Global Refining Outlook 2015-16 Margins Under Pressure Until Industry a

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Asia Pacific Equity Research18 November 2014

Global Refining outlook 2015-16Margins under pressure until industry addresses over-capacity, we prefer US>Asia>Europe

Regional Petrochemicals and Refining

See page 78 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.

Refiners operate in a global market with little product differentiation,which means that unit costs remain the main profitability driver. Key costs include crude feedstock, energy and logistics which are unitized by scale and availability/utilization (bigger and more reliable the better). Assuming the US crude oil export embargo remains in place, US refiners will remain the most advantaged given cheaper crude feeds, lower energy costs and a product deficit market. Asian refiners have scale and a growing market to sell to but their competitive landscape is deteriorating given the startup of mega-refineries in ME. European refiners lack any competitive advantage, so their profitability will continue to languish until there is very material capacity rationalization. We introduce JPM’s proprietary Global Refining Model, which forecasts regional margins based on supply/demand scenarios that can be used to quantify the required capacity retirements.

US will retain its structural cost advantage with lower crude oil/gas prices, while products are priced globally based on higher priced Brent. Additionally, with growing logistics businesses being valued at higher multiples and monetized through MLPs, US refiners are capturing greater value from the sum of their parts. The risks are an end to the crude export ban, narrower crude price differentials if Brent is lower for longer and declining domestic supplies if the lower oil price curtails rates of reinvestment. Top Picks: PSX/MPC.

Asia remains the main growth driver for global product demand. However, GRMs are likely to be under pressure due to new capacity not only in the region but also in ME, which will likely grab export market share from Asian refiners. New condensate splitting capacity startup will also pressure middle distillates margins where Asian refiners have the most exposure. Near term, a narrowing of the Brent-Dubai spread maydrive profitability lower. Preferred: HPCL/Caltex/JX Holdings/RIL/ Sinopec. Least Preferred: S-Oil/SPC/Idemitsu Kosan.

Aside from old age and lack of scale, European refineries will continue to struggle given relatively expensive crude, high energy costs, high/ inflexible labor costs, tough emission standards/product specs, high plant closure costs and declining end-market demand. The European refining system will also be under attack from rising volumes of refined product exports from ME and as India. Utilization rates will continue to fall which mandates further capacity rationalization. Preferred: RD Shell/Novatek/Tupras. Least Preferred: Galp/Rosneft/PKN.

JPM Global Refining Model: We introduce our proprietary model based on JPM’s latest global refining capacity data and product demand outlook which we use to predict regional GRMs. In the most bearish case, our model shows that unless there is sizable incremental capacity retirement, Asia and NW Europe margins may reach historical trough levels by 2016 ($0.3/bbl) and 2017 (c$0.8/bbl) respectively.

Asia

Samuel Lee, CFA AC

(852) 2800-8536

[email protected]

Bloomberg JPMA SLEE <GO>

J.P. Morgan Securities (Asia Pacific) Limited

Scott L Darling AC

(852) 2800 8578

[email protected]

Bloomberg JPMA DARLING <GO>


Parsley Rui Hua Ong AC

(852) 2800-8509

[email protected]


Yuji Nishiyama AC

(81-3) 6736-8617

[email protected]

JPMorgan Securities Japan Co., Ltd.

Neil Gupte AC

(91-22) 6157 3592

[email protected]

J.P. Morgan India Private Limited

Shaun Cousins AC

(61-2) 9003-8623

[email protected]

J.P. Morgan Securities Australia Limited

Europe

Fred Lucas AC

(44-20) 7134-5943

[email protected]

Bloomberg JPMA LUCAS <GO>

J.P. Morgan Securities plc

US

Phil Gresh, CFA AC

(1-212) 622-4861

[email protected] JPMA GRESH <GO>

J.P. Morgan Securities LLC

Latam

Felipe Dos Santos AC

(55-11) 4950-3796

[email protected]

Banco J.P. Morgan S.A.

CEEMEA

Andrey Gromadin, CFA AC

(7-495) 967-1037

[email protected]

Bloomberg JPMA GROMADIN <GO>

J.P. Morgan Bank International LLC

Neeraj Kumar AC

(971) 4428-1740

[email protected]

JPMorgan Chase Bank, N.A., Dubai Branch

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Samuel Lee, CFA(852) [email protected]

Parsley Rui Hua Ong(852) [email protected]

Table of ContentsSummary ...................................................................................3

Global choices to play the theme............................................6

Introducing the JPM Global Refining model ........................11

Results – 5 possible outcomes for margins ........................14

US – Cost advantage, logistics value creation ....................21

LatAm – Moving Ahead with Capacity Expansion...............29

Asia – Flat or lower GRMs likely for 2015.............................31

China – Managing over-supply with slowing demand ........34

Japan – Can Japan remain an independent market? ..........37

India – Overcapacity remains; prefer marketing..................40

Australia – domestic refining shifting to product imports..42

Europe – refiners’ graveyard .................................................43

Russia – Slow upgrading in changing tax environment .....49

Poland/Turkey – Fuel importers............................................52

Appendix I: Downstream glossary of terms.........................54

Appendix II: Investment Thesis, Valuation, Risks ...............64

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Summary

This note is the first comprehensive update to our research piece on global downstream (Global refining - a long and painful sunset for many, 8 September 2011). In that note, we concluded:

“….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…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.”

Since then refining has been a very bad industry. Over three years on our outlook for refining remains as grim as ever. The only exception has been and remains US refining, which has experienced a renaissance due to unexpectedly strong growth in shale oil, hence depressing the cost of US crude feedstock and shale gas, and thus depressing plant energy costs. Europe has been bad and, as we show, will remain the most challenged region for refiners.

Refiners operate in a global market with very little product differentiation, which means that unit costs remain the main profitability driver. Key costs include crude feedstock, energy and logistics, which are unitized by scale and availability/ utilization (the bigger and more reliable the better). Assuming US crude oil exports remain constrained, US refiners will remain the most advantaged given access to cheaper crude (mainly WTI), lower energy costs (from shale gas) and a product deficit market. Asian refiners have scale and a growing market to sell to but their competitive landscape is deteriorating given the startup of mega-refineries in ME. European refiners lack any competitive advantage, so their profitability will continue to languish until there is material capacity rationalization.

Therefore, we believe tough times lay ahead for refiners outside of the US. 2014 refining margins have sunk to the lowest levels since 2010 (Asia) and 2003 (Europe), while the US remains the only sole bright spot due to cost-advantaged crude. The last refining renaissance occurred between 2003 and 2007, when a combination of persistently strong global product demand growth, hurricanes and MENA supply disruptions pushed crude prices up by 186%, while oil product prices rallied harder. For every $1/bbl increase in crude, global margins rose $0.1/bbl, peaking at $7.9/b in 2007. Today, they are languishing around $5/bbl. After adjusting for inflation and rising energy costs, this is a very weak number indeed.

In September 2011, we predicted tough years ahead for

refiners....in November 2014, we

predict much the same with the exception of the US.

Low unit cost is the biggest

profit driver for refiners given

that they sell a globally fungible product with little differentiation.

2014 refining margins have been

disappointing for both Asia and

Europe – the lower oil price has not helped.

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Figure 1: NW Europe cracking and Asia hydrocracking margins - 2014 near historical lows

$/bbl

Source: Bloomberg, BP, IEA, J.P. Morgan estimates.

Recently, J.P. Morgan Commodities Research published their latest outlook on global oil supply/demand and prices. Global oil demand growth in 2014 will likely remain depressed (at around 620 kbd) on the back of declining demand in many DM countries with the US being the exception. They expect European demand to slow in 2015 and be almost flat in 2016 Y/Y. Consequently, given growth in most other DM, OECD demand should be less of a drag on the global growth rate over the next two years. EM demand is expected to grow by 1 million bpd in 2014, with similar rates forecasted for the next 2 years.

In terms of oil prices, Commodities Research is now forecasting an average of $80/bbl for Brent in Q4 2014, with the possibility of going as low as $65 in 1Q 2015 if OPEC does not cut production. For 2015, the full year average is now forecast to be $82 (previously $115) and for 2016 $87.75 (previously $120) per barrel. The lower oil price deck forecast is mainly a function of continued growth in shale oil in the US and higher spare capacity within OPEC vs. previous expectations.

Over the next 2 years, global refining capacity growth is set to outpace demand growth by 1.5 million bpd, driven by capacity growth in Asia (+1.4 million bpd, 39% of total) and the Middle East (+1 million bpd, 29% of total). A potential 1.5 million bpd product surplus is untenable – we believe marginal refiners will likely be forced to close. Most of the new Chinese capacity will be expansions rather than greenfield plants, as Chinese product demand growth has slowed down significantly from previous years (YTD diesel demand is flat Y/Y). Therefore, many previously planned new projects by Sinopec and Petrochina have been delayed, but expansions are still going ahead as gasoline demand remains relatively robust. Mega-refineries in the ME will make up the bulk of the new capacities there. They will compete for market share with both European and Asian refiners in their home markets.

In order to identify the amount of closure necessary to shore up margins and to identify capacity at risk and forecast margins through 2017 under different scenarios (e.g. upside or downside demand surprise, or US policy shift), we have developed aproprietary Global Refining Model. Based on historical correlations, we can calculate future regional refining margins based on forecast operating rates, which are in turn a function of our forecast regional refining supply/demand. We note that while in the most bearish case of no further capacity rationalization aside from the ones we have identified, refiners are not likely to operate at negative margins and therefore, run rates will be cut even if plants are not permanently retired.

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NW Europe cracking margin Singapore hydrocracking margin USGC cok margin (Rhs)

JPM Commodities Research latest forecast for 2015/16 global

oil demand growth is c900 kbd

for both years, higher than 620 kbd demand growth for 2014.

New Brent oil price forecast is

$82/bbl and $87.75/bbl for 2015/16 respectively.

We now forecast global product

surplus of 1.9mbd for 2015-16, a

situation which we think must enforce further capacity

rationalization.

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Figure 2: 2015 to 2016 net capacity additions - majority from Asia and Middle East

Source: Bloomberg, BP, IEA, J.P. Morgan estimates.

Figure 3: Persistent capacity growth, although not as high as the 1970s, comes to a market already suffering from a surpluskbd

Source: J.P. Morgan estimates.

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2015 to 2016 scheduled net capacity additions: +3.6 mbd (global)

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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

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Global choices to play the theme

By region we list JPM analysts’ most / least preferred names to play our refining theme. Given the relatively advantaged status of US refining, this is the only region where we have two preferred plays (no least preferred). We note that analyst recommendations are set according to their broader local coverage universe. This is why some of the least preferred names may still be rated Neutral.

US Preferred

Philips 66 (OW) – While shares have underperformed recently on concerns about the impact of lower oil prices on Chemicals, we still see many value levers to pull, as PSX has the most diversified portfolio in the group and the highest potential for more growth outside of refining (Midstream and Chemicals). We see a strong backlog of MLP drop down opportunities (to PSXP) within Midstream. As a result of its diversity, we also see the lowest downside risk at PSX in a scenario where the crude export ban gets lifted (~15% EPS downside, group average ~26%).

Marathon Petroleum (OW) – We see MPC as a solid way to play the most favorable themes in US refining, given that all of MPC’s exposure is in the US central corridor, which we expect to remain crude cost advantaged. MPC also has several refining projects under way to drive controllable EBITDA growth. Finally, MPC is diversifying its portfolio into higher-multiple logistics and retail businesses (~22% of 2016E EBITDA), both of which have non-macro levers for growth and significant MLP opportunities.

Latam ideas

Petrobras (N) – We rate Petrobras Neutral due to: 1) uncertainties on short-term production and a miss on the 2014 production guidance; 2) FX devaluation impact on fuel import costs and leverage; 3) lack of clarity on fuel price readjustments and a specific price readjustment policy that would allow prices to be readjusted according to international parity.

Ecopetrol (N) – We rate Ecopetrol Neutral due to: 1) small reserve lifetime of ~7 years, amidst low replacement ratios; 2) non-compelling trading multiples of 12.7x P/E and 2.4x P/B for 2015, compared to global peers selling at 11.5x P/E and 1.4x P/B. We would avoid exposure to Ecopetrol as we consider the company’s main challenge remains long-term sustainability of reserves that currently reaches eight years, the ratio has decreased to 6-7 years currently. We highlight Ecopetrol’s initiatives to boost its reserve level on four fronts: exploration, improvement of recoverable factor, development of unconventional potential and acquisition. However, we see no single source as enough to deliver the likely volumes required.

Asia Preferred

HPCL (OW) – With our expectation of a more benign crude price environment, we highlight that the state owned oil marketing firms are likely to see a quicker roll off of subsidy losses, and a gradual expansion in diesel marketing margins. We expect the private players to take an 8-10% share as a consequence. Leverage is likely to decline quicker than earlier anticipated, with a consequent reduction in interest costs as well.

Caltex (OW) – CTX is the only publicly listed refinery operator in Australia. CTX is undergoing a repositioning and one we believe will increasingly be considered by a broader range of investors including consumer focused investors due to its

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increasingly stable earnings profile as refining becomes less influential (given recent closure of the Kurnell refinery), and the opportunity to participate in the early stage of a business improvement programme.

JX Holdings (N) – JX Holdings already has a dominant market share and can be distanced from concerns about market realignment uncertainty. In addition, we believe it is best positioned to benefit from the margin improvement that is likely to accompany consolidation measures by other refiners. Even if petroleum product supply capacity continues to decline, JX Holdings can expand through its non-refining businesses, which include upstream oil operations and a copper mine development. JX Holdings is currently struggling to expand copper mine and petrochemical operations and the share price is low, but we believe this is a short term issue.

Reliance Industries (N) – In light of the weaker Y/Y refining outlook in 2015, we currently do not have any OW stocks in our coverage and therefore RIL is preferred on a relative basis. We believe RIL will fare better relative to peers in a weak GRM environment due to its scale and complexity. Also, unlike other Asian refiners where most of the crude is sourced from the ME, RIL buys its crude from wherever it can secure an attractive price. Finally we believe significant capacity expansion in itspetchems businesses over the next 12-18 months will help RIL offset declines in refining earnings.

Sinopec (N) – Sinopec is China's largest refiner with refining capacity at 5.7 million bpd (43% domestic capacity share), the largest in Asia and one of the largest in the world. Sinopec’s refineries are mainly located in China's southeast coastal area, middle and lower reaches of the Yangtze River and North China, where they have good access to high growth demand centres. Refining profitability has been weak with cuts to oil product pricing and moderation in oil demand growth, although the company continues to shift product mix toward gasoline (yield was c46% in 2013, an increase from c37% in 2011), which still exhibits strong volume growth (gasoline sales rose 11% y/y last year) and margins.

Asia Least Preferred

S-Oil (UW) – We believe with the emergence of new mega-refineries from the ME, traditional export refiners in South Korea, Taiwan and Singapore will be under increasing margin pressure. 63% owned by Saudi Aramco, S-Oil is a simple refinery with large exposure to PX, a product on which we are also bearish. Despite fairly robust Asian GRMs for most of 2013-14, S-Oil refining business has been loss-making on an OP basis for the last 7 quarters. In the past, S-Oil was seen as a dividend play, but we think that is also at risk now given our forecast of FY14 losses, weak business environment outlook and increasing capital expenditure for 2017-18 for expansion/upgrading projects. We value S-Oil on 0.6x 2015 BV as we forecast 2015-16 ROE to only average around 6%.

Sinopec Shanghai Petrochemical (UW) – Sinopec Shanghai Petrochemical (SPC) is one of the top five largest refineries owned by Sinopec Corp (51% shareholding). Although its refineries are upgraded for high oil product specification largely directed into the Shanghai market, it also is exposed to commodity chemicals which have seen a collapse in profitability this year. This also reflects lower utilization at its refinery due to a moderation in oil product demand and lower refining margins as well as weak chemical margins. It also suffers limited product grade portfolio/feedstock flexibility to partly mitigate the current chemical environment. Yet SPC shares have outperformed in 2014 reflecting anticipation of the HK-SH connect program (SPC-H currently trades at a c30% discount to SPC-A). However, with the program’s start date now in question and the company’s fundamentals

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increasingly challenged, we continue to view the shares as overvalued against regional peers.

Idemitsu Kosan (N) – Idemitsu’s position in its domestic market is stable, but it is moving forward with a US$9 billion refinery/petrochemical plant project in Nghi Son, Vietnam. Returns on this investment are at risk from a slump in refining margins in Asia, which we have identified as a possibility. Idemitsu plans to refine Kuwaiti crude oil in Vietnam and sell petroleum products in the local market, but if the price of crude increases sharply it is unclear whether Idemitsu could pass on the cost to sales prices. Petroleum products are much more of a necessity good in emerging markets than they are in developed economies, and if large increases in crude prices were passed on directly to sales prices it could cause political unrest.

Europe Preferred

RD Shell (OW) – RD Shell continues to shrink its refinery portfolio. In 2003, it had interests in 55 refineries. If it sells its Fredericia refinery in Denmark, it will have downsized to just 27 refineries by 2015. At the same time, RD Shell has repositioned its refining exposure away from Europe, the most challenged region. In 2005, 46% of its total net refining capacity was in Europe; by next year this could be just 26%. This portfolio shift has also skewed its refinery exposure more to the US, the more advantaged region, to 36% 2015E versus 23% in 2005. The performance of its core refining portfolio continues to improve, most notably Motiva, RD Shell’s 50:50 JV with Saudi Aramco which owns 3 US refineries. At YE 2013, refining capital employed was around $33bn or just under 15% of group capital employed. We expect refining capital employed to shrink in absolute and percentage terms as working capital efficiency improves and capital expenditure trends down (given fewer assets and better capital discipline). Combined with reduced costs and higher plant availability / utilization, this will drive this sub-segment’s improvement in ROACE from around 2% in 2013 (given -3% in Merchant Refining and 6% in Integrated Refining & Marketing Value Chain) and lift through cycle free cash flow generation. This will ultimately help RD Shell to better cover its dividend – a key consideration for investors.

Europe Least Preferred

Galp (UW) – Galp has evolved from a pure play Portugal-focused refining company(pre-IPO in 2006) into an Integrated name driven by its exploration successes in Brazil (and more recently in Mozambique). Galp still retains an above sector average exposure to European downstream – which accounts for 13% of our Galp SOTP of €16.6/share. We believe that the outlook for this business remains challenging (downstream reported operating losses in 2 of the 3 quarters in 2014) – an ongoing negative for Galp's equity story, in our view.

Russia Preferred

Novatek (OW) – Novatek has the lowest refining exposure in the Russian oil and gas universe. The company operates the Pur gas condensate stabilization plant (upgraded to 11 mn tons) in West Siberia and the Ust Luga gas condensate processing facility (6 mn tons) located on Baltic Sea, where it refines gas condensate mainly into naphtha and light products. Given a light oil feedstock at Ust Luga, the company will not have to upgrade the facility if there is higher taxation on heavy products.

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Russia Least Preferred

Rosneft (UW) – Although Rosneft has invested more than $17 bn in the refining segment capex for the last five years, the key upgrade projects are yet to start. Roughly half of the spending was allocated on building new Tuapse refinery and terminal. We believe that the rest of the money was mainly spent on light product quality improvements. We believe that the company is likely to spend no less than $25 bn on the refining segment (excluding Far East green field projects) within the next four years. New unit launch delays and capex overrun risks are substantial.

CEEMEA Preferred

Tupras (OW) – We are OW on Tupras due to: 1) Potential for margin improvement by more than 150bps due to the Residuum Upgrade Project (RUP); 2) Tupras’s capex cycle is nearing its end, so increasing dividend potential; 3) Tupras’s key demand drivers are still intact, i.e. low autos penetration (120 cars per 1,000 person vs. average 450 for EU); 4) Increase in fuel demand. Diesel demand consumption grew by 7% in 2013 and > 5% in 1H14. There was an increase in gasoline consumption by 1-2% in 2013 and 1H 2014.

CEEMEA Least Preferred

PKN (UW) – We forecast an EBITDA increase over 2014-17 of PLN1.6bn, c20%, below company guidance, mainly on a lower contribution from the downstream business. We forecast Petrochemicals will be the biggest contributor to 2014-17 EBITDA (c42%), with retail (c27%) in line with company guidance and upstream benefiting from the recent acquisitions in Canada. We are cautious on shale production in Poland. We believe low refinery margins will remain a drag on downstream performance. We think downstream margins are likely to remain under pressure and forecast average model downstream margin of $9.9/bbl, below guidance of $11/bbl over 2014-17. Downstream business contributes c70% of 2014-17E EBITDA (LIFO). In our view, capital discipline remains key as the energy and upstream businesses get an over-proportionate share of development capex (c60%)vs. limited contribution (c6%) to 2014-17E EBITDA.

Table 1: Global refining valuations

Preferred Ticker Rating Price PT MktCap PE (x) PB (x) EV/EBITDA ROE (%) Yield (%)(LC) (LC) USD mil FY14e FY15e FY14e FY15e FY14e FY15e FY14e FY15e FY14e FY15e

Phillips 66 PSX OW 71.78 96.00 41,007 11.1 13.3 1.9 1.8 7.7 9.6 16.8% 13.4% 2.6% 3.3% Marathon Pet. MPC OW 92.38 118.00 26,698 11.6 13.9 2.4 2.4 6.1 6.5 21.0% 16.9% 2.0% 2.3% HPCL HPCL.BO OW 549.85 690.00 3,020 10.5 8.5 1.2 1.1 7.4 6.1 11.4% 12.9% 2.9% 3.5% Caltex CTX.AX OW 31.45 28.44 7,429 33.3 17.6 NM NM 10.5 8.3 13.7% 16.8% 1.3% 2.7% RD Shell RDSa.L OW 2,202 2,500 218,105 9.5 13.6 1.1 1.1 5.0 5.4 12.3% 8.2% 5.4% 5.5% Novatek NVTKq.L OW 98.13 130.00 29,795 12.4 8.7 2.6 2.1 8.2 7.6 22.2% 27.0% 0.2% 0.3% Tupras TUPRS.IS OW 49.70 57.00 5,551 18.4 9.2 1.8 1.6 13.8 6.5 11.3% 18.6% 4.5% 7.0% JX Holdings 5020.T N 436.50 480.00 9,333 12.3 6.9 0.4 0.4 11.0 7.7 3.7% 5.7% 4.1% 4.1% Petrobras PBR N 9.96 17.00 64,962 7.8 9.2 0.5 0.6 7.2 8.8 6.0% 5.9% 7.0% 3.0% Reliance Ind. RELI.BO N 985 1,080 51,637 12.6 11.9 1.7 1.5 8.1 7.5 14.5% 13.6% 1.1% 1.2% Sinopec 0386.HK N 6.22 7.00 69,545 8.3 9.7 0.9 0.9 4.0 4.1 11.5% 9.1% 5.1% 4.3% YYYLeast Preferred Ticker Rating Price PT MktCap PE (x) PB (x) EV/EBITDA ROE (%) Yield (%)

(LC) (LC) USD mil FY14e FY15e FY14e FY15e FY14e FY15e FY14e FY15e FY14e FY15eS-Oil 010950.KS UW 42,500 29,000 4,347 (124.0) 15.9 0.9 0.9 25.1 9.1 (0.7%) 5.6% 2.2% 2.5% Shanghai Pet. 0338.HK UW 2.43 1.50 3,384 144.0 27.6 1.2 1.1 23.5 17.4 0.8% 4.1% 0.2% 1.1% PKN PKN.WA UW 45.45 38.00 5,757 (6.4) 14.2 0.8 0.8 (33.6) 6.6 (12.3%) 5.8% 3.3% 3.5% Rosneft ROSNq.L UW 4.98 5.00 52,725 7.6 4.2 0.7 0.6 4.1 4.3 14.2% 13.3% 2.8% 6.0% Galp GALP.LS UW 11.07 11.50 11,634 33.9 29.5 1.4 1.4 10.8 10.2 5.3% 6.1% 3.1% 3.1% Ecopetrol EC N 24.81 30.00 51,004 9.7 12.5 2.1 2.3 5.1 6.6 17.2% 17.9% 8.6% 6.4% Idemitsu Kosan 5019.T N 2,018 2,100 694 10.7 7.9 0.4 0.4 7.8 7.3 4.0% 5.2% 2.5% 2.5%

Source: J.P. Morgan estimates, Bloomberg. Priced as of Nov 15, 2014. Note: FY14e represents end-March 15 for HPCL, JX Holdings, Reliance Ind., and Idemitsu Kosan.

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In order to expand the remit of this report for investors, we also include a schematic which shows a broader set of choices within the global refining theme. We include potential beneficiaries in the Engineering & Construction space as well as plant software and hardware suppliers (Figure 4).

Figure 4: Exposure to the refining space aside from refiners


GLOBAL INVESTMENT THEME Refining capacity growth

SOFTWARE & HARDWARE PROVIDERSEuropeAveva Group [AVV LN]IMI [IMI LN]Invensys [ISYS LN]KBC Advanced Technologies [KBC LN]Rotork [ROR LN]Siemens [SIE GY]Weir Group [WEIR LN]

USAAspen Technology [AZPN US]Dresser-Rand [DRC US]Honeywell International [HON US]

EPC PROVIDERSEurope & North AmericaAmec [AMEC LN]Chicago Bridge & Iron [CBI US]Fluor Corp [FLR US]Jacobs Engineering [JEC US]Petrofac [PFC LN]SNC-Lavalin Group Inc [SNC CN]Technip SA [TEC FP]Tecnicas Reunidas SA [TRE SM]

Asia ex-JapanDaelim Industrial Co. Ltd [000210 KS]Daewoo E&C [047040 KS]GS E&C [006360 KS]Hyundai E&C [000720 KS]Samsung Engineering [028050 KS]Worley Parsons Ltd [WOR AU]

JapanChiyoda Corp [6366 JP]JGC [1963 JP]

INDIRECT beneficiaries

Developed EuropeERG [ERG IM]Neste Oil [NES1V FH]Saras [SRS IM]

Developing Europe / RussiaNovatek [NVTK LI]PKN Orlen [PKN PW]Rosneft [ROSN LI]Tupras [TUPRS TI]

Asia ex-JapanBangchak Petroleum [BCP TB]BPCL [BPCL IN]Caltex Australia Ltd [CTX AU]Essar Oil [ESOIL IN]HPCL [HPCL IN]Reliance Industries [RIL IB]S-OIL Corp [010950 KS]SK Innovation [096770 KS]

PR CHINAShanghai Petro. [338 HK]Sinopec [386 HK]

JAPANIdemitsuKosan [5019 JT]JX Holdings [5020 JT]Showa Shell [5002 JT]Tonen General [3402 JT]

REGIONAL WINNERS

ADVANTAGED PLAYERSUSAAlon USA Energy [ALJ US]Delek US Holdings [DK US]HollyFrontier Corp [HFS US] Marathon Petroleum Corp [MPC US]Phillips 66 [PSX US]Tesoro Corp [TSO US]Valero Energy Corp [VLO US]Western Refining [WNR US]

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Introducing the JPM Global Refining model

Our proprietary model forecasts refining margins under multiple scenarios, based on a baseline, bull and bear case supply/demand outlook. The demand forecast is provided by JPM Commodities research, and tracks global oil product demand on a country-level basis, based on factors like GDP, oil price elasticity, tax policy and structural factors like nuclear capacity and vehicle sales. Refining capacity forecasts are based on company announcements and our conversations with industry contacts on capacity expansion plans. We note that startups from 2017 onwards are more susceptible to further delays and cancellations. While we adjust for this in our model to give our most realistic assessment, history has shown that forecasting new refining capacity more than 2 years out has a high degree of uncertainty.

Model methodology

1. Track global refinery capacity additions by country and project

2. Track historical refinery throughput by region

3. Using #1 and #2, compute historical utilization rate by region and establish correlation to margins

4. Forecast oil product demand by country and region through 2025

5. Forecast global refinery maintenance through 2025

6. Forecast throughput for price-insensitive markets (US, ME, China)

7. Forecast throughput and utilization rates for rest of world based on demand growth and competitive positioning through 2025

8. Using forecast utilization rates, derive margins using historical correlation

9. Identify required amount of capacity closures or expansion delays needed to balance market

Model limitations

1. Requires manual judgment of US, ME and Chinese refinery utilization

2. While near-term refinery maintenance forecasts are based on reported maintenance activity, longer term maintenance forecasts are derived based on a % of refining capacity

3. Assessment on impact of crude differentials on US margins is done separately

4. Margin forecasts assume typical yields for a USGC coking refinery, NW Europe cracking refinery, and SG hydrocracking refinery, and do not adjust for evolving complexity over time. The model does not adjust for the grade of crude being processed

5. Condensate splitters are treated like CDU units in the model. Realistically, output from condensate splitters will have much higher naphtha and gasoline yields

Our bottom-up approach highlights the amount of refining

capacity closures needed to

balance aggressive world-scale refinery startups, the regions

most at risk, and what happens

to regional margins under bull, bear and base case demand

scenarios.

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Theory behind the model

1. Strong historical correlation between refinery utilization and margins

The relationship is especially significant for marginal refineries in Northwest Europe and Asia ex China, that are typically the first to cut runs when margins are poor. Utilization rates, in turn, are driven by end-user demand and available refining capacity. In NW Europe, light sweet cracking margins have only averaged $6/b to $7/b (annual basis) twice since 1992. This occurred in 2008, when utilizations were 84%, and in 2012, when a spate of capacity closures lifted European utilizations to 82% (Figure 5). Meanwhile, Asian utilizations have declined steadily from 2008 highs.

Figure 5: 1992 to 2014 Europe utilization vs. NWE light sweet cracking marginUtilization rates (x-axis), $/bbl (y-axis)

Source: Bloomberg, BP, IEA, J.P Morgan estimates.

Figure 6: 1992 to 2014 Asia ex-China utilization vs. Singapore medium sour hydrocracking marginUtilization rates (x-axis), $/bbl (y-axis)

Source: Bloomberg, BP, IEA, J.P Morgan estimates.

2. Not all refineries are created equal – separating price-insensitive refiners

In a low margin environment, complex Middle Eastern refineries with ready access to ME crude will run harder than simple Asian or European refineries. Saudi Arabia’s new Jubail and Yanbu mega refineries (400 kbpd each) are already sufficient to offset 1 year’s worth of global demand growth. Similarly, some Indian refiners (eg. Essar, RIL) are so complex they can process 10 to 13 API crude, yet produce negligible fuel oil. US refiners are well positioned to withstand a hostile margin environment due to cheap domestic crude and higher output of diesel and gasoline. Lastly, Chinese refineries have the home advantage of being located in the hub of global demand growth.

The aforementioned refineries are less price-sensitive, and likely to run at high utilizations even if demand disappoints. As the world's ability to absorb product output is limited by demand growth, the least competitive refiners will be forced to lower utilization. In 2012 to 2014, we saw 3.6 million bpd of global capacity closures (32% Europe, 17% Japan, 6% Australia), with run cuts in Singapore, Taiwan and South Korea in times of margin pressure. Going forward, our model embeds the assumption that utilization rates (and margins) in the US, Middle East and China are likely to outperform, with the rest of the world competing for the remaining market share.

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Figure 7: Net capacity additions look set to outpace demand growth through 2017

LHS: kbd, RHS: $/bbl

Source: J.P. Morgan estimates. Highlighted portion shows margin stress – further closures and delays needed.

3. Adjusting the world ex-US, ME and China for complexity and policy

Simply deducting price-insensitive throughput from global throughput and allocating the rest to remaining regions based on capacity weight is insufficient. In regions ex-US, ME and China, a secondary layer of inequality exists, based on factors like refining complexity, tax, country-specific policy/subsidies and NOC versus IOC versus independent ownership. Based on our understanding of the conditions in each region, as well as our assessment of current refining margins and competitive positioning in each refinery, we allocate remaining throughput using an adjusted capacity weight.

Figure 8: Refinery ownership - Europe has most of world’s IOC capacity. NOCs not always driven by economics

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Results – 5 possible outcomes for margins

Table 2: Summary of key assumptions for the 5 scenarios

Scenario # 2014-17 avg annual demand growth

Retirements incremental to those already announced

1. Margin crash +0.88 mbd +0.0 mbd2. Barely balanced +0.88 mbd +3.4 mbd3. +ve demand shock +1.3 mbd +3.4 mbd4. -ve demand shock +0.47 mbd +3.4 mbd5. US policy shift +0.88 mbd +3.4 mbd

Source: J.P. Morgan. See Page 16 for details of the individual scenarios.

Scenario 1: Margin crash

Assuming trend demand growth of 880 kbd yoy on average between 2014-17, we expect scheduled capacity growth of 1.9 mbd yoy on average will overwhelm product markets and flip most refiners ex-US into loss-making territory by 2017. Weighted average global margins will decline to $2.6/b, the lowest level since 2002.

Scenario 2: Barely balanced

3.4 mbd of capacity closures or cancelled expansion plans, on top of those already announced, help balance the market and avert a 2017 margin crash. Assuming trend demand growth of 880 kbd yoy, these closures/delays will lift European and Singapore margins to near 2014 levels, while US margins remain strong.

Scenario 3: +ve demand shock

Stronger demand growth in China, ME and US lift global demand growth to 1.3 mbd yoy on average, 48% above the 880 kbd baseline. US margins rise to the highest levels since 2007, while European and Singapore margins rise by $0.3/bbl to $1/bbl. Even with stronger demand growth, incremental capacity closures or expansion delays mentioned in Scenario #2 are still necessary to sustain refining profitability.

Scenario 4: -ve demand shock

Even with the incremental capacity closures, if demand growth disappoints by 47% (+470 kbd yoy instead of +880 kbd yoy baseline), Singapore margins will struggle to breakeven by 2017, while European margins decline to the lowest level since 2002. US margins will falter, but remain near multi-year highs.

Scenario 5: US policy shift

We attach a very low probability for meaningful volumes of US crude to hit global markets by 2017. The policy shift scenario assumes an aggressive 1 mbd of US condensate exports by 2017, versus our baseline of 250 kbd of condensate exports. Our balances indicate that this shift will be insufficient to meaningfully diminish US crude surplus and significantly damage US refiners' advantaged position.

Table 3: Results – even US margins will fall in the Margin Crash (base case) scenario with Europe/Asia suffering the most$/bbl

USGC coking margin NW Europe cracking margin Singapore hydrocracking marginScenarios 2013 2014E 2015E 2016E 2017E 2013 2014E 2015E 2016E 2017E 2013 2014E 2015E 2016E 2017E

#1 8.1 8.9 8.8 8.0 7.0 4.1 2.1 1.9 1.5 0.8 2.7 1.2 0.9 0.3 -0.7#2 8.1 9.3 9.2 9.5 9.5 4.1 2.1 1.9 2.3 2.2 2.7 1.2 0.9 1.4 1.3#3 8.1 9.8 10.0 10.5 10.5 4.1 2.1 2.2 2.8 2.9 2.7 1.3 1.3 2.0 2.3#4 8.1 8.9 8.5 8.5 8.5 4.1 2.1 1.5 1.6 1.3 2.7 0.9 0.3 0.4 0.1#5 8.1 9.3 9.1 9.0 8.0 4.1 2.1 1.9 2.3 2.2 2.7 1.2 1.1 1.5 1.4


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Conclusion: Of the 5 scenarios listed in Table 1, margins are most likely to average slightly above scenario 2, which assumes 3.4 million bpd of capacity delays/ retirements, on top of those already announced, will occur by 2017 (see Table 4 and Table 5 for list of announced expansions and closures). A positive demand surprise (global growth of +1.3 mbd yoy, instead of +0.88 mbd yoy baseline) would lift US and Asian margins the most, though Europe would also benefit. Meanwhile, a negative demand surprise (global growth of +0.47mbd yoy, versus +0.88 mbd baseline) could be most destructive for European and Asian margins. We believe that in reality, the outcome will be somewhere between Scenario #1 and #2, or between 0-3.4 mbd of incremental retirements.

Table 4: List of global capacity additions (>100 kbd), 2014 to 2016Kbd

Year Refinery Capacity Operator Country

2014 Quanzhou 240 Sinochem China2014 Pengzhou 200 PetroChina China2014 Yangzi 160 Sinopec China2014 Yanbu 400 Aramco/ Sinopec Saudi Arabia

2014 Total 1,0002015 Abreu e Lima 230 Petrobras Brazil2015 Zhuhai Baota 100 Zhuhai Baota China2015 Huabei 100 CNPC China2015 Jiujiang 100 Sinopec China2015 Hainan 100 Sinopec China2015 Cuddalore 130 NOC / TIDCO / Tata Petrodyne India2015 Paradip 300 IOC India2015 Ruwais 417 ADNOC UAE

2015 Total 1,4772016 Comperj 165 Petrobras Brazil2016 Huizhou 200 CNOOC China2016 Zhenhai 240 Sinopec China2016 Shanghai Gaoqiao 140 Sinopec China2016 Nassiriyah 300 SCOP Iraq2016 Missan 150 Oil Ministry Iraq2016 Kochi 121 BPCL India2016 El Palito refinery 140 PDVSA Venezuela

2016 Total 1,456


Table 5: List of global capacity retirements, 2014 to 2016Kbd

Year Refinery Capacity Owner Region

2014 Tokuyama -120 Idemitsu Kosan Asia ex CN2014 Muroran, Hokkaido -180 Nippon (JX Holdings) Asia ex CN2014 Kawasaki, Tokyo Bay Japan -67 TonenGeneral Asia ex CN2014 Wakayama West Japan -38 TonenGeneral Asia ex CN2014 Kurnell, Sydney Australia -135 Caltex Asia ex CN

2014 Total -5402015 Kaohsiung, Taiwan -200 CPC Asia ex CN2015 Gela, Sicily -105 ENI Europe2015 Milford, Haven -135 Murphy Oil Europe2015 Bulwer Island, Australia -118 BP Asia ex CN

2015 Total -5582016 Shuaiba -200 KNPC Middle East

2016 Total -200TBD Tobangao, Philippines -96 RD Shell Asia ex CNTBD Lytton, Australia -109 Chevron (Caltex) Asia ex CNTBD Szazhalombatta, Hungary -160 MOL EuropeTBD Mongstad, Norway -205 Statoil / RD Shell EuropeTBD Cressier, France -65 Petroplus Europe

Total unconfirmed date -635


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Scenario 1: No additional capacity retirements

Between 2010 and 2014, global net capacity additions have grown by a steady +1% yoy to +1.5% yoy. In 2015 and 2016, a larger than usual proportion of expansions will come from Latin America, most notably the +230 kbd Abreu e Lima refinery in Brazil, of which 115 kbd (phase 1) is >95% complete, with the remaining 115 kbd expected to be commissioned by end 2015(Figure 9). The Latam additions will add to Atlantic surplus. Another big contributor to new refining capacity is the ME, with 3 new plants starting up during 2014-15 (2 in Saudi Arabia and 1 in UAE).

Figure 9: Scheduled net capacity additions and retirements

kbd


Given that we expect refinery capacity growth to outpace refined product demand growth by c1mbd in 2014-17, SG hydrocracking margins could very well end up in negative territory if there are no further cuts in Asian capacity. The prognosis is very much similar in Europe where NW Europe cracking margin will barely breakeven at $0.8/b by 2017 if there are no further capacity cuts. While we highlight up to 635 kbd of potential incremental retirements in Table 5, these retirements are yet to be confirmed but could be accelerated if margins remain weak.

Figure 10: Worse case scenario – without further capacity retirements, margins in the world ex-US could collapse as early as 2017

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Largest capacity growth aspirations 2014-2016 located in Asia and Middle East -

NOC sponsored.....

JPM estimates 3.4 mbd must be closed or delayed by 2017 to raise global

utilisation rates to 78%.....

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Scenario 2 (base case): 3.4 million bpd of closures (barely) balance the world

Based on our analysis and assuming trend demand growth, 3.4 million bpd of additional closures or delays to refining capacity expansions over the next two years will help avert the 2017 margin crash seen in Figure 10 and support margins around 2014 levels. In both 2016 and 2017, 800 kbd of capacity will need to be retired or delayed per year in Europe, and 900 kbd per year in Asia.

Figure 11: Capacity closures and delays to expansion plans help support margins$/bbl


Asia accounts for 44% of 2013 to 2017 global net capacity additions, while Europe only accounts for 2%. We identify Asia and Africa (2017) as the most likely regions for closures and delays to expansion plans, while European closures, though required, will be limited by labor unions and the fact that IOCs like RD Shell have already retired or sold a lot of capacity in the region (see page 43).

Figure 12: Scheduled net capacity additions and retirementskbd


In RD Shell’s Q3 2014 results conference call, Simon Henry (CFO) indicated that the group is reviewing its global distillation capacity and may close one of three CDUs at its Bukom refinery in Singapore (total capacity 462 kbd). Figure 13 shows the relative complexity of refineries in Asia. While many countries have refineries with below average complexity (eg. PNG, North Korea, Bangladesh, Indonesia), those that have captive markets or are state run are unlikely to shutter anytime soon. In Figure 14, we identify regions with relatively high refining capacities that mayface margin pressure or threat of closure, with Singapore and Taiwan under the most pressure.

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Figure 13: Refining complexity by country in AsiaIndex: higher = more complex, better margins

Source: Bloomberg, Wood Mackenzie, company data, J.P. Morgan

Note: Based on universe of 220 Asian refineries totaling 32 mbd of CDU capacity.

Figure 14: 2014 select Asian refining capacities (kbd)

Source: Bloomberg, Wood Mackenzie, company data, J.P. Morgan

Scenario 3 & 4: 3.4 million bpd closures, +ve/ -ve demand surprise

While the +2-3 million bpd yoy demand growth phase of the commodity supercycle is well behind us, over the next 3 years we are still likely to see +600 kbd to +1mbd yoy of demand growth.

Figure 15 shows historical global demand growth, along with our bull and bear demand scenarios. Assuming 3.4 million bpd of delays/ additional closures, a bear demand scenario will push Singapore margins into negative territory by 2016 (negligible impact on USGC), while a positive demand surprise will help European and Singapore margins stay near 2014 levels (Figure 16 to Figure 19). If demand continues to disappoint, more than an additional 3.4 million bpd of capacity will need to be delayed or shuttered.

Figure 15: Yoy global demand growth (kbd)

Source: J.P. Morgan estimates. Light blue bar denote forecast

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Figure 16: Capacity weighted world average margin ($/bbl)

Source: J.P. Morgan estimates.Note: Baseline assumes 3.4 mbd of additional closures/delays by 2017

Figure 17: USGC heavy sour cracking margin ($/bbl)


Figure 18: NW Europe light sweet cracking margin ($/bbl)


Figure 19: Singapore medium sour hydrocracking margin ($/bbl)


Scenario 5: US export policy shift

We view a full reversal in crude export policy and a removal of the Jones Act requirement as unlikely before 2017, but attach a slightly stronger likelihood of +1mbd of condensate exports by 2017, which we have incorporated into scenario 5. Our baseline assumes 250 kbd of condensate exports by 2016, so the “US policy shift” scenario is significantly more aggressive. Even so, we view +1mbd of condensate exports as insufficient to significantly diminish US surplus. Overall, the lift in condensate exports will be insufficient to significantly damage US refining profitability. Cheap condensate will mostly go to Asia, giving a slight boost to margins for refiners processing condensate.

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World scheduled capacity vs. demand growth (kbd, yoy)

Figure 20: Global


Figure 21: United States


Figure 22: North America ex-US


Figure 23: South and Central America


Figure 24: Asia-ex China


Figure 25: China


Figure 26: Europe


Figure 27: Middle East


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US – Cost advantage, logistics value creation

Phil GreshAC

(1-212) 622 4861

[email protected]

J.P. Morgan Securities LLC

2014 Overview: US enjoys a structural cost advantage with lower crude oil and natural gas prices, while products are priced on the global markets based on higher priced Brent crudes. Additionally, with growing logistics businesses being valued at higher multiples and monetized through the MLP structure, US refiners are capturing greater value from the sum of their parts.

2015-16 Key Issues/Risks: Potential crude export ban lift, narrower crude differentials if Brent is lower for longer, lower absolute oil prices reduce US crude supply, oversupply in global refining weighing on product prices.

Key Stock Picks: PSX, MPC.

Overview

US cost advantages allow for sustainable margin benefit versus global peers. A refinery buys a globally traded commodity input (crude oil) and converts it into a basket of globally traded commodity outputs (gasoline, diesel, etc). Thus, a refiner’s gross margin is a function of the price it pays for crude relative to the revenues it can obtain for the products that it yields, net of transportation costs. Within this framework, the US has recently developed two major competitive advantages vs.global peers as a result of the shale oil & gas revolution: (1) increased access to abundant domestically sourced crude oil, reducing the amount of crude that has to be purchased at a global price plus transportation costs; and, (2) lower natural gas operating costs. We believe that these advantages are sustainable, with the degree of the crude input cost benefit contingent, to some degree, on the existence of the crude export ban (discussed later).

Within the US, the biggest margin differentiator, in our view, is how close a refinery is to where the crude is produced (shorter distance equals lower transport costs), with certain regions more advantaged than others. Product yields are also important. Global product pricing is typically based on (currently higher) international crude costs and related transportation costs, allowing cost advantaged US producers to make a healthy spread to global product pricing. That said, we are somewhat cautious that product yields could tighten as more product tries to find a home in international markets, where soft demand and capacity increases could limit

further US market share gains in export markets without weighing on pricing.

Figure 28: Refining margin framework highlights US costs advantages

Source: J.P. Morgan (Green = Positive, Red = Negative).

Transportation costs and quality differentials drive long-term crude pricing/differentials. We believe that the main factors driving regional crude differentials will be transportation costs and crude quality (i.e. light versus heavy) differentials. For our base case scenario, where the crude export ban is not lifted, the chart below summarizes our key assumptions for transportation cost driven crude differentials, as well as a table with our forecasts.

Figure 29: Transportation costs between key US regions

$/bbl


Some of the key longer term differentials that we would point out are Brent/LLS at $3-4/bbl (we use $3.50/bbl), LLS/WTI at $4-6/bbl (we use $4.50/bbl in the near term, driven by tighter capacity at Cushing), and thus Brent/WTI at ~$7-9/bbl (we use $8/bbl). Note that we also provide a forecast for Houston (HLS) at a $1.50/bbl discount to LLS based on pipeline transportation costs. Next, we have WTI/Bakken at ~$7/bbl, which places Brent/Bakken at ~$15/bbl, in line with rail economics. On the West Coast, we have Brent/ANS at $1/bbl, which implies ANS/Bakken at ~$14/bbl (similar to rail economics to California). For Maya, we assume an

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$11.50/bbl quality discount to LLS (recently in the $10-15/bbl range), with a $15/bbl spread between Maya and WCS based on transportation cost differentials to the Gulf Coast. Finally, while WTI Midland is currently at a large discount to WTI Cushing, we assume it normalizes over time (by 2016) to ~$1/bbl.

Table 6: J.P. Morgan Crude Differential Forecasts$/bbl

2011 2012 2013 2014E 2015E 2016E

Brent/LLS -0.96 -0.12 1.31 2.74 2.75 3.50LLS/HLS n/a n/a 3.05 2.40 1.50 1.50LLS/WTI 17.20 17.57 9.36 4.05 4.50 4.50Brent/WTI 16.24 17.45 10.67 6.79 7.25 8.00Brent/Bakken 13.00 22.74 15.55 13.64 14.25 15.00WTI/Bakken -3.24 5.29 4.88 6.85 7.00 7.00Brent/ANS 1.30 0.54 0.92 1.51 1.00 1.00ANS/Bakken 11.70 22.20 14.63 12.13 13.25 14.00LLS/Maya 13.58 12.17 10.04 11.97 11.50 11.50Maya/WCS Cushing 19.28 27.46 23.97 13.84 15.00 15.00WTI Cushing/Midland 0.53 4.06 1.72 8.40 4.50 1.00

Source: Platts and J.P. Morgan estimates. N/A means that Platts did not have this crude

price historically.

Light crude outlet valves suggest significant oversupply less likely in 2015. One big question that remains with respect to US crude input cost advantages is whether there will be light crude oversupply, which could lead to a “blow out” (significant widening) of crude differentials. We believe that there are still several outlets available (estimated at ~1.75mmbpd at year-end 2014E) to absorb US light sweet crude production growth (estimated at ~1.75mmbpd cumulatively in 2015-16E for API 35+ crudes) before the market becomes over saturated.

By region, the largest is the US Gulf Coast (950 kpbd), followed by Eastern Canada (325 kbpd), the US West Coast (175 kbpd), the US East Coast (125 kbpd) and the Mid-Continent (75 kbpd). This does not include other crude exchange/swap/export opportunities (100+ kbpd). This displacement can come in several forms, including: 1) replacing foreign imports in US and Canadian refineries; 2) investment in new light crude processing and condensate splitter capacity; 3) replacing light sour/medium crudes; 4) condensate exports and other crude exchanges/swaps.

Table 7: Light sweet crude and condensate outlets, end-2014Ekbd

Region Potential Commentary

Gulf Coast 950 kbd ~75 kbpd of import displacement

~100 kbpd in higher utilization rates

~220 kbpd in new light capacity (VLO, Flint Hills)

~100 kbpd of condensate splitters

~250 kbpd of minimally processed condensate exports

~200 kbpd through displacement of light sour/medium

blending

Eastern Canada 325 kbd ~275 kbpd displacement of foreign light imports by US

exports

~50 kbpd displacement of Eastern Canadian offshore

(exported elsewhere)

West Coast 175 kbd ~75 kbpd displacing non-Canadian, non-Hawaii foreign

lights

~100 kbpd in higher runs and medium displacement

East Coast 125 kbd ~125 kbpd displacement of non-Canadian foreign lights

Mid-Continent 75 kbd ~75 kbpd in higher runs (~25kbpd) and capacity

increases (~50kbpd)

Swaps/Other

Exports

100 kbd ~100 kbpd opportunity for crude exchanges/swaps (e.g.

Mexico)

Total 1750 kbd

Source: CAPP, EIA and J.P. Morgan estimates. Note: light sweet crude (35+ API).

Logistics Value Creation Opportunities

MLPs have typically led to cash inflows for refiners…

HFC (then Holly Corp.) was the first of the major U.S. refiners to create an MLP structure for its logistics assets in 2004, receiving a ~9.5x multiple, lower than the ~12.5x-22.5x multiples received by refiners in subsequent years. Holly’s MLP creation was followed several years later by TSO in 2011 (12.7x), MPC in 2012 (13.6x), and PSX (16.2x) and VLO (16.2x) in 2013. All valuations exclude additional value from GP distribution rights. The creation of the MLP structures typically have resulted in the receipt of a combination of an equity interest in the LP and cash representing a portion of the of the IPO proceeds. Cash received from MLP creation has been utilized by refiners to fund debt reduction (TSO), dividends (MPC), and share repurchases (HFC).

Table 8: MLP creation history - large US refiners$ in millions

Date Parent/MLPAsset Value EBITDA Multiple

Cash Rec’d

Principal Cash Use

Jul-04 HFC/HEP 288 30 9.7x 126 BuybackApr-11 TSO/TLLP 670 53 12.7x 330 Debt Red.Oct-12 MPC/MPLX 1,424 105 13.6x 203 DividendJul-13 PSX/PSXP 1,219 75 16.2x 0 N/ADec-13 VLO/VLP 955 59 16.2x 0 N/A

Avg. 13.7x

Source: Company reports and J.P. Morgan estimates.

Note: Valuations excludes value of future GP distribution rights.

23




…with further dropdowns also creating cash inflows and capturing value…

Each company in our refining group has dropped additional assets down to the MLP level subsequent to the initial IPO. HFC underwent dropdowns roughly annually through 2012, with seven in total, while TSO has performed five in three years. MPC’s two dropdowns have consisted of stakes in a joint venture entity between MPC and MPLX (the MPLX’s vast majority of MPLX’s current asset base). The most recently created MLPs, PSXP and VLP, have undergone two and one dropdowns in 2014, respectively, using cash raised from the initial IPO (as equity only was used in the initial dropdown). Valuation of subsequent dropdowns have averaged ~9.5x, well below that of initial dropdowns, which could be due to the fact that subsequent drops having a growing IDR burden, requiring lower multiples to remain accretive.

…while each company still has significant opportunities for further dropdowns

In order to compare each company’s future dropdown potential and the effect it theoretically could have on their financials, we examine the forecasted future dropdowns for MPLX, PSXP, TSO, and VLO per J.P. Morgan MLPs analyst Jeremy Tonet. We make several assumptions designed to present the companies on an apples-to-apples comparison basis (but not reflecting a realistic scenario), whereby all dropdowns from 2014-2024 are paid in cash to the parent company. We examine future dropdown value simply as a percentage of 2013 market capitalization, with MPLX and PSXP showing the highest potential. We note that HFC was not included in the analysis (HEP Not Covered by J.P. Morgan), but that HEP is the most mature of the refining group’s MLP entities and is currently maintaining a focus on organic growth.

Figure 30: Several MLP’able opportunitiesEBITDA Multiple


MLP Opportunities exist in several areas

We see further upside potential from the MLP structure not only in logistics, but also other areas like fuels distribution (e.g. WNR/CST) and chemicals (e.g. WLK).

Table 9: MLP post-IPO dropdown history – large US refiners$ in millions

DateParent/

MLP AssetAsset Value EBITDA Multiple

Jul-05 HFC/HEP Lovington and Artesia intermediate feedstock pipelines

82 10 8.2x

Mar-08 HFC/HEP Pipeline and tankage assets 180 20 9.0x

Jun-09 HFC/HEP Lovington to Artesia pipeline 34 N/A N/A

Aug-09 HFC/HEP Tulsa unloading facilities 18 N/A N/A

Apr-10 HFC/HEP Additional Tulsa assets 93 N/A N/A

Nov-11 HFC/HEP Ed Dorado, Cheyenne assets 340 N/A N/A

Apr-12 TSO/TLLP Martinez crude marine terminal 75 8 9.4x

Jul-12 HFC/HEP 75% of UNEV Pipeline 315 N/A N/A

Sep-12 TSO/TLLP Long Beach marine terminal and LA short-haul pipelines

210 22 9.5x

Nov-12 TSO/TLLP Anacortes rail unloading facility 180 19 9.5x

May-13 MPC/MPLX 5% of Pipe Line Holdings 100 11 9.5x

Jun-13 TSO/TLLP Carson logistics assets (first portion)

640 63 10.2x

Dec-13 TSO/TLLP Carson logistics assets (remainder)

650 70 9.3x

Mar-14 PSX/PSXP Gold Line System, Medford Spheres

700 68 10.4x

Mar-14 MPC/MPLX 13% of Pipe Line Holdings 310 31 10.0x

Jul-14 VLO/VLP McKee Crude System, Three Rivers Crude System, Wynnewood Products System

154 15 10.0x

Oct-14 PSX/ PSXP 1

Bayway and Ferndale rail unloading facilities, Houston

340 33 10.0x

Avg 9.5x

Source: Company reports and J.P. Morgan estimates.1 EBITDA and multiple represents only rail unloading facilities.

Crude Export Ban Analysis

Why does the US have a crude export ban?

The ban on US crude oil exports began as a reaction to the oil embargo in the early 1970s and later was put into law in 1975 as part of the Energy Policy and Conservation Act (EPCA). The primary goals of EPCA were to increase energy production and supply, reduce energy demand, provide energy efficiency, and give the executive branch additional powers to respond to disruptions in energy supply. Most notably, the EPCA established the Strategic Petroleum Reserve (SPR), the Energy Conservation Program for Consumer Products, and Corporate Average Fuel Economy regulations.

Who can change export policy?

This EPCA instills the president with the authority to restrict the export of, “coal, petroleum products, and natural gas or petrochemical feedstocks,” as well as crude oil if s/he determines such action to be in the national interest. The EPCA vests the secretary of

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commerce and the Department of Commerce’s Bureau of Industry and Security (BIS) with the responsibility to implement any rules stipulated in the legislation, but mandates that both the president and the secretary of commerce shall, when imposing restrictions, ensure that the national interest is left “uninterrupted or unimpaired.” Therefore, ultimately the president retains the power to allow exports of all energy forms and to restrict exports of energy currently allowed if the president finds it necessary due to national circumstances. Only three presidents have exercised this authority (Presidents Reagan, Bush and Clinton) on five different occasions. These export exceptions are discussed next.

What exports are allowed?

Since the ban was put into place, the Commerce Department has given some exceptions to the crude export ban. Specifically, crude oil can be exported: 1) to Canada, but only for consumption within Canada; 2) from Alaska’s Cook Inlet, with certain restrictions around route of travel; 3) in conjunction with refining or for the exchanges of oil in the SPR; 4) if it is Californian heavy, not in excess of 25kbpd; 5) if it is foreign oil being re-exported (e.g. Canadian crude passing through the US) and can be proven to not have been co-mingled with US crude; 6) if it is provided for in certain international agreements; 7) if it is consistent with presidential findings under certain legal statutes.

Why are we talking about crude exports if the US is still a net importer?

As discussed throughout this report, while the US is still importing crude oil, it is also approaching self-sufficiency on light sweet crudes, while still importing medium and heavy crudes. This is important because the US refining system is still dependent on imported heavy barrels based on the optimal configuration of its crude slates, particularly in the Gulf Coast.

Figure 31: Light sweet self-sufficiency close, but medium/heavy imports still necessaryKbd

Source: EIA.

Whether the US export ban is lifted or not would likelynot impact the US importation of heavy barrels in a meaningful way in the near term, as reconfiguring these refineries would require significant investment that likely will not happen with the potential overhang of the export ban going away, leading to lower returns on such investments. A good example of this would be condensate splitters, which are now looking less favorable based on the recent BIS ruling that “processed condensate" can now be exported.

Energy security, gasoline prices and the economy arekey topics of debate

Growing domestic crude oil and condensate production has recently led to a re-opening of the crude export ban debate. In fact, in late January 2014, the US Senate held a full sub-committee hearing on the topic, the first such discussion in 25 years. While the crude export ban has been hotly debated, we do not believe this is an issue that will be resolved in 2014, even if additional producers are given approval to export condensate, given the highly political nature of the debate.

A few overarching themes related to the debate, which are not particularly surprising, are: 1) the potential impact on domestic gasoline prices if crude exports were allowed (would it really lead to lower prices?); 2) the need for US energy security and energy independence; and, 3) the potential benefits to the US economy in terms of job creation and trade flows if the ban is removed; and 4) the need to consider other policy changes that should also be taken into account, such as the Jones Act (discussed later). As mentioned above, white papers have been written by several think tanks on the topic of the crude oil export ban; and, the EIA has been tasked with doing its own analysis on some elements of this debate as well, which we assume the government will wait on before moving forward with the debate.

Background on BIS “processed condensate” ruling

On the evening of June 24th, it was reported by the Wall Street Journal that two companies (Enterprise and Pioneer) received a letter of approval from the Department of Commerce's Bureau and Industry and Security (BIS) to export “processed condensate”. This ruling initially led to significant confusion about what “processed condensate” actually is, which has since been clarified, to some degree. As discussed in the recent Brookings Institute report that has been made publicly available, the BIS rulings are based on the fact that the processed condensate has been “processed though a distillation tower” in the CDF. While there are many different distillation-based equipment and technologies, at its essence a distillation tower involves the use of heat,

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Canadian Light All Other Light Medium Heavy

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evaporation, and condensation to fractionate the lease condensate into separate petroleum products. From a regulatory perspective, these uses support the rulings that the distillation in the CDF produces a product (processed condensate) which is distinctly different from the lease condensate feedstock. Finally, the BIS apparently based its rulings on the fact that the regulations are designed to restrict the export of crude oil, while allowing freely the export of petroleum products. BIS recognized that processed condensate is much like other, readily exportable products, such as natural gasoline, produced in a gas processing plant, and refinery-produced naphtha.

Crude-for-crude exchanges possible with Mexico

Following the BIS approval of processed condensates, upstream producers have been exploring what other alternatives might exist to bypass the crude export ban, aside from the few exceptions noted above (from Alaska; to Canada; etc). Two such options are crude-for-crude exchanges and crude swaps. Crude-for-crude exchange licenses can be obtained if the transaction promotes “efficiency of transportation” or “convenience.” Such licenses for exports to Canada are freely granted, leaving Mexico as the primary additional alternative. Mexico recently opened up its energy industry to outside participants (besides Pemex), around which we would expect to potentially see more activity in terms of crude-for-crude exchanges (e.g. light for heavy). That said, there is currently no BIS precedent for what constitutes a permissible exchange. Either way, we estimate that the refining system in Mexico is currently only ~1.1mmbpd, with 100-150kbpd of light processing. Therefore, while this outlet valve could be leveraged, it is likely to be fairly minimal (<100 kpd).

Crude swaps likely to be a more difficult pitch

In additional to crude-for-crude exchanges, the possibility could exist down the road to conduct crude swaps. However, the steps required to obtain a crude swap license seem likely to be more difficult, particularly given that the applicant must prove that the domestic crude oil cannot reasonably be marketed in the US. We believe that the idea of using general market conditions (e.g. significant light crude discounts in the US) may face a fairly high bar for a swap, especially after the political backlash that has occurred with the processed condensate export approvals.

We assume some condensate exports and crude-for-crude exchanges

Despite the existence of the export ban, we believe that there should be plenty of opportunities for US producers to leverage the existing exceptions and licensing opportunities to find incremental outlet valves for US

crude. Exports to Canada, in particular, have seen significant growth in 2014, which we expect to continue into 2015 then level off in 2016. However, with the BIS ruling, we see processed condensate exports stepping in as the next meaningful opportunity. We also think that it is possible that crude-for-crude exchanges with Mexico and/or crude swaps could start to occur by 2016.

Figure 32: Despite crude export ban, we see opportunities for exportskbd

Source: EIA and J.P. Morgan estimates.

Importance of the Jones Act

Background on Jones Act vessels

The Merchant Marine Act of 1920 (commonly known as the Jones Act, named after Senator Wesley Jones) governs the movement of goods between US ports. The Act promotes the maintenance of a strong merchant marine industry, with the belief that having a strong domestic shipbuilding industry is a critical element to national security. As it relates to the movement of crude and petroleum products between US ports, such cargo must be transported on US flagged ships that are US-built, owned and operated. Given the stringent conditions imposed by the Jones Act, chartering such vessels can become expensive. The overall limited supply of Jones Act tankers and growing demand for crude transportation via water has led to a rapid increase in day charter rates.

Industry participants, such as PSX and VLO, are chartering Jones Act compliant vessels with the intent of moving Eagle Ford crude from South Texas into the Gulf Coast, and in some cases, into the East Coast (New York Harbor). For example, PSX has two Jones Act tankers moving Eagle Ford crude into the Gulf Coast, and at times moving crudes from the Gulf Coast to its Bayway refinery in New Jersey. Total transportation costs from the Gulf Coast to the East Coast are estimated to be $5-6/bbl. We believe this transportation cost may play a role in setting the Brent/LLS differential as some refiners seek to move light sweet crudes from the Gulf Coast to

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displace Brent-linked imports on the East Coast. In comparison, shipping crude from the Gulf Coast to Eastern Canada (e.g. Quebec) in the cases where an exception to the crude export ban has been granted, is notably cheaper than moving crude to the US East Coast. Industry sources estimate that the cost is roughly half, despite the similar haul distance, with VLO pegging the cost from Corpus Christi to Quebec at ~$2/bbl.

On speaking with refiners, we believe that the primary deciding factor for whether Bakken or Eagle Ford barrels end up on the East Coast is price and transportation cost differentials. That said, Eagle Ford is also more paraffinic (waxy), so the quality could be perceived to be lower than Bakken; and, the Eagle Ford quality can vary meaningfully throughout the basin. For the East Coast, the key difference is that Bakken costs ~$15/bbl by rail, while Eagle Ford can take a ~$5-6/bbl Jones Act vessel. So as long as Eagle Ford is within $10/bbl of Bakken, it could make sense.

Table 10: Comparison between Bakken and Eagle Ford crude$/bbl

Eagle Ford Bakken

Hypothetical Cost $94-95 $85

Implied Differential $10

Transportation Cost $5-6 $15

Total Cost to Refiner $100 $100


Refining Downside Scenario Analysis from Lifting Ban

Whether the Jones Act remains in place will be key to trade flow impacts

One of the more common topics about the potential lifting of the export ban is the US refiners' desire to have the Jones Act repealed at the same time. The Jones Act significantly raises the cost of shipping crude between two US ports. Thus, if the export ban was lifted, but the Jones Act remained in place, it could result in a scenario in which crude is incentivized to move to export markets instead of other US refineries. We provide one example below where crude exports from the Gulf Coast can be shipped to overseas markets for $2/bbl (roughly the same cost as shipping Brent to the US). However, shipping crude to the East Coast on Jones Act vessels would still cost the same $5-6/bbl from prior examples given.

Figure 33: Crude export ban removed, but Jones Act still in place

$/bbl

Source: J.P. Morgan.

Crude export ban important to cost advantage

One important factor in currently strong refining profitability is the existence of the crude oil export ban. In a world where transportation costs are the primary driver of crude differentials, we have run a scenario in which crude oil exports are allowed to a high enough degree to impact crude differentials. We believe that one of the biggest impacts would be on the Gulf Coast, where the current discount to Brent could fade, as increased outlet valves decrease the amount of excess crude on the Gulf Coast. For our export ban downside scenario, we assume that the LLS discount will be $2/bbl (versus $3.50/bbl in our base case). Assuming regional US crudes still discount to LLS using transport differentials, we believe that Bakken spreads could also narrow, particularly if Bakken is incentivized to flow south to a location of potentially higher netbacks, replacing light sweet crude exported from the Gulf Coast. Below we show possible normalized crude spreads in this scenario, which highlights the ripple effects of a potential tightening of Brent/LLS and WTI/Bakken on other crude spreads.

Table 11: JPM crude differential forecasts – with and without crude export ban$/bbl

2016ECurrent

2016ENo Ban Difference

Brent/LLS 3.50 2.00 (1.50)LLS/WTI 4.50 4.50 n/cBrent/WTI 8.00 6.50 (1.50)WTI/Bakken 7.00 6.00 (1.00)Brent/Bakken 15.00 12.50 (2.50)Brent/ANS 2.00 2.00 n/cANS/Bakken 13.00 10.50 (2.50)

Source: Platts and J.P. Morgan estimates. Bakken = Clearbrook price.

Houston St. James (LLS)

New York Harbor

$2 ship$5 JA ship

$2 ship

Eastern Canada

27




Jones Act repeal could make domestic waterborne competitive with export

If crude exports are allowed, and the Jones Act is repealed, then we believe that the shipment of oil between US ports could become more competitive with exports. Specifically, we see a scenario where Gulf Coast crude could then be sent to the East Coast for the same ~$2/bbl that it would cost to send to an export market, making the East Coast at least on par with export. On the West Coast, we also see a scenario where crude could be sent from the Pacific Northwest to California for <$1/bbl, which would compare with ~$2/bbl for exports. Thus, refiners on the East and West coasts could still receive Bakken crude, depending on (a) whether cheaper pipelines are built to the Gulf Coast relative to the rail costs to the East/West Coast, and/or (b) whether ocean freight costs from the Gulf Coast to the East/West Coast can compete with other international markets.

Figure 34: Crude export ban removed, Jones Act repealed

$/bbl


Refined product exports/margins could also be negatively impacted

A secondary impact of a potential relaxation of the US crude export ban could be on refined products exports/margins. As discussed previously, the US has become a net refined product exporter in recent years, in part due to the growing availability of cheaper domestic crudes, particularly in PADD III. However, if crude exports were allowed and LLS traded closer to Brent, PADD III refineries likely would not achieve the same margins on exports. As a result, refiners might choose to either shift more refined products to the domestic markets (which may not need the product) or be forced to cut production. In either case, US refining margins could weaken, particularly on the Gulf Coast, where most of the exports are currently occurring. Thus, we have factored in a modest reduction to cracking margins in our crude export ban removal downside scenario.

Table 12: JPM cracking margin differentials – export ban downside case scenario (Mid-Con WTI)$/bbl

Mid-Con WTIBase Case ban lifted

Cracking Netback 97.56 96.56Crude Cost 82.00 83.50Cracking Margin 15.56 13.06

Base Case Cracking Margin 15.56Netback Impact (1.00)Crude Cost Impact (1.50)Downside Case Cracking Margin 13.06

Source: Platts and J.P. Morgan estimates.

Table 13: JPM cracking margin differentials – export ban downside case scenario (Gulf Coast LLS)$/bbl

Gulf Coast LLSBase Case ban lifted


Base Case Cracking Margin 14.01Netback Impact (0.50)Crude Cost Impact (1.50)Downside Case Cracking Margin 12.01


Table 14: JPM cracking margin differentials – export ban downside case scenario (West Coast Bakken)$/bbl

West Coast BakkenBase Case ban lifted


Base Case Cracking Margin 11.00Netback Impact 0.00Crude Cost Impact (2.50)Downside Case Cracking Margin 8.50


EPS impact could be in the ~25% range

Using the crude and product price forecasts mentioned above, we ran our earnings models to show what would hypothetically happen to refining earnings in 2016 under the scenario that crude exports are allowed. We see a potential ~25% downside risk to group EPS, relative to our base case scenario. The largest impact would be to VLO (35%) and MPC (35%), given that they have heavier exposure to the Gulf Coast, while HFC and TSO would see 20-30% impact. PSX would be 15%, given its more diversified business mix.

28




Table 15: Potential impact on operating margins and EPS from no export ban$/share

HFC MPC PSX TSO VLO Average

2016E Op Margin/bbl – Current $8.82 $5.32 $3.19 $4.29 $5.32 $5.392016E Op Margin/bbl - No Export Ban $6.88 $3.51 $2.15 $3.37 $4.16 $4.01

% Impact -22% -34% -32% -21% -22% -26%

2016E EPS – Current $4.50 $9.00 $6.35 $5.50 $7.002016E EPS - No Export Ban $3.45 $5.82 $5.38 $3.99 $4.55% Earnings Impact -23% -35% -15% -27% -35% -27%


Conclusion

Refining stocks feeling the impact of political swings

Refining stocks have underperformed the S&P 500 on a YTD basis, which we think is largely a function of the concerns of the crude export ban potentially being lifted in years ahead. For example, on the day after the Wall Street Journal reported the “processed condensate” approvals, the refining group traded down ~6%, as it created significant uncertainty about whether this would be the first step in lifting the entire crude export ban.

Since the initial sell-off, the group recovered most of its initial losses through early September, as concerns eased around the full ban being lifted. However, concerns have re-emerged in September, with additional analyses being published around the potential benefits of lifting the ban (e.g. Brookings Institute noting the potential benefits to consumers with lower gasoline prices, overall US GDP growth, etc.), which was followed by another reversal in the refining stocks. However, since then, despite the sell off in the energy group more broadly, the stocks have recovered some of their losses on good 3Q results and a focus by investors on the value of logistics assets. On a valuation basis, refining stocks are trading at ~6x 2015EEBITDA, which is above the longer term average in the 4-5x range, which we think is a function of the growing value of the logistics assets on a sum of the parts basis.

Table 16: US refining valuations

JPM EV/EBITDA

Company Rating 2014E 2015E 2016E

HollyFrontier N 6.1x 6.7x 5.0x

Marathon Petroleum OW 5.8x 6.5x 5.2x

Phillips 66 OW 5.8x 6.4x 6.0x

Tesoro N 5.8x 5.4x 6.1x

Valero N 4.5x 5.0x 3.9x

U.S. Average 5.6x 6.0x

Source: Bloomberg, J.P. Morgan estimates. Priced as of November 14, 2014.

Figure 35: Refining stock performance reflects degree of uncertainty around export banIndex = 100 = 12/31/2013 Price

Source: Bloomberg.

Top Pick: PSX (OW, PT $96)While shares have underperformed recently on concerns about the impact of lower oil prices on Chemicals, we still see many value levers to pull, as PSX has the most diversified portfolio in the group and the highest potential for more growth outside of refining (Midstream and Chemicals). We see a strong backlog of MLP drop down opportunities (to PSXP) within Midstream. As a result of its diversity, we also see the lowest downside risk at PSX in a scenario where the crude export ban gets lifted (~15% EPS downside, group average ~26%).

Second Pick: MPC (OW, PT $118)We see MPC as a solid way to play the most favorable themes in US refining, given that all of MPC’s exposure is in the US central corridor, which we expect to remain crude cost advantaged. MPC also has several refining projects under way to drive controllable EBITDA growth. Finally, MPC is diversifying its portfolio into higher-multiple logistics and retail businesses (~22% of 2016E EBITDA), both of which have non-macro levers for growth and significant MLP opportunities.

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LatAm – Moving Ahead with Capacity Expansion

Felipe Dos SantosAC

(55 11) 4950-3796

[email protected]

Marcos Severine(55 11) 4950-4297

[email protected]

Banco J.P. Morgan S. A.

2014 Overview: Latin America refining business was marked by Petrobras losses during 9M14 on its downstream unit due to lack of prices alignment to international market and importing needs to supply Brazil. Petrobras has a dominant market share in the Brazilian market owing 12 refineries, with a total net distillation capacity of 2.1 mmbopd, one of the world’s largest refiners. In the case of Ecopetrol, 2014 was marked by almost zero margins.

Next couple of years will be marked by refining capacity expansions in LatAm: In our view, 2015 and 2016 will mark a transition as Petrobras and Ecopetrol expand their refining capacities. Petrobras is currently building two new refining facilities:

1) Complexo Petroquímico do Rio de Janeiro or COMPERJ is an integrated refining and petrochemical complex (165 kbd) with startup expected for 2016 and a second trench with additional 165 kbd expected to start up in 2018, including additional petrochemicals capacity. COMPERJ construction has reached 66% of completion while the investment in COMPERJ is around $13.6bn.

2) Abreu e Lima Refinery, or RNEST, will start up at end-2014 with a total processing capacity of 230 kbd of crude oil and with production capacity for 162 kbd of low sulfur diesel. Investment in RNEST refinery investment is around $18.6bn.

In the case of Ecopetrol, the company is expanding capacity of its REFICAR refinery from 80 kbd to 265 kbd in 2015 while the product mix will also change with more focus on mid-distillates and gasoline. The company will likely be investing ~$6.5bn to increase and upgrade its refining capacity between 2014 and 2020.

And also increase quality of refined products: We believe the LatAm oil & gas companies are investing to upgrade their fuel output to international standards. In that sense, Petrobras has been investing in refineries to improve both gasoline and diesel quality and to increase crude slate flexibility in order to be able to process more Brazilian crude. Petrobras has indicated that after the upgrades, their Solomon Index will jump to 9.6 in 2016

from 8.3 in 2012 with total investments in the quality upgrade likely to reach $15bn between 2014 and 2018. In the case of Ecopetrol, the company’s Solomon index at Cartagena Refinery will jump to 10.4 from 5.4 while Barrancabermeja will reach 10.3 vs. 6.9 previously.

Increase capacity in Brazil is particularly important as reduces imports needs. Brazil has been importing on average 225kbd of diesel and gasoline. In our view, with RNEST start up the diesel importing level is likely to reduce this number in to ~40kbd of gasoline, pretty much reducing PBR’s diesel importing gap.

Figure 36: Diesel and Gasoline Importskbd

Source: ANP.

In our view, further capacity expansion plans would come only if capex estimates for those refineries decline. We believe Petrobras is not likely to move ahead with Premium I and II refineries projects unless capex estimate of $20bn reduces. The two refineries are in their design phase to process 20° API heavy crude oil, with throughput production of low sulfur diesel with similar throughput capacity of ~300 kbd each. The two refineries will be constructed in single-trains of 300 kbd each, with maximization of energy generation while using the best technology for each single unit.

Figure 37: Capex per complexity barrelThousand dollars/complexity barrel

Note: The company has informed the infrastructure costs with ports, power generation units and other related capex contributes for refining

capex increase.

Source: J.P. Morgan estimates Based on informed investments for each refinery and

considering the production capacity divided by released Solomon index.

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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 115kbopd. The first will process Marlim's field heavy crude (26º API) while the second will process Venezuelan synthetic heavy crude (16º API).

We believe that downstream investments areinevitable as otherwise fuel imports would skyrocket over time. In our view, the expensive downstream investments might not increase the companies’ value but are necessary for companies as Ecopetrol and Petrobras that have the mandate to supply the domestic market with refined products. On the other hand, Petrobras and Ecopetrol have the benefit of supplying a captive market that is growing in terms of consumption on a yearly basis. Please see below the absolute and adjusted cost per capacity of the ongoing and planned refinery expansions in Latin America.

In our view, the main risk for Petrobras Downstream unit is that selling prices lag international ones. We believe investors would like to see a fuel policy increase rather than a sporadical price increase. Currently, bothgasoline and diesel are virtually at parity however, over the last years, the discount to international prices widened whenever Brent and BRL/USD parity moved.

We have a Neutral rating for both Petrobras and Ecopetrol, but for different reasons.

Petrobras (Neutral, PT $25)We rate Petrobras Neutral due to: 1) uncertainties on short-term production behavior and a miss on the 2014 production guidance; 2) FX devaluation impact on fuel import costs and leverage; 3) lack of clarity on fuel price readjustments and a specific price readjustment policy that would allow prices to be readjusted according to international parity.

Least Preferred: Ecopetrol (Neutral, PT $30)We rate Ecopetrol Neutral due to: 1) small reserve lifetime of ~7 years, amidst low replacement ratios; 2) non-compelling trading multiples of 12.7x P/E and 2.4x P/B or 2015, compared to global peers selling at 11.5xP/E and 1.4x P/B.

We would avoid exposure to Ecopetrol as we consider the company’s main challenge remains long-term sustainability of reserves that currently reaches eight years, the ratio has decreased to 6-7 years currently. We highlight Ecopetrol’s initiatives to boost its reserve level on four fronts: exploration, improvement of recoverable factor, development of unconventional potential and acquisition. However, we see no single source as enough to deliver the likely volumes required.

Figure 38: YTD share price performance

Source: Bloomberg.

Table 17: Latam refining valuations

Company Rating Price PT MktCap PE (x) PB (x) EV/EBITDA ROE (%) Yield (%)(LC) (LC) USD mil FY14e FY15e FY14e FY15e FY14e FY15e FY14e FY15e FY14e FY15e

PETROBRAS ON ADR N 9.96 17.00 64,962 7.8 9.2 0.5 0.6 7.2 8.8 6.0% 5.9% 7.0% 3.0% PETROBRAS PN ADR N 10.27 18.00 66,951 8.1 9.5 0.5 0.6 7.3 8.9 6.0% 5.9% 6.8% 2.9% PETROBRAS ON N 12.78 24.00 64,079 8.6 8.7 0.5 0.5 7.6 8.8 5.8% 6.0% 4.6% 1.7% PETROBRAS PN N 13.20 25.00 66,185 8.9 9.0 0.5 0.5 7.6 8.8 5.8% 6.0% 4.5% 1.7% YPF N 32.96 41.00 12,964 10.1 11.6 1.2 1.1 3.3 3.4 14.1% 9.9% 0.0% 0.0% Ecopetrol ADR N 24.81 30.00 51,004 9.7 12.5 2.1 2.3 5.1 6.6 17.2% 17.9% 8.6% 6.4%


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31




Asia – Flat or lower GRMs likely for 2015

Samuel LeeAC

(852) 2800 8536

[email protected]

Parsley OngAC

(852) 2800 8509

[email protected]


2014 Overview:

Asia sits at the heart of global demand growth, but cost pressure from world-scale refinery startups in India, China and the Middle East have stolen market share and called the economics of marginal refineries into question. Asia ex-China accounts for 19% of global capacity, but only 11% of demand. With China largely self-sufficient, exporters have struggled to find new markets (China became a net product exporter in 4 out of 9 months in 2014, while between 2000 and 2013, this occurred in only 2 out of 168 months). Korea has raised exports to countries like Singapore and Indonesia, while lowering exports to China to 15% of total, versus 23% in 2008 (Figure 39). Likewise, India has increased its Europeanmarket share, particularly for diesel and kerosene/jet fuel. Given tepid demand growth, the Asian market looks saturated and we anticipate a challenging refining environment that will suppress margins and utilizations, and necessitate further closures.

Figure 39: South Korea product exports by destination

Source: JODI, Korea customs, J.P. Morgan estimates.

We see numerous operational disadvantages refineries face: (1) slowing demand in China of c200 to 300 kbd and gradual uptick in product exports; (2) high percentage of NOCs in the region with lower price sensitivity; (3) crude quality imbalances, with limited heavy crude supply growth but strong development of deep conversion assets in East of Suez. This might result in Asian refiners processing sub-optimal feedstock, which lowers the value of their upgrading projects and competitiveness; (4) increasingly tough emission standards and refined product specifications; (5)

Commissioning of significant condensate splitting capacity and CTL projects. Asia has the world's largest naphtha deficit, but the startup of 3 large condensate splitter projects in 2014 have weakened naphtha cracks.

2014 started off with robust GRMs, but they have struggled to stay above $5/bbl (2Q-to-date avg: $4.8/bbl), versus the 2013 average of $6/bbl (Figure 40). Diesel has declined throughout the year due to the start up of new ME capacity in 4Q13 and +67% Y/Y increase in YTD Chinese diesel exports. Fuel oil has generally been weak in 2014 as more Chinese teapots can import crude directly, with a total of 504 kbd of import licenses awarded to independents in 2014.

Figure 40: Asia gross refining margins$/bbl


2015-16 Key Issues/Risks

Our global refining model suggests that Asia refiners will face extreme margin pressure as more competitive refineries are commissioned in China, India and the Middle East. Most notably, 2 mega-refineries totaling 800 kbd of capacity will start up in the ME over the next 12 months, with their products likely flooding Asian markets initially during the test run and ramp up phases.

Figure 41: Asia refinery utilizations

Source: J.P. Morgan

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As upgrading units come online, product specifications will improve and more exports will flow to Europe. Additionally, in 2015, c900 kbd of capacity expansions are expected to come online in Asia (400 kbd from China), versus 670 kbd of Asian demand growth. While Chinese margins will see moderate support from the displacement of teapot capacities and domestic demand, its gradual shift towards being a net exporter removes an important demand sink the region, compressing utilization rates and margins in Asia-ex China.

Table 18: New 2014-16 Asian capacity additions (>50 kbd)kbd

Year Refinery Capacity Operator2014 Quanzhou 240 Sinochem2014 Pengzhou 200 PetroChina2014 Yangzi 160 Sinopec2014 Rayong 50 IRPC2014 Map ta Phut 50 IRPC2015 Zhuhai Baota 100 Zhuhai Baota2015 Huabei 100 CNPC2015 Jiujiang 100 Sinopec2015 Hainan 100 Sinopec2015 Cuddalore 130 NOC / TIDCO / Tata Petrodyne2015 Paradip 300 IOC2015 Cilacap 62 Cilacap2016 Sitra 93 BAPCO2016 Huizhou 200 CNOOC2016 Taizhou 60 CNPC / RD Shell / Qatar Petroleum2016 Zhenhai 240 Sinopec2016 Shanghai Gaoqiao 140 Sinopec2016 Kochi 121 BPCL


Not only are there CDU capacity expansions but there are also 500-600 kbd of new condensate splittingcapacities starting up in Asia during 4Q14-1Q15. Since condensate splitters generally produce middle distillates, some of the new capacities will be used to feed new downstream petrochemical plants (mainly PX) while the rest of the products will be likely be diesel/jet. This will further put pressure on Asian refiners as they are middle distillates-centric given the growth of diesel demand over the past 10 years, especially in places like China and Indonesia.

Table 19: Select Asian refiners product exposure

Petchem Mogas JET Diesel Fuel Oil OthersSIN 7% 27% 4% 39% 22% 1%Simple 7% 12% 13% 26% 41% 2%FPCC 18% 22% 9% 35% 4% 12%S-Oil 10% 13% 29% 31% 12% 5%SK Inno 18% 18% 17% 39% 8% 0%RIL 5% 23% 7% 43% 0% 22%TOP 14% 17% 19% 39% 8% 3%PTTGC 9% 12% 9% 50% 14% 6%

Source: J.P. Morgan. SIN=JPM benchmark GRM, Simple= Simple refinery GRM

>1.8mbd of Asian capacity closures necessary to balance market. In our view, given announced capacity expansions and closures, further capacity rationalization is necessary to support margins through 2016 and beyond. We saw a spate of refinery closures in Japan and Australia in 2013 and 2014 (total: 685 kbd), but are presently aware of only two Asian refinery closures in 2015, one of which had been planned since 1991. Plans to shutter a further 323 kbd of Asian capacity have been announced, though no concrete dates have been fixed.

Table 20: Select Asian capacity closureskbd

Year Refinery Capacity Owner2014 Tokuyama -120 Idemitsu Kosan2014 Muroran, Hokkaido -180 Nippon (JX Holdings)2014 Kawasaki, Japan -67 TonenGeneral2014 Wakayama West Japan -38 TonenGeneral2014 Kurnell, Australia -135 Caltex2015 Kaohsiung, Taiwan -200 CPC 2015 Bulwer Island, Australia -118 BPTBD Tobangao, Philippines -96 RD ShellTBD Lytton, Australia -109 Chevron (Caltex)


Brent-Dubai spread narrowing

The other key risk for Asian refiners is the recent narrowing of Brent-Dubai spread. As more and more light crude is available globally, Brent pricing has been under more pressure as of late. The Brent-Dubai spread is important as most of the Asian refiners’ crude costs are based on Dubai while product prices are more of a function of Brent prices. Not only that, Asian refiners normally pay a premium to Dubai crude via the premium that Saudi charges to it customers (called Official Selling Price - OSP) so that higher Brent prices gives the refiners a small buffer of margins as well. Interestingly, Saudi has been cutting its OSP with the decreasing spread.

Figure 42: Lower Brent-Dubai crude spread is negative for Asian refiners$/bbl

Source: Bloomberg.

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Preferred: Reliance Industries (N, PT Rs1,080)

In light of the weaker Y/Y refining outlook in 2015, we currently do not have any OW stocks in our coverage and therefore RIL is preferred on a relatively basis. We believe RIL will fare better relative to peers in a weak GRM environment due to its scale and complexity. Also, unlike other Asian refiners where most of the crude is sourced from the ME, RIL buys their crude almost from anywhere in the world where it can get an advantageous price. Finally we believe significant capacity expansion in their petchems businesses over the next 12-18 months will help RIL offset declines in refining earnings.

Table 21: RIL will have significant petchem capacity growth in the next 12-18 months'000 tons

Current capacity

Expansion Timeline

PolyesterPFY 823 425 CommissionedPET 290 648 Phase 1 commissioned;

Phase 2 end FY15PSF 742 346 FY16PTA 2,050 4,350 Phase 1 in 3QFY15; Phase

2 in early FY16PX 1,856 2,328 Phase 1 in 3Q/4QFY15;

Phase 2 in 1HFY16ROGCMEG 733 730 End FY16Ethylene 1,883 1,400 End FY16Propylene 3,000 150 End FY16PP 2,685 156 End FY16HDPE/LLDPE 1,200 950 End FY16PBR 74 40 CommissionedSBR - 150 End FY15Butyl Rubber - 120 CY16

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

Our SOTP based Mar-16 PT of Rs1080 values the refining, petchem and shale/PMT businesses at 6.5x, 7.5x and 5x EV/EBITDA respectively (in-line with peer group). We value the D6 stake on an NPV basis, and we value investments at book value (telecom at a 50% discount to BV to account for earnings uncertainty). We use FY16 EBITDA in our SOTP.

Least Preferred: S-Oil (UW, PT W29,000)

We believe with the emergence of new mega-refineries from the ME, traditional exporting refiners from Korea,Taiwan and Singapore will be under increasing margin pressure. 63% owned by Saudi Aramco, S-Oil is a simpler refinery with large exposure to PX, a product where we are also bearish on. Despite fairly robust Asian GRMs for most of 2013-14, S-Oil refining business has been loss-making on an OP basis for last 7 quarters. In the past, S-Oil was seen as a dividend play but we think that is also at risk now given our forecast of FY14 losses, weak business environment outlook and increasing CAPEX for 2017-18 for expansion/upgrading projects. We value S-Oil on 0.6x 2015 BV as we forecast 2015-16 ROE to only average around 6%.

Figure 43: S-Oil refining has been loss making for last 7 quarters$/bbl

Source: Bloomberg.


Source: Bloomberg.

Table 22: Asian refining valuations

Company Rating Price PT Mkt Cap PE (x) PB (x) ROE (%) Yield (%)(LC) (LC) USD mil FY14e FY15e FY14e FY15e FY13 FY14e FY15e FY14e FY15e

FPCC N 68.4 71.0 21,235 25.0 24.9 2.7 2.7 12.0% 10.8% 10.8% 3.7% 3.6%SK Innovation N 86,000 87,000 7,231 97.4 11.3 0.5 0.5 5.0% 0.5% 4.4% 3.7% 3.7%S-Oil UW 40,850 29,000 4,182 -119.2 15.3 0.9 0.8 5.2% -0.7% 5.6% 2.3% 2.6%PTTGC N 63.50 60.00 8,716 10.7 10.2 1.1 1.1 14.8% 11.2% 10.8% 4.3% 4.4%Thai Oil N 42.50 47.00 2,639 27.4 14.0 1.0 0.9 14.2% 3.5% 6.7% 1.9% 3.2%RIL N 969 1080 50,841 12.4 11.7 1.7 1.5 14.7% 13.4% 14.0% 1.1% 1.2%Shanghai Petchem UW 2.60 1.8 5,425 34.4 22.7 1.5 1.5 12.2% 4.5% 6.6% 1.0% 1.4%Sinopec Corp N 6.36 8.00 98,933 10.6 9.5 1.2 1.1 11.4% 11.7% 12.0% 4.0% 4.5%


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34




China – Managing over-supply with slowing demand

Scott DarlingAC

(852) 2800 8578

[email protected]

Michael Stansfield(852) 2800 8563

[email protected]


The moderation in Chinese oil demand growth has impacted refining dynamics in the country. Apparent demand for key products - gasoline, diesel, kero/jet, naphtha and fuel oil averaged 230 kbd yoy in 9M14, 60% the yearly average over the last three years, with gasoline demand growth around 10% y/y, offset by weakness in diesel from lackluster industrial activity. With new capacity still coming on-stream after years of over investment by the industry, refinery utilization rates have fallen to 78% so far this year from just over 80% over the last few years (Figure 45). Chinese state refiners have also raised oil product exports as domestic oil demand growth lags capacity additions.

China became a net diesel exporter since late 2012 and overall net oil product imports have fallen sharply this year (Figure 47). Government quotas for such exports have increased accordingly. Chinese refiners are said to continue to be offering tolling agreements whereby crude oil is supplied in exchange for oil products with a small processing fee. This volume of exports is apparently not counted towards the export quotas. In an effort to improve competition within the domestic oil market, the government has also started to approve crude oil import licenses not only to small state owned enterprises (e.g. Sinochem Hongrun), but also private companies (e.g. Guanghui Energy), although the amounts are small relative to total imports (c0.5m b/d import licenses granted which represents only c5% of the country’s imports). This, however, further exacerbates the overcapacity situation as the ability to import crude oil improves their competitiveness to state refiners.

Figure 45: China refining plant utilization

Source: BP 2014 Statistical Review of World Energy

Figure 46: Chinese oil product demand outlook, kbd (y/y)

Source: NBS, CGA, OGP, J.P. Morgan

Figure 47: Net oil product imports collapsed

Source: J.P. Morgan estimates, Bloomberg. Chart shows total oil product imports and

exports in m tonnes on a quarterly basis

The Chinese government remains in control over oil product prices through the National Development and Reform Commission (NDRC). The fuel price mechanism for gasoline and diesel prices was amended in March 2013 and the government is adhering to the revised mechanism. However, the sharp fall in oil prices saw several oil product cuts with a subsequent fall in refining margins (Figure 48). (Note: the NDRC adjusts gasoline and diesel prices when a basket of crude oil prices (dated Brent, Dubai and Cinta) moves by Rmb50/ton (US$1/bl) over a 10 day period).

Figure 48: Decline in China refining margins

Source: Bloomberg, J.P. Morgan

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The main challenges facing the refining industry in China remain managing overcapacity, as the country’s oil demand growth moderates and upgrading existing plants, phasing out small and inefficient teapot refineries. Both PetroChina and Sinopec are likely to guide lower capex in 2015 and perhaps beyond and we see some of the capex reduction from downstream (and chemical segments) which may see delays the capacity expansion (Table 23). This together with some oil demand growth, albeit slight, in oil demand in the country next year, our global refining model suggests plant utilization remains broadly unchanged in the coming years.

Table 23: China refinery capacity additions 2014-17EKbd

Year Plant Capacity Operator2014 Quanzhou 240 Sinochem2014 Pengzhou, Sichuan 200 PetroChina2014 Yangzi Petrochemical 160 Sinopec2015 Zhuhai Baota 100 Zhuhai Baota2015 Huabei Petrochemical 100 CNPC2015 Jiujiang Petrochemical 100 Sinopec2015 Hainan refining &

Chemical100 Sinopec

2016 Huizhou, Guangdong 200 CNOOC parent2016 Taizhou, Zhejiang 60 CNPC / RD Shell / Qatar

Petroleum2016 Zhenhai 240 Sinopec2016 Shanghai Gaoqiao 140 Sinopec2017 Dushanzi - Xinjiang 120 PetroChina2017 Kunming, Yunnan 200 PetroChina / Saudi Aramco

Total additions 1,960

Source: J.P. Morgan estimates

Fuel specification reform

China continues to rollout fuel specification adjustments. (Table 24) to address pollution caused by vehicle fuelemissions in major cities and further eliminates inefficient teapot refineries, which represent c20% of the country’s total 12.6 mb/d refinery capacity. While major cities such as Shanghai and Beijing already have implemented the highest fuel specification standards, nationwide rollout started this year with gasoline moving to China IV standards and diesel to follow in 2015. Most major refineries have already invested in upgrading to meet these specifications which add cUS$0.5-1.0/bl incremental margins (all other things being equal) according to Sinopec, as the consumer is required to pay a higher price at the pump for the tighter specification.

Table 24: National rollout of fuel specificationsStage Diesel GasolineChina I 1-Jan-02China II 1-Oct-03 6-Dec-06China III 1-Jul-11 31-Dec-09China IV 31-Dec-14 31-Dec-13China V 31-Dec-17 31-Dec-17

Source: Bloomberg

Phase out of teapots

Shandong province, home to the majority of China’s inefficient teapot refineries has recently announced a reform and upgrading plan for the refining industry. The initiative closes 20 small plants to remove 12mt capacity by 2017 and increasing plant scale from 2.3mt per year to 4.5mt by 2017 and 5mt by 2020 and control total provincial capacity to c100mt.

Key Stock Picks

Within our Asia Oils coverage, we have had a broad preference for more upstream biased companies with less refining exposure, where through cycle returns are better for upstream rather than refining assets such as PetroChina. However, there is a focus for the Chinese government to on improving returns at SOE companies by promoting capital discipline and cost management and efficiency as well as allowing entry by private investors to some segments (e.g. retail, energy infrastructure).Sinopec has been the first of the China Oil & Gas SOE to reform certain parts of its business and while the macro outlook for refining may remain challenging, corporate re-structuring is improving the free cash outlook for the business.

Preferred: Sinopec (N, PT HK$7.0)Sinopec is China's largest refiner with refining capacity at 5.7 mb/d (43% domestic capacity share), the largest in Asia and one of the largest in the world. Sinopec’srefineries are mainly located in China's southeast coastal areas, middle and lower reaches of the Yangtze River and North China, where plants have good access to high growth demand centres. Refining profitability has been weak with cuts to oil product pricing and moderation in oil demand growth, although the company continues to shift product mix toward gasoline (yield was c46% in 2013, an increase from c37% in 2011) which still exhibits strong volume growth (gasoline sales rose 11% y/y last year) and margin (Figure 49 - Figure 51).

Figure 49: Sinopec profitability still biased to the upstream

Source: J.P. Morgan estimates. Chart shows operating profit by segment for 2013

E & P, 55%

Refining , 9%

Marketing, 35%

Petrochemicals, 1%

36




Figure 50: Superior refining performance than domestic peers

Source: J.P. Morgan estimates. Chart shows refining operating profit (US$) per bl

throughput for PetroChina and Sinopec, unadjusted.

The company recently proposed to acquire a 37.5% interest in its parent, Sinopec Group’s Yanbu refinery in Saudi Arabia (400kb/d, Saudi Aramco has a 62.5% stake) for US$0.5bn with a transaction value at 1.6x P/B, a premium to book which reflects the fact that Sinopec Group invested in 2011 bearing all construction and related risks. The refinery is currently in the commissioning phase, but the investment marks the first refining asset entry into the Middle East. Management notes that the project meets the company’s internal IRR hurdle rate (guided in the past at 12%) and can help Sinopec enhance supply chain linkage with this asset and with Saudi Aramco, a major crude supplier.

The company also opened up its retail network to private investors with 25 new investors taking a 30% stake in a new entity, Sinopec Easy Joy Sales, its newly created marketing arm, for US$17.5bn, which will have a Board of Directors made up of three members from these new investors and of which some have already worked closely with Sinopec marketing as well as Sinopec (3 seat) and an independent director.

A potential IPO will be decided by the new board of directors which has yet to meet. Deal is awaiting Ministry of Commerce approval possibly later this year. Sinopec guides that non-fuels has delivered 15-20% y/y revenue growth over the last six years and that this could expand to 30% y/y growth in the medium term; the company expects margins to improve (Shanghai-based test stores, likely in cooperation with Reuntex, are seeing fresh food gross margins at 35% and tobacco products 6-8%). Sinopec is still considering use of cash proceeds with some being used in shale gas, although will allocate capital in the best interests of shareholders according to management.

Figure 51: Sinopec’s refining/retail network is well positioned in China

Source: Baidu Maps. Note: East - Shandong, Jiangsu, Zhejiang, Anhui, Jiangxi, Fujian;

North - Hebei, Shanxi, Inner Mongolia; North East - Liaoning, Heilongjiang, Jilin; North

West - Shaanxi, Xinjiang, Ningxia, Qinghai, Gansu; South Central - Henan, Guangdong

(less Guangzhou), Hubei, Hunan, Guangxi, Hainan; South West - Guizhou, Sichuan, Tibet

Least Preferred: Sinopec Shanghai Petrochemical (UW, PT HK$1.5)Sinopec Shanghai Petrochemical (SPC), one of the top five largest refineries owned by Sinopec Corp (51% shareholding), while upgraded for high oil product specification largely directed into the Shanghai market, also is exposed to commodity chemicals has seen a collapse in profitability this year (Figure 52). This reflects lower utilization at its refinery from a moderation in oil product demand and lower refining margins as well as weak chemical margins and a plant scale and limited product grade portfolio/feedstock optimization to partly mitigate the current chemical environment. However, SPC shares have outperformed in 2014 reflecting anticipation of the HK-SH connect program (SPC-H currently trades at a c30% discount to SPC-A); however, with the program’s start date now in question and the company’s fundamentals increasingly challenged, we continue to view the shares as overvalued against regional peers.

Figure 52: Single-asset refinery biased to commodity chemicals

Source: J.P. Morgan estimates. Chart shows net sales by segment for 2013

Petroleum Products

54%Intermediate PetChems

17%

Resins & Plastics

14%

Synthetic Fibers

3%

Trading11%

Others1%

37




Japan – Can Japan remain an independent market?

Yuji NishiyamaAC

(81) 3 6736 8617

[email protected]

J.P. Morgan Securities (Japan) Co.,Ltd

2014 Overview: Profit improving on a reduction in refining capacity

Japanese petroleum industry earnings slumped in 2013 but have recovered in 2014 amid improving refining margins. The recovery has been driven by three main factors: 1) supply/demand improvement due to refinery closures; 2) a change in the way sales prices to wholesales are determined; and 3) the enactment of laws to boost industry competitiveness in January. At the end of March 2014, JX Holdings closed its Muroran refinery (180 kbd) and Idemistu closed its Tokuyama refinery (120 kbd). This reduced capacity by 10%.

Figure 53: Gasoline marginY/Liter

Source: Nikkei, J.P. Morgan.

Petroleum product wholesale prices were previously based on prices announced by a market research company. However, a sharp divergence between this indicator and actual market conditions in 2013 prompted a change to price setting based on the price of crude oil. Also, the price of brand gasoline was increased by ¥1-2/l.

Industry competitiveness laws provide tax breaks and other incentives to promote consolidation in an industry that has too much processing capacity vis-a-vis demand. The Minister of Economy, Trade, and Industry (METI) has publicly stated that the petroleum industry must reduce capacity and consolidate and refiners are unable to disregard the new laws. As a result, the flow of surplus products into the market caused by an emphasis on

capacity utilization has slowed, contributing to supply/demand balance normalization.

Figure 54: Change in refining capacitykbd

Source: Company reports, J.P. Morgan.

Share performance weak despite refining margin correction

Although the petroleum industry has embarked on a road to normalization in 2014, the share price performance of refiners has been weak. As of October 31, Topix was up 2% YTD, while JX Holdings, the largest refiner, and Showa Shell Sekiyu were down 12%, Cosmo Oil was down 15%, and Idemitsu was down 10%. TonenGeneral was up 1%, but this was still worse than the overall market performance.

We believe this is mainly due to disappointing April-June results announcements. Refining margins bottomed in February and began to rise, raising expectations of strong earnings for the first time in a while. But scheduled maintenance costs weighed on profits and demand was lackluster because of unfavorable weather. We believe weak results severely damaged investor confidence in the petroleum industry and created doubt as to whether profit levels would increase even if refining margins improved. We believe July-September results are likely to be strong, but it is difficult to see investor sentiment improving given the rapid drop in refining margins caused by crude oil price declines.

2015-16 Key Issues/Risks: A further 10% reduction in capacity

We believe investors will focus on industry realignment developments in 2015. Pursuant to regulations to enhance the sophistication of energy supply structures, refiners must increase their residue cracking-to-distillation ratios by end-March 2017. Upgrading cracking facilities is not feasible because of the large investment required, and as a result refiners are likely to comply by reducing their processing (distillation) capacity.

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Figure 55: Capacity reduction requiredkbd

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

If refiners were to comply with regulations purely by reducing processing capacity, we estimate the following cuts would be needed: JX Holdings (160 kbd), Tonen General (81 kbd), Idemitsu (55 kbd), Cosmo Oil (52 kbd), Showa Shell (37 kbd). This equates to an industry-wide reduction of 410 kbd, which is another 10% of current processing capacity.

Realignment in focus

Although the pace of capacity reduction has accelerated since 2010, it has gradually become more difficult for companies to achieve targets on their own. We believe the probability of multi-company alliances—that is, realignment— is high. It would be difficult for JX Holdings to merge with another company because of its high domestic market share and we therefore expect its efforts to center on its existing distribution tie-up with Idemitsu. Tonen General has begun integrating its refining operations at the Chiba complex with those of Cosmo Oil, and we expect it to strengthen cooperation with Showa Shell at the Kawasaki complex, where Showa Shell has surplus coker capacity.

As a result, we believe consolidation measures are likely to be concentrated in two groups: a JX Holdings-Idemitsu alliance and a TonenGeneral-Cosmo Oil-Showa Shell alliance. Cosmo Oil’s debt and Showa Shell’s capital relationship with Royal Dutch Shell are potential obstacles to closer ties and we highlight related news flow as a point to watch (please see the Europe section of this report for more on asset sales by Royal Dutch Shell).

Can Japan’s market independence be maintained?

The Japanese petroleum products market is not integrated with the Asian market and the wider global market. This is because Japanese companies have enough refining capacity to meet domestic demand and importers are required to hold 70-days-worth of inventory. In this report, we forecast global supply capacity growth will

outstrip demand growth and refining margins will slump, but Japanese refiners could still post relatively strong earnings as the Japanese market is largely independent. This is a big point of difference from refining industries in other countries.

However, to remain an independent market, Japan must bring domestic demand and supply into balance or reduce domestic supply to below demand. As mentioned earlier, we expect domestic supply to be reduced by around 10% moving forward, but petroleum product demand declined 4% Y/Y in Jan-Aug 2014 and if it continues to contract at this pace we estimate there will again be a processing capacity surplus in three years.

Nuclear restarts unlikely to have a major impact

Finally, we would like to discuss the issue of nuclear plant restarts. Nuclear power generation was gradually wound down after the March 2011 Great East Japan Earthquake and no reactors have operated since October 2013. The increase in thermal power generation to compensate for the loss of nuclear power led to a significant increase in furnace fuel oil demand. However, oil-fired power generation costs are high, and power companies responded by postponing periodic inspections of coal-fired plants and increasing LNG facility capacity utilization. Oil-fired thermal power generation has now almost returned to the pre-disaster level.

Figure 56: Consumption of crude oil and fuel oil for electric generation

Source: FEPC, J.P. Morgan.

As furnace fuel oil demand is no longer a major contributor to refiners’ earnings, we forecast nuclear plant restarts will have only a limited earnings impact. Also, refiners had consistently reduced Bunker C output since the 1970s, and the minimization of related production equipment in refinery configurations meant that imports were needed to meet the demand spike after the March 2011 disaster. We do not expect nuclear plant restarts to significantly change Bunker C production volume.

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39




Preferred: JX Holdings (N, PT¥480)JX Holdings already has a dominant market share and can be distanced from concerns about market realignment uncertainty. In addition, we believe it is best positioned to benefit from the margin improvement that is likely to accompany consolidation measures by other refiners.

Also, even if petroleum product supply capacity continues to decline, JX Holdings can expand through its non-refining businesses, which include upstream oil operations and copper mine development. JX Holdings is currently struggling to expand copper mine and petrochemical operations and the share price is low, but we believe this is just a teething stage.

Least Preferred: Idemitsu Kosan (N, PT ¥2,100) Idemitsu’s position in the domestic market is stable, but it is moving forward with a US$9 billion petroleum refinery/petrochemical plant project in Nghi Son, Vietnam, and has the highest exposure to a slump in refining margins in Asia, which we have identified in this report as a possibility.

Idemitsu plans to refine Kuwait crude oil in Vietnam and sell petroleum products in the local market, but if the price of crude increases sharply it is unclear whether Idemitsu could pass on the cost to sales prices. Petroleum products are much more of a necessity good in emerging markets than they are in developed economies, and if large increases in crude prices are passed on directly to sales prices it could cause political unrest.

Other stocks

Showa Shell and TonenGeneral are both dividend yield plays. Solar cell business environment deterioration (Showa Shell) and oil business profitability deterioration (TonenGeneral) are potential risks to dividend sustainability. In the short term, however, we believe the likelihood of dividend cuts is small and we expect share prices to remain stable.

Operations at Cosmo Oil’s mainstay Chiba refinery have finally returned to normal after the disruption caused by the Great East Japan Earthquake and performance is improving. As the smallest of the big five refiners Cosmo Oil is unlikely to be a driver of industry realignment, but securing a casting vote is not out of the question if it moves quickly.

Figure 57: Stock performance

Source: Bloomberg

Table 25: Japan refining valuations

Bloomberg Market Cap P/E(x) P/B(x) ROE(%)Company name Ticker Currency Price Price date ($mn) FY14E FY15E FY16E FY14E FY15E FY16E FY14EShowa Shell Sekiyu 5002 JT JPY 972 Nov-14 3,149 11.9 9.5 9.8 1.14 1.07 1.00 10.4Cosmo Oil 5007 JT JPY 164 Nov-14 1,195 8.9 7.7 6.6 0.55 0.52 0.49 5.7TonenGeneral Sekiyu 5012 JT JPY 990 Nov-14 4,809 9.3 27.0 28.2 1.15 1.15 1.14 15.5Fuji Oil 5017 JT JPY 321 Nov-14 216 6.6 5.6 4.4 0.32 0.30 0.28 4.9Idemitsu Kosan 5019 JT JPY 2,064 Nov-14 2,839 10.3 7.9 7.3 0.46 0.44 0.42 4.8JX Holdings 5020 JT JPY 450 Nov-14 9,642 10.4 6.4 6.1 0.51 0.48 0.45 5.2

Source: Bloomberg, J.P. Morgan estimates.

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Cosmo Oil

JX Holdings

Idemitsu Kosan

Showa Shell

Tonen General

40




India – Overcapacity remains; prefer marketing

Neil GupteAC

(91 22) 6157 3592

[email protected]

J.P. Morgan India Private Limited

2014 Overview: While the downstream Indian names have performed well through 2014 (ex RIL) due to reforms/oil price weakness leading to lower subsidies, this masks continuing challenges facing the refining sector. Oil product consumption growth is beginning to recover, after weakness through 2013/early 2014 and has averaged c.3.5% since April. Diesel, consumption of which declined into early 2014, has begun to rebound as well, and has averaged ~1.5% since April.

Figure 58: India oil consumption growth (3 month rolling average)

Source: PPAC

Figure 59: India diesel consumption growth (3 month rolling average)

Source: PPAC

2015-16 Key Issues/Risks: India remains an oversupplied market, with capacities being enhanced at existing refineries, and new refineries being set up – as the state owned oil marketing firms look to bridge the gap between refining throughput and retail sales. With

our global refining model suggesting a growing supply overhang, and with new refineries potentially competing for share outside their home markets, private sector Indian refiners will face rising competition, necessitating the development of new product markets. We see the overcapacity in the Indian system remaining, with the potential start up of IOCL’s Paradip refinery (albeit delayed), and the expansion at BPCL's Kochi refinery. As such, exports are likely to continue to trend higher, with the oil marketing firms satisfying a higher proportion of retail sales through their own refinery operations. With older, less complex refineries, the state owned refiners continue to face a low margin environment.

Figure 60: Net product exports (3 month rolling average)‘000 MT

Source: PPAC

Figure 61: Oil product consumption vs. Refinery throughputMMT

Source: PPAC. Note: Refinery throughput includes RIL SEZ refinery – which is an export

oriented unit

Key Stock Picks: Within the Indian refining space, we currently, we think RIL as well placed as far as refining margins are concerned. However, with continuing weakness in downstream businesses, we see HPCL/BPCL better placed due to benefits of fuel price reform/lower oil prices.

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41




Preferred: HPCL (OW, PT Rs690)

With our expectation of a more benign crude price environment, we highlight that the state owned oil marketing firms are likely to see a quicker roll off of subsidy losses, and a gradual expansion in diesel marketing margins. We expect the private players to take an 8-10% share as a consequence. Balance sheet leverage is likely to decline quicker than earlier anticipated, with a consequent reduction in interest costs as well.

Figure 62: Reduction in HPCL leverage


Table 26: Sensitivity to subsidy share and diesel marketing margins



Source: Bloomberg.

Table 27: India refining valuations

Company Rating Price PT Mkt Cap PE (x) PB (x) ROE (%) Yield (%)(LC) (LC) USD mil FY15e FY16e FY15e FY16e FY14 FY15e FY16e FY15e FY16e

RIL N N 969.2 1,080.0 50,767 13.8 13.1 1.88 1.68 14.4% 14.5% 13.6% 1.0%BPCL OW OW 734.9 895.0 8,605 19.6 17.5 2.99 2.68 22.5% 16.1% 16.2% 1.5%HPCL OW OW 555.2 690.0 3,044 13.1 10.7 1.44 1.33 12.1% 11.4% 12.9% 2.3%IOCL N N 356.8 405.0 14,028 14.9 11.7 1.32 1.22 9.1% 7.6% 9.2% 1.6%


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0 539 614 690 765 841

10 475 550 626 701 776

20 411 486 561 637 712

30 347 422 497 573 648

40 282 358 433 508 584

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42




Australia – domestic refining shifting to product imports

Shaun CousinsAC

(612) 9003 8623

[email protected]

Quinn Pierson(612) 9003 8628

[email protected]

J.P. Morgan Securities Australia Limited

2014 Overview

The transport fuels market in Australia has undergone significant change in recent years with more possible. Refinery capacity has been reduced and some global oil players have exited from elements of the value chain, with trading houses and convenience retailers playing a greater role.

Refineries in Australia have endured rising energy, labour and maintenance costs, and suffer from a lack of scale. As a result, the economics of Australian refineries is somewhat challenged with competing product from attractive sources (i.e. large scale Asian refineries) now more available, resulting in a significant number of closures announced and occurred in recent years resulting in imported refined product increasing as a percentage of transport fuels.

There are plans to have only 4 refineries in the middle of this decade following the announced closures and /or conversion to import terminals at Bulwer Island (BP), Clyde (Vitol), Kurnell (CTX) and Port Stanvac (Mobil). This reduces the proportion of transport fuels sourced from domestic refineries to less than 50%.

Table 28: CTX - Australian Refinery Details & Capacity

Location State OperatorYear commissioned

Capacity (ML/pa)

Kurnell* NSW Caltex 1956 7,820 Bulwer Island** QLD BP 1965 5,910 Lytton QLD Caltex 1965 6,300 Altona VIC Mobil 1949 4,640 Geelong VIC Vitol 1954 7,470 Kwinana WA BP 1955 8,300

Source: BREE, Energy in Australia, 2013. *Refining shut down October 2014. **Refining

to halt mid 2015.

Global oil players have exited some elements of the industry with specialist retail operators (e.g. 7-Eleven) and trading houses (e.g. Vitol, Trafigura) playing a greater role in the industry. A key example is Vitol’s acquisition of the downstream, ex jet, operations of Shell in Australia in February 2014 for A$2.9bn, with theprimary asset the more than 600 Shell Coles Express petrol stations and the Geelong refinery.

Overall the importance of domestic refining is decreasing with import infrastructure becoming more important as judicious sourcing becomes vital.


Australian participants will continue to look to secure import infrastructure as importing product is increasingly attractive compared to domestic refining. As a result, further refinery closures cannot be ruled out.

Preferred: Caltex (OW, PT A$28.44)CTX is the only publicly listed refinery operator in Australia. CTX is undergoing a repositioning and one we believe will increasingly be considered by a broader range of investors including consumer focused investorsdue to its increasingly stable earnings profile as refining becomes less influential (given recent closure of Kurnell), and the opportunity to participate in the early stage of a business improvement programme. We suggest there is further upside with 4 key medium term drivers.

1) Company wide cost and efficiency review which should support future ROCE expansion. Initial outcomes include A$80-100m cost savings, working capital reductions of 1mmbl and lower capex guidance. Capital management review announced, with initial progress the early repayment of high cost debt, with dividend payout ratio and return of surplus capital including franking credits possible outcomes.

(2) Premium diesel growth, up 55% in 1H14, driving transport fuels margin and overall marketing EBIT. While the rate of premium petrol growth has moderated, the rate of premium diesel growth is in its infancy and hence is likely to be a multi-year driverdue to vehicle mix and canopy reconfiguration.

(3) Kurnell closure of refinery and conversion to an import terminal. In October 2014 Kurnell refinery units were shut, with Lytton, the remaining refinery, having better product mix and yield and lower operating costs, with a CRM breakeven of US$6.50/bbl, with plans to increase efficiency to enable break even at US$5.50/bbl. Kurnell production is to be replaced with imported product driving sourcing benefits.

(4) Broader repositioning benefits remain at CTX. Increasing focus on leveraging the CTX infrastructure network (i.e. win new contracts, host competitors, defend position, value-add acquisitions), with broad retail network and brand valuable but not fully leveraged.

43




Europe – refiners’ graveyard

Fred LucasAC

(44-20) 7155 6131

[email protected]

Nitin SharmaAC

(44-20) 7134 5947

[email protected]

J.P. Morgan Securities plc

2014 Overview

Aside from their old age and inefficient scale (average capapcity around 135 kbopd compared to new world scale capacity of 300-400 kbopd), European refineries suffer numerous operational disadvantages which include:

1) High dependency on relatively expensive Atlantic Basin crude oil feedstock

2) Relatively high energy (gas and electricity) costs3) Relatively high and inflexible labor costs4) Tough emission standards and refined product

specifications which mandate relatively high sustained levels of asset integrity expenditure

5) Relatively mature markets with declining consumption patterns

6) Reduced export opportunities as US refineries reduce US import needs and as ME refineries export more products to Asia.

7) High costs of plant closure, often made more difficult by politics which has inhibited the necessary capacity closure

This leaves the European refining system under enduring attack from refined product exports from the Middle East and as far afield as refineries in India. Combined with soft demand trends this has, in turn, suppressed European refinery utilization (Figure 64).

Figure 64: European refining capacity & utilization

Source: BP 2014 Statistical Review of World Energy.

As we have shown, European margins show a relatively high historic positive correlation to average utilization. So we think it is reasonable that as utilization rates

remain suppressed, so too will European margins (Figure 65).

Figure 65: European refinery utilization vs. gross margins 1992-2014



Our Global Refining Model suggests that European refiners will remain under extreme margin pressure as other regions e.g. USA and Middle East build more competitive refined product export capacity. These flows will continue to displace European refinery runs, thus driving down utilization rates and margins (Figure 66).

Figure 66: European refinery utilization outlook


In our view, more disadvantaged refineries in Europe e.g. France and Italy must be converted to terminals or closed. We are only aware of two small refinery closures / conversions in 2015 (Table 29). We note that Murphy Oil’s failure to complete the planned sale of its Milford Haven refinery to Klesch Refining Limited may reflect the buyer's concerns on the margin outlook. There have not been any closures in 2014 and none are scheduled post-2015. Our Global Refining Model shows that in order to raise European refining utilization to a more reasonable 72%, over 1.6 mbd of incremental European refining capacity must be removed. In our view, this is

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extremely unlikely to happen in the foreseeable future given political sensitivities to the unemployment and trade balance consequences.

Table 29: European refinery capacity reduction 2009-15Ekbd

Year Plant, Country Capacity Operator2009 Teesside, UK -117 Pluspetrol

Dunkirk, France -137 TOTALNormandy, France -80 TOTAL

2010 Odessa, Ukraine -80 LukoilWilhelmshaven, Germany -260 ConocoPhillips

2011 Reichstett, France -85 PetroplusPorto Marghera, Venice -70 ENI Arpechim, Austria -70 OMV

2012 Cremona, Italy -80 TamoilBerre L'Etang, France -105 Lyondell BasellRaffineria di Roma, Italy -90 ERGCoryton, UK -220 PetroplusLisichansk, Ukraine -320 TNK-BPFiumicino, Italy -86 ERG-TOTAL

2013 Petit Couronne, France -162 PetroplusHarburg, Germany -110 RD Shell

2015 Gela, Sicily -105 ENI Milford Haven, UK -135 Murphy OilTotal closures -2,312


Key Stock Picks: Within our European coverage universe, investors in the large cap integrated space can side-step refining altogether via BG Group which instead provides an above average and differentiated exposure to global LNG. Alternatively, investors can assume a small refining exposure via Statoil which owns 100% of two refineries (Mongstad, Norway – 240 kbd and Kalundborg, Denmark – 118 kbd), having spun-off and then divested its fuels retailing business.

We consider two names: (+) RD Shell – this name retains a relatively heavy exposure to refining (Oil Products 14% 2013 earnings), but it is undergoing a major restructuring to raise cash flow and returns from this business so it has self-help protection. (-) GALP – like Statoil, this name also owns 100% of two refineries both in Portugal (Sines – 220 kbd and Porto – 110 kbd), but unlike Statoil it lacks a large cash generative upstream business. In our view, GALP has rising balance sheet risk given its upstream expenditure commitments (over which it has little control as minority partner) in the pre-salt Santos Basin, offshore Brazil and the Rovuma Basin, offshore Mozambique. It also suffers a higher near term earnings dependency on downstream which is likely to remain in loss in 2015, per 2014.

Preferred: RD Shell (OW, PT 2,500p)One of the reasons for our OW recommendation on RD Shell is the restructuring potential of its North American Upstream and its global Downstream portfolios. Under the strong leadership of John Abbott, RD Shell aims to

improve Downstream financial performance, returns (target ROACE 10-12% versus 6.9% in 2013) and free cash flow (target CFFO > $10bn versus $7.5bn excluding WC 2013 or 20% of group CFFO). .

The first action was to atomize performance in order to enable more accurate capital deployment / rationing, and more value-oriented decision-making. RD Shell’s downstream business has been reorganized in to 72 of 150 group-wide business performance units, each with its own P&L, capital employed, cash flow and performance targets. A restructuring of RD Shell’s refining business is front and centre to this aspect of the group’s overall positive change story.

Figure 67 highlights the downstream ROACE improvement potential if RD Shell can reduce its exposure to loss-making Merchant Refining (plants with little or no integration e.g. Deer Park in the USA) and also raise the performance of its Integrated Refining & Marketing Value Chain (IRMVC which includes integrated refineries e.g. the Scotford refinery in Canada, but also some more challenged legacy integrated refinery positions such as those in Argentina and Pakistan).

Figure 67: RD Shell - downstream portfolio segmentation & performance

Source: RD Shell presentation NYC – 5 September 2014, Company data. Blob size

equates to capital employed.

At YE 2013, refining capital employed was around $33bn or just under 15% of RD Shell group capital employed. Excluding any contribution from fuels marketing, lubricants etc, we estimate that refining lost money in 2013 so this remains a real drag on Downstream and group ROACE. Of $33bn refining capital employed, merchant refining capital employed was approximately $15bn, but generated a loss between $(0.5)bn and $(1.0)bn with a through cycle ROACE ranging from -5% to +10%. The through cycle performance of its IRMVC sub-segment is even more

Merchant refining

Biofuels

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45




variable, ranging from -20% to +40%, underlining the varied quality of RD Shell’s legacy positioning.

Since 2007, RD Shell has sold 11 refineries with a total net capacity over 1 million bopd (Table 30). RD Shell continues to shrink its refining footprint via divestments.

Table 30: RD Shell refinery divestments since 2007kbd

Year Country Plant Net capacity 2007 France Berre L'Etang 80

Petit Couronne 154USA Wilmington 100

2008 Dominican Rep Haina 172010 Germany Heide 83

Sweden Gothenberg 872011 UK Stanlow 2962013 Norway Mongstad 432014 Czech Republic Kralupy & Litvinov 29

Australia Geelong 120TOTAL 1,009

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

We await the sale of its Fredericia refinery in Denmark to reduce its total refinery count to 27, less than half its peak refinery count of 55 in 2002. By exiting small minority positions e.g. the Kralupy and Litvinov refineries in the Czech Republic in 2014, RD Shell has almost doubled its unit net refining capacity since 2000 (Figure 68). The average gross capacity of its 28 refineries is now a more competitive 193 kbd (198 kbd if Fredericia is sold).

Figure 68: RD Shell - number of refineries & net refinery size


By concentrating its ownership in fewer, larger and more efficient, advantaged (by location, scale and integration) refineries RD Shell has reduced its working capital and maintenance capital needs. We note that Oil Products capex in 2014 may be around $3.3bn (based on 9M run-rate), down 21% Y-o-Y and an implied capex to depreciation ratio below 1x (Figure 69). RD Shell is also showing good availability of its global refinery portfolio

at 93% 9M 2014. These are all important drivers of RD Shell's growth in group operating and free cash flow.

Figure 69: RD Shell - Oil Products cash flow and capex / depn

Source: J.P. Morgan estimates, Company data. * Post tax cash flow calculated as net

income plus DD&A less capex so excludes changes to working capital.

The combination of refinery sales and a recent plant closure (Harburg – Germany) in Europe has also reduced its net capacity exposure to this most challenged region. Assuming an exit from Denmark, RD Shell's net European refining capacity will fall to 783 kbopd or 26% of its global capacity comprising interests in four refineries (Table 31). We note that in 2005, its European capacity percentage peaked at 46% of its global system. In contrast, we note that in 2000 BP’s European refining capacity was just 23% of its global refining capacity. As a result of refinery divestments ex-Europe, at YE 2013 BP’s European refinery capacity was 46% of its total capacity. Over the same period, RD Shell has raised its US refining exposure from 19% to 36% of its total, thus concentrating its position in what is now the most advantaged region for refining.

Table 31: RD Shell - European refining exposure

Capacity (kbopd)Country Plant Interest Gross NetGermany Miro 32% 310 99

Schwedt 38% 220 84Rheinland 100% 325 325

Netherlands Pernis 100% 404 404


Looking beyond Europe, on the Q3 2014 results conference call, Simon Henry (CFO) indicated that the group is reviewing its global distillation capacity and may close one of three CDUs at its Bukom refinery in Singapore (100%, 462 kobpd) which is an over-supplied fuels market. RD Shell has already reduced unplanned plant downtime to less than 2% in H1 2014 (Figure 70).

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Figure 70: Bukom refinery, Singapore - unplanned downtime (%)

Source: RD Shell presentation NYC - 5 September 2014

In the USA, where RD Shell owns 6 refineries, we also note a material improvement in the financial contribution from Motiva, RD Shell’s 50:50 downstream JV with Saudi Aramco (Figure 71). Motiva owns 100% of three Gulf Coast refineries (Louisiana: Convent – 227 kbd, Norco – 229 kbopd, Texas: Port Arthur – 600 kbd) with a total capacity of almost 1.1 million bopd as well as 35 terminals and 8,300 retail sites. The improved financial performance followed a change to Motiva’s management in 2014, improved plant reliability, lower cost feedstock selection with enhanced product yields and the successful ramp up of the Port Arthur refinery (now the largest refinery in North America) following some initial commissioning issues. We note that Q3 2014 Oil Product earnings benefitted $140m Q3-o-Q3 from a higher 50% share of Motiva earnings, so Motiva continues to drive Downstream performance improvement.

Figure 71: Motiva earnings and FCF (100%, $bn)

Source: RD Shell presentation NYC - 5 September 2014

All these measures should helpfully reduce the volatility of its Oil Products earnings stream which per Figure 72(including Merchant refining and Integrated refining + marketing value chain) demonstrates by far the highest through cycle ROACE variability.

Figure 72: RD Shell's regional refining exposure


At end Q3 2014, RD Shell’s total downstream business (Oil Products and Chemicals) held capital employed of $56.7bn or 25% of group capital employed. This has already shrunk from a peak of $69bn in mid-2011 through capex moderation (from a recent peak of $4.9bn in 2011), divestments (on-going), impairments ($2.284bn to global refining – primarily Bukom in Singapore -charge taken with Q2 2014 results) and, more recently, downstream product price weakness which has reduced working capital. We expect divestments to further reduce this capital pool and cost efficiency measures with improved plant operating efficiency to amplify the benefit to segment ROACE. This is a key driver of the group’s overall ROACE improvement objective which is, in turn, a key driver of the stock’s FCF generation and relative valuation.

Notwithstanding our cautious outlook for refining margins (especially in Europe), RD Shell’s Downstream restructuring which includes refinery divestments / impairments, improved cost efficiency and capital discipline should enable some overall ROACE and free cash flow improvement. This will help the group to cover its dividend in a lower oil price environment as we now forecast Brent 2015-16 $82-$88/bbl.

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47




Least Preferred: Galp (UW, PT €11.50)Galp has evolved from a pure play Portugal-focusedrefining company (pre-IPO in 2006) into a more integrated play driven by its exploration successes in Brazil (and more recently in Mozambique). Galp still retains an above sector average exposure to European downstream – which accounts for 15% of our Galp SOTP of €16.8/share. We believe that the outlook for this business remains challenging (downstream reported operating losses in 2 of the 3 quarters in 2014) – an ongoing negative for Galp's equity story, in our view.

Figure 73: Galp’s number of refineries and average size$/bbl


Refining exposure concentrated in Portugal

Galp’s refining business is concentrated in Portugal -total refining capacity increased to 330 kbd from 310 kbd in 2010. The company owns two refining assets: 1) Sines– started operating in 1978 (220 kbd) and has a NCI of 7.7; 2) Porto - started operations in 1966 (110 kbd) andhas a NCI of 10.7. Per Figure 74, we note that the utilization of Galp’s refining capacity has averaged only 71% 2008-13 vs. an average of 82% 2000-2007. This partly shows the impact of declining product demand in Iberia.

Figure 74: Galp refining capacity and utilizationkbd


Limited options

Galp has no plans to shrink its refining base. It invested€1.4bn upgrading its refineries/ conversion projects (2008-12). We believe that the loss of the US as a product export market and decline in product demand in Portugal means that the Galp would anyway struggle to find a buyer for these assets (no such intention expressed by the company).

Downstream profitability has been under pressure

Galp delivered average earnings per barrel processed of €0.7 per bbl over the period 2010-13, well below the comparable average for Repsol, the other name with abig downstream exposure to Iberia. Galp’s average post tax 2010-13 ROFA (return on total fixed assets) is only 1% -this is a low return. We believe that the earnings upside from the increased complexity have been more than offset by the weaker margin environment. As is often the case, returns from investing in complexity are often much lower than expected.

Figure 75: Galp post-tax income/bbl


Weak cash generation despite capital intensity decline

Galp's downstream cash generation (excluding changes to working capital) has turned positive over the last 2 years but the segmental cash contribution remains low. FCF contribution from downstream in 2012/13 is significantly below the 2002-2007 average despite the lighter product slate from the higher complexity. The negative cash flow (in 2008-10) was due to the acquisition of Exxon and Agip's downstream business in 2008 and higher capex spend on refinery upgrades in 2009-2011. Galp’s capital expenditure to depreciation ratio spiked in 2008 driven by these asset acquisitions. This ratio has averaged 1.5x 2000- 13 – this average has dropped to 0.6x 2012-13. We expect the capital intensity of the business to remain low.

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48




Figure 76: Galp downstream cash flow and capital intensity$m


Galp's strategy of heavy investment in European refining (conversion projects) was in contrast to the ‘step back' from refining theme noted with the other Euro names. The performance of Galp's downstream business has been persistently weak in recent years - reflecting a challenging operating environment in Portugal). This has denied any earnings upside from higher complexity.

Notwithstanding what appears to have been relatively low levels of reinvestment in last couple of years; Galp’s downstream cash flow (excluding changes to working capital) contribution to the group has reduced from a peak of €337m in 2006 to just €127m in 2012 and €152m in 2013. This deterioration in downstream cash return will certainly increase the stress on Galp’s B/S -especially given its relatively high capex commitments to non-operated upstream growth projects in Brazil, Mozambique and the weaker oil price outlook. We remind that Galp was an enforced seller of part of its pre-salt portfolio in 2011/12 and, judged by the share price reaction to the news of its dilution, the price achieved disappointed the market.

Figure 77: Share price performance

Source: Bloomberg.

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Russia – Slow upgrading in changing tax environment

Andrey GromadinAC

(7-495) 967-1037

[email protected]

J.P. Morgan Bank International LLC

Background

Russian oil sector taxation historically favored the refining sector. Since 2004 light oil product export duties (ED) were at about 70% and heavy oil product EDs at about 38-40% of crude oil EDs (65% above $25/bbl). This system was clearly beneficial for simple refining distillation units. In practice, the integrated oil companies (the holders of the bulk of the legacy Soviet Union refineries) were encouraged to maximize the existing distillation capacity utilization, while there were numerous small independent refinery projects with the key goal to play on export duty differential. As a result, the refining throughput increased by 40% for last 10 years and refining coverage reached 52% in ‘14 (vs. 42% in ‘04).

With growing crude oil prices, the government decided to support upstream at the expense of downstream and introduced a ‘60/66’ tax rebalancing: crude oil ED cut to 60% and equalizing product EDs at 66% from 4Q11. Gasoline/naphta rates were set at 90% to effectively ban export. In the same decree, the government introduced 100% ED on heavy oil products from 2015. This was the key encouragement for the oils to build cracking units. In a parallel process, the government was quickly raising gasoline/diesel excises, providing material discounts to high quality products (Euro4/Euro5). This supported the investments into hydrotreaters and hydrogen units.

2014 Overview

Operationally, the key events in 2014 were launching of two big hydrocrackers by Tatneft (2.9 m tons) and by SurgutNG (4.9m tons). Rosneft was gradually ramping up the upgraded capacity of Tuapse refinery within the existing infrastructure limitation, while Novatek was increasing the capacity utilization of Ust Luga gas condensate processing facility (launched in 2013). There were a number of serious accidents at Rosneft’s refineries throughout this year led by serious blast at the Achinsk refinery. Overall, 2014 was in line with the general trend of last few years: the integrated oils continued their refineries upgrading program with the key focus on light product quality improvement (a shorter payback) and worked on selective cracking units building.

Figure 78: Russian refining throughputmbd

Source: InfoTEK, J.P. Morgan estimates.

Figure 79: Russian crude oil output and refining coveragembd

Source: InfoTEK, J.P. Morgan estimates.

Figure 80: Integrated oils light product output and yieldmbd

Source: InfoTEK, companies reports, J.P. Morgan estimates.

The key focus of this year’s developments was clearly on the regulation front. Since the beginning of this year, the government started actively discussing a major ED/MET upstream taxes rebalancing (halving crude oil ED and doubling MET). Given ED level importance for the downstream, the tax regime changes also included a major review of oil product ED rates. The planning tax changes were called the ‘tax maneuver’.

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50




The government published the first draft of the tax changes in late August for the public discussion. The Duma approved the tax rebalancing in the first reading in late October. The government’s main idea of switching from export to production tax revenue collection remains intact. Given the Custom Union expansion plans, the rebalancing is inevitable, in our view. The draft legislation includes the following: 1) crude oil export duty (ED) marginal rate is to be cut gradually to 30% in 2018 (from 59% in 2014). 2) Gasoline and distillates EDs are set gradually to decrease to 30% and naphta ED to 55%in 2017, while fuel oil ED is to reach 100%. 3) Gasoline, diesel and heating oil excises are to be cut, while the document proposes RUB3,500/ton excise rates on aromatic products and jet fuel.

Table 32: Old/current tax regime

Old tax regime 60/66/90

55/60-66/90

55/60/90/100

‘04-‘10 2012 2015 2015Export duties ($/ton)Crude oil 433 402 370 370Light products 258 265 222 222Gasoline 258 361 333 333Naphta 258 361 333 333Heavy products 139 265 245 370ED differentials ($/ton)Crude oil/Light product 174 137 148 148Crude oil/Heavy product 294 137 126 0Heavy/Light -119 0 22 148ED differential basket($/ton)Simple 217 130 128 69Complex 171 80 84 61

Source: J.P. Morgan estimates; 60/66/90 EDs- 60% crude oil, 66% products, 90% gasoline;

55/60-66/90 EDs- 55% crude oil, 60-66% products, 90% gasoline; 55/66/90/100 EDs- 55%

crude oil, 60% diesel, 90% gasoline, 100% heavy products.

Table 33: New tax regime (after major tax rebalancing)

New regime New regime vs.2015 2016 2018 Old 60/66 Current

Export duties ($/ton)Crude oil 290 253 215 -217 -186 -155Light products 139 101 65 -194 -200 -158Gasoline 226 154 65 -194 -297 -269Naphta 246 179 118 -140 -243 -215Heavy products 220 207 215 76 -50 -155

ED differentials ($/ton)Crude oil/Light product 151 152 151 -24 14 3Crude oil/Heavy product 70 45 0 -294 -137 0Heavy/Light 81 106 151 270 151 3ED differential basket($/ton)Simple 101 94 75 -141 -55 7Complex 87 96 106 -65 26 45

Source: J.P. Morgan estimates; ‘Current’ assumption suggest 100% heavy product ED.

The implications for the refining business

Simple distillation profitability will still suffer (-$55/ton, -$7/bbl), as heavy product ED differential shrinks by $137/ton ($19/bbl) in 2018. Complex refining profitability should improve moderately (+$26/ton, +$4/bbl). This happens mainly due to the gasoline ED rate cut to 30% of crude oil rate from 90% (+$111/ton, +$15.0/bbl).


The numerous changes in the taxation throughout last three years raised the risks for the refining segment. There is no certainty that the planning major tax rebalancing is a final one and the government would not amend the legislation in coming years. On the other hand, the sanctions introduced against certain oil and gas companies and remaining uncertainties in Russia/Ukraine situation development effectively closed the access to the debt markets for Russian oil and gas companies, limiting financing ability for sector. In this situation, the medium-term outlook consists of three main parts:

Figure 81: Product ED differential basket (‘15E) vs. crude oil price $/bbl


The growth in independents distillation capacity stopped given higher taxation of heavy oil products. If a new distillation facility is built it means that it will need to be upgraded, significantly raising capital cost requirements. The key exemptions from this trend are 1) potential Tatneft’s Taneco capacity raising to 14 mn tons (the existing refinery is overly complex even with 8.5 mn tons run rate); 2) Rosneft’s Far East downstream facility (24 mn tons) driven mainly by political reasons, in our view; 3) potential gas condensate processing facilities, producing predominantly light products even in simple configuration.

The upgrading programs implementation delays with finishing the process is now expected in 2017-2020 vs. 2015-2016 targeted previously. The key driving factors are limited financing, heavy product tax increase delay and the regulation uncertainties. The gradual

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improvement in the light yields is still on agenda for the integrated oils, but the process development is extended by at least 3-4 years. According to our estimates, the light yield for the integrated oils (holding about 84% of distillation throughput currently) could reach 78-80% by 2020 from current 59% in 2014, implying slightly more than 1 mmbpd of extra light product output.

The simple distillation capacity utilization might be under pressure from the oil prices and the regulation. The undergoing tax changes in the sector make the refining profitability even more sensitive to the oil price. According to our rough estimates, the economics of remaining relatively simple refining operations could become relatively questionable for some distant regions if ED differential basket falls below $10/bbl given the extra costs on transport and processing. In particular, the dependent sector accounting for about 16% of total refining throughput (c. 800 kbpd) might be at risk.

Preferred: Novatek (OW, PT $130)

Novatek has the lowest refining exposure in the Russian oil and gas universe. The company operates Pur gas condensate stabilization plant (upgraded to 11 mn tons) in West Siberia and Ust Luga gas condensate processing facility (6 mn tons) located on Baltic Sea, where it refines gas condensate mainly into naphta and light product mix. Taking into account light own feedstock at Ust Luga, the company will not have to upgrade the facility in conditions of higher taxation on heavy products.

Figure 82: Ust Luga gas condensate processing facility

Source: Novatek.

Least Preferred: Rosneft (UW, PT $5.0)

Although Rosneft spent more than $17 bn in refining segment capex for the last five years, the key complexity upgrade projects are yet to start. Roughly half of the spending was allocated on building new Tuapse refinery and terminal. We suppose that the rest of money was mainly spent on light product quality improvement. We believe that the company is likely to spend not less than $25 bn on the refining segment (excl Far East greenfield) within next four years and new unit launching delays/capex overruns risks are substantial.

Figure 83: Rosneft refining capex ($ mn)

Source: Novatek.

Rosneft still has a huge Far East refining and petchem facility still in the pipeline. The capex requirements for all three stages (1) 12 mn tons refining, 2) 3 mn tons petchem and 3) 12 mn tons refining + 3 mn tons petchem) have been indicated at RUB1.3 trln. The project is unlikely to be economically viable, taking into account changing tax landscape, but the management is still keen to go ahead with its development and even asked the government about financial support from National Wellbeing fund.

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Poland/Turkey – Fuel importers

Neeraj KumarAC

(971)4428 1740

[email protected]

J.P. Morgan Chase Bank, N.A. Dubai Branch

2014 Overview

Turkey and Poland import about 25%-35% of fuel required. Tupras is the sole refiner in Turkey and provides about 65% of fuel demand while PKN provides about 60-65%. We have seen an increase in fuel consumption YTD on the back of improving economy and as demand improves from a lower base in both Turkey and Poland. In Turkey, diesel/jet fuel/gasoline consumption increased by 2%/12%/2% over the Jan-Aug14. There was an increase in fuel oil consumption by about 1.6% mainly due to a higher demand from power sector. In Poland, diesel/ gasoline consumption increased by 0-2% over 9MTD.

Figure 84: Turkey: diesel consumption (mt)


Figure 85: Poland- fuel consumption growth (%)


On the refinery margin front, Mediterranean refinery margins (complex) reduced to $1.4/bbl in 9M14 from $2.13/bbl in 9M13. Despite the decrease in Mediterranean refinery margins (complex), Tupras’ average net refinery margins slightly increased to $2.71/bbl in 9M14 from $2.59/bbl in 9M13 mainly on a better demand environment and crack spreads. However, refinery margins remain challenging for PKN with average refinery margin of $2.9/bbl in 9M14 vs $4.3/bbl

in 9M13. PKN recognized impairment charges in 2Q for refining assets (which could process10mt crude) of Orlen Lietuva. We expect refinery assets of Orlen Lietuva to run at relatively low operating rates c.60-70% in 2015. Both TRY and PLN depreciated more than 5% YTD had a negative impact on the earnings.

Figure 86: Tupras’ refinery margin vs Mediterranean ($/bbl)


Figure 87: PKN- model refinery margin ($/bbl)


2015-16 Key Issues/Risks:

In our view, apart from challenging refinery margin environment, other key issues/ risks are development in the fuel demand growth, varies crude oil grades differential with Brent, currency depreciation, and any geopolitical risk. Despite, our negative view on the refinery margins, we expect Tupras to benefit from its Residuum Upgrade Project (RUP) which would increase the fuel/white product yield and hence higher margins. In our view, lower crude oil price is positive for Turkish GDP growth. This should have a positive impact on the fuel demand growth in 2015 but it remains to be seen.

We expect transportation fuel consumption to increase in Turkey due to a low auto penetration rate (120 cars per 1000 person vs more than 400 cars per 1000 person for EU). Poland has an above average autos penetration of 486 cars per thousand people. This rate is close to some of the WE countries, i.e. France and Germany, which is not hugely supportive of very high fuel demand growth over the long term, in our view.

Key Stock Picks: We prefer Tupras over PKN.

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Preferred: Tupras (OW, PT TL57)

We are OW on Tupras due to: 1) Potential of margin improvement by more than 150bps due to the Residuum Upgrade Project (RUP); 2) Tupras’s capex cycle is nearing its end, so increasing dividend potential; 3) Tupras’s key demand drivers are still intact, i.e. low autos penetration (120 cars per 1000 person vs average 450 for EU); 4) Increase in fuel demand. Diesel demand consumption grew by 7% in 2013 and > 5% in 1H14. There was increase in gasoline consumption by 1-2% in 2013 and 1H14. (Benefit from better product cracks in 3Q but inventory losses/fx could be a drag; Prefer Tupras over PKN)

Least Preferred: PKN (UW, PT PLN38)

We forecast an EBITDA increase over 2014-17 of PLN1.6bn, c20%, below company guidance, mainly on lower contribution from downstream business. We forecast Petrochemical will be the biggest contributor to 2014-17 EBITDA (c42%), with retail (c27%) in line with company guidance and upstream benefiting from recent acquisitions in Canada. We are cautious on shale production in Poland. We believe tough refinery margin to be a drag on downstream business. We think downstream margins are likely to remain under pressure and forecast average model downstream margin of $9.9/bbl, below guidance of $11/bbl over 2014-17. Downstream business contributes c70% of 2014-17E EBITDA (LIFO). In our view, capital discipline remains key as the energy and upstream businesses get an over-proportionate share of development capex (c60%) vs. limited contribution (c6%) to 2014-17E EBITDA.(Tough refinery margin outlook, ambitious EBITDA guidance- Initiate with UW)

https://markets.jpmorgan.com/research/email/-m355e0p/GPS-1502418-0.pdf

https://markets.jpmorgan.com/research/email/-m355e0p/GPS-1502418-0.pdf

https://markets.jpmorgan.com/research/email/-3l17u23/GPS-1519139-0.pdf



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Appendix I: Downstream glossary of terms

Refining

The core refining process is simple distillation (Table 34). 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 34: 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.

Alicyclic hydrocarbons – ringed hydrocarbons in which the rings are made up only of carbon atoms.

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Distillate fuel blending

Fluid catalytic cracking

Coking

Crude oil

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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 32.5 degrees 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 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.

56




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.

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

57




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 35: 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.

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.

58




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 thecomponents 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 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

http://en.wikipedia.org/wiki/Value_added

http://en.wikipedia.org/wiki/Throughput_(business)

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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).

Refinery product yields - these are used for refinery margin calculations and, as per Table 36, vary with crude feedstock and refinery configuration.

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Table 36: 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.

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.

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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.

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

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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.

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.

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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 II: Investment Thesis, Valuation, Risks

Phillips 66 (Overweight; Price Target: $96.00)

We remain Overweight. While shares have underperformed recently, we still see many value levers available to pull, as PSX has the most diversified portfolio in the group and the highest potential for more stable growth outside of refining(Midstream and Chemicals). Further, we see a strong backlog of MLP drop down opportunities (to PSXP) within Midstream. As a result of its diversity, we also see the lowest downside risk at PSX in a scenario where the crude export ban gets lifted (~15% EPS downside, group average ~28%), making PSX an attractive investment in both our base case and our downside case.

We maintain our price target of $96/share. We have valued PSX using a sum-of-the-parts approach on its adjusted (look-through) EBITDA, given the significant uplift from JVs with minimal related debt. On this basis, we have a December 2015 price target of $96/share, which represents 39% total return potential, including dividends (group average 29%). In our scenario where the crude export ban gets lifted in 2016, we estimate ~15% EPS downside for PSX (group average 28%), lowest in the group. Coupled with PSX’s MLP upside potential, we think risk-adjusted return potential is favorable.

Risks to Rating and Price Target

We believe the primary downside risks to our price target and Overweight rating include: growing concern that the crude export ban will be lifted; weaker Brent prices cause contraction in olefin chain margins within Chemicals, weighing on EBITDA growth/multiple; Midstream EBITDA growth does not meet expectationsand/or NGL prices weaken relative to natural gas; scaling back of share buybacks while in growth phase; Gulf Coast crude spreads narrow versus those of international markets; and Mid-Continent crude spreads tighten versus those of other markets.

Marathon Petroleum (Overweight; Price Target: $118.00)

Investment Thesis

We remain Overweight. We see MPC as a solid way to play the most favorable themes in US refining, given that all of MPC’s exposure is in the US central corridor, which we expect to remain crude cost advantaged (to varying degrees) relative to the East and West coasts. MPC also has several refining projects under way to drive controllable EBITDA growth. Finally, MPC is diversifying its portfolio into higher-multiple logistics and retail businesses (~22% of 2016E EBITDA), both of which have non-macro levers for growth and significant MLP value creation opportunities.

Valuation

Using our sum-of-the-parts approach, we estimate a December 2015 price target of $118/share (28% upside, group average 26%). In a downside case in which the export ban is lifted, we see 7% upside (group average 9%).


We believe the primary downside risks to our price target and Overweight rating include: growing concern that crude export ban will be lifted; Gulf Coast crude spreads narrow versus international markets; Mid-Continent crude spreads tighten

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versus other markets; refining project execution does not live up to expectations; Hess retail acquisition integration synergies miss targets; and MLP valuations take a step backward or rules change around MLPs.

Hindustan Petroleum Corporation (HPCL) (Overweight; Price Target: Rs690.00)

Investment Thesis

With lower oil prices likely to lead to a quicker reduction in subsidy losses, and also support a gradual expansion in margins. HPCL is most levered to reform/crude and we see HPCL as continuing to remain well placed. Unlocking value from infrastructure assets could provide further upside

Valuation

We have an OW rating and a Mar-16 PT of Rs690. Our PT is based on 56x EV/EBITDA. Our estimates are based the downstream not bearing any subsidy losses in FY17.

HPCL Valuation

EV/EBITDA multiple 6.0

EBITDA (Rs mn) 62,353

EV (Rs mn) 374,118

Debt 252,733

Cash/Inv. 112,173

Net Debt (Rs mn) 140,560

Equity value (Rs mn) 233,558

No. of shares 339

FAIR VALUE (Rs/sh) 690Source: J.P. Morgan estimates.


Downside risk emanates from higher crude/a weaker rupee, no improvement in diesel margins, roll back of reform, and loss of higher-than-expected market share, while upside risks are better-than-forecast refining margins and higher margins.

Caltex Australia Ltd (Overweight; Price Target: A$28.44)

Investment Thesis

Retain Overweight. Despite recent share price performance and early progress on business reposition, we suggest there is further upside with key drivers remaining: (1) Leveraging the infrastructure network; (2) Leveraging the retail network and brand; and (3) Improving the financial position. While valuation support has moderated (DCF A$26.54), we note the FY15 multiple remains underwhelming for a company with significant earnings growth, rising consensus earnings forecasts, and the prospect of capital management.

Valuation

Our DCF valuation is A$26.54 per share as detailed in the table below.

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Table 37: CTX – DCF Valuation Summary

A$ in millions

PV of Cash Flows $4,361Terminal Value $3,672

Enterprise Value $8,032Net Debt $854Minority interests $11

Valuation $7,167Per Share (A$/share) $26.54



Our 30 June 2015 share price target has increased to A$28.44 per share from A$27.38 per share. This share price target is based on our DCF valuation, rolled forward at the cost of equity (10.3%), less the FY14 interim dividend (A20cps) and the FY14E final dividend (A21cps).

Risks to our share price target include:

Lytton refinery (operating and incident risk);

Currency (lower AUDUSD negative for accounts payable near term, positive for CRM and Refining & Supply EBIT medium/long term);

Caltex Refiner Margin (lower CRM a negative for Refining & Supply EBIT);

Changing product mix within transport fuels (slower growth in higher margin premium fuels a negative for Marketing EBIT);

Increasing capital investment by some competitors (additional capacity adds competition for volumes which could reduce margins);

Major customer risk (WOW comprises ~20% of revenue); and

Government and regulatory (CTX operates in a highly regulated industry).

Royal Dutch Shell A (Overweight; Price Target: 2,500p)

Investment Thesis

We remain Neutral on RD Shell given some welcome signs of improved medium-term capital discipline. However, we continue to harbor some structural concerns: 1) We believe RD Shell continues to carry too much low-return capital employed e.g. refining and Upstream Americas and it will take 1-2 years to raise the productivity of these large units. 2) We are relatively oil price cautious – the breakeven oil price to avoid borrowing to pay its dividend is above $100 per barrel – an oil price around or below this level could undermine its dividend appeal and would send the dividend yield higher. 3) RD Shell remains over-exposed, in our view, to refining where we have a structurally negative view on margins in 2013. 4) RD Shell is absent or under-exposed in many of the key frontier exploration plays, e.g. East Africa and the pre-salt Santos Basin; its exploration performance continues to disappoint. 5) However, RD Shell has above-average exposure to high quality LNG assets – we have a very positive view on global LNG in 2014.

ValuationOur SOTP is £28.5 per share to reflect recent disclosures and assumptions. It continues to reflect our latest long-term Brent oil price of $90/bbl (US natural gas price of $4.75/mmbtu) with 2013 disclosures relating to upstream reserves,

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downstream assets and off balance sheet liabilities. Provided RD Shell 1) confirms and successfully executes a large divestment program in 2014-15 and 2) demonstrates that organic capex of $35bn pa is a peak, we believe that a discount to our SOTP is still appropriate. We note a long-run average discount of 21%. We note a long-run average discount of 21%. We reset our fair value price target to £23.25 which represents an 18% discount to our SOTP (very close to our prior discount of 19%). It implies a 2014E PER of 12x and a dividend yield just below 5% and a price to book multiple of 1.2x – this seems reasonable given a 2014E (2015E) ROACE of 9% (8%). The two factors which constrain upside are negative free cash flow in 2014-15 (an uncovered dividend) and a relatively high 2014E EV/DACF multiple of over 7x.


Downside risks: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. Sustained oil price strength (much above $100 per barrel) would de-risk RD Shell’s dividend since it would provide the all important cash flow cover.

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 to incorporate more of a regional gas hub connection.

Upside risks:

Portfolio shrinkage – RD Shell could sell more than $15bn of assets 2014-15 and divest more refineries. This would reduce RD Shell’s exposure to a very volatile and low return stream.

Improved capex control is followed by opex efficiency drive – We assume an organic capex spend of $35bn pa. It is possible that RD Shell will supplement better capital disciple and announce an operating cost efficiency drive in H2 2014.

Novatek (Overweight; Price Target: $130.00)

Investment Thesis

Novatek is the largest Russian independent gas producer, operating in West Siberia and on the Yamal peninsula. The company expanded its liquids value chain through addition of the Ust-Luga fractionalization plant and the expansion of condensate processing capacity at the Purovsky plant, aiming to accommodate rising liquids production at the equity subsidiaries such as SeverEnergia and Nortgas.

Although we see limited opportunities for the company in the gas segment because of pricing pressure and existing reserve base limitations, Novatek should be able to

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demonstrate an 18% CAGR over 2013-2020 in adjusted net income. Novatek GDR’s valuation offers an attractive risk/reward opportunity at this point, in our view.

Valuation

Our end-’15 price target of $130/GDR is based 50% on our DCF-based end-15 fair value and 50% on our target (normalized) EV/EBITDA (‘15E). We calculate our DCF using a WACC of 13.2% and terminal growth rate of 3.0%, assuming no additional discount in terminal value. We perform separate valuation exercises for the company’s equity projects, such as Yamal LNG, SeverEnergiya, Nortgas and Yarudeyskoye, based on the projected cash flows and Novatek’s effective ownership percentage, and add them to our DCF-based value of the core business. Our target EV/EBITDA multiple is derived by dividing our DCF-based (target) EV by our estimated normalized EBITDA for ‘17-18E. Our target EV/EBITDA (15E) for Novatek is 7.6x.


We believe the key downside risks that could prevent our rating and price target from being achieved include the following: flat or declining domestic gas prices, fluctuations in oil prices affecting the liquids side of the company’s business, and further expansion in US/EU sanctions terms against the company.

Tupras (Overweight; Price Target: TL57.00)

Investment Thesis

Tupras is independent and the sole refiner in Turkey with a throughput of 28.1m tons and Nelson Complexity index of 7.25. The company serves about 65% of the energy deficient Turkish refined product demand and generates more than 20% of revenues from exports.

Tupras benefits from a low motorization rate in Turkey and domestic demand drivers remain intact. RUP (Residuum Upgrading Project) remains one of the key positive catalysts for the company and is expected to come online later this quarter which could improve gross margins by up to 200bps, in our view.

Valuation

We derive our Dec15 PT of TRY57 using a DCF approach. Our key assumptions are a terminal growth rate of 3% and weighted average cost of capital of 12%.


The primary downside risks to our rating and price target include:

Execution risk/cost overrun for RUP and other investment projects.

Higher than expected impact from price ceiling from EMRA,

Lower-than-expected refined products demand growth

Crude oil supply disruptions

Lower-than-expected product prices and refining margins

Decreasing discount between Brent and heavy crude oil benchmarks

Meaningful fines from ongoing investigations

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JX Holdings (5020) (Neutral; Price Target: ¥480)

Investment Thesis

Investor confidence in the company has been hurt by a series of guidance misses caused by such factors as declining profitability in the petroleum business and delays in copper development. We think this has rendered the shares unlikely to advance on expectations alone. While we think the shares do look attractive at their current level, we also see little possibility of a rally until the company starts delivering better results.

Valuation

We base our price target on a P/B derived from an RoE-P/B matrix. Our price target of ¥480 is based on end-Q2 FY2014 BPS of ¥849 and a P/B of 0.6x, derived from our FY2014 ROE forecast of 4.2%. The implied P/E is 14x based on our FY2014 forecasts. The timeframe of our price target is through December 2015.


Change in shareholder returns: A larger-than-expected dividend hike (cut) could pose upside (downside) risk for our price target. A share buyback announcement would also pose upside risk.

Fluctuation in resource prices: JX Holdings develops crude oil, natural gas, and copper, meaning that profits are highly exposed to fluctuations in resource prices. A sharper-than-expected rise (decline) in resource prices could pose upside (downside) risk for our price target.

Expansion of power generation and other domestic energy business: With Japan deregulating its electric power and gas industries, energy companies such as JX are seeing expanded opportunities for entry. Participation in these new businesses could pose upside risk for our price target.

Industry realignment: Industry realignment could pose upside risk for our price target even if JX is not a principal, as it could generate expectations for a better supply-demand balance for petroleum products.

Fluctuation in refining margins: Every ¥1/liter fluctuation in the refining margin impacts annual recurring profit by around ¥40 billion. A sharper-than-expected rise (decline) in the refining margin could thus pose upside (downside) risk to our price target.

Refinery glitches or accidents: Protracted refinery shutdowns owing to technical glitches or accidents could have a major impact on profits and could therefore pose downside risk for our price target.

Fluctuation in petrochemical prices: A sharper-than-expected improvement (deterioration) in petrochemical prices could pose upside (downside) risk to our price target.

PETROBRAS PN (Neutral; Price Target: R$25.00)

Investment Thesis

We rate the four Petrobras stocks that we cover Neutral. We have a Neutralrating on Petrobras shares on the back of: i) uncertainties on short-term production behavior and a miss on the 2014 production guidance—we estimate 2014 production to average 2,662kbd, 2% higher than 2013 production; ii) FX devaluation impact on fuel import costs and leverage; and iii) lack of clarity on fuel price readjustments and

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a specific price readjustment policy that would allow prices to be readjusted according to international parity.

Valuation

We rate the four Petrobras stocks that we cover Neutral. We have Dec’15 price targets of $17/ADR for ONs and $18/ADR for PNs, as well as R$24/ON share and R$25/PN share. Our YE15 price targets for PETR3 and PETR4 are based on our PBR and PBR/A targets using a year-end 2015 BRL exchange rate of R$2.80/USD. We value the 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 to all of PBR’s refining systems. We apply a WACC of 10.0% with an equity risk premium of 6.0%.

Table 38: PETROBRAS ON ADR



Downside risks Sensitivity to oil prices: PBR generates incremental EBITDA of ~$29 million for

every 1% decrease in reference oil prices, by our estimates. Should oil prices retreat or fail to meet our 2014 average assumption of $100/bbl (Brent), share prices would likely decline.

Returns from new investments could be lower than estimated. The company has a capital expenditures plan for 2012-16 of $233 billion. While we believe the investments devoted to E&P projects are strategic and therefore unlikely to be

EM Integrated Oil Valuation - PETROBRAS (USING OIL @ $87.75/BBL LT in 2016) and $90/bbl LT

EV / Unit Firm Value

NPV per ADS Capacity Type per unit WACC

CONSOLIDATED ASSETS

Prov en Reserves 110,577 $16.95 10,594 $10.4 Variables

Probable 19,940 $3.06 3,475 $5.7 Equity risk premium 6.0% a

Ex isting Brazil 130,516 $20.01 14,069 Rsrvs $9.3 Long term US bond 2.3% b

Tupi (Lula) 27,062 $4.15 3,670 $7.4 LT Country Spreads 2.5% c

Iara 10,010 $1.53 2,201 $4.5 Risk-free rate 4.8% d=b+c

Guará (Sapinhoa) 9,628 $1.48 920 $10.5

Carioca (Lapa) 1,810 $0.28 229 $7.9 Cost of equity

Rights Cession 35,023 $5.37 4,999 $7.0 Target Leverage (D/D+E) 35% e

Iracema (Cernambi) 12,136 $1.86 1,201 $10.1 D/E 54% f=e/(1-e)

Carcara 3,335 $0.51 536 $6.2 Unlev ered beta 1.08 f

Jupiter 144 $0.02 226 $0.6 Levered beta 1.46 h

Libra 4,798 $0.74 3,338 $1.4 Cost of Unlevered Equity 11.3% i=a*f+d

Exceeding Rights Cession 12,359 $1.89 8,890 $1.4 Cost of Levered Equity 12.3% j

Pre-Salt 116,305 $17.83 26,210 Resource $4.4 Cost of Debt

Upstream 246,821 $37.84 40,279 Rsrvs/Rsrc $6.1 US$ debt spread 6.3% k

Refining 13,688 $2.10 Cost of Debt 8.5% l=b+k

Int'l (non-upstream) 1,842 $0.28 Tax Rate 34% g

Distribution 4,721 $0.72 WACC 10.0%

Biofuels (1,720) ($0.26)

Gas & Energy 2,773 $0.43

Corporate (19,365) ($2.97)

Downstream & Other 1,938 $0.30

Total 248,759 $38.14

Unconsolidated Assets - BAK 2,006 $0.31

- Net Debt '15E (142,743) ($21.89)

+ Div idends paid 14 2,563 $0.39

- Net Working Capital Changes 89 $0.01

Equity Value 110,675 $17.0

Number of Shares mn FY15 6,522

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modified, investments in segments such as 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 should boost PBR’s NAV by $3.0/ADR, by our estimates.

Demonstrating larger scale of pre-salt fields already in portfolio. An increase of 1bn boe in pre-salt resource base should boost PBR’s NAV by $0.8/ADR.

Reliance Industries Ltd (Neutral; Price Target: Rs1,080.00)

Investment Thesis

We remain positive on RIL’s strategy of organic growth in its core businesses and continue to see strong earnings delivery with the commissioning of new capacities –we expect a 17% earnings CAGR over FY14-FY17. However, we do not see a material change in earnings trajectory near-term, while uncertainty over telecom spends is likely to continue to weigh on the stock. We believe GRM are likely to be slightly better, but will be offset by weaker petchem margins, with earnings driven by capacity growth. We factor in gas price reform, but a turnaround in production is likely to be slow, in our opinion.

Valuation

Our SOTP-based Sep-15 PT of Rs1,080 values the refining, petchem and shale/PMT businesses at 6.5x, 7.5x and 5x EV/EBITDA, respectively (in line with peer groups). We value the D6 stake on an NPV basis and investments at book value (with telecom at a 50% discount to BV).

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RIL: SOTP valuation

Source: J.P. Morgan estimates


Key downside risks include project delays, weaker refining/PX margins and a stronger rupee, adverse E&P regulations and significantly larger-than-expected telecom spend/losses.

Key upside risks include better-than-expected refining margins, higher-than-expected gas price rises and an improvement in petrochemical demand/margins.

Sinopec Corp - H (Neutral; Price Target: HK$7.00)

Investment Thesis

Sinopec is the second-largest oil company in China. It is integrated with E&P, R&M and chemicals. In 2013, crude production was 0.9mn BOPD and natural gas 0.30mn BOEPD, refining throughout was 4.9mn BOPD, ethylene production 10mn tonnes. Sinopec has SEC proven reserves of 4.4bn BOE (70%+ is crude). Our Neutral view is based on the following:

Improving refining margins on improved product specs – We expect Sinopec’s refining margins to improve as China moves to tougher gasoline standards. China IV gasoline may add cUS$1/bl to refining margins in 2014 and almost a similar incremental uplift for diesel in 2015.

Sep-15 SOTP Rs m US$ bn Rs/share Comments

RefiningExisting Refinery

Refining EBITDA 175,954EV of Refining business 1,143,698 18.9 354 At 6.5x EV/EBITDA - in line with peers

Value of Refining businesses 1,143,698 18.9 354

Petrochemicals

Petchem EBITDA 155,443 EV of petchem business' 1,165,826 19.3 At 7.5x EV/EBITDA - in line with peers

Value of Petrochem business 1,165,826 19.3 360

Shale/PMT and other assetsShale/PMT EBITDA 89,410 PMT and shale businesses 447,052 7.4 138 At 5x EV/EBITDA - in line with peersNew E&P Assets 569,862 9.4 176 SOP of E&P assets without sustainability premiumValue of total E&P & other assets 1,016,914 16.8 314

Investments and Net debt Treasury stock 281,004 4.6 87 Net Cash (103,869) -1.7 (32) (Cash+Investments-Debt).

Value of Investments and Net debt 177,135 2.9 55

New E&P Assets Rs mn US$ bn Rs/Share

KG D-6 Gas + Oil 390,542 6.5 121DCF based on 60 mmscmd of peak production + 60K b/d of oil production from MA fields

NEC-25 + CBM 179,320 3.0 55NEC -25 50% recovery and CBM at 50% recovery at US$ 3.5/boe

New E&P Valuation 569,862 9.4 176

Value for Equity holders (Rs m) 3,503,574 57.9 1,083

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Demand outlook for refined products remains strong – Earnings are expectedto be driven by robust Chinese oil demand growth (4% y/y) from double-digit gasoline demand growth more than offset by diesel demand growth at 1% y/y.

Natural gas upside – Strong natural gas production growth as well as further natural gas price hikes should support upstream profitability.

Lack of positive catalysts in the medium term - Post announcing its USD17.5bn marketing stake sale, we see the pace of reform at Sinopec slowing down as the company digests the stake sale (focus on IPO) and previous purchases (international E&P assets, Yanbu refinery); additionally, we have increasingly limited visibility on use of the proceeds of the stake sale in the medium term.

Valuation

Our Dec-15 PT of HK$7.0 is based on our DCF valuation of the different segments, using a WACC of 10.5% and a terminal growth rate of 3%.


Risks to our rating and PT include: lower/higher domestic oil product demand; a collapse/improvement in chemicals profitability from weaker/higher margins; and lower-/higher-than-expected incremental refining margin upside from fuel spec reform.

S-Oil Corp (Underweight; Price Target: W29,000)

Investment Thesis

S-Oil is an integrated refiner/petrochemical company with downstream in PX. In Korea, refiners’ profitability can be highly volatile due not only to swings in GRMs and PX spreads, but also to FX and commodity movements. Swings in the latter two components can wipe out operating profits in some quarters. We are more positive on refining in 2014, but negative on PX spreads due to overcapacity.

Valuation

UW with Dec-15 PT of W29,000: New valuation is based on 0.6x 2015E BV, as we now expect 2015-16 ROE to average 6%. While S-Oil is already trading at trough valuations, we believe there are further downside risks due to a weaker refining outlook for 2015 and PX likely to stay near trough valuations for the foreseeable future. We see the potential for S-Oil to cut its dividend payout for 2014 as another de-rating risk for the stock.


Upside risks to our rating and price target include a strong rebound in PX spreads due to new capacity delays and a spike in oil prices.

Sinopec Shanghai Petrochemical (Underweight; Price Target: HK$1.50)

Investment Thesis

Sinopec Shanghai Petrochemical is one of the largest integrated refining and petrochemical companies in China. It is a subsidiary of Sinopec Corp (386 HK). It produces refined oil products, intermediate, petrochemicals, synthetic resins and synthetic fibers. The company recently completed the 6th Phase expansion and

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upgrading program which increases its effective refining capacity to 16mn ton/yr from 12 mn ton/yr. Shanghai Petrochemical is currently capable of producing gasoline meeting Euro V (similar to China standards), and diesel of Euro IV and Euro V qualities. Key points to our negative view include:

Limited view on capex spending – While the company has cut its Rmb2.0bn capex spending in FY14 to Rmb1.2bn, we remain unclear on if the cut is merely a delay of project spending to be pushed into FY15 (we model Rmb2.0bn capex in FY15). High capex spending in chemicals capacity limits free cashflow.

Weakness in petrochemicals to continue; limiting refining upside – With petrochemicals pricing weak going into 2015 and limited improvements forecasted, we believe that the commodity chemical segments will remain a drag on SPC’s earnings.

ValuationOur Dec-15 PT of HK$1.5 is based on DCF. We have applied a WACC of 11.2% and perpetual growth rate of 2% in our DCF calculations.


Risks to our price target include improving petrochemicals pricing, better-than-expected improvements in GRM’s on the shift to higher spec gasoline/diesel, asset injections from Sinopec, and the A-H share through-train program shrinking the discount of SPC’s H-share listing vs A-shares.

PKN ORLEN (Underweight; Price Target: zl38.00)

Investment Thesis

We have an UW rating and Dec15 PT of PLN38. Our 2014-17E EBITDA (LIFO) increase is c20% below PKN guidance and our 2015/16E EPS is c5-10% below BBG consensus. We see tough refinery margins being a drag on the downstream business, which contributes c70% of 2014-17E EBITDA (LIFO). In our view, capital discipline remains key as the energy and upstream businesses get an over-proportionate share of development capex (c60%) vs. limited contribution (c6%) to 2014-17E EBITDA. PKN’s valuation looks demanding to us.

Valuation

We derive our Dec15 PT of PLN38 from our DCF valuation. Our key assumptions are 1) terminal growth rate of 2%, and 2) weighted average cost of capital 8.8%.

Risks to rating and price target

Upside risks:

Higher-than-expected downstream, refinery and petrochemical margin

Higher-than-expected Brent/Ural differential

Better-than-expected refined product demand growth

Better-than-expected operating rates for plants

Higher-than-expected production from TriOil and Birchill in Canada

Crude oil supply disruptions due to various potential reasons

Changes in the regulatory environment for E&P/shale in Canada/Poland

Any lack of capital discipline

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Overpayment for any potential acquisition in upstream/other businesses

Unschedule maintenance shutdown

Rosneft (Underweight; Price Target: $5.00)

Investment Thesis

With total hydrocarbon output exceeding 5 mmboe/day, Rosneft is the largest global crude oil producer. Given the size of the company, efficient maintenance is the key issue: expansion in the gas segment is becoming less attractive, in our view, while any planning growth in crude oil production is getting more and more challenging. The company is included in both the US and EU sanctions lists, effectively banning the company from access to the global debt markets. Taking into account cash on balance sheet and more crude oil prepayments in the future, we believe that Rosneft's financial position looks manageable even though net debt/EBITDA exceeds 2x.

Valuation

Our end-15 PT for Rosneft of $5.0 is based on a 50% weight of DCF-based fair value and 50% weight on target (normalized) EV/EBITDA (’15E). This is our standard valuation approach for Russian oil and gas companies. We calculate our DCF using a WACC of 12.3% and terminal growth rate of 3.0%, assuming additional 23% discount in terminal value due to discrepancy between expected dividend flow and FCF generation in the LT. Out target EV/EBITDA multiple is derived by dividing our DCF-based (target) EV by our estimated normalized EBITDA in 2017-2018. Our target EV/EBITDA (15E) for Rosneft is 4.2x.


We consider additional state financing support, improvement in the dividend policy, potential gas pipeline export access and the existing sanctions removing as the key upside risks, in our view.

Ecopetrol ADR (Neutral; Price Target: $30.00)

Investment Thesis

Ecopetrol’s biggest challenge remains reserve addition and LT production growth. We rate EC Neutral and maintain our view that Ecopetrol’s main challenge remains long-term sustainability. After peaking in 2009 with reserves life reaching eight years, the ratio has decreased to 6-7 years currently. We highlight Ecopetrol’s initiatives to boost its reserve level on four fronts: exploration, improvement of recoverable factor, development of unconventional potential and acquisition. However, we see no single source as enough to deliver the likely volumes required.

Valuation

To arrive at our YE15 PT of US$30/ADR, we use a sum-of-the-parts NAV model, valuing the largest portion of the portfolio, the E&P assets, with a reserve depletion model based on the existing proved reserves and estimates for produced volumes adding up to 5.1bn boe. Our YE15 PT of Col$3,150/share for ECOPETL CB is derived from the conversion of our YE15 PT of US$31/ADR using J.P. Morgan’s forecast YE15 FX rate of Col$2,100. We assume a production schedule that is lower than the company’s target of 1.3mn boed by 2020. We apply our own assumptions in terms of price realizations for crude and gas, lifting costs, and development costs and discount the cash flow schedule using an 8.8% discount rate (CAPM with cost of levered equity of 10.4% and cost of debt of 6.1%, and a debt-to-capital ratio of 33%).

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The remaining portions of the portfolio, such as downstream, are also valued using a DCF model. Please find below a summary of our SOTP for EC.

Table 39: Ecopetrol NAV



Downside risksEC generates incremental EBITDA of $125mn for every $1/bbl rise in oil prices, by our estimates. Should oil prices retreat or fail to meet our 2014 assumption of $100/bbl (Brent), our price target would likely decline.

The company has an aggressive capital expenditures plan in order to meet its 1.3mnboed target by the end of 2020. While we believe the investments devoted to E&P projects are strategic and therefore unlikely to be modified, investments in segments such as refining could be front loaded as work completion moves forward.

Upside risks Faster production growth than assumed;

Potential sizable discoveries in existing licenses;

Increase in dividend payout and commitments;

Outperformance in Colombia’s macro figures;

Management potentially meeting or exceeding key performance goals.

Idemitsu Kosan (5019) (Neutral; Price Target: ¥2,100)

Investment Thesis

We believe not only is profit stable in the oiled business, but cost cutting in the coal business, previously a cause for concern, has greatly reduced the risk of big losses, so earnings are healthy overall. We think the share price appropriately reflects the situation at the company.

ECOPETROL NAV

DescriptionEV per ADR

% of total

Assets

Upstream 62,494 $30.4 85% CAPM Inputs

Refining 7,461 $3.6 10% Adjusted equity risk premium 6.0%

Transportation 3,224 $1.6 4% Long term US bond rate 2.3%

Consolidated Units 73,179 $35.6 100% LT Country Spreads 1.8%

Risk-free rate 4.0%

Working Capital YE15 + Stakes 553 $0.3

Div idend YE15 3,277 $1.6 Cost of equity

(+) Net Debt (YE15) (15,637) ($7.6) Current Capital structure (D/D+E) 25.0%

(+) ST/LT Debt (YE15) (16,822) ($8.2) D/E 33.3%

(-) Cash (YE15) 1,185 $0.6 Unlev ered beta 0.93

Balance Sheet (11,807) ($5.7) Lev ered beta 1.14

Cost of Unlev ered Equity 9.6%

NAV 61,372 $29.9 Cost of Levered Equity 10.4%

Share Count (Basic) 2,056 Cost of Debt

Current Price 52,238 $25.4 US$ debt spread 2.0%

Upside 17% Cost of Debt 6.1%

Tax Rate 33%

WACC 8.8%

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Valuation

We set our price target using an ROE-P/B matrix. We calculate our ¥2,100 price target by applying a P/B of 0.6x derived from our FY2014 forecast ROE of 4.9% and a discount of 15% taking dilution risk into account) to end-Q2 FY2014 BPS of ¥3,844. Implied FY2014E P/E is 11x. (Our price target applies through December 2015).


Movements in refining margin: We calculate that for each ¥1/liter change in the refining margin has a roughly ¥20 billion impact on operating profit. Given the substantial earnings impact, a greater increase (decline) in the margin than we forecast is a potential upside (downside) risk to our price target.

Movements in resources prices: Idemitsu Kosan is engaged in crude oil, natural gas, and coal development projects. Greater price rises (declines) for these resources than we forecast are a potential upside (downside) risk to our price target.

Industry realignment: Irrespective of whether Idemitsu Kosan is directly concerned, we think industry realignment could benefit the share price owing to expectations for the supply/demand balance to optimize, and thus see it as an upside risk to our price target.

Refinery problems/accidents: Problems/accidents resulting in prolonged productionstoppages are a downside risk to our price target because they have a considerableimpact on income.

Difficulties for Vietnam refinery construction project: The company is building a refinery in Vietnam, and we see any difficulties that may arise as a downside risk to our price target.

Capital increase: We see a capital increase as a downside risk to our price target.

Galp Energia (Underweight; Price Target: €11.50)

Investment Thesis

We rate Galp Underweight for the following reasons: 1) we believe that the weaker outlook for oil prices and refining margins will continue to increase the stress on Galp's balance sheet ; 2) the stock does not have wither the yield or earnings support – a negative when oil price is weakening ; and 3) we see limited potential for resources upgrades emanating from the company’s drilling pipeline in 2014.

Valuation

Our end June 2015 PT is €11.50. Our PT is set at a discount of c.30% to our SOTP valuation of €16.6/share (in-line with average 12-month discount suffered by the stock).


The main generic risks to our rating and price target come from crude oil or natural gas prices or refining margins significantly above our projections. For Galp specifically, upside risks include success in the deepwater Brazil exploration programme and delays associated with the Tupi project. Other upside risks could come from material improvement in downstream.

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Companies Discussed in This Report (all prices in this report as of market close on 14 November 2014, unless otherwise indicated)BG Group (BG.L/1046p/Neutral), Bharat Petroleum Corporation (BPCL) (BPCL.BO/Rs726.05[17 November 2014]/Overweight), Caltex Australia Ltd (CTX.AX/A$31.45[17 November 2014]/Overweight), Ecopetrol ADR (EC/$24.81/Neutral), Essar Oil Ltd. (ESRO.BO/Rs116.15[17 November 2014]/Neutral), Galp Energia (GALP.LS/€11.21/Neutral), Hindustan Petroleum Corporation (HPCL) (HPCL.BO/Rs549.85[17 November 2014]/Overweight), Idemitsu Kosan (5019) (5019.T/¥2018[17 November 2014]/Neutral), JX Holdings (5020) (5020.T/¥437[17 November 2014]/Neutral), Marathon Petroleum (MPC/$92.38/Overweight), Novatek (NVTKq.L/$98.13/Overweight), PETROBRAS PN (PETR4.SA/R$13.20/Neutral), PKN ORLEN (PKN.WA/zl45.45/Underweight), Phillips 66 (PSX/$71.78/Overweight), Reliance Industries Ltd (RELI.BO/Rs985.20[17 November 2014]/Neutral), Rosneft (ROSNq.L/$4.98/Underweight), Royal Dutch Shell A (RDSa.L/2202p/Overweight), Royal Dutch Shell B (RDSb.L/2295p/Overweight), S-Oil Corp (010950.KS/W42500[17 November 2014]/Underweight), Showa Shell Sekiyu (5002) (5002.T/¥961[17 November 2014]/Overweight), Sinopec Corp - H (0386.HK/HK$6.22[17 November 2014]/Neutral), Sinopec Shanghai Petrochemical (0338.HK/HK$2.43[17 November 2014]/Underweight), Statoil (STL.OL/Nkr149.40/Overweight), TonenGeneral Sekiyu (5012) (5012.T/¥980[17 November 2014]/Overweight), Tupras (TUPRS.IS/TL49.70/Overweight)

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. For all Korea-based research analysts listed on the front cover, they also certify, as per KOFIA requirements, that their analysis was made in good faith and that the views reflect their own opinion, without undue influence or intervention.

In compliance with Instruction 483 issued by Comissao de Valores Mobiliarios (the Brazilian securities commission) on July 6, 2010, the Brazilian primary analyst signing this report declares: (1) that all the views expressed herein accurately reflect his or her personal views about the securities and issuers; (2) that all recommendations issued by him or her were independently produced, including from the entity in which he or she is an employee; and (3) that he or she will set forth any situation or conflict of interest believed to impact the impartiality of the recommendations herein, as per article 17, II of Instruction 483.

Important Disclosures

Market Maker/ Liquidity Provider: J.P. Morgan Securities plc and/or an affiliate is a market maker and/or liquidity provider in Royal Dutch Shell A, Royal Dutch Shell B, Galp Energia, Novatek, Rosneft, Tupras, PKN ORLEN, BG Group, Statoil.

Lead or Co-manager: J.P. Morgan acted as lead or co-manager in a public offering of equity and/or debt securities for Ecopetrol ADR, Sinopec Corp - H, Galp Energia, PETROBRAS PN, Essar Oil Ltd., BG Group, Statoil, Marathon Petroleum within the past 12 months.

Client: J.P. Morgan currently has, or had within the past 12 months, the following company(ies) as clients: Ecopetrol ADR, Hindustan Petroleum Corporation (HPCL), Caltex Australia Ltd, JX Holdings (5020), Reliance Industries Ltd, Sinopec Corp - H, S-Oil Corp, Sinopec Shanghai Petrochemical, Idemitsu Kosan (5019), Royal Dutch Shell A, Royal Dutch Shell B, Galp Energia, Novatek, Rosneft, Tupras, PKN ORLEN, PETROBRAS PN, Showa Shell Sekiyu (5002), Bharat Petroleum Corporation (BPCL), Essar Oil Ltd., TonenGeneral Sekiyu (5012), BG Group, Statoil, Phillips 66, Marathon Petroleum.

Client/Investment Banking: J.P. Morgan currently has, or had within the past 12 months, the following company(ies) as investment banking clients: Ecopetrol ADR, JX Holdings (5020), Reliance Industries Ltd, Sinopec Corp - H, Idemitsu Kosan (5019), Royal Dutch Shell A, Royal Dutch Shell B, Galp Energia, PETROBRAS PN, Essar Oil Ltd., BG Group, Statoil, Phillips 66, Marathon Petroleum.

Client/Non-Investment Banking, Securities-Related: J.P. Morgan currently has, or had within the past 12 months, the following company(ies) as clients, and the services provided were non-investment-banking, securities-related: Ecopetrol ADR, Caltex Australia Ltd, JX Holdings (5020), Reliance Industries Ltd, Sinopec Corp - H, S-Oil Corp, Idemitsu Kosan (5019), Royal Dutch Shell A, Royal Dutch Shell B, Galp Energia, Novatek, Rosneft, Tupras, PETROBRAS PN, Showa Shell Sekiyu (5002), Bharat Petroleum Corporation (BPCL), Essar Oil Ltd., BG Group, Statoil, Phillips 66, Marathon Petroleum.

Client/Non-Securities-Related: J.P. Morgan currently has, or had within the past 12 months, the following company(ies) as clients, and the services provided were non-securities-related: JX Holdings (5020), Reliance Industries Ltd, Sinopec Corp - H, Royal Dutch Shell A, Royal Dutch Shell B, Galp Energia, Rosneft, Tupras, PETROBRAS PN, BG Group, Statoil, Phillips 66, Marathon Petroleum.

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Investment Banking (past 12 months): J.P. Morgan received in the past 12 months compensation from investment banking Ecopetrol ADR, JX Holdings (5020), Reliance Industries Ltd, Sinopec Corp - H, Idemitsu Kosan (5019), Royal Dutch Shell A, Royal Dutch Shell B, Galp Energia, PETROBRAS PN, Essar Oil Ltd., BG Group, Statoil, Phillips 66, Marathon Petroleum.

Investment Banking (next 3 months): J.P. Morgan expects to receive, or intends to seek, compensation for investment banking services in the next three months from Ecopetrol ADR, JX Holdings (5020), Reliance Industries Ltd, Sinopec Corp - H, Idemitsu Kosan (5019), Royal Dutch Shell A, Royal Dutch Shell B, Galp Energia, Tupras, PETROBRAS PN, Essar Oil Ltd., BG Group, Statoil, Phillips 66, Marathon Petroleum.

Non-Investment Banking Compensation: J.P. Morgan has received compensation in the past 12 months for products or services other than investment banking from Ecopetrol ADR, Caltex Australia Ltd, JX Holdings (5020), Reliance Industries Ltd, Sinopec Corp -H, S-Oil Corp, Idemitsu Kosan (5019), Royal Dutch Shell A, Royal Dutch Shell B, Galp Energia, Novatek, Rosneft, Tupras, PETROBRAS PN, Showa Shell Sekiyu (5002), Bharat Petroleum Corporation (BPCL), Essar Oil Ltd., BG Group, Statoil, Phillips 66,Marathon Petroleum.

Broker: J.P. Morgan Securities plc acts as Corporate Broker to BG Group.

Company-Specific Disclosures: Important disclosures, including price charts, are available for compendium reports and all J.P. Morgan–covered companies by visiting https://jpmm.com/research/disclosures, calling 1-800-477-0406, or e-mailing [email protected] with your request. J.P. Morgan’s Strategy, Technical, and Quantitative Research teams may screen companies not covered by J.P. Morgan. For important disclosures for these companies, please call 1-800-477-0406 or e-mail [email protected].

Explanation of Equity Research Ratings, Designations 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.] Not Rated (NR): J.P. Morgan has removed the rating and, if applicable, the price target, for this stock because of either a lack of a sufficient fundamental basis or for legal, regulatory or policy reasons. The previous rating and, if applicable, the price target, no longer should be relied upon. An NR designation is not a recommendation or a rating. In our Asia (ex-Australia) and U.K. small- and mid-cap equity research, each stock’s expected total return is compared to the expected total return of a benchmark country market index, not to those analysts’ coverage universe. If it does not appear in the Important Disclosures section of this report, the certifying analyst’s coverage universe can be found on J.P. Morgan’s research website, www.jpmorganmarkets.com.

Coverage Universe: Lee, Samuel See Wai: Formosa Chemicals and Fibre Corp (1326.TW), Formosa Petrochemical Corp (6505.TW), Formosa Plastics Corp (1301.TW), Hanwha Chemical Corp (009830.KS), Indorama Ventures (IVL.BK), LG Chem Ltd (051910.KS),Lotte Chemical Corp (011170.KS), Nan Ya Plastics Corp (1303.TW), PTT Global Chemical Pcl (PTTGC.BK), Petronas Chemicals Group Berhad (PCGB.KL), Reliance Industries Ltd (RELI.BO), S-Oil Corp (010950.KS), SK Innovation Co Ltd (096770.KS), Siam Cement (SCC.BK), Thai Oil Public Company (TOP.BK)

Darling, Scott L: Anton Oilfield Services Group (3337.HK), CNOOC (0883.HK), Cairn India Limited (CAIL.BO), China BlueChemical Ltd (3983.HK), China Oilfield Services Limited (2883.HK), Hilong Holdings Ltd. (1623.HK), Honghua Group (0196.HK), Inpex Corporation (1605) (1605.T), Oil and Natural Gas Corporation (ONGC.BO), PTT Exploration & Production (PTTE.BK), PTT Public Company (PTT.BK), PetroChina (0857.HK), SPT Energy Group Inc. (1251.HK), Sinopec Corp - H (0386.HK), Sinopec Shanghai Petrochemical (0338.HK)

Nishiyama, Yuji: Asahi Kasei (3407) (3407.T), Chubu Electric Power (9502) (9502.T), Chugoku Electric Power (9504) (9504.T), Cosmo Oil (5007) (5007.T), Hokkaido Electric Power (9509) (9509.T), Hokuriku Electric Power (9505) (9505.T), Idemitsu Kosan (5019) (5019.T), J-POWER (9513) (9513.T), JX Holdings (5020) (5020.T), Kansai Electric Power (9503) (9503.T), Kyushu Electric Power (9508) (9508.T), Mitsubishi Chemical Holdings (4188) (4188.T), Mitsui Chemicals (4183) (4183.T), Osaka Gas (9532) (9532.T), Shikoku Electric Power (9507) (9507.T), Shin-Etsu Chemical (4063) (4063.T), Showa Shell Sekiyu (5002) (5002.T), Sumitomo Chemical (4005) (4005.T), Tohoku Electric Power (9506) (9506.T), Tokyo Gas (9531) (9531.T), TonenGeneral Sekiyu (5012) (5012.T), Toray Industries (3402) (3402.T)

Gupte, Neil: Bharat Petroleum Corporation (BPCL) (BPCL.BO), Essar Oil Ltd. (ESRO.BO), Gas Authority of India Limited (GAIL.BO), Hindustan Petroleum Corporation (HPCL) (HPCL.BO), Indian Oil Corporation (IOC.BO), Petronet LNG Ltd. (PLNG.BO)

Cousins, Shaun: Billabong International (BBG.AX), Caltex Australia Ltd (CTX.AX), Fantastic Holdings (FAN.AX), Harvey Norman (HVN.AX), JB Hi-Fi Limited (JBH.AX), Metcash Ltd (MTS.AX), Myer Holdings Limited (MYR.AX), Pacific Brands (PBG.AX), Super Retail Group Ltd (SUL.AX), Wesfarmers Limited (WES.AX), Woolworths Limited (WOW.AX)

mailto:[email protected]


https://jpmm.com/research/disclosures

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Lucas, Frederick G: BG Group (BG.L), BP (BP.L), Gulf Marine Services (GMS.L), Royal Dutch Shell A (RDSa.L), Royal Dutch Shell B (RDSb.L)

Gresh, Phil M: Cenovus Energy (CVE.TO), Chevron Corp (CVX), Exxon Mobil Corp (XOM), HollyFrontier (HFC), Marathon Petroleum (MPC), Phillips 66 (PSX), Tesoro Corporation (TSO), Valero Energy (VLO)

Dos Santos, Felipe: Alpek (ALPEKA.MX), Braskem (BRKM5.SA), Braskem ADR (BAK), Ecopetrol ADR (EC), Ecopetrol S.A. (ECO.CN), GeoPark (GPRK), Gran Tierra Energy (GTE), HRT (HRTP3.SA), Mexichem (MEXCHEM.MX), PETROBRAS ON (PETR3.SA), PETROBRAS ON ADR (PBR), PETROBRAS PN (PETR4.SA), PETROBRAS PN ADR (PBRa), Pacific Rubiales (PRE.TO), QGEP (QGEP3.SA), Tenaris SA (TS), Ultrapar ADR (UGP), Ultrapar S.A. (UGPA3.SA), YPF (YPF)

J.P. Morgan Equity Research Ratings Distribution, as of September 30, 2014

Overweight(buy)

Neutral(hold)

Underweight(sell)

J.P. Morgan Global Equity Research Coverage 46% 42% 12%IB clients* 57% 49% 34%

JPMS Equity Research Coverage 46% 48% 7%IB clients* 76% 67% 51%

*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. Please note that stocks with an NR designation are not included in the table above.

Equity Valuation and Risks: For valuation methodology and risks associated with covered companies or price targets for covered companies, please see the most recent company-specific research report at http://www.jpmorganmarkets.com, contact the primary analyst or your J.P. Morgan representative, or email [email protected].

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.

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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 October 18, 2014.

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