decade. By 2025, major automakers have agreed to reach an average of 55 miles per gallon - to be achieved by raising car fuel efficiency by 5% per annum and light truck fuel efficiency by 3.5% per annum from 2017-2021 and then by 5% per annum from 2022. This will be achieved by greater conventional engine efficiency and a higer penetration by hybrids and electric cars. Automakers may also look to develop more efficient natural gas-fueled combustion engines. As per Figure 12, the transportation sector is the largest consumer of (refined) oil – so changes to its fuel diet can have a potentially material impact on the demand for gasoline and diesel (refined products).

Figure 12: Composition of global oil demand

Source: Exxon Mobil – The Outlook for Energy - A view to 2030 (December 2006)

Figure 13: Composition of uses within transportation market

Source: Exxon Mobil – The Outlook for Energy - A view to 2030 (December 2006).

Initiatives to encourage lower carbon fuel substitution – A recent example of this in the US is the New Alternative Transportation to Give Americans Solutions Act (NAT GAS Act) – this is to be heard by the US House of Representativessubcommittee in September. This Act will provide federal incentives for the use of natural gas as a vehicle fuel, the purchase of natural gas-fueled vehicles and the installation of natural gas vehicles fueling properties. We note that the Natural Gas Vehicles for America (NGVA) group estimates that in 2009 c.18% of all transit buses ran on natural gas.

Costing of carbon emissions – This is a fast evolving trend whereby governments are taxing either the oil producers or the fuel manufacturers for the carbon emission consequences of refined product combustion. Refineries typically lose the legislative battles. Assuming a $25 per ton CO2 price, a 100 kbopd refiner would have to spend almost $320 million annually on CO2 credits to cover both direct and indirect emissions. It will be very difficult for refiners to pass these costs on to consumers – refiners are both cost and price takers.

0

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120

1980 1985 1990 1995 2000 2005 2010 2015 2020 2025 2030

TRANSPORTATION 1.8%

INDUSTRIAL 1.3%

RESIDENTIAL / COMMERCIAL 0.2%POWER GENERATION -0.2%

Average growth 2000-30 1.4%

53

%

58%

Light Duty Vehicles28%

Rail4%

Marine11%

Aviation12%

Heavy Duty Vehicles45%

30



Implicit-explicit retail price controls – This applies to a number of emerging markets. Essentially, in order to protect the end consumer from volatile and high fuel prices, governments require refiners to suppress factory gate (wholesale) / pump (retail) prices. Refiners are subsequently compensated for their losses, but often incompletely and some time after the losses are incurred. This occurs in a number of emerging markets e.g. India.

Figure 14: New car U.S. Corporate Average Fuel Economy (CAFÉ)

Source: U.S. Department of Transportation (sales weighted combined city / highway miles per gallon), J.P. Morgan.

These are the key reasons why investors tend, quite rightly, to place a lower valuation on the downstream than the upstream. Not only is it an inherently low growth business, but its returns are structurally challenged by a number of powerful forces from suppliers, government and consumers.

Unfortunately, this investor tendency is further encouraged by much poorer levels of disclosure downstream versus upstream. Companies continue to excuse the need for increased downstream disclosure due to ‘competitive sensitivity’. This makes it very difficult to predict performance, an issue made worse by very volatile refining margins. Our experience is that poor disclosure in the oil & gas sector either obscures a very good or a very bad business.....we'll let our readers decide which one of these refining is. Specific incremental downstream disclosures that we would like companies to make, at least annually, include:

EBIT split – we would like refining EBIT to be separately disclosed.

Capital employed – we would like all companies to give a standard measure of post-tax downstream capital employed.

Refining costs and capex – we would like refining operating costs and capital investment / depreciation to be disclosed.

Retailing – we would like the number of company-owned versus dealer-owned sites to be disclosed, as well as regional site throughput volumes and non-petroleum turnover.

10

15

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25

30

35

40

45

50

55

74 76 78 79 80 82 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 00 01 02 03 04 05 06 07 08 09 10 15E20E

Federal Standard Total Fleet

Subject to lobbying

Confirmed

31



Refining capacity growth outlook

We use our global database that tracks all refinery expansions, green field construction and plant closures (details of new projects in Appendix III). We exclude potential (likely) capacity creep as a result of existing plant debottlenecking which may be as much as 0.5%+ per annum. We also exclude bio-fuel production capacity growth, but include a few of the most likely GTL projects. We include identified capacity retirement either as a result of plant closure or conversion to terminal status – although this is a very modest amount of existing capacity. We also include capacity that has been shut, but that is due to re-open.

Our analysis shows a sustained increase in primary distillation capacity 2010-16(Figure 15). Given global operable refining capacity at year-end 2010 of approximately 91.2 million bopd, we estimate aggregate net capacity additions(additions less closures) of 27.8million bopd, 28% or a capacity CAGR of 4.2%. This is 4x the global refining capacity CAGR 2000-10 of just 1.1%.

Figure 15: Outlook for global refining capacity additions by region (kbopd)


-1000

1000

3000

5000

7000

9000

11000

10 11E 12E 13E 14E 15E 16E

North America Latin America Europe Eastern Europe Africa Middle East Asia Retirements

Largest capacity growth aspirations 2014-16 located in Asia and Middle East - NOC sponsored.....

+0.8% net increase +2.2% +2.1%

+1.8%

+3.4%

+8.0%

+9.4%

Net capacity growth potential of 28 million bopd or 28% 2010-16E

32



We acknowledge that much of the capacity data for 2015 and 2016 necessarily includes projects that have not yet been sanctioned and which therefore may yet be delayed or indeed may be cancelled. Specific to PR China, which shows the largest amount of potential capacity additions, some projects compete head-on for government approval - not all will be approved in the timeframe shown. However, we note three specific threats:

As per Figure 15, much of the potential capacity growth in 2014-16 is presently being sponsored by NOCs in Asia and the Middle East who are least sensitive to the risk of poor commercial returns given weak margins and who are often driven to reduce sovereign import product import requirements. This, in turn, enables governments to impose more direct control over domestic product prices. So, we believe that there is a heightened risk that low margins 2011-12 do not inhibit project sanction and consequent capacity growth as might occur if the key sponsors were more sensitive to expected returns.

The supply / demand balance may be further upset by two more risks. IOCs continue to operate marginal plants in the hope that maverick NOC buyers will step forward, as they have done recently (e.g. Essar Energy / RD Shell's Stanlow facility).

The block size of new plants is now much larger, with green field plants typically scaled 200 kbopd or larger. Two examples of mega-refinery projects are in Saudi Arabia (Jubail, 400 kbopd) and the UAE (Ruwais, 415 kbopd). These units are 3-4x the global average refinery size of around 130 kbopd (Figure 16).

Figure 16: Average refinery size in each country (bopd)


0

100000

200000

300000

400000

500000

1 6 11 16 21 26 31 36 41 46 51 56 61 66 71 76 81 86 91 96 101 106 111

Average refinery size 132 kbopd

115 countries have c.655 refineries

New mega refineries typically scaled up to

200-500 kbopd

NOC sponsorship is a risk

IOCs refuse to ‘bite the bullet’

Greenfield unit sizes are getting

much larger

33



So, we are concerned that a rational industry response to sustained weak refining margins may be slow to manifest – capacity growth may thus continue, unabated by weak margins. The situation therefore looks as bad, if not worse, than it did in the late 1970s / early 1980s (Figure 17). The implications for regional refining margins are negative.

Figure 17: Global capacity growth / reduction 1970-2010, 2011-16E

Source: J.P. Morgan, BP 2011 Statistical Review of World Energy

What determines refining margins

In our view, the primary drivers of capacity utilization are product demand (that pulls crude through the processing system) and net capacity changes (that determine the levels of available / idle capacity). Product demand is naturally sensitive to economic growth. However, Figure 18 shows a limited positive correlation (+0.10) between US Gulf Coast refining margins and US GDP growth other than at cycle turning points e.g. most notably in to an economic slowdown when utilization rates collapse. Interestingly (Figure 19), measured quarterly, we see a much stronger correlation (+0.75) between the oil price (WTI) and gross refining margins (US Gulf Coast).

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13E

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15E

16E

Global capacity growth (kbopd) % change (RHA)

Scale of potential capacity growth this decade marks a return to the 1970s build out....which destroyed industry profitability and

necessitated years of net capacity retirements

34



Figure 18: GDP growth as a driver of refining margins


Figure 19: Oil price as a driver of refining margins


In Figure 20 and Figure 21, we demonstrate the strongly positive correlation between regional capacity utilization and annual regional average gross refining margins. Regional capacity utilization has shown a strongly positive historical correlation with refining margins. We focus on this parameter as a primary margin driver.

Figure 20: NW European refinery utilization versus gross refining margins 1998-2010


Figure 21: Asian refinery utilization versus gross refining margins 1998-2010


-10.0%

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90 91 92 93 94 95 96 97 98 99 00 01 02 03 04 05 06 07 08 09 10 11E 12E

US Gulf Coast GRM ($/bbl) US GDP growth (real, %)

US RECESSIONS

JPM GDP forecasts H2

2011-2012

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US Gulf Coast GRM ($/bbl) WTI ($/bbl)

US RECESSIONS

R² = 0.8112

0

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73% 74% 75% 76% 77% 78% 79% 80% 81% 82% 83% 84%

GR

OS

S R

EF

ININ

G M

AR

GIN

($/B

BL

)

EUROPEAN REFINERY UTILISATION

19981999

20002001

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R² = 0.6935

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20012002

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2008

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2010

Regional system utilization is a

key driver of gross margins

35



Bull and Bear scenarios

We examine two quite extreme potential demand growth scenarios 2011-15 as defined below in order to set the most likely book ends for regional capacity utilization rates (Figure 22).

Figure 22: Regional refinery throughput growth rates


BEAR CASE – We incorporate all net capacity additions that we have identified and assume 0% throughput growth 2011-15 in Europe and the USA and only 3% per annum for the Middle East + Asia.

Under this set of assumptions (Figure 23), we see European and US refinery utilization rates continuing to decline from 2011 to 2015. Under this scenario, we therefore expect that refining margins in the US and Europe will continue to soften. Asian capacity utilization rates may improve slightly 2011 to 2013, but will then slide. At this point we expect surplus product to flood in to Europe. In our view, this will destroy margins globally in 2014 and 2015 and for some years thereafter.

BULL CASE – We delay all net capacity additions in 2012 and beyond by 1 year and we assume refinery throughput growth of 2% per annum for Europe and the US and 6% per annum for the Middle East + Asia.

-10.0%

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0.0%

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8.0%

1990 1995 2000 2005 2010 2015E

USA NW Europe Asia

2000-10 CAGRUSA -0.2%NW Europe +0.2%Asia +2.8%

1990-2000 CAGRUSA +1.2%NW Europe -0.6%Asia +4.9%

BULL CASE +6%

BEAR CASE +3%

BULL CASE +2%

BEAR CASE 0%

BEAR CASE portends weak margins for years to come

BULL case portends a continued margin recovery

36



Under this scenario (Figure 24), capacity utilization rates will continue to rise from the 2009-2010 lows in all regions. Specifically, utilization rates in the Middle East and Asia will rise to above 90% in 2013, peaking in 2014 above 95%.

Figure 23: Regional utilization - BEAR CASE


Figure 24: Regional utilization - BULL CASE


In practice, we fear that the outcome will be closer to our BEAR case than to our BULL case given continued capacity creep and the likelihood that more refined product will be sourced from outside the conventional refinery gate e.g. via GTL and bio-fuels. If anything, we also feel that our BEAR CASE is likely too optimisticsince we exclude capacity creep and bio-fuels encroachment. Furthermore, we suspect that our throughput growth assumptions over the period may be too high, especially in 2011 and 2012 given recent economic data.

Furthermore, as we have argued, we do not believe that NOC sponsors to large greenfield projects will pull back from investment given deteriorating margins. We therefore believe that any optimism that the refining margin recovery experienced in 2010-11 will continue in 2012-13 is dangerously misplaced.

To be more bullish, investors have to believe that NOC-sponsored capacity growth will fall well short of our projections and that demand growth will exhibit a prolonged up-cycle. We cannot see any compelling reasons for either to occur, especially given the latest GDP growth signals in Europe and the USA.

Our regional refining margin forecasts (Figures 25 to 28) are aligned to our BEAR case and therefore continue to assume a year-on-year de-gradation in the period 2011-15. Although we cannot rule out seasonal spikes, perhaps exaggerated by unexpected capacity losses, we expect such spikes to be short-lived.

65%

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98 99 00 01 02 03 04 05 06 07 08 09 10 11E 12E 13E 14E 15E


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100%

98 99 00 01 02 03 04 05 06 07 08 09 10 11E 12E 13E 14E 15E


Reality likely to be closer to our

BEAR CASE

We thus forecast continued

weak margins

37



Figure 25: US Gulf Coast gross refining margins ($/bbl)


Figure 26: US West Coast gross refining margins ($/bbl)


Figure 27: NW Europe gross refining margins ($/bbl)


Figure 28: Singapore gross refining margins ($/bbl)


Our declining margin forecasts are aligned with our declining oil price forecast (Figure 29). Given the aforementioned positive correlation between the oil price and refining margins, this is not inconsistent.

Figure 29: Brent oil price futures curve ($/bbl)


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98 99 00 01 02 03 04 05 06 07 08 09 10 11E 12E 13E 14E 15E

1998 5.61999 4.72000 8.92001 9.52002 6.02003 8.42004 13.12005 18.22006 20.12007 20.82008 17.02009 9.22010 10.2

13 year average$11.7/bbl

2011E 14.22012E 13.52013E 12.82014E 12.22015E 11.6

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2011E 15.22012E 14.42013E 13.72014E 13.02015E 12.4

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nt F

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($/b

bl,

mo

nth

ly a

vera

ge

)

Actual $38.0

Actual$55.3

Actual $28.5

2008Actual $98.4

2009Actual $62.7

Actual$66.1

2012ECurve $111.2

JPM $95.0

2011ECurve $112.3JPM $110.02007

Actual $72.72010

Actual $80.3

2013ECurve $108.0

JPM $90.0

38



Future imperfect

In this section we consider the potential implications of a continued long-term drift in refining capacity away from OECD to non-OECD.

The relocation of refining

Historically, refineries were located close to the key consuming areas, because it was cheaper to move crude oil than to move product and co-locating product output with demand made it easier to respond to changes in seasonal consumption patterns. Furthermore, importing countries wanted to encourage the formation of the refining industry on their shores, for reasons of local employment, inward investment and to ensure strategic control over this important manufacturing industry.

For these same reasons and given other key incentives (cheaper labor, special tax incentives in development zones, zero carbon costs etc), as refined product demand patterns have evolved (more sluggish in OECD, faster in non-OECD) and non-OECD has become more import-dependent, the location of new refineries has shifted to the Middle East and Asia, as per Figure 30. In 1965, these two regions held 15% of global capacity; by 2010 this had increased to 40%. We expect this trend will continue given an uneven playing field for emission costing, cheaper labor, cheaper land and special tax incentives (e.g. advantaged capital allowance schedules, specific tax holidays).

Figure 30: Regional distribution of global refining capacity 1965-2010

Source: BP 2011 Statistical Review of World Energy Statistics, J.P. Morgan.

This substantial and ongoing migration of refining capacity also reflects increased vehicle ownership and vehicle manufacturing capacity in these regions, particularly Asia and most specifically PR China. We note that in 1980 PR China produced 0.4% of total worldwide new vehicles. In 2010, PR China produced 24.0% of all new vehicles. In 1950, the US and Western Europe produced 98% of all new vehicles; by 2010 this had fallen to just 31%.

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Asia Middle East North America Europe RoW

Refineries historically co-located close to demand centers

Refining capacity will continue to migrate to Asia and Middle

East

China's vehicle manufacturing capacity 24% of global capacity

39



We suspect that without changes to government policy to encourage domestic refining, OECD refining will follow the marginalization trajectory of US vehicle manufacturing, as it is gradually displaced by lower cost refining centers in Asia and the Middle East.

Figure 31: New vehicle production by country & region (000s)

Source: Ward’s Automotive Group, J.P. Morgan.

Figure 32: New vehicle production by country & region (%)

Source: Ward’s Automotive Group, J.P. Morgan.

With respect to vehicle ownership (passenger vehicles plus trucks), PR China surpassed Japan for the first time in 2010 with approximately 78m units (Figure 33). Since 1986 to 2010, China’s vehicle park has grown at a CAGR of +14% compared to +2% for Japan and just +1% for the USA. If these historical growth rates are sustained, the size of China’s vehicle park will surpass the size of the USA's vehicle park by 2021, in just ten years’ time.

Figure 33: Number of vehicles - passenger cars and trucks

Source: Respective Auto Associations, J.P. Morgan.

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US + Canada W.Europe China Japan Other

-

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1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

China Japan USA

Total vehiclepark CAGR 1986-2010PR China +14%Japan +2%USA +1%

China’s vehicle park could surpass US by 2021

40



Future imperfect

From experience, we are mindful that ‘absolute certainty’ in the oil & gas sector is a myth - it is often those forecasts where we have supreme confidence that prove incorrect. Equally, we are acutely aware that long-term forecasts in the oil & gas industry carry very high risks of being wrong given three key big change drivers:

unexpected technological break throughs e.g. we note how development of US gas shale completely up-ended domestic gas supply forecasts and bullish US gas price forecasts. The US Energy Information Administration (EIA) now estimatesthat production of natural gas from shale plays increased from 4% of total natural gas production prior to 2005 to about 23% of total natural gas production in 2010.

unexpected changes to government policies e.g. we note how the Fukushima nuclear disaster has transformed the views of certain governments (e.g. Germany, Switzerland and Thailand) with regard to their dependency on nuclear power.

unexpected political change e.g. we note how regime change in Iraq has materially changed this country's oil output capacity potential.

We also acknowledge that our capacity growth data for 2011-16 is inevitably error-prone and likely over-states the actual pace of capacity additions. However, it points to a clear refining capacity migration trend, from OECD to non-OECD, that we believe will continue and that will have important long-term implications for refined product trade flows and trade balances.

Figure 34 shows the 2010 refined product balances of key countries and regions. For example, PR China’s net imports were 638 kbpd in 2010 (comprising exports of 615 kbpd net of imports of 1,253 kbpd) and the FSU’s net product exports were 2,057 kbpd. As per this schematic, the FSU, the Middle East and India were the world’s largest exporters of refined products. Globally, a total of 15.8 million bpd of refined products were imported and exported.

Figure 34: Refined product NET importers (negative) and exporters (positive) in 2010 (kbopd)

Source: BP Statistical Review of World Energy 2011, J.P. Morgan.

NORTH AMERICA

SOUTH AMERICA

JAPANMIDDLE EAST

EUROPE

AFRICA

-513

-253

-1,252

FSU

2,057

2,029

232

-135

-638

852

INDIA-561

SINGAPORE

-716

--1102

REST OF ASIA

CHINA

AUSTRALASIA

Long-term forecasts can prove

very wrong due to technological

breakthroughs

World’s key refined product

export hubs

41



If we fast forward only five years hence to end 2016, based on our capacity addition data to this time horizon, we expect to see some significant changes to these product trade balances. At end 2005 (2010), Asia plus the Middle East held 36% (40%) of global refining capacity (Figure 35). By end 2016, we expect this figure to have risen from 40% to almost 45%. We see absolutely no reason for this trend in regional capacity relocation to change post-2016. Indeed, it may well accelerate given the structural drivers that underpin it.

Middle East – this region is set to become an even more dominant product exporter. This may enable key OPEC members to exercise more influence over the oil price by controlling more exportable refined product flows.

India – we expect this country will become a much more significant product exporter. This may have implications for the M&A market as Indian refiners e.g. Essar Energy, look to secure terminal infrastructure and downstream market positions in target import markets.

PR China – this country could actually extinguish its product import requirements and become a net product exporter. Indeed, it could become an important new export hub for Asia Pacific which may bring it into a competitive conflict with Middle Eastern exporters. However, we suspect that PR China policy will more likely only permit enough refining capacity to be built to satisfy the country’s product needs whilst looking to improve the energy efficiency of its existing refining base. This will leave the country a net exporter / importer at certain times of the year.

Europe / North America – we expect that the product import requirements of both regions will increase, despite sluggish demand growth, given modest economic growth and engine efficiency gains, as more disadvantaged refineries are closed and no new refineries are added.

Figure 35: Changes to regional refining capacity location (year end, %)


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42



The science and art of separation

We have long encouraged an active debate about the merits and benefits of a vertically integrated business model in the oil & gas sector. We first proposed consideration of a restructuring to separate upstream from downstream in mid-March 2006 as presented in Figure 36. As the returns from upstream and downstream diverge further (more specifically as downstream returns look set to deterioriate), we believe the case to separate these two parts of the value chain grows ever stronger.

Figure 36: Simple transaction model for upstream-downstream separation – a tax free spin-off to shareholders


In Table 5, we summarize the pros and cons of vertical disintegration to create two pure parts – one upstream and one downstream. This has been done by Marathon Oil, effective 23 June 2011. It originally proposed this restructuring step in 2008, but the plans were abandoned in 2009 as a result of the global financial crisis.

Vertically integrated oil & gas company (VIOC plc)

UPSTREAM plc

• Oil & gas assets - producers, developments, acreage

• Processing & storage facilities

• Transportation networks - oil & gas pipelines, shipping

• LNG - liquefaction and re-gasification terminals, shipping

• Power, Renewables

• Trading - oil, gas, LNG, power, renewables, carbon

DOWNSTREAM plc

• Refining - manufacturing

• Marketing - retail, business

• Terminals & storage facilities

• Lubricants - blending & marketing

• Shipping

• Chemicals - bulk, specialty

• Trading - products, carbon

Spin-off downstream entity

Concept of vertical integration has passed its sell-by date

43



Figure 37: Marathon Oil - absolute and sector relative performance (rebased)


Figure 38: ConocoPhillips - absolute and sector relative performance (rebased)


Such a move has also been proposed by ConocoPhillips. On 14 July 2011, it announced that it will split into two companies by spinning off its refining business as a separate, publicly traded entity by the end of June 2012, at which time the CEO (Jim Mulva) will retire. Figure 37 and Figure 38 show the absolute and relative share price performance (versus the US Integrated Sector) of these two companies since the beginning of 2008.

The announcement by the industry heavyweight ConocoPhillips regarding its intended upstream – downstream separation (scheduled to be completed by mid-2012) has helped to recharge the debate about this radical form of corporate restructuring. On balance, we squarely believe that for some companies, a separation will ultimately lead to superior performance from and a higher valuation for the two parts versus the single more lowly rated integrated entity.

Figure 39: Correlation between upstream & downstream earnings 1997-2011

Source: J.P. Morgan. Quarterly post tax earnings for BP, Chevro, Exxon Mobil and RD Shell.

Source: Thomson Reuters Datastream

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2008 2009 2010 201130

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-100

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Upstream Downstream

Correlation coefficient +0.50

Pros of separation outweigh the

cons

44



Table 5: Pros and Cons of upstream-downstream separation

Pros ConsGive investors important choice - the majority of investors prefer the choice between two pure entities across the macro cycle that offer gearing to different parts of the energy value chain and more direct leverage to segment-specific event risk e.g. exploration success for a pure upstream entity.

It would create two entities with increased earnings volatility - we disagree given the positive correlation between upstream and downstream earnings (see Figure 39).

Reduce risk of cross-segment valuation contamination - so if one part of the business performs poorly, it does not bring down the valuation of the whole. Arguably, Macondo (Texas City) damaged the valuation of the whole of BP.Consistent with our bearish downstream outlook, we see an increasing threat that poor downstream results drag down the valuation of the whole.

Downstream businesses cannot survive the cycle stand alone - again we disagree and, even if this was true, we cannot see any validation for a good upstream business to subsidize a bad downstream business.

Facilitate necessary downstream consolidation - consistent with our bearish analysis of the global refining outlook, we believe that further consolidation will be required. Figure 36 highlights a highly fragmented landscape of pure downstream players. Such consolidation will be more easily achieved by independent downstream players. The best acquisition opportunities often occur when the cycle is at its worst.

It would expose both parts to an increased risk of takeover - this is potentially true, but in our view no bad thing from a shareholder's perspective. Management should not stand in the way of this outcome by sustaining inefficient scale and complexity.

Permit more effective management incentives - upstream (downstream) management ought to perform better given a more direct incentive linked to the share price of a pure upstream (downstream) company.

It would cost money to separate the businesses - yes, it would, however a tax-free spin-off was delivered by Marathon and ConocoPhillips looks likely to do the same. Furthermore, we believe that the enduring benefits would more than offset the one-off upfront costs of separation and higher overall corporate costs for two separate entities

Encourage fuller downstream disclosure - this would overcome the current situation where vertically integrated companies give fuller upstream disclosures, but excuse themselves from equivalent downstream disclosure policies due to ‘competitive sensitivities’.

Loss of global procurement efficiency - we accept that some loss of procurement efficiency may be incurred, but we doubt that it would be material.

Shift valuation metric to raise relevance of asset value - we do not agree that the market would be reluctant to price a very large, well run E&P company using a NAV metric, as it does smaller independents. Equally, we believe that the downstream valuation focus could usefully shift to an, EV/EBITDA multiple.

Loss of recruitment / retention power - we simply do not agree that the best people prefer to develop their careers at integrated companies given the greater 'career safety and choices'. Indeed, we believe that the integrated companies have actually suffered a 'brain drain' to the more entrepreneurial, independent sector.

Permit tailored capital structuring - the debt capacity and tolerances of an upstream company are different to those of a pure downstream company. Note that ConocoPhillips recently indicated that the separate entities could hold more debt than the combined entity.

Damage trading efficiency - we accept that some loss of trading efficiency may be incurred, but since the market regards this business as low quality, the value implications ought to be very limited indeed.

Permit greater ownership flexibility - many institutional investors face 'big oil' ownership limitations given their heavy index weighting; this issue could be reduced if not eliminated given two smaller listed entities.

Reduce global access capabilities - we do not agree that a downstream capability is important for upstream access in the 21st century. However, we see a continued risk that certain companies use the offer of a low return downstream investment in order to leverage their access upstream.

Avoid the hazards of an internal capital market – downstream has never really been able to compete with upstream, which offers superior returns. Downstream would no longer have to compete with upstream and (to a lesser extent) vice versa; this would enable more efficient cross-cycle investment patterns.


We continue to believe that BP is a prime candidate amongst the stable of integrated names to implement this kind of restructuring. We note that the CEO stated following BP’s Q2 2011 results that no strategic option has been ruled out. We believe that the Macondo crisis could be positively resolved via this corporate restructuring remedy and identify five company-specific motivations:

Address the very substantial share price to intrinsic value gap – Management has publicly acknowledged the value gap and all restructuring options are 'on the table'. Our SOTP for BP is around 800 pence or $77.8 per ADR – more than double the current share (ADR) price (Figure 40).

Strategy derives little or no integration benefits - BP is one of the few oil majors which is not physically integrated e.g. via refining to chemicals. Furthermore, its share price is clearly not registering any such synergies given the deep discount to its SOTP. So, the natural argument against disintegration, as coherently articulated by companies like Exxon Mobil, does not apply to BP.

Shareholders want radical action, sooner not later – We believe that this form of corporate restructuring would help to appease BP’s long-term shareholders

BP is a prime candidate to dis-

integrate

45



who want more radical action to address the stock’s long-run underperformance and who do not believe that the current divestment program is a sufficiently profound change for the company. This is substantiated by public comments by a number of BP’s UK shareholders.

Figure 40: BP SOTP and share price discount (%)


Table 6: BP Downstream - estimated enterprise value

Segment ($m) (p/share) %Refining 19,107 62 32Shipping 3,295 11 6Marketing Retail 21,205 68 36

Commercial 3,240 10 6Lubricants 5,940 19 10Chemicals Specialities 4,388 14 7Corporate 1,629 5 3Enterprise value 58,803 189 100

Downstream financials ($m) 2010 2011E 2012EEBIT * 4,883 6,639 6,764DD&A 2,258 2,300 2,350EBITDA 7,141 8,939 9,114Post tax earnings if ungeared 3,906 5,311 5,411Potential distribution at 40% payout - 2,124 2,164Capital expenditure 4,029 3,500 3,500Net fixed assets 28,147 29,347 30,497Theoretical net debt capacity given ND/ND+E ratio 25% 7,037 7,337 7,624Implied multiple if valued at EVEV/EBITDA (x) 8.2 6.6 6.5EBITDA CAGR 2010-12E 13%PER (x) 15.1 11.1 10.9Dividend yield (%) - 3.6 3.7Price to NFA (x) 2.1 2.0 1.9

Source: J.P. Morgan estimates. * BP reported H1 2011 downstream EBIT of $3,588m.

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Average discount (28)%

46



As detailed in Table 6, our BP downstream EV, as per our BP SOTP, is $58.8bn or around 189 pence per share. We value BP’s fuels retailing business at $21.2bn and its refineries (including working capital) at $19.1bn. These sub-segment valuations imply a unit value of just under $1m per retail site (22,100 sites at year end 2010) and $7,200 per bopd refining capacity (16 refineries with total net capacity 2,667 kbopd at YE 2010). We do not value BP’s powerful Trading function – instead we assume that the benefits derived from this business are already expressed in the performance of the key businesses that we explicitly value and, ergo, in the total downstream financial performance.

In Figure 41, we position BP Downstream's theoretical market capitalisation alongside 27 pure downstream plays that are listed in Europe, the USA and Asia. As per this chart, a debt-free BP Downstream would currently rank as the world’s largest pure downstream entity, just ahead of Reliance Industries. We note that J.P. Morgan’s analyst for ConocoPhillips (Katherine Minyard) estimates an EV for its downstream business (including Midstream and Chemicals in their present configurations) of just over $31bn. Assuming this downstream entity holds $6bn of net debt, this implies a potential equity value of around $25bn - much larger than the two largest US plays today (Marathon Petroleum and Valero Energy), but less than half the size of a debt-free BP Downstream.

Figure 41: Equity market values of pure downstream names on 1 September 2011

Source: J.P. Morgan – blue – US companies, Green – European companies, Red – Asia and Rest of World companies.

In Figure 42, we show the current trading (2012E EV/EBITDA) multiples of a broadcross-section of these downstream plays. Where possible, we have positioned each

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Downstream at $59bn, 189 pence

per share

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EV/EBITDA 6.5x

47



pure play according to EBITDA CAGR 2010-12E and 2012E EV/EBITDA multiple. The blob size corresponds to current market capitalization. We have also positioned BP Downstream amongst these names assuming the aforementioned enterprise value (equity value given zero net debt assumption). We do not believe that the implied 2012E EV/EBITDA multiple of 6.5x, required to give parity with our estimated EV, looks out of line with these peers (2012E EV/EBITDA median 5.6x) given the unique scale and quality of BP Downstream, which would be the only trans-regional pure downstream player.

Figure 42: Comparable downstream 2012E EV/EBITDA multiples 1 September 2011 (blob size corresponds to market capitalization, $m)

Source: J.P. Morgan. Consensus EBITDA data from IBES and current EV based on last disclosed net debt figure. Asian companies colored red; European companies colored green, US companies

colored blue.

If listed as a separate entity and assuming zero debt and a value parity with our SOTP, BP Downstream would rank alongside Reliance Industries of India as the world's largest listed, pure downstream company (current market value $57bn).

If we assume that net assets are 33% higher than net fixed assets and a net debt to net debt plus equity ratio of 25% (note that US downstream plays bear an average debt to capitalisation ratio around 25%), this would imply a very manageable net debt capacity of around $8bn. This would reduce the implied equity value of BP Downstream to around $50bn. Since we do not know the potential off-balance sheet liabilities of BP Downstream e.g. pension deficit, it is difficult for us to prescribe a capital structure.

IOC

SK Innovation

S-OIL

Marathon PetroleumValero Energy

HollyFrontier

BPCL

Thai oil

Tesoro

HPCL

Caltex Australia

ERG SPA

Saras SPA

Western Refining

Bangchak Pet.

Petroplus

Alon USA Energy *

BP

Reliance Industries

Hellenic Pet.

Motor OilPKN Orlen

Sunoco

TonenGeneral

Showa Shell

JX Holdings*

Neste Oil

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Average5.6x

Average36%

BP Downstream potentially larger than RIL of India

48



Downstream performance assessment

We have analyzed the downstream performance and strategies of fifteen listed companies over a period of 11 years from 2000-10.

International Oil Companies (IOCs) - BP, Essar Energy, ENI, GALP, OMV, RD Shell, Repsol YPF, Reliance Industries, Sasol, Statoil and TOTAL

National Oil Companies (NOCs) - IOC, Sinopec, PetroChina and Petrobras.

Broadly, these names may be sub-divided in to five core categories, as per Figure 43. All of the OECD IOC names are focused on enduring the cycle, usually via a combination of upgrading, restructuring and shrinking the downstream (extracting capital therefrom). The growth-focused NOCs are less focused on costs and more focused on growth projects, typically in their domestic markets. These often involve moving further downstream in to petrochemicals in order to capture more value from downstream products that are not price regulated.

More specifically, we have chosen these companies in order to be able to compare and contrast the strategies and performance (operational and financial) of the world’s best known IOCs and NOCs. We include a strategic analysis of Sasol to underline another bearish factor for refining - the growth in the production of refined products via non-conventional processes i.e. natural gas-to-liquids. We also include IOC and RIL to show examples of two structurally advantaged refiners.

Figure 43: Five categories of downstream strategy

Source: J.P. Morgan. * Chevron and Exxon Mobil are excluded from the strategic analysis, but data for both is included in the peer

group performance analysis.

SIT OUT THE CYCLEChevron

ENI

Exxon Mobil

UPGRADEGALP

Repsol YPF

SELECTIVE GROWTHEssar Energy

OMVReliance Industries

Sasol

AGGRESSIVE GROWTHIOC

PetrobrasPetroChina

Sinopec

RESTRUCTURE / SHRINK

BPRD ShellStatoil

PETROCHEMICALS

49



Setting the scene

Before we score and rank these companies, we illustrate the scale and spread of their operations. Combined these companies include many of the world's key listed players and, in aggregate they have a very substantial share of global refining and retailing. As per Figure 44 and Figure 45, at year end 2010 the aggregate refining capacity of these names was approximately 32.6 million bopd – this represented 36% of global refining capacity (YE 2010 91.8 million bopd).

Figure 44: OECD companies – aggregate refining capacity


Figure 45: Non-OECD companies – aggregate refining capacity


As per Figure 46 and Figure 47, in total these companies owned approximately 242 refineries, which represented around 37% of the total number of refineries in the world (c.655). Both categories of companies have clearly been increasing the average unit size of their refineries. OECD names have typically done so by selling smaller plants to increase their average capacity to 128 kbopd. Non-OECD names have typically grown their average capacity, from 109 to 146 kbopd, by building new,larger plants.

Figure 46: OECD companies – number & average size of plants


Figure 47: Non-OECD companies - number & average size of plants


As per Figure 48 and Figure 49, OECD companies clearly have a fuller regional spread compared to the non-OECD names that are naturally more focused on domestic refining needs.

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Companies represent 36% of

global refining capacity

50



Figure 48: OECD companies - regional refining distribution


Figure 49: Non-OECD companies - regional refining distribution


In aggregate, at year end 2010, both categories of companies had approximately 216,000 retail outlets. OECD companies have shrunk the size of their networks by an average of 3% per annum, whilst non-OECD companies have grown their networks by an average of 2% per annum.

Figure 50: OECD companies - number of retail sites


Figure 51: Non-OECD companies - number of retail sites


We also group the OECD names to compare their overall downstream performance with the non-OECD names. Figure 52 shows how the non-OECD group sustained higher average refinery utilization rates through the 2008-09 economic slow down. 2010 marked the first year of higher utilization rates following five years of utilization declines for the OECD names. We believe that this reveals a key challenge for the OECD names – they have lost refined product market share to their non-OECD rivals. We expect they will continue to do so.

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51



Figure 52: Refinery utilization


Figure 53 highlights that, in most years, OECD downstream operations are more profitable than non-OECD operations – they generate a higher profit per barrel of refining throughput and a higher return in net fixed assets. However, the more challenging conditions in 2010 enabled non-OECD players to generate higher unit earnings and to match OECD asset returns. This could be shape of things to come.We note that the average OECD ROFA 2000-10 was 14% and the comparable non-OECD company average was 10%. So, both sets of companies show downstream returns in excess of their respective cost of capital. OECD based companies that pursue non-OECD downstream growth should expect very significant downstream return dilution, bearing in mind that we are measuring the returns of the dominant incumbents ex-OECD. Fortunately, none of the OECD companies that we cover iscurrently pursuing such growth – those that did (e.g. Repsol via YPF) have long since regretted it and their owners have certainly paid for it.

Figure 53: Post-tax earnings per barrel refining throughput ($/bbl)


Figure 54: Post tax return on net fixed assets (%)


Unsurprisingly, non-OECD downstream markets offer more growth opportunities and the incumbents thus show much higher capex to depreciation ratios (Figure 55). This has inevitable consequences for the relative free cash flow generation profiles of the two groups of companies which, in turn, limits the distribution powers of non-OECD players – their downstream operations are a sink for not a source of cash. We

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52



also note how the free cash flow profile of the OECD group deteriorated between 2006 and 2009.

Figure 55: Capex to depreciation ratio (x)


Figure 56: Free cash flow per barrel refining throughput ($/bbl)


Company downstream performance ranking

Based on 11 years of historical downstream performance data (2000-10) and using seven simple, specific metrics that we believe correlate most closely with shareholder value and valuation, we rank all our companies in Table 7. A full explanation of each parameter and the detailed scoring mechanism is in given in Appendix I. We weight each factor evenly and by summing the ranking on each parameter we derive an overall ranking. We split the companies - OECD and non-OECD.

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2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010


53



Table 7: Downstream corporate scores and peer group ranking

Source: J.P. Morgan. * We rank OECD companies for network shrinkage, whilst we rank non-OECD companies for network growth.

We have not included Essar in this ranking because it does not have a sufficiently long operating history to enable a comparison.

We are not surprised that GALP and OMV score poorly and rank low. We are, however, surprised by the high score and top ranking of Statoil – we had never thought of its downstream business as being that high quality – it clearly is, ableit very small in a group valuation context. Similarly, we are pleasantly surprised by TOTAL’s overall ranking third. We, perhaps in common with some investors, had believed that its downstream business was lower quality and would not score as high under scrutiny.

Of the non-OECD companies, we are most impressed by the operating and financial performance of Reliance Industries that possesses many, if not all of the competitive advantages that we look for in refining.

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BP

ENI

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OMV

RD SHELL

STATOIL

TOTAL

IOC

PETROBRAS

PETROCHINA

SINOPEC

RIL

2 4 5 2 4 6 31 2nd

6 2 1 7 5 9 39 5th9

3 10 9 9 8 8 57 8th10

10 7 10 5 10 10 56 7th4

5 9 6 3 9 4 43 6th7

7 6 7 4 7 2 38 3rd=5

9 1 3 1 6 1 22 1st1

8 5 8 8 1 5 38 3rd=3

4 5 1 1 2 2 17 2nd2

4 1 4 2 3 3 18 3rd3

5 2 2 5 5 5 29 5th5

3 3 3 4 4 4 25 4th4

1 4 5 3 1 1 16 1st1

54



BP

Overweight

Company DataPrice (p) 372Date Of Price 06 Sep 11Price Target (p) 575Price Target End Date 31 Dec 1152-week Range (p) 515 - 363Mkt Cap (£ bn) 69.7Shares O/S (mn) 18,755

BP (BP.L;BP/ LN)

FYE Dec 2010A 2011E 2012EAdj. EPS FY ($) 1.09 1.15 1.11Bloomberg EPS FY ($) 1.13 1.16 1.18EBIT FY ($ mn) 31,388 35,937 34,892Net Attributable Income FY ($ mn)

20,352 22,778 22,155

Dividend (Net) FY (p) 4.5 17.7 19.0Net Yield FY 1.2% 4.8% 5.1%EBITDA FY ($ mn) 31,388 35,937 34,892EV/EBITDA FY 4.8 4.5 4.6Source: Company data, Bloomberg, J.P. Morgan estimates. NB: unit for EPS figures is £.

Downstream overview

Downstream contents & structure

BP’s Refining & Marketing business is responsible for the supply and trading, refining, manufacturing, marketing and transportation of crude, petroleum, petrochemicals products and related services to wholesale and retail customers.

BP’s Refining & Marketing business therefore combines refining, fuels retailing (service stations and wholesale), lubricants (including Castrol), a small specialty chemicals business (BP sold the bulk of its olefins and derivatives business, Innovene, in 2005) and downstream trading. BP has a larger than normal trading function – this identifies the best markets and prices for crude oil, sources optimal feedstocks for BP's refineries and provides competitive supply for BP's marketing business. In addition, it generates trading profits from arbitrage, blending and storage opportunities. BP provides very limited detailed financial information on these sub-segments, especially its trading operations.

BP’s downstream business is managed through two main groupings – fuels value chains (FVCs) and international businesses (IBs):

FVCs - combine refining, logistics (pipelines, terminals etc), marketing (retail stations) and supply and trading on a regional basis. BP has 6 regional FVCs –each optimizes crude delivery to the refineries, the manufacture of fuels, pipeline and terminal infrastructure and marketing and sales to customers.

IBs – these operate on a global basis and include manufacturing, supply and marketing of lubricants, petrochemicals, aviation fuels and liquefied petroleum gas (LPG). The IBs operate in more than 70 countries. In 2010, the IBs accounted for just over half of BP's downstream replacement cost profit ($4.9bn).

Downstream strategy

BP's downstream strategy is to reduce its portfolio’s exposure to low growth markets (US and Europe) to enhance its focus whilst improving its overall returns and growth potential. As such, its strategy is not focused on scale, but on the quality of its assets and their performance. Ultimately, BP aims for each core piece of its downstream portfolio to generate attractive returns and growth. This strategy may be decomposed into three key areas:

BP is a European Analyst Focus

List stock

Downstream includes chemicals

and above-average contribution from trading

Continue to shrink, focus and

raise underlying returns

55



Reposition US fuels value chains and halve US refining capacity – this includes divesting the Texas City refinery and the Southern West Coast Fuels Value Chain (including the Carson refinery), whilst improving the capability of the Whiting refinery and raising the performance of the Cherry Point and Toledo refineries and focusing the marketing and logistics footprint.

Improve Eastern hemisphere fuels value chains and access market growth –this includes improving refinery yields (e.g. Gelsenkirchen), focusing the marketing and logistics footprint and expanding the marketing margin.

Grow high quality International Businesses – this includes lubricants, Asian chemicals and Air BP.

Downstream performance drivers

Under the leadership of Iain Conn (Chief Executive Officer, Refining & Marketing since 2007), BP has been restructuring its downstream business since 2007 in order to raise returns and ensure strong free cash flow. Throughout, the number one priority has been safe and reliable operations via an unrelenting focus on process safety risk management and the deployment of its Operating Management System. In this respect, BP’s Downstream business shares the group’s top three priorities -Safety & operational risk management, Rebuilding trust and Pursuing value growth.

BP’s downstream restructuring continued in 2010-11 and is scheduled to be completed in 2012. It has involved selling assets, simplifying processes (local head offices were closed and replaced by three regional centers), reducing costs (2007-09 headcount excluding retailing was reduced by 4,500 and senior management headcount was also reduced 20%) and driving revenue growth. During 2007-09, pre-tax earnings gains derived from these self-help measures totaled $4.8bn ($0.6bn costs, $1.4bn simplification and $2.8bn from revenue growth). In 2010, another $0.9bn was achieved with an incremental target of over $1.1bn by 2012 to make a total increment of $6.8bn relative to 2007 EBIT of $3.93 billion. BP estimates that in 2010 its Refining & Marketing cash costs (excluding energy, FX, plant turnaround costs and manufacturing variable costs) had been reduced to their level in 2004.

Downstream growth projects

BP only has one material downstream project – the Whiting Refinery Modernization Project (WRMP). This is a large and complex project that will take five years to complete. It involves the rebuild of its crude distillation unit to process heavy crude oil, the addition of a 100 kbpd six-drum coking unit and the addition of a new world-scale sulfur removal and gas-oil hydro-treating units. The project was 60% completed by end 2010 and is due to be commissioned in 2013. When completed, BP estimates that the plant’s pre-tax profits will be increased by more than $200m as it captures the WTI-Lloydminster price differential. Indeed, progress on pipeline interconnections was completed in 2010, allowing Whiting early access to cheaper crude imports and product export opportunities. This project will also help BP to access other heavy oil / non-conventional upstream opportunities in Canada. When up and running in H2 2013, the impact on BP’s free cash flow ought to be material given an end to project investment (2011E $1bn) and an incremental operating cash flow of up to $1bn at cycle average conditions.

BP is also considering an upgrade to the hydrocracker at its wholly owned Rotterdam refinery.

EBIT potential of around $7bn by

2012 versus cycle low $3.3bn in

2008

Whiting refinery upgrade is BP's only major downstream project

56



BP Downstream Efficiency Overview

Refining scale, reach & utilization

Following its acquisition of SOHIO (January 1989), BP's downstream business went through two further transformative steps following its merger with Amoco (December 1998) and acquisition of ARCO (April 2000). The size of BP’s refining network ultimately peaked following the acquisition of Veba’s retail and refining assets in Germany and Central Europe in 2002. Since then, BP has led the trend amongst its IOC peers by downsizing its refining exposure most effectively. This has been primarily achieved by divestments (corporate e.g. Innovene, plus numerous piecemeal asset sales e.g. Tesoro acquired two BP refineries in September 2001; the 58 kbopd Mandan, North Dakota refinery and the 58 kbopd Salt Lake City, Utah refinery. Prior to that, Clark acquired BP’s 162 kbopd Lima (Ohio) refinery in August 1998). BP has one US JV with Husky Energy (BP-Husky Refining LLC, April 2008 – BP contributed its 160 kbopd Toledo refinery).

By end 2010, BP had reduced its capacity from a peak of 3.1 million bopd in 2002 by 14%. BP has sold its interests in 10 refineries (Alliance, Coryton, Grangemouth, Lavera, Mandan, Mombasa, Reichstett, Salt Lake, Singapore and Yorktown), reducing its portfolio from 24 to 16 refineries at end 2010 (given 2 refineries also acquired). In so doing, BP has raised the average size of its retained refineries by 46% - from 114 kbopd in 2000 to 167 kbopd in 2010. BP is currently looking to sell its wholly owned Texas City refinery (475 kbopd gross rated distillation capacity) and its wholly owned Carson refinery in California (266 gross rated distillation capacity). These divestments are due to complete before the end of 2012 – they will almost halve BP’s US refining capacity. BP’s average refinery utilization has returned to very competitive levels (91% in 2010) having fallen to very low levels in 2006-07 following the Texas City tragedy (23 March 2005) which triggered a ‘root and branch’ review of plant safety and operations.

Refining product yield and product / equity oil cover ratio

Notwithstanding major divestments, BP’s refining slate has actually changed very little over the last decade. The only notable slate shifts have been a small increase in aviation fuel (from 9% to 12% by volume) and fuel oil (from 25% to 29% by volume) and a small reduction in gasoline output (from 38% to 35% by volume). In effect, BP’s refinery orientation has become more diesel-capable, which better suits the consumer demand trends in the OECD. As BP has grown its oil production whilst reducing its refining capacity, the ratio of refinery throughput to equity oil production has fallen from 145% in 2000 to 102% in 2010. Given the aforementioned refinery sales (741 kbopd) and notwithstanding upstream asset sales, we expect this ratio to fall below 100% in 2011-12. So, BP’s earnings will become less sensitive to refining margins and more sensitive to the oil price.

Retailing network

BP sells fuels under three power brands - BP, Aral (parts of Europe) and ARCO (West Coast of USA). BP’s retail convenience offer includes brands such as ampm, Wild Bean Café and Petit Bistro. BP also has a retailing partnership with Marks & Spencer. BP has reduced its network scale by an average of 3% per annum over the 11-year period 2000-10. In so doing, it has raised its network’s exposure to Europe from 27% to 38% and reduced its US exposure from 60% to 51%. BP also exited retailing in a number of countries e.g. in Africa (Botswana, Malawi, Namibia, Tanzania and Zambia) and France. BP has also de-capitalized its retailing business by shifting its US operations from a Company-Owned to Dealer-Owned model.

BP has led IOC downstream downsizing trend

Product yield shifts to more

diesel and aviation fuel, less gasoline

Reduced US exposure, raised

European exposure

57



Downstream profitability

BP’s downstream business has never reported a full year loss – indeed, since 2000 it has only reported a loss in one quarter (Q4 2007). BP's downstream business has also consistently generated a positive return on net fixed assets, with an average 2000-10 ROFA of 14%. BP’s ROFA is buoyed by three factors: (i) it has an above-average exposure to asset-light streams such as lubricants and trading (ii) it includes the remains of its specialty chemicals business which some of its peers (e.g. Exxon Mobil and RD Shell) report separately (iii) it has impaired certain assets and written off goodwill associated with the ARCO acquisition. However, BP has helped itself by always striving to be a low-cost player (e.g. 2009 cash costs reduced to 2004 level). However, we believe that these statistics show that BP’s downstream business is relatively high return and generates a more resilient performance than many of its peers. Between 2000 and 2010 BP generated an average of $3.9 post tax per barrel of refinery throughput.

Downstream cash generation and capital intensity

BP's downstream cash generation (excluding changes to working capital) has swung negative in three years. Negative cash flow in 2000 and 2002 was due to acquisitions (Castrol and then Veba). In 2008, negative cash flow was attributable to a weak operating performance and the asset exchange with Husky Energy Inc. to create an integrated North American oil sands business (which added $1.9bn to BP’s reported capital expenditure). These acquisitions have also ‘spiked’ BP’s capital expenditure to depreciation ratio. This ratio has averaged 2.1x 2000-10, which is a robust level of reinvestment – we are concerned when this ratio falls much below 2x given relatively fully depreciated assets and the high costs of ensuring asset integrity. We note that the Texas City tragedy also caused higher levels of downstream investment. Adjusted for acquisitions, BP’s downstream business has consistently returned cash to BP plc and thus supported the group’s cash returns to shareholders. Given much improved performance and two major refinery divestments (Texas City and Carson) which may realize $7-10bn, we expect this very healthy downstream cash flow profile to be continued in 2011-12.

Consistently profitable and robust returns

Consistent positive cash flow

excluding acquisitions

58



Figure 57: BP - refining capacity (kbopd) & utilization (%)

Source: J.P. Morgan. All BP data excludes TNK-BP

Figure 58: BP - number of refineries & average size (kbopd)


Figure 59: BP - refinery yield and output / equity oil cover ratio (x)


Figure 60: BP - retailing network size & location


Figure 61: BP - downstream profitability ($/bopd) & post-tax ROFA (%)


Figure 62: BP - downstream cash flow ($m) & capital intensity (x)


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59



Summary

BP's downstream strategy recognized early the perils of a global presence in refining and retailing – focusing instead on asset quality, operational reliability, cost efficiency and local focus – owning the right assets in the right markets. As a result, it differentiated itself from the majority of its integrated peers by a more aggressive downsizing and geographical repositioning – reshaping the downstream for improved returns and growth. BP is more aggressively transitioning downstream capital employed to upstream. Furthermore, by doing much of its downsizing early in the margin upcycle (2005-08), BP has been able to divest assets at good prices, especially its non-core refineries.

Another difference, BP has long been less dependent on the benefits of physical integration and, consequently, more dependent on its trading operations to source and place crude / product optimally and exploit arbitrage opportunities. Unfortunately, investors see this part of the business as a ‘high risk, black box’ type stream and therefore it typically fails to be accorded a fair value, in our view.

Clearly, BP’s downstream performance was badly damaged by the Texas City tragedy (March 2005) and the performance of its US retailing network was further damaged by the Macondo incident (April 2010). As is so often the case in this industry, a devastating accident acted as the trigger to improve performance. BP’s downstream safety (both process and personal) has improved, helped by its Operating Management System (OMS). This covers all contractor management processes. All of Refining & Marketing's major operations had transitioned to OMS by the end of 2010. It is clearly vital that BP maintains a flawless operational performance.

When it has sold its Texas City and Carson refineries (expected by 2012), BP will have total refining capacity of just over 1.9 million bopd with just 14 refineries (average net interest 138 kbopd) - this will rank it one of the smallest refiners amongst the oil majors. BP is already a low cost downstream player - this will protect it from the margin downside risks that we see over coming years.

BP is fast becoming a distinctive (growth oriented, consistently high return, consistent positive free cash flow) downstream player with a niche-like position in refining. This ought to be constructive for BP's overall valuation which, in turn, is ever more dependent on its upstream performance.

Our downstream EV (as included in our BP sum-of-the-parts) is approximately $59bn or 189 pence per share. This represents 24% of our total sum-of-the-parts value of around 800 pence per share (unchanged). Given the aforementioned performance improvement measures and continued safe and reliable operations, we see downstream EBIT potential in 2012E of approximately $6.8bn assuming no loss of profitability if margins are lower. Adding annual downstream depreciation of around $2.4bn, this implies a 2012E EBITDA of $9.2bn and an EV/EBITDA multiple of 6.5x.

Downsized early in the upcycle,

shifted focus to asset quality

and performance

OMS deployed across all

downstream operations

BP becoming more of a niche

refiner

Fuller recognition of $59bn

downstream EV is attainable

given 2012E EBITDA of $9.2bn

60



Figure 63: Downstream post-tax earnings versus global refining margin

Source: J.P. Morgan. We have assumed a 20% downstream effective tax rate for BP; RD Shell and Exxon Mobil report downstream profits post-tax.

Given improved underlying returns (i.e. EBITDA growth without material growth in operating capital employed) that should consistently exceed the division’s cost of capital and a stronger downstream portfolio growth orientation, this ought to be an attainable embedded multiple in our view, especially:

if the business continues to support the group's dividend as it should given EBITDA of $9.4bn and organic capital expenditure of around $4bn pa.

BP’s underlying profitability continues to surpass its closest competitors as it has done 2009-10 (Figure 63) – this is not a feature that many fund managers are aware of.

since it is not mis-aligned with the EV/EBITDA multiples of the listed pure downstream plays (see the section on the Science and Art of Separation).

This, in turn, will bring more of the downstream intrinsic value in to BP's share price which continues to languish at a 50%+ discount to our SOTP. So the performance of BP’s downstream business has an important role to play in raising BP’s overall valuation recovery story at this critical time in the company’s recent volatile history.

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BP RD Shell Exxon Mobil

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BP's profitability set to exceed 2004 level at lower margins

61



Royal Dutch Shell B

Neutral

Company DataPrice (p) 1,993Date Of Price 06 Sep 11Price Target (p) 2,400Price Target End Date 31 Dec 1152-week Range (p) 2,352 - 1,730Mkt Cap (£ bn) 122.0Shares O/S (mn) 6,122

Royal Dutch Shell B (RDSb.L;RDSB LN)

FYE Dec 2010A 2011E 2012E 2013EAdj. EPS FY ($) 2.94 4.23 4.66 4.77Bloomberg EPS FY ($) 3.08 4.40 4.75 4.94Adj P/E FY 10.9 7.6 6.9 6.7Dividend (Net) FY (p) 106.8 104.6 107.8 111.0Net Yield FY 5.4% 5.3% 5.4% 5.6%EBITDA FY ($ mn) 57,118 82,268 78,983 78,216EBITDA margin FY 9.8% 12.9% 12.3% 12.1%Net Attributable Income FY ($ mn)

18,073 27,107 29,773 30,186

Source: Company data, Bloomberg, J.P. Morgan estimates.

Downstream overview


RD Shell’s downstream covers manufacturing, distribution and marketing activities for oil products and chemicals. These activities are organized into globally managed businesses, although some are managed regionally or provided through support units. Manufacturing and supply includes refining, supply and shipping of crude oil. Marketing sells a range of products including fuels (including Shell Aviation and Shell Marine Products), lubricants (key brands include Pennzoil, Quaker State, Shell Helix, Shell Rotella, Shell Tellus and Shell Rimula), bitumen (via Shell Specialties) and liquefied petroleum gas for home, transport and industrial use (via Shell Gas LPG). Downstream also includes some trading. Specifically, Shell Trading supports the downstream businesses by trading gas, power, refined products, chemical feedstocks and environmental products. It also manages a shipping fleet of more than 50 vessels. Downstream also oversees Shell’s interests in alternative energy (including biofuels, but excluding wind) and CO2 management.

Shell's downstream also includes Chemicals. However, since financial information for this sub-segment is disclosed, we exclude it from our comparative financial analysis of Shell’s downstream business. This makes a comparison with its competitors such as Exxon Mobil, BP and Chevron more meaningful.

62



RD Shell Downstream Efficiency Overview


The size of RD Shell’s refining network peaked at 4.4 million bopd at year end 2002 following two major transactions:

RD Shell completed the acquisition of Texaco’s interests in Equilon Enterprises LLC, making Shell the 100% owner, and Shell, with Saudi Refining, Inc also jointly acquired Texaco's interest in Motiva Enterprises LLC. Equilon Enterprises was a 56/44 joint venture between Shell Oil and Texaco, respectively, that operated in the western United States and sold motor gasoline and petroleum products under both the Shell and Texaco brand names. Shell contributed its 288kbopd Wood River (Illinois) and 155 kbopd Martinez (California) refineries to the venture. Texaco contributed its 142 kbopd Anacortes (Washington) refinery; 99 kbopd El Dorado (Kansas) refinery; 91 kbopd Wilmington (California)refinery; and 63 kbopd Bakersfield (California) refinery. As a precondition of the U.S. Federal Trade Commission’s approval of the merger of Chevron and Texaco, Texaco sold its ownership in Equilon to Shell Oil, which then consolidated Equilon as of March 2002. Motiva Enterprises was a joint venture between Star Enterprise and Shell Oil that sold motor gasoline and petroleum products under both the Shell and Texaco brand names. After Texaco sold its ownership to its partners as a precondition of the U.S. Federal Trade Commission’s approval of the 2001 merger of Chevron and Texaco, Motiva became a 50/50 joint venture between Saudi Refining and Shell Oil.

RD Shell bought out RWE-DEA from its 50:50 downstream joint venture in Germany in 2002.

Shell maintains its 50/50 joint venture between Shell Oil and PEMEX (Shell contributed its 216 kbopd Deer Park, Texas refinery in April 1993). PEMEX has no other presence in the U.S. refining/marketing industry outside of this joint venture.

Subsequent refinery rationalization was slow to follow. At end 2010 (3,594 kbopd) RD Shell had slightly more capacity than it did at end 2000 (3,525 kbopd). Between 2003 and 2009, modestly sized refinery exits were made from France, Italy, Thailand, Brunei and various African countries. Tesoro acquired RD Shell’s142kbopd Anacortes, Washington refinery in August 1998 and its 97 kbopd Wilmington, California refinery in May 2007.

With the arrival of a new leadership team and facing the prospect of much thinner margins, the pace of rationalization then accelerated in 2010-11 as part of a formal program to sell 15% (560 kbopd) of disadvantaged refining capacity. Shell has since announced the divestment of refineries in New Zealand (Marsden Point), Germany (Heide), Sweden (Gothenburg) and the UK (Stanlow) with a total net capacity of 465 kbopd. These sales reduced Shell’s refinery count to 36 at end 2010 and helped to continue the gradual increase in the average scale of its refineries. The potential sale of the Harburg refinery in Germany would reach the target capacity reduction. The sale of under-utilized plants in Europe should help to raise the average utilization of Shell’s refining portfolio, which has been below 90% since 2006 and reached an all-time low of just 76% in 2009.

Shell was late to ‘bite the bullet’ on refinery sales, but progress

has improved 2010-11

63




RD Shell's refined product slate has changed very little since 2000. The only notable slate shift has been a small increase in gasoline (from 33% to 36% by volume). We may see some more notable shifts in 2011 following completion of the aforementioned divestments and the commissioning of Pearl GTL given its diesel (middle distillate) output.

Refining capacity growth combined with successive years of equity oil output declines raised RD Shell’s refining throughput to equity oil production ratio to a peak of 1.84x in 2007. Refinery divestments coupled to oil production growth in 2010 have reduced this ratio to 1.72x. The completion of the Stanlow and (potentially) the Harburg refinery sales will only reduce this ratio to around 1.6x in 2011 given no change to equity oil output. This ratio is still clearly well above BP’s comparable ratio, which is set to fall below 1x in 2012. So, RD Shell’s earnings will retain an above-average sensitivity to global refining margins.


Measured across the entire 11-year period 2000-10, RD Shell’s average earnings per barrel processed is $3.5 per bbl, lower than BP’s comparable average of $3.9 per barrel. RD Shell’s average post tax ROFA is 13% versus 14% from BP – so RD Shell has been less profitable and generated slightly lower returns. In essence, RD Shell has done slightly better in the upcycle, but much worse in the most recent downcycle. This is important since we believe we are many years from the next pronounced upcycle, if ever one returns – RD Shell’s portfolio just does not seem to be well positioned if our bearish outlook proves to be accurate. We suspect that BP’s superior performance in 2008-10 was a factor that encouraged RD Shell’s new leadership team to rid its retailing and refining portfolios of more underperforming assets. We note that RD Shell’s downstream business has never reported a full year loss (as per BP), but it has reported a loss in two quarters (Q4 2009 and Q4 2010).

Retailing network

RD Shell sells fuels, primarily under a single Shell power brand via almost 43,000 sites. In 2010, it sold 135 billion litres of retail fuel. Unfortunately, Shell has not disclosed retail site numbers prior to 2004. However, based on our estimates for 2000-03, we calculate a relatively slow pace of network shrinkage (-1% 2000-10) compared to its peers. In our view, this reflects three key factors (i) Shell did not consummate any large-scale mergers (unlike legacy BP with Amoco and ARCO and Exxon with Mobil) and so had a smaller network rationalization opportunity, since more of its network was built organically under the Shell banner (ii) Shell’s management was originally reluctant to embrace the need to focus its portfolio and so strengthen its profitability (iii) Shell has the number one brand in a number of countries and regions and has a relatively profitable marketing business. In 2008,Shell finally announced a network rationalization to exit 35% of its retail markets which contain around 5% of Shell-branded service stations. Since the beginning of 2010 it has announced retail divestments (exits) from New Zealand, Greece, Sweden and Chile. It has also announced an agreement to withdraw and partner with Vitol and Helios in 14 African countries (5% of total network in 2010). So, the geographical spread of Shell’s network, which changed very little in 11 years, with Europe now 25% (versus 23% in 2004) and the USA 33% (versus 34% in 2004), is finally being reset. The formation of the Raizen JV (completed 2011) with Cosan of Brazil has also created a network of 4,500 biofuel sites spread across Brazil – this

Little change to product slate, but Pearl GTL will raise diesel

percentage

High operational leverage shows

when the cycle weakens

Slow to embrace the need for

network rationalization, but

change is underway

64



will raise the overall exposure to South America. Other markets where Shell has added sites include the UK (via an acquisition from Rontec Investments LLP), Germany and China.


RD Shell's downstream cash generation (excluding changes to working capital) has been negative in just one year – 2002. This was due to three major acquisitions (i) Motiva, Equilon - $2.1bn purchase price plus $1.4bn debt and $0.3bn pension liabilities (ii) RWE-DEA - $1.3bn (iii) Pennzoil-Quaker State Company - $1.8bn equity plus $1.1bn debt. These acquisitions ‘spiked’ RD Shell’s downstream capital expenditure to depreciation ratio to 3.2x. We are slightly intrigued by RD Shell’s otherwise low average downstream reinvestment ratio, which has averaged just 1.2x 2000-10 versus BP’s average 2.1x. It is possible that RD Shell has under-invested in its downstream portfolio, but it is unfortunately not possible for us to reach that conclusion with much certainty. However, notwithstanding what appear to have been relatively low levels of reinvestment, we also note that RD Shell’s downstream cash flow (excluding changes to working capital) contribution to the group has reduced from a peak of $7.2bn in 2004 to just $1.1bn in 2009 and $2.0bn in 2010. A deteriorating downstream cash return has almost certainly been a reason for the dollar dividend freeze since Q1 2009 at 42.0 cents pcq. The question is, are the cash returns from this division likely to improve much from the level in 2010? If not, given a prolonged period of weak refining margins, this is another reason for investors not to expect much dividend growth from RD Shell in 2011-12.

Consistent positive cash flow excluding acquisitions, but low

rates of reinvestment might have

flattered

65



Figure 64: Shell - refining capacity (kbopd) & utilization (%)


Figure 65: Shell - number of refineries & average size (kbopd)


Figure 66: Shell - refinery yield and output / equity oil cover ratio (x)


Figure 67: Shell - retailing network size & location


Figure 68: Shell - downstream profitability ($/bopd) & ROFA (%)


Figure 69: Shell - downstream cash flow ($m) & capital intensity (x)


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2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Post tax earnings per refinery barrel throughput ($/bbl) Post tax return on NFA (%)

2000-10 average ROFA13%

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

(4,000)

(2,000)

0,000

2,000

4,000

6,000

8,000

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010



66



Summary

We commend RD Shell’s leadership team for its efforts in 2009-2011 to reduce the group’s downstream footprint whilst pursuing selective growth and striving for operational excellence. However, we would have liked the divestment program to have started and finished much earlier in the upcycle.

We are yet to be convinced that RD Shell’s downstream portfolio is fit for a prolonged bottom to this cycle. We accept that RD Shell has a stronger retail brand than BP and it can thus sustain the largest retailing network in the world (RD Shell 42,816 versus BP 22,100 at year end 2010). However, RD Shell’s refining portfolio (potentially 34 plants with an aggregate capacity of 3.2 million bopd) is still, in our view, unnecessarily large. As a reminder, BP is shrinking to a 14-refinery portfolio with a capacity of just 1.9 million bopd. RD Shell should sell more refining capacity and further reduce its operating costs too in order to raise the downstream free cash flow.

Our downstream EV (as included in our RD Shell sum-of-the-parts) is approximately $68bn or 685 pence per share. This represents 22% of our total sum-of-the-parts value of around 2600 pence per share. So, our estimated value of RD Shell’s downstream portfolio is larger than our value of BP’s smaller portfolio ($59bn). We note that our RD Shell value of $68bn equates to a 2010 EV/EBITDA multiple of almost 10x assuming a 35% downstream tax rate. This seems fair enough, if not generous. Even if we assume that more recent refinery and retailing divestments add $1bn to downstream EBITDA and also add $1bn of downstream cost reductions by 2012, the implied 2012E EV/EBITDA multiple is 7.7x. This is higher than our implied multiple for BP’s downstream business of 6.3x.

Downsized more in to the

downcycle, refining portfolio is

still too large

We would like management to

go further

Downstream EV of $68bn or 7.7x

2012E EV/EBITDA is fair, if not

generous given underlying performance and cash returns

67



ENI

Overweight

Company DataPrice (€) 13.02Date Of Price 06 Sep 11Price Target (€) 22.50Price Target End Date 31 Dec 1152-week Range (€) 18.66 - 11.83Mkt Cap (€ bn) 47.2Shares O/S (mn) 3,622

ENI (ENI.MI;ENI IM)

FYE Dec 2010A 2011E 2012E 2013EAdj. EPS FY (€) 1.90 2.39 2.57 2.68Bloomberg EPS FY (€) 1.88 2.12 2.30 2.53Adj. EBIT FY (€ mn) 17,304 20,767 21,803 22,292Pretax Profit Adjusted FY (€ mn)

17,393 20,976 22,053 22,542

Net Attributable Income FY (€ mn)

6,869 8,656 9,314 9,700

Adj P/E FY 6.9 5.4 5.1 4.9EV/DACF FY 5.8 4.6 4.0 3.8Div Yield FY 6.1% 6.4% 6.8% 7.1%Source: Company data, Bloomberg, J.P. Morgan estimates.

Downstream overview


ENI's downstream segment is mainly responsible for the refining and marketing (R&M) of refined products, supply of crude oil, and shipping of crude oil and products. ENI's R&M business is largely concentrated in Italy – this extreme exposure to a country experiencing declining product demand means that the operating performance of this business has been very weak in recent years. Please note that for our analysis we have used balanced primary distillation capacity for2000-03 as for these years the company has not reported distillation capacity (ENI's share).

Downstream strategy

The key medium-term target for ENI's downstream business is to generate positive free cash flow - the business has reported operating losses and negative free cash flow for the past two years. ENI's downstream portfolio has not changed much over the past decade. Despite management's cautious outlook for refining margins in Europe, ENI has yet to make any divestments in this business. The planned sale of Livorno refinery was withdrawn in 2010 due to lack of interest from buyers.

Optimize the refining system – ENI plans to selectively upgrade the conversion capacity of its refineries and adapt the refining throughputs to expected product demand trends. The Nelson Complexity Index of ENI’s refining system will increase 0.5 by end 2014.

Upgrading the retail network – ENI is looking to upgrade and rebrand the retail network given the short payback period.

Focus on core market – Italy will remain the obvious focus for ENI's downstream business – it is looking to 'revise its presence outside Italy'.


AgipPetroli, a wholly owned subsidiary, was merged with ENI in 2003 to form the company's refining and marketing business. Following the acquisition of an additional stake in Ceska Rafinerska and an increase in the refining capacity of Bayrenoil (ENI stake 20%), ENI's refining capacity peaked in 2008. The utilization rate of ENI’s refining system has seen a steady decline in this decade due to thechallenging operating environment and poor alignment between ENI's refining

Optimize plant portfolio, focus on core areas and target positive

free cash flow

Refining capacity is largely unchanged over the last decade

68



system and market demand. Downstream divestments are still not on management's agenda despite the weak operating performance of its refining assets – the company has dropped its planned divestment of its Livorno refinery.


ENI’s refining slate has changed very little over the past decade. The only slate shiftshave been a slight decline in gasoline (from 26% to 24% by volume) and in fuel oil (13% to 11% by volume). Like the majority of its peers, ENI is looking to realign its refining system’s output with the demand trends in Europe and plans to increase the middle distillate yield of its refining system. The company is targeting a 0.5 increase in the NCI of its refining system by end 2014. Given robust upstream production,CAGR of 4% 2000-10 and a declining trend in the utilization rate of ENI's refining system, the company's refinery throughput/ equity oil production ratio has declined from over 100% in 2000 to 70% in 2010.

Retailing network

ENI's marketing business (like its refining business) also has a strong operational bias towards Italy. The size of ENI’s retail network almost halved between 2000-10. The key divestments were Agip Brazil (1,500 service stations in 2004), IP in Italy (2,915 service stations in 2005) and various Iberian retail sites (371 service stations in 2008).


ENI's downstream performance has clearly been below par in the recent years with an operating loss in 2009 and 2010. Some key reasons for this weak operating performance are (i) a very challenging operating environment in its home market, (ii) no progress reducing exposure to the low margin refining business, (iii) historical underinvestment means that ENI’s refining output is poorly aligned to local marketdemand trends.


ENI's post tax free cash flow (excluding changes to working capital) was negative in 2009 and 2010 due to low profitability and rising capital expenditure. We also note that the company has underinvested in the downstream business – the average 2000-10 depreciation to capex ratio is below 1.5x - a key contributor to the below par performance of the segment.

Product yield has been stable

Good progress shrinking

network

Low profitability and challenging

outlook

Negative free cash flow and underinvestment in downstream

business

69



Figure 70: ENI - refining capacity (kbopd) & utilization (%)


Figure 71: ENI - number of refineries & average size (kbopd)


Figure 72: ENI- refinery yield and output / equity oil cover ratio (x)

Source: J.P. Morgan

Figure 73: ENI - retailing network size & location

Source: J.P. Morgan

Figure 74: ENI - downstream profitability ($/bopd) & post-tax ROFA (%)

Source: J.P. Morgan

Figure 75: ENI - downstream cash flow ($m) & capital intensity (x)

Source: J.P. Morgan

70



Summary

One of the most constructive things that we can say about ENI’s downstream business is that ‘it is very small’ (as a % of the total group EV) compared to its peer group. We regard this as a plus for ENI, especially as the majority of its peers are now looking to shrink their exposure to this business segment.

However, the performance of ENI's downstream business has been persistently weak in recent years - reflecting no divestments of low margin/loss-making refineries, historical underinvestment and its concentration in Italy, a very challenging operating environment. Unfortunately, ENI’s strategic options are very limited. Attempted divestments have failed and we very much doubt that ENI would consider a wholesale exit from the downstream given its 'national' status.

Our downstream EV (as included in our ENI sum-of-the-parts) is approximately €1.9bn. This represents just 2% of the corporate EV of €111bn. Our SOTP of around €27per share has come down from €29 per share - we refresh our $/€ spot rate, mark to market the Galp, SRG and Saipem stakes and made a downward adjustment in our downstream EV. We note that our total value of €1.9bn equates to a 2012E EV/EBITDA multiple of almost 3.8x - this is signifcantly below the comparable implied average multiple TOTAL. This is appropriate, in our view, given the lower profitability of ENI's downstream asset base.

Whilst we concede that given the small downstream footprint, the valuation of this business does not have a very significant impact on ENI's overall valuation, we also believe carrying loss-making/ low margin assets is a negative from an investor’s perspective.

Weak downstream performance

but very small exposure is a plus

Downstream EV of €1.9bn seems fair - operating profitability

ought to improve

More aggressive divestment

agenda needed, but unlikely

71



Essar Energy

Overweight

Company DataPrice (p) 241Date Of Price 06 Sep 11Price Target (p) 570Price Target End Date 30 Jun 1252-week Range (p) 638 - 233Mkt Cap (£ bn) 3.1Shares O/S (mn) 1,303

Essar Energy Plc (ESSR.L;ESSR LN)

FYE Dec 2010A 2011E 2012E 2013EAdj. EPS FY ($) 0.19 0.31 0.59 0.77Adj P/E FY 20.3 12.7 6.5 5.0EBIT FY ($ mn) 602 966 1,824 2,090EBITDA FY ($ mn) 729 1,155 2,192 2,542Pretax Profit Adjusted FY ($ mn)

357 577 1,114 1,439

Net Attributable Income FY ($ mn)

250 411 799 1,036

EV/EBITDA FY 18.7 14.8 8.2 7.2EBITDA margin FY 8.1% 12.0% 15.5% 17.1%Source: Company data, Bloomberg, J.P. Morgan estimates. *source : company, dated 20/03/2011

Downstream overview


Essar Energy’s downstream business covers manufacturing, distribution and marketing activities for oil products. Essar Energy’s downstream business is dominated by its refining business. The company also has a marketing network in India. The refinery at Vadinar is the company’s flagship downstream asset and has a nameplate capacity of 230 kbopd. Its fuel retailing assets include an extensive network of 1,385 retail outlets across India.

Refining

Essar Energy owns 100% of a 230 kbopd (nameplate capacity), 6.1 NCI (Nelson Complexity Index) refinery at Vadinar, near Jamnagar in Gujarat, India. The refinery has an operational capacity of 300 kbopd - a result of two successful de-bottlenecking programmes undertaken by the company. The refinery started commercial production on 1 May 2008. The project was originally started in 1990s, but faced significant delays and cost overruns. We have used the nameplate capacity for the purpose of our analysis.

Essar Energy also has a 50% stake in Kenya Petroleum Refineries, which operates a refinery in Mombasa, Kenya, with a gross nameplate capacity of 80 kbopd. Essar Energy acquired the stake in July 2008 from BP, RD Shell and Chevron; the remaining 50% stake is held by the Government of Kenya. The refinery operates as a 'tolling' refinery for the oil marketing companies in Kenya. In August 2011, Essar Energy completed the acquisition of the Stanlow refinery (in the UK) from RD Shell – this plant has a nameplate capacity of 296 kbopd.

Marketing

The company has an extensive network of 1,385 retail outlets spread throughout India, making Essar one of India’s largest non-PSU fuel retailers. The company also has 29 supply points to service its network – 12 terminals and 17 depots. The marketing network is based on a franchisee model which provides the company with the flexibility to grow without making significant investment – that burden is taken by the dealer. Given that the Indian product market is not fully liberalized (diesel is subsidized), this segment largely carries an option value of full market deregulation.

72



Downstream strategy

Essar Energy's strategy is to emerge as a low cost energy producing company focused on India and to capitalize on the rapidly growing energy demand in the country. Its strategy can be decomposed into two key areas:

Capitalize on India's growing energy demand - India has exhibited extremely resilient and above average economic growth since 2005 (average rate of GDP growth 8%+). Whilst conceding that the export sales may need to increase to c.40% of total sales due to new capacity additions by it and the public sector refiners, wealso believe that export sales % will decline over the medium term as Indian product demand growth is likely to remain bouyant - led by demand from India's transpostation sector (car density likely to go up significantly from a very low base in India). This underpins Essar Energy’s expansion plans in the domestic refining segment.

Leverage the low-cost base - Essar Energy’s Indian refining asset base bears materially lower operating costs than comparable assets overseas. We believe that this cost advantage is particularly relevant to the company’s refining business as we expect that regional refining margins will remain weak in 2012-13.

Key growth project

Expansion plan for Vadinar refinery – Essar Energy plans to increase its refining capacity to 20 MT in two phases, with phase I taking the capacity to 18 MT or 375kbopd (Nelson complexity index to rise to 11.8 from 6.1) and a further increase in the capacity to 20 MT or 405 kbopd. The expansion programme will also raise the refinery's complexity and the quality of its refined product slate.

Essar Energy Downstream Efficiency Overview

Refining scale and reach

Essar Energy is a relatively recent entrant to the refining business – the company's flagship refinery in Vadinar started commercial production in 2008. Given that theVadinar refinery has an operational capacity of 300 kbopd, which is significantly higher than the its nameplate capacity of 230 kbopd, it delivered an unusually high utlisation rate in 2009 and 2010 (average 127%) – more than offsetting the weaker utilization performance of its only other refinery in Kenya.

Following the recent acquisition of the Stanlow refinery in the UK (296 kbopd) and the phase 1 expansion of the Vadinar refinery that is likely to enter commercial production by end 2011/early 2012, Essar Energy’s total refining capacity will increase to 711 kbopd by end March 2012. It is then slated to grow by a further 30kbopd (Vadinar refinery optimization project) to 741 kbopd by end March 2013.


We have limited historical data given the relatively recent start-up of the Vadinar refinery (the key refining asset) – this means that a review of historical trends is not very meaningful for this name and we therefore focus more on the likely evolution of this business as the expansion projects come on-stream. Post completion of phase 1 expansion, the middle distillate yield of the Vadinar refinery will increase from 47% to 49% and conversion of all negative margin fuel oil into value-added products and pet coke. The fuel loss will also decline from 6% to 5%.

Low cost, India-focused integrated energy company

Refining capacity is slated to

increase significantly in 2011/12

Growth in complexity and middle distillate yield as the expansion

projects start up

73



Essar Energy does not have any upstream projects that are expected to start production of equity volumes and therefore the refining product to equity oil cover ratio is not relevant for this name.

Retailing network

Essar Energy sells fuels under the Essar Oil brand name in India. Essar Oil is one of India’s largest non-PSU fuel retailers. The company has a plan to increase the number of its fuel stations in India to 1,700 (+23%) – but this expansion is subject to the further steps by the Government of India to liberalize the retail fuel market. Given the country’s high rate of inflation, we believe that further retail fuel pricing liberalization is unlikely.

Essar Energy has a profitable downstream/refining business – the company has delivered strong operating results in both 2009 and 2010 (in the down cycle for the refining industry). Essar Energy's downstream business has also generated a healthy positive return on net fixed assets with an average 2009-10 ROFA of 9%. Essar Energy’s downstream business is relatively high return, despite the zero/negative contribution from the company's marketing business.


Essar Energy's downstream cash generation (excluding changes to working capital) was negative in 2010 given the heavy capex on the company's planned Vadinar Phase 1 expansion. The heavier than normal capex in 2010 also ‘spiked’ Essar’s capital expenditure to depreciation ratio to 10x.

Aggressive growth plans subject to further product pricing de-

regulation in India

Profitable business – increase in complexity will add to the

margins

Consistent positive cash flow

excluding acquisitions

74



Figure 76: Essar - refining capacity (kbopd) & utilization (%)


Figure 77: Essar - Number of refineries & average size (kbopd)

Source: J.P. Morgan

Figure 78: Essar- refinery yield


Figure 79: Essar - retailing network size

Source: J.P. Morgan

Figure 80: Essar - downstream profitability ($/bopd) & post-tax ROFA (%)


Figure 81: Essar - downstream cash flow ($m) & capital intensity (x)


0%

20%

40%

60%

80%

100%

120%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2009 2010

Heavy (Fuel oil/other products) Middle distillates

Light distillates (Aviation fuel/Kerosene/Gasoline) Refining throughput / equity oil production, right

1,220

1,240

1,260

1,280

1,300

1,320

1,340

1,360

1,380

1,400

2009 2010

Retailing stations (Total)

75



Summary

Essar Energy is committed to an aggressive growth strategy in its refining business –this is partly inspired by a very positive medium/long-term outlook for product demand growth in India and its ability to export products to quite distant demand centres.

We expect the company's net refining capacity to reach around 750 kbopd by end March 2013 from 210 kbopd as at end 2010. This results from a combination of relatively higher margin additional capacity for Vadinar (+195 kbopd) plus the capacity addition from the Stanlow refinery acquisition (+296 kbopd), which brings exposure to weaker European refining margins.

Our downstream EV (as included in our Essar Energy's sum-of-the-parts) is approximately $5.3bn. This represents 38% of our corporate EV of around $14.1bn (SOTP of around £4.9 per share). Given the aforementioned ramp-up in the refining capacity and complexity by end March 2013, we see downstream EBIT potential in 2013E of approximately $1.2bn. Adding downstream depreciation of around $0.2bn, this implies a 2013E EBITDA of $1.4bn and an EV/EBITDA multiple of only 3.8x –which seems conservtive. The stock trades at a discount of c.50%+ to our SOTP. We believe that investors are pricing in excessively high 'execution risk'.

Aggressive growth agenda in

refining business

2013E downstream EBITDA of

c.$1.4bn clearly supports the

$5.3bn EV of downstream business

76



Galp Energia

Overweight

Company DataPrice (€) 13.00Date Of Price 06 Sep 11Price Target (€) 20.00Price Target End Date 31 Dec 1152-week Range (€) 16.97 - 11.60Mkt Cap (€ bn) 10.8Shares O/S (mn) 829

Galp Energia (GALP.LS;GALP PL)

FYE Dec 2010A 2011E 2012EAdj. EPS FY (€) 0.37 0.46 0.75Bloomberg EPS FY (€) 0.40 0.42 0.72Adj. EBIT FY (€ mn) 524 676 991Pretax Profit Adjusted FY (€ mn)

426 532 836


306 394 613

Adj P/E FY 35.2 28.0 17.3Div Yield FY 1.3% 1.3% 1.3%EV/DACF FY 21.1 17.2 14.8Source: Company data, Bloomberg, J.P. Morgan estimates.

Downstream overview


Galp has evolved into an integrated name from being a pure play Portugal-focused refining name (pre-IPO in 2006). The downstream business of this name is concentrated in Portugal.

Galp’s Refining & Marketing business involves supply, logistics and refining of crude oil and marketing and supply of products. Galp owns two refining assets: (i) Sines – started operating in 1979 and has a refining capacity of 220 kbopd and a Nelson complexity index of 6.3 - post upgrade it will increase to 7.7 and (ii) Porto -started operations in 1969 and has a refining capacity 90 kbopd. This refinery has a NCI of 7.9 - post upgrade it will increase to 10.7. Galp's downstream segment also includes its chemicals business – this is relatively small and we have not separated it from the segmental numbers as Galp does not make any separate disclosure for its chemicals business.

Downstream strategy

Galp continues to make significant investment in the downstream business – both refining and marketing. The company plans to increase profitability by raisingrefinery complexity and strengthening the refinery products/marketing coverage:

Increasing the complexity of the refining system – Upgrade projects will be a plus for Galp's gross refining margin – mostly benefitting from a higher yield and utilization, lower cost crude diet and lower plant energy costs.

Focus of the marketing business is on Iberia – Galp consolidated its marketing presence in the region by acquiring the retailing businesses of ENI and Exxon Mobil in Iberia. The company is looking at increasing the synergies arising fromthese acquisitions.


Galp's only growth projects are the conversion projects at Sines and Porto – these assets lie at the lower end of the complexity range for the refineries located in Europe. Therefore these upgrades will be a plus for Galp’s gross refining marginpotential – mostly on account of the improved product mix and crude diet and lower own energy consumption costs. The projects are scheduled to be on-stream end 2011.

Galp Energia is a European Analyst Focus List stock

Aligning the product slate to

Portuguese/Iberian demand

trends

Sines and Porto upgrade projects

77



Galp Downstream Efficiency Overview


Galp's refining base has remain unchanged between 2000-10 – the refining capacity will increase from 310 kbopd to 330 kbopd as the upgrade/expansion projects come onstream at the end of this year. The 2000-10 average refinery utilization was 80% -this is below the euro sector average. In our view, this is a reflection of the low complexity and ageing refining system of Galp. Also, in recent years, system utilization has suffered from weakening product demand in Iberia.


Galp's product slate has remained stable through 2000-2010 given no change to its refining base. The only notable slate shifts have been a small increase in aviation fuel (from 5% to 8% by volume) and fuel oil (from 15% to 17% by volume) and a small reduction in gasoline output (from 38% to 35% by volume) – middle distillate yield has remained largely unchanged. Given a very small production base of just 12kboepd versus a refining capacity of 310 kbopd, Galp’s product/equity oil cover ratio is not very meaningful. This ratio will rapidly decline as output from the company's Brazilian pre-salt assets ramp up.

Retailing network

Galp has increased its network scale by 1% CAGR over the 11-year period 2000-10. In so doing, it has raised its network’s exposure to Spain from 23% to 49%, mainly a result of Galp's acquisition of Agip's and Exxon Mobil's oil products marketing business in Iberia in 2008 (the addition of 497 service stations). In the same year, Galp also acquired Shell's marketing business in Mozambique, Swaziland and Gambia – growing the company's small marketing footprint in Africa (103 service stations).


Galp delivered average earnings per barrel processed of €2 per bbl over the period 2000-10, well below the comparable average for Repsol YPF, the other name with a big downstream exposure to Iberia. Galp’s average post tax 2004-10 ROFA is 16%,but this declined significantly in the recent downcycle (2008-10 average was only 8%) – highlighting the need to realign the company's crude diet and product slate torestore downstream profitability. We support the company's investment in refinery upgrades, which ought to help Galp's downstream margins starting 2012.


Galp's downstream cash generation (excluding changes to working capital) has been negative in the past three years. This negative cash flow (in 2008-10) is due to the company's acquisition of Exxon and Agip's downstream business in 2008 and higher capex spend on refinery upgrades in 2009-2010 . This increased spend also ‘spiked’ Galp’s capital expenditure to depreciation ratio. This ratio has averaged 1.5x 2000-10, which is low despite the high investment in recent years. We believe that the historical underinvestment (2000-2007) is one of the key reasons for Galp’s low refining margins in the recent downturn.

Stable refining base

Product slate almost unchanged

2000-10

Focused on Iberia – rising

exposure to Spain

Consistently profitable and robust returns

Recent investment has resulted

in negative cash flow

78



Figure 82: Galp - refining capacity (kbopd) & utilization (%)


Figure 83: Galp - number of refineries & average size (kbopd)


Figure 84: Galp – refinery yield

Source: J.P. Morgan

Figure 85: Galp - retailing network size & location

Source: J.P. Morgan

Figure 86: Galp - downstream profitability ($/bopd) & post-tax ROFA (%)

Source: J.P. Morgan

Figure 87: Galp - downstream cash flow ($m) & capital intensity (x)

Source: J.P. Morgan

79



Summary

In recent years, Galp has pursued an aggressive downstream investment strategy, which is one of the key reasons for the increase in the company’s indebtedness. The company has invested in both its refining and marketing (retail and wholesale) businesses. We believe that the company's refining assets have long suffered from under-investment - 2000-07 average capex/deprecation ratio is only 0.7x - this contributed to their weak performance in the 2009-2010 downcycle.

We believe that post upgrades, the profitability of Galp's refining system will improve significantly. Post upgrades (end 2011), we expect a boost to the company's refining margin given a product slate that will be better aligned to market demand, a lower cost crude diet and reduced own energy costs.

Our downstream EV (as included in our Galp sum-of-the-parts) is approximately €3.2bn. This represents 15% of our corporate EV of around €20.9bn - we adjust our SOTP to €21 from €22 - as we update for end Q2 net debt and refresh $/€ spot rate. We note that our total value of €3.2 bn equates to a 2012E EV/EBITDA multiple of almost 5.1x.

.

Investment to improve asset

quality and profitability

Improved downstream

profitability will support growth

ambitions

Downstream EV of €3.2bn seems

reasonable given 2012E EBITDA

of €0.6bn

80



OMV

Neutral

Company DataPrice (€) 25.80Date Of Price 06 Sep 11Price Target (€) 29.00Price Target End Date 31 Dec 1152-week Range (€) 34.90 - 20.81Mkt Cap (€ bn) 7.7Shares O/S (mn) 298

OMV (OMVV.VI;OMV AV)

FYE Dec 2010A 2011E 2012EAdj. EPS FY (€) 3.76 4.03 4.43Adj P/E FY 6.9 6.4 5.8Adj. EBIT FY (€ mn) 2469 2601 3081Net Attributable Income FY (€ mn)

1,118 1,316 1,453

Dividend (Net) FY (€) 1.00 1.05 1.07Gross Yield FY 3.9% 4.1% 4.2%Bloomberg EPS FY (€) 3.99 3.80 4.35EV FY (€ mn) 11,955 11,882 11,861Pretax Profit Adjusted FY (€ mn)

2,097 2,401 2,914

Source: Company data, Bloomberg, J.P. Morgan estimates.

Downstream overview


OMV’s downstream business spans manufacturing, distribution and marketing activities for oil products and petrochemicals. The company's downstream business has three broad geographical sub-segments – Austria/ central Europe, Romania/south eastern Europe and Turkey (following the recent acquisition of an additional stake in Petrol Ofisi).

We have excluded the minority stake in Petrom from our analysis and accordingly adjusted the consolidated reported numbers. OMV has not reported segmental details of its net fixed assets and we have therefore used total downstream assets as a proxy in our analysis (2005-10) – we concede that this difference unjustifiably burdensOMV's return on net assets when compared to some of its European peers. We encourage OMV to disclose comparable information.

The acquisition of Petrom (51% stake) in 2004 brought transformational change tothe company's downstream business. Restructuring this business remains the key challenge for management.

Downstream strategy

OMV's downstream strategy is to adapt and restructure its downstream assets and reduce fixed costs to strengthen the operating performance of the business. The company is also progressing with the divestment/shutdown of non-core low margin/lossmaking assets (e.g. the Arpechim refinery in Austria). Ultimately, OMV aims to have a better downstream profitability.

Deliver on Petrom restructuring – Weak downstream operating results from Petrom have been a consistent drag on OMV's overall downstream performance. A successful restructuring of Petrom’s downstream business will give a boost to segmental profitability. OMV is investing in the mordernisation of the Petrobrazi refinery and has shut down the Arpechim refinery.

Integrate Petrol Ofisi and capture the profitability upside – Management is conscious that Petrol Ofisi is facing a challenging environment in the short term, but remains convinced on the profitability upside for the business.

Deliver on restructuring targets

and adapt the downstream portfolio

81




OMV has only one material downstream project – the modernization of its Petrobrazi refinery in Romania. This project entails 2010-14 investment of €750m with theinstallation of a thermal cracker and bitumen plant. OMV also estimates that post modernization, the own energy consumption of the Petrobrazi refinery will come down from 11.5% to 10% and the plant’s product yield of middle distillates will increase from 38% to 45%.

OMV Downstream Efficiency Overview


OMV’s refining capacity is located in Austria/Bavaria (West) and Romania (East). The refining capacity of the company has more than doubled since 2000 due to two transactions – the acquisition of a 45% stake in Bayernoil (2003) and the acquisition of a 51% stake in Petrom (2005). Some of this growth will be offset by the closure of Arpechim in 2011. The refinery utilization for OMV has averaged 89% 2000-2010, but this has clearly fallen in the recent down cycle.


OMV does not disclose its yearly product slate – but we believe that the complexity of its refining system has declined since 2000 given that Petrom refineries are of very low complexity. OMV's product/equity oil cover ratio declined from 420% (in 2000) to 193% (in 2010) – the key reason was the strong growth (> 2x) in its equity oil volumes following the Petrom acquisition in 2005. We expect this ratio to fall further in 2011 following closure of the Arpechim refinery (c.70 kbopd).

Retailing network

OMV sells fuels under two brands – OMV (VIVA shops) in Europe and Petrol Ofisi in Turkey. OMV's retail network has grown by an average of 5% per annum over the 10-year period 2000-2010. This very strong growth in the company’s marketing network is due to two key transactions – (i) the acquisition of Aral, BP and Avantifilling stations in 2003 and (ii) the Petrom acquisition in 2005. Following the acquisition of Petrol Ofisi in 2011, the marketing business has grown strongly this year, as has OMV's retailing exposure outside Europe.


OMV reported an operating loss for the segment in 2009 – the only year in which OMV reposted a downstream loss since 2000. OMV's downstream business has generated a below par return on net fixed assets with an average 2000-2010 ROFA of 5%. We believe that the low margin/loss-making refining business in Romania (Petrom) has been and remains a drag on the company's results.


OMV's downstream cash generation (excluding changes to working capital) has been negative in 4 of the past 5 years. The reason for this negative cash flow is the high capex spend by the company – mostly refinery upgrade spend in recent years (West refineries and now East) and acquisitions. This higher spend has also increased the depreciation to capex ratio, which averaged 2.6x in 2000-10.

Petrobrazi modernization project

Downstream growth driven by

acquisitions

Product yield shifts to more

diesel and aviation fuel, less

gasoline

Exposure to Turkey will increase, reliance on

acquisitions for growth

Consistently profitable and

robust returns

Weak free cash flow profile

82



Figure 88: OMV - refining capacity (kbopd) & utilization (%)

Source:


Figure 89: OMV - number of refineries & average size (kbopd)


Figure 90: OMV - retailing network size & location

Source: J.P. Morgan

Figure 91: OMV - downstream profitability ($/bopd) & post-tax ROFA (%)

Source: J.P. Morgan

Figure 92: OMV - downstream cash flow ($m) & capital intensity (x)

Source: J.P. Morgan

83



Summary

Whilst we concede that OMV has made good progress in divesting of the loss-making downstream activities of Petrom (closure of Arpechim refinery, transfer of Petrochemicals business in Romania etc), we also believe that the path ahead remains challenging' - delivery of the Petrobrazi refinery modernisation project is very important for improving the profitability of Petrom's refining business..

OMV's downstream growth strategy has been clearly based on acquisitions (Petrom, Petrol Ofisi etc). We believe that the company needs to now integrate and capture the profitability upside of some key recent acquisitions like Petrol Ofisi. Management has been robust in its defence of the 'integrated business model of OMV' and therefore we believe that it is unlikely that OMV will pursue an agressive downstream divestment strategy.

Our downstream EV (as included in our OMV sum-of-the-parts) is approximately €4bn. This represents 26% of our corporate EV of €16.6bn. We reduce our SOTP by 12% to c.€37 from €42 – this reflects dilution from the company's recent rights issue, some downward adjustments to our downstream EV and we also refresh the spot €/$ rate. We note that our total value of €4 bn equates to a 2012E EV/EBITDA multiple of almost 4.9x - this is seems reasonable.

Delivery on Petrom restructuring

is the key near-term target

Focus on profitablable growth

Downstream EV of €4bn seems

reasonable given 2012E EBITDA

of €0.8bn

84



Repsol YPF

Neutral


Repsol YPF (REP.MC;REP SM)

FYE Dec 2010A 2011E 2012EAdj. EPS FY (€) 1.66 1.97 2.39Bloomberg EPS FY (€) 1.74 1.92 2.40Adj. EBIT FY (€ mn) 4,714 5,207 6,399Pretax Profit Adjusted FY (€ mn)

3,856 4,538 5,827


2,032 2,402 2,916

Adj P/E FY 11.1 9.4 7.7EV/DACF FY 5.7 5.4 6.1Div Yield FY 4.8% 5.2% 5.8%Source: Company data, Bloomberg, J.P. Morgan estimates.

Downstream overview


Repsol YPF’s downstream business consists of the supply and trading of crude oil and products, oil refining, marketing oil-based products and LPG, as well as the production and marketing of chemical products. The business is mainly concentrated in Spain and Latin America (Argentina). For the purposes of financial reporting, the company now includes its downstream business in Argentina under the YPF segment; we have therefore consolidated YPF downstream (net interest of Repsol YPF) with the group downstream segment. Further, we have not excluded the chemical results from this segment as Repsol YPF does not make a separate disclosure of this sub-segment. In recent years, chemicals operating results have been negative - this is therefore a drag on the downstream performance of Repsol YPF versus other European competitors like TOTAL. Further, Repsol YPF does not report segmental details of its net fixed assets and we have therefore used total downstream assets as a proxy in our analysis – we concede that this difference unjustifiably burdens Repsol YPF's return on net assets versus some of its European peers. Again, we would encourage management to raise its disclosure standards.

Downstream strategy

Repsol YPF has continued to invest in downstream (refinery upgrade projects) through the cycle - a key difference in the company's downstream strategy versus the majority of its competitors in Europe.

Increase middle distillate yield – Repsol YPF has invested c.€4bn (Cartagena and Bilbao refineries) to increase the capacity and complexity of its refining system in Spain – it plans to increase its middle distillate yield to supply the diesel short Spanish market.

Reduce Argentine exposure – This theme cuts across the different business segments – a progressive divestment of its stake in YPF has resulted in lower downstream exposure to Argentina.


There are two key growth projects for Repsol YPF's downstream business: (i) expansion project for the Cartagena refinery - this expansion project includes a hydrocracker, a coker, new atmospheric and vacuum distillation units and desulphurization and hydrogen plants at its main units. It will double the refinery’s

Downstream includes chemicals

- a drag for operating results

Investing in downstream growth

Upgrade projects in Spain will help profitability

85



capacity to 220,000 bopd and (ii) Increase conversion capacity at Bilbao – Repsol YPF plans to install a new coker (2MT pa capacity) at the Bilbao refinery. These projects are scheduled to come on-stream end Q3 / early Q4 2011. Post upgrade, the middle distillate yield of the complex will be 50%+ and the FCC equivalent will grow from 43% to 63%.

Repsol YPF Downstream Efficiency Overview


Repsol YPF’s refining assets are primarily concentrated in two countries - Spain and Argentina (via YPF). The acquisition of YPF in 1999 grew its downstream business. More recently, the piecemeal divestment of its YPF stake (starting in 2007-2008) has been a key reason for the reduction in the company's exposure to Latin America – we use net economic interest of Repsol YPF in YPF for the purpose of our analysis. Repsol YPF's refining capacity will grow this year as the Cartegena expansion (+110kbopd) comes on-stream in Q3/Q4 2011.


Given that the refining assets of Repsol YPF have not changed/gone through major upgrades in last decade, the company's refining slate has also remained largelystable. There has been a marginal decline in fuel oil (from 17% to 14% by volume) and a marginal increase in diesel output (from 46% to 48% by volume). Declining oil production in Argentina has meant that the refining throughput/equity oil production has increased from 158% in 2000 to 236% in 2010. This ratio will increase further as new refining capacity comes on-stream this year and oil production continues to decline in Argentina.

Retailing network

Repsol YPF sells its products under five brands in Spain (under Repsol, CAMPSA and Petronor brand names) and in Argentina (under YPF and Refinor brand names). Repsol YPF has reduced its network scale by an average of 2% per annum over the 11-year period 2000-10. In so doing, it has raised its network’s exposure to Europe from 53% to 67% and reduced its Latin American exposure from 47% to 33%. Repsol YPF recently exited retailing in Brazil (327 stations). Product sales in Spain have declined by an average of 3-4% pa, which is a challenge for the business.


Repsol YPF's downstream business has reported a full year operating and net profit in every year since 2000. Repsol YPF has delivered a return on net fixed assets that has averaged 11% 2000-10. We acknowledge that Repsol YPF's downstream performance has been burdened by the very weak operating results of its Chemicals –a disadvantage versus other European competitors. We also highlight that between 2000 and 2010 Repsol YPF generated an average of €3.2 post tax per bbl.


Repsol YPF's downstream cash generation (excluding changes to working capital) has been negative in only one year (2009) since 2000. Negative cash flow in 2009was due to high capital expenditure on the upgrade projects and a very weak operating environment. Repsol YPF's depreciation/capex ratio has averaged 1.6x 2000-10 – this ratio has increased since 2007 as the company started its investment in the upgrade projects.

Stable refining capacity in Europe, declining capacity in

Latin America

Higher diesel output

Increase in European exposure

and reducing exposure to Latin

America

Consistently profitable

Increase in capital intensity and

consistent free cash flows pre investment

86



Figure 93: Repsol YPF - refining capacity (kbopd) & utilization (%)


Figure 94: Repsol YPF - number of refineries & average size (kbopd)


Figure 95: Repsol YPF- refinery yield and output / equity oil cover ratio (x)

Source: J.P. Morgan

Figure 96: Repsol YPF - retailing network size & location

Source: J.P. Morgan

Figure 97: Repsol YPF - downstream profitability ($/bopd) & post-tax ROFA (%)

Source: J.P. Morgan

Figure 98: Repsol YPF - downstream cash flow ($m) & capital intensity (x)

Source: J.P. Morgan

87



Summary

Repsol YPF's strategy of heavy investment in European refining is completely at odds with the 'shrinking refining theme' noted with the other euro names. We believe that Repsol YPF's strategy is supported by the market dynamics in Spain (diesel short market) and therefore the incremental investment has the potential to deliverimproved returns. However, we also believe that the influence exercised by the Spanish state on the company and the company’s role as the national energy champion of Spain means that it must remain committed to Spanish refining. So, we do not expect any shift in Repsol YPF's commitment to Spanish refining even if conditions worsen.

Given the significantly improved credentials of the company in the high margin upstream business, we do not expect the company to announce any other major investment projects for the downstream business. Even at existing levels, the company’s equity oil production/ refining throughput ratio is amongst the highest in the euro majors.

Our downstream EV (as included in our Repsol YPF's sum-of-the-parts) is approximately €11.5bn. This represents 31% of our corporate EV of around €36.5bn( SOTP of around €28 per share). Post refinery upgrade and expansion projects (Cartegena and Bilbao), we see downstream EBITDA potential in 2012E of approximately €2.7bn assuming no loss of profitability. This implies an EV/EBITDA multiple of 4.2x – which seems reasonable, if not a shade conservative.

.

Growth capex in refining should

end this year

Earnings exposure to European

refining will remain high

Downstream EV of €11.5bn looks

reasonable given the 2012E

EBITDA of €2.7bn

88



Statoil

Underweight

Company DataPrice (Nkr) 121.00Date Of Price 06 Sep 11Price Target (Nkr) 145.00Price Target End Date 31 Dec 1152-week Range (Nkr) 161.70 -

108.10Mkt Cap (Nkr bn) 385.4Shares O/S (mn) 3,185

Statoil (STL.OL;STL NO)

FYE Dec 2010A 2011E 2012EAdj. EPS FY (Nkr) 13.14 17.22 17.08Bloomberg EPS FY (Nkr) 13.40 16.56 18.54Adj. EBIT FY (Nkr mn) 142,730 171,419 172,468Pretax Profit Adjusted FY (Nkr mn)

141,630 171,419 172,468

Net Attributable Income FY (Nkr mn)

42,232 54,467 54,036

Adj P/E FY 9.2 7.0 7.1EV/DACF FY 6.2 4.6 4.7Div Yield FY 4.6% 4.8% 5.1%Source: Company data, Bloomberg, J.P. Morgan estimates.

Downstream overview


Statoil's downstream business is now divided into two business segments -Manufacturing and Marketing and Fuel & Retail. This business is responsible for the group's combined operations in the transportation of oil, processing, sale of crude oil and refined products, retail activities and marketing of natural gas in Scandinavia.

Statoil's downstream business is also responsible for the processing and sale of the Norwegian state's production of crude oil and natural gas. The fuel and retail arm of the business was listed in 2010 and therefore this business is now held in a separate company in which Statoil has a 54% stake - we have accordingly for the purpose of our analysis taken the net economic interest of Statoil in Fuel and Retail into consideration. Investor focus on this segment has been understandably limited given Statoil's very limited exposure to the downstream business. Statoil does not report segmental details of its net fixed assets and we have therefore used total non-current assets of the segment as a proxy in our analysis – we concede that this difference unjustifiably burdens Statoil's return on net assets versus some of its European peers.

Downstream strategy

Supports dominant upstream - Focus on maximizing the value of the group's equity oil and NGL production The strategy of Statoil's downstream business is centered around the maximization of the value of the company's upstream production of crude oil and natural gas liquids (NGL). Unlike the majority of its European peers, Statoil has not made significant investments in its downstream business over the last decade. The carving out of the fuel and retail arm in the IPO in 2010 was an innovative strategic step in the right direction.

Further reduction in downstream exposure – Statoil's management believes that the market fails to reflect the value of the company's non-upstream assets and therefore further divestments remain on the agenda – the recent listing of the fuel and retail business is a case in point.

Strengthen the global trading arm - Recent capex in the segment has been focused on the oil sales, supply and trading business – Statoil is one of the world's biggest net sellers of crude oil because it handles the crude volumes on

Small downstream footprint

89



behalf of the Norwegian state. Statoil does not have any significant investment planned for its refining business.

Growth in renewable space – Statoil is looking to grow its renewable energy business and is looking to utilize its extensive experience from offshore operations.

Statoil Downstream Efficiency Overview


Statoil's refining capacity has not changed since 2000 given no impact from the 2007 merger with the oil and gas business of Norsk Hydro, which did not bring any additional refining capacity to the group. It is noteworthy that Statoil has not made any growth investments in its refining business even through the business up-cycle (since 2000) – a clear indication that the strategic priorities of this company lie upstream. The 2000-10 refinery utilization of the company has averaged a healthy 92%. The decline seen in 2010 was mainly due to the planned turnarounds at the Mongstad and Kalundborg refineries.


Given that its refining system has changed little over the past decade, its refining yield has also remained stable. The only notable shifts in product slate have been a small increase in gasoline (from 36% to 38% by volume) and middle distillates (from 37% to 39% by volume) and a small decline in fuel oil yield (from 9% to 7% by volume). The merger with Norsk Hydro upstream in 2007 meant that the equity oil production of the company increased without any compensating increase in refining capacity - the ratio of refinery throughput to equity oil production has therefore fallen from 33% in 2000 to 23% in 2010. We expect the refining throughput to equity oil production ratio to remain low over the medium and long term as Statoil does not have any major identified growth projects in refining.

Retailing network

In the mid-1980s, Statoil's marketing business expanded outside the Norwegian market. There were two key transactions with Exxon Mobil: (i) purchase of Esso stations in Sweden in 1985 and (ii) acquisition of Exxon’s Danish fuel station network in 1986. In 2009, Statoil acquired the network of automated stations under the JET brand from ConocoPhillips in Sweden and Denmark. As a condition to clearance of the acquisition, the EU Commission required the sale of the JET branded stations in Norway to a third party and the sale of 158 fuel stations in Sweden, most of which had been gained during the merger between Statoil and Norsk Hydro in 2007.

Statoil listed its fuel retail arm in 2010 – Statoil Fuel & Retail ASA - a move that helped the company demonstrate the value of a sub-segment, albeit one that had a very limited impact on Statoil's equity value given the small footprint. In the near term we do not believe that Statoil has any intention of reducing its controlling 54% stake in its retail arm. Therefore on a net ownership basis, Statoil has managed to reduce the number of its retail outlets by 5% CAGR 2000-10 given that the company now holds a 54% stake in the fuel and retail business.

No change in refining capacity since 2000

Stable refining yield and low

refining throughput to equity oil ratio

First euro name to list its

marketing business

90




Statoil's downstream business has delivered positive operating results in every year since 2000. The company has delivered a positive return on net fixed assets, with avery healthy average 2000-10 ROFA of 18%. We believe that Statoil's downstream performance has been helped by strong integration with the upstream – resulting in reliable and appropriate quality crude feedstock supplies for its refining business. A dominant marketing position in Scandinavia has also been a strong plus for the downstream profitability. Between 2000 and 2010 Statoil generated an average of Nkr 41 post tax per barrel of refinery throughput.


Statoil’s downstream cash generation has been negative in only one year since 2000. Negative cash flow in 2008 was primarily due to the acquisition of the South Riding point crude oil terminal lease. Statoil’s capital expenditure to depreciation ratio averaged 1.7x 2000-10. This ratio has been buoyed by the company's investments inthe oil trading/supply business and associated infrastructure. We do not expect any major shift in the very healthy downstream cash flow profile of Statoil in 2012/13 -the company has not announced any major refinery upgrade/expansion projects.

Consistently profitable operations

Healthy cash flow generation

pre-acquisitions

91



Figure 99: Statoil - refining capacity (kbopd) & utilization (%)


Figure 100: Statoil - number of refineries & average size (kbopd)


Figure 101: Statoil- refinery yield and output / equity oil cover ratio (x)

Source: J.P. Morgan

Figure 102: Statoil - retailing network size & location

Source: J.P. Morgan

Figure 103: Statoil - downstream profitability ($/bopd) & post-tax ROFA (%)

Source: J.P. Morgan

Figure 104: Statoil - downstream cash flow ($m) & capital intensity (x)

Source: J.P. Morgan

92



Summary

Investors have historically not focused on the downstream business of Statoil given its absolute small downstream footprint and the much larger scale of its upstream business - this will not change. Statoil's listing of its marketing business was clearly astep in the right direction - transitioning downstream capital employed to upstream Statoil's strong retail brand in Scandinavia was a key plus in this process. However, the valuation impact of this listing was not very meaningful to Statoil's equity value.

We believe that divestment of the refining business could be the next step on management’s agenda - this is clearly not a core focus area for the company and we believe that this small base of refining assets does not get appreciation (value focus) from investors within what is largely a pure play upstream company. We also note that the company has been very active in recent years in monetising the value of its non core assets – supporting our contention of a possible divestment of refining assets. Whilst we concede that management has been rightly cautious in its refining investment (no growth in capacity since 2000), we also believe that the company can now be more aggressive and hive off parts of its refining business which are facing more severe margin pressure. Recent listing of the marketing business provides a good ‘template' for the divestment of Statoil's refining assets. The company has not commented explicitly on the likelihood of divestment of refining assets.

Our downstream EV (as included in our Statoil's sum-of-the-parts) is approximately Nkr 24 bn. This represents just 4% of our corporate EV of c.Nkr683bn (SOTP c.Nkr190 per share). We note that our Statoil downstream's value of Nkr 24bn equates to a 2012E EV/EBITDA multiple of 3.7x. This seems fair enough, if not conservative in our view, especially given almost one third of our downstream EV is represented by the market value of Statoil’s 54% stake in Statoil Fuel & Retail ASA.

Small downstream business has

limited share price relevance

Refining capacity divestment

could be on management’s

agenda

Downstream EV of Nkr 24bn

implies a 2012E EV/EBITDA of

c.3.7x - supported by market value of fuel and retail stake

93



TOTAL

Neutral


TOTAL (TOTF.PA;FP FP)

FYE Dec 2010A 2011E 2012EAdj. EPS FY (€) 4.64 5.56 5.43Bloomberg EPS FY (€) 4.65 5.32 5.38Adj. EBIT FY (€ mn) 21,503 26,061 25,051Pretax Profit Adjusted FY (€ mn)

21,277 25,681 24,711

Adj P/E FY 6.8 5.7 5.8Div Yield FY 5.8% 6.2% 6.6%EV/DACF FY 5.3 5.1 5.0Dividend (Net) FY (€) 2.28 2.44 2.56Source: Company data, Bloomberg, J.P. Morgan estimates.

Downstream overview


TOTAL's downstream segment includes the company's refining, marketing, trading and shipping businesses. TOTAL's downstream business is concentrated in Western Europe and Africa. In 2010, TOTAL's worldwide sale of refined products was 3,776 kbpd.

Refining - TOTAL holds interests in 24 refineries, including 12 (pre-CEPSA divestment) that it operates. The company produces a wide range of specialty products such as lubricants, liquefied petroleum gas (LPG), jet fuel, special fluids, bitumen, marine fuels and petrochemical feedstock.

Marketing – TOTAL markets a wide range of specialty products which it produces from its refineries and other facilities. TOTAL has a strong presence in specialty products which are sold in approximately 150 countries.

Trading & Shipping - The Trading division operates extensively on physical and derivatives markets, both organized and over the counter. The group’s Shipping division arranges the transportation of crude oil and refined products necessary for the group’s activities.

Downstream strategy

TOTAL’s downstream strategy is to optimize its portfolio with a focus on improving downstream profitability - it has a target to increase this segment’s ROACE by 4% and to double its net cash flow by 2015. Management has acted to rid its downstream portfolio of underperforming/non core assets (divestment of CEPSA stake), and plans to focus on large projects and growing markets (e.g. via a 37.5% stake in the Jubail refinery in Saudi Arabia).

Shrinking the European refining base and focus on most competitive assets –In an effort to concentrate on its most competitive refining assets, TOTAL targeted a reduction over 2007-11(e) of 500 kbopd or around 20% of its global refining capacity. The company is largely on track to exceed this target - key actions have been the closure of its Dunkirk refinery and the sale of its CEPSA stake.

Realigning the existing assets to the market – TOTAL is aiming to improve the product slate of its refining system, increasing the output of middle distillates(higher margins) and reducing production of loss-making/lower margin products.

Optimization of the downstream

portfolio – shrinking the refining

base in Europe

94



Growing in emerging markets – TOTAL is looking to make downstream investments in selective growing markets to gain exposure to the Middle East, Africa and Asia.

TOTAL Downstream Efficiency Overview


TOTAL's downstream business was transformed by two key mergers, first between TOTAL and Petrofina in 1999. In the same year, the merged entity, renamed Totalfina, offered to acquire Elf Aquitaine – the boards of both companies ultimately recommended a ‘friendly’ merger. The size of TOTAL's refining network peaked in 2005. The process of rationalizing the company's refining capacity was started by the new management team, now led by Christophe de Margerie, in 2007 - stressing the need to improve downstream profitability. The process has gathered momentum in 2010/11 – the company has divested its stake in CEPSA and closed the Dunkirk refinery.


TOTAL’s refining slate has changed a little over the past decade. The notable shifts in the product slate have been a decline in gasoline (from 26% to 18% by volume) and a small increase in other products (from 15% to 18% by volume) and fuel oil output (from 10% to 12% by volume). TOTAL plans to increase the middle distillate yield of its refining system via the divestment of some low complexity projects and investment in new higher complexity projects (like the Jubail refinery on the east coast of Saudi Arabia). Very modest production growth in the last decade means that TOTAL's equity oil to refining throughput ratio has remained above 150% - we expect this ratio to decline in 2011 (given the recent refining divestments) before increasing again as the Jubail refinery comes on-stream in 2013.

Retailing network

TOTAL’s marketing network includes TOTAL and Elf branded stations. In Italy, TotalErg (a joint venture between TOTAL 49% and Erg 51%) operates under both TOTAL and ERG brand names. After a steady decline 2000-09, TOTAL's marketing network grew strongly in 2010, mainly a result of the aforementioned JV with ERG. TOTAL’s marketing business (like its refining business) is strongly concentrated in Western Europe and the company is looking to grow selectively in the growth markets (Asia, Central Europe and Latin America).


TOTAL has delivered an average 2000-10 post tax return on capital employed of c.22% - near the top among euro-integrated names. We have used capital employed in our analysis (instead of net fixed assets) given the material contribution made by affiliates in TOTAL's downstream results. TOTAL's downstream performance is helped by its focus and concentration in key markets and measured rates of reinvestment. TOTAL’s management has also been very active in restructuring the company's downstream portfolio in the past 12-18 months (e.g. the divestment of its stake in CEPSA, divestment of marketing assets in UK, closure of the Dunkirk refinery in France, tie-up with ERG in Italy). We believe pressure on downstream margins in Europe and a view that such pressure will not relent has been a catalyst for this more proactive stance by management.

Active downsizing in 2010/11 of its refining footprint in Europe

Product yield has changed a

little with less gasoline

Heavy exposure to Western

Europe

Impressive downstream profitablity and robust returns

95




Consistent with its strong downstream profitability, TOTAL's post tax free cash flow (excluding changes to working capital) has been negative in only one year in the period 2000-10. In 2009, negative cash flow (in common with the majority of its European peers) was attributable to a very weak operating environment and higher than normal capital expenditure. The acquisition/investment in 2008 meant that the company's capex/depreciation ratio was above 2x versus a 2000-10 average of 1.4x. With this exception, TOTAL's downstream business has consistently generated cash for the group and thus contributed to the group’s dividend. We also believe that the recent portfolio changes and investments will help TOTAL to regain some of the downstream profitability lost in the recent years.

Generates positive cash flow excluding acquisitions

96



Figure 105: TOTAL - refining capacity (kbopd) & utilization (%)


Figure 106: TOTAL - number of refineries & average size (kbopd)


Figure 107: Total- refinery yield and output / equity oil cover ratio (x)

Source: J.P. Morgan

Figure 108: TOTAL - retailing network size & location

Source: J.P. Morgan

Figure 109: TOTAL - downstream profitability ($/bopd) & post-tax ROFA (%)


Figure 110: TOTAL - downstream cash flow ($m) & capital intensity (x)


97



Summary

TOTAL has made good progress in 2010-11 upgrading and restructuring its downstream business, especially downsizing its exposure to a challenging European refining environment. Management's strategy of 'shrinking in Europe and growing in emerging markets/ Asia' is sensible, albeit fairly undifferentiated.

Whilst we believe that TOTAL has made significant progress in realigning its downstream portfolio to changes in the operating environment, we also believe that there is room for further portfolio improvements – especially reducing exposure to low complexity refining in France. Post the CEPSA divestment in 2011, TOTAL’srefining capacity will have declined 13% from its peak in 2005. The next increase will occur in 2013 when the Jubail refinery is scheduled to be commissioned – this will add 150 kbopd of capacity net to TOTAL (37.5% of 400 kbopd plant).

Management is looking for a 4% increase in its downstream ROCE 2010-15 - we believe that this is an achievable, albeit a tough objective. The achievement of this target has three drivers - divestment of low margin/loss-making assets (marketing stations in UK, sale of stake in CEPSA, closure of Dunkirk etc), investment in higher margin assets (Jubail refinery) and cost reduction (control of fixed costs, reducing costs of major turnarounds, improving energy efficency etc).

Our downstream EV (as included in our TOTAL sum-of-the-parts) is approximately €18.6 bn or €8.3 per share. This represents 14% of our corporate EV of €129bn. We see downstream EBIT potential in 2012E of approximately €1.8bn. Adding downstream depreciation of around €1.3bn, this implies a 2012E EBITDA of €3.1bn and an EV/EBITDA multiple of only 5.9x – which seems fair – at the higher end of the EV/EBITDA multiple range for euro integrated names given that historical profitability of TOTAL's downstream assets has been good.

High-grading of portfolio will

help restore good profitability

Downstream EV of €18.6 bn

implies 2012E EV/EBITDA

multiple of 5.9x

98



Petrobras

PETROBRAS ON

Neutral

Company DataPrice (R$) 22.51Date Of Price 06 Sep 1152-week Range (R$) 33.92 - 20.00Mkt Cap (R$ mn) 293,627.70Fiscal Year End DecShares O/S (mn) 13,044Price Target (R$) 35.00Price Target End Date 31 Dec 12

PETROBRAS ON (PETR3.SA;PETR3 BZ)

FYE Dec 2010A 2011E 2012EEPS Reported (R$)FY 2.70 2.78 3.54P/E FY 8.3 8.1 6.4EBITDA FY (R$ mn) 60,325 63,394 76,610EV/EBITDA FY 7.0 5.8 5.1Bloomberg EPS FY (R$) 3.31 2.96 3.33Source: Company data, Bloomberg, J.P. Morgan estimates.

PETROBRAS ON ADR

Neutral

Company DataPrice ($) 27.42Date Of Price 06 Sep 1152-week Range ($) 42.74 - 24.51Mkt Cap ($ mn) 178,805.10Fiscal Year End DecShares O/S (mn) 6,522Price Target ($) 41.00Price Target End Date 31 Dec 12

PETROBRAS ON ADR (PBR;PBR US)

FYE Dec 2010A 2011E 2012EEPS Reported ($)FY 3.01 3.76 4.46P/E FY 9.1 7.3 6.1EBITDA FY ($ mn) 35,239 40,429 48,839EV/EBITDA FY 7.5 6.9 6.4Bloomberg EPS FY ($) 3.70 3.79 4.06Source: Company data, Bloomberg, J.P. Morgan estimates.

Downstream contents & structureRefining, Transportation and Marketing (RTM) is one of the five Petrobras Business Units, that comprises the downstream activities in Brazil, including refining, logistics, transportation, oil products and crude oil exports and imports and petrochemicals.

Table 8: Refining, Transportation and Marketing Key Statistics

(U.S.$ million) 2010 2009 2008

Net operating revenues 97,540 74,307 95,659Income (loss) before income tax 2,278 9,980 -3,017Total assets at December 31 69,487 49,969 27,166Capital expenditures 15,356 10,466 7,234

Source: Petrobras

Petrobras is the dominant player in domestic refining - As an integrated company, Petrobras has a dominant market share in the Brazilian market, with a limited international presence. Petrobras owns and operates 12 refineries in Brazil, with a total net distillation capacity of 2,007 kbopd, one of the world’s largest refiners. As of December 31, 2010, Petrobras operated 90% of Brazil’s total refining capacity, supplying almost all of the refined product needs of third-party wholesalers, exporters and petrochemical companies, in addition to the needs of its own distribution segment.Petrobras operates a large and complex infrastructure of pipelines and terminals and a shipping fleet to transport oil products and crude oil to domestic and export markets.Most of its refineries are located near crude oil pipelines, storage facilities, refined product pipelines and major petrochemical facilities, facilitating access to crude oil supplies and end-users.

Caio M Carvalhal

(55-11) 4950-3946

[email protected]

Banco J.P. Morgan S.A.

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Petrobras also imports and exports crude oil and oil products, with diesel being the most important import product, as Brazilian demand exceeds domestic output. The company’s strategy is to reduce this gap in the future, with new refining capacity and upgrades to existing plants to facilitate the processing of domestically produced crudes. The RTM business unit also includes petrochemical operations and two fertilizer plants.

Table 9: Petrobras' Refining Capacity

(mbbl/d) Location 2010 2010 2009 2008LUBNOR Fortazleza (CE) 7 8 7 6RECAP (Capuava) Capuava (SP) 53 36 44 45REDUC (Duque de Caxias) Rio de Janeiro (RJ) 242 256 238 256REFAP (Alberto Pasqualini) Canaoas (RS) 189 145 169 142REGAP (Gabriel Passos) Betim (MG) 151 143 140 143REMAN (Isaac Sabbá) Manaus (AM) 46 42 41 39REPAR (Presidente Getúlio Vargas) Araucária (PR) 189 170 185 183REPLAN (Paulínia) Paulinia (SP) 396 316 341 324REVAP (Henrique Lage) Sao Jose dos Campos (SP) 252 238 241 205RLAM (Landulpho Alves) Mataripe (BA) 279 250 220 254RPBC (Presidente Bernardes) Cubatão (SP) 170 160 165 168RPCC (Potiguar Clare Camarão) Guamaré (RN) 34 33Total 2,007 1,798 1,791 1,765

Source: Petrobras

Investments in existing refineries, with a focus to improve fuel quality, reached $6.7bn in 2010. In recent years, Petrobras has made substantial investments in itsrefinery system to improve gasoline and diesel quality (to comply with environmental regulations) and to increase crude slate flexibility to process more Brazilian crude (taking advantage of light/heavy crude price differentials). In 2010, Petrobras invested approximately $6.7bn in its refineries, of which $5.3bn went intohydro-treating units to improve the quality of diesel and gasoline and $1.2bn intocoking units to convert heavy oil into lighter products (compared to a total RTM capex of $15.4 bn in 2010). By the end of 2013, Petrobras is expected to reduce the maximum sulfur content of the diesel produced from 1800 ppm to 500 ppm, with some of its refineries already producing 50 ppm sulfur diesel.

Petrobras also owns and operates an extensive network of crude oil and oil products pipelines connecting its terminals, refineries and other primary distribution points. On December 31, 2010, onshore and offshore, crude oil and oil products pipelines extended 15,199 km (9,397 miles), with 28 marine storage terminals and 20 other tank farms with nominal aggregate storage capacity of 63 million barrels. Themarine terminals handle an average 10,422 tankers annually, and the company isworking in partnership with other companies to develop and expand Brazil’s ethanol pipeline and logistics network.

Until 1998, Petrobras held the monopoly on oil and natural gas pipelines in Brazil and shipping oil products to and from Brazil. The deregulation of the Brazilian oil sector in that year permitted open competition in the construction and operation of pipeline facilities and gave the ANP the power to authorize entities other than Petrobras to transport crude oil, natural gas and oil products. In accordance with this deregulation, Petrobras transferred its transportation and storage network and fleet to a separate wholly owned subsidiary, Petrobras Transporte S.A.—Transpetro, to allow third parties to access its excess capacity on a non-discriminatory basis. Petrobras

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enjoys preferred access to the Transpetro network based on historical usage levels. In practice, third parties make very limited use of this network.

Petrobras’ petrochemicals operations provide a growing outlet for the crude oil and other hydrocarbons, increasing value add and providing domestic sources for products that would otherwise be imported. Petrobras’ strategy is to increase domestic production of basic petrochemicals and engage in second generation and biopolymer activities through investments in companies in Brazil and abroad, capturing synergies within all its businesses.

The Brazilian petrochemical industry was developed with the formation of 3 petrochemical poles: Sao Paulo (1972); Bahia/Camaçari (1978) and Rio Grande do Sul/Triunfo (1982), all of them created through the stimulation of industrial settlements close to 3 of the largest Petrobras refineries and mainly controlled by the national oil company. Until today, it is around these 3 poles that almost all the first-and second-generation petrochemicals production capacity is located. This first phase of the petrochemical industry was heavily promoted by the Petroquisa action, the petrochemical arm of Petrobras, which controlled the raw material supply to the poles and was a mandatory partner of all the second-generation companies, with one-third participation (the so-called three-party model). In the 1990s, when Petroquisa was partner in no less than 36 companies, a process began of reducing the state weight in the sector, consequently expanding the role of private conglomerates. As a consequence, until recently, the Brazilian petrochemicals industry was fragmented,with a large number of small companies, many of which were not internationally competitive and were therefore poor customers for petrochemical feedstock. In a series of mergers and a capital subscription completed in 2010, Petrobrasconsolidated and restructured the Brazilian petrochemicals industry by creating Brazil’s largest petrochemicals company and one of the largest producers of thermoplastic resin in the Americas, Braskem. Braskem is a publicly traded company in which Petrobras holds a 36.1% interest. The controlling shareholder, with 38.3%, is Odebrecht S.A. (Odebrecht). Braskem operates 31 petrochemical plants, produces basic petrochemical and plastics, and conducts related distribution and waste processing operations.

The table below sets forth the primary production capacities of Braskem as of December 31, 2010:

Table 10: Braskem Nominal Capacity by Petrochemical Type – MT pa

Ethylene 3.77Propylene 1.59Polyethylene 3.06Polypropylene 2.88PVC 0.51Cumene 0.32

Source: Petrobras

Brazilian pricing dynamics

From its total refined products output, approximately 40% is subject to “loose” prices, immediately adjusted for international price variations (e.g., jet kero, petrochemical naphtha and fuel oil). However, for gasoline and diesel, Petrobrasadopts a policy of not automatically passing through the international oil price variations, until the price reaches (and stabilizes) at what could be considered a “new standard.” The concept is vague enough to encourage analysts to spend long hours

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anticipating the next move, as any variation could impact the company’s earnings almost immediately.

Are we in the “new standard” oil prices yet? We don’t think so. Our position is explained more by the lack of confidence in a stable international oil price level than by inflationary concerns. We believe that the Brazilian government is opposed to further price increases. Since 2002, Petrobras has strictly followed its policy of working as a buffer to international variations in oil prices, without automatically passing through any variation, up or down. From that date on, refined price adjustments took place only when the company’s realization price was below the international oil price and when the international oil price kept its upward trend. We believe the recent ups and downs in international oil prices will enable government policymakers to justify a soon-to-be-considered stabilization in international oil prices at a different and higher level. That said, inflationary concerns will complete the picture and possibly help to keep ex-refinery prices down.

Downstream strategyPetrobras says increasing domestic fuel demand could require all new refining throughput capacity. In our view, this makes more sense of Petrobras’ downstream expansion than its prior argument of “exporting diesel” to Europe.

We are at the beginning of what could be called a fourth phase in Brazil's downstream history, or a second round of green field expansion. We can classify the previous phases in the downstream segment in Brazil as the following:

Creation of the country’s refinery park: the current refinery park was almost entirely created up until the late 1970s, when the country’s (and consequently, the company’s) strategy was to add value to the imported crude trough refining, as there was no perspective of a domestic production to supply local demand.

Increasing capacity and improving operational design: the discoveries in the Campos Basin transformed the country’s perspectives in terms of oil balance. Nevertheless, the oil discovered was not suited for the installed refinery park, designed to process lighter imported crude. So from the late 1980s to the late 1990s, refinery investments were focused on improving the refineries’ operational design to cope with the increased domestic oil and changing consumption patterns.

Improving fuel quality driven by growing environmental concerns: the last decade was marked by the increased international concern in relation to fuel quality. As a late arrival, at least in terms of gasoline and diesel quality, Petrobras was mandated by the government to invest heavily in improving its overall fuel quality. Consequently, almost 50% of the record high RTM capex released in the 2010-14 business plan was related to fuel quality improvement.

Greenfield refinery construction: After more than 30 years since the last greenfield project, Petrobras is entering now into what could be called a fourth phase in Brazil's downstream history, or a second round of greenfield expansion.Petrobras is currently building two new refining facilities, with further expanstion projects for the short term:

Complexo Petroquímico do Rio de Janeiro - Comperj, an integrated refining and petrochemical complex, broke ground in 2008, and began construction in 2010. The 165 kbopd refinery operation is scheduled to start

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up in 2013. A second phase, scheduled for 2018, will increase capacity to 330 kbopd and add petrochemicals manufacturing.

Abreu e Lima – this is a refinery in Northeastern Brazil that was originally proposed as a partnership with Petróleos de Venezuela S.A. (PDVSA), the Venezuelan state oil company. However, given the lack of commitment from the Venezuelan company, Petrobras looks likely to pursue the project alone. Indeed, Petrobras budgets for a 100% commitment to Abreu Lima’sconstruction cost, estimated at $13bn. This refinery is designed to process 230 kbopd of crude oil to produce 162 kbpd of low sulfur diesel (10 ppm) as well as LPG, naphtha, bunker fuel and petroleum coke. The company targets the beginning of operations for 2013.

Further expansion options - In addition, Petrobras is planning two new refineries in Northeastern Brazil. Both refineries are in their design phase to process 20° API heavy crude oil, maximize production of low sulfur diesel, and also to produce LPG, naphtha, low sulfur kerosene, bunker fuel and petroleum coke. Both will be integrated with marine storage terminals: i) Premium I in the State of Maranhão – this will be built in two phases of 300 kbopd each; ii) Premium II in the State of Ceará – this will have processing capacity of 300 kbopd.

In the petrochemical segment, Petrobras has three new projects under construction atvarious stages of engineering and design:

Complexo Petroquímico do Rio de Janeiro - Comperj: plans to develop a petrochemicals complex to be integrated with the Comperj refinery to produce materials for the plastics industry;

PetroquímicaSuape Complex in Pernambuco - to produce purified terephthalic acid (PTA), polyethylene terephthalate (PET) resin, and polymer and polyester filament textiles; and

Companhia de Coque Calcinado de Petróleo - Coquepar: petroleum coke plants in Rio de Janeiro and Paraná.

We have a more positive stance on Petrobras’ recent expansion plans

We differ from the Street in believing that the market overestimates the potential downside driven by downstream investments, given that:

Approximately half of the 2010-14 downstream budget is non-discretionary, being related to the Brazilian regulatory agency requirement on increasing the fuel quality in Brazil. Going forward, investments related to this requirement are expected to decrease, as the largest bulk is targeted for the 2010-12 period.

Budgeted capex is not necessarily the same as executed capex, and if this is expected to apply to the whole investment portfolio, this is particularly true for Petrobras’ new refinery plans. Due to a combination of historical focus on upstream and a restrictive regulatory environment for infrastructure projects in Brazil, downstream projects are likely to take longer than anticipated.

Future refining units are expected to cost significantly less than the under-construction RNEST plant, as they will be designed for the lighter pre-salt oil (25 API, compared to the 16 API of the RNEST), configured for only one train (as opposed to two at RNEST), and built from replicated structures, potentially

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offering standardization benefits. The company’s “Design Competition” system for new refineries targets a 30% capex reduction. We welcome the initiative, but we prefer to wait and see the results of such program. Petrobras has contracted UOP Honeywell to provide the “state of art” technology for Refineries Premium I and II. The two refineries will be constructed in single-trains of 300 kbopd each. UOP will be responsible for better integrating the units, with maximization of energy generation and using the best technology for each single unit. RNEST’s total cost could have been lower if it was not designed to process Venezuela's synthetic oil. Petrobras conceived RNEST in two different units of 115 kbopd. The first will process Marlim's field heavy crude (26º API) while the second will process Venezuelan synthetic heavy crude (16º API).

Among the world’s listed oil companies, Petrobras is the one with the largest captive downstream market – this provides an unusual security of demand at almost any price. It is worth mentioning that in 2008, when international prices dropped from $140/bbl in June to $40/bbl in December, Petrobras kept selling its gasoline and diesel at the same price.

Petrobras targets an 8% return for its investments in downstream. The number is somewhat similar to PBR’s WACC of 8%, mentioned by the company’s CEO during the 5bn boe transfer of rights.

Investment Thesis

We see three potential triggers for Petrobras stocks in 2011 and 2012, but as of now we only see reasons to factor two of them into our investment thesis: the updated business plan and domestic oil production growth. We are not considering any increase in refinery prices for gasoline and diesel for the time being.

The updated Business Plan: We view the new Business Plan as a positive for the company, although with the potential impact partially offset by the lengthy approval process. Detailed assumptions for the next five years were pretty much in line with our model.

International oil prices . . . Our international commodities team is bullish on oil prices, albeit some cautiousness in the short term is appropriate after the OECD oil destocking announcement.

. . . and what is left for Petrobras. Conventional wisdom is only partially correct when assuming no upside for Petrobras from international oil prices. From its total refined products slate, approximately 40% is subject to “loose” prices, immediately adjusted for international price variations (e.g., jet kero, petrochemical naphtha and fuel oil). However, it is for gasoline and diesel that the bells toll. It is well known that Petrobras’s long-term policy has been to not automatically pass through international oil price variations until the price reaches (and stabilizes) at what could be considered a “new standard.” The concept is vague enough to encourage analysts to spend long hours anticipating the next move, as any variation could impact the company’s earnings almost immediately. Nevertheless, we stand alongside those who are not yet comfortable about anticipating any such move for the 2H 2011.

Are we in the “new standard” oil prices yet? We don’t think so. Our position is explained more by the above-mentioned lack of confidence in a stable international oil price level than by inflationary concerns. Although strategists were anticipating

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an oil price increase even before the “Arabic Spring” events triggered in Tunisia, it is the new geopolitical climate that has accounted for most of the recent increase rather than market fundamentals. Given the intrinsically sporadic effects of a revolutionary situation and the recent drop in international oil prices, we believe the Brazilian government has more than enough arguments to resist attempts by other stakeholders to convince it otherwise.

Valuation & Price Target Discussion

We rate the four Petrobras stocks that we cover Neutral. Our end-2012 price target for PBR is $41/ADR. Our R$35/sh YE12 price target for PETR3 is based on the PBR target using a year-end 2012 BRL exchange rate of R$1.7/USD. Our YE12 price target of $37/ADR for PBR/A applies a 10% discount to our price target for PBR. Our R$31/sh YE12 price target for PETR4 applies JPM’s year-end 2012 BRL exchange rate of R$1.7/USD to our target price for PBR/A. We value E&P portfolio of PBR using a reserve depletion model and value each of the pre-salt projects independently. We also value the downstream projects under a DCF approach that is applied for all refining system of PBR.

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Figure 111: Petrobras - refining capacity (kbopd) & utilization (%)


Figure 112: Petrobras - number of refineries & average size (kbopd)


Figure 113: Petrobras - refinery yield and output / equity oil cover ratio


Figure 114: Petrobras - retailing network size & location


Figure 115: Petrobras - downstream profitability ($/bopd) & ROFA (%)


Figure 116: Petrobras - downstream cash flow ($m) & capital intensity


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China: Refining and Marketing structure

China R&M has generally been under strict regulatory control, effectively setting the prices for gasoline, diesel and jet kerosene, in the last ten years. Naphtha and fuel oil are priced at international prices. During this period, China has been a marginal exporter and importer of products, with little impact from this on refinery economics. Prior to 2005, this price control model worked “fine” as oil prices were rangeboundat $20-30 per barrel, and the NDRC (the regulating body) changed prices according to a basket of international products. Later, the pricing formula became a cost-plus structure, referenced to a basket of crudes, but this was only effectively put in place in early 2009 and relatively well adhered to until this year (we show Brent, as the crude basket generally traded at a slight discount to Brent).

As oil prices started to move up in late 2004/early 2005, NDRC did not follow with enough price hikes, effectively pushing refiners into losses. As the majority (80%) of refining capacity in China was contained within two state-owned enterprises (SOEs), they had no choice but to continue to run refineries in order to avoid product shortages. Some ad hoc “subsidies” were given to Sinopec and PetroChina to compensate for losses, but these “subsidies” were not enough to cover losses. A refund of VAT on imported crude and some products was also implemented, alleviating some of the losses.

Downstream product price controls in China work at different levels, including ex-refinery gate, wholesale and retail levels (i.e. marketing margins are controlled), with a +/-10% flexibility for marketers. There is also a consumption tax (currently Rmb1,385/ton for gasoline and Rmb941/ton on diesel, up from Rmb277/ton and Rmb118/ton, respectively, in Jan 2009) and 17% VAT charged, adding up to retail prices. Hence, even with refiners running at losses and appearing to be subsidizing the consumers, with these taxes, Chinese retail prices have been lower than US retail prices only for very short periods (mid-2008). Hence, the notion of Chinese consumers getting subsidized fuel is generally a misnomer. Jet kerosene has recently been de-controlled, now being priced relative to Singapore import parity on a monthly basis.

In addition to controlling refining in China, the two SOEs also control marketing,with over 50% of retail stations under their names (with 80-90% of overall throughput). Either through control by NDRC or through internal pricing, the marketing segment of Sinopec and PetroChina generally report profits throughout refining loss periods. This has partially to do with a “guaranteed” marketing margin available to independent marketers, but is also likely an effective way for authorities to isolate losses in the refining segment.

Independent refineries (teapots) have been and still are a meaningful aspect of Chinese refining. They generally refine fuel oil (imported) as they do not have a crude import license. We estimate around 1.5 million bopd of capacity in this segment, with CNOOC (parent) controlling around 0.4 million bopd (in addition to their large-scale 0.24 million bopd Huizhou refinery). Facility run rates for these teapots range from 30-45% depending on prevailing economics. The government’s strategy is, however, to eradicate this segment of inefficient (energy and environmentally) facilities and to replace them with large scale SOE-owned facilities. The higher consumption tax on fuel oil in early 2009 squeezed teapot economics. However, they continue to play a major role as swing producers when profitability allows operation to continue. The ongoing closure of teapots could act as

Hong Kong, China Oil, Gas and Petrochemicals

Brynjar Eirik Bustnes, CFA AC

(852) 2800-8578

[email protected]

J.P. Morgan Securities (Asia Pacific) Limited

JPM China GRM is made up of

38% diesel, 18% gasoline, 10% kerosene and the rest at a 20%

discount to crude. Prices are ex-

refinery prices.

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a counterweight to the likely overcapacity in China developing over the next five years.

Figure 117: China GRM based on product prices and one month delayed crude (US$/bbl)

Source: J.P. Morgan estimates, Bloomberg data, NDRC.

Figure 118: China product and Brent prices (Rmb/ton)

Source: J.P. Morgan estimates, Bloomberg data, NDRC.

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PetroChina

Underweight

Company DataShares Outstanding (mn) 183,021Market Cap (Rmb mn) 2,203,573Market Cap ($ mn) 344,831Price (HK$) 9.69Date Of Price 07 Sep 11Free float (%) 13.3%Avg Daily Volume (mn) 126Avg Daily Value (HK$ mn) 1,411Avg Daily Value ($ mn) 181HSCEI 10,347Exchange Rate 7.79Fiscal Year End Dec

PetroChina (Reuters: 0857.HK, Bloomberg: 857 HK)

Rmb in mn, year-end Dec FY09A FY10A FY11E FY12E FY13ERevenue (Rmb mn) 1,019,275 1,465,415 1,432,924 1,327,399 1,332,663Net Profit (Rmb mn) 103,387 139,992 162,089 148,506 150,654EPS (Rmb) 0.56 0.76 0.89 0.81 0.82DPS (Rmb) 0.27 0.29 0.40 0.37 0.37Revenue Growth (%) (5%) 44% (2%) (7%) 0%EPS Growth (%) (10%) 35% 16% (8%) 1%ROCE 14% 17% 18% 15% 14%ROE 13% 16% 16% 14% 13%P/E 14.1 10.4 9.0 9.8 9.7P/BV 1.7 1.5 1.4 1.3 1.2EV/EBITDA 6.8 5.5 4.8 5.0 4.7Dividend Yield 3.5% 3.7% 5.0% 4.6% 4.7%Source: Company data, Bloomberg, J.P. Morgan estimates.

Downstream overview


PetroChina’s Refining & Marketing business is responsible for the supply, trading, refining, manufacturing and marketing of crude and petroleum products and related services to wholesale and retail customers. We believe most of the pipeline infrastructure-related profits are reported within the Natural Gas and Pipeline segment (so not included here). Most of PetroChina’s operation is domestic China, with deals in Singapore, Japan and Europe in the last 2-3 years adding an international presence that includes refining assets (including expansion of trading). PetroChina also has a relatively big petrochemical business, which we exclude from this analysis. Its parent CNPC also has stakes in refineries in Sudan, Algeria and Kazakhstan.

PetroChina’s R&M operation is still predominantly in Northern and Western China, as a legacy of how oil & gas assets were split up in the late 90s (PetroChina/CNPC north of the Great Wall, and Sinopec to the south). This is also how E&P assets were divided, leaving PetroChina with substantially greater upstream versus Sinopec’s much greater downstream presence in southern/eastern China. Most of PetroChina refineries are built for domestic supply, predominantly processing light and sweet crudes.

PetroChina has been increasingly involved in international trading of crude and products, but due to lack of transparency, it is not entirely clear whether this is done as part of R&M, E&P (Russian imports of crude is through E&P segment) or through the parent CNPC's operations. PetroChina has E&P producing upstream assets in Venezuela, Kazakhstan, Iraq and its parent CNPC has operations in Sudan, all of which supply international crude into PetroChina’s refining system, in addition to third party crude.

Until recently, PetroChina reported R&M as one segment – analysts were also given access to a split between refining and marketing without further details. In 2010, PetroChina switched to reporting marketing separately, while reporting refining and chemical together, again providing split between the two in less detail.

PetroChina has Chevron JV in Singapore (SRC – 290 kBOPD)

and INEOS JV in Europe

(Grangemouth, UK – 210 kBOPD, Lavera, France – 210 kBOPD,

and trading JV)

CNPC has stakes in Sudan (100

kbopd and 20 kbopd refineries), Kazakhstan (105 kbopd) , Algeria

(12 kbopd) and JX JV in Japan

(Osaka refinery – 115 kbopd)

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PetroChina’s downstream business is managed through two main groupings –refining and marketing:

Refining – this grouping is primarily the operation of refineries domestically and abroad, and possibly includes the trading of some crudes internationally. Refining includes the production of transport fuel, in addition to lubricants, asphalt, chemical feedstock and other refined products. Other than in 2001, refining has in recent years struggled to generate profits.

Marketing – this grouping encompasses primarily wholesale and retailing of transport fuels and other products from the refineries. There may be an element of trading in products internationally, in addition to more recent ramp-up of non-fuel business in retail stations.

Downstream strategyPetroChina, resident in the fastest petroleum product growth country in the world, will continue to grow capacity and related marketing network. Being an SOE, profitability is not paramount, resulting in increasing capital commitments, while profitability and returns are still in the hands of the regulator (NDRC).

PetroChina is also planning to increase its international presence, through acquiring refining assets (or stakes) as a base for increased trading activities in crude and products. This is possibly to pre-empt a greater need for international interaction, whether for imports or exports in the future. Especially for crude, this will very likely become increasingly important, as China’s demand grows faster than domestic crude production. Building to a position of excess domestic refining capacity will at times also necessitate greater exports, which should benefit from an expanded global trading presence.

Downstream performance drivers – price control and our view

We believe the current price controls will be relaxed over time, initially with the price adjustments made more frequently than currently. Current adjustments are theoretically to be made every time the 22 daily moving average of a crude basket has moved more than 4%. Due to the transparency (in theory) of this formula, and market participants taking advantage of it, we believe the window will be shortened and at some point pricing will be left entirely to the market participants (likely under the watchful eyes of regulators – as is the case most places in non-OECD). This liberalization will to a great extent depend on the path of oil prices in the next year or two. In the meantime, we expect gross refining margins “next year” (always “next year”) to normalize at around $5-6 per barrel, which is a level where PetroChina will be able to generate positive EBIT. Adding in less volatile marketing margins should result in EBIT in the range of Rmb20-25,000 per annum. There is potentially some upside to this structurally, as PetroChina starts to utilize its vast retail network for non-fuel sales, which could add a few billion Rmb to the EBIT line over five years.


PetroChina will spend most of its efforts downstream on growing refining capacity and increasing the complexity of existing refineries. Increasing its ability to refine heavier and sourer crude is vital, as China (and PetroChina) will have to increase its import dependency on foreign oil. PetroChina should increase refining capacity from a current 3 million bopd to around 4.5 million bopd by 2015. Half will be from expansions and the rest from greenfields, including JVs with foreign partners, linked

PetroChina will be focusing on

upgrading complexity of existing refineries and adding presence

in south/eastern China along

with taking marketing market share

R&M EBIT potential of around

US$3-4bn in an average year

under controlled product prices – upside from non-fuel sales

PetroChina to grow refining faster than Sinopec

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to crude purchase agreements. PetroChina will also likely add retail stations in the south/eastern part of China in order to attempt to gain market share on the back of expanded refining market share.

Table 11: China refining capacity addition – PetroChina to add an estimated 1.5 million bopd cumulative capacity over 2011-15

(000 bopd) 2011 2012 2013 2014 2015 TotalPetroChina 180 370 250 471 260 1,531Sinopec 238 240 530 300 300 1,608China overall 748 730 780 1,010 740 4,008

Source: Company estimates, J.P. Morgan estimates

PetroChina Downstream Efficiency Overview


PetroChina has 26 refineries in China in addition to 50% stakes in 4 refineries overseas. Total equity refining capacity is 3.4 million bopd as of June 2011, and we expect this to grow to 4.5 million bopd by 2015, excluding any further acquisitions abroad. The average size of its refineries has increased from less than 100 kbopd in 2000 to close to 115 kbopd. The plan is to expand a group of existing refineries further in addition to new large-scale refineries, raising energy efficiency and reducing environmental impact in line with the government’s 12th five-year plan. Although these refining complexes will be more expensive than historically, the operating economics of the new refineries should also improve PetroChina’s overall refining performance.


Product yield has remained relatively stable, as domestic demand has not changed significantly during the last eleven years. Diesel yield around 42-44% is slightly above the domestic demand profile, while gasoline yield is 20%. Kerosene yield at 2% is too low, making China a net importer of jet kerosene (although not reported as such due to international airlines filling up counting as exports).

PetroChina has gone from being net long crude to now being net short due to crude production growth lagging its refinery expansion. However, including CNPC’s equity production abroad, CNPC as a group is close to 100% covered now. We expect PetroChina’s equity oil cover ratio to drop further as it expands, with domestic production stagnating and international production likely not keeping up (unless Iraq can ramp-up according to plan). The impact on financials from this is that PetroChina will be increasingly dependent on what NDRC does to product prices (or any liberalization). PetroChina no longer sells crude (on a netted basis), and since two thirds of refined products are NDRC-controlled, less than one third of PetroChina’s production (fuel oil, naphtha, LPG etc) will be exposed to international oil prices (this is something not fully appreciated by investors). Taking into account cost escalation downstream from higher crude prices, without NDRC raising product prices, higher crude is likely negative for PetroChina’s earnings. We do, however, as mentioned above, expect NDRC to follow the current pricing formula and at some point to liberalize prices, exposing PetroChina to more “normal” earnings dynamics of an international integrated company (at least within certain oil price limits).

PetroChina has one of the world’s largest refining bases,

and is expected to expand it

Middle distillates make up more

than 50% of China demand base – PetroChina matches this

Without NDRC response to

higher crude, it is actually negative for PetroChina’s

earnings

111



Retailing network

PetroChina owns around 18,000 retail stations, predominantly in the north/western part of China. With refinery expansions, we expect its retail network will also expand, and also make room for PetroChina’s move south/east to compete with Sinopec for market share. This could have the effect of pressuring marketing margins, especially at the retail level, although we expect competition to be ‘friendly’ enough to maintain a relatively strong marketing margin. PetroChina is, along with Sinopec, also targeting to expand its non-fuel business from the retail network, which could add substantial revenues for the marketing segment.


PetroChina’s R&M profitability has been very volatile historically due to the controlled pricing regime it operates under. Marketing makes stable profits, while refining has swung from big losses to reasonable profits. Overall, its return on segment assets is below 6% (on fixed assets closer to 10%), reflecting the challenged pricing environment. Future investments will also not likely generate much higher returns, depending on how pricing develops. New and larger scale assets may have greater profitability, but will come at higher capital cost, hence maintaining returns at relatively low levels.


PetroChina’s operating cash generation in downstream turned slightly positive in 2009 after more than an estimated $10 billion in negative free cash flow in 2008, from refining losses because NDRC did not permit higher product pricing. Operating cash flow in 2010 remained fairly stable as marketing margins improved while refining declined from 2009, but a lower capex spend for 2010 resulted in around $1 billion in free cash flow for the year. Due to relatively old and depreciated downstream assets on PetroChina’s balance sheet, its capex to depreciation ratio is relatively high at 2x. It has been decreasing in recent years as segment depreciation has picked up more than capex. Going forward, we expect refining to be weak this year (losses for the full year) and depending on where oil prices go and NDRC’s response to this, we expect a pick-up in refining next year, while marketing should turn in a “normal” stable profit. Slightly higher capex in 2011/12 versus 2010 will result in negative free cash flow in 2011 and possibly $1-2 billion in 2012 (normalized), according to our estimates.

PetroChina is going south/east –where demand growth is

strongest

Risk of losses decreasing due to

pricing formula

Positive operating cash flow

expected, but FCF will be only

around US$1-2 bn normalized

112



Figure 119: PetroChina - refining capacity (kbopd) & utilization (%)

Source: Company reports, J.P. Morgan estimates

Figure 120: PetroChina - Number of refineries & average size (kbopd)

Source Company reports, J.P. Morgan estimates

Figure 121: PetroChina - refinery yield and output / equity oil cover ratio (x)


Figure 122: PetroChina - retailing network size & location


Figure 123: PetroChina - downstream profitability ($/bopd) & post-tax ROFA (%)


Figure 124: PetroChina - downstream cash flow ($m) & capital intensity (x)


75%

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Post-tax f ree cash flow ($m) Capex / depreciation (x)

113



Summary

PetroChina is moving in the opposite direction of IOCs by increasing downstream refining capacity, to match domestic petroleum product demand in China. Ideally, it wants to increase market share, especially in south/east China by adding marketing outlets in that part of China. Unfortunately, economics in China are very much in the hands of the regulator NDRC, which sets prices for transportation fuels. Prices are in theory set at cost plus, but recent higher oil prices have resulted in negative margins in refining. Marketing makes relatively stable margins and is a growth segment with upside from non-fuel sales. We do expect liberalization over the next couple of years, depending on where oil prices move.

In order to be better prepared for the greater dependency on international crude for itsgrowing refining capacity and to facilitate channels for excess products, PetroChina has in the last few years acquired refining and trading operations abroad. An increased exposure to international upstream has also been necessary, as domestic production is maturing and overall crude coverage declining. This should result in PetroChina becoming more influential in the international crude and product market over the next few years, in our view.

Our R&M EV (as included in our PetroChina DCF value) is approximately $40 billion or HK$1.40 per share. This represents 19% of our total sum-of-the-parts value of around HK$7.50 per share. Under normalized circumstances (ie gross refining margin of around $5-6/bbl), we see downstream EBIT potential in 2012E of approximately $3.5bn assuming stable profitability in marketing. Adding annual downstream depreciation of around $3bn, this implies a 2012E EBITDA of $6.5bn and an EV/EBITDA multiple of 6.2x.

In our view an EV/EBITDA multiple of 6.2x for a stable marketing business (half of EBIT) and, in theory, a stable refining business (cost plus formula) is not very demanding. However, the risk to refining profitability will continue to induce an overall multiple discount, until liberalization of product prices or lower stable oil prices brings this risk down. Also, the related investments into the segment for capacity growth will require profits to stay at these levels and grow with investments in order to maintain a slightly positive free cash flow position which is required to justify any value from this segment.

Growing capacity to “feed the

dragon”

PetroChina becoming more

international in both

downstream and upstream

Normalized R&M EBITDA of

around US$6-7 bn justifies our

R&M EV value of around US$40 bn

114



Sinopec Corp – H

Overweight

Company DataShares Outstanding (mn) 86,702Market Cap (Rmb mn) 684,082Market Cap ($ mn) 107,050Price (HK$) 7.73Date Of Price 07 Sep 11Free float (%) 19.6%Avg Daily Volume (mn) 205Avg Daily Value (HK$ mn) 1,098Avg Daily Value ($ mn) 141HSCEI 10,347Exchange Rate 7.79Fiscal Year End Dec

Sinopec Corp - H (Reuters: 0386.HK, Bloomberg: 386 HK)

Rmb in mn, year-end Dec FY09A FY10A FY11E FY12E FY13ERevenue (Rmb mn) 1,345,052 1,913,182 2,634,625 2,385,530 2,377,818Net Profit (Rmb mn) 61,760 71,800 79,816 84,118 80,556EPS (Rmb) 0.71 0.83 0.92 0.97 0.93DPS (Rmb) 0.18 0.21 0.23 0.25 0.24Revenue Growth (%) (10%) 42% 38% (9%) (0%)EPS Growth (%) 117% 16% 11% 5% (4%)ROCE 16% 19% 19% 19% 16%ROE 18% 18% 18% 16% 14%P/E 8.9 7.7 6.9 6.5 6.8P/BV 1.5 1.3 1.1 1.0 0.9EV/EBITDA 5.2 4.2 3.9 3.6 3.3Dividend Yield 2.8% 3.3% 3.7% 3.9% 3.7%Source: Company data, Bloomberg, J.P. Morgan estimates.

Downstream overview


Sinopec is Asia's largest crude oil refiner and refined products producer and ranks 2nd globally (along with Exxon Mobil and RD Shell) in terms of primary distillation capacity. Sinopec’s Refining & Marketing business is responsible for the supply and trading, refining, manufacturing, marketing and transportation of crude, petroleum and related services to wholesale and retail customers. Sinopec also has a relatively big downstream chemicals business which we exclude from this analysis.

Sinopec's refineries are predominantly located around the south/east coastal region of China which is a legacy effect of the way the upstream and downstream assets were re-organised by the Chinese government (Sinopec was established in 1983 from the downstream assets of MPI (Ministry of Petroleum Industry) and the Ministry of Chemical Industry). As a result, the company's refining assets are located close to the major consumption centers, which helps it save on downstream transportation cost. In addition to domestic supply, Sinopec also exports some of its gasoline to Southeast Asia and Middle East.

The company at present operates 34 refining units in China with a total refining capacity (end-2010) of 4.9 million bopd, of which 11 refineries have a capacity of over 200 kbopd. It also has the largest sales and distribution network for refined products in China, with retail, wholesale and direct sales operating under a unified Sinopec brand.

Sinopec’s downstream business is managed through two main groupings – refining and marketing:

Refining – combines purchase of crude from Sinopec’s E&P and third parties for feeding refineries and processing crude into refined products and selling the products to the marketing segment.

Marketing – consists of purchase of products from Sinopec's refining segment and third parties and marketing and distributing those products to wholesale and retail customers through its service network.

Sinopec’s refineries are better designed to run heavy crude compared to PetroChina, which is somewhat a reflection of the flagship crude fields of both the companies

115



(PetroChina’s Daqing produces light crude and Sinopec’s Shengli produces heavier crude).

Downstream strategySinopec’s downstream strategy is to maintain its foothold in its traditional South and South-East China markets as well as to expand into North/North-East China (which have traditionally been PetroChina strongholds). On its home turf, it faces added competition from PetroChina’s capacity expansion plans and CNOOC’s Huizhou refinery (in the Southern Guangdong province) which it is planning to expand in addition to two new planned refineries in Liaoning and Hebei provinces (North East and North China respectively).

Sinopec plans to add capacity in the coastal regions to maintain its stronghold in those markets. However, the capacity addition is predominantly from debottlenecking and brownfield expansions. For Sinopec, being an SOE, securing the products’ supplies ranks over profitability, but Sinopec has recently increased its upstream focus to increase production and reserves and reduce earnings volatility.


Refining and marketing margins are the primary downstream performance drivers for Sinopec. At present China controls the pricing through its economic planning agency (NDRC) for diesel and gasoline (over 50% of the refining yield) at the retail and the wholesale level, effectively determining the marketing margins for the controlled products. Jet fuel prices have been recently aligned more closely to Singapore market prices. Under the current pricing mechanism, the product prices are adjusted if the moving average of crude prices moves +/-4% over a 22-day trading period. However, in practice the adjustments are done on an ad-hoc basis and in theory the transparency of this mechanism lends itself to market manipulation. To tackle these shortcomings we believe the window will be shortened and at some point pricing will be left to the market participants (draft of the proposed reforms was sent to the 3 SOEs for comments in June, but no timeline for change has been committed to). This liberalization will to a great extent depend on the path of oil prices in the next year or two. Sinopec normally maintains stable marketing segment EBIT of around Rmb30bn and adjusts for the margin volatility in the refining segment. We believe the refining segment can generate Rmb 20-25bn in an average year with less volatile refining margins.

There is further upside from reforming the fuel-oil business by leveraging on the bonded bunker franchise license, as well as from the non-fuel business (Easy JOY stores) which have grown about 3x from around 5,000 stores in 2008 to over 15,000 in 2010 with similar growth in turnover.


Sinopec will spend most of its efforts downstream in adding refining capacity by debottlenecking and brownfield expansion in the coastal China areas to face increasing competition from PetroChina. Sinopec will also look to revamp crude adaptability in the face of increasing volatility amongst crude spreads (eg China looking to reduce its purchase of West African crude grades; Cabinda, Hungo and Girassol in favor of similar Qatari Al-Shaheen grade, which is about $5/bbl cheaper).

Sinopec will continue to add

capacity primarily by brownfield expansion

R&M EBIT potential of around

$7-8bn in an average year with

crude prices under $100/bbl and controlled pricing

Upside from the non-fuel EASY JOY stores business which is

growing at about 20-25% CAGR.

Sinopec to add 1.6 million bopd capacity over 2011-15

116



Sinopec has plans to build a 300 kbopd green field refinery with Kuwait Petroleum in Zhanjiang, Guangdong province, for which it received NDRC approval in March, 2011. We understand Sinopec is pushing forward the construction date of this refinery to compete with PetroChina’s 400 kbopd Jieyang refinery in Guangdong (still awaiting NDRC approval). Sinopec may also be looking to bring forward its 200 kbopd Tieshan refinery in Guangxi to compete with PetroChina's new Qinzhou refinery in Guangxi. It has also proposed a new 600 kbopd Lianyungang plant in Jiangsu for which a co-operation agreement was signed in June 2011 with the Jiangsu provincial government.

Sinopec is also looking at construction of new retail stations, storage facilities and pipelines in its traditional coastal China markets to service the incremental demand and defend its leading position.

Table 12: China refining capacity addition – Sinopec to add an estimated 1.6 million bopd cumulative capacity over 2011-15

(000 bopd) 2011 2012 2013 2014 2015 TotalPetroChina 180 370 250 471 260 1531Sinopec 238 240 530 300 300 1608China overall 748 730 780 1010 740 4,008

Source: Company estimates, J.P. Morgan estimates

Sinopec Downstream Efficiency Overview


As of December 2010 Sinopec operated 34 refineries in China with a total primary distillation capacity of 4.9 million bopd. Sinopec’s refining capacity has seen a steady rise over the last decade from 2.6 million bopd in 2000 to 4.9 million bopd at present. We expect its refining capacity to further increase to 6.5 million bopd by 2015 (Sinopec’s target is 5.5-5.9 million bopd).

The number of refineries Sinopec operates has increased from 25 in 2000 to 34 at present. The newer additions have been larger, bringing the overall average net refinery size from 105 kbopd in 2000 to 145 kbopd in 2010. Currently 11 of the 34 refineries Sinopec operates are of over 200 kbopd capacity (Zhenhai, Shanghai, Maoming, Guangzhou, Jinling, Yanshan, Gaoqiao, Qilu, Qingdaolianhua, Fujian and Tianjin). The bigger ones are also situated close to the biggest consumption centres (coastal region); the provinces of Shandong, Jiangsu, Zhejiang, Fujian, Guangdong (and the Shanghai and Tianjin municipality).

The product marketing operations of Sinopec consist of three parts. First is the product retailing directly through service stations run by its marketing units. This accounts for about 63% of its GDK sales (by volume, GDK: Gasoline, Diesel, Kerosene). Second is the wholesale centers operated by the marketing units to supply oil products to designated agents and retail companies. This accounts for around 15% of its entire marketing business. The third comprises selling products to large customers (“Direct sales”) and this comprises around 23 % of its marketing business.

Sinopec is the world’s 2nd largest and Asia’s largest refiner

117




Despite the almost 7% per annum refining throughput growth from 2000-2010, which has almost doubled the output from 2.1 million bopd in 2000 to 4.3 million bopd in 2010, Sinopec’s refining slate has changed very little. Jet/Kero, diesel and gasoline account for about 60% of the products, with naphtha, lubes, LPG, fuel oil, asphalt etc accounting for the rest. In line with the consumption trends of China, the diesel yield at 36% is almost the double of gasoline yield at 17%.

With equity oil production CAGR at 3% lagging that of the refining throughput (7% CAGR), the ratio of equity oil production to throughput has fallen from around 1/3 to 1/5th in the previous decade.

Currently, Sinopec produces roughly 20% of its crude requirement internally and purchases the rest from the open market (CNOOC’s domestic production accounts for another 3-4% and imports about 75%). To decrease its dependency on imported crude, Sinopec has been expanding its overseas upstream reach; most recently in Angola (listco), Nigeria-focused Addax Petroleum (by parent Sinopec Group), Brazil (via Repsol Sinopec JV – again parent) and Argentina (via purchase of Occidental's Argentina assets by the parent). There are also reports of Sinopec and CNOOC considering forming a downstream alliance which would provide Sinopec with assured crude supply from CNOOC’s increasing domestic production (in addition to the already existing trading JV: CNOOC-Sinopec United International Trading, owned 60%:40% by CNOOC and Sinopec respectively, for CNOOC's overseas crude imports).

Retailing network

Sinopec has the biggest downstream retailing network in China, with around 30,000 service stations. The company sells its products under a unified Sinopec Group brand. Moreover, around half of the total service stations have convenience stores (EASY JOY stores) which have seen around 25% per annum top-line growth in the past 2 years. Sinopec also has a cooperation agreement with McDonald for drive-through fast food service. Sinopec also operates about 500 service stations with BP in the Zhejiang province, has a JV with RD Shell for operating service stations in Jiangsu province and a JV with Saudi Aramco for service stations in Fujian province. Sinopec plans to expand in the West China market, with plans to build around 500 gas stations in Xinjiang by 2015.


Sinopec’s R&M profitability has been impacted historically due to the controlled pricing regime it operates under. Marketing makes stable profits, while refining bears the swings in margin volatility. However, the big change in downstream profitability came in when in 2009 NDRC changed the refined product pricing mechanism to "cost-plus", which basically swung the refining operating profit into positive in 2009/10 from losses in 2005-2008 period.

Overall in 2010 the return on the segment’s net fixed assets was about 20%, which was about twice that of PetroChina’s, reflecting the relatively higher profitability of the assets. Future profitability depends on the direction of pricing reforms, but in general the downstream returns are expected to be much better for Sinopec compared to PetroChina due to the better asset productivity and efficiency. In 2009-10 Sinopec has generated an average of US$4.1/bbl post tax per barrel of refinery throughput compared to PetroChina’s average US$3.2/bbl.

Diesel yield at 36% is around twice that of gasoline.

Equity oil production coverage is about 20%.

Sinopec has China’s biggest

retailing network and sells around half of the total products

sold in China

Sinopec has relatively better

downstream assets and

profitability compared to PetroChina

118




Sinopec’s estimated post tax free cash flow turned positive in 2009 after posting an estimated $5 billion in negative free cash flow in 2008, from refining losses on NDRC not pricing up products. We estimate Sinopec can generate about $7-8 billion R&M EBIT and around $3.5 billion free cash flow per year under less volatile and in a controlled pricing environment. Due to still some old refining assets and the addition of newer capacity (almost 40% growth in refining capacity over 2006-2010 period) the capex to depreciation ratio has been relatively high at an average 2.4x for the past five years. Going forward, we expect refining to be weak this year (break even for the full year) and depending on where oil prices go and NDRC’s response to this, we expect next year to pick up in refining, while marketing should turn in a “normal” stable profit.

Consistent positive cash flow excluding acquisitions

119



Figure 125: Sinopec - refining capacity (kbopd) & utilization (%)


Figure 126: Sinopec - Number of refineries & average size (kbopd)


Figure 127: Sinopec - refinery yield and output / equity oil cover ratio (x)


Figure 128: Sinopec - retailing network size & location


Figure 129: Sinopec - downstream profitability ($/bopd) & post-tax ROFA (%)

Source: Company reports, J.P. Morgan estimates; 2008 includes a direct subsidy of

Rmb40.5bn (US$6.2bn)

Figure 130: Sinopec - downstream cash flow ($m) & capital intensity (x)

Source: Company reports, J.P. Morgan estimates; 2008 includes a direct subsidy of

Rmb40.5bn (US$6.2bn)

75%

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Summary

In common with PetroChina, Sinopec is also moving in the opposite direction of IOCs by increasing downstream refining capacity, to match domestic petroleum product demand in China. Ideally, it wants to increase market share, especially in north/north-east China, through adding marketing outlets in that part of China (and refineries). Unfortunately, economics in China are very much in the hands of regulator NDRC, setting prices for transport fuels. Prices are in theory set at cost plus, but recent higher oil prices have resulted in negative margins in refining. Marketing makes relatively stable margins and is a growth segment with upside from non-fuel sales. We do expect liberalization over the next couple of years, depending on where oil prices move.

Sinopec has for many years had a strong international presence in the crude and product trading segment, done through Unipec (a subsidiary of its parent). Sinopec has, however, not acquired any downstream operating assets, while its parent has made some purchases upstream. Last year one of these was sold down to listco (Angolan assets), while the rest remains with its parent (Addax, Repsol JV in Brazil, Oxy assets in Argentina). Greater exposure to international upstream has been necessary, as domestic production is maturing and crude coverage declining from current low levels. Sinopec is an influential trader in the regional crude and product market due to its large crude requirements and at times import and export activities.

Our R&M EV (as included in our Sinopec’s PT) is approximately $50 billion or HK$3.5 per share. This represents 40% of our total sum-of-the-parts value of around HK$9.40 per share. Under normalized circumstances (ie GRM of around $5.5-6.5/bbl), we see downstream EBIT potential in 2012E of approximately $8 billion assuming stable profitability in marketing. Adding annual downstream depreciation of around $3bn, this implies a 2012E EBITDA of $11bn and an EV/EBITDA multiple of 4.5x.

An EV/EBITDA multiple of 4.5x for a stable marketing business (half of EBIT) and in theory stable refining (cost plus formula) is not very demanding, but reflects the greater importance of R&M for Sinopec and the risk inherent in the current pricing regime. The risk to refining margins will continue to induce an overall multiple discount, until liberalization of product prices or lower stable oil prices brings this risk down. Also, the related investments into the segment for capacity growth will require profits to stay at these levels and grow with investments in order to maintain a positive free cash flow position which is required to justify value in this segment.

Growing capacity to “feed the

dragon”

Sinopec is lagging PetroChina in

internationalization downstream

and upstream

Normalized R&M EBITDA of

around US$11 bn more than

justifies our R&M EV value of around US$50 bn

121



India: Refining and Marketing structure

The retail fuel pricing environment in India is regulated by the government, with prices of major fuels (diesel, LPG, kerosene – 58% of India’s oil product consumption) being subsidized to end consumers. The price of gasoline was de-regulated in June last year, but is still subject to some degree of government intervention (as was seen by the absence of any price hikes during Jan-May 2011 – a period with important state assembly elections).

The subsidy regime has been a cause of uncertainty in earnings, with profitability essentially linked to the level of government support paid out to compensate for losses on the subsidized fuels. Typically, the upstream SOEs (ONGC, Oil India and GAIL) are expected to share a certain percentage of these losses (as these upstream companies benefit from higher crude prices), with the government coming in with a larger share (usually over 50%), as the downstream SOE companies have a limited ability to absorb the losses.

Table 13: Subsidy losses (for fiscal year)

Rs bn FY09 FY10 FY11 FY12E FY13E

Auto Fuel subsidy (Rs bn) 580 140 351 465 113Cooking Fuel Subsidy (Rs bn) 465 320 429 470 339TOTAL SUBSIDY (Rs bn) 1045 460 780 934 452

Upstream SOE share (Rs bn) 320 140 301 421 271Government share (Rs bn) 713 260 410 434 126Downstream SOE share (Rs bn) 12 60 69 80 55

Source: J.P. Morgan estimates, company data.

As can be seen from the table above, the level of subsidies has reached critical levels, with crude prices remaining elevated. The government is also faced with fiscal deficit reduction targets that will be difficult to meet in the absence of price reforms. This is, however, balanced by the need to control inflation (at 9.44%) and related political concerns.

Figure 131: Crude levels implied by product prices

Source: J.P. Morgan estimates.

$0

$20

$40

$60

$80

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Petrol Diesel LPG Kerosene

Pricing of key auto (diesel) and cooking (kerosene/LPG) fuels

are subsidized. Petrol pricing

was de-regulated only in June ’10.

With high crude, subsidy losses have reached unsustainable

levels, necessitating partial

reform.

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Table 14: Sensitivity of subsidies to crude (for fiscal year)

FY12ERs bn JPMe -$106.25 $100 $110 $115

Auto fuels 465 322 550 664 Cooking fuels 470 418 501 542 TOTAL SUBSIDY 934 741 1,051 1,206

Upstream share 421 333 473 543 Govt. share 434 327 498 583 Downstream share 80 80 80 80

Source: J.P. Morgan estimates.

The government has reacted to the high price of crude oil by de-regulating the price of petrol (June 2010). In addition, the price of diesel and LPG has been raised twice (June 2010 and June 2011), while kerosene prices were raised once. The government has a stated intention of freeing up the pricing of diesel, but has not set a timeframe for this to be implemented. In June, the government also cut excise/customs duties on crude/petroleum products, helping reduce absolute subsidy borne by the downstream companies, without raising consumer prices. However, we expect the government will scale back some level of subsidy support, with the upstream having to pay 45-60% of the subsidy bill in FY12/13. The government has also announced plans to implement direct targeting of subsidies – particularly for cooking fuels. Implementation of these schemes would be a big positive for fuel pricing reform in India.

For now, the current subsidy regime (and ad-hoc nature of government compensation) does hamper investment plans for the downstream SOEs, and is the reason for the private sector scaling back its presence in the fuel marketing segment.

With only partial reforms carried

out, high crude levels represent a drag on fuel marketing

earnings.

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Indian Oil Corporation

Neutral

Company DataShares O/S (mn) 2,428Market Cap (Rs mn) 769,904Market Cap ($ mn) 16,698Price (Rs) 317.10Date Of Price 07 Sep 11Free float (%) -3-mth trading value (Rs mn) 34.23-mth trading value ($ mn) 0.73-mth trading volume (mn) 0.0BSE30 16,863Exchange Rate 46.11Fiscal Year End Mar

Indian Oil Corporation Limited (Reuters: IOC.BO, Bloomberg: IOCL IN)

Rs in mn, year-end Mar FY10A FY11A FY12E FY13ERevenue (Rs mn) 2,711,105 3,288,532 3,871,018 3,648,493Net Profit (Rs bn) 102.2 74.5 45.2 82.8EPS (Rs) 42.10 30.67 18.60 34.08DPS (Rs) 12.63 9.20 5.58 10.22Revenue Growth (%) -11.3% 21.3% 17.7% -5.8%EPS growth (%) 240.4% -27.2% -39.3% 83.2%ROCE 9.9% 8.6% 5.9% 10.9%ROE 21.6% 14.1% 7.1% 11.1%P/E 7.5 10.3 17.0 9.3P/BV 1.5 1.4 1.1 1.0EV/EBITDA 7.9 8.2 9.4 5.7Dividend Yield 4.0% 2.9% 1.8% 3.2%Source: Company data, Bloomberg, J.P. Morgan estimates.

Downstream overview


IOC’s downstream businesses are in the areas of crude refining, fuel marketing and petrochemicals production. IOC has the largest fuel retailing network in India.

Refining: IOC runs eight refineries across India, with a combined capacity of ~1.1 million bopd. It also owns a significant stake in Chennai Petroleum (210 kbopd).

Petrochemicals: IOC has a relatively small petrochemicals business, with one naphtha cracker and presence in polyester intermediaries (PTA/PX).

Marketing: IOC runs the largest fuel retailing network in India, with ~19,500 outlets in total. The company has a dominant share in domestic fuel retail in India (Market share of 45%-65% for gasoline/diesel/LPG/kerosene).

Downstream strategyRefining: IOC continues to invest in its refining assets, raising capacity/modernizing the refineries at Panipat and Haldia. In addition, IOC is also building a new refinery at Paradip on the east coast (~300 kbopd); this will make IOC India’s largest refining company.

Marketing: The marketing business has been hampered by subsidized prices, and the need to bear a portion of the losses on the sale of retail fuels. However, with incremental reforms (petrol pricing has been de-regulated, while diesel / LPG / kerosene prices have been hiked), IOC continues to invest in its retail network, positioning for further fuel de-regulation.

Petrochemicals: Petrochemicals is a focus area for IOC, as it allows a diversification away from retailing – a business dogged by subsidized prices and periods of heavy losses. To this end, IOC has built a major petrochemicals facility at its Panipat refinery.

IOC is a large refiner (largest in India including Chennai

Petroleum) and runs the largest

fuel retailing network in the country.

IOC is incrementally raising

capacity in refining, and is

building a new refinery in eastern India. Petrochemicals

capacity is being added as well.

124




Key performance drivers of the downstream business are refining margins (which tend to move along with regional benchmarks) and the level of subsidies to be borne by the company (the extent of losses depends on the crude prices, level of price adjustment allowed by the Government of India and subsidy support from upstream SOEs, GoI). Key drivers on the petrochemical side are polymer and polyester intermediate spreads – with the commissioning of the Panipat facilities.


Downstream growth is to come from the completion of the Paradip refinery on the east coast, which is expected to have a capacity of 300 kbopd. While the company maintains that the project will be completed by March 2012, we expect most secondary units to come on-stream later.

IOC Downstream Efficiency Overview


IOC has a current nameplate capacity of ~1.1 million bopd across its eight directly operated refineries spread across India – with large capacities in Western and Northern India. Increases in capacity have been through incremental additions to the existing portfolio through upgrade and expansions. This will change with the commissioning of the Paradip refinery (~300 kbopd) - while the company is targeting a March 2012 start-up, we believe secondary units could be delayed.

Refining product yield and product

While IOC does not disclose yearly product yields, the company enjoys dominant positions in the fuel market in India (market leader in domestic petrol / diesel / LPG / kerosene sales) – its refining product slate largely mirrors this, and is focused on supplying the domestic market.

Retailing network

IOC has ~19,500 fuel retail outlets, the largest network in India. IOC enjoys a dominant position in fuel retailing, with shares of 45%-65% in gasoline / diesel / LPG / kerosene. However, with subsidized prices for diesel / LPG / kerosene, IOC incurs significant losses on sales. A key driver of profits/losses in the marketing business is the extent of government/upstream SOE support. Incremental pricing reforms (gasoline was de-regulated in June 2010, and diesel prices have been hiked twice over the last year) raise some hope of a move towards market-determined pricing for auto fuels in coming years.


As retail fuel (diesel / LPG / kerosene) prices are subsidized (petrol was de-regulated only in June last year), IOC’s downstream profitability is closely linked to the level of compensation received from the government and the upstream SOEs (which benefit from higher crude). Years with high crude prices (and consequently high losses due to subsidies), such as FY09 and FY11, have seen low levels of overall profitability.

Marketing remains a volatile business, with profitability

determined by the extent of govt.

support on subsidies.

125




While IOC has in most years generated positive cash flows (excluding working capital changes), the extent of these has been dependent more on compensation for fuel retailing losses than refining margins. Reinvestment has been healthy, with growth in the retail network (across the country), and upgrade/expansions carried out at various refineries (e.g the capacity at Panipat and Haldia was raised in recent years).

Figure 132: IOC refining capacity (kbopd) and utilization rate

Source: J.P. Morgan estimates, Company data.

Figure 133: IOC - number of refineries and average size (kbopd)


Figure 134: IOC - No. of retail outlets

Source: Infraline, Company data.

Figure 135: IOC - downstream profitability ($/bbl) & post-tax ROFA

Source: J.P. Morgan estimates, Company data. Note: US$/Re is average for fiscal year.

Figure 136: IOC - downstream cash flow ($m) & capital intensity

Source: J.P. Morgan estimates, Company data. Note: US$/Re is average for fiscal year.

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Summary

IOC’s refining business is focused on the domestic market (feeding its own retail network), and IOC has maintained a leadership position in the retailing of various products. However, with the prices of key auto (diesel) and cooking (LPG / kerosene) fuels being subsidized, the marketing business is dependent on compensation for losses from the government and the upstream SOEs. Government support is unpredictable and this has caused swings in company profitability - also hampering investment decisions.

As a result, IOC has tried to diversify away from this dependency on government policy through investments in other parts of the hydrocarbon chain - an investment in petrochemicals is amongst them, along with investments in E&P assets (Carabobo project in Venezuela among them). The company is also setting up a new refinery on the east coast (Paradip) which would add ~300 kbopd of capacity to the company.

Petrol pricing has been de-regulated (though there remains an element of government control, as seen from the lack of price hikes from mid-January to mid-May this year), and diesel prices have been hiked 10-15% over the past year, raising hopes of a market-determined pricing regime - in such a scenario, IOC is well placed to capture significant incremental value.

Our EV for IOC is $19.6bn (~$8.1/share). This includes value from the R&M, petrochemical and pipeline businesses. In addition, IOC has net cash/investments of $1.2/share, leading to our fair value of $9.3 (Rs420). We expect GRMs of $6/bbl over FY12/13E. We use an EV/EBITDA multiple of 6x for IOC – this is at a discount to regional refining peers, which we feel is justified, given the continuing uncertainty over sharing of subsidies by downstream SOEs – while we build in a sharing of Rs80bn/Rs55bn over FY12/13 for the downstream (implying 9-12% share), in a high crude environment, the government could expect the state-owned refiners to bear a larger loss.

127



Reliance Industries Ltd

Overweight

Company DataShares O/S (mn) 3,274Market Cap (Rs mn) 2,729,213Market Cap ($ mn) 59,192Price (Rs) 833.50Date Of Price 07 Sep 11Free float (%) 50.2%3-mth trading value (Rs mn) 2,307.973-mth trading value ($ mn) 50.063-mth trading volume (mn) 1.38IN

Reliance Industries Ltd (Reuters: RELI.BO, Bloomberg: RIL IN)

Rs in mn, year-end Mar FY10A FY11A FY12E FY13E FY14ERevenue (Rs mn) 2,037,400 2,658,106 3,132,220 3,005,420 2,946,670Net Profit (Rs mn) 158,180.00 192,715.20 220,537.76 258,286.67 293,954.39EPS (Rs) 53.12 64.65 73.98 86.64 98.61DPS (Rs) 7.00 8.00 10.00 10.00 10.00Revenue growth (%) 34.7% 30.5% 17.8% -4.1% -2.0%EPS growth (%) -4.2% 21.7% 14.4% 17.1% 13.8%ROCE 12.0% 13.0% 12.6% 13.3% 13.8%ROE 16.5% 17.5% 17.3% 17.6% 17.5%P/E 15.7 12.9 11.3 9.6 8.5P/BV 2.4 2.1 1.8 1.6 1.4EV/EBITDA 9.3 7.0 5.9 5.1 4.3Dividend Yield 0.8% 1.0% 1.2% 1.2% 1.2%Source: Company data, Bloomberg, J.P. Morgan estimates.

Downstream overview


RIL’s downstream businesses are concentrated in the areas of crude refining and petrochemicals production, in which the company enjoys a dominant position in India, and has achieved global scale. RIL also has a retail fuel network - however, this business is fairly small, due to regulated auto fuel pricing in India.

Refining: RIL runs two mega-refineries at the Jamnagar refining complex, with a combined nameplate capacity of 1.24 million bopd (current utilization rates are ~110%). The two refineries have significant secondary processing facilities. The Nelson Complexity Index for the old refinery is 11.3 and the newer refinery has a NCI of 14 – allowing RIL to process a variety of tough and sour crudes. The new refinery based in a special economic zone (SEZ) exports its entire output.

Petrochemicals: RIL has a significant petrochemicals business, with 55-85% of Indian capacities across various products. RIL is among the largest producers of polyester fiber and yarn, polypropylene and paraxylene in the world. The company has fairly even revenue/earnings split between the polyester and polymer chains.

Downstream strategyRefining: RIL has focused on products with strong demand (particularly in Asia) such as diesel (diesel accounts for over 40% of its product slate) - it destroys or upgrades most of the low value-added fuel oil, to maximize margins. With its high secondary processing ability, RIL has consistently been able to deliver GRMs at a premium to benchmarks. While its refineries have a nameplate capacity of 1.24 million bopd, RIL has operated at rates consistently over this (105-110% utilization) maximizing the scale advantage its two giant refineries enjoy. A key component of RIL’s refining advantage is the low capital costs associated with its refineries - the new 580 kbopd refinery had a capital cost of $6bn ($10,400 per bpd). In terms of expansions, the company is setting up a petcoke gasification facility at the refinery, to generate revenue from the bottom of the barrel and is setting up off-gas-based petrochemical facilities.

RIL runs the world’s largest single refining location at

Jamnagar, and is a dominant

player in the Indian petrochemicals market

A focus on high demand, high

value products has seen RIL

consistently earn premiums over benchmark refining margins

128



Petrochemicals: Petrochemicals is a major focus area for RIL, with the company earmarking $12bn in investments for expansions over the next 4-5 years. A key theme is achieving global scale across a range of products. The company aims to bring these new capacities on-stream at a time when global capacity additions are expected to be muted, and margins stable.


Key performance drivers on the refining side are 1) middle distillate spreads – diesel constitutes over 40% of the product slate 2) refining utilization levels - RIL consistently runs its assets at over 100% throughput and 3) light-heavy crude differentials. Given scale advantage, relatively new refineries (older refinery is 11 years old) and low labor costs – RIL’s refining costs per bbl are very competitive (US$2.5/bbl)

With an even split in production between the polyester and polymer chains, a key driver over the past few quarters on the petrochemicals side has been polyester margins. However, with a correction in cotton prices (and consequently across the polyester chain), earnings from this segment are moderating. A pick-up in polymers (our regional analysts expect a bottom in 2HCY11) should help buttress earnings.


Downstream growth is largely restricted to the petchemicals business. RIL has planned $12bn of investments over the next 4-5 years (out of a company-wide investment of $19bn) – with significant additions to PX, PE, MEG, PET and polyester fibre/yarn capacities.

Table 15: Petrochemical expansions

Plant/Project Current capacity (MTPA) Expansion (MTPA) % increaseIncremental netback (based on

FY11 prices) - RsmnEthylene + Propylene 2,643,200 1,500,000 57%HDPE/LLDPE 1,117,500 1,000,000 89% 39,825 Paraxylene 1,856,000 1,800,000 97% 34,425 Poly Butadiene Rubber 80,000 35,000 44% 1,122 SBR 150,000 2,827 PTA 2,050,000 2,300,000 112% 29,498 MEG 733,400 700,000 95% 18,585 PET 290,000 650,000 224% 4,388 PFY/Polyester Chip 822,725 400,000 49% 10,260 PSF/Acrylic Fibre/Chip 741,612 300,000 40% 5,063 Incremental Petrochem netback (JPMe) 145,991 FY11 Petrochemical netback (JPMe) 146,982

Source: J.P. Morgan estimates, company data.

RIL Downstream Efficiency Overview


RIL has a current nameplate capacity of 1.24 million bopd, across its two Jamnagar refineries, with the new refinery having begun operations in December 2008. At present, the company does not have any announced plans to further add significant refining capacity - incremental enhancements to production have taken place, with utilization rates reaching 105-110%.

Petrochemicals is a focus area,

and RIL is investing heavily to

consolidate its leadership in India, and ensure global scale

129



Refining product yield

RIL’s product slate has a clear tilt towards diesel, which accounts for over 40% of output from both refineries – diesel is a product that sees significant demand across Asia. The new refinery (export-oriented) has significantly raised RIL’s output of gasoline and also produces alkylates, while bringing down the proportion of LPG. Petcoke from the refinery will form the feedstock for a petcoke gasification facility which is being set up in Jamnagar. The two refineries have no production of fuel oil.


RIL has consistently delivered profits from its refining business, delivering better than industry average returns – a function of consistently delivering better than benchmark refining margins. The high complexity of both refineries allows RIL to capture value through widening light-heavy differentials, along with a product skew towards high demand middle distillates.


RIL has typically delivered reasonably large positive cash flows from its refining business – excluding a period from FY05-08 (including negative cash flows in FY07), when investments were made in the new SEZ refinery. The investment in the new refinery was made through a separate entity (RPL, 75% owned by RIL), which later merged into RIL – we have included the total capex impact on RIL in this discussion. With an uptick in margins over the past 12 months, the refining business is once again a key driver of company profitability. With both assets being relatively new, maintenance capex requirements have been comparatively small.

130



Figure 137: RIL refining capacity (kbopd) and utilization rate (%)

Source: Company reports.

Figure 138: No. of refineries and average size (kbopd)

Source: Company reports.

Figure 139: RIL - indicative refinery product yield


Figure 140: RIL - downstream profitability ($/bbl) and post tax ROFA

Source: J.P. Morgan estimates, Company data. Note: US$/Re is average for fiscal year

Figure 141: RIL - downstream cashflow ($ mn) and capital intensity x)

Source: J.P. Morgan estimates, Company data. Npte: US$/Re is average for fiscal year

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131



Summary

RIL's downstream businesses have been key profitability drivers over the past year, as the expected ramp-up in upstream natural gas production has been delayed. High complexity allows the refinery to realize a premium to regional benchmark Singapore GRMs. An even mix in production between polyester and polymers (whose cycles are not concurrent) allows for a certain level of profitability from the petrochemicals business - however, while these businesses may generate higher than average returns, they are not immune from cyclical slowdowns.

In the refining business, RIL has focused on producing high demand products such as diesel - which enjoys healthy growth both in India (with product subsidies) and in the wider Asian region (the second refinery exports its output) - diesel spreads have remained robust, and coupled with wide light-heavy differentials, RIL has generated significant profits from refining.

Figure 142: RIL GRMs vs. Singapore GRMs

Source: Company data, Bloomberg

In petrochemicals, RIL is concentrating on building global scale across a range of products, adding capacity in polyester yarn/fiber, polyester intermediary and polymer segments – at a time when global capacity additions are expected to be small (less likelihood of supply overhangs, as seen in 2010/2011). Its presence across the polyester chain allows RIL to capture value across the chain, boosting profitability.

Challenges for these businesses largely emanate from the risk of a renewed global slowdown, and on the polyester side, a correction in cotton prices, which has already seen some level of margin compression (though these remain above levels seen last year).

We estimate an EV of $30.6bn for RIL’s refining business, and $21.5bn for petrochemicals, leading to a value of Rs717/share ($16/share). This represents ~60% of our SOTP valuation of Rs1200. We expect GRMs of $9.5-10/bbl over FY12/13. The stock price appears to price in a significant slowdown in the global economy –reflecting GRMs of $6.5/bbl (low during GFC: $6.6/bbl; Singapore GRMs $2.7/bbl), along with a ~30% contraction in petrochemicals EBITDA, leading to an estimated contribution of ~Rs415/share ($9.2/share). The implied EV of the refining business is ~$16bn – an EV/boe of $12,800, which we believe is unjustified, as RIL has consistently delivered superior margins to benchmark Singapore GRMs due to its high complexity and scale, cost economics. RIL also has significant scale across

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various petrochemical products, and its even mix between polyester and polymer along with large level of integration allow for a more stable earnings stream from this business, which we believe justifies a premium valuation for the downstream business.

133



Sasol

Overweight

Company DataPrice (c) 31,115Date Of Price 06 Sep 11Price Target (c) 39,800Price Target End Date 01 Aug 1252-week Range (c) 40,355 -

28,060Mkt Cap (R bn) 207.8Shares O/S (mn) 668

Sasol Ltd. (SOLJ.J;SOL SJ)

FYE Jun 2010A 2011E 2012E 2013EAdj. EPS FY (R) 2,656.67 3,440.63 3,772.72 4,788.39EV/EBITDA FY 6.7 5.7 5.3 4.3Adj P/E FY 11.7 9.0 8.2 6.5EBITDA FY (R mn) 30,651 38,263 42,574 50,923EBITDA margin FY 25.1% 26.6% 28.1% 30.5%Revenue FY (R mn) 122,256 144,011 151,580 167,229OpFCF FY (R mn) 5,181 122 2,844 12,998FCF Yield FY 2.7% -0.7% 0.7% 6.2%Source: Company data, Bloomberg, J.P. Morgan estimates.

Although the macro looks unappealing, Sasol is already discounting an oil price at $90 per barrel, in our view. In addition, the company’s balance sheet strength, Randhedge characteristics and improving internal drivers add to downside protection. Looking forward, Sasol’s burgeoning gas franchise and GTL technology offer long-term upside potential, in our view.

Volumes – Sasol should see the biggest uplift in volumes in a decade in 2012FY with the absence of major shutdowns and the feed in of additional gas from Mozambique to the Secunda plant.

Gas Franchise - Sasol now has access to a burgeoning gas franchise which iffully developed as indicated by the company could lead to ~ 240,000 boepd of gas from Canadian shale by 2020 versus current production at Secunda of ~ 160,000 bopd. Sasol’s GTL technology ensures that even if natural gas prices stay low, a market for its Canadian resources can be guaranteed. Moreover, if oil and gas prices continue to remain disconnected, as seems likely, Sasol should benefit from increasing opportunities to build further GTL plants.

Chemicals – We expect a squeeze in chemical spreads in the near-term but supply constraint and structural changes in Chinese demand continue to suggest the cycle will tighten going forwards. Sasol’s under appreciated chemicals business should see EBIT recover from R 5.5bn in 2010 to ~ R 13.5bn by 2015.

Management - We wait to see what track Sasol's new CEO (the first from outside the company) will take, but over time there is potential to adopt a more aggressive and dynamic strategy towards both cost cutting and M&A.

Valuation - In uncertain times asset values and technicals provide useful guidance. Sasol is now trading on 1.45x our FY2012E book value versus its trough during the 2008 financial crisis of 1.50x. The stock is also trading at less than 50% of replacement cost and at close to an historical trough versus the spot rand oil price.

134



GTL - Global Opportunity

Overview

Shale gas has revolutionized the US energy landscape and an apparent abundance of gas and a paucity of oil have caused US oil and natural gas prices to decouple. With many expecting the shale revolution to spread to other parts of the globe there is increasing pressures not just on spot gas prices but on the extent of the linkage between oil and gas prices in long-term gas and LNG contracts. Unsurprisingly, under this scenario gas producers are increasingly looking at alternative options to increase the value of their gas resources.

Figure 143:Brent, US and UK gas prices in USD/bbl

Source: Bloomberg

Figure 144: US HH gas futures as % of Brent oil price

Source: Bloomberg

GTL offers an arbitrage between gas and oil prices with GTL plants acting as gas ‘refineries’ producing liquid fuels using gas feedstock. Consequently, GTL offers gas owners a product selling price guaranteed to be at a premium to the prevailing oil price.

GTL has suffered its set backs but with questions over future LNG pricing, interest in the technology is coming to the fore. After a series of problems, Sasol’s 32,400 bpdOryx plant has run at 80-90% capacity over the last 12 months and should report a RoIC of ~60% for the 2011FY and generate 10% of the company’s EPS. Further de-bottle necking should increase Oryx capacity by 10% over the next year or so. RD Shell’s giant 140,000 bpd Pearl plant has sold its first cargoes and is ramping up production. Consequently, the technology risks surrounding GTL have largely dissipated in our view.

From an economic perspective we estimate GTL can make > 10% RoIC with oil at USD 100/bbl, provided gas feedstock can be sourced at < $4 per mmbtu. In our view there should be plenty of remote gas available at ~ $4 per mmbtu or less and long-term oil prices look secure at ~ $100 per barrel. Moreover, our analysis suggests that GTL is preferable to LNG to monetize gas unless the selling price of the LNG is greater than 55-60% of oil parity. In conclusion, we view the economics of GTL as similar to oil sands in-terms of its position on the oil cost curve. The technology has many advantages over LNG in terms of reduced product risk and can also be used in land locked locations.

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135



Table 16: Recoverable gas resources and indicative production cost by type and region

Conventional Tight Gas Shale CBMTCM USD/MBTU TCM USD/MBTU TCM USD/MBTU TCM USD/MBTU

E. Europe & Eurasia 136 2 to 6 11 3 to 7 83 3 to 6Middle East 116 2 to 7 9 4 to 8 14Asia/ Pac 33 4 to 8 20 4 to 8 51 12 3 to 8OECD N America 45 3 to 9 16 3 to 7 55 3 to 7 21 3 to 8Lat Am 23 3 to 8 15 3 to 7 35Africa 28 3 to 7 9 29OECD Europe 22 4 to 9 16World 404 2 to 9 84 3 to 8 204 3 to 7 118 3 to 8

Source: IEA

How big could GTL be?

Currently, the market for GTL is relatively small with less than 100,000 bpdof products being produced globally from dedicated gas fed GTL plants. Moreover, although Sasol and a number of smaller players have plans for a number of new plants, given the construction time lines, it is unlikely that GTL will have a material impact on liquid fuel volumes until well into the next decade. European middle distillates imports are expected to increase from ~ 1.1 million bopd to ~ 1.4 million bpd by 2016 according to the IEA. Consequently, RD Shell and Sasol combined would be supplying only ~7% of European supply even if all the production from their respective Qatari plants was exported into Europe.

However, this not to say the potential for a greater expansion of GTL is not there. If gas resources are available at an economic price - and with shale gas expansion that looks likely - then there should be potential for a significant ramp-up in GTL projects. In our view, GTL is competitive with oil sands as a source of liquid fuels and consequently we see the potential at up to one million bpd by 2030 (IEA 2011 forecast 750,000 bpd). To take things to the extreme, we calculate the US could entirely remove its dependence on importing 5.6 million bpd of OPEC oil if it converted 0.5 TCM a year of gas into GTL products. Clearly, that would involve a massive infrastructure investment and require a huge amount of gas but assessments of US resources continue to move upwards. In addition, the IEA suggests that if half the worlds flared gas was converted to fuels using GTL, an extra 700,000 bpd of liquid product could be produced. The flared gas market is one which a number of companies are targeting via smaller modular GTL plants of below 3,000 bpd, with Velocys/ Oxford catalyst looking at floating GTL projects and due to test a facility with Petrobras later this year.

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Table 17: GTL plants existing and planned

Company Project Size bbl/d Status

Existing Commercial GTL Plants

Sasol/ QP Oryx 32,400 Running at 80-90%

PetroSA Mossel Bay 36,000 Running out of feedstock

RD Shell Bintulu 14,600 Running at >95%

RD Shell Pearl 140,000 Ramping up first 70,000 bpd phase

Planned Major GTL Plants

Sasol/ Chevron Escravos 32,400 Terrorist activity has forced up costs and delayed start-up now expected to start up in 2014

Sasol/ Petronas/ Uzbekneftegaz

Uzbekistan 38,000 Feasibility study nearly completed decision on progression to next phase to be taken before year end

Sasol/ Talisman Farrell Creek 48,000 -96,000

Feasibility study underway expected to take until end of 2012 CY

Sasol/ QP Oryx expansion 66,000 Current moratorium on further expansion in Qatar

Smaller Scale Players

Velocys Small demonstration with Petrobras

Compact CGTL Small demonstration with Petrobras

Syntroleum Demonstration scale

Rentech Demonstration scale

Source: J.P. Morgan, Company data

Sasol’s competitive position

With coal to liquids projects now firmly on the back burner, Sasol views GTL as the company’s future and has been buying up shale gas assets in order to provide security of supply for GTL projects and to act as a hedge should natural gas prices rise and negate the gas-oil arbitrage, which GTL relies on. We believe Sasol has now ironed out many of the production issues which dogged the start-up of its Oryx plant. The slurry phase process should offer capex cost advantages over RD Shell’s fixed bed process and is better suited to smaller gas deposits. Provided the dis-connect between gas and oil prices is maintained we see a bright future for GTL. Sasol has several projects in the pipeline and whilst it is difficult to speculate beyond these, it is reasonable to assume that, provided the oil gas price ratios remain attractive, Sasol projects could generate ~ 450,000 bpd of GTL by 2030.

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Overview of GTL

Process and Chemistry

Gas to liquids plants can be thought of essentially as ‘Gas Refineries’ using natural gas as opposed to oil as the feedstock to produce liquid fuels. Simplistically, the GTL process involves three steps:

1) Gas reforming: The manufacture of syngas (a mix of carbon monoxide and hydrogen) by the partial oxidation of purified natural gas.

CH4 + ½ O2 → CO + 2H2

2) Fisher–Tropsch Synthesis: Syngas is catalytically reformed into a mixture of long chain hydrocarbons.

nCO + (2n +1) H2 →CnH2n+2 + H2O

3) Product Work-Up: The hydrocarbon mixture is separated and processed into various products e.g. diesel, gasoline, naphtha, LPG, waxes, olefins etc.

Figure 145: GTL Schematic

Source: Sasol

Technology Considerations

Fisher-Tropsch synthesis is a process which dates from the 1930s and hence is not a new technology. However, like most chemical processes a significant amount of work has been done over time to improve overall yields and product specificity. Depending on reaction conditions i.e. reactor design, temperature, pressure and catalyst used, different hydrocarbon mixtures can be produced and hence plant conditions can be designed to yield differing quantities of diesel, gasoline or chemical feedstock as required. Generally speaking, GTL plants have more flexibility on end product slate than conventional refineries.

Whilst many companies have GTL pilot plants or small scale demonstration reactors currently only three companies run commercial scale GTL plants of any scale: Sasol, RD Shell and the South African government owned PetroSA. Sasol and RD Shell are clearly leading the globalization of GTL via their large scale Oryx and Pearl GTL

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projects in Qatar. Both companies are using low temperature F-T processes utilizing cobalt catalysts designed to raise yields of middle distillates and particularly diesel. However, there are important differences between both companies’ approach.

RD Shell

RD Shell’s GTL plants use what it calls the Shell Middle Distillate Syntheses process. (SMDS). The process utilizes fixed bed multi tubular reactors and these are used at its 14,700 bpd Bintulu plant in Malaysia and at its 140,000 bpd Pearl plant in Qatar. These reactors consist of thousands of narrow tubes with cobalt catalyst inside. Gas is injected into the top of the reactor and passed down the tubes and reacts with the catalyst contained within. The waxy reaction products are collected at the bottom of the reactor and further processed into the desired hydrocarbon fractions. RD Shell has been using fixed bed reactors successfully for a long period of time, notably at its Bintulu plant in Malaysia, and they have a number of advantages. Chief amongst these are reliability and ease of operation. In addition, the performance of fixed bed reactors can be predicted with reasonable certainty from pilot plant reactors. RD Shell’s Bintulu plant has run at operating rates close to 100% for many years. In addition, scale up is relatively easy via the addition of more tubes to each reactor and by adding further reactors. Catalyst improvements also increase capacity by raising activity levels. Pearl’s reactors have ~ 13% more tubes (29,0000 each) than at Bintulu and catalyst improvements mean each reactor will produce 5,800 bpd versus 3,600 bpd at Bintulu. Importantly, in the process there is complete separation of catalyst and product which eliminates the need for complex catalyst and product separation, and ensures minimal catalyst losses and product contamination. The simplicity of design and operating track record at Bintula has enabled RD Shell’s Pearl plant to start up in good time and it has begun to sell its first cargoes of product.

However, there are limitations and disadvantages with fixed bed reactors. The interaction of catalyst with syngas is limited by the design which can slow the reaction rate and hinder product specificity. This means large numbers of tubes have to be used to scale up production, and output per ton of reactor is lower than in other systems and capex costs are consequently higher. Catalyst loading/ unloading can be difficult although RD Shell’s catalyst should be able to be regenerated and has a three year life expectancy.

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Figure 146:Pearl fixed bed reactor

Source: RD Shell

Figure 147:Pearl GTL - product slate

Source: Shell

Sasol

Sasol has been operating commercial F-T plants for longer than any other firm and has run the full gambit of reactor designs and catalyst types. Currently, Sasol runs a mixture of fluidized bed and slurry phase reactors in South Africa. The advantage of these types of reactor is that they allow for greater interaction between catalyst and syngas, and hence higher degrees of conversion per unit size of reactor and hence lower capex and construction costs. Sasol’s latest design is based on a low temperature slurry phase reactor using cobalt catalysts. This design allows for very high catalyst - syngas interaction since the catalyst is suspended in liquid wax with gas bubbled through the slurry. This design allows for high conversion to wax, good product specificity and smaller unit reactor size. Sasol’s Oryx slurry phase reactors are 60m high and weigh 2,200tons and have name plate capacity of 7.3 bpd per ton of reactor. This compares to Shell’s Pearl fixed bed reactors which are 20m high,weigh 1,200 tons and have name plate capacity of 4.8 bpd per ton of reactor. There are however practical issues with the use of slurry phase reactors and their use was for a long time held up by problems associated with separating the wax products from the catalyst. The separation issue is made more acute by the tendency of the catalyst to break-up into small pieces (‘fines’) under attrition caused by the turbulent conditions inside slurry phase reactors. Sasol thought it had solved the problem after pilot plant tests but when its 32,400 bpd Oryx plant started up in Q2 2007, catalyst attrition led to clogging of the filtration units and the plant had to be shut down and then run at low operating rates to allow for effective filtration. Sasol has since refined operating conditions and strengthened its catalysts, with the result that performance and service life have improved significantly. For the 2011FY, Oryx is expected to run at ~ 80-90% utilization and barring scheduled shut downs should run at ~ 90% in 2012FY. De-bottle necking is expected to add 10% to effective capacity over the next couple of years.

36%

21%18%

25%

Gasoil Base oil Kerosene Naphtha

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Figure 148: Slurry phase reactor

Source: Oxford Catalysts

Figure 149:Sasol Oryx product slate

Source: Sasol/ J.P. Morgan

The Oryx reactors are ~ 16,200 bpd units, but Sasol is targeting 24,000 bpd from the same sized reactors with its improved catalysts with a line of sight to > 30,000 bpd. From an operating cost perspective, Sasol expects to get catalyst costs down by 50% going forwards and changes to reformation technology should also cut syngas plant capex costs by ~ 20%. Improvements to unit costs should help capex and construction costs to be kept under control.

Costs

Costs are key for GTL plants and particularly capex and gas feedstock costs. Historically, company estimates of capex and operating costs have proved light versus actual experience. Sasol’s Oryx plant cost ~ $1bn and although it had technical difficulties and much higher operating costs than expected, it was constructed at a cost reasonably close to its initial budget. RD Shell’s Pearl plant on the other hand was originally supposed to cost $6bn but ended up close to $20bn and Sasol’s Nigerian GTL plant, of the same size as Oryx, has seen huge cost escalation and is now expected to cost close to ~ $10bn.

The estimated returns of Oryx and Pearl are indicated below assuming a $100 per barrel oil price and a $10 per barrel product spread. Oryx’s returns are boosted by its relatively low construction costs. Conversely, its higher operating cost are due to higher catalyst attrition rates, higher utility costs and higher feedstock costs due to purchase of gas and utilities over the fence. RD Shell has lower operating costs due to scale and its back integrated into the upstream allows for very cheap feedstock and utility costs. RD Shell is yet to show operating and financial statistics, so estimates are based on company presentations and JPM estimates as opposed to actual reported figures. Sasol has a 49% share in Oryx with 51% owned by QP. RD Shell has 100% ownership of Pearl but has an upstream production sharing agreement with Qatar. The Pearl project’s returns are boosted significantly through the production of 120,000 bpd of condensate, the impact of which is not shown in our analysis.

75%

15%10%

Diesel Naphtha LPG

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Table 18: GTL plant costs and returns assuming oil at USD 100/bbl and a product spread of USD 10/bbl. Assumes plants run at 100% of design capacity.

Oryx GTL est Pearl GTL est New Sasol GTL Plant estEPC 2003 2006Start-up 2007 2011Capacity 32,400 140,000 48,000Cost USDm 1,040 15,7701 4,800 Capex Cost per $/bbl 32,099 112,643 100,000Depreciation $/bbl 7 15 14Gas cost $/bbl 10 3 26.0Employee Costs $/bbl 5.1 2.5 5.0Utilities $/bbl 7.0 2.0 5.0Maintenance/ Other $/bbl 4.0 3.5 5.0Catalyst/ Other $/bbl 7.0 2.0 4.0Total Costs USD/bbl 40 28 59 Margin 64% 75% 46%Pre Tax Project RoIC 80% 27% 19%Pre-tax RoIC to Sasol/ RD Shell2 80% 16% 19%

Source: J.P. Morgan, Sasol, Shell. 1) Assumes 83% of Pearl cost GTL, 10% Processing/ Condensate and 7% Upstream. 2) RD Shell

has PSA agreement with QP which reduces returns. Returns for Pearl assessed on just the GTL component

The costs of building new GTL plants are highly location specific. We currently estimate Sasol’s construction costs at 2-3x the cost of the original Oryx plant at the same location. We believe there are several advantages to the Sasol technology versus RD Shell’s which should lead to lower capex costs per unit of production. Sasol’s more complex technology has obviously suffered from operating/ reliability issues, hopefully these are now largely behind the company.

Sasol is investigating building new GTL plants in a number of different locations but perhaps the most interesting is in Canada based off of shale gas. GTL plants economics depend largely on capex costs, feed stock costs and end selling price assumptions. Our model suggests, assuming oil at $100 per barrel and capex costs at$100,000 per barrel, that a post tax RoIC > 10% is possible assuming gas feed stock costs of up to $4 per mmbtu. With shale extraction costs continuing to fall and conventional extraction costs typically considerably below $4 per mmbtu, this should mean there are ample locations with gas extraction costs which make GTL viable.

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Table 19: GTL Model based on prospective 48,000bbl/d Sasol plant in Canada

Pricing Assumptions Operating & Production StatsBrent USD/bbl 100 Total Gas used 25 years TCF 4.2Refining margin 8 Gas used per year bn BTU 169Price of Diesel USD/b 108 Gas used mmBTU 101,616,000 Low Sulphur Premium 1.5 Efficiency 60%

Price of Low Sulphur Diesel 109.5 Barrels a year produced 17,520,000

Naptha Spread 3 Revenue & ProfitabilityPrice of Naptha USD/b 103 Diesel USDm 1439Average Product Selling Price 108 Naphtha USDm 451

Capacity and Capex Assumptions Total Sales USDm 1,890Utilisation 100% Cost of gas USDm 457Project size bbl/d 48,000 Other operating costs USDm 333Production bbl/d 36,000 Depreciation USDm 240GTL Diesel bbl/d 12,000 Total Costs USDm 1030GTL Naphtha 48,000 EBIT USDm 860Capex Cost USD/bbl 100,000 Margin % 45%Total Investment USDm 4,800 Investment USDm 4,800

Tons CO2 produced per bbl 0.22

Costs per USD/ bbl ReturnsGas Cost USD per MMBtu 2.7 Pre Tax Year 1 RoIC 18%Conversion efficiency 10 Post Tax Year 1 RoIC 13%Cost of gas USD/bbl 26.1 Pre Tax IRR 15%

Depreciation per USD/bbl 13.7 Post Tax IRR 13%Labour USD/bbl 5Maintenance USD/bbl 5Utilities USD/bbl 5Catalysts / Other USD/bbl 4CO2 costs 0Total Op Costs 19Total Costs USD/ bbl 59

Source: J.P. Morgan

Figure 150: IRR at different levels of Capex cost

Source: J.P. Morgan

Figure 151: Ratio of Oil Price in USD bbl to Input Gas Price in USD BTU to make IRR of 10%

Source: J.P. Morgan

Environmental Issues

CO2

GTL plants are not very energy efficient ~ 60% and whilst they emit significantly less CO2 than CTL plants they still emit meaningful amounts of CO2 and far higher

0%

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10%

15%

20%

25%

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Oil

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Oil Price Feedstock US Gas Price

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amounts than an ordinary refinery in the production process. However, on a Well-to-Wheel basis, GTL plants emit comparable amounts of CO2 to an ordinary refinery given the benefits derived from the higher quality fuel slate produced by a GTL plant. Hence, in theory, GTL plants should not suffer any material additional costs from CO2 legislation versus an ordinary refinery. There may well also be methods of reducing / capturing GTL CO2 emissions.

Figure 152: Environmental Emission GTL vs Refinery diesel

Source: Sasol

Figure 153: CO2 emissions comparison of Sasol’s Natref refinery and Oryx plant Well –to-Wheel basis

Source: J.P. Morgan/ Sasol

Product quality

The products produced via the GTL process are extremely pure and almost devoid of sulphur and the diesel is of particularly high quality with a high cetane number. This enables marketers of GTL products to achieve a premium over and above that achieved for ordinary low sulphur diesel and naphtha.

GTL versus LNG

GTL effectively competes with pipeline and LNG as a route to getting stranded gas to market. Five years ago there was, similar to today, great excitement about the potential for GTL. At one point Sasol was predicting that with its partners it would have 450,000 bpd of GTL in production by 2014. In fact, even if Escravos (Nigerian GTL plant) is running flat out by 2014, the maximum Sasol will have with partners is ~68,000 bpd. The problem has been that resource owners have preferred to commit gas assets to LNG projects as opposed to GTL. The reasoning behind this has been the lower capex cost of LNG, the simpler and more proven nature of the technology and most importantly the fact that LNG customers have been prepared to lock in long-term LNG contracts at prices close to oil parity - essentially negating the economic point of GTL. However, with a wave of new technologies unlocking unconventional (shale, CBM, FLNG, tight gas) gas reserves, the outlook might be changing as gas supply threatens to outstrip demand. Consequently, whilst we think a link to oil prices will likely remain in many LNG contracts, the ‘slope’ or ratio of oil price to LNG contract price looks under threat and increasingly LNG customers are turning to the spot market and locking in less under long-term contract. We note that India and Pakistan in particular have been keen to shift away from oil indexation and have been using a mixture of oil and Henry Hub prices in some of their LNG contracts. Consequently, we believe it will become increasingly difficult for LNG producers to get close to oil parity for their gas. This should favour GTL as a competing technology to monetize the gas.

CO2

Emissions

Kgs/bbl

Production

process Kgs of

CO2/bbl

Extraction +

transport to

refinery

Combustion Total Well-

to-Wheel

Natref 43 60 400 503

Oryx 220 20 280 520

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GTL vs LNG – A Canadian Comparison

Assessing the economics of different LNG and GTL plants in different locations is very difficult. However, one location where both LNG and GTL are being proposed is Western Canada. Apache and EOG are looking to build an LNG export facility at Kitimat 400miles north of Vancouver on the BC coast to be fed from Horn River shale gas. Whereas Sasol/ Talisman are looking a GTL plant supplied by Montney shale gas.

Figure 154: Canadian LNG vs GTL

Source: Petroleum economist

A final investment decision on Kitimat is expected some time this year, but initial estimates of costs from Apache were $3.0bn for the 5 million ton pa facility with $1.1bn for associated pipelines. This looks a little light to us given recent cost inflation and Canada’s weather-related construction issues. We would estimate realistic costs in 2011 money at $5.1bn for a 5 million ton pa LNG plant and associated pipeline or roughly $800 per ton of liquefaction capacity. For a GTL 48,000 bpd we would estimate capex costs at $100,000 bpd (~3x the cost of Oryx)

Assessing capex and operating costs for different plants is fraught with potential for error and the experience at Oryx has been that operating cost are far higher than at first expected. However, Oryx’s costs are coming down and we believe for a new GTL plant of Oryx next generation design operating costs per bbl should be ~$18-20per bbl.

Our analysis suggests that a year one post tax RoIC of 10% can be made with oil at $90/bbl for a GTL plant based off Canadian shale gas. In terms of whether LNG or GTL is the better option for monetizing gas will ultimately depend on what selling price is achieved for the LNG. Given that Kitimat is likely to be serving the Asian LNG market it may well be that LNG proves to be the more economic outlet. Our analysis suggest that LNG from Kitimat would have to be priced at ~55% of energy parity with oil, equivalent to $8.6 per mmbtu to make a10% year one RoIC. Energy parity of 55% is equivalent to a 13% discount to oil price parity, roughly in-line with what our Australian analysts are forecasting for new long-term LNG contract prices to Asia from the new raft of Australian LNG projects. This is, however, still some way from the ~90% parity being seen until recently and hence it may well be that LNG proves the better option.

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Table 20: GTL vs LNG based on British Columbia Shale Gas

GTL LNGTotal Feedstock TCF (for 25yrs) 4.2 7.2 Feedstock requirement BCF/year 169 288 Carbon efficiency 60% 90%Effective Gas Feed MMBTU/year 101,616,000 259,000,000 Production mbbl/yr /Mt/yr 17,520,000 5.00 Capacity per bbl/d - MMBTU/d 48,000 667,123 Depreciable Life Time 20 20Capital Cost USD per bbl/d - MMBTU/d 100,000 7,645Capital Cost USDm total 4,800 5,100 Capital Charge per bbl/d - MMBTU/d 13.7 1.0

Operating costs per bb/d USDMMBTU 19 0.5Input Gas cost USD/BTU 2.7Gas cost per project (bbl equv btu) 27 2.7Transportation/ Re Gas 1.5Total Costs Per BBL/ MMBTU 60 5.7 Selling Prices GTL LNGGas Per BTU US 8.6Crude 90Diesel spread 8Naptha spread 3Low Sulphur Premium 1.5Sales USD 1,688 2,099 Costs USD (1,030) (1,400)EBIT USD 658 699 Pre- Tax RoIC 14% 14%Post Tax RoIC 10% 10%

Source: J.P. Morgan

Whether the economics of GTL/ LNG stacks up relative to selling gas into the US market remains to be seen. Our model suggests that at $100/bbl oil, if Henry Hub prices are above $5.25 per mmbtu then the better option would be to just sell the gas into the US market and not bother building a GTL plant. However, today’s Henry Hub price is some 30% below that level.

Figure 155:GTL vs LNG economics based off of BC shale gas

Source: J.P. Morgan

Figure 156: Pipe to the US vs GTL/LNG economics

Source: J.P. Morgan

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Appendix I: Downstream performance analysis

In this section, we define the key downstream performance metrics and, where appropriate, highlight their pros and cons. As per our approach upstream, we avoid complex and derived measures of performance. In a complicated sector we always findthat investors want a simple explanation of what matters and an easy line of sight thereto. As per Table 21, whilst all companies include refining, fuels retailing, wholesale marketing and lubricants, some also include speciality chemicals whilst others exclude certain logistics and shipping from their reported downstream segment results.

Table 21: Downstream segment configuration


From an investor perspective, the downstream industry suffers from generally poor levels of public disclosure e.g. segment profits are not disaggregated into refining, marketing, lubricants etc, there are different definitions of capital employed and working capital disclosures are very limited. Underlying costs for refineries are rarely disclosed by any company on a regular basis. This is in contrast to the upstream where SEC regulations enforce much fuller, systemmatic annual disclosures.

As a result, it is more difficult to benchmark downstream performance than upstream performance. Indeed, we can but feel less than satisfied with the insights that we can provide - we are disclosure constrained. Given the downstream data that is availableand comparable, we focus on the following eight metrics:

LPG

EN

I

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Ind

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trie

s

Sta

toil

TO

TA

L

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a

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SEGMENT EXPOSURE Market leader Significant exposure Some exposure No exposure

Rep

so

lY

PF

BP

Refining

Fuels retailing

Wholesale marketing

GA

LP

Sin

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RD

Sh

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OM

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Pipelines, terminals

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Trading

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Lubricants

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on

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bil

Avoid complex measures of

downstream performance

Make the best of poor disclosure levels

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Capital efficiency – return on net fixed assets.

Profitability and cash flow – net profit per barrel of refining throughput, capital expenditure to depreciation ratio, free cash flow per barrel of refining throughput.

Volume –average net size of refinery, refinery utilization, refinery throughput to equity oil production and retail network churn.

The following tables summarize the data for the 11-year period 2000-10 (for some companies, data is not available for all years). This 11-year observation period captures a multi-year upcycle in refining margins (2002-07), followed by a two-year downcycle (2008-09) and the subsequent modest recovery.

In each year, we show the group average and identify the worst-performing (colored red) and best-performing (colored blue) companies. We rank each company based on their score in each year and, where appropriate, over the entire 11-year period. The score is the sum of the scores in each year based on the number of standard deviations from the group’s average – this sets the overall ranking. We rank the OECD and non-OECD companies separately.

CAPITAL EFFICIENCY BASED METRICS

Return on net fixed assets – Ideally, we would like to measure express capital efficiency as a post-tax return on total downstream capital employed. Unfortunately, companies disclose capital employed using different definitions (net versus operating, pre-tax versus post-tax). So, to enable a more meaningful comparison using a very common disclosure, we calculate a net return on downstream net fixed assets. We acknowledge that this may mis-state measured returns since it excludes working capital (primarily crude oil and refined product inventories). However, we believe that it is a useful measure of downstream capital productivity. Furthermore, there is not necessarily a material difference between net fixed assets and capital employed. As we show inFigure 157, for Exxon Mobil year-end net fixed assets and average capital employed in Refining & Marketing have been quite similar. Over the period 2000-10, its fixed assets have been on average 12% higher than capital employed. So, in our view downstream net fixed assets are a reasonable proxy for downstream capital employed.

Figure 157: Exxon Mobil - R&M net fixed assets & capital employed $m


We note that OMV has generated the lowest ROFA in six of the eleven years under observation. With the exception of OMV and Repsol YPF PetroChina, we also note robust 2000-2010 average ROFAs for all of the companies.

90%

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115%

120%

125%

130%

0,000

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30,000

35,000

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Net fixed assets ($m) Capital employed ($m) NFA / CE (x, RHA)

Fixed assets are a good capital

employed proxy

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Table 22: Post-tax return on net fixed assets


Figure 158: Dispersion of returns and profit per barrel


Post tax return on net fixed assets (%)

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 Score Rank Average

BP 18% 19% 7% 12% 19% 19% 18% 13% 11% 11% 14% 1.7 4 15%

Chevron 9% 15% 0% 13% 29% 24% 35% 30% 24% 3% 17% 4.2 3 18%

ENI 22% 22% 8% 14% 20% 27% 17% 7% 11% (4)% (1)% (1.5) 5 13%

Exxon Mobil 13% 17% 5% 12% 21% 28% 29% 32% 28% 6% 12% 6.0 2 18%

GALP - - - - 15% 19% 23% 17% 15% 3% 5% (2.8) 8 14%

OMV 4% 11% 6% 11% 15% 8% 4% 3% 12% (3)% 3% (13.0) 10 7%

Repsol YPF 7% 8% 5% 7% 10% 14% 10% 10% 12% 4% 6% (11.1) 9 8%

RD Shell 14% 14% 7% 9% 19% 22% 20% 17% 15% 4% 6% (2.2) 7 13%

Statoil 10% 10% 4% 10% 11% 28% 20% 16% 18% 8% 13% (2.0) 6 14%

TOTAL 21% 21% 8% 16% 24% 26% 22% 21% 19% 6% 8% 7.2 1 17%

Average 13% 16% 6% 11% 20% 22% 21% 18% 17% 5% 9%

STDEV 6% 5% 2% 3% 6% 7% 9% 9% 6% 5% 6%

Average 2000-10 14%

Post tax return on net fixed assets (%)


RIL - - 11% 16% 25% 24% 32% 41% 17% 11% 17% 8.3 1 21%

IOC - - 25% 27% 14% 14% 18% 19% 11% 19% 14% 7.3 2 18%

Sinopec 7% 3% 8% 9% 9% 4% 2% 14% (12)% 33% 19% 2.1 4 9%

Petrochina (8)% (2)% 2% 4% 9% (14)% (20)% (12)% (50)% 13% 9% (9.5) 5 -6%

Petrobras 24% 28% 12% 20% 9% 16% 17% 12% (4)% 15% 4% 3.7 3 14%

Average 6% 8% 9% 12% 10% 6% 6% 10% -12% 18% 10%

STDEV 16% 16% 8% 9% 7% 15% 20% 19% 26% 9% 6%

Average 2000-10 10%

BP

Chevron

ENI

Exxon Mobil

GALP

OMV

Repsol YPFRD Shell

Statoil

TOTAL

RIL

IOC

Sinopec

Petrochina

Petrobras

-3%

2%

7%

12%

17%

22%

-1.5 -0.5 0.5 1.5 2.5 3.5 4.5 5.5

RO

FA (

20

10

) (%

)

Net income per throughput (2010) ($/bbl)

2000-1015%, $3.9

2000-108%, $3.9

2000-1018%, $2.6

2000-1013%, $3.4 2000-10

14%, $2.5

2000-106%, $2.4

2000-1013%. $2.3

2000-1021%, $4.6

2000-1018%, $3.2

2000-109%, $1.5

2000-1018%, $4.3

2000-1014%, $3.7

2000-10-6%, -$1.2

2000-1014%, $6.3

2000-1017%, $2.8

Net fixed assets $67.2bn

149



PROFITABILITY & CASH FLOW BASED METRICS

Figure 159 shows the post-tax earnings in 2010 of the OECD and non-OECD names. Some investors may be surprised to see that Sinopec generated the largest downstream earnings and BP’s downstream earnings exceeded Exxon Mobil’s.Furthermore, Sinopec has delivered an impressive downstream earnings CAGR 2000-2010 of 22%.

Figure 159: Downstream earnings in 2010 ($m) and 2000-10 downstream earnings CAGR (%) *

Source: J.P. Morgan. * Profit CAGRs for RIL and IOC are calculated 2002-2010.

Net profit per barrel of refinery throughput – Since refineries hold and consume most of downstream capital and for most downstream players are the source of product from which margins are made, we believe that a good holistic measure of downstream profitability and one that neutralizes for operational scale ties downstream post-tax profits to annual refinery throughput.

Clearly, profits will be generated outside refineries (retailing, lubricants marketing etc) and consume less capital employed than refining. A downstream portfolio skewed away from refining is a positive and desirable attribute that will bolster a company’s score and ranking on this measure.

For companies that do not report in US dollars, we have converted from the reporting currency (€, Real etc) to US dollar using the annual average FX rate. For companies that do not report post-tax earnings (i.e. only disclose EBIT), we have estimated a notional tax rate based on the geographical mix of statutory tax rate exposures. We note that BP generated the highest unit profits in four of the eleven years and ranks second overall amongst the OECD names behind Statoil. We note that PetroChina has generated the lowest unit profits in ten of the eleven years.

-1,000

0,000

1,000

2,000

3,000

4,000

5,000

6,00022% profit

2000-10 CAGR

1%

0%

8%

-3%

5% 19%6%-3%

NMNM

4%

NM

8%6%

3%

Sinopec has the world’s largest

downstream earnings

We look for profit augmentation beyond the refinery gate

150



Table 23: Net income per refinery throughput barrel ($/bbl)


Capital expenditure: depreciation ratio – Under-investment can flatter downstream free cash flow generation and earnings (a lack of asset renewal will allow depreciation to run down over time). This can endanger operational reliability with potentially catastrophic consequences which, in turn, can trigger a period of much higher capital expenditure to improve asset integrity. So, we look at this measure as an indicator of asset integrity as well as a lead indicator of new asset formation. We note that GALP ranked lowest in the OECD group 2002 to 2007 and has since played catch-up. Clearly, the rates of downstream investment of the non-OECD names are much higher than the OECD names.

Table 24: Capital expenditure / depreciation (x)


Net income per refinery throughput barrel ($/bbl)


BP 3.8 4.1 1.7 3.1 5.0 4.9 5.3 4.0 3.4 3.5 4.4 9.0 2 3.9

Chevron 1.5 2.6 0.0 2.1 4.6 4.1 5.8 5.4 4.7 0.7 3.6 (0.6) 6 3.2

ENI 3.2 3.1 1.3 3.0 4.2 5.3 3.6 1.7 3.2 (2.0) (0.9) (2.2) 7 2.3

Exxon Mobil 1.7 2.1 0.7 1.7 3.0 3.8 4.1 4.7 4.1 0.9 1.9 (4.9) 10 2.6

GALP 1.0 0.9 2.1 3.0 2.8 3.2 3.4 2.9 4.6 1.1 2.4 (3.8) 9 2.5

OMV 2.1 2.8 1.4 2.5 4.7 5.4 2.8 3.0 7.3 (1.5) 2.6 0.1 5 3.0

Repsol YPF 2.5 2.6 1.6 2.6 3.7 6.2 4.3 5.1 6.5 2.7 4.9 5.0 3 3.9

RD Shell 2.6 2.6 1.6 2.2 4.6 5.3 5.3 5.2 4.7 1.6 2.1 3.0 4 3.4

Statoil 4.2 4.0 1.8 3.5 4.9 10.6 8.8 8.1 13.0 4.3 5.9 21.5 1 6.3

TOTAL 2.3 2.3 0.9 1.8 3.2 4.1 3.9 3.9 4.4 1.7 2.1 (3.0) 8 2.8

Average 2.3 2.6 1.1 2.2 3.8 4.5 4.6 4.6 4.5 1.5 2.6

STDEV 1.0 0.9 0.6 0.6 0.8 2.1 1.7 1.8 2.9 2.0 1.9

Average 2000-10 3.4

Low 1.0 0.9 0.0 1.7 2.8 3.2 2.8 1.7 3.2 -2.0 -0.9

Net income per refinery throughput barrel ($/bbl)


RIL - - 1.9 2.8 4.2 4.9 6.0 9.0 7.2 2.3 3.5 6.5 3 4.6

IOC - - 4.5 5.1 3.5 3.5 4.2 5.2 2.8 5.3 4.4 9.1 1 4.3

Sinopec 1.0 0.6 1.8 2.1 1.9 0.6 0.4 2.3 (2.3) 4.7 3.5 (1.0) 4 1.5

Petrochina (1.5) (0.4) 0.5 0.7 1.6 (2.6) (3.7) (2.6) (11.3) 3.6 2.8 (10.5) 5 (1.2)

Petrobras 3.5 3.8 1.4 3.2 1.8 4.1 4.9 5.1 (1.4) 10.5 4.0 7.5 2 3.7

Average 0.8 1.1 1.7 2.4 2.2 1.2 1.1 2.5 -3.1 5.3 3.5

STDEV 2.5 2.2 1.5 1.6 1.1 3.1 4.0 4.3 6.9 3.1 0.6

Average 2000-10 2.4

Capex / depreciation (x)


BP 4.9 1.2 2.9 1.4 1.2 1.2 1.4 2.3 3.0 1.8 1.8 4.6 3 2.1

Chevron 1.7 2.1 1.5 1.0 1.3 2.1 2.8 2.9 3.4 3.2 2.2 8.4 2 2.2

ENI 1.1 1.0 1.1 1.5 1.5 1.4 1.5 1.6 1.6 1.7 2.1 (1.0) 6 1.5

Exxon Mobil 0.9 1.0 1.1 1.2 0.9 1.0 1.2 1.4 1.5 1.4 1.1 (5.0) 10 1.2

GALP 0.6 0.8 0.5 0.8 0.7 0.7 0.7 1.0 7.5 2.2 4.1 (1.1) 7 1.8

OMV 2.3 1.5 2.0 4.2 1.9 2.6 5.3 3.7 2.5 0.9 2.9 12.6 1 2.7

Repsol YPF 1.0 1.0 0.9 1.1 1.9 1.5 1.2 3.2 2.1 2.4 1.7 1.8 4 1.7

RD Shell 0.5 0.9 3.2 0.8 0.8 1.0 1.3 1.5 1.4 1.2 1.1 (4.0) 9 1.2

Statoil 1.6 0.4 1.0 1.1 2.6 0.8 1.3 1.7 4.0 1.9 1.8 (0.3) 5 1.7

TOTAL 1.1 1.2 1.2 1.4 1.4 1.5 1.2 1.3 1.8 2.1 1.4 (1.1) 8 1.4

Average 1.7 1.2 2.1 1.2 1.2 1.3 1.5 1.9 2.2 1.7 1.6

STDEV 1.3 0.4 0.9 1.0 0.6 0.6 1.4 0.9 1.8 0.7 0.9

Average 2000-10 1.6

Capex / depreciation (x)


RIL - - 0.8 1.4 0.9 3.4 11.2 4.4 3.0 0.3 0.3 (0.1) 4 2.9

IOC - - 2.4 2.2 3.5 2.2 2.2 2.6 3.9 2.8 3.0 2.5 2 2.8

Sinopec 3.1 3.5 1.7 1.9 3.1 3.1 2.9 2.4 2.0 2.0 2.7 1.6 3 2.6

Petrochina 2.2 2.0 1.6 1.6 2.0 1.8 1.6 2.4 1.0 2.4 2.0 (5.7) 5 1.9

Petrobras 1.6 1.7 2.4 2.7 2.6 1.8 2.1 3.9 4.8 8.7 14.0 5.6 1 4.2

Average 2.5 2.7 1.8 1.9 2.5 2.4 2.9 2.9 2.3 3.1 3.8

STDEV 0.8 1.0 0.6 0.5 1.0 0.7 4.1 1.0 1.5 3.2 5.5

Average 2000-10 2.6

Capex to depreciation is a health

check for asset integrity spend

151



Of note, the downstream capex to depreciation ratio for all the OECD names is not very different to their upstream capex to depreciation rate (Figure 160). In 2010, both segments showed a ratio of around 1.5x.

Figure 160: Upstream versus Downstream Capex to Depreciation (OECD names only)

Source: J.P. Morgan. * Upstream capex is development plus net acquisition expenditures.

Free cash flow generation per barrel of refinery throughput - The downstream, like any business, must earn its keep and return an appropriate level of free cash flow to the integrated owner, not least to be accorded value and to contribute to the group's dividend. We derive a simple measure of free cash flow as net income plus depreciation less capital expenditure. All that we are missing is changes to downstream working capital, but over many years this effect should not be significant. In order to neutralize for operational scale when comparing one company to another, we divide this parameter by refinery throughput to derive a $ per bbl cash flow metric (as per our earnings metric).

Clearly, OMV has shown the most consistently weak net free cash flow generation of the group of OECD names. Of note, Statoil ranks first and RD Shell second when measured over the eleven year period.

0.0

0.5

1.0

1.5

2.0

2.5

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Upstream Downstream

Downstream must support the dividend

152



Table 25: Free cash flow per refinery throughput barrel ($/bbl)


VOLUME & SCALE BASED METRICS

Average net size of refinery – As we have highlighted in our summary of downstream competitive advantages, the profitability and returns from a well run refinery are greater if the refinery is larger rather than smaller. The data in Table 26shows the average size of each company’s refinery. We have taken net refining capacity and divided that by the number of refinery interests – this penalizes companies with small, minority interests. As we have highlighted, refining capacity growth 2011-2016 is characterized by ever larger facilities. This will leave smaller (higher unit cost) plants more disadvantaged, emphasizing the need for companies tofocus their refinery portfolios on large units. RD Shell's portfolio has shown the smallest average refinery size in almost of year.

Table 26: Average size of refinery


Free cash flow per throughput barrel ($/bbl)

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 Total Rank

BP (1.5) 1.3 (1.3) 0.8 1.6 1.6 1.5 0.0 (0.8) 0.4 0.9 (2.4) 6

Chevron 0.1 0.4 (0.3) 0.8 1.5 0.9 1.2 0.8 0.3 (1.0) 0.6 (3.6) 7

ENI 0.8 0.9 0.3 0.4 0.7 1.2 0.7 0.1 0.5 (1.0) (0.8) (4.5) 9

Exxon Mobil 0.6 0.8 0.2 0.6 1.1 1.4 1.4 1.5 1.3 0.2 0.6 1.2 3

GALP 0.9 0.6 1.3 1.3 1.4 1.5 1.6 1.1 (4.8) (1.2) (2.6) (4.1) 8

OMV (0.1) 0.5 (0.2) (1.1) 0.4 (0.1) (2.8) (2.1) 0.4 (0.1) (2.0) (14.9) 10

Repsol YPF 0.9 0.9 0.6 0.9 0.6 1.9 1.4 0.9 1.2 (0.6) 0.6 0.7 4

RD Shell 1.4 1.0 (0.8) 0.9 1.8 1.9 1.7 1.5 1.4 0.4 0.7 4.3 2

Statoil 1.0 1.9 0.6 1.2 0.3 4.1 2.8 1.6 (0.1) 0.1 0.9 7.3 1

TOTAL 0.8 0.8 0.3 0.5 0.9 1.2 1.3 1.3 1.0 (0.3) 0.4 (0.4) 5

Average 0.5 0.9 (0.2) 0.7 1.3 1.5 1.3 1.1 0.7 (0.1) 0.5

STDEV 0.8 0.5 0.8 0.7 0.5 1.1 1.5 1.1 1.8 0.6 1.3

Average 2000-10 0.6

Free cash flow per throughput barrel ($/bbl)

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 Total Rank

RIL - - 0.8 0.8 1.6 0.5 (3.5) 1.0 1.3 1.2 1.6 7.4 1

IOC - - 1.0 1.3 (0.0) 0.6 0.8 0.9 (0.5) 0.9 0.3 7.4 2

Sinopec (0.5) (0.9) 0.3 0.3 (0.3) (0.7) (0.7) (0.0) (1.4) 1.1 0.3 (0.3) 4

Petrochina (1.2) (0.6) (0.1) (0.1) 0.0 (1.4) (1.8) (1.9) (4.1) (0.3) (0.3) (7.8) 5

Petrobras 1.1 1.3 0.2 0.6 0.1 1.2 1.2 (0.1) (3.3) (0.7) (6.0) 1.3 3

Average (0.1) (0.1) 0.3 0.5 0.1 (0.2) (0.6) (0.3) (2.2) 0.4 (0.8)

STDEV 1.2 1.2 0.5 0.5 0.7 1.0 1.9 1.1 2.2 0.9 3.0

Average 2000-10 (0.2)

Average size of refinery (kbopd)

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 Score Rank

BP 114 135 130 124 149 149 157 163 158 167 167 11.6 3

Chevron 98 98 95 109 111 111 107 107 114 130 130 (1.8) 5

ENI 95 90 82 76 98 98 98 101 103 103 103 (7.3) 8

Exxon Mobil 146 145 146 154 154 155 176 175 173 173 174 17.0 1

GALP 155 155 155 155 155 155 155 155 155 155 155 15.1 2

OMV 131 131 131 123 123 106 106 106 104 104 104 0.5 4

Repsol YPF 121 131 103 103 103 103 103 103 110 110 116 (1.9) 6

RD Shell 67 69 80 78 82 84 80 86 88 89 100 (12.3) 10

Statoil 89 89 89 89 89 89 89 89 89 89 89 (9.6) 9

TOTAL 95 96 95 96 96 100 100 104 104 104 98 (5.9) 7

Average 103 106 107 108 114 115 117 120 122 125 128

STDEV 28 29 27 28 28 27 33 32 31 32 31

Average size of refinery (kbopd)

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 Score Rank

RIL 542 542 643 663 663 663 663 663 663 623 623 24.3 1

IOC 98 103 106 106 106 110 125 125 125 129 136 (0.4) 4

Sinopec 105 105 107 110 120 124 131 135 127 134 145 (0.1) 3

Petrochina 83 85 86 90 87 93 99 99 99 103 114 (1.4) 5

Petrobras 133 133 135 140 142 141 148 144 148 148 148 0.9 2

Average 109 110 113 117 119 123 130 131 128 138 146

STDEV 196 196 239 247 246 245 241 241 241 222 218

Refinery size is a driver of profitability…..

153



Refinery utilization - Refineries, like most industrial plants, have relatively high fixed costs. So, their profitability is partly indexed to plant load factor or refinery utilization. This is measured as annual refinery crude throughput to nameplate operating capacity. We grade companies accordingly. This is an indicator of management efficiency, robust plant integrity (a well maintained refinery should not experience material unplanned outages) and market requirements (strong demand will consistently pull product through the system). Statoil has shown the highest utilization rate in five of the eleven years under observation. GALP ranks last in the OECD group with an average utilization of just 80% versus 87% for the group. Overall, Reliance Industries is the clear leader with an average utilization of 98%.

Table 27: Average refinery utilization (%)


Refinery throughput: equity oil production – This is the ratio of annual refinery throughput to equity oil production. It gives a useful sense of how biased a company's operations are to upstream, specifically oil (ratio < 1) or downstream (ratio > 1). Given our bearish outlook for refining margins, we prefer companies which are long upstream and thus show a ratio close to or less than one. Whatever an investor’s preference, they can use this metric to steer their investment choices. This ratio highlights a clear winner (ENI) and a clear loser (Repsol YPF).

Table 28: Refinery throughput / equity oil production (%)


Average refinery utilisation (%)


BP 95% 92% 89% 91% 92% 85% 78% 77% 80% 86% 91% (3.4) 8 87%

Chevron 91% 92% 93% 94% 91% 88% 91% 89% 90% 90% 91% 5.8 2 91%

ENI 91% 93% 95% 88% 85% 88% 86% 82% 77% 74% 75% (6.8) 9 85%

Exxon Mobil 90% 89% 87% 88% 90% 90% 88% 88% 87% 86% 84% (0.2) 6 88%

GALP 75% 81% 76% 82% 84% 86% 87% 81% 79% 69% 75% (18.1) 10 80%

OMV 88% 94% 95% 95% 94% 90% 92% 85% 86% 82% 76% 2.9 4 89%

Repsol YPF 84% 85% 85% 86% 89% 89% 90% 91% 92% 80% 80% (2.9) 7 87%

RD Shell 91% 89% 88% 92% 93% 93% 89% 88% 85% 76% 82% 0.7 5 88%

Statoil 92% 91% 90% 96% 95% 95% 95% 93% 90% 88% 85% 9.6 1 92%

TOTAL 94% 96% 88% 92% 93% 88% 88% 87% 88% 83% 85% 2.9 3 89%

Average (%) 91% 90% 88% 90% 91% 89% 88% 87% 86% 83% 84%

STDEV 6% 4% 5% 4% 4% 3% 5% 5% 5% 7% 6%

Average 2000-10 87%

Average refinery utilisation (%)


RIL 95% 107% 89% 92% 100% 93% 96% 96% 100% 100% 105% 19.2 1 98%

IOC 85% 83% 83% 89% 87% 88% 89% 95% 103% 99% 98% 7.0 2 91%

Sinopec 81% 78% 79% 82% 86% 91% 91% 90% 82% 80% 86% (2.2) 4 84%

Petrochina 78% 80% 78% 84% 89% 88% 84% 87% 90% 85% 83% (3.9) 5 84%

Petrobras 79% 84% 84% 82% 86% 87% 85% 91% 87% 89% 90% (1.4) 3 86%

Average (%) 81% 82% 82% 84% 88% 89% 88% 91% 88% 87% 89%

STDEV 7% 12% 4% 5% 6% 2% 5% 4% 9% 9% 9%

Average 2000-10 89%

Refinery throughput / equity oil production (%)

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 Score Rank

BP 145% 135% 139% 128% 103% 94% 88% 88% 90% 90% 102% 5.5 3

Chevron 96% 100% 102% 100% 104% 102% 106% 102% 110% 100% 98% 5.9 2

ENI 104% 88% 67% 61% 73% 70% 71% 73% 70% 69% 70% 9.6 1

Exxon Mobil 221% 218% 218% 219% 222% 227% 209% 213% 225% 224% 217% (8.9) 7

OMV 420% 453% 465% 450% 459% 266% 290% 276% 268% 248% 227% (22.3) 8

Repsol YPF 158% 156% 179% 179% 193% 208% 212% 233% 282% 248% 236% (8.2) 6

RD Shell 140% 146% 165% 166% 173% 175% 176% 184% 176% 166% 172% (2.5) 5

TOTAL 168% 170% 148% 149% 147% 149% 163% 160% 162% 156% 155% (1.0) 4

Average 154% 152% 153% 152% 150% 148% 147% 149% 152% 144% 146%

STDEV 104% 116% 122% 119% 122% 70% 74% 74% 80% 72% 64%

Refinery throughput / equity oil production (%)

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Reliance Industries Limited - - - - - - - - - - -

IOC - - - - - - - - - - -

Sinopec 314% 277% 286% 316% 359% 382% 413% 413% 425% 446% 473%

Petrochina 72% 74% 74% 82% 87% 91% 94% 98% 98% 98% 105%

Petrobras 89% 91% 84% 78% 83% 77% 83% 86% 81% 79% 77%

….as is refinery utilization

154



Figure 161: Refinery utilization, capacity and average size


Retail network management – Integrated oil companies can gather assets like a ship gathers barnacles. Some companies just sit on their assets regardless, citing long-term strategic benefits of retained ownership, so opting for scale rather than value and efficiency. Other companies are simply better at churning their assets to right-size and optimize their portfolios and to exploit variations in the asset pricing cycle. This releases capital for efficient redeployment, back to the business or to shareholders. We believe that the concept of a global fuels retailer, present in most countries, is a flawed strategic aspiration - retailers must focus. As per Figure 162, RD Shell has the world's largest fuels retail network.

BP

GALP

Repsol YPF

OMV

ENI

RD Shell

Statoil

TOTAL

Chevron

Exxon Mobil

RILIOC

Sinopec

Petrochina

Petrobras

0

1000

2000

3000

4000

5000

6000

7000

70% 75% 80% 85% 90% 95% 100% 105% 110%

Re

fin

ery

cap

acit

y 2

01

0 (k

bo

pd

)

Refinery utilization 2010 (%)

2000-1084%

2000-1088%

2000-1087%

2000-1089%

2000-1092%

2000-1085%

2000-1089%2000-10

80%

2000-1084%

2000-1088%

2000-1086%

2000-1091%

2000-1098%

2000-1091%

Average refinery size 623 kbopd

2000-1087%

We look for healthy retail churn

– we prefer OECD names to

focus and non-OECD names to capture growth efficiently

155



Figure 162: Scale of retail networks (YE 2010) & 2000-10 network CAGR


So, we examine which have managed down their retailing exposure best from 2000-10. We score and rank each company on the average rate of network shrinkage measured over 2000-10. We prefer OECD companies that release capital from their retail networks and focus their market positions. Conversely, we look for non-OECD companies that successfully capture market growth via efficient network expansion.

Table 29: Retail network size


-1.3 % CAGR '00-10

1.7 %

-2.7 %

7.2 %

4.7 %-0.8 % 1.2 %

-6.5 %

-1.7 %

7.3 % 1.3 %

1.3 %1,233 1,539

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

Retail sites at YE 2010 * For IOCCAGR is calculated for 2003-10

Marketing outlets at year end

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 CAGR Rank

BP 29,000 26,800 29,200 27,800 26,500 24,600 23,900 23,300 22,600 22,400 22,100 (2.7)% 5

Chevron 20,349 20,404 20,368 19,615 20,220 20,354 20,493 19,657 19,457 16,350 14,638 (3.2)% 4

ENI 12,085 11,707 10,762 10,647 9,140 6,282 6,294 6,440 5,956 5,986 6,167 (6.5)% 1

Exxon Mobil 45,001 42,853 41,786 39,488 37,374 35,432 33,848 32,386 28,674 27,720 26,278 (5.2)% 2

GALP 1,353 1,310 1,181 1,148 1,154 1,123 1,108 1,100 1,605 1,549 1,539 1.3% 9

OMV 1,136 1,160 1,232 1,782 1,773 2,451 2,540 2,538 2,528 2,433 2,291 7.3% 10

Repsol YPF 7,224 6,636 6,629 6,614 6,913 6,853 6,806 6,514 5,818 5,838 5,818 (2.1)% 6

RD Shell 48,830 48,347 47,868 47,394 46,925 45,765 44,725 45,160 44,605 43,912 42,816 (1.3)% 7

Statoil 2,006 1,889 1,883 1,989 1,984 1,998 1,803 2,477 2,426 2,297 1,233 (4.8)% 3

TOTAL 18,957 18,051 17,755 17,284 16,857 16,976 16,534 16,497 16,425 16,299 17,490 (0.8)% 8

Total 185,941 179,157 178,664 173,761 168,840 161,834 158,051 156,069 150,094 144,784 140,370

Y-o-Y growth (4)% (0)% (3)% (3)% (4)% (2)% (1)% (4)% (4)% (3)%

11 year marketing outlet CAGR (3)%

Marketing outlets at year end

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 Score Rank

RIL - - - 0 0 0 0 0 0 0 0 0.0% 5

IOC - - - 11,926 13,528 15,275 16,607 17,803 18,547 18,643 19,463 7.2% 1

Sinopec 25,493 28,246 28,127 30,242 30,063 29,647 28,801 29,062 29,279 29,698 30,116 1.7% 3

Petrochina 11,350 12,102 13,160 15,231 17,403 18,164 18,207 18,648 17,438 17,262 17,996 4.7% 2

Petrobras 7,000 7,261 7,120 6,998 8,331 6,933 6,554 6,436 6,350 7,221 7,873 1.2% 4

Total 43,843 47,609 48,407 64,397 69,325 70,019 70,169 71,949 71,614 72,824 75,448

Y-o-Y growth 9% 2% 33% 8% 1% 0% 3% (0)% 2% 4%

2003-10 year marketing outlet CAGR 2%

156



Appendix II: Refinery transactions

We track refinery transactions in order to sense-check our downstream asset valuations and to assess management's ability to optimize the timing of refinery sales and purchases given a cyclical variation in refinery valuations. We record buyer / seller, price paid ($m including amount paid for plant working capital) and net capacity transferred (kbopd). Where appropriate, for mixed asset transactions, we estimate the value assigned to non-refining assets in order to distill a pure value for the refinery. Since the beginning of 2007, we have tracked a total of 42 refinery transactions where the price paid has been publicly disclosed. As per Figure 163, we note the following features of this specific M&A trend:

A cyclical variation in transaction frequency – We recorded a total of 12 transactions in 2007, 5 in 2008, 7 in 2009, 9 in 2010 and 9 YTD 2011. So, perhaps unsurprisingly, there was a reduction in transaction frequency during the oil price / capital market / industry hiatus in 2008-09 as both buyers and sellers withdrew from the market. However, transaction frequency has picked up nicely in 2010 and 2011 as more companies look to offload marginal plants within their portfolios.

Europe has been the most ‘liquid’ market, then the USA - We have noted the highest number of transactions (20 or just less than 50% of total) in Europe (excluding the most recently announced ConocoPhillips/Hyesta Energy transaction for which price has not been disclosed), 16 in the USA and just 6 in the Rest of the World. Refineries in Asia are very infrequently traded – we have public data for only six transactions 2007-2011.

A significant cyclical variation in asset prices - This is not surprising either since the purchaser will likely shift its forecast margins and utilization rates when valuing the asset, just as a purchaser of an upstream asset will shift its near, medium and long-term oil (gas) price forecast. Furthermore, during margin upcycles there are likely to be more interested buyers with more acquisition firepower. It would appear that refinery values peaked in 2007 and then bottomed out in 2010-11, but have since started to recover.

Transaction data is a cross-check for our refinery valuations

Asset prices vary significantly across the cycle….so does

transaction frequency

157



Figure 163: Refinery transaction values ($ 000 per bopd capacity)

Source: J.P. Morgan. We include working capital in our transaction multiples and adjust, where possible, for the value of other assets e.g. pipelines, retail outlets etc.

Limited regional average price dispersion over the cycle – As per Table 30, we see limited cross-cycle variation in asset prices when compared across the three key regions of the USA (2007-11 average $8,600 per bopd), Europe (2007-11 average $8,500 per bopd) and the Rest of the World (2007-11 average $9,100 per bopd). Measured globally, over the past 4.5 years, 42 refineries have traded for a total of $49bn at an average unit price of $8,600 per bopd. Our downstream asset values rely on lower, more conservative unit assumptions for company-specific refineries.

Table 30: Refinery transaction data 2007-2011 YTD

Region Number of Deals Total refining capacity (kbopd) Total value ($m) Average value ($000/bopd)

Europe 20 3,275 27,942 8.5USA 16 1,924 16,453 8.6Rest of world 6 507 4,621 9.1TOTAL 42 5,706 49,016 8.6


In the public domain, we are aware of at least 18 refineries / stakes in refineries that are either on the market and being actively marketed or are likely still available for sale following an unsuccessful auction (Table 31). The total capacity is almost 2.4million bopd, of which over half (1.53 million bopd) is located in the USA where there are at least six refineries for sale. In addition to these refineries, Saras continues to look for an NOC partner for its 300 kbopd Sarroch refinery in Italy.

0

5

10

15

20

25

30

35

0 5 10 15 20 25 30 35 40

$k

pe

r b

op

d

2007 2008 2009 2010 2011

USA

EUROPE

RoW283 kbopd

Circle size reflects refinery size

Asset prices bottomed and turned

Cross-cycle average value around $9k per bopd

Number of refineries on the

market

158



Table 31: Refineries for sale

Country LocationCapacity

kbopd Vendor Comments

Caribbean Aruba 285 Valero Valero confirmed it has had talks with PetroChina & PemexCzech Republic Kralupy 30 RD Shell / ENI * Reported $232m offer from Mero CRaccording to Platts

Litvinov 54 RD Shell / ENI Unipetrol (51%) has pre-emption right.FranceIreland

Berre L-EtangWhitegate

10571

Lyondell-BasellConocoPhillips

Company confirmed plant for sale on 31 May 2011.

Italy Livorno 85 ENI Pulled following talks with PE Klesch, as confirmed by ENILithuania Orlen Lietuva 190 PKN Orlen Platts reported that may be selling 25% to Rosneft for $425mLibya Zawia 60 LNOC Libyan Investment Authority was selling prior to civil unrestUSA Ardmore (Oklahoma) 92 Valero

Trainer (Pennsylvania) 185 ConocoPhillipsCarson (California) 270 BP Likely transaction in 2012 according to BP.Texas City 475 BP Likely transaction in 2012 according to BP.Marcus Hook 175 Sunoco Possible transaction in 2012 according to Sunoco (6 Sept)Philadelphia 330 Sunoco Will take an impairment charge of $1.9-$2.2bn with Q3 2011 results

Thailand Esso Thailand stake 116 Exxon Mobil In our view, the natural buyer is Thai OilUK Milford Haven 130 Murphy

Killingholme (Lindsey) 225 TOTAL TOTAL’s CFO said (29 July) that exclusive talks failed because unnamed buyer Zambia Indeni 19 TOTAL was refused financing.

2,897

Source: J.P. Morgan. RD Shell has 16.4% and ENI has 32.5% stake in the Kralupy plant.

Further to our core research theme of surplus refining capacity, we note that changes to refinery ownership can add to this risk. For example, Valero shut its Delaware City refinery (210 kbopd) in November 2009 due to weak margins and then sold it to PBF Investments LLC in February 2010. Following a plant upgrade, PBF re-opened the refinery in Q2 2011. Similarly, ConocoPhillips has announced the sale of its Wilhemshaven refinery in Germany (260 kbopd) to Hyesta Energy. The latter is backed by private equity firms (Riverstone/Carlyle Global Energy and Power Funds, a group of energy-focused private equity funds managed by Riverstone and AtlasInvest) - it intends to re-open the plant that has been closed since a fire in May 2010.

Refinery transfers can stall retirement and return retired

capacity to operations

159



Appendix III: Refinery projects data

The following tables detail our database on global refining projects - by country, location, primary sponsor and primary distillation capacity. We only include additions, either brownfield expansion or green field, to primary distillation capacity – we therefore exclude upgrading additions. Our experience when tracking these projects is that they have a notable tendency to complete and commission later than scheduled. We also include capacity that has been or is expected to re-open. Figure 164 shows how the regional capacity growth profiles may evolve 2010 to 2016E.

Figure 164: Regional net refining capacity growth (kbopd)


In the data tables, we have shaded those projects that are sponsored by NOCs / government controlled entities – these total over 130 (52%) of the 250 projects that we have identified in these lists, but these represent a much larger percentage of new capacity. Of the aggregate new capacity identified 2011-16 (c.27.4 million bopd), NOCs are sponsoring 67% (c.18.5 million bopd).

NORTH AMERICA

SOUTH AMERICA

ASIA PACIFIC

MIDDLE EAST

EUROPE

AFRICA

160



Table 32: Refinery projects

2010 2011E

Country Location Primary sponsorCapacity (kbopd) Country Location Primary sponsor

Capacity (kbopd)

ARGENTINA San Lorenzo Petrobras 15 AUSTRALIA Chinchilla Linc 5CHINA Qinzhou PetroChina 200 CHAD N'Djamena CNPC / SHT 20CHINA Jilin expansion PetroChina 60 CHINA Daxie - Zhejiang CNOOC 40CHINA Qingyang - Gansu PetroChina 24 CHINA Liaoyang PetroChina 70CHINA Tahe expansion Sinopec 70 CHINA Fushun - Liaoning PetroChina 50CHINA Changling - Hunan Sinopec 60 CHINA Dongmin Dongmin P’chem 60CHINA Shandong Sinopec 40 CHINA Shangdong ChemChina 80CHINA Zhejiang Sinopec 60 CHINA Shandong ChemChina 70CHINA Shanghai Gaoqiao Sinopec 34 CHINA Beihai / Tieshan Sinopec 100CHINA Luoyang - Henan Sinopec 40 CHINA Ningxia Hui CNPC 67CHINA Yingkou - Liaoning CNOOC 20 IRAQ Khabat, near Erbil KRG 40CUBA Santiago Cupet / PDVSA 28 IRAQ Koia Cicsco 70GREECE Elefsina, South Greece Hellenic 60 INDIA Guru Gobind Singh HPCL / Mittal 181GREECE Agioi, Theodoroi Motor Oil 120 INDIA Bina BORL 120HUNGARY Szazhalombatta MOL 25 INDIA Vadinar Essar 75IRAN Arak refinery National Iranian Oil 30 JAPAN Sakai Cosmo Oil 67IRAN Isfahan National Iranian Oil 100 JAPAN Kashima Japan Energy 30IRAQ Suleimaniya Kar Group 75 JAPAN Shikoku Taiyo Oil 25IRAQ Najaf Kar Group 10 MEXICO Minatitlan Pemex Refinacion 111IRAQ Samawah Kar Group 10 N. ZEALAND Marsden Point New Zealand R Co. 35INDIA Panipat, Haryana IOC 60 NIGERIA Akwa Ibom State Amakpe Intl. 20INDIA Haldia, West Bengal IOC 30 PERU Talara Petroleos de Peru 28INDIA Kochi, Southern Kerala BPCL 38 QATAR Pearl Royal Dutch Shell 140JAMAICA Kingston Petrojam 25 RUSSIA Niznhekhamsk Tatneft 140KUWAIT Mina Abdullah KNPC 260 S. KOREA Incheon SK Energy 40PAKISTAN Baluchistan Bosicor Oil Pakistan 115 SPAIN Cartagena Repsol YPF 120S. ARABIA Jubail , East Coast SASREF 100 USA Delaware PBF * 210S. KOREA Yeosu GS Caltex 20 TOTAL 2,014SYRIA Banias 50 NOC sponsored 905TUNISIA La Skhira, Tunisia ETAP 120UAE Dubai - Jebel Ali ENOC 50USA Garyville, Louisiana Marathon 180YEMEN Ras Issa Reliance Industries 50TOTAL 2,179NOC sponsored 1,669

Source: J.P. Morgan. * Plant was closed by Valero in November 2009, but re-opened by PBF in Q2 2011 following substantial upgrade.

161



Table 33: Refinery projects (continued)

2012E 2013E

Country Location Primary sponsorCapacity (kbopd) Country Location Primary sponsor

Capacity (kbopd)

ALGERIA Skikda Sonatrach (Naftec) 7 ALGERIA Arzew Sonatrach (Naftec) 27CHINA Pengzhou PetroChina 200 BRAZIL Abreu e Lima Petrobras 230CHINA Anqing expansion Sinopec 60 CHINA Hohot PetroChina 60CHINA Juliang Sinopec 70 CHINA Wuhan - Hubei Sinopec 60CHINA Huabei - expansion PetroChina 96 CHINA Quanzhou Sinochem 240GERMANY Wilhelmshaven * Hyesta Energy 260 CHINA Urumqi PetroChina 40IRAQ Basra Basra Refiney 70 COLOMBIA Cartagena Ecopetrol 165IRAQ Basra Basra Refiney 20 C. RICA Moin CNPC 42INDIA Vadinar Essar 30 CUBA Cienfuegos Cupet / PDVSA 85INDIA Mangalore MRPL 61 ISRAEL Ashdod Paz Group 13JORDAN Zarqa refinery MENA 30 KAZAKHSTAN Pavlodar KazMunaiGaz 50PAKISTAN Mouza Bosicor Oil 30 MALAYSIA Melaka Petronas 30PAKISTAN Thatta Indus Refinery Ltd 93 SAUDI ARABIA Jubail Saudi Aramco 400PORTUGAL Sines Galp 50 S. KOREA Daesan Hyundai Oilbank 52RUSSIA Tuapse Rosneft 163 TARTASTAN Nizhnekamsk Tatneftekhiminvest 140RUSSIA Kirishi Surgutneftegas 100 THAILAND Sriracha Thai Oil 25SUDAN Khartoum CNPC / SEM 100 USA Illinois ConocoPhillips 50USA Port Allen Placid 25 TOTAL 1,709USA Port Arthur Motiva 325 NOC sponsored 1,454USA Mandan Tesoro 10VENEZUELA Santa Ines PDVSA 100VENEZUELA Caripito PDVSA 50TOTAL 1,950NOC sponsored 1,097

Source: J.P. Morgan. * Plant was closed by ConocoPhillips in May 2010, but new owner (Hyesta Energy) likely to re-open it in 2012.

2014E

Country Location Primary sponsorCapacity (kbopd)

ALGERIA Algiers Sonatrach (Naftec) 21BAHRAIN Sitra BAPCO 125BRAZIL Comperj Petrobras 165CHINA Tianjin CNPC 260CHINA Jieyang CNPC 400CHINA Donghai Is. Kuwait Petroleum 300CHINA Yunnan CNPC / Saudi Aramco 200IRAQ Nassiriyah SCOP 300INDIA Paradip IOC 240INDONESIA Tuban Pertamina 200MONGOLIA Darkhan City Mongol Sekiyu 44NIGERIA Edo State TFS Financial Services 12NIGERIA Escravos GTL Chevron 30RUSSIA Nizhni Novgorod Lukoil 60RUSSIA Tuapse Rosneft 200THAILAND Map ta Phut IRPC 50TURKEY Port of Ceyhan Petrol Ofisi Anonim Sirket 192UAE Ruwais ADNOC 417VIETNAM Vung Ro Technostar 80YEMEN Mariboil Yemen govt 15TOTAL 3,311NOC sponsored 3,017


162



Table 34: Refinery projects (continued)

2015E 2016E

Country LocationPrimary sponsor

Capacity (kbopd) Country Location Primary sponsor

Capacity (kbopd)

ARGENTINA Refineria del Sur Bridas 100 ARGENTINA Chubut TBC 150ALGERIA Tiaret Sonatrach 300 ALGERIA Tinrhert Sasol 36ANGOLA Lobito Sonangol 200 BANGLADESH Chittagong Eastern Refinery Ltd 50BRAZIL Ceara P1 Petrobras 300 BRAZIL Ceara P2 Petrobras 300BRUNEI Pulau Muara PetroBru 200 BRAZIL Maranhao Petrobras 300BRUNEI Pulau Muara Zhejiang 135 BOLIVIA La Paz YPFB 35BULGARIA Silistra Petromaxx 55 CANADA Newfoundland Newfoundland & Labrador Ref. 300CANADA Newfoundland Harvest En. 75 CHINA Huizhou CNOOC 200CHINA Dushanzi PetroChina 120 CHINA Anning CNPC 200CHINA Maoming Sinopec 240 CHINA Jiangsu Sinopec 240CHINA Guizhou Guizhou Yufu 100 CHINA Ningdong Sasol 80CUBA Matanzas Cupet 150 ECUADOR Manta PDVSA 300IRAQ Karbala Govt. 200 EGYPT TBC EGPC 130IRAQ Missan Oil Ministry 150 EGYPT TBC Citadel Capital 200IRAQ Kirkuk Oil Ministry 150 EGYPT Cairo ERC 94INDIA Koyali, Gujarat IOC 44 INDIA Jamnagar Reliance Industries 540INDIA Vadinar Essar 345 IRAN Hormuz TBC 300INDONESIA Selayar Island Pertamina 300 IRAN Pars TBC 120INDONESIA Banten West Pertamina 300 IRAN Anahita TBC 150INDONESIA Dumai Pertamina 80 IRAN Caspian TBC 300MALAYSIA Manjung Gulf Petm. 150 IRAN Khoaestan TBC 180NIGERIA Rivers State Shaygaz 200 IRAN Shahriyar TBC 150PAKISTAN Khalifa Point Pak-Arab 250 IRAQ Kurdistan Make Oil 250RUSSIA Kola Bay Sintez Petm. 120 INDIA Lote HPCL 360RUSSIA Chelyabinsk Quality En. 180 INDIA Kochi BPCL 121RUSSIA Teriberka Gazprom 100 INDONESIA Balongan Pertamina 200S. ARABIA Yanbu Saudi Aramco 400 JORDAN Aqaba Kuwait govt. 100S. ARABIA Jazan Saudi Aramco 325 KUWAIT Nr Az-Zour Kuwait National Petroleum Co 615S. ARABIA Ras Tanura Saudi Aramco 400 MALAYSIA Kedah Merapoh Resources 350S. AFRICA Richards Bay Drako O & G 300 MEXICO Tula Pemex Refinacion 300SRI LANKA Cuddalore Nagarjuna Oil 120 MOZAMBIQUE TBC OilMoz 350SRI LANKA Sapugaskanda Ceypetco 50 NIGERIA Central Kogi NNPC 150TAIWAN Changhua Kuokuang PC 300 NIGERIA Lagos NNPC 300TANZANIA Dar Es Salaam Noor Oil 175 PAKISTAN Baluchistan OGDC 168TURKEY Port of Ceyhan STEAS 200 PAKISTAN Port Qasim KPC 200TURKEY Port of Ceyhan Calik Enerji 212 PAKISTAN Morgah Attock Refinery Ltd 10TURKEY Aliaga SOCAR 200 PANAMA Puerto Armuelle Occidental 350UGANDA Hoima Essar 200 RUSSIA Ust-Luga Guvnor 160USA Port Arthur Valero 100 S. AFRICA Mthombo PetroSa 400USA St Charles Valero 60 SUDAN Port Sudan Petronas 175USA McKee Valero 25 SUDAN Akon Southern Sudan govt 200VENEZUELA Cabruta PDVSA 400 SYRIA Furoqios PDVSA 140VIETNAM Thanh Hoa PetroVietnam 200 SYRIA Deir Al-Zur Nour Investment Company 140TOTAL 8,211 UAE Fujairah IPIC 175NOC sponsored 5,009 UKRAINE Odessa Ukraine / Libya 220

USA Arizona Arizona Clean Fuels LLC 150VIETNAM Quang Nai PetroVietnam 58VIETNAM Nam Van Phong Petrolimex 205TOTAL 10,202NOC sponsored 6,992


163



Appendix IV: Global Integrated Valuation Update

Table 35: Global Integrated Valuation Update

Source: Company data, J.P. Morgan estimates

Global Integrated Oils - Analyst Team

UK Integrateds European Integrateds US Integrateds Emerging Oils - Asia Emerging Oils - Russia Emerging Oils - LatAmFred Lucas (AC) Nitin Sharma Katherine Lucas Minyard, CFA Brynjar Eirik Bustnes Nadia Kazakova Caio Carvalhal(44-20) 7155 6131 (44-20) 7155 6133 (1-212) 622 6402 (852) 2800 8578 (7-495) 937 7329 (55-11) 3048 [email protected] [email protected] [email protected] [email protected] [email protected] [email protected]

Emerging Oils -South Africa For specialist sales advice please contact:

Alex Comer Hamish Clegg(44-20) 7325 1964 (44-20) 7325 0878

[email protected] hamish.w [email protected]

Prices as of c.o.b. 06-Sep-11

Company SOTP Premium PER (x) EV/DACF (x) Dividend Yield (%) YE Net debt / (cash) (m) Net Debt / Equity (%)

per share (Discount) 10A 11E 12E 10A 11E 12E 10A 11E 12E 10A 11E 12E 10A 11E 12E

OECD

Exxon Mobil 86.0 (17)% 11.4 8.5 6.2 7.6 6.1 6.3 2.4 2.5 2.6 8,422 8,825 -10,135 6 6 -5

BP 787 (53)% 5.5 5.2 5.3 9.2 3.8 3.9 1.2 4.8 5.1 19,278 16,239 16,360 20 14 12

RD Shell A 29.4 (24)% 10.7 7.4 6.8 8.3 5.3 4.8 6.3 6.0 6.2 30,888 22,659 14,781 21 14 8

RD Shell B 2,600 (23)% 10.9 7.6 6.9 8.4 5.4 4.9 5.4 5.2 5.4 30,888 22,659 14,781 21 14 8

Average (29)% 9.6 7.2 6.3 8.4 5.2 5.0 3.8 4.6 4.8 17 12 6

BG Group 1,908 (36)% 15.9 15.4 14.2 10.9 11.2 10.1 1.1 1.2 1.4 4,466 7,950 11,162 26 41 51

Chevron 101.0 (5)% 10.0 6.8 6.0 5.8 5.1 6.0 3.0 3.2 3.3 -4,509 -8,772 -10,620 -4 -7 -7

ConocoPhillips 91.0 (28)% 11.1 7.7 5.0 5.7 5.6 5.8 3.3 4.0 4.4 18,353 16,648 13,753 27 24 17

Hess 96.0 (41)% 11.0 8.1 4.8 4.5 4.4 4.7 0.7 0.7 0.7 1,848 1,522 125 11 8 1

Marathon 35.0 (28)% 6.9 5.7 4.7 3.9 3.1 3.0 4.0 4.0 4.0 4,404 3,600 1,985 19 14 7

Murphy 68.0 (26)% 11.3 8.8 5.5 5.0 4.3 4.2 2.1 2.1 2.2 1,335 1,235 1,467 16 14 14

Occidental 100.0 (17)% 14.4 10.2 7.5 8.2 6.8 7.0 1.7 2.1 2.2 549 483 -1,401 2 1 -3

Cenovus Energy 43.0 (21)% 32.1 18.6 9.4 10.8 9.8 8.2 3.9 5.8 10.7 3,631 3,775 3,169 36 35 24

Husky Energy 28.0 (15)% 18.0 10.1 7.9 7.2 5.9 6.1 5.1 5.1 5.2 3,982 4,359 4,828 26 26 26

Suncor 47.0 (38)% 16.8 9.9 6.3 8.8 6.3 7.8 1.4 1.4 1.4 11,098 8,077 6,169 30 20 13

ENI 29.4 (56)% 6.9 5.5 5.1 5.0 4.1 3.7 7.7 8.1 8.5 26,119 24,228 21,777 47 39 32

Essar Energy 5.20 (54)% 20.1 12.6 6.5 -34.0 13.8 7.2 0.0 0.0 0.0 3,934 7,081 7,876 92 151 143

GALP 18.4 (29)% 35.2 28.0 17.3 17.9 14.0 11.9 1.5 1.5 1.5 2,840 3,597 3,782 105 116 107

OMV 42.7 (39)% 6.9 6.4 5.9 4.5 4.5 4.0 3.9 4.0 4.1 5,167 4,445 4,423 46 34 32

Repsol YPF 28.7 (36)% 11.0 9.3 7.7 5.1 4.9 5.3 5.7 6.3 6.9 10,958 9,894 11,367 42 36 39

Statoil 184.8 (34)% 9.2 7.0 7.1 5.6 4.5 4.6 5.2 5.4 5.7 69,681 30,626 36,725 31 12 12

TOTAL 53.8 (41)% 6.8 5.7 5.9 4.5 4.3 4.4 7.2 7.7 8.1 13,031 12,310 10,324 22 18 14

Average (32)% 14.8 10.6 7.5 4.7 6.8 6.2 3.3 3.7 4.1 33 34 31

Emerging Market

Sinopec 7.5 6.7 6.4 5.3 4.6 4.3 3.4 3.8 4.0 135,344 146,894 132,423 32 31 24

PetroChina 10.3 8.9 9.7 6.3 5.8 5.4 3.7 5.1 4.6 187,911 274,883 324,134 20 27 29

S-Oil 17.7 9.0 9.4 36.9 21.2 13.3 2.4 4.7 3.8 1,062,689 1,782,255 442,996 23 34 7

SK Innovation 11.4 6.4 7.6 12.0 8.6 8.5 1.4 1.5 1.6 6,312,558 3,668,442 1,918,263 58 24 11

Gazprom 4.4 3.4 3.5 4.5 3.8 3.1 1.5 1.9 1.8 28,643 34,214 19,763 14 14 7

Gazprom Nef t 6.4 5.1 5.7 4.4 5.3 4.3 3.1 4.0 3.5 5,380 6,131 4,518 29 27 17

Lukoil 4.7 4.7 5.1 4.4 4.2 3.8 3.7 3.8 4.4 8,658 5,276 2,116 15 8 3

Rosneft 6.6 5.4 7.9 8.8 5.2 5.1 1.3 1.5 1.7 19,401 14,016 7,861 36 21 11

Surgutneftegaz 5.8 4.4 4.5 1.6 1.5 1.4 2.5 3.8 3.7 -15,686 -18,901 -23,038 -36 -38 -42

Tatneft 8.6 5.7 5.7 6.5 5.9 4.6 3.5 5.3 5.3 2,526 1,640 95 23 13 1

MOL 15.5 5.4 5.5 4.1 2.7 2.8 0.0 4.4 4.3 4,810 3,437 3,002 70 38 30

Sasol* 11.7 9.0 8.2 9.7 8.3 6.5 3.4 3.9 4.0 -902 -9,002 -14,550 -1 -8 -11

Ecopetrol 19.6 13.3 10.6 13.7 10.3 8.8 3.1 3.7 5.5 4,968 3,334 3,226 NM NM NM

Reliance Industries** 15.5 12.7 11.1 34.7 7.0 7.7 0.9 1.0 1.2 376,024 196,210 -162,325 37 17 -12

Average 10.4 7.1 7.2 10.9 6.7 5.7 2.4 3.4 3.5 25 16 6

164



Appendix V: Downstream glossary of terms

Refining

The core refining process is simple distillation (Table 36). Crude oil is heated and put into a distillation column - different products boil off and are recovered at different temperatures. The lighter products - LPG, naptha and gasoline - are recovered at the lowest temperatures. Middle distillates - jet fuel, kerosene, distillates (heating oil and diesel) - boil off next. The heaviest products (residuum) are recovered at temperatures that may exceed 1,000 degrees F. The simplest refineries stop at this point. In a more complex refinery, additional processes follow which take the heavy, low-valued streams and convert them into lighter, higher-valued output. A catalytic cracker converts gasoil into finished distillates (heating oil, diesel and gasoline). A hydro-treater removes sulfur. A reforming unit produces higher octane components for gasoline from lower octane feedstock recovered during distillation. A coker uses the heaviest output (the residue) to produce lighter feedstock and petroleum coke.

Table 36: Refining process - simple overview


The downstream industry contains no fewer technical terms than the upstream. We summarize the most commonly used terms to enable investors to see through more of the 'jargon', specifically relating to the refining process.

Acid treatment – A process in which unfinished petroleum products such as gasoline, kerosene and lubricating oil stocks are treated with sulphuric acid to improve colour, odor or other properties.

Additive – chemicals added to petroleum products in small amounts to improve quality or add special characteristics.

Air fin coolers – a radiator-like device used to cool or condense hot hydrocarbons.

Dis

till

atio

nco

lum

n

Temp Deg F

<90

90-200

200-350

350-450

450-650

650-1,000

1000+

Product recovered

Butane & lighter

Light straight naptha

Naptha

Kerosene

Distillate

Heavy Gas Oil

Residuum

Product sent to

Gas processing

Gasoline blending

Catalytic reforming

Hydro-treating

Distillate fuel blending

Fluid catalytic cracking

Coking

Crude oil

165



Alicyclic hydrocarbons – ringed hydrocarbons in which the rings are made up onlyof carbon atoms.

Aliphatic hydrocarbons – hydrocarbons characterized by open-chain structures e.g. ethane, propane, butane.

Alkylation – a process using sulfuric acid or hydrofluoric acid as a catalyst to combine olefins (usually butylenes) and isobutene to produce a high-octane product known as alkylate.

API gravity – an arbitrary scale expressing the density of crude oil and petroleum products. A lower figure (gravity) indicates higher density, more viscous fluid and a higher gravity indicates a lower density (lighter, thinner) fluid. Over the last 20 years, the EIA estimates that the average API of US crude imports has fallen from 32.5degrees to 30.2 degrees.

Aromatic – organic compound with one or more benzene rings.

Asphaltenes – the asphalt compounds soluble in carbon disulfide but insoluble in paraffin napthas.

Atmospheric tower – a crude distillation unit operated at atmospheric pressure.

Barrel – the American standard unit of measurement for oil; one barrel is 35 imperial gallons or 159 litres.

Bitumen – an extremely heavy semi-solid product of oil refining made up of long chain (heavy) hydrocarbons. It is used for road-building and roofing.

Blending – the process of mixing two or more petroleum products with different properties to produce a finished product.

Bottoms – tower bottoms are residue remaining in a distillation unit after the highest boiling point material to be distilled has been removed. Tank bottoms are the heavy materials that accumulate in the bottom of storage tanks, usually comprised of oil and water.

BTX - industry term referring to the group of aromatic hydrocarbons benzene, toluene and xylene.

Catalyst - a substance which alters the rate of a chemical reaction without being used up itself in the reaction.

Caustic wash - a process in which distillate is treated with sodium hydroxide to remove acidic contaminants that contribute to poor odor or stability.

Coke – a high carbon content residue that remains following the destructive distillation of petroleum residue.

Coking – a process for thermally converting and upgrading heavy residual into lighter products and by-product petroleum coke. Coking also is the removal of all lighter distillable hydrocarbons that leaves a residue of carbon in the bottom of units

166



or as buildup or deposits on equipment and catalysts. The accumulated coke can be removed from the coking vessels during an off cycle and either sold, primarily as a fuel for electricity generation, or used in gasification units to provide power, steam, and/or hydrogen for the refinery.

Condenser reflux – condensate that is returned to the original unit to assist in giving increased conversion or recovery.

Cracking – the process of breaking down larger molecules of hydrocarbons into smaller ones. When this is done by heating the oil it is known as thermal cracking. If a catalyst is used, it is known as catalytic cracking.

Crude assay – a procedure for determining the general distillation and quality characteristics of crude oil.

Debottlenecking – a process that improves the flow and better matches capacity among different refining units by turning more and more to computer control of processing.

Dehydrogenation - A reaction in which hydrogen atoms are eliminated from a molecule. Dehydrogenation is used to convert ethane, propane, and butane into olefins (ethylene, propylene and butene).

Desulphurization – any process or process step that results in the removal of sulphur from organic molecules.

Distillates – the products obtained by condensation during the fractional distillation process.

Feedstock – stock from which material is taken to be fed (charged) into a processing unit.

Flashing - the process in which a heated oil under pressure is suddenly vaporized in a tower by reducing pressure.

Flash point – lowest temperature at which a petroleum product will give off sufficient vapor so that the vapor-air mixture above the surface of the liquid will propagate a flame away from the source of ignition.

Fluid catalytic cracking (FCC) – a process for converting high boiling gas oils to lighter liquids, primarily gasoline range naptha and diesel range gas oils.

Fraction – one of the portions of fractional distillation having a restricted boiling range.

Fractional distillation – a separation process which uses the difference in boiling points of liquids.

Fuel gas – refinery gas used for heating.

Fuel oil – a heavy residual oil used for power stations, industry and marine boilers.

167



Gas oil – a middle distillate petroleum fraction with a boiling range 350-370 deg F, usually includes diesel fuel, kerosene, heating oil and light fuel oil; used to produce diesel fuel and to burn in central heating systems.

Gross product worth (GPW) – this is the weighted average value of all refined product components (less an allowance for refinery fuel and loss) of a barrel of the marker crude. GPW is computed by multiplying the spot price of each product by its percentage share in the yield of the total barrel of crude.

Gross refining margin (GRM) - this is the net difference in value between the products produced by a refinery and the CIF value of the crude oil used to produce them, taking into account the marginal refinery operating costs. Refining margins will thus vary from refinery to refinery and depend on the cost and characteristics of the crude used, its yield and the value of its products (and hence its location).

For forecasting purposes the J.P. Morgan European Oil & Gas Team uses BP’s Refining Marker Margin (RMM) so that we have a long, continuous and comparable data series for regional GRMs. BP’s RMM uses regional crack spreads to calculate the margin indicator and does not include estimates of fuel costs and other variable costs. The RMM is calculated using the following marker crudes and product yields.

Table 37: Regional Refining Marker Margin definitions

Region Crude Refinery Gasoline GasoilUS Gulf Coast Mars Coking 66.7% 33.3%US West Coast ANS Coking 66.7% 33.3%US Midwest LLS Coking 66.7% 33.3%NW Europe Brent Cracking 50.0% 50.0%Mediteranean Azeri Light Cracking 50.0% 50.0%Singapore Dubai / Tapis Cracking 50.0% 50.0%

Source: BP

Heavy vacuum gas oil (HVGO) – an intermediate product produced in the vacuum distillation unit which is further processed to produce gas oil or gasoline.

Hydrocarbon – a compound containing hydrogen and carbon only. Hydrocarbons may exist as solids, liquids or gases.

Hydro-cracking - A process used to convert heavier feedstock into lower-boiling, higher-value products. The process employs high pressure, high temperature, a catalyst, and hydrogen.

Hydro-desulfurization - A catalytic process in which the principal purpose is to remove sulfur from petroleum fractions in the presence of hydrogen, which produces hydrogen sulphide that can be easily removed from the crude stream.

Hydro-finishing - A catalytic treating process carried out in the presence of hydrogen to improve the properties of low viscosity-index naphthenic and medium viscosity-index naphthenic oils. It is also applied to paraffin waxes and micro-crystalline waxes for the removal of undesirable components. This process consumes hydrogen and is used in lieu of acid treating.

Hydrogenation – the chemical addition of hydrogen to a material in the presence of a catalyst.

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Idle capacity – the component of operating capacity that is not in operation and not under active repair, but capable of being placed in operation within 30 days; plus capacity not in operation but under active repair that can be completed within 90 days.

Isomerization - A reaction that catalytically converts straight-chain hydrocarbon molecules into branched-chain molecules of substantially higher octane number. The reaction rearranges the carbon skeleton of a molecule without adding or removing anything from the original material.

Iso-octane – a hydrocarbon molecule (2,2,4-trimethylpentane) with excellent anti-knock characteristics on which the octane number of 100 is based.

Kerosene – a medium light oil use for lighting, heating and aviation fuel.

Light vacuum gas oil (LVGO) – the lightest fraction from the vacuum column that is blended in to the gas oil mix.

Liquefied petroleum gas (LPG) - commercial LPG usually contains mixtures of propane and butane.

Marine distillate – or residual fuel oil is used for marine applications. Additives help to stabilize fuel consumption in four stroke engines, reduce piston deposits, lower smoke emissions and reduce lube oil fouling.

Methane – the main component of natural gas; it is the smallest hydrocarbon molecule with only one carbon atom and four hydrogen atoms.

Methyl-t-butyl-ether (MTBE) – an oxygen-containing fuel component used in reformulated gasoline; commonly made from methanol and isobutene.

Naphtha – A general term used for low boiling hydrocarbon fractions that are a major component of gasoline. Aliphatic naphtha refers to those naphthas containing less than 0.1% benzene and with carbon numbers from C3 through C16. Aromatic naphthas have carbon numbers from C6 through C16 and contain significant quantities of aromatic hydrocarbons such as benzene (>0.1%), toluene, and xylene; used to produce petrol and as a raw material for the petrochemical industry to make plastics.

Nelson complexity index (NCI) – the NCI was developed by Wilbur L. Nelson in a series of articles in Oil & Gas Journal in 1960-61 to quantify the relative costs of the components that constitute the refinery. The Nelson complexity index assigns a complexity factor to each major piece of refinery equipment based on its complexity and cost in comparison to crude distillation, which is assigned a complexity factor of 1.0. For example – vacuum distillation 2.0, thermal processes 2.75, catalytic reforming 5.0, coking 6.0, aromatics / polymerization 10.0 and lubes 60.0.

The complexity of each piece of refinery equipment is then calculated by multiplying its complexity factor by its throughput ratio as a percentage of crude distillation capacity. Adding up the complexity values assigned to each piece of equipment, including crude distillation, determines a refinery’s complexity on the Nelson Complexity Index. The Nelson complexity index indicates not only the investment

http://en.wikipedia.org/wiki/Throughput_(business)

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intensity or cost index of the refinery but also its potential value addition. Thus, the higher the index number, the greater the cost of the refinery and the higher the value of its products. The NCI method uses only the Refinery Processing Units or the"Inside Battery Limits " ( ISBL ) Units, and does not account for the costs of Offsitesand Utilities or the " Outside Battery Limits " ( OSBL ) Costs, such as Land, Storage tanks, terminals, utilities required etc. A high NCI means that a refinery can (i) process inferior quality crude or heavy sour crudes (ii) produce a superior product slate comprising a high percentage of LPG, light distillates and middle distillates and a low percentage of heavies and fuel oil.

Net refining margin – this is the gross product worth (calculated by multiplying the spot price of each product by its percentage share in the yield of he total barrel of crude) Less variable refinery operating costs; defined to include the feed-dependent costs for power, water, chemicals, additives, catalyst and refinery fuels beyond own production Less fixed refinery operating costs; defined to include labor, maintenance, taxes and overhead costs adjusted monthly to take account of escalations based on industry cost indices Less refinery delivered crude cost; defined to include transport and credit allowance costs Transport costs; marginal crude freight, insurance and ocean loss (in case of an FOB crude), and applicable fees and duties, assuming a single voyage for an appropriately sized tanker chartered on the spot market LessCredit allowance; representing the financial effect of the time delay between paying for crude versus when it is received in the refinery (crude credit, crude transit time).

Paraffins – a family of saturated aliphatic hydrocarbons (alkanes) with the general formula CnH2n+2

Polyforming - the thermal conversion of naphtha and gas oils into high-quality gasoline at high temperatures and pressure in the presence of re-circulated hydrocarbon gases.

Polymerization – the process of combining two or more unsaturated organic molecules to form a single (heavier) molecule with the same elements in the same proportions as in the original molecule.

Quench oil - oil injected into a product leaving a cracking or reforming heater to lower the temperature and stop the cracking process.

Raffinate - the product resulting from a solvent extraction process and consisting mainly of those components that are least soluble in the solvents. The product recovered from an extraction process is relatively free of aromatics, naphthenes, and other constituents that adversely affect physical parameters.

Recycle gas – high hydrogen content gas returned to a unit for reprocessing.

Refinery – a plant where the components of crude oil are separated and converted into useful products.

Refinery processing gain - the volumetric amount by which total refinery output is greater than input for a given period of time. This difference is due to the processing of crude oil into products, which, in total, have a lower specific gravity than the crude oil and feed stocks processed (e.g. in conversion processes).

http://en.wikipedia.org/wiki/Value_added

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Refinery product yields - these are used for refinery margin calculations and, as per Table 38, vary with crude feedstock and refinery configuration.

Table 38: Refined product yields

Refinery product yield (%, bbl)

Region Input crude Refinery typePetroleum

gasesGasoline /

naptha Distillate Fuel oilEurope Brent Catalytic cracking 3.3 35.6 42.3 14.0

Hydroskimming 3.0 22.7 42.8 29.9Urals Catalytic cracking 2.9 28.9 39.4 23.6

Hydroskimming 1.6 13.4 37.1 46.9US Gulf Coast LLS Catalytic cracking 4.6 42.1 42.9 10.7

Mars Blend Coking 7.9 46.1 41.6 1.6US West Coast ANS Catalytic cracking 2.8 43.0 25.4 30.7Singapore Dubai Hydroskimming 2.6 14.6 39.8 41.7

Hydrocracking 5.8 24.7 50 22.3Tapis Hydroskimming 3.7 30.6 43.7 19.5

Hydrocracking 8.1 36.4 52.9 3.5


Reflux - portion of the distillate returned to the fractionating column to assist in attaining better separation into desired fractions.

Reformate - an upgraded naphtha resulting from catalytic or thermal reforming.

Regeneration - in a catalytic process the reactivation of the catalyst, sometimes done by burning off the coke deposits under carefully controlled conditions of temperature and oxygen content of the regeneration gas stream.

Resid - an abbreviation for residuum; the general term given to any refinery fraction that is left behind in a distillation. Atmospheric resid, sometimes called long resid or atmospheric tower bottoms (ATB) is the undistilled fraction in an atmospheric pressure of crude oil. Vacuum resid, short resid, or vacuum tower bottoms (VTB), is the undistilled fraction in a vacuum distillation.

Scrubbing – purification of a gas or liquid by washing it in a tower.

Sour gas – natural gas that contains corrosive, sulfur-bearing compounds such as hydrogen sulfide and mercaptans.

Stabilization – a process for separating the gaseous and more volatile liquid hydrocarbons from crude petroleum or gasoline and leaving a stable (less-volatile) liquid so that it can be handled or stored with less change in composition.

Straight-run gasoline - Gasoline produced by the primary distillation of crude oil(as opposed to conversion). It contains no cracked, polymerized, alkylated, reformed, or vis-broken feedstock.

Stripping – the removal (by steam-induced vaporization or flash evaporation) of the more volatile components from a cut or fraction.

Sweetening - processes that either remove obnoxious sulfur compounds (primarily hydrogen sulfide, mercaptans, and thiophens) from petroleum fractions or streams, or convert them, as in the case of mercaptans, to odorless disulfides to improve odor, color, and oxidation stability.

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Switch loading - the loading of a high static-charge retaining hydrocarbon (i.e. diesel fuel) into a tank truck, tank car, or other vessel that has previously contained a low-flash hydrocarbon (gasoline) and may contain a flammable mixture of vapor and air.

TAN – total acid number is the standard measure for crude corrosiveness; it indicates the number of milligrams of potassium hydroxide needed to neutralize the acid in 1 gram of oil. The most corrosive crudes, with TANs greater than 1, require significant accommodation to be processed.

Tail gas – the lightest hydrocarbon gas released from a refining process.

Thermal cracking - the breaking up of heavy oil molecules into lighter fractions by the use of high temperature without the aid of catalysts.

Turnaround – a planned complete shutdown of an entire process or section of a refinery, or of an entire refinery to perform major maintenance, overhaul, and repair operations and to inspect, test, and replace process materials and equipment. For example, US demand for product is lower in the colder months and higher in the warmer months. As refineries move out of the gasoline (driving) season in early autumn, refiners routinely perform maintenance. The depth of maintenance is influenced by the margin environment and outlook e.g. if product inventories are high and demand is slack, maintenance activities are likely to be longer and deeper.

Upgrading oil – extra heavy oils, like those from the Orinoco region (Venezuela) and the Alberta tar sands (Canada), are typically upgraded to produce high quality synthetic crude (syncrude) which is then refined.

Utilization – represents the utilization rate of the atmospheric crude oil distillation units. The rate is calculated by dividing the gross input to these units by the operating capacity of the units.

Vacuum distillation – The distillation of petroleum under vacuum which reduces the boiling temperature sufficiently to prevent cracking or decomposition of the feedstock.

Vis-breaking – Viscosity breaking is a low-temperature cracking process used to reduce viscosity or pour point of straight-run residuum.

Wet gas - a gas containing a relatively high proportion of hydrocarbons that are recoverable as liquid.

WTI – West Texas Intermediate crude is a light (low density, high API), sweet (low sulfur, <0.5% content by weight) crude that is produced in the USA. This combination of characteristics makes it an ideal crude oil to be refined since it yields a greater proportion of its volumes as lighter products. Premium (heavier) crudes yield c.70% (c.50%) of their volume as light products.

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Retailing

The modern forecourt today may have multi-pump dispensers, a car wash and a convenience store. A modern high volume throughput filling station may sell more than 5 million liters per year and cost $3-4m to build (subject to location and real estate value). About 60% of this capital is equipment that is not seen but which is essential to the safe and more environmentally friendly operation of a modern site. Underground storage tanks and fuel lines are either made from steel set in concrete or special plastic. Tanks are usually double skinned and both tanks and connecting pipes have detectors which warn of the slightest leak before it becomes a problem. Storage tanks also have vapor recovery systems which recover vapors emitted from the tank when it is being filled with petrol from a road tanker. Often called "Stage 1" recovery, this system is being extended as "Stage 2" to capturing vapors when a vehicle is filled. Also underground out of sight is the drainage interceptor system. This collects water off the forecourt which may contain fuel or oil and stops it getting into surface drains and watercourses.

The ownership and branding of retail forecourt sites is complex, but broadly falls into three areas:

Dealer-owned, Dealer-Operated (DODO) - The forecourt is owned by an independent business, acting as a distributor for an oil company, which supplies fuel and usually a branding package.

Company-Owned, Dealer-Operated (CODO) - The forecourt is owned by an oil company which also supplies the fuel, but the site and store are operated by an independent business.

Company-Owned Company-Operated (COCO) – The forecourt is owned by an oil company and operated by its employees according to instructions from Head Office, as with any other multiple retail business.

Company-Owned Group-Operated (COGOP) - This is a similar model to CODO, with the key difference being that a group of stores are run by another independent company rather than an independent dealer.

We follow with a brief glossary of terms for fuels retailing.

Advanced performance fuels - these are high octane and high cetane formulations that are designed to burn more efficiently; some also help to clean the engine.Chemical additives are typically ‘splash-blended’ at the terminal.

Biodiesel - a biodegradable transportation fuel for use in diesel engines that is produced through trans-esterification of organically derived oils or fats. Biodiesel is used as a component of diesel fuel. In the future it may be used as a replacement for diesel.

Convenience stores – these sell a range of non-petroleum products that include alcohol, baked goods, chilled food, confectionary, fast food, frozen food, fruit & vegetables, health & beauty products, household goods, lottery tickets, milk, newspapers & magazines, packaged groceries, snacks, soft drinks and tobacco.

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Diesel - a light oil fuel used in diesel engines. Clean diesel is an evolving definition of diesel fuel with lower emission specifications which strictly limit sulfur content to 0.05% weight.

Fuel additives – for both diesel and gasoline, these help fuel economy, engine cleanliness, friction, emissions, power restoration and compatibility with biodiesel blends.E10 (Gasohol): Ethanol/gasoline mixture containing 10% denatured ethanol and 90% gasoline, by volume.

E85: Ethanol/gasoline mixture containing 85% denatured ethanol and 15% gasoline, by volume.

Gasoline – an alternative term for petrol. A blend of napthas and other refinery products with sufficiently high octane and other desirable characteristics to be suitable for use as fuel in internal combustion engines.

Octane rating – a measure of the performance (antiknock characteristics) of gasoline; a high octane rating gives efficient ignition.

Lubricants

Synthetic base stocks – synthetic motor oils are made from the following classes of lubricants: polyalphaolefins (PAO), synthetic esters and hydro-cracked lubricants. Chevron, Shell, and other petrochemical companies developed a catalytic conversion of feedstocks under pressure in the presence of hydrogen to produce high-quality mineral lubricating oil. In 2005, production of GTL (gas-to-liquid) Group III base stocks began, the best of which perform much like polyalphaolefin.

Synthetic lubricants – these are a combination of synthetic base oil plus thickeners and additives that will give the grease or oil lubricant a number of performance advantages over conventional mineral based lubricants. Such advantages include their ability to perform under extreme conditions e.g. low and high temperatures and chemical resistance.

Semi-synthetic oils - also called 'synthetic blends' are blends of mineral oil with no more than 30% synthetic oil. They are designed to have many of the benefits of synthetic oil without matching the cost of pure synthetic oil.

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Appendix VI: Valuation Methodology and Risks

BP (Overweight Price Target: 575p)

Valuation Methodology :

Our 575p Dec-11 price target for BP captures (i) the reinstatement of BP's dividend with its Q4 2010 results (ii) a positive resolution to the risk of gross negligence versus negligence, as per our Central Case Macondo Liability analysis (iii) further progress towards its $25bn - $30bn divestment target (iv) further evidence that BP's abilities to access new high potential exploration acreage (as per BP's alliance with RIL in the Krishna Godavari Basin, off the East Coast of India) is intact. Our price target still assumes a discount of around 30% to our sum-of-the-parts value of around 800 pence that is consistent with our Central Case and compares to BP's long run average discount of 26%.

Risks to Our View :

Macro factors – As an integrated oil & gas company, BP’s earnings and cash flow are naturally sensitive to oil and natural gas prices and refining margins. BP does not hedge any of these top line macro exposures.US dollar – BP is US dollar long and has a US dollar-based dividend policy. Dollar

weakness could erode BP’s sterling dividend which is important given the dividend yield sensitivity of the UK market.Asset integrity / project execution – Unexpected asset integrity issues eg field or

refinery downtime, delays to projects and capital budget over-runs can damage perceptions of management quality and, ergo, BP’s stock market valuation.Industrial accidents – Unexpected industrial accidents involving BP assets could

expose the company to loss of earnings, asset confiscation and potential litigation risk.Russian risk – Via its 50% stake in TNK-BP, BP carries a significant production,

reserve, cash flow and earnings exposure to assets in Russia. The perceived value of this asset is vulnerable to an escalation in Russian country risk and any signs of company-specific corporate governance problems.Gross Negligence - There is risk that BP will be found grossly negligent and thus face much higher overall Macondo related liabilities than our Central Case.Divestment program fails - Although it is a seller's market for upstream assets, there is a risk that this changes and BP fails to complete its $25bn to $30bn divestment program.

Royal Dutch Shell B (Neutral Price Target: 2,400p)


We leave our SOTP at 2,650p: we apply our long-term oil price of $85/bbl (US natural gas price of $5.90/mmbtu) and RD Shell’s 2010 Form 20-F disclosures relating to upstream reserves, downstream assets and off balance sheet liabilities. We still believe that a 10% discount to our SOTP is appropriate and therefore keep our price target at 2,400p.

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Risks to Our View :

Macro factors – As an integrated oil & gas company which does not hedge prices or margins, RD Shell’s earnings and cash flow are naturally sensitive to oil and natural gas prices and refining margins.

Industrial accidents – Unexpected industrial accidents involving RD Shell assets could expose the company to loss of earnings, asset confiscation and potential litigation risk.

Fiscal regimes – Unexpected or adverse changes to the upstream fiscal regimes that apply to any of RD Shell’s key operating areas could reduce its value.

Acquisition risk - RD Shell's balance sheet is strengthening fast as larger than expected divestments and a higher than expected oil price raise cash flow. A large acquisition could dilute returns and perceptions of capital controls.LNG pricing risk – As one of the largest IOC producers of LNG, a prolonged period of LNG market over-capacity could dilute the returns from RD Shell’s LNG projects. This damage could prove more permanent if LNG's pricing relationship with the oil price is weakened.

ENI (Overweight Price Target: €22.50)


Our end Dec 2011 price target of €22.5 is derived from our SOTP valuation. Our price target for the stock is set at a 24% discount to our SOTP– very close to average long term discount on this name. We expect this discount to narrow as ENI's asset structure becomes simpler.

Risks to Our View :

The main generic risks to our rating and price target come from crude oil or natural gas prices or refining margins significantly below/above our projections. Specifically for ENI, downside risks include a further decline in the natural gas demand in Italywhich is likely to put pressure on the operating margin of the company.

Essar Energy (Overweight Price Target: 570p)


We maintain our price target for Essar Energy at £5.70 - a premium to our SOTP for the stock. Whilst we acknowledge that majority of the integrated names under our coverage trade at a discount vs SOTP, we believe that strong growth profile of Essar Energy will help it trade at a premium to our SOTP.

Risks to Our View :

Execution risk - Bringing in large capital projects on time and on budget is crucial in the creation and/or preservation of shareholder value. The scale of the task is amplified by the fact that company is executing ambitious growth projects in both power and refining business. We acknowledge that the presence of EPC contracting capability within the Essar Group is a plus for the company’s expansion plans and would help the company in partially mitigating this key risk.

Sustained weakness in GRMs – we believe that a sustained weakness in GRMs could exert pressure on the company’s near term cash flows. We also see a negative

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read across for the timing of phase II expansion, if the weakness in GRMs continues through 2011.

Fuel supply - We believe that the security of the fuel supply is very important for the company's expansion plans in the power sector. We highlight that the pit head coal reserves are a key contributor to the value of some of the major phase 1 projects (like Mahan). Mahan - We also highlight the expiry of the coal block allocation contract as a risk to our valuation for this key project.

Project clearances – Whilst we acknowledge that majority of the Phase II expansion projects are brownfield and company has secured land, water and fuel, we also note that on a number of these projects are yet to secure the environmental clearance/PPA agreements - a potential risk, in our view, to the development timeline for these projects.

Sales tax deferral under litigation - Essar Oil has received a favorable verdict from the Gujarat High Court but the government of Gujarat has appealed against the verdict in the Supreme Court. Sales tax deferral benefit contributes c. $507mn (c,3% of GAV) to our SOTP for the company.

Galp Energia (Overweight Price Target: €20.00)


Our end Dec 2011 revised price target of €20 is derived from our SOTP valuation. Our price target for the stock is set at a discount of just 9% to our SOTP – we expect the discount vs SOTP to narrow (from c.18%) given the likely near term upside from the company's capital increase in Brazil. We also believe that the differentiated growth profile of Galp will also be a plus for the re-rating of the stock.

Risks to Our View :

The main generic risks to our rating and price target come from crude oil or natural gas prices or refining margins significantly below our projections. For Galp specifically, downside risks include possible disappointments in the deepwater Brazil exploration programme, and the timely delivery of the Tupi project. Other risks come from further weakness in downstream.

Indian Oil Corporation (Neutral, Price Target: Rs420)

Our Mar-12 price target of Rs420 is based on 6x EV/EBITDA. Our earnings are based on a benign subsidy sharing mechanism (<10% share for the downstream SOEs). We value IOC at a discount to regional peers due to continuing uncertainty on the level of subsidies to be borne by the SOE R&M companies.

Key upside risks to our call are structural reforms on fuel pricing and sustained low crude prices. Downside risks are a global slowdown leading to lower refining margins and a higher share of retail fuel losses.

OMV (Neutral Price Target: €29.00)


Our end Dec 2011 price target of €29 is derived from our SOTP valuation - no change to our key assumptions or our SOTP valuation. Our price target for the stock is set at a 28% discount to our SOTP of c.€40 - very close to the 12 month average

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discount to the share price. OMV's higher than average sector discount is justified by the concentration of its asset risk in Romania with associated exposure to regulated gas prices in the country and the challenges that OMV faces turning around its upstream performance.

Risks to Our View :

The main generic risks come from crude oil or natural gas prices or refining margins significantly below our projections. Upside risks include faster-than-expected increases in Romanian gas prices and faster delivery of restructuring benefits from the Petrom acquisition. Downside risks could come from the acquisition of additional stake in Petrol Ofisi, downgrades to production targets, further delays in the Petrom refinery upgrades or failure of the Romanian government to raise gas prices at the rate we had expected.

Petrobras (Neutral)

We rate the four Petrobras stocks that we cover Neutral. Our end-2012 price target for PBR is $41/ADR. Our R$35/sh YE12 price target for PETR3 is based on the PBR target using a year-end 2012 BRL exchange rate of R$1.7/USD. Our YE12 price target of $37/ADR for PBR/A applies a 10% discount to our price target for PBR. Our R$31/sh YE12 price target for PETR4 applies JPM’s year-end 2012 BRL exchange rate of R$1.7/USD to our target price for PBR/A. We value E&P portfolio of PBR using a reserve depletion model and value each of the pre-salt projects independently. We also value the downstream projects under a DCF approach that is applied for all refining system of PBR.

Risks to Rating and Price Target

Downside risks:

Sensitivity to oil prices: PBR generates incremental EBITDA of $500 million and incremental earnings of $300 million for every $1/bbl rise in reference oil prices. Should oil prices retreat or fail to meet our 2011 assumption of $106/bbl (Brent), share prices would likely decline.

Returns over new investments could be lower than estimated. The company has a capital expenditures plan for 2011-15 of $224 billion. While we believe the investments devoted to E&P projects are strategic and therefore unlikely to be modified, investments in segments such as in refining could have returns lower than the company’s weighted average cost of capital.

Upside risks:

Addition of new production licenses in large reservoirs such as Libra.

Faster production growth than assumed.

Faster upturn in oil prices than assumed.

Demonstrating better economics in pre-salt fields already in portfolio. A $1/boe increase in the NPV per barrel of pre-salt assets would boost PBR’s NAV by $2.4/ADR.

Demonstrating larger scale of pre-salt fields already in portfolio. An increase of 1 bn boe in pre-salt resource base would boost PBR’s NAV by $0.7/ADR.

Potential savings in execution of refinery budgets.

Potential sizable discoveries in existing licenses.

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PetroChina (Underweight, Price Target: HK$9.00)

Valuation Methodology:

Our Dec-11 PT of HK$9.00 is based on 20% premium to DCF value for PetroChina. DCF is based on using LT oil price of US$85/bbl and 10.4% WACC. We apply a 20% premium to this DCF value due to current oil prices being substantially higher than our LT forecasts, reflecting markets focus on earnings and earnings multiples rather than long term intrinsic value.

Risks to Our View:

Main risks to our UW is higher oil and gas prices coupled with NDRC raising product prices. Operationally, stronger than expected production upstream and less losses from natural gas imports will also be positive for PetroChina.

Repsol YPF (Neutral Price Target: €25.00)


Our end Dec 2011 price target of €25 is derived from our SOTP valuation. Our price target is set at a c.12% discount to our SOTP, this is lower than the long-term average discount for Repsol YPF. We believe that near-term catalysts like YPF divestment, exploration results from Brazil, West Africa etc will help the stock's performance.

Risks to Our View :

The main generic risks to our rating and price target come from crude oil or natural gas prices or refining margins significantly below our projections. Specifically for Repsol, downside risks include a further weakness in the refining margins and possible disappointments in the company's ongoing exploration campaign - offshore Brazil, GoM and Venezuela.

Reliance Industries (Overweight, Price Target Rs1200)

Our Mar-12 price target of Rs1200 is SOTP-based, and values the refining business at 8x EVBITDA, the petchem business and PMT E&P business at 7.5x EV/EBITDA, and an NPV valuation of the E&P business (multiples in line with peer group). We use the SOTP to fully capture the value on RIL's balance sheet.

Key risks to our view include a global slowdown impacting the cyclical refining and petchem businesses, along with harsh regulatory action on the E&P business.

Sinopec Corp - H (Overweight, Price Target HK$9.40)

Valuation Methodology:

Our Dec-11 PT of HK$9.40 is based on 5x 2011E EV/EBITDA (same as PetroChina at our PT of HK$9.00). We use LT oil price of US$85/bbl and 10.4% WACC.

Risks to Our View:

Main risks to our OW is higher than expected oil prices and NDRC not following up with product prices.

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Statoil (Underweight Price Target: Nkr145.00)


Our end Dec 2011 price target of Nkr145 is derived from our SOTP valuation - no change to our key assumptions or our SOTP valuation. Our price target for the stock is set at a c.24% discount to our SOTP of NKr190 – this is in-line with the 12 month average discount suffered by the stock. We still believe that a discount will prevail until Statoil shows a clearer, sustainable improvement in its upstream performance.

Risks to Our View :

The main generic risks come from crude oil or natural gas prices or refining margins significantly below our projections. For Statoil specifically, negative risks include any slippage to production targets resulting from higher core decline rates in Norwegian production or if lower crude prices prevent Statoil from sanctioning new projects. Positive risks include further success in the international portfolio, notably in the deepwater US Gulf and offshore Brazil. Changes in crude prices affect Statoil’s shares more than its peers given its greater upstream leverage.

TOTAL (Neutral Price Target: €47.00)


Our end Dec 2011 price target is €47- no change to our key assumptions or our SOTP valuation. Our price target for the stock is set at a 14% discount to our SOTP –slightly below the 12 month average discount suffered by this name.

Risks to Our View :

The following risks could prevent the stock from achieving our price target and rating. The main generic risks come from crude oil or natural gas prices or refining margins significantly below our projections. For Total specifically, negative risks could come from project slippage relative to the last guidance, but positive risks could come from better-than expected volume growth in 10-11.

Sasol (Overweight Price Target: 39,800c)


We derive our 12-month target price from the average of our DCF valuation (R382)and our 2012E HEPS of R 37.7 at Sasol’s average historical trailing P/E multiple of 11x (R415). This gives us an average value of R398.

Risks to Our View :

We believe the key risks that could keep our target price from being achieved include the following:

BEE covenants

Sasol has share price covenants attached to debt provided by third party banks to support its BEE deal. If its share price falls below R 211 it has to assume R 4.5bn in debt from the banks and if it falls below R 191 a further 2.5bn has to be absorbed. The share price has to remain below the trigger points for 10 days VWAP.

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Weaker long-term oil price

Our recommendation hinges on the basic assumption of a higher than previously witnessed long-term oil price. If investors do not believe in relatively high long-term oil prices (USD 80-110), we recommend they avoid investing in Sasol.

Macro factors

Sasol is very exposed to macro factors, particularly the oil price and Rand/USD. Sasol estimates that for 2011, a USD1 per barrel movement in the oil price would have a ~R615m impact on its EBIT. The company estimates that for 2011, a 10c weakening or strengthening in the Rand/USD would impact Sasol’s EBIT by ~R632m.

Engineering competency and geography

Our recommendation depends on Sasol continuing to operate its Oryx GTL and Iranian Chemicals expansion without further issues (note both these plants have had significant problems). In addition, Sasol is exposed to projects in areas of relatively high political risk e.g. Iran, Nigeria, and China, which creates relatively high specific risk in Sasol.

Management capacity

We are assuming that Sasol can negotiate contracts and bring onstream a significant number of major GTL projects over the next 10 years. Given the relatively limited number of experienced engineers in this area, we see a significant risk that our expectations overestimate the capacity and availability of Sasol’s pool of qualified individuals.

Environmental factors

Sasol’s key CTL technology produces significant amounts of CO2 and we believe Secunda to be one of the world’s largest single-point CO2 emitters. Given global concerns over CO2 emissions, Sasol will likely have to satisfy increasingly stringent environmental rules, which will likely place additional costs and technical burdens on the company. CO2 legislation could also lead to taxes and or charges for CO2 emissions. Sasol also has exposure to shale gas which also has potential environmental issues associated with it.

Competition

We are relying on Sasol being able to deliver equity stakes in major GTL projects going forward. Whilst we believe Sasol is the global leader in GTL technology, competition is increasing and resource owners may decide to partner with others or progress projects on their own.

181



BP: Summary of FinancialsProfit and Loss Statement Valuation, performance and production

$ in millions, year end Dec FY09 FY10 FY11E FY12E $ in millions, year end Dec FY09 FY10 FY11E FY12E

E&P 21,616 27,389 31,354 30,103 - Brent crude, $/bbl 62.67 80.34 110.00 95.00 -

R&M 3,607 4,868 5,633 5,839 - US Gas, $/MMBtu 4.16 4.38 4.33 5.40 -

Other & Corporate -2,550 -869 -1,050 -1,050 -

Total Segmental EBIT 22,673 31,388 35,937 34,892 - Valuation

Mkt Cap ($ bn)

Finance Costs (1,302) (1,025) (975) (875) - P/E adjusted 9.2 6.5 6.4 6.6 -

Pre-Tax Income 21,371 30,363 34,962 34,017 - P/CF 2.9 6.0 2.6 2.7 -

Less: Tax (6,613) (9,613) (11,637) (11,366) - P/FCF -26753.6% 1251.6% 2991.2% -75424.3% -

Tax Rate 30.9% 31.7% 33.3% 33.4% - EV/DACF 547.8% 1059.3% 461.8% 484.6% -

Minorities 181 399 546 495 - CF Yield 0.4% 0.2% 0.4% 0.4% -

FCF Yield 7.6% 7.2% 5.9% 4.0% -

Adjusted Net Income 14,577 20,352 22,778 22,155 - FCF yield ex-w/c 1.4% 3.4% 4.4% 1.4% -

Growth (44.5%) 39.6% 11.9% (2.7%) - Dividend Yield 7.7% 1.0% 3.9% 4.2% -

Avg. shares in issue (m) 18,732.46 18,791.23 19,825.52 19,898.02 - Buyback Yield 0.0% 0.0% 0.0% 0.0% -

Combined Yield 7.7% 1.0% 3.9% 4.2% -

Adjusted EPS (cents) 0.78 1.09 1.15 1.11 -

EPS growth(%) NM 39.5% 5.8% NM - Ratios

Adjusted EPS (pence) 49.7 70.3 71.5 69.3 - Net debt to equity 25.7% 20.7% 13.7% 12.2% -

EPS growth(%) -34.1% 41.5% 1.8% -3.1% - Net Debt to Capital Employed 20.5% 17.2% 12.1% 10.9% -

DPS (cents) 56.0 7.0 28.5 30.5 - ROE 14.3% 21.8% 20.5% 17.4% -

DPS growth(%) 0.9% (87.5%) 307.1% 7.0% - ROCE 11.9% 16.9% 19.0% 16.4% -

DPS (pence) 35.3 4.5 17.7 19.0 -

DPS growth(%) 8.9% (87.3%) 295.5% 7.0% - Production

Group oil, kbopd 2,535 2,374 2,133 2,111 -

Group gas, mmcfpd 8,485 8,401 8,011 8,382 -

Group Total, kboepd 3,950 3,774 3,468 3,508 -

Y/Y growth 4.2% -4.4% -8.1% 1.2% -

Balance sheet Cash flow statement

$ in millions, year end Dec FY09 FY10 FY11E FY12E $ in millions, year end Dec FY09 FY10 FY11E FY12E

Cash and cash equivalent 8,339 14,354 17,393 17,272 - Consolidated Net Income 14,577 20,352 22,778 22,155 -

Other current assets 7,178 73,654 73,597 76,226 - DD&A 12,699 11,539 11,924 12,482 -

Current assets 67,653 88,008 90,989 93,498 - Cash tax payable (6,324) (6,610) (9,613) (11,637) -

Tangible fixed assets 108,275 107,516 120,582 134,253 - Other items 9,285 -5,443 13,521 17,124 -

Other non current assets 10,046 65,915 75,703 77,794 - Cash Earnings 30,237 19,838 38,611 40,124 -

Total non current assets 168,315 173,431 196,285 212,047 - Change in working capital (2,294) 2,182 (3,000) (2,000) -

Total assets 235,968 261,439 287,274 305,545 - Cash flow from Operations 32,531 17,656 41,611 42,124 -

Short term debt 9,109 14,022 14,022 14,022 -

Other current liabilities 15,007 70,041 70,109 71,479 - Capex (20,073) (18,421) (18,153) (19,653) -

Total current liabilities 59,320 84,063 84,131 85,501 - Other investing cash flow 2,681 17,455 -6,837 -6,500 -

Cash Flow from Investing -17,392 -966 -24,990 -26,153 -

Long term debt 25,518 25,957 25,957 25,957 -

Other non current liabilities 49,017 57,269 57,478 57,691 - Share Buybacks 0 0 0 0 -

Total non current liabilities 74,535 83,226 83,435 83,648 - Dividends (s/h & minorities) (10,483) (2,627) (5,478) (5,963) -

Total liabilities 133,855 167,289 167,566 169,149 - Other cash flow from financing 9,742 (367) 4,952 5,437 -

Shareholders' equity 101,113 93,138 118,150 134,342 - Cash flow from Financing -741 -2,994 -526 -526 -

Minorities 500 1,012 1,558 2,054 - Change in Net debt 1,120 -6,883 -3,039 121 -

Total Equity 101,613 94,150 119,709 136,396 -

Total Liabilities and Shareholders Equity 235,968 261,440 287,275 305,545 - Debt adjusted cash flow 29,210 14,323 34,947 33,436 -

Free cash flow (321) 6,883 3,039 (121) -

Net debt/ (cash) 26,161 19,278 16,239 16,360 - FCF ex-W/Capital Changes 1,973 4,701 6,039 1,879 -

Capital Employed 127,774 112,416 134,390 150,703 - CFPS 1.6 1.1 1.9 2.0 -

Source: Company reports and J.P. Morgan estimates.

182



Royal Dutch Shell B: Summary of FinancialsProfit and Loss Statement Valuation, performance and production

$ in millions, year end Dec FY09 FY10 FY11E FY12E FY13E $ in millions, year end Dec FY09 FY10 FY11E FY12E FY13E

Exploration & Production 18,333 33,230 54,030 49,392 48,159 Brent crude, $/bbl 62.67 80.34 110.00 95.00 90.00

Gas & Power 2,423 4,060 4,877 5,495 6,021 US Gas, $/MMBtu 4.16 4.38 4.33 5.40 5.90

Oil Products 2,291 2,969 4,420 5,823 6,578

Chemicals 410 1,983 2,067 2,734 2,377 Valuation

OIS & Corporate 408 -719 -649 -643 -636 Mkt Cap ($ bn)

Total Segmental EBIT 23,865 41,523 64,745 62,801 62,499 P/E adjusted 17.0 10.9 7.6 6.9 6.7

P/CF 0.7 0.5 0.3 0.3 0.3

Finance Costs 1,664 (140) (406) (123) 407 P/FCF -252.5% 371.4% 172.9% 182.0% 147.6%

Pre-Tax Income 25,529 41,383 64,338 62,678 62,906 EV/DACF 1186.9% 915.6% 604.3% 531.3% 496.4%

Less: Tax (12,194) (23,117) (37,136) (32,551) (31,817) CF Yield 0.1% 0.2% 0.3% 0.3% 0.3%

Tax Rate 47.8% 55.9% 57.7% 51.9% 50.6% FCF Yield 2.3% 6.1% 8.1% 8.0% 8.9%

Minorities 118 333 502 476 497 FCF yield ex-w/c -1.4% 4.4% 7.2% 7.4% 8.4%

Dividend Yield 4.7% 4.7% 4.6% 4.7% 4.9%

Adjusted Net Income 11,553 18,073 27,107 29,773 30,186 Buyback Yield 0.0% 0.0% 0.0% 0.0% 0.0%

Growth (59.3%) 56.4% 50.0% 9.8% 1.4% Combined Yield 4.7% 4.7% 4.6% 4.7% 4.9%

Avg. shares in issue (m) 6,128.90 6,139.28 6,312.83 6,362.83 6,412.83

Ratios

Adjusted EPS (cents) 1.89 2.94 4.23 4.66 4.77 Net debt to equity 18.6% 20.9% 13.8% 8.0% 2.5%

EPS growth(%) NM 56.2% 43.7% 10.2% 2.4% Net Debt to Capital Employed 15.7% 17.3% 12.1% 7.4% 2.4%

Adjusted EPS (pence) 120.3 190.4 263.4 290.2 297.1 ROE 8.5% 12.2% 16.5% 16.2% 14.9%

EPS growth(%) -50.0% 58.3% 38.3% 10.2% 2.4% ROCE 7.3% 10.7% 14.7% 15.4% 15.0%

DPS (cents) 168.0 168.0 174.7 181.7 181.7

DPS growth(%) 5.0% 0.0% 0.0% 3.0% 0.0% Production

DPS (pence) 106.3 106.8 104.6 107.8 111.0 Group oil, kbopd 1,680 1,709 1,706 1,681 1,720

DPS growth(%) 14.5% 0.5% (2.0%) 3.0% 3.0% Group gas, mmcfpd 8,483 9,305 9,837 10,857 11,105

Group Total, kboepd 3,094 3,259 3,345 3,490 3,571

Y/Y growth -3.3% 5.4% 2.6% 4.3% 2.3%


$ in millions, year end Dec FY09 FY10 FY11E FY12E FY13E $ in millions, year end Dec FY09 FY10 FY11E FY12E FY13E

Cash and cash equivalent 9,719 13,444 21,673 29,551 39,344 Consolidated Net Income 11,553 18,073 27,107 29,773 30,186

Other current assets 86,738 99,450 99,450 99,450 99,450 DD&A 14,458 15,595 17,523 16,182 15,717

Total current assets 96,457 112,894 121,123 129,001 138,794 Cash tax payable (9,243) (15,362) (17,523) (16,182) (15,717)

Tangible fixed assets 131,619 142,705 146,854 157,683 168,478 Other items 2,389 3,115 7,480 8,757 9,855

Other non current assets 64,105 66,961 65,152 63,870 62,601 Cash Earnings 19,157 21,421 34,587 38,531 40,041

Total non current assets 195,724 209,666 212,006 221,553 231,078 Change in working capital (2,331) (5,929) (7,732) (8,586) (8,859)

Total assets 292,181 322,560 333,129 350,555 369,872 Cash flow from operations 21,488 27,350 42,319 47,117 48,900

Short term debt (4,171) (9,951) (9,951) (9,951) (9,951)

Other current liabilities 88,960 110,503 103,602 101,500 101,178 Capex (27,838) (25,399) (28,214) (28,214) (27,714)

Total current liabilities 84,789 100,552 93,651 91,549 91,227 Other investing cash flow 1,604 3,427 5,000 175 175

Cash Flow from Investing Acitivites -26,234 -21,972 -23,214 -28,039 -27,539

Long term debt (30,862) (34,381) (34,381) (34,381) (34,381)

Other non current liabilities 104,290 116,560 116,864 116,864 116,864 Share Buybacks 0 0 0 0 0

Total non current liabilities 69,257 72,228 72,532 72,532 72,532 Dividends (s/h & minorities) (10,526) (9,584) (10,442) (10,722) (11,043)

Total liabilities 154,046 172,780 166,183 164,081 163,759 Other cash flow from financing 9,803 7,931 (435) (478) (526)

Shareholders' equity 134,727 146,246 162,409 180,984 199,630 Cash flow from Financing -723 -1,653 -10,876 -11,200 -11,569

Minorities 1,704 1,767 2,269 2,745 3,242 Change in Net debt 17,233 5,574 -8,229 -7,879 -9,793

Total Equity 136,431 148,013 164,678 183,730 202,872

Total Liabilities and Shareholders Equity 292,181 322,560 333,129 350,555 369,873 Debt adjusted cash flow 20,610 27,042 42,056 46,698 48,375

Free cash flow (5,469) 3,725 8,229 7,879 9,793

Net debt/ (cash) 25,314 30,888 22,659 14,781 4,988 FCF ex-W/Capital Changes -3,138 9,654 15,961 16,465 18,652

Capital Employed 161,745 178,901 187,337 198,510 207,860 CFPS 3.1 3.5 5.5 6.1 6.2


183



ENI: Summary of FinancialsProfit and Loss Statement Valuation, performance and production

€ in millions, year end Dec FY09 FY10 FY11E FY12E FY13E € in millions, year end Dec FY09 FY10 FY11E FY12E FY13E


Gas & Power 3,683 3,119 3,375 3,571 3,720 US Gas, $/MMBtu 4.16 4.38 4.33 5.40 5.90

Refining & Marketing -357 -171 -13 133 228

Chemicals -426 -113 183 183 183 Valuation

Corporate & other 528 585 935 1,214 1,315 Mkt Cap (bn)

Total Segmental EBIT 12,912 17,304 20,767 21,803 22,292 P/E adjusted 9.3 6.9 5.4 5.1 4.9

P/CF 5.3 4.0 3.3 2.9 2.8

Finance Costs 149 89 209 250 250 P/FCF -3722.8% 3355.9% 1051.0% 927.7% 840.7%

Pre-Tax Income 13,061 17,393 20,976 22,053 22,542 EV/DACF 7.4 5.8 4.6 4.0 3.8

Less: Tax 7,049 9,459 11,105 11,318 11,332 CF Yield 18.9% 24.8% 30.5% 34.0% 35.2%

Tax Rate 54.0% 54.4% 52.9% 51.3% 50.3% FCF Yield 4.5% 6.9% 9.5% 10.8% 11.9%

Minorities 950 1,065 1,215 1,421 1,510 FCF yield ex-w/c 0.5% 5.9% 11.2% 10.8% 11.9%

Dividend Yield 6.1% 6.1% 6.4% 6.8% 7.1%

Adjusted Net Income 5,062 6,869 8,656 9,314 9,700 Buyback Yield 0.0% 0.0% 0.0% 0.0% 0.0%

Growth (50.2%) 35.7% 26.0% 7.6% 4.2% Combined Yield 6.1% 6.1% 6.4% 6.8% 7.1%

Avg. shares in issue (m) 3,622.10 3,622.10 3,622.10 3,622.10 3,621.60 Ratios

Net debt to equity 42.4% 43.4% 35.8% 28.7% 22.3%

Adjusted EPS 1.40 1.90 2.39 2.57 2.68 Net Debt to Capital Employed 31.4% 31.9% 28.1% 24.1% 19.9%

EPS growth(%) NM 35.7% 26.0% 7.6% 4.2% ROE 10.1% 12.3% 14.0% 13.6% 12.8%

DPS 1.00 1.00 1.05 1.10 1.16 ROCE 7.2% 8.9% 10.3% 10.5% 10.5%

DPS growth(%) (23.1%) 0.0% 5.0% 5.0% 5.0%

Production

Group oil, kbopd 1,007 997 947 1,020 1,075

Group gas, mmcfpd 4,374 4,540 3,915 4,410 4,287

Group total, kboepd 1,796 1,816 1,654 1,816 1,849

Y/Y growth 0.4% 1.1% -9.0% 9.8% 1.8%



Tangible fixed assets 63,287 67,133 70,400 74,787 78,994 Consolidated Net Income 5,062 6,869 8,656 9,314 9,700

Other non current assets 16,676 20,058 20,058 20,058 20,058 DD&A 9,811 9,392 9,327 9,559 9,741

Total non current assets 79,963 87,191 90,458 94,845 99,052 Cash tax payable 7,049 9,459 11,105 11,318 22,663

Cash and cash equivalent 1,625 1,549 3,457 5,908 8,821 Other items -4,099 -3,949 -994 1,171 -10,071

Total assets 73,339 81,847 86,114 90,501 94,706 Cash Earnings 17,823 21,771 28,094 31,361 32,034

Change in working capital (1,901) (1,726) (1,000) 0 0

Short term debt 137 115 98 98 98 Cash flow from Operations 19,724 23,497 29,094 31,361 32,034

Long term debt 24,800 27,783 27,783 27,783 27,783

Total liabilities 23,038 26,119 24,228 21,777 18,864 Capex (13,695) (13,870) (14,094) (13,945) (13,948)

Shareholders' equity 46,323 51,206 56,149 61,565 67,173 Other investing cash flow 847 931 1,500 0 0

Minorities 3,978 4,522 5,737 7,159 8,669 Cash Flow from Investing -12,848 -12,939 -12,594 -13,945 -13,948

Total Equity 50,301 55,728 61,887 68,723 75,841 Share Buybacks 0 0 0 0 0

Total Liabilities and Equity 73,339 81,847 86,114 90,501 94,706 Dividends (s/h & minorities) (2,956) (4,099) (3,713) (3,898) (4,092)

Other cash flow from financing 4,224 2,285 0 0 1

Net debt 23,038 26,119 24,228 21,777 18,864 Cash flow from Financing 1,268 -1,814 -3,713 -3,898 -4,091

Capital Employed 73,339 81,847 86,114 90,501 94,706

Change in Net debt 4,662 3,081 -1,891 -2,450 -2,913

Debt adjusted Cash Flow 11,117 14,605 17,989 20,044 20,702

Free cash flow (1,582) 1,755 5,604 6,349 7,004

Free cash flow (ex-w/c) 319 3,481 6,604 6,349 7,004

CFPS 4.9 6.0 7.8 8.7 8.8


184



Essar Energy: Summary of FinancialsProfit and Loss Statement Valuation, performance and production

$ in millions, year end Dec FY10 FY11E FY12E FY13E $ in millions, year end Dec FY10 FY11E FY12E FY13E

Revenues 8,959 9,656 14,122 14,873 Valuation

EBITDA 729 1,155 2,192 2,542 Mkt Cap ( bn)

Depreciation 127 189 368 452

Total EBIT 602 966 1,824 2,090 P/E adjusted 20.3 12.7 6.5 5.0

Finance Costs (272) (390) (711) (650) P/BV 1.2 1.1 1.0 0.8

Other income 45 - - - EV/Sales 1.5 1.8 1.3 1.2

Pre-Tax Income 357 577 1,114 1,439 EV/EBITDA 18.7 14.8 8.2 7.2

Less: Tax 71 123 245 315 EV/DACF (Dynamic EV) -5209.4% 2660.7% 1447.4% 1154.9%

Tax Rate 20.0% 21.3% 22.0% 21.9%

Minorities 36 43 70 88

Post tax inventory adjustment 0 0 0 0 FCF Yield -28.7% -27.1% -0.8% 3.4%

Adjusted Net Income 250 411 799 1,036 Dividend Yield 0.0% 0.0% 0.0% 0.0%

Growth 135.4% 64.6% 94.3% 29.8%

Reported Net Income 250 411 799 1,036

Ratios

Avg. shares in issue (m) 1,303.00 1,346.00 1,346.00 1,346.00 Net debt to equity 84.7% 138.9% 132.0% 115.4%

Per share amounts Net Debt to Capital Employed 45.9% 58.2% 56.9% 53.6%

Reported EPS 0.19 0.31 0.59 0.77 Net Debt/EBITDA 5.4 6.1 3.6 3.2

Adjusted EPS 0.19 0.31 0.59 0.77 ROE 5.8% 8.8% 14.5% 15.9%

DPS 0.00 0.00 0.00 0.00 ROCE 2.9% 3.4% 5.8% 6.8%


$ in millions, year end Dec FY10 FY11E FY12E FY13E $ in millions, year end Dec FY10 FY11E FY12E FY13E

Total l/term assets 8,412 11,761 13,082 14,314 Consolidated Net Income 250 411 799 1,036

Tax 17 -512 -955 -965

Cash and cash equivalent 564 300 250 200 DD&A 127 189 368 452

Other current assets 1,520 1,773 2,116 2,314 Other (including non-recurring) -1,664 555 1,026 1,053

Current assets 2,083 2,073 2,366 2,514 Cash Earnings -1,270 643 1,237 1,576

Total assets 10,495 13,833 15,447 16,828 Increase in working capital (1,008) 0 0 0

Cash flow from operations (262) 643 1,237 1,576

Total Debt 4,498 7,381 8,126 8,382 Capex (2,496) (3,349) (1,321) (1,232)

Cash Flow from Investing -2,612 -3,349 -1,321 -1,232

Total liabilities 5,852 8,736 9,480 9,736

Dividends (S/H & Minorities) - 0 0 0

Minorities 360 403 474 562 Cash flow from Financing 3,312 2,494 34 -394

Shareholders' equity 3,922 4,289 5,018 5,966

Change in Net debt 2,052 2,884 745 256

Total Equity 4,282 4,693 5,492 6,528

Total Liabilities & Shareholders Equity 10,495 13,833 15,447 16,827

Debt adjusted Cash Earnings -262 643 1,237 1,576

Net debt 3,934 7,081 7,876 8,182 Free cash flow (2,874) (2,706) (84) 344

Capital Employed 8,576 12,178 13,842 15,272 FCF ex-W/Capital Changes -1,866 -2,706 -84 344

CFPS -1.0 0.5 0.9 1.2


185



Galp Energia: Summary of FinancialsProfit and Loss Statement Valuation, performance and production


Exploration & Production 68 61 121 147 263 Brent Crude, $/bbl 62.67 80.34 110.00 95.00 90.00

Refining & Marketing 79 193 253 498 508 US Gas, $/MMBtu 4.16 4.38 4.33 5.40 5.90

Gas & Power 135 181 213 241 244

Other 75 89 90 105 105 Valuation

Total Segmental EBIT 357 524 676 991 1,121 Mkt Cap (bn)

P/E adjusted 48.5 35.2 28.0 17.3 16.4

Finance Costs (76) (98) (145) (155) (171) P/CF 12.9 17.3 13.5 11.5 10.8

Pre-Tax Income 281 426 532 836 950 P/FCF 11352.3% -22704.6% -1753.6% -7199.6% -43615.6%

Less: Tax 61 115 133 218 287 EV/DACF 14.8 21.1 17.2 14.8 13.9

Tax Rate 21.7% 27.0% 25.0% 26.0% 30.2% CF Yield 7.7% 5.8% 7.4% 8.7% 9.3%

Minorities (6) (5) (5) (5) (5) FCF Yield 1.8% 0.4% -4.5% -0.1% 1.0%

FCF yield ex-w/c 0.9% -0.4% -5.7% -1.4% -0.2%

Adjusted Net Income 214 306 394 613 658 Dividend Yield 1.3% 1.3% 1.3% 1.3% 1.3%

Growth (54.7%) 43.2% 28.7% 55.8% 7.2% Buyback Yield 0.0% 0.0% -0.0% -0.0% -0.0%

Combined Yield 1.3% 1.3% 1.3% 1.2% 1.2%

Shares in issue (mn) 829.0 829.0 829.0 829.0 829.0

Ratios

Adjusted EPS 0.27 0.37 0.46 0.75 0.79 Net debt to equity 79.8% 103.6% 114.5% 105.8% 93.6%

EPS growth(%) NM 37.8% 26.0% 61.3% 5.6% Net Debt to Capital Employed 44.7% 51.2% 53.7% 51.7% 48.6%

DPS 0.20 0.20 0.20 0.20 0.20 ROE 9.0% 11.3% 12.7% 17.4% 16.3%

DPS growth(%) (37.5%) 0.0% 0.0% 0.0% 0.0% ROCE 5.1% 6.2% 6.4% 8.8% 8.7%

Production

Group Total, kboepd 10 11 14 22 29

Y/Y growth -1.5% 16.7% 18.4% 63.4% 31.1%



Tangible fixed assets 3,190 3,588 4,575 5,211 5,740 Consolidated Net Income 214 306 394 613 658

Investments in associates 227 253 253 297 297 DD&A 459 317 285 220 217

Other non current assets 999 1,916 1,916 1,848 1,848 Cash tax payable (176) (195) (278) (373) (458)

Total non current assets 4,416 5,757 6,744 7,356 7,885 Other items 195 -37 7 4 5

Cash and cash equivalent 244 188 (567) (752) (785) Cash Earnings 1,043 781 963 1,210 1,338

Other current assets 2,583 3,202 3,202 3,203 3,203 Change in working capital 0 0 0 0 0

Total Current assets 2,827 3,390 2,635 2,451 2,418 Cash flow from Operations 1,043 781 963 1,210 1,338

Total assets 7,243 9,147 9,379 9,808 10,303

Capex (800) (1,371) (1,362) (962) (852)

Short term debt 423 616 618 618 618 Other investing cash flow -4 -22 90 105 105

Other current liabilities 2,083 2,562 2,562 2,562 2,562 Cash Flow from Investing -804 -1,393 -1,272 -857 -747

Long term debt 1,747 2,412 2,412 2,412 2,412

Other non current liabilities 599 846 726 726 726 Dividends (s/h & minorities) (127) (108) (166) (166) (166)

Total liabilities 4,856 6,436 6,273 6,273 6,318 Other cash flow from financing 105 770 (145) (155) (171)

Shareholders' equity 2,360 2,678 3,068 3,492 3,982 Cash flow from Financing -22 662 -311 -321 -337

Minorities 27 32 37 42 47

Total Equity 2,387 2,710 3,105 3,534 4,029 Change in Net debt 62 914 757 185 33

Total Liabilities and Equity 7,243 9,146 9,378 9,807 10,347 Debt adjusted Cash Flow 1,017 760 976 1,148 1,221

Free cash flow 116 (58) (751) (183) (30)

Net debt 1,926 2,840 3,597 3,782 3,815 Free cash flow (ex-w/c) 116 -58 -751 -183 -30



186



OMV: Summary of FinancialsProfit and Loss Statement Valuation, performance and production



Refining & Marketing -222 225 65 260 289

Gas & Power 254 279 393 396 503 Valuation

Corporate & Other -133 -133 -110 -110 -110 Mkt Cap (bn)

Total Segmental EBIT 1495 2469 2601 3081 3034 P/E adjusted 11.9 6.9 6.4 5.8 5.6

P/CF 4.2 2.4 2.6 2.3 2.3

Finance Costs (228) (373) (200) (167) (119) EV/DACF 6.2 4.1 4.1 3.6 3.5

Pre-Tax Income 1,266 2,096 2,401 2,914 2,915 CF Yield 23.7% 42.3% 38.7% 43.5% 43.8%

Less: Tax 478 684 642 1,117 1,075 FCF Yield 4.6% 8.9% 4.0% 6.8% 11.5%

Tax Rate 37.7% 32.6% 26.7% 38.3% 36.9% FCF yield ex-w/c 4.3% 15.0% 8.5% 0.3% 5.3%

Minorities 145 294 443 344 322 Dividend Yield 4.4% 4.4% 4.6% 4.7% 4.8%

Combined Yield 4.4% 4.4% -6.0% 4.7% 4.8%

Adjusted Net Income 644 1,118 1,316 1,453 1,518

Growth (61.4%) 73.8% 17.7% 10.4% 4.4% Ratios

Avg. shares in issue (m) 297.70 297.70 326.20 326.20 326.20 Net debt to equity 33.0% 45.7% 34.4% 32.2% 27.8%

Net Debt to Capital Employed 24.8% 31.4% 25.6% 24.3% 21.8%

Adjusted EPS 2.17 3.76 4.03 4.43 4.63 ROE 6.4% 9.9% 10.2% 10.6% 10.4%

EPS growth(%) NM 73.6% 7.1% 10.2% 4.5% ROCE 4.9% 7.5% 7.8% 8.2% 8.2%

DPS 1.00 1.00 1.05 1.07 1.09

DPS growth(%) 0.0% 0.0% 5.0% 2.0% 2.0% Production

Group oil, kbopd 127 127 102 133 129

Group gas, mmcfpd 562 563 557 571 584

*Group Total, kboepd 227 227 202 235 233

Y/Y growth 1.4% 0.2% -11.3% 16.3% -0.5%



Cash and cash equivalent 675 946 1,528 1,550 1,915 Consolidated Net Income 644 1,118 1,316 1,453 1,518


Total current assets 5,622 7,544 8,126 8,148 8,513 Cash tax payable (249) (310) (442) (950) (956)

Tangible fixed assets 11,370 12,829 14,619 15,570 16,239 Other items -375 -586 1 2 3


Total non current assets 15,615 18,670 20,460 21,412 22,080 Change in working capital (317) (750) 0 0 0

Total assets 21,414 26,404 28,776 29,749 30,783 Cash flow from Operations 2,096 3,197 3,339 4,204 4,234

Short term debt 674 968 968 968 968


Total current liabilities 4,732 6,220 6,241 6,389 6,569 Other investing cash flow 997 -787 -601 0 0

Cash Flow from Investing -1,210 -2,875 -3,351 -2,750 -2,426

Long term debt 3,197 5,005 5,005 5,005 5,005

Other non current liabilities 3,157 3,330 4,080 4,080 4,080 Dividends (s/h & minorities) (336) (334) (441) (486) (493)

Total non current liabilities 6,354 8,335 9,085 9,085 9,085 Other cash flow from financing (322) 589 1,477 4 6

Total liabilities 11,381 15,092 15,863 16,011 16,191 Cash flow from Financing -658 256 1,036 -482 -487

Shareholders' equity 8,098 9,081 10,239 10,720 11,252 Change in Net debt -119 1,853 -722 -22 -365

Minorities 1,936 2,232 2,675 3,018 3,340

Total Equity 10,034 11,312 12,914 13,739 14,592 Debt adjusted Cash Flow 1,618 2,886 2,897 3,254 3,278

Total Liabilities and Shareholders Equity 21,415 26,404 28,777 29,749 30,783 Free cash flow (27) 272 582 22 365

FCF ex-W/Capital Changes 291 1,022 582 22 365

Net debt 3,314 5,167 4,445 4,423 4,058



187



Repsol YPF: Summary of FinancialsProfit and Loss Statement Valuation, performance and production


Exploration & Production 884 1,473 1,917 2,360 2,245 Brent Crude, $/bbl 62.67 80.34 110.00 95.00 90.00

Refining & Marketing 647 977 865 1,393 1,528 US Gas, $/MMBtu 3.66 4.38 4.34 5.40 5.90

YPF 789 1,625 1,549 1,800 1,899

Gas Natural 745 849 933 939 961 Valuation

LNG 50 127 259 253 279 Mkt Cap (bn)

Corporate -354 -336 -316 -345 -349 P/E adjusted 17.4 11.1 9.4 7.7 7.4

Total Segmental EBIT 2,761 4,714 5,207 6,399 6,561 P/CF 4.9 4.1 4.0 4.3 3.4

P/FCF -4225.8% 653.7% 3663.4% -1835.7% -52790.2%

Finance Costs (468) (858) (669) (572) (571) EV/DACF 7.5 5.7 5.4 6.1 4.9

Pre-Tax Income 2,293 3,856 4,538 5,827 5,990 CF Yield 20.5% 24.4% 25.0% 23.4% 29.1%

Less: Tax 832 1,561 1,870 2,587 2,599 FCF Yield 4.8% 18.3% 7.5% -0.2% 5.6%

Tax Rate 36.3% 40.5% 41.2% 44.4% 43.4% FCF yield ex-w/c -0.2% 17.5% 9.0% -2.7% 7.3%

Minorities 166 263 267 324 339 Dividend Yield 3.9% 4.8% 5.2% 5.8% 6.3%

Buyback Yield 0.0% 0.0% 0.0% 0.0% -0.0%

Adjusted Net Income 1,295 2,032 2,402 2,916 3,052 Combined Yield 3.9% 4.8% 5.2% 5.8% 6.3%

Growth (50.6%) 57.0% 18.2% 21.4% 4.6%

Ratios

Avg. shares in issue (m) 1,221.00 1,221.00 1,221.00 1,221.00 1,221.00 Net debt to equity 73.4% 45.4% 39.2% 42.5% 40.4%

Net Debt to Capital Employed 42.4% 31.2% 28.1% 29.8% 28.8%

Adjusted EPS 1.06 1.66 1.97 2.39 2.50 ROE 6.1% 7.8% 8.8% 10.0% 9.8%

EPS growth(%) NM 57.0% 18.2% 21.4% 4.6% ROCE 4.2% 5.8% 6.8% 8.0% 7.8%

DPS 0.85 1.05 1.16 1.27 1.40 Production

DPS growth(%) (19.1%) 23.5% 10.0% 10.0% 10.0% Group oil, kbopd 438 437 401 437 431

Group gas, mmcfpd 2,808 2,700 2,491 2,394 2,322

Group Total, kboepd 906 887 816 836 818

Y/Y growth -4.8% -2.1% -8.0% 2.5% -2.2%





Total non current assets 43,310 45,753 45,665 46,962 48,866 Cash tax payable (1,168) (1,627) (1,776) (2,457) (2,469)

Total Current assets 14,773 21,878 23,349 21,876 21,824 Other items 770 106 -1,486 -928 -775

Total assets 58,083 67,631 69,014 68,838 70,689 Cash Earnings 6,119 7,641 6,858 8,045 8,321

Change in working capital (590) (590) (1,693) (733) (2,031)

Cash flow from Operations 6,709 8,231 8,551 8,778 10,352

Short term debt 3,499 4,362 4,362 4,362 4,362


Total Current Liabilities 11,993 15,773 15,773 13,742 13,743 Other investing cash flow 56 -27 0 0 0

Cash Flow from Investing -7,854 -73 -3,417 -5,240 -5,240

Long term debt 15,411 14,940 14,940 14,940 14,941

Other non current liabilities 9,288 10,932 10,932 10,932 10,932 Dividends (s/h & minorities) (1,935) (806) (1,282) (1,410) (1,552)

Total non current liabilities 24,699 25,872 25,872 25,872 25,873 Other cash flow from financing 4,440 (653) (669) (572) (572)

Total liabilities 36,692 41,645 41,645 39,614 39,616 Cash flow from Financing 2,505 -1,459 -1,950 -1,982 -2,123

Shareholders' equity 19,951 24,140 25,260 26,766 28,266

Minorities 1,440 1,846 2,113 2,437 2,776 Change in Net debt 7,796 -3,696 -1,064 1,473 53

Total Equity 21,391 25,986 27,373 29,203 31,042

Total Liabilities and Shareholders Equity 58,083 67,631 69,018 68,817 70,658 Debt adjusted Cash Flow 5,541 6,604 6,774 6,321 7,882

Free cash flow (640) 4,137 738 (1,473) (51)

Net debt 14,654 10,958 9,894 11,367 11,420 FCF ex-W/Capital Changes -50 4,727 2,431 -740 1,980



188



Statoil: Summary of FinancialsProfit and Loss Statement Valuation, performance and production

Nkr in millions, year end Dec FY09 FY10 FY11E FY12E FY13E Nkr in millions, year end Dec FY09 FY10 FY11E FY12E FY13E

Exploration & production 111,881 125,730 158,516 157,737 148,521 Brent crude, $/bbl 62.67 80.34 110.00 95.00 90.00

Marketing, Process mgt & Renewable Enrgy 16,500 13,500 12,335 14,080 14,113 US Gas, $/MMBtu 4.16 4.38 4.34 5.40 5.90

Manufacturing & Marketing 2,100 1,700 - - -

Other Operations -1,100 -400 -1,100 -1,100 -1,100 Valuation

Total Segmental EBIT 130,881 142,730 171,419 172,468 163,406 Mkt Cap (Nkr bn)

P/E adjusted 10.0 9.2 7.0 7.1 7.5

Finance Costs (300) (1,100) 0 0 0 P/CF 5.9 5.3 4.3 4.3 4.4

Pre-Tax Income 129,081 139,593 170,551 171,517 162,334 P/FCF 7092.3% 8349.4% 1087.1% -7694.9% -

Less: Tax 92,286 98,800 116,185 117,626 111,859 EV/DACF 6.9 6.2 4.6 4.7 4.9

Tax Rate 70.7% 69.8% 67.8% 68.2% 68.5% CF Yield 16.9% 18.7% 23.4% 23.0% 22.6%

Minorities (598) (598) (767) (805) (861) FCF Yield 6.8% 5.7% 13.8% 3.6% 3.1%

FCF yield ex-w/c 2.7% 4.8% 10.5% 0.1% -0.7%

Adjusted Net Income 37,697 42,232 54,467 54,036 50,686 Dividend Yield 4.4% 4.6% 4.8% 5.1% 5.3%

Growth (34.7%) 12.0% 29.0% (0.8%) (6.2%) Buyback Yield 0.1% 0.1% 0.0% 0.0% 0.0%

Avg. shares in issue (m) 3,185.00 3,182.00 3,182.00 3,182.00 3,182.00 Combined Yield 4.5% 4.7% 4.8% 5.1% 5.3%

Adjusted EPS (Nkr) 12.07 13.14 17.22 17.08 16.04 Ratios

EPS growth(%) NM 8.8% 31.1% NM NM Net debt to equity 37.6% 30.8% 11.7% 12.5% 14.0%

DPS (Nkr) 6.00 6.24 6.55 6.88 7.22 Net Debt to Capital Employed 27.3% 23.5% 10.5% 11.1% 12.3%

DPS growth(%) (17.2%) 4.0% 5.0% 5.0% 5.0% ROE 18.8% 18.7% 20.9% 18.3% 15.7%

ROCE 13.7% 14.3% 18.7% 16.3% 13.7%

Production

Group oil, kbopd 1,061 968 962 987 976

Group gas, mmcfpd 4,440 4,428 4,160 4,543 4,356


Y/Y growth 2.8% -5.3% -3.0% 5.4% -2.4%


Nkr in millions, year end Dec FY09 FY10 FY11E FY12E FY13E Nkr in millions, year end Dec FY09 FY10 FY11E FY12E FY13E

Cash and cash equivalent 24,723 30,337 69,392 63,293 54,697 Consolidated Net Income 37,697 42,232 54,467 54,036 50,686


Current assets 116,384 148,762 187,674 181,606 173,010 Cash tax payable 100,773 93,266 110,376 111,745 106,266

Net fixed assets 340,835 348,204 358,487 391,046 422,255 Other items -13,930 -18,281 -2,313 -7,519 -7,053


Total non current assets 446,456 449,356 459,241 491,800 523,009 Change in working capital (5,687) (15,429) (5,809) (5,881) (5,593)

Total assets 562,840 643,008 691,597 718,086 740,699 Cash flow from operations 173,774 174,081 211,107 210,986 203,564

Short term debt 8,150 11,730 11,730 11,730 11,730


Total current liabilities 111,805 136,135 130,326 124,444 118,851 Other investing cash flow -206 -2,063 48,366 0 0

Cash Flow from Investing Acitivites -75,356 -76,218 -41,097 -83,872 -83,872

Long term debt 95,962 99,797 99,797 99,797 99,797

Other non current liabilities 154,955 171,458 169,729 169,729 169,730 Share Buybacks -343 -294 0 0 0

Total non current liabilities 250,917 271,255 269,526 269,526 269,527 Dividends (s/h & minorities) (23,085) (19,095) (19,974) (20,973) (22,022)

Total liabilities 362,722 416,613 399,852 393,970 388,378 Other cash flow from financing 34,719 19,956 0 0 0

Shareholders' equity 198,319 219,542 254,358 287,748 316,752 Cash flow from Financing 11,291 567 -19,974 -20,973 -22,022

Minorities 1,799 6,853 6,853 6,853 6,853 Change in Net debt 29,304 -5,586 -39,055 6,099 8,596

Total Equity 200,118 226,395 261,211 294,601 323,605

Total Liabilities and Shareholders Equity 562,840 643,008 661,062 688,571 711,984 Debt adjusted cash flow 73,001 80,815 100,731 99,242 97,298

Free cash flow 6,085 5,164 39,660 (5,603) (8,596)

Net debt 75,267 69,681 30,626 36,725 45,321 FCF ex-W/Capital Changes 11,772 20,593 45,469 278 -3,003



189



TOTAL: Summary of FinancialsProfit and Loss Statement Valuation, performance and production


Exploration & production 13,885 19,003 23,981 22,435 22,965 Brent crude, $/bbl 62.67 80.34 110.00 95.00 90.00

Refining & marketing 1,173 1,518 1,298 1,853 1,695 US Gas, $/MMBtu 4.16 4.38 4.33 5.40 5.90

Chemicals 314 1,124 1,162 1,143 1,184

Corporate & other 290 -143 -380 -380 -379 Valuation

Total Segmental EBIT 15,663 21,503 26,061 25,051 25,466 Mkt Cap (bn)

P/E adjusted 9.1 6.8 5.7 5.8 5.6

Finance Costs (264) (226) (380) (340) (285) P/CF 6.9 4.6 4.5 4.5 4.1

Pre-Tax Income 15,399 21,277 25,681 24,711 25,181 P/FCF -13169.1% 3069.8% 4910.0% 4371.4% 5308.7%

Less: Tax (7,436) (10,755) (13,321) (12,867) (12,834) EV/DACF 7.9 5.3 5.1 5.0 4.5

Tax Rate 48.3% 50.5% 51.9% 52.1% 51.0% CF Yield 14.5% 21.6% 22.4% 22.3% 24.4%

Minorities (178) (234) (260) (310) (311) FCF Yield 5.1% 9.1% 8.3% 8.9% 8.8%

FCF yield ex-w/c 3.0% 3.8% 2.0% 2.3% 1.9%

Adjusted Net Income 7,785 10,288 12,100 11,534 12,035 Dividend Yield 5.8% 5.8% 6.2% 6.6% 6.9%

Growth (44.1%) 32.2% 17.6% (4.7%) 4.4% Buyback Yield -0.0% -0.1% 0.0% 0.0% 0.0%

Combined Yield 5.8% 5.8% 6.2% 6.6% 6.9%

Avg. shares in issue (m) 2,217.00 2,217.00 2,217.00 2,217.00 2,217.00

Ratios

Adjusted EPS 3.48 4.64 5.56 5.43 5.65 Net debt to equity 25.3% 21.3% 18.0% 13.7% 10.6%

EPS growth(%) NM 33.4% 19.8% NM 4.2% Net Debt to Capital Employed 21.6% 18.7% 16.1% 12.6% 10.0%

DPS 2.28 2.28 2.44 2.56 2.69 ROE 14.8% 17.0% 18.0% 15.6% 15.0%

DPS growth(%) 0.0% 0.0% 7.0% 5.0% 5.0% ROCE 12.4% 14.7% 15.8% 14.1% 13.9%

Production

Group oil, kbopd 1,381 1,339 1,309 1,362 1,428

Group gas, mmcfpd 4,923 5,674 5,684 5,650 5,542


Y/Y growth -2.6% 4.1% -1.2% 2.0% 2.0%





Total non current assets 77,996 85,512 92,025 96,745 102,035 Cash Tax Payable 7,700 10,980 13,701 13,207 13,120

Other items -5,032 1,296 512 850 851

Cash and cash equivalent 11,662 14,489 16,256 18,242 19,877 Cash Earnings 16,744 28,977 32,767 32,205 34,028

Other current assets 38,095 42,447 42,447 42,447 42,447 Change in working capital (3,316) (496) 1 0 0

Total Current assets 49,757 56,936 58,703 60,689 62,324 Cash flow from Operations 20,060 29,473 32,766 32,205 34,028

Total assets 127,753 143,718 150,727 157,433 164,357

Capex (11,711) (12,278) (13,865) (13,310) (13,310)

Short term debt 6,994 9,653 9,653 9,653 9,653 Other investing cash flow -922 -735 0 0 0

Other current liabilities 27,411 30,597 30,598 30,598 30,598 Cash Flow from Investing -10,268 -11,957 -11,888 -11,334 -13,310

Total Current Liabilities 34,405 40,250 40,251 40,251 40,251

Share Buybacks 22 49 0 0 0

Long term debt 19,437 20,783 20,783 20,783 20,783 Dividends (s/h & minorities) (5,086) (5,098) (5,409) (5,679) (5,963)

Other non current liabilities 20,369 21,216 21,216 21,216 21,216 Cash flow from Financing -2,868 -3,348 -5,409 -5,679 -5,963

Total non current liabilities 39,806 41,999 41,999 41,999 41,999 Change in Net debt 2,895 -535 -721 -1,985 -1,635

Total liabilities 74,211 82,249 82,250 82,250 82,250

Shareholders' equity 52,552 60,414 67,355 73,750 80,362 Debt adjusted Cash Flow 12,624 18,719 19,445 19,338 21,193

Minorities 987 857 1,117 1,427 1,738 Free cash flow (659) 2,827 1,767 1,985 1,635

Total Equity 52,552 60,414 67,355 73,750 80,362 FCF ex-W/C Changes 2,657 3,323 1,766 1,985 1,635

Total Liabilities and Shareholders Equity 127,753 143,718 150,727 157,433 164,356 CFPS 7.6 13.1 14.8 14.5 15.3

Net debt 13,566 13,031 12,310 10,324 8,689



190



PETROBRAS ON: Summary of FinancialsIncome Statement - Annual FY10A FY11E FY12E FY13E Cash Flow Statement FY10A FY11E FY12E FY13E FY14E

Revenues 213,274 230,851 256,353 240,484 EBIT 47,058 48,333 60,251 58,234 -

% change YoY 16.7% 8.2% 11.0% (6.2%) Depreciation (14,881) (15,061) (16,359) (16,881) -

Upstream, % - - - - Working Capital changes 3,542 (736) (664) (1,262) -

Downstream, % - - - - Taxes (12,236) (14,146) (16,367) (17,444) -

Gas & Energy, % - - - - CFO 53,435 54,079 63,260 52,291 -

International,% - - - - Capex (73,169) (67,449) (72,725) (72,388) -

EBITDA 60,325 63,394 76,610 73,371 FCFF (52,482) (11,178) (9,395) (5) -

% change YoY 13.5% 13.2% 18.8% (12.8%) Net Interest Expense 2563.00 5651.79 7353.79 706.26 -

EBITDAmargin, % 29.0% 27.8% 30.5% 30.5% FCFE 70499.00 (12147.44) (11799.32) 1628.96 -

EBIT 47,058 48,333 60,251 58,234 Equity raised/ (repaid) 120,249 0 0 0 -

% change YoY 15.4% 12.4% 21.5% (10.2%) Debt raised/ (repaid) 12,147 12,448 14,956 15,975 -

EBIT margin, % 22.0% 20.9% 23.5% 24.2% Dividends (9,415) (13,417) (17,360) (14,341) -

Net Interest Expense 0 (113) (237) (883) Other

EBT 49,621 51,102 63,810 58,146

% change YoY 14.6% 3.0% 24.9% (8.9%) Change in cash 1,289 (11,698) (11,799) 1,629 -

Tax (12,236) (14,146) (16,367) (17,444) Beginning cash 29,034 30,323 18,625 6,825 -

Net Income 35,190 36,237 46,143 36,673 Ending cash 30,323 18,625 6,825 8,454 -

% change YoY (13.3%) 15.0% 24.1% (26.2%)

Shares outstanding, mn 13,044 13,044 13,044 13,044 DACF 33,625 37,049 41,492 29,495 -

EPS, R$/share 2.70 2.78 3.54 2.81 DPS, R$/share 1.98 1.60 1.95 1.40 -

Fully Diluted EPS - - - -

Balance Sheet FY10A FY11E FY12E FY13E Operating Data & Ratio Analysis FY10A FY11E FY12E FY13E FY14E

Cash and cash equivalents 56,340 43,594 31,794 13,407

Accounts receivable 17,334 18,763 18,763 18,763 Reserves (SPE), kboed - - - - -

Inventories 19,816 25,751 25,751 25,751 Production,kboed 2,575 2,663 2,877 3,121 -

Others 13,195 15,338 15,338 15,338 % change YoY 2.4% 3.4% 8.0% 8.5% -

Current Assets 106,685 103,446 91,646 73,259 Liquids, kbd 2147.75 2211.50 2372.73 2576.73 -

Taxes - - - - Gas, mcmd 2,399 2,537 2,830 3,054 -

Others 14,626 15,918 14,981 13,766 Prices

LT ASSETS 413,285 465,662 524,700 582,118 Brent, US$/bbl - as per JPM 79.71 111.81 115.00 85.00 -

Net PP&E 282,838 332,954 389,320 444,827 Dom. Realization price,US$/bbl 74.63 100.00 101.00 71.00 -

Total Assets 519,970 569,107 616,346 655,377 Petrobras discount to brent 6.37% 10.56% 12.17% 16.47% -

ST Loans 15,492 16,737 16,737 16,737 Ratios

Payables 17,044 18,616 18,616 18,616 SG&A/revenues, % 7.8% 7.5% 7.3% 8.5% -

Dividends - - - - Interest Coverage - - 0.0 0.0 -

Others 24,298 25,468 25,468 25,468 Net Debt (incl.pension liab) 63,903 87,404 114,159 148,521 -

Current Liabilities 56,834 60,821 60,821 60,821 Net Debt to Total Capital, % 13.6% 22.1% 25.9% 29.5% -

LT Debt 102,051 111,561 126,517 142,492 Net Debt to Equity, % 15.8% 28.8% 35.4% 42.3% -

Other LT liabilities 50,860 55,859 55,859 55,859 Net debt to EBITDA, (x) 1.1 1.4 1.4 1.9 -

LT Liabilities 152,911 167,420 182,376 198,351 Capex/Depreciation, (x) 5.4 4.5 4.4 4.3 -

Total Liabilities 209,745 228,241 243,197 259,172 Net Margin 16.2% 15.7% 18.0% 15.2% -

Minority Interests 3,459 3,631 3,631 3,631 Revenues/Assets, (x) 0.4 0.4 0.4 0.4 -

Shareholders Equity 306,766 337,235 369,518 392,574 Assets/Equity, (x) 1.7 1.7 1.7 1.7 -

Liabilities and Equity 519970.00 569107.29 616346.00 655377.15 ROE (%) 10.6% 10.7% 12.9% 9.7% -

ROCE (%) 11.0% 8.7% 9.6% 7.2% -

Eneterprise Value 283,801 246,627 259,018 271,974 Div. Yield (%) 8.8% 7.1% 8.7% 6.2% -

FCF Yield (%) - - - - -


Note: R$ in millions (except per-share data).Fiscal year ends Dec

191



PETROBRAS ON ADR: Summary of FinancialsIncome Statement - Annual FY10A FY11E FY12E FY13E Cash Flow Statement FY10A FY11E FY12E FY13E FY14E

Revenues 121,329 135,589 154,571 128,694 EBIT 26,741 30,876 38,277 33,383 -

% change YoY 30.1% 11.8% 14.0% (16.7%) Depreciation (8,474) (8,820) (9,501) (9,687) -

Upstream, % - - - - Working Capital changes 2,091 (1,032) (672) (715) -

Downstream, % - - - - Taxes (6,948) (8,906) (10,246) (9,957) -

Gas & Energy, % - - - - CFO 30,481 33,563 38,688 29,906 -

International,% - - - - Capex (45,619) (46,226) (44,087) (40,782) -

EBITDA 35,239 40,429 48,839 42,075 FCFF (16,104) (12,663) (5,399) (10,876) -

% change YoY 13.5% 14.7% 20.8% (13.8%) Net Interest Expense 1514.23 5834.98 3608.47 111.72 -

EBITDAmargin, % 29.0% 29.8% 31.6% 32.7% FCFE (14724.49) (14347.53) (7371.93) (10294.87) -

EBIT 26,741 30,876 38,277 33,383 Equity raised/ (repaid) 0 0 0 0 -

% change YoY 15.4% 15.5% 24.0% (12.8%) Debt raised/ (repaid) 12,755 6,925 9,000 9,000 -

EBIT margin, % 22.0% 22.8% 24.8% 25.9% Dividends (11,375) (8,610) (10,973) (8,419) -

Net Interest Expense (1,481) (233) (320) (500) Other

EBT 27,126 33,677 39,921 33,189

% change YoY 24.2% 24.2% 18.5% (16.9%) Change in cash 17,270 2,791 4,906 1,363 -

Tax (6,948) (8,906) (10,246) (9,957) Beginning cash 16,643 18,253 7,869 539 -

Net Income 19,609 24,529 29,118 20,934 Ending cash 33,913 21,044 12,775 1,902 -

% change YoY (13.3%) 25.1% 18.7% (28.1%)

Shares outstanding, mn 6,522 6,522 6,522 6,522 DACF 33,625 36,097 42,170 30,042 -

EPS, $/share 3.01 3.76 4.46 3.21 DPS, $/share 1.74 1.32 1.68 1.29 -

Fully Diluted EPS 0.00 0.00 0.00 0.00

Balance Sheet FY10A FY11E FY12E FY13E Operating Data & Ratio Analysis FY10A FY11E FY12E FY13E FY14E

Cash and cash equivalents 33,913 21,044 12,775 1,902

Accounts receivable 10,434 11,111 10,458 9,610 Reserves (SPE), kboed - - - - -

Inventories 11,928 14,918 14,041 12,902 Production,kboed 2,575 2,694 2,896 3,141 -

Others 7,943 9,393 8,840 8,123 % change YoY 2.4% 4.6% 7.5% 8.5% -

Current Assets 64,218 56,466 46,113 32,537 Liquids, kbd 2147.75 2242.50 2391.93 2596.89 -

Taxes 393.0 1293.0 1232.0 0.0 Gas, mcmd 2,399 2,538 2,830 3,054 -

Others 14,626 15,871 14,938 13,726 Prices

LT ASSETS 248,772 296,909 314,835 320,175 Brent, US$/bbl - as per JPM 79.71 106.81 114.00 85.00 -

Net PP&E 170,251 213,978 234,949 245,733 Dom. Realization price,US$/bbl 74.63 93.52 100.00 71.00 -

Total Assets 312,990 353,374 360,948 352,712 Petrobras discount to brent 6.37% 12.45% 12.28% 16.47% -

ST Loans 9,325 10,372 9,762 8,970 Ratios

Payables 10,259 11,626 10,942 10,055 SG&A/revenues, % 7.8% 7.7% 7.4% 8.9% -

Dividends 0.0 0.0 0.0 0.0 Interest Coverage 0.0 0.0 0.0 0.0 -

Others 14,626 15,871 14,938 13,726 Net Debt (incl.pension liab) 38,466 61,268 73,493 86,006 -

Current Liabilities 34,211 37,869 35,641 32,751 Net Debt to Total Capital, % 13.6% 21.1% 24.3% 27.3% -

LT Debt 61,428 70,253 74,917 77,478 Net Debt to Equity, % 15.8% 27.0% 32.4% 37.9% -

Other LT liabilities 30,615 33,599 31,623 29,059 Net debt to EBITDA, (x) 1.1 1.5 1.5 2.0 -

LT Liabilities 92,043 103,852 106,540 106,537 Capex/Depreciation, (x) 5.4 5.2 4.6 4.2 -

Total Liabilities 126,254 141,721 142,182 139,288 Net Margin 16.2% 18.1% 18.8% 16.3% -

Minority Interests 2,082 2,132 2,006 1,844 Revenues/Assets, (x) 0.4 0.4 0.4 0.4 -

Shareholders Equity 184,654 209,522 216,760 211,580 Assets/Equity, (x) 1.7 1.7 1.7 1.7 -

Liabilities and Equity 312989.83 353374.09 360947.60 352712.11 ROE (%) 10.6% 11.7% 13.4% 9.9% -

ROCE (%) 11.0% 9.1% 9.9% 7.2% -

Eneterprise Value 267,193 290,045 302,144 314,495 - Div. Yield (%) 6.4% 4.8% 6.1% 4.7% -

FCF Yield (%) 0.0% 0.0% 0.0% 0.0% -


Note: $ in millions (except per-share data).Fiscal year ends Dec

192



PetroChina: Summary of FinancialsIncome Statement Cash flow statement

Rmb in millions, year end Dec FY09 FY10 FY11E FY12E FY13E Rmb in millions, year end Dec FY09 FY10 FY11E FY12E FY13E

Revenues 1,019,275 1,465,415 1,432,924 1,327,399 1,332,663 EBIT 143,444 187,777 230,596 209,496 207,096

% change Y/Y (5%) 44% (2%) (7%) 0% Depr. & amortization 92,259 113,209 129,430 147,598 160,737

EBITDA 235,703 300,986 360,025 357,094 367,833 Change in working capital 37,833 31,741 -721 -2,342 117

% change Y/Y (7%) 28% 20% (1%) 3% Taxes -16412 -26169 -49996 -45303 -45694

EBIT 143,444 187,777 230,596 209,496 207,096 Cash flow from operations 258,159 306,348 305,968 305,877 322,859

% change Y/Y (10%) 31% 23% (9%) (1%)

EBIT Margin 14% 13% 16% 16% 16% Capex -277,518 -265,571 -320,000 -288,300 -213,313

Net Interest -3,813 -4,338 -9,559 -10,159 -6,372 Disposal/(purchase) - - - - -

Earnings before tax 140,032 189,305 227,255 205,924 207,699 Net Interest -3,813 -4,338 -9,559 -10,159 -6,372

% change Y/Y (14%) 35% 20% (9%) 1% Other - - - - -

Tax -33,473 -38,513 -49,996 -45,303 -45,694 Free cash flow -19,359 40,777 -14,032 17,577 109,546

as % of EBT 23.9% 20.3% 22.0% 22.0% 22.0%

Net income (reported) 103,387 139,992 162,089 148,506 150,654 Equity raised/(repaid) 0 0 0 0 0

% change Y/Y (10%) 35% 16% (8%) 1% Debt raised/(repaid) 77,401 52,656 85,000 20,000 0

Shares outstanding 183,021 183,021 183,021 183,021 183,021 Other 49,037 -35,320 0 0 -20,000

EPS (reported) 0.56 0.76 0.89 0.81 0.82 Dividends paid -50,092 -53,198 -72,940 -66,828 -67,794

% change Y/Y (10%) 35% 16% (8%) 1% Beginning cash 33,150 86,925 45,709 43,737 14,486

Ending cash 86,925 45,709 43,737 14,486 36,238

DPS 0.27 0.29 0.40 0.37 0.37

Balance sheet Ratio Analysis


Cash and cash equivalents 86,925 45,709 43,737 14,486 36,238 EBITDA margin 23% 21% 25% 27% 28%

Accounts receivable 33,053 50,960 49,830 46,160 46,344 Operating margin 14% 13% 16% 16% 16%

Inventories 114,781 134,888 131,897 122,184 122,669 Net margin 10% 10% 11% 11% 11%

Others 59,624 54,835 53,686 49,954 50,140

Current assets 294,383 286,392 279,150 232,785 255,390

Sales per share growth (5%) 44% (2%) (7%) 0%

LT investments - - - - - Sales growth (5%) 44% (2%) (7%) 0%

Net fixed assets 1,075,467 1,238,599 1,429,169 1,569,871 1,622,448 Net profit growth (10%) 35% 16% (8%) 1%

Total Assets 1,450,288 1,656,487 1,839,815 1,934,152 2,009,334 EPS growth (10%) 35% 16% (8%) 1%

Liabilities Interest coverage (x) 61.82 69.38 37.67 35.15 57.72

Short-term loans 148,851 102,268 102,268 102,268 82,268

Payables 204,739 270,191 264,200 244,744 245,714 Net debt to equity 17% 20% 27% 29% 24%

Others 34,963 57,277 57,277 57,277 57,277 Sales/assets 0.77 0.94 0.82 0.70 0.68

Total current liabilities 388,553 429,736 423,745 404,289 385,259 Assets/equity 1.56 1.66 1.72 1.74 1.68

Long-term debt 85,471 131,352 216,352 236,352 236,352 ROE 13% 16% 16% 14% 13%

Other liabilities 68,563 85,270 85,270 85,270 85,270 ROCE 14% 17% 18% 15% 14%

Total Liabilities 542,587 646,358 725,367 725,911 707,468

Shareholders' equity 847,223 938,926 1,028,075 1,109,753 1,194,906

BVPS 4.63 5.13 5.62 6.06 6.53


193



Sinopec Corp - H: Summary of FinancialsIncome Statement Cash flow statement


Revenues 1,345,052 1,913,182 2,634,625 2,385,530 2,377,818 EBIT 84,431 105,004 117,437 124,676 118,511

% change Y/Y (10%) 42% 38% (9%) (0%) Depr. & amortization 50,487 59,223 61,929 64,987 67,069

EBITDA 134,918 164,227 179,366 189,663 185,580 Change in working capital 15,571 -1,109 -19,421 -83 92

% change Y/Y 86% 22% 9% 6% (2%) Taxes -4027 -25689 -26947 -29341 -28001

EBIT 84,431 105,004 117,437 124,676 118,511 Cash flow from operations 152,075 170,333 130,010 157,505 156,558

% change Y/Y 221% 24% 12% 6% (5%)

EBIT Margin 3% 3% 2% 3% 2% Capex -112,875 -97,637 -121,320 -121,703 -70,963

Net Interest -7,105 -7,312 -10,656 -10,785 -9,567 Disposal/(purchase) 594 16,126 0 0 0

Earnings before tax 80,568 103,693 108,772 118,435 113,027 Net Interest -7,105 -7,312 -10,656 -10,785 -9,567

% change Y/Y 264% 29% 5% 9% (5%) Other - - - - -

Tax -16,084 -25,689 -26,947 -29,341 -28,001 Free cash flow 39,200 72,696 8,691 35,802 85,596

as % of EBT 20.0% 24.8% 24.8% 24.8% 24.8%

Net income (reported) 61,760 71,800 79,816 84,118 80,556 Equity raised/(repaid) - - - - -

% change Y/Y 117% 16% 11% 5% (4%) Debt raised/(repaid) -4,116 11,687 5,000 5,000 5,000

Shares outstanding 86,702 86,702 86,702 86,702 86,702 Other - - - - -

EPS (reported) 0.71 0.83 0.92 0.97 0.93 Dividends paid -13,559 -16,391 -20,241 -21,332 -20,428

% change Y/Y 117% 16% 11% 5% (4%) Beginning cash 7,008 8,728 17,008 10,458 29,929

Ending cash 8,750 17,004 10,458 29,929 100,096

DPS 0.18 0.21 0.23 0.25 0.24



Cash and cash equivalents 8,750 17,008 10,458 29,929 100,096 EBITDA margin 5% 4% 3% 4% 4%

Accounts receivable 26,592 43,093 59,343 53,732 53,559 Operating margin 3% 3% 2% 3% 2%

Inventories 141,611 156,546 215,578 195,196 194,565 Net margin 2% 2% 2% 2% 2%

Others 23,091 42,450 58,458 52,931 52,759

Current assets 201,280 260,229 344,969 332,919 402,111

Sales per share growth (10%) 42% 38% (9%) (0%)

LT investments - - - - - Sales growth (10%) 42% 38% (9%) (0%)

Net fixed assets 584,968 630,299 682,021 730,686 726,125 Net profit growth 117% 16% 11% 5% (4%)

Total Assets 877,842 995,154 1,133,606 1,174,765 1,243,479 EPS growth 117% 16% 11% 5% (4%)

Liabilities Interest coverage (x) 18.99 22.46 16.83 17.59 19.40

Short-term loans 58,898 17,019 17,019 17,019 17,019

Payables 97,749 132,528 165,830 151,186 150,777 Net debt to equity 42% 32% 31% 24% 11%



Long-term debt 108,828 136,465 141,465 146,465 151,465 ROE 18% 18% 18% 16% 14%

Other liabilities 56,742 71,915 71,915 71,915 71,915 ROCE 16% 19% 19% 19% 16%

Total Liabilities 478,989 544,786 621,655 595,052 599,168

Shareholders' equity 375,661 419,047 478,623 541,409 601,536

BVPS 4.33 4.83 5.52 6.24 6.94


194



Indian Oil Corporation: Summary of FinancialsIncome Statement Cash flow statementRs in millions, year end Mar FY10 FY11 FY12E FY13E Rs in millions, year end Mar FY10 FY11 FY12E FY13E FY14E

Revenues 2,711,105 3,288,532 3,871,018 3,648,493 EBIT 90,925 87,251 61,313 108,972 -

% change Y/Y (11.3%) 21.3% 17.7% (5.8%) Depr. & amortization 32,271 45,467 36,364 38,289 -Gross Margin 0.8% 0.5% 5.5% 7.5% Change in working capital - - - - -

EBITDA 123,196 132,718 97,678 147,261 Taxes - - - - -

% change Y/Y 62.1% 7.7% -26.4% 50.8% Others - - - - -

EBITDA Margin 4.5% 4.0% 2.5% 4.0% Cash flow from operations 27,565 22,331 -35,593 187,554 -

EBIT 90,925 87,251 61,313 108,972% change Y/Y 92.6% NM NM 77.7% Capex -131,123 -125,321 -80,916 -35,000 -

EBIT Margin 3.4% 2.7% 1.6% 3.0% Disposal/(purchase) 0 0 0 0 -

Net Interest 50,136 3,708 1,415 5,960 Free cash flow 45,569 -71,027 -51,354 158,415 -

Earnings before tax 141,061 90,959 62,729 114,932

% change Y/Y 225.9% -35.5% -31.0% 83.2% Equity raised/(repaid) 9,711 0 0 0 -Tax -46,020 -16,504 -12,546 -22,986 Debt raised/(repaid) -4,058 81,676 -230,956 -83,015 -

as % of EBT 32.6% 18.1% 20.0% 20.0% Other 0 0 0 0 -

Net income (reported) 102.2 74.5 45.2 82.8 Dividends paid -34,586 -25,196 -15,284 -28,003 -

% change Y/Y 246.5% -27.2% -39.3% 83.2% Beginning cash 7,980 13,151 12,944 14,239 -Shares outstanding 2,428 2,428 2,428 2,428 Ending cash 13,151 12,944 14,239 15,662 -

EPS (reported) 42.10 30.67 18.60 34.08 DPS 12.63 9.20 5.58 10.22 -

% change Y/Y 240.4% (27.2%) (39.3%) 83.2%


Rs in millions, year end Mar FY10 FY11 FY12E FY13E Rs in millions, year end Mar FY10 FY11 FY12E FY13E FY14E

Cash and cash equivalents 13,151 12,944 14,239 15,662 EBITDA margin 4.5% 4.0% 2.5% 4.0% -Accounts receivable 57,993 88,697 84,844 79,967 Operating margin 3.4% 2.7% 1.6% 3.0% -

Inventories 364,041 492,845 530,277 499,794 Net margin 3.8% 2.3% 1.2% 2.3% -

Others 158,886 238,877 243,411 248,035

Current assets 580,920 820,419 858,531 827,795

Sales per share growth (12.8%) 21.3% 17.7% (5.8%) -LT investments - - - - Sales growth (11.3%) 21.3% 17.7% (5.8%) -

Net fixed assets 628,497 708,351 591,071 587,781 Net profit growth 246.5% -27.2% -39.3% 83.2% -

Total Assets 998,753 1,144,028 1,085,028 1,065,956 EPS growth 240.4% (27.2%) (39.3%) 83.2% -

Liabilities Interest coverage (x) - - - - -Short-term loans 0 0 0 0 Net debt to total capital 22.7% 31.4% 14.4% 6.6% -

Payables - - - - Net debt to equity 41.3% 57.6% 20.9% 8.5% -

Others 447,517 593,134 510,522 497,092 Sales/assets 2.79 3.07 3.47 3.39 -

Total current liabilities 447,517 593,134 510,522 497,092 Assets/equity 2.42 2.14 2.16 1.38 -

Long-term debt 445,663 527,339 296,383 213,368 ROE 21.6% 14.1% 7.1% 11.1% -Other liabilities 47,561 63,366 68,384 77,579 ROCE 9.9% 8.6% 5.9% 10.9% -

Total Liabilities 493,224 590,705 364,767 290,947

Shareholders' equity 505,529 553,323 720,261 775,009

BVPS 208.21 227.90 296.65 319.20


195



Reliance Industries Ltd: Summary of FinancialsIncome Statement Cash flow statementRs in millions, year end Mar FY09 FY10 FY11 FY12E FY13E Rs in millions, year end Mar FY09 FY10 FY11 FY12E FY13E

Revenues 1,512,245 2,037,400 2,658,106 3,132,220 3,005,420 EBIT 181,123 199,480 239,228 263,330 299,254

% change Y/Y 13.3% 34.7% 30.5% 17.8% (4.1%) Depr. & amortization 56,510 109,460 141,208 128,925 141,424Gross Margin 27.3% 24.1% 23.1% 56.9% 58.6% Change in working capital -46,221 -143,128 25,257 -98,787 1,656

EBITDA 237,633 308,940 380,436 392,255 440,679 Taxes -12740 -31250 -44124 -60512 -70026

% change Y/Y 6.5% 30.0% 23.1% 3.1% 12.3% Others - - - - -

EBITDA Margin 15.7% 15.2% 14.3% 12.5% 14.7% Cash flow from operations 159,502 210,573 359,180 240,279 380,568

EBIT 181,123 199,480 239,228 263,330 299,254% change Y/Y 3.7% 10.1% 19.9% 10.1% 13.6% Capex -437,983 -219,210 -150,474 -175,500 -267,000

EBIT Margin 12.0% 9.8% 9.0% 8.4% 10.0% Disposal/(purchase) - - - - -

Net Interest -2,720 87,320 1,321 21,184 33,438 Free cash flow -278,481 -8,638 208,705 388,779 113,568

Earnings before tax 175,123 372,860 240,550 284,514 332,692

% change Y/Y -35.6% 112.9% -35.5% 18.3% 16.9% Equity raised/(repaid) 68,056 -116,128 -1,973 0 0Tax -29,190 -42,560 -47,834 -63,976 -74,406 Debt raised/(repaid) 398,046 -116,511 195,007 -42,682 -31,802

as % of EBT 16.7% 11.4% 19.9% 22.5% 22.4% Other - - - - -

Net income (reported) 152,492.60 158,180.00 192,715.20 220,537.76 258,286.67 Dividends paid -22,195 -24,286 -34,729 -34,729 -34,729

% change Y/Y -0.1% 3.7% 21.8% 14.4% 17.1% Beginning cash - - - - -Shares outstanding 2,749 2,978 2,981 2,981 2,981 Ending cash - - - - -

EPS (reported) 55.46 53.12 64.65 73.98 86.64 DPS 6.90 7.00 8.00 10.00 10.00

% change Y/Y 5.6% (4.2%) 21.7% 14.4% 17.1%


Rs in millions, year end Mar FY09 FY10 FY11 FY12E FY13E Rs in millions, year end Mar FY09 FY10 FY11 FY12E FY13E

Cash and cash equivalents 227,421 138,908 301,390 561,259 570,266 EBITDA margin 15.7% 15.2% 14.3% 12.5% 14.7%Accounts receivable 48,450 100,829 156,952 109,575 105,875 Operating margin 12.0% 9.8% 9.0% 8.4% 10.0%

Inventories 201,096 343,933 385,194 414,881 392,310 Net margin 10.1% 7.8% 7.2% 7.0% 8.6%

Others 110,494 107,409 137,273 139,952 142,699

Current assets 651,816 822,203 1,324,271 1,625,113 1,648,625

Sales per share growth 19.8% 24.4% 30.3% 17.8% (4.1%)LT investments - - - - - Sales growth 13.3% 34.7% 30.5% 17.8% (4.1%)

Net fixed assets 1,498,880 1,375,761 1,385,028 1,107,602 1,233,178 Net profit growth -0.1% 3.7% 21.8% 14.4% 17.1%

Total Assets 2,150,696 2,197,964 2,709,299 2,732,715 2,881,803 EPS growth 5.6% (4.2%) 21.7% 14.4% 17.1%

Liabilities Interest coverage (x) 87.36 - - - -Short-term loans 83,675 66,192 131,886 131,662 131,662 Net debt to total capital 35.2% 22.6% 10.6% -7.8% -10.7%

Payables - - - - - Net debt to equity 52.1% 36.9% 16.6% -11.9% -15.4%



Long-term debt 678,891 579,863 709,176 666,718 634,916 ROE 19.8% 16.5% 17.5% 17.3% 17.6%Other liabilities 0 0 0 0 0 ROCE 13.6% 12.0% 13.0% 12.6% 13.3%

Total Liabilities 1,246,399 1,178,870 1,526,391 1,369,924 1,316,253

Shareholders' equity 904,296 1,019,093 1,182,908 1,362,791 1,565,550

BVPS 328.91 342.20 396.81 457.16 525.17


196



Sasol: Summary of FinancialsProfit and Loss Statement FY10 FY11E FY12E FY13E FY14E Production FY10 FY11E FY12E FY13E FY14E

Sales 122,256 144,011 151,580 167,229 175,524 Vol bbl/d 190,669 199,667 224,768 249,864 274,852

EBITDA 30,651 38,263 42,574 50,923 56,370 Growth 3.5% 4.7% 12.6% 11.2% 10.0%

D&A 6,712 7,508 9,246 9,957 10,966 Secunda costs per barrel (45) (52) (54) (55) (58)

EBIT 23,939 30,754 33,328 40,966 45,404

Financing (782) (800) (900) (900) (900) Macro FY10 FY11E FY12E FY13E FY14E

Associates 217 279 302 371 653

PBT 23,372 30,231 32,728 40,435 45,155

Tax (6,985) (9,037) (9,493) (11,096) (12,219) Global GDP est 3.6 3.0 2.7 3.3 3.3

Minorities (446) (620) (674) (704) (733) Rand/USD (Sasol Year) 7.60 7.07 7.20 7.60 7.60

Net Profit 15,941 20,575 22,561 28,635 32,202 Oil Price Brent (Sasol Year) 74.50 92.80 100.00 100.00 102.00

Ave No Shares 595.80 598.00 598.00 598.00 598.00 Refining Margin 813.6% 926.0% 1084.0% 1098.5% 1098.5%

HEPS 2,656.67 3,440.63 3,772.72 4,788.39 5,385.01 Forecast Macro Effect on EBIT (9,776) 6,216 5,460 4,000 1,262

DPS 1,050.00 1,204.22 1,245.00 1,580.17 1,777.05 Oil Hedge gain/ (loss) - - - - -

CF/Share 4,569.78 5,680.31 6,890.37 8,042.04 9,175.40

Valuation FY10 FY11E FY12E FY13E FY14E

Balance Sheet FY FYE FYE FYE FYE

EV/ Sales 1.7 1.5 1.5 1.3 1.3

Fixed Assets 102,761 121,624 141,994 156,813 179,704 EV/EBITDA 6.7 5.7 5.3 4.3 3.9

Current Assets 53,723 60,390 62,585 67,123 69,529 EV/EBIT 8.5 7.1 6.7 5.3 4.8

Current Liabilities (22,869) (25,242) (26,067) (27,774) (28,679) EV/ Invested Capital 1.7 1.5 1.4 1.2 1.1

LT Liabilities -36,373 -45,379 -51,166 -48,720 -50,571 RoIC 14.8% 16.3% 15.3% 17.1% 17.0%

Net Assets 97,242 111,393 127,346 147,442 169,983 P/E 11.7 9.0 8.2 6.5 5.8

Invested Capital 120,406 143,563 165,302 182,952 207,345 FCF yield 2.7% -0.7% 0.7% 6.2% 4.4%

Net debt -902 -9,002 -14,550 -10,143 -10,843 Debt/ EBITDA 0.0 0.2 0.3 0.2 0.2

Net Working Capital 21,761 26,055 27,425 30,256 31,757 Interest Cover 58.5 29.2 27.9 35.7 36.7

Cash Flow FY FYE FYE FYE FYE

EBIT 23,939 30,754 33,328 40,966 45,404

D&A 6,712 7,508 9,246 9,957 10,966

Wcap (3,424) (4,294) (1,369) (2,831) (1,501)

Other - - - - -

Operating cash flow 27,227 33,968 41,204 48,091 54,869

Interest (1,053) (1,195) (1,146) (1,237) (3,089)

Dividends (5,360) (6,138) (7,044) (7,282) (9,243)

Tax (6,040) (9,037) (9,493) (11,096) (12,219)

Capex (16,108) (25,086) (29,167) (24,367) (33,358)

Trading Cash flow (813) (7,069) (5,394) 4,569 (537)

FCF before financing 5,181 122 2,844 12,998 9,943

Acquisition / disposals 0 0 0 0 1

Other 192 0 0 0 0

Change in Net Debt -1,813 -8,100 -5,548 4,407 -700


197



198



Analyst Certification: The research analyst(s) denoted by an “AC” on the cover of this report certifies (or, where multiple research analysts are primarily responsible for this report, the research analyst denoted by an “AC” on the cover or within the document individually certifies, with respect to each security or issuer that the research analyst covers in this research) that: (1) all of the views expressed in this report accurately reflect his or her personal views about any and all of the subject securities or issuers; and (2) no part of any of the research analyst's compensation was, is, or will be directly or indirectly related to the specific recommendations or views expressed by the research analyst(s) in this report.

Important Disclosures

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Explanation of Equity Research Ratings and Analyst(s) Coverage Universe: J.P. Morgan uses the following rating system: Overweight [Over the next six to twelve months, we expect this stock will outperform the average total return of the stocks in the analyst's (or the analyst's team's) coverage universe.] Neutral [Over the next six to twelve months, we expect this stock will perform in line with the average total return of the stocks in the analyst's (or the analyst's team's) coverage universe.] Underweight [Over the next six to twelve months, we expect this stock will underperform the average total return of the stocks in the analyst's (or the analyst's team's) coverage universe.] The analyst or analyst's team's coverage universe is the sector and/or country shown on the cover of each publication. See below for the specific stocks in the certifying analyst(s) coverage universe.

Coverage Universe: Lucas, Frederick G: BG Group (BG.L), BP (BP.L), Royal Dutch Shell A (RDSa.L), Royal Dutch Shell B (RDSb.L)

J.P. Morgan Equity Research Ratings Distribution, as of June 30, 2011

Overweight(buy)

Neutral(hold)

Underweight(sell)

J.P. Morgan Global Equity Research Coverage 47% 42% 11%IB clients* 50% 46% 32%

JPMS Equity Research Coverage 45% 47% 8%IB clients* 70% 64% 52%

*Percentage of investment banking clients in each rating category.For purposes only of FINRA/NYSE ratings distribution rules, our Overweight rating falls into a buy rating category; our Neutral rating falls into a hold rating category; and our Underweight rating falls into a sell rating category.

Equity Valuation and Risks: Please see the most recent company-specific research report for an analysis of valuation methodology and risks on any securities recommended herein. Research is available at http://www.morganmarkets.com , or you can contact the analyst named on the front of this note or your J.P. Morgan representative.

Equity Analysts' Compensation: The equity research analysts responsible for the preparation of this report receive compensation based upon various factors, including the quality and accuracy of research, client feedback, competitive factors, and overall firm revenues, which include revenues from, among other business units, Institutional Equities and Investment Banking.

Registration of non-US Analysts: Unless otherwise noted, the non-US analysts listed on the front of this report are employees of non-US affiliates of JPMS, are not registered/qualified as research analysts under NASD/NYSE rules, may not be associated persons of JPMS, and may not be subject to FINRA Rule 2711 and NYSE Rule 472 restrictions on communications with covered companies, public appearances, and trading securities held by a research analyst account.

Other Disclosures

J.P. Morgan ("JPM") is the global brand name for J.P. Morgan Securities LLC ("JPMS") and its affiliates worldwide. J.P. Morgan Cazenove is a marketing name for the U.K. investment banking businesses and EMEA cash equities and equity research businesses of JPMorgan Chase & Co. and its subsidiaries.

Options related research: If the information contained herein regards options related research, such information is available only to persons who have received the proper option risk disclosure documents. For a copy of the Option Clearing Corporation's Characteristics and Risks of Standardized Options, please contact your J.P. Morgan Representative or visit the OCC's website at http://www.optionsclearing.com/publications/risks/riskstoc.pdf

Legal Entities Disclosures U.S.: JPMS is a member of NYSE, FINRA,SIPC and the NFA. JPMorgan Chase Bank, N.A. is a member of FDIC and is authorized and regulated in the UK by the Financial Services Authority. U.K.: J.P. Morgan Securities Ltd. (JPMSL) is a member of the London Stock Exchange and is authorized and

http://www.optionsclearing.com/publications/risks/riskstoc.pdf

http://www.morganmarkets.com/

https://mm.jpmorgan.com/disclosures.jsp

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regulated by the Financial Services Authority. Registered in England & Wales No. 2711006. Registered Office 125 London Wall, London EC2Y 5AJ. South Africa: J.P. Morgan Equities Limited is a member of the Johannesburg Securities Exchange and is regulated by the FSB. Hong Kong: J.P. Morgan Securities (Asia Pacific) Limited (CE number AAJ321) is regulated by the Hong Kong Monetary Authority and the Securities and Futures Commission in Hong Kong. Korea: J.P. Morgan Securities (Far East) Ltd, Seoul Branch, is regulated by the Korea Financial Supervisory Service. Australia: J.P. Morgan Australia Limited (ABN 52 002 888 011/AFS Licence No: 238188) is regulated by ASIC and J.P. Morgan Securities Australia Limited (ABN 61 003 245 234/AFS Licence No: 238066) is a Market Participant with the ASX and regulated by ASIC. Taiwan: J.P.Morgan Securities (Taiwan) Limited is a participant of the Taiwan Stock Exchange (company-type) and regulated by the Taiwan Securities and Futures Bureau. India: J.P. Morgan India Private Limited, having its registered office at J.P. Morgan Tower, Off. C.S.T. Road, Kalina, Santacruz East, Mumbai - 400098, is a member of the National Stock Exchange of India Limited (SEBI Registration Number - INB 230675231/INF 230675231/INE 230675231) and Bombay Stock Exchange Limited (SEBI Registration Number - INB 010675237/INF 010675237) and is regulated by Securities and Exchange Board of India. Thailand: JPMorgan Securities (Thailand) Limited is a member of the Stock Exchange of Thailand and is regulated by the Ministry of Finance and the Securities and Exchange Commission. Indonesia: PT J.P. Morgan Securities Indonesia is a member of the Indonesia Stock Exchange and is regulated by the BAPEPAM LK. Philippines: J.P. Morgan Securities Philippines Inc. is a member of the Philippine Stock Exchange and is regulated by the Securities and Exchange Commission. Brazil: Banco J.P. Morgan S.A. is regulated by the Comissao de Valores Mobiliarios (CVM) and by the Central Bank of Brazil. Mexico: J.P. Morgan Casa de Bolsa, S.A. de C.V., J.P. Morgan Grupo Financiero is a member of the Mexican Stock Exchange and authorized to act as a broker dealer by the National Banking and Securities Exchange Commission. Singapore: This material is issued and distributed in Singapore by J.P. Morgan Securities Singapore Private Limited (JPMSS) [MICA (P) 025/01/2011 and Co. Reg. No.: 199405335R] which is a member of the Singapore Exchange Securities Trading Limited and is regulated by the Monetary Authority of Singapore (MAS) and/or JPMorgan Chase Bank, N.A., Singapore branch (JPMCB Singapore) which is regulated by the MAS. Malaysia: This material is issued and distributed in Malaysia by JPMorgan Securities (Malaysia) Sdn Bhd (18146-X) which is a Participating Organization of Bursa Malaysia Berhad and a holder of Capital Markets Services License issued by the Securities Commission in Malaysia. Pakistan: J. P. Morgan Pakistan Broking (Pvt.) Ltd is a member of the Karachi Stock Exchange and regulated by the Securities and Exchange Commission of Pakistan. Saudi Arabia: J.P. Morgan Saudi Arabia Ltd. is authorized by the Capital Market Authority of the Kingdom of Saudi Arabia (CMA) to carry out dealing as an agent, arranging, advising and custody, with respect to securities business under licence number 35-07079 and its registered address is at 8th Floor, Al-Faisaliyah Tower, King Fahad Road, P.O. Box 51907, Riyadh 11553, Kingdom of Saudi Arabia. Dubai: JPMorgan Chase Bank, N.A., Dubai Branch is regulated by the Dubai Financial Services Authority (DFSA) and its registered address is Dubai International Financial Centre - Building 3, Level 7, PO Box 506551, Dubai, UAE.

Country and Region Specific Disclosures U.K. and European Economic Area (EEA): Unless specified to the contrary, issued and approved for distribution in the U.K. and the EEA by JPMSL. Investment research issued by JPMSL has been prepared in accordance with JPMSL's policies for managing conflicts of interest arising as a result of publication and distribution of investment research. Many European regulators require a firm to establish, implement and maintain such a policy. This report has been issued in the U.K. only to persons of a kind described in Article 19 (5), 38, 47 and 49 of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 (all such persons being referred to as "relevant persons"). This document must not be acted on or relied on by persons who are not relevant persons. Any investment or investment activity to which this document relates is only available to relevant persons and will be engaged in only with relevant persons. In other EEA countries, the report has been issued to persons regarded as professional investors (or equivalent) in their home jurisdiction. Australia: This material is issued and distributed by JPMSAL in Australia to "wholesale clients" only. JPMSAL does not issue or distribute this material to "retail clients". The recipient of this material must not distribute it to any third party or outside Australia without the prior written consent of JPMSAL. For the purposes of this paragraph the terms "wholesale client" and "retail client" have the meanings given to them in section 761G of the Corporations Act 2001. Germany: This material is distributed in Germany by J.P. Morgan Securities Ltd., Frankfurt Branch and J.P.Morgan Chase Bank, N.A., Frankfurt Branch which are regulated by the Bundesanstalt für Finanzdienstleistungsaufsicht. Hong Kong: The 1% ownership disclosure as of the previous month end satisfies the requirements under Paragraph 16.5(a) of the Hong Kong Code of Conduct for Persons Licensed by or Registered with the Securities and Futures Commission. (For research published within the first ten days of the month, the disclosure may be based on the month end data from two months prior.) J.P. Morgan Broking (Hong Kong) Limited is the liquidity provider/market maker for derivative warrants, callable bull bear contracts and stock options listed on the Stock Exchange of Hong Kong Limited. An updated list can be found on HKEx website: http://www.hkex.com.hk. Japan: There is a risk that a loss may occur due to a change in the price of the shares in the case of share trading, and that a loss may occur due to the exchange rate in the case of foreign share trading. In the case of share trading, JPMorgan Securities Japan Co., Ltd., will be receiving a brokerage fee and consumption tax (shouhizei) calculated by multiplying the executed price by the commission rate which was individually agreed between JPMorgan Securities Japan Co., Ltd., and the customer in advance. Financial Instruments Firms: JPMorgan Securities Japan Co., Ltd., Kanto Local Finance Bureau (kinsho) No. 82 Participating Association / Japan Securities Dealers Association, The Financial Futures Association of Japan. Korea: This report may have been edited or contributed to from time to time by affiliates of J.P. Morgan Securities (Far East) Ltd, Seoul Branch. Singapore: JPMSS and/or its affiliates may have a holding in any of the securities discussed in this report; for securities where the holding is 1% or greater, the specific holding is disclosed in the Important Disclosures section above. India: For private circulation only, not for sale. Pakistan: For private circulation only, not for sale. New Zealand: This material is issued and distributed by JPMSAL in New Zealand only to persons whose principal business is the investment of money or who, in the course of and for the purposes of their business, habitually invest money. JPMSAL does not issue or distribute this material to members of "the public" as determined in accordance with section 3 of the Securities Act 1978. The recipient of this material must not distribute it to any third party or outside New Zealand without the prior written consent of JPMSAL. Canada: The information contained herein is not, and under no circumstances is to be construed as, a prospectus, an advertisement, a public offering, an offer to sell securities described herein, or solicitation of an offer to buy securities described herein, in Canada or any province or territory thereof. Any offer or sale of the securities described herein in Canada will be made only under an exemption from the requirements to file a prospectus with the relevant Canadian securities regulators and only by a dealer properly registered under applicable securities laws or, alternatively, pursuant to an exemption from the dealer registration requirement in the relevant province or territory of Canada in which such offer or sale is made. The information contained herein is under no circumstances to be construed as investment advice in any province or territory of Canada and is not tailored to the needs of the recipient. To the extent that the information contained herein references securities of an issuer incorporated, formed or created under the laws of Canada or a province or territory of Canada, any trades in such securities must be conducted through a dealer registered in Canada. No securities commission or similar regulatory authority in Canada has reviewed or in any way passed judgment upon these materials, the information contained herein or the merits of the securities described herein, and any representation to the contrary is an offence. Dubai: This report has been issued to persons regarded as professional clients as defined under the DFSA rules.

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General: Additional information is available upon request. Information has been obtained from sources believed to be reliable but JPMorgan Chase & Co. or its affiliates and/or subsidiaries (collectively J.P. Morgan) do not warrant its completeness or accuracy except with respect to any disclosures relative to JPMS and/or its affiliates and the analyst's involvement with the issuer that is the subject of the research. All pricing is as of the close of market for the securities discussed, unless otherwise stated. Opinions and estimates constitute our judgment as of the date of this material and are subject to change without notice. Past performance is not indicative of future results. This material is not intended as an offer or solicitation for the purchase or sale of any financial instrument. The opinions and recommendations herein do not take into account individual client circumstances, objectives, or needs and are not intended as recommendations of particular securities, financial instruments or strategies to particular clients. The recipient of this report must make its own independent decisions regarding any securities or financial instruments mentioned herein. JPMS distributes in the U.S. research published by non-U.S. affiliates and accepts responsibility for its contents. Periodic updates may be provided on companies/industries based on company specific developments or announcements, market conditions or any other publicly available information. Clients should contact analysts and execute transactions through a J.P. Morgan subsidiary or affiliate in their home jurisdiction unless governing law permits otherwise.

"Other Disclosures" last revised June 13, 2011.

Copyright 2011 JPMorgan Chase & Co. All rights reserved. This report or any portion hereof may not be reprinted, sold or redistributed without the written consent of J.P. Morgan. #$J&098$#*P

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