barclays global energy outlook (2)

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This research report has been prepared in whole or in part by research analysts based outside the US who are not registered/qualified asequity research analysts with FINRA.

FOR ANALYST CERTIFICATION(S), PLEASE SEE PAGE 149.

FOR IMPORTANT FIXED INCOME RESEARCH DISCLOSURES, PLEASE SEE PAGE 149.

FOR IMPORTANT EQUITY RESEARCH DISCLOSURES, PLEASE SEE PAGE 151.

RESEARCH COMMODITIES, CREDIT AND EQUITY VIEWS1 March 2012

GLOBAL ENERGY OUTLOOK

OIL UPSIDE, RISING CAPEX

Barclays Capital | Global Energy Outlook

1 March 2012 1

OVERVIEW

Tight oil and LNG, upstream bias, rising capex Exposure to oil and LNG markets, and a bias to upstream growth and rising capex are the main global energy investment themes we see across commodities, credit and equities.

Oil has very little spare production capacity globally – well below 2% – and demand, even in a weak global economy, still outstrips supply, based on our analysis. We also believe Asian oil demand is growing at a faster pace than markets are currently pricing in. Our Brent price forecast for 2012 is $115/bl, rising to $135/bl in 2015, with the balance of risk to the upside.

Global LNG trade expanded significantly in 2011, led by strong Asian demand in the aftermath of the Tohoku earthquake. Liquefaction capacity additions will slow sharply in 2012-13, with regasification capacity outpacing supply additions by a factor of 4:1. This will provide a significant number of new potential destinations for cargoes and we expect LNG prices to remain strong.

In equities, the upstream has consistently been the highest return segment and we expect it to remain so. We recommend integrated companies with an upstream and growth bias, and US, Canadian and European E&Ps that are leveraged to oil prices, growth and exploration.

Strongly rising capex is a consequence of tight oil markets and higher prices. We see multi-year industry capex growth of >10%, with mid-teens growth in 2012. We recommend oil service equities, and highlight oil service opportunities in credit where cash flows are robust.

Also in credit, we no longer see the value discount of high yield to high grade that we highlighted in our last Global Energy Outlook six months ago. Subsequent performance has closed this gap. We are now overweight the US HG sectors, notably pipelines and oil field services, as well as oil refiners and electric utilities. In Europe, we are Overweight HG integrated energy and in Asia we are Underweight HY coal.

The energy markets where we are less positive are US natural gas, coal, power utilities and carbon. We do not yet see an upturn in US natural gas prices, and advise investors to stay short. US thermal coal prices have been dragged down by gas displacement, and we forecast an extended period of oversupply. In China, coal infrastructure investment has eased domestic supply constraints, and we also expect improved output from South Africa and Australia, all of which suggest more supply in the Atlantic and Pacific seabourne coal markets. Power and power utilities in all regions will continue to experience what we believe will be weak markets, dampening our enthusiasm in commodities and equities, although in the US the defensive high yield credits are attractive. We prefer more defensive regulated utilities in the US and Europe to power price leveraged names.

In the volatile sectors of oil products/refining and renewable energy, we expect ongoing price swings and we would trade selectively. We still like US refining equities, but see structural challenges globally as a wall of refining capacity comes onstream over the next few years. In renewables, we expect significant new solar and wind capacity, and the economics are challenging. We prefer opportunities in electric cars and battery recycling.

Overall, we continue to believe there is value in comparing investments across the energy spectrum, and in the following pages we set out the views and investment ideas of all of our analysts in commodities, credit and equities. A complete list of our energy research analysts is provided on page 160. Our library of published energy research, plus additional analytical tools, is available on our award winning Barclays Capital Live website, at live.barcap.com.

Tim Whittaker +44 (0)20 3134 6696

[email protected] Barclays Capital, London

New LNG markets, robust prices

Prefer equities with oil bias, growth and exploration upside

Strongly rising capex supports oil services

US HY energy credit no longer at a discount, prefer HY

Negative on US natural gas, coal, power and carbon

Renewables economic challenges

https://live.barcap.com/�


1 March 2012 2

Commodities: Oil and LNG well supported We continue to see a tight oil market in 2012 and beyond. We maintain our Brent price forecast of $115/bl for 2012, which we have held since last July. However, should the scenario of a rapid deterioration in Iran’s external relations transpire, we would expect the annual average to be as much as $20 higher. In the longer term, we see limited scope for supply to grow faster than demand; hence, we also maintain our price forecast of $135/bl for 2015.

Non-OPEC supply growth in 2012 is again likely to disappoint: we estimate 0.3m bls/d versus consensus agency forecasts of +0.7-1.0m bls/d. For OPEC, the challenge is maintaining sufficient spare capacity, which we estimate is close to 1.6 mb/d, well below 2% of the total. For demand, we believe Asia is growing faster than markets are currently pricing in.

In oil products, OECD refinery closures have gained momentum, but any support to margins is likely to be short-lived given the plethora of capacity additions in the non-OECD. We see net refinery additions (ie, after announced closures) of around 2m bls/d globally for each of the next three years. Despite a warm winter depressing heating oil demand, underlying distillate demand remains strong and should be supported through 2012 as economic activity improves. Fuel oil demand has found a new life due to Japanese nuclear plant closures, at the same time as refinery upgrades have restricted supplies.

Global LNG trade expanded significantly in 2011, led by strong Asian demand in the aftermath of the Tohoku earthquake. Liquefaction capacity additions will slow sharply in 2012-13. Regasification capacity should outpace supply additions by a factor of 4:1 over the coming two years, providing a significant number of new potential destinations for cargoes. Europe will likely be most affected by tightening global LNG balances, losing at least 3 bcm/y (0.3 bcf/d) of LNG imports in 2012. While this does not mean a supply shortfall in aggregate, it suggests that European natural gas prices will be higher.

Oversupply in the US natural gas market has seen prompt prices trading around $2.50/MMbtu since early January. We expect production growth to decelerate, or perhaps reverse, as the impact of $2-3 gas prices takes hold. Falling gas-supply costs and the attractiveness of drilling NGL-rich wells should prevent a dramatic fall-off in drilling activity. We expect coal displacement to start to support the natural gas market, and forecast a 2012 annual average price of $3.05/MMBtu. We advise investors to stay short but to watch for rallies and possible entry points. We would also advise producers of gas and power to hedge.

In Europe, we expect gas demand to increase significantly, by 6.6 bcm y/y in Continental Europe and by 1.1 bcm y/y in the UK. With the Nordstream pipeline from Russia to Germany and the Medgaz line from North Africa to Italy now onstream, the expansion of pipeline gas supply into Europe is increasingly likely to allow LNG to be diverted to the tighter Asian markets instead of being used in Europe. However, we do not view a supply-shortage risk as imminent, given the other supply options available to Europe. We forecast that NBP prices will average 59.5 p/therm in 2012, up 5.5% y/y. We have also introduced our 2013 price forecast of 67.5p/therm, up 13% y/y.

Global coal markets enter 2012 in a remarkably different place from where they started 2011, with a warm Q4 2011 across the Northern Hemisphere depressing demand and leaving port and utility stocks high. In China, rationalisation and consolidation of coal mines as well as the completion of new rail routes result in a big easing of the domestic coal supply constraints that have turned China into a net importer in recent years. At the same

Prefer oil and LNG, to oil products, US natural gas, coal

and carbon

Wall of new refining capacity

Higher distillate and fuel oil demand

New regas capacity opens new markets

Coal displacement floor to US natgas

More EU pipeline gas, less LNG

Less coal supply constraints

Softer Atlantic and Pacific basin markets


1 March 2012 3

time, infrastructure bottlenecks in South Africa are also easing and, if Australia’s coal shippers avoid a repeat of last year’s La Nina driven weather disruptions, their performance should improve considerably. In the Atlantic basin, we forecast a continued softening of European delivered coal prices with both API2 and API4 prices averaging $102/t in 2012, 17% lower than last year. In the Pacific basin, we expect Newcastle prices to average $112/t in 2012, down 7% y/y on better supply performance, but maintaining value better than European prices as a result of the more buoyant demand picture in Asia. In the US, we expect thermal coal prices to suffer through an extended period of oversupply, lasting at least through 2014, brought about by lower natural gas prices, weak electricity demand, and limited incentive to cut contracted production in the near term. Met coal should be better, tempered by a weak outlook globally.

In US power, an exceptionally mild 2011-12 winter has taken its toll on energy demand, pushing US natural gas and power prices lower. Also, lower natural gas prices are displacing coal in almost every US market, dramatically compressing power plant margins for coal, nuclear and other non-gas assets, while handing increasing chunks of market share to gas-fueled units. The Barclays Capital outlook for 4.1% growth in 2012 US industrial production should help boost power demand modestly, but growth in the residential and commercial sectors remains sluggish.

In carbon, the European market is looking oversupplied amid macroeconomic concerns, and in our view downside risk persists for EU emission allowances (EUAs) and certified emission reduction offsets (CERs) – even from the low prices of January 2012. The only potential upside from current levels is likely to come from attempts by the market regulator, the EC, to reduce supply from 2013. Without such intervention, we believe the EU ETS market will likely see a number of years of only modest price improvement. Our 2012 forecast is for little, if any, price movement from current levels, although our H2 12 forecasts do factor in some upside from expected progress on the set-aside concept.

Credit: Better value in High Grade In credit, we no longer see the value discount of high yield to high grade that we highlighted in our last Global Energy Outlook six months ago. Subsequent performance has closed this gap (see chart on page 8). We are now Overweight the HG sectors, notably in pipelines, refiners, oil field services and electrics. In Europe, we are also Overweight HG integrated energy and in Asia we are Underweight HY coal.

In US high grade, we see better value in the pipelines sector than in energy and have recently upgraded the pipelines sector to Overweight from Underweight. The HG E&P sector has been buffeted by concerns around US natural gas, and we see selective opportunities. Oil field service credits continue to trade cheap to their 3y average differential versus US Credit. Our top picks in the pipelines sector are Enterprise Products Partners and Energy Transfer Partners, In E&P, we are Overweight Anadarko Petroleum Corporation and Nexen. In oil services, we remain Overweight Nabors, which we expect to reduce debt in 2012.

High Yield Energy is trading ~600bp over Treasuries, about 85bp cheap to its 10-year average. Weak natural gas prices have led to a sell-off in E&P credits levered to gas, and benchmark bonds are down 5-7% year-to-date. We would buy MEG 21s and sell CXO 21s to pick up 125bp in yield. Both companies are B3 rated and have good exposure to oil prices, though the recent divergence in spreads leaves a better opportunity in MEG, in our view. We see similar pair trades for yield pickup in NGLS/RGP and PGS/CGV (see page 69).

Sluggish US and EU power demand growth

Limited upside for carbon over next few years

US high yield no longer at a big discount to high grade

HG better value in pipelines than energy

US HY 85bp cheap


1 March 2012 4

In HY Coal, we are cautious on thermal coal names given weak fundamentals. Arch Coal (ACI) 7.25% senior notes of ’20 have widened 80-90bp relative to Consol Energy (CNX) 6.375s and Alpha Natural (ANR) 6.25s since mid-January. We are comfortable that ACI can remain free cash flow positive under some very bearish assumptions and believe investors should consider swapping out of CNX/ANR into ACI 7.25s to pick up the additional yield at current levels.

In HG Utilities, our Overweight recommendation on this defensive sector reflects its strength during periods of market volatility. At current spreads, we favour BBB and crossover regulated utilities, and utility holding companies with predominantly regulated business models. Given continued weak pricing conditions, we remain cautious on generation subsidiaries and diversified holding companies with larger unregulated generation businesses. Buy Duquesne Light Holdings 5.90% bonds due 2021, quoted at +290, and buy Metropolitan Edison (FE) 7.70% bonds due 2019, quoted at +135.

In Europe, our positive outlook for the HG Oil & Gas sector is supported by our expectations that WTI and Brent prices will improve through 2012 and into 2013. We highlight that E&P dominates cash generation and fosters cash flow stability and growth. We recommend switching out of BG Group and into BP (in euro). Evidence of production growth translating into operating cash flow and improved discretionary cash flows is required before we become more confident on BG Group building rating headroom. We recommend buying Repsol 5y CDS, owing to limited downside, spread volatility in Europe and ongoing tail risk on YPF in Argentina.

European HG Utility credits managed to marginally beat the Pan-European Credit Index in 2011. Despite the market rally that has accompanied the start of this year, we remain cautious on the periphery in the near term. We recommend switching out of Iberdrola and Enel into Gas Natural Fenosa across the EUR cash curve. We believe Iberdrola and Enel, through Endesa, are exposed to near-term risk regarding the tariff deficit and special taxation in Spain. In the UK, we would buy United Utilities plc 5y CDS, as it is too tight for BBB-/Baa1 credit. The most liquid CDS contract references holding company United Utilities plc and is therefore at risk of adverse movements on a leveraged takeover of United Utilities Group.

In Asian High Yield, despite our constructive outlook on Indonesian coal, we believe bond valuations look fair to rich given the rally YTD, high cash prices and potential supply risk. As such, we revise our sector weighting to Underweight from Overweight. We would sell Adaro ‘19s (UW). The bonds offer one of the lowest yields among Asian HY bonds. While we view the company’s credit profile as relatively stable in the near term, we see higher downside risk on the bonds given tight valuations and the company’s growth ambitions. We would also switch from Indika ‘18s (UW) to Indika ‘16s (MW). The yield curve on the bonds is inverted. We expect this to normalise over time. Further, the two bonds are pari passu to one another and share the same key covenants.

In Asian HG energy, we remain constructive on the Oil and Gas sector and in particular upstream producers on the back of elevated oil prices. We expect earnings to improve in 2012 largely due to higher realised oil prices and increased production. We recommend Reliance Industries and see CNOOC as a core position

We remain cautious on Asian HG Utilities as we expect input costs to remain high for the power and gas utilities in 2012, albeit continuing strong governmental support due to low reserve margins. We expect inflation concerns and slowing growth to weigh on earnings; the ability to pass on rising cost remains a concern in Malaysia, and to a lesser extent, in Korea. We are Overweight Korea Hydro & Nuclear Power Co.

Cautious on HY thermal coal names

Prefer defensive US HG utilities

Positive on European HG Oil & Gas;

Switch out of BG into BP

Cautious on EU periphery country credits

Rich valuations in Asian HY

Asian HG better value, recommend CNOOC


1 March 2012 5

Equities: Prefer E&P biased stocks and oil services In oil equities, among the integrateds, our preference is for the upstream biased names. We recommend Suncor, Hess, Imperial, BG, Statoil, Galp, Sasol and CNOOC. We expect this group to outperform the less oil price levered and lower growth model of the Majors. In E&P, we recommend oil-biased names with exploration upside, including EOG and Noble in the US; Crescent Point, Baytex and PetroBakken in Canada; and Afren, and Tullow Oil in Europe, where recent M&A is also a share price driver. In the downstream, we saw an opportunity in the US refiners six months ago, and after strong performance we see further upside from the Jan-May seasonal trade. We recommend Tesoro, Valero and Marathon Petroleum. Globally, we continue to have a negative view on the refining sector as we see net capacity additions of 2m bls/d coming onstream in each of the next three years.

In oil services, capex on energy investments is increasing at around 10% pa. The oil services companies are likely to capture a significant part of this uptrend. Most recently announced spending programmes have been higher than our previous estimates, so 2012 is likely to be a year of mid-teens capex growth. In our view, the most attractive US stocks are the large-cap diversified companies (BHI, HAL, SLB, WFT), the capital equipment names (CAM, NOV), several of the offshore drillers (RIG, RDC, NE, ESV), and select small/mid caps such as HOS, GLF, SPN, DRC, GGS and IO. For the European companies, pricing for seismic in summer 2012 is likely to be up 10-25%, offshore construction backlogs are at all-time highs and companies are taking record levels of enquiries. Our preferred seismic play remains PGS. Our European oil services bellweather is Saipem (1-OW) with its broad portfolio of activities across drilling, onshore and offshore construction.

In coal, we expect US thermal coal prices to experience an extended period of oversupply, brought about by lower natural gas prices, weak electricity demand, and limited incentive to cut contracted production. While the seaborne market looks stronger at the margin, with India coming back as a buyer, the domestic supply/demand balance in the two largest global markets – China and the US – does not look too promising for the first half. China Coal Energy is our recommended coal equity.

In power utilities, we are cautious on the US and European sectors, as weak natural gas prices in the former and rising oil prices in the latter pressure margins. US power stocks are 7-13% overvalued based on our analysis, with natural gas prices being the biggest risk. We prefer NextEra Energy as it provides power exposure with long-term contracts insulating the company from short-term swings in price. In Europe, we do not see compelling valuations given the challenging growth outlook. We prefer companies with defensive characteristics and secular growth potential, including International Power and National Grid.

In renewable energy, we forecast ongoing demand growth and expect annual installations for wind and solar to see CAGRs of 8.5% and 11.1%, respectively, from 2010-15. Renewable economics have improved in recent months, with grid parity in some markets as solar costs have fallen 50% in a year driven by overcapacity. In the US, we see near-term expiration of the production tax credit ("PTC") creating some challenges for wind, and the PTC is only likely to be extended next spring before an upturn in demand. Over time we expect an increasing switch from centralised power generation to a hybrid approach, supported by the ability of rooftop solar to provide a meaningful proportion of a household’s power generation requirements. We also expect further industry consolidation driven by capital needs and scale. We highlight investments in growing technologies such as electric cars, where we recommend Tesla, and battery recycling, where we recommend Umicore.

Prefer upstream biased integrateds, oil and exploration

levered E&Ps

Further upside in US refiners, but not in Europe

Wall of spending to drive oil services

China Coal a top pick

Cautious on US and EU power utilities

Prefer regulated names

Stong renewables demand growth, but economic challenges

Buy Tesla (electric cars) and Umicore (battery recycling)


1 March 2012 6

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1 March 2012 7

CONTENTS

Overview – Tight oil and LNG, upstream bias, rising capex 1 Price Performance 8 Summary of Energy Themes 10

COMMODITIES

Commodities Oil – Less downside, more upside 18 Geopolitics – Crossing the Rubicon 30 Oil Products – Refinery closures: Too little too late? 33 LNG – In a tighter spot 44 US Natural Gas – Finding a new coal floor 48 European Natural Gas – Complex equations 52 Coal – Year of the dragon? 56 US Power – Cheap gas and mild weather pummel power 60 Carbon – Nothing to shout about 63

CREDIT

US High Grade Energy & Pipelines – We favor pipelines over energy 68 US High Yield Energy – Weak natural gas weighing on spreads 69 US High Yield Coal – Challenging fundamentals look set to persist 70 US High Grade Electric Utilities – Regulated utilities remain stable 72 European High Grade Oil & Gas – Oil price bias and disposals support sector ratings 73 European High Grade Utilities – Modest expectations 75 Asia High Yield Coal – Getting too hot 77 Asia High Grade Energy – Constructive outlook for upstream producers; event risk manageable 78 Asia High Grade Utilities – Stable outlook, fuel cost remains key credit driver 79

EQUITIES

Americas Integrated Oil – Our favorites include SU, HES, and IMO; Supermajors will likely underperform 82 European Integrated Oil – Upstream bias 85 European Integrated Oil – Sasol: Strong results & growth 88 Asia ex-Japan Oil & Gas – Value in upstream growth, pricing reform may take time 90 US Exploration & Production – Continue to favor oil producers 93 Canadian Exploration & Production – Income and growth: the best of both worlds 96 Europe Exploration & Production – Good, but not over yet 99 US Independent Refiners – Strong support for the seasonal trade; Could see cyclical upturn pending capacity shutdowns 100 European Refining & Marketing – Too little, too late 104 US Oil Services & Drilling – The next Mega-Cycle takes hold 107 Europe Oil Services & Drilling – Signs of a pick-up 109 US Coal – Challenging thermal coal outlook, prefer metallurgical exposure 112 Asia ex-Japan Coal – High inventories and supply growth limits positives of demand growth 115 US Power – Rising expectations 120 European Utilities – Under shadow 122 US Clean Technology and Renewables – Improving data points, though ultimately end market trajectory remains the key question 126 European Clean Technology & Sustainability – Green growth in an uncertain world 130 Equity Valuation Table 133

CONTACTS 160


1 March 2012 8

PRICE PERFORMANCE

Since our previous Global Energy Outlook in August 2011, oil prices and equities have been the big winners. We continue to expect strong oil prices and still recommend oil leveraged equities. The best performers in equities include the US refiners, the oil service companies and the E&P names. Although there is less average upside to our share price targets than six months ago, we still see double digit performance potential from these sectors. In credit, high yield has outperformed high grade, with the HY Credit Index up 4.8% over an unmoved HG credit index. We now prefer opportunities in HG.

Price change, 9 August 2011 - 24 February 2012

-40 -30 -20 -10 0 10 20 30 40

US Independent RefinersLatam Oil & Gas

EU E&PsUS Oil ServicesEU IntegratedsLatam UtilitiesUS Integrateds EU Oil Services

US offshore & onshore drillingRussian Oil Services

S&P 500Russian IntegratedsUS E&Ps large caps

US PowerUS E&Ps

EU UtilitiesEurostoxx 600

US E&Ps small and mid capsEU Independent Refiners

US CoalEU RenewablesUS Renewables

US HY Credit IndexUS HY Energy US HY Electric

EU HY Credit IndexEU HY Energy

EU HG Utilities US HG Integrated

EU HG EnergyUS HG Energy

US HG Credit IndexEU HG Credit Index

US HG Independent E&P US HG Electric

Asian Credit IndexUS HG Oil Field Services

US HG Pipelines US HG Refining

WTI CrudeBrent Crude

GSCI, CommodityUK power

UK Natural GasUS Coal AP14

German powerUS Coal AP12

CarbonUS Power

US Natural Gas

Equi

tyC

redi

tC

omm

odit

y

The data on the chart show the price performance of each of the named commodities/indices in US dollars for August 9, 2011 to February 24, 2012. Source: Datastream, Bloomberg, Barclays Capital


1 March 2012 9

Looking back to the start of 2011, the wide divergence in commodity and equity performance compared with the lack thereof in credit is stark. Crude oil is the stand-out commodity and, perhaps surprisingly, US refiners have been the best performing equity category. Low US natural gas prices and weak power, carbon, solar and wind markets have had clear consequences for performance across commodities and equities.

Price change, 3 January 2011 - 24 February 2012

-80 -60 -40 -20 0 20 40 60

US Independent RefinersUS Oil ServicesLatam Utilities

Russian IntegratedsUS offshore & onshore drilling

EU Integrateds US Integrateds

S&P 500US Power

EU UtilitiesUS E&Ps large caps

EU E&PsLatam Oil & Gas

EU Oil ServicesUS E&Ps

Eurostoxx 600US E&Ps small and mid caps

EU Independent RefinersRussian Oil Services

US CoalEU RenewablesUS Renewables

EU HG Utilities EU HY Energy

US HY Energy US HY Credit IndexUS HG Integrated

EU HG EnergyUS HG Energy US HG Electric

US HG Oil Field Services US HG Refining

EU HY Credit IndexUS HG Pipelines

US HG Independent E&PUS HG Credit IndexEU HG Credit Index

US HY ElectricAsian Credit Index

Brent CrudeWTI Crude

GSCI, CommodityUK Natural Gas

UK powerGerman power

US Coal AP14US Coal AP12

US PowerCarbon

US Natural Gas

Equi

tyC

redi

tC

omm

odit

y

The data on the chart show the price performance of each of the named commodities/indices in US dollars for January 3, 2011 to February 24, 2012. Source: Datastream, Bloomberg, Barclays Capital


1 March 2012 10

SUMMARY OF ENERGY THEMES

INVESTMENT VIEW KEY RECOMMENDATIONS

Commodities

Oil We continue to see a tight oil market in 2012, with non-OPEC supply likely to again disappoint relative to demand, We estimate 0.3m bls/d in 2012 vs consensus agency forecasts of +0.7-1.0m bls/d. For OPEC, the challenge is maintaining sufficient spare capacity despite growing adversities on the geopolitical front. We estimate current global spare capacity at close to 1.6 mb/d – well below 2% of demand – as OPEC volumes remain at three-year highs. On demand, we believe Asia is growing at a faster pace than markets are currently pricing. At the same time, geopolitical tensions, largely related to Iran, have intensified since the start of the year. Inventories remain below seasonal averages, despite the recent build. While not only supportive for near term prices, the lack of steady capacity additions within OPEC makes back-end prices look attractive.

We maintain our Brent price forecast of $115/bbl for 2012, which we have held since last July. However, should the scenario of a rapid deterioration in Iran’s external relations, with no resolution in 2012, continue to force itself into the base case, we would expect the annual average to be as much as $20 higher. With extremely limited buffers to absorb any of the potential geopolitical mishaps, the backdrop to the oil market is challenging. Thus, maintaining a deep short position would be unwise, in our opinion. In the longer term, we see limited scope for supply to grow faster than demand; hence, we also maintain our price forecast of $135/bbl for 2015.

Geopolitics There are new fears about the security of the Straits of Hormuz, as Iran and the West appear to be engaged in a dangerous game of brinkmanship. We still contend that the risk of either an Israeli or a US strike on the Iranian nuclear facilities is low, but it has risen, in our view, from 5-10% last year to 25-30% now. Violence has escalated in Iraq in the wake of the US troop departure and could imperil oil production if it continues or escalates. Prime Minister Maliki’s efforts to sideline his political rivals are adding to the anxiety about the country’s near-term trajectory. Nigeria is also experiencing a new wave of unrest that is deepening the country’s regional and religious divide and prompting comparisons to the run-up to the devastating 1967-70 Civil War.

Oil Products OECD refinery closures have gained momentum, but any support to margins is likely to be short-lived, given the plethora of capacity additions in the non-OECD. We see net refinery additions (ie after announced closures) of about 2m bls/d globally for each of the next three years.

Despite a warm winter depressing heating oil demand, underlying distillate demand remains strong and should be supported through 2012 as economic activity improves. Gasoline has been the Achilles heel of oil demand, but almost 2 mb/d of gasoline oriented refinery closures is set to constrict supplies and support prices in 2012. Fuel oil demand has found a new life due to Japanese nuclear plant closures, at the same time refinery upgrades have limited supplies.

LNG Global LNG trade expanded significantly in 2011, led by strong Asian demand in the aftermath of the Tohoku earthquake pushing global LNG supply and demand into balance. Liquefaction capacity additions should slow sharply in 2012-13, as less plants are due onstream. Global additions to LNG regasification capacity should outpace supply additions by a factor of 4:1 over the coming two years, providing a significant number of new potential destinations for cargoes.

Europe will likely be most affected by tightening global LNG balances, losing at least 3 bcm/y (0.3 bcf/d) of LNG imports in 2012. While this does not mean a supply shortfall in aggregate, it suggests that European natural gas prices will be higher.


1 March 2012 11


Commodities

Natural Gas - US Oversupply in the US natural gas market has seen prompt prices trading around $2.50/MMbtu since early January. We expect production growth to decelerate, or perhaps reverse, as the effect of $2-3 gas prices takes hold. Falling gas-supply costs and the attractiveness of drilling NGL-rich wells, however, should prevent a dramatic fall-off in drilling activity. We also expect coal displacement to rise slowly through the year to at least an annual average of 6 Bcf/d.

We expect coal displacement to start to support the natural gas market, and forecast a 2012 annual average price of $3.05/MMBtu. As production growth slows in 2013, we expect natural gas prices to rise to an average $3.25/MMBtu. We advise investors to stay short but watch for rallies and possible entry points. We also think producers of gas and power should hedge. In higher cost areas, activity is moderating and this should allow gas markets to re-establish a long-term equilibrium price of $3.25-4.00 by mid- to late 2013.

Natural Gas - Europe

We expect 2012 European and UK gas demand to increase 6.6 bcm y/y in Continental Europe and 1.1 bcm y/y in the UK through higher residential demand, assuming a less mild winter, weak industrial demand, and power demand that should be little changed from 2011. With the Nordstream pipeline from Russia to Germany and the Medgaz line from North Africa to Italy now onstream, the expansion of pipeline gas supply into Europe is increasingly likely to allow LNG to be diverted to the tighter Asian markets instead of being used in Europe. However, we do not view a supply-shortage risk as imminent, given the other many supply options available to Europe.

We expect the UK gas market to tighten increasingly through the next two years, with modest demand growth from the weak economy offset by limited supply growth given UKCS supply, price sensitivity from Norwegian imports and limited growth in LNG imports. Weather is the swing factor. We forecast that NBP prices will average 59.5 p/therm in 2012, up 5.5% y/y. We have also introduced our 2013 price forecast of 67.5p/ therm, up 13% y/y.

Coal In China, rationalisation and consolidation of coal mines, as well as the completion of new rail routes with the capacity to shift about 90Mt, is likely to result in a big easing of the domestic coal supply constraints that have turned China into a net importer in recent years. At the same time, infrastructure bottlenecks in South Africa are easing and if Australia’s coal shippers avoid a repeat of last year’s La Nina-driven weather disruptions, their performance should improve considerably. While weather offset sluggish underlying power demand through summer 2011, helping to support power prices, a chronically soft 2011-12 winter has taken its toll on energy demand, pushing US natural gas and power prices lower. Lower natural gas prices are displacing coal in almost every US market, dramatically compressing power plant margins for coal, nuclear and other non-gas assets, while handing increasing chunks of market share to gas-fueled units.

In the Atlantic basin, we expect demand growth to follow a flat profile across major North West European countries, producing growth of 2% (4 mt) y/y in 2012, mostly from the Latin American region. In 2013, we expect Atlantic Basin coal demand to fall 2.2%. In the US, we expect thermal coal prices to suffer through an extended period of oversupply, lasting at least through 2014, brought about by lower natural gas prices, weak electricity demand, and limited incentive to cut contracted production in the near term. Met coal should be better, tempered by a weak outlook globally. The Barclays Capital outlook for 4.1% growth in 2012 US industrial production should help boost power demand modestly, but growth in the residential and commercial sectors remains sluggish. Coal prices are drifting close to marginal cost, suggesting there is little downside relief to buyers. With the risk of plant shutdowns to meet new pollution controls and the effect of the ongoing drought, the Texas power market faces a challenging 2012, with heightened risks of further power price spikes.

Power - US While weather offset sluggish underlying power demand through summer 2011, helping to support power prices, a chronically soft 2011-12 winter has taken its toll on energy demand, pushing US natural gas and power prices lower. Lower natural gas prices are displacing coal in almost every US market, dramatically compressing power plant margins for coal, nuclear and other non-gas assets, while handing increasing chunks of market share to gas-fueled units.

What Barclays Capital expects to be 4.1% growth in 2012 US industrial production should help boost power demand modestly, but growth in the residential and commercial sectors remains sluggish. Coal prices are drifting close to marginal cost, suggesting there is little downside relief to buyers. With the risk of plant shutdowns to meet new pollution controls and the effect of the ongoing drought, the Texas power market faces a challenging 2012, with heightened risks of further power price spikes.


1 March 2012 12


Credit

US High Grade Energy and Pipelines Market Weight (Integrated Energy) Market Weight (Refining) Overweight (Pipelines)

We see better value in the pipelines sector than in energy and have recently upgraded the pipelines sector to Overweight from Underweight. The high grade E&P sector has been buffeted by concerns about low natural gas prices, while the integrated oil and gas category is trading 10bp rich to its 3y average differential versus U.S. Credit, which seems too tight in light of an improving environment for risk. Oil field service credits continue to trade cheap to their 3y average differential versus U.S. Credit, while the refining sector has benefited as investors have grown less concerned about the new supply effects related to the pending separation of Phillips 66 from ConocoPhillips (COP, MW).

Our top picks are in the pipelines sector, where we remain Overweight Enterprise Products Partners L.P. (EPD)(OW) and Energy Transfer Partners, L.P. (ETP)(OW). In the high grade E&P sector, we are Overweight Anadarko Petroleum Corporation (AP)(OW) and Nexen Inc. (NXYCN)(OW). In oil services, we remain Overweight Nabors Industries Ltd (NBR)(OW), which we expect to reduce debt in 2012.

US High Yield Energy Market Weight

We are Market Weight the High Yield Energy sector, and despite the sell-off, expect 5-7% returns for energy bonds in 2012. HY Energy is trading ~600bp over Treasuries, about 85bp cheap to its 10-year average. Weak natural gas prices have led to a sell-off in E&P credits leveraged to gas, and benchmark bonds are down 5-7% year-to-date. High Yield Energy is now more fairly valued compared with IG. In August 2011, High Yield Energy was ~470bp wide of IG Energy, while the current differential is ~405bp.

Buy MEG Energy 21s (OW), sell Concho Resources 21s (NR), pick up 125bp in yield. Both companies are B3 rated and have good exposure to oil prices, though the recent divergence in spreads leaves better opportunity in MEG, in our view. Buy Targa Resources Partners (NGLS) 21s (OW), sell Regency Energy Partners 21s (MW), pick up 60bp in yield. We believe NGLS is trading cheap to RGP, given its lower leverage and better ratings. Buy PGS 18s (NR), sell CGV 21s (NR), roughly even yield and shorten duration. PGS has better ratings with a lower net leverage and benefits from a younger seismic fleet capable of generating higher margins.

US High Yield Coal Market Weight

We are cautious on thermal coal names, given weak thermal coal fundamentals, within a Market Weight view on the wider US metals & mining sector. Domestic thermal coal fundamentals continue to weaken, as persistently warmer-than-expected winter weather and sub-$3/MMBtu natural gas erode demand. With production largely committed and priced, investors will be watching closely to see whether utilities are able to renegotiate pricing and/or delivery of 2012 commitments.

Arch Coal (ACI) 7.25% senior notes of ’20 have widened 80-90bp relative to Consol Energy (CNX) 6.375s and Alpha Natural (ANR) 6.25s since mid-January. We are comfortable that ACI can remain free cash flow positive under some very bearish assumptions and believe investors should consider swapping out of CNX/ANR into ACI 7.25s to pick up the additional yield at current levels.

US High Grade Utilities Overweight

Our Overweight recommendation on this defensive sector reflects its strength during periods of market volatility. As market conditions stabilize in 2012, we expect the high grade electric utility sector to perform in line with the Credit Index. At current spreads, we favour BBB and crossover regulated utilities, and utility holding companies with predominantly regulated business models. Given continued weak pricing conditions, we remain cautious on unregulated generation subsidiaries and diversified holding companies with larger unregulated generation businesses.

Buy Duquesne Light Holdings (DQE)(OW) 5.90% bonds due 2021, quoted at +290. Rated Ba1/BBB-, this crossover holding company with a predominantly regulated utility transmission and distribution business benefits from a constructive regulatory environment, an attractive service territory, and favorable provider of last resort arrangements. Buy Metropolitan Edison (FE)(MW) 7.70% bonds due 2019, quoted at +135. Met Ed is a low-risk, regulated transmission and distribution utility with a supportive regulatory environment in Pennsylvania and manageable capex requirements.


1 March 2012 13


Credit

European High Grade Oil & Gas Overweight

Our positive outlook for the European HG Oil & Gas space is supported by expectations that WTI and Brent prices will improve through 2012 and into 2013. We highlight that overall EBITDA and, thus, cash flow growth in the oil and gas sector remain strongly linked to the price of oil due to the dominance of E&P in cash generation, fostering cash flow stability or growth throughout the year.

Switch out of BG Group and into BP (in euro): We need to see evidence of production growth translating into operating cash flow that is ahead of capital expenditure growth before we can be more confident on BG building some rating headroom. Buy Repsol 5y CDS, owing to limited downside, spread volatility in Europe and ongoing tail risk on YPF in Argentina. Sell BP 5y CDS against buying 5y CDS protection on Total. We expect BP's spreads and ratings relative to its AA peers to narrow should a favourable Macondo settlement be reached. We recommend a CDS pair trade that involves selling BP 5y CDS against buying protection on Total (Aa1Stbl /AA- Stbl).

European High Grade Utilities Market Weight

Paying respect to excess return performance during 2011, while euro credit indices were dominated by peripheral issuers, utilities still managed to marginally beat the Pan-European Credit Index market by 17bp. Despite the market rally that has accompanied the start of this year, we remain cautious on the periphery in the near term. However, owing to recessionary risks, where utilities will likely fare better than most, we believe a Market Weight recommendation is appropriate.

Switch out of Iberdrola and Enel into Gas Natural Fenosa across the EUR curve. We believe Iberdrola and Enel, through Endesa, are significantly exposed to near-term risk regarding the tariff deficit and special taxation in Spain. Buy United Utilities plc CDS. The most liquid CDS contract references United Utilities plc and is therefore at risk of adverse movements on a leveraged takeover of United Utilities Group and we believe the CDS is too tight for a BBB/ Baa1 credit.

Asia High Yield Coal Underweight

We remain constructive on the fundamentals of the Indonesian coal sector. Higher production targeted by most companies should fuel cash flow growth in the near term and support stable to improving, albeit slight, credit profiles. Despite our constructive outlook, we believe bond valuations look fair to rich, given the rally YTD, high cash prices and potential supply risk. As such, we revise our sector weighting to Underweight from Overweight.

Sell Adaro ‘19s (UW). The bonds offer one of the lowest yields among Asian HY bonds. While we view the company’s credit profile as relatively stable in the near term, we see higher downside risk on the bonds, given tight valuations and the company’s growth ambitions. Switch from Indika ‘18s (UW) to Indika ‘16s (MW). The yield curve on the bonds is inverted. We expect this to normalise over time. Further, the two bonds are pari passu to one another and share the same key covenants.

Asia High Grade Energy Market Weight

We remain constructive on the Asia Oil and Gas sector and in particular upstream producers on the back of elevated oil prices. We expect earnings to improve in 2012, due largely to higher realised oil prices and increased production. We think merger and acquisition event risk remains elevated but is mitigated by the strong credit profiles of issuers, as well as adequate ratings headroom to accommodate a moderate increase in debt-funded leverage.

Overweight Reliance Industries: We expect the credit profile of Reliance to remain stable in 2012, especially after the sale of its stakes in KGD6 to BP, which should offset the near-term risk of decreased gas production output. Market Weight CNOOC: Given the company’s strong financial and operating profiles compared with peers, we continue to view CNOOC ‘21s as a core position.

Asia High Grade Utilities Market Weight

We remain cautious on Asian Utilities, as we expect input cost to remain high for the power and gas utilities in 2012, albeit continuing strong governmental support due to low reserve margins. We expect inflation concerns and slowing growth to weigh on earnings; the ability to pass on rising cost remains a concern in Malaysia, and to a lesser extent, in Korea.

Overweight Korea Hydro & Nuclear Power Co: KHNP benefits from strong support from the Korean government and has the strongest credit profile among the Korean quasi-sovereigns. As a predominantly nuclear operator, it has the lowest generation cost per unit and is not exposed to carbon fuel prices. This will support the company’s earnings and credit profile in the event of volatile energy prices, in our view.


1 March 2012 14


Equities

Americas Integrated Oil 1-Positive

Our base-case scenario is that oil (Brent) could continue to trade mostly in the range of $100-120 per barrel over the next 12 months, while the North American gas market will remain challenging. We estimate that the sector is currently reflecting a long-term oil price assumption of $85-90 per barrel. However, we believe the Supermajors will underperform other energy subsectors in 2012.

Suncor (1-OW, PT CAD48) is currently our favorite name, for its progressing reliability in production and utilization levels, potential improvements in cost structure, attractive valuation, and high oil price leverage. We maintain our 1-Overweight rating on Hess (1-OW, PT $90), as we see the valuation gap between HES and other large cap E&P companies as too wide. We favor Imperial Oil (1-OW, PT CAD60) for its strong long-term growth potential and attractive valuation, with shares trading at an 11% discount to our C$54 per share NAV estimate.

European Integrated Oil 2-Neutral

With higher cash flows, the integrateds have had a greater focus on growing production through increased capital expenditure, rather than using the cash to lift shareholder returns, and as a result, there has been little gain in free cash flow. Valuations for the group remain in a narrow range, with only a 15% spread in 2012E cash flow multiples between the top five European integrated companies by market capitalisation.

Our favoured companies remain those with leverage to oil prices, a bias towards LNG and with differentiated growth or exploration profiles. Our current favourites include BG (1-OW, PT 1800p), Statoil (1-OW, PT NOK180) and GALP (1-OW, PT EUR19.6). Also in the EMEA time zone, we recommend Sasol (1-OW, PT ZAR440). It is poised to deliver strong FY12 results and further growth, with expansion potential from its GTL, synfuels/optimisation and gas segments.

Asia Ex-Japan Oil & Gas 1-Postive

China remains a key driver for global oil demand growth, partly reflecting demand growth for middle distillates owing to continued industrialisation and urbanisation in the country. While Chinese refiners’ profitability has improved from recent fuel price hikes, expectations of widespread energy policy reforms in the short term is, to us, a more complex proposition than the market may anticipate.

Our stock preferences focus on companies with an upstream bias, which are also oil price leveraged. CNOOC (1-OW, PT HK$21) remains our top pick, offering good value and returns, with its high-margin domestic barrels likely to drive 4% pa production growth over the medium term.

US Exploration & Production 2-Neutral (Large-Cap) 1-Positive (Mid-Cap)

We expect natural gas production growth to decelerate, or perhaps reverse, as the effect of $2-3 gas prices takes hold. Falling gas-supply costs and the attractiveness of drilling NGL-rich wells should, however, prevent a dramatic fall-off in drilling activity. In higher cost areas, activity is moderating, and this should allow gas markets to re-establish a long-term equilibrium price of $3.25-4.00 by mid- to late 2013.

We continue to support the purchase of oil-oriented producers and we recommend that investors avoid most gas producers. Our top picks in the large-cap group are EOG Resources (1-OW, PT $144) and Noble Energy (1-OW, PT $123). In mid-cap space, we favor Denbury Resources (1-OW, PT $24), Plains Exploration (1-OW, PT $51) and Whiting Petroleum (1-OW, PT $70).

Canadian Exploration & Production 1-Positive (Mid-Cap)

We believe the Canadian E&P sector offers an attractive growth/income profile (average 12% production growth and 5.5% dividend yield) while providing exposure to Canada’s highest quality resource plays. In our view, the Canadian mid-cap names are generally high quality, with strong management teams and prudent strategies.

With a weak outlook for natural gas, we remain biased toward oil-weighted names with exposure to high netback, large oil resource plays. Our top oil-weighted picks include Crescent Point (1-OW, PT CAD51) and Baytex (1-OW, PT CAD64) for their strong track records and clean balance sheets, and PetroBakken (1-OW, PT CAD19) as an inexpensive oil-weighted name looking to regain confidence due to its recent operational successes and financial repositioning.

European Exploration & Production 1-Positive

Year to date, sector performance has been strong rebounding from its Q3 11 lows, with the E&Ps gaining 30%, compared to a 25% of the wider market. However, with an average upside potential over 20%, based an oil price of $110/bl in FY12, we believe the sector still offers attractive returns for investors.

Afren (1-OW, PT 195p) is our Top Pick, as it combines production growth, free cash flow and an attractive exploration upside at an undemanding price. We also see value in Tullow (1-OW, PT 180p), as it has the most attractive exploration portfolio of the group, with French Guyana now a low-risk asset that could add £6/sh to our NAV over the next few years as exploration drilling intensifies.


1 March 2012 15


Equities

US Independent Refiners 1-Positive

We recommend overweighting the sector to take advantage of this traditionally strong seasonal trade. Between 1990 and 2011, the sector has outperformed the market by 14% from January 1 to the end of May. With a normal to heavy spring turnaround season in the Atlantic basin and refinery closure announcements from Hess and Petroplus, margins are unlikely to deteriorate in the near term and may show signs of improvement. US margins are likely to remain more robust than European margins, given the higher own energy costs of the European group.

We are positive on Tesoro Corporation (1-OW, PT $37), as we do not believe the current share price has fully reflected TSO’s improving margin capture rate in their core West Coast market. We think Valero Energy’s (1-OW, PT $31) recent underperformance, coupled with its strong earnings potential, offers an attractive investment opportunity for investors. We rate Marathon Petroleum (1-OW, PT $50) Overweight, as we think the recent approval of a two-year $2bn share buyback program and potential MLP of its midstream assets indicate MPC’s commitment to returning cash to shareholders and unlocking value.

European Refining & Marketing 3-Negative

We expect 2012 to be the fourth consecutive year of difficult margins for the European refining industry, caused by overcapacity, lacklustre demand and a higher-than-average cost base. However, the closure-driven near-term margin strength is likely to be supportive of the seasonal trade, which normally runs January through March.

Our preference remains for those companies that have high quality assets which should convert to cash flow through the cycle – namely Motor Oil (1-OW, PT EUR11) and Neste Oil (1-OW, PT EUR14), both 1-Overweight.

US Oil Services & Drilling 1-Positive

We believe the reason to own oil services stocks is clear: the world is becoming increasingly short energy, hydrocarbon prices are likely to rise further; cash flow and, thus, capex on energy investments are increasing rapidly; and the oil services companies are likely to capture the economic benefit of this unfolding trend. We remain bullish on the oil services, equipment and drilling companies and believe the group will significantly outperform the broader equity market over the next several years.

In our view, the most attractive stocks are the large-cap diversified companies: Baker Hughes (1-OW, PT $85), Halliburton Co. (1-OW, PT $67), Schlumberger (1-OW, PT $107) and Weatherford International (1-OW, PT $27); the capital equipment names Cameron International (1-OW, PT $75) and National Oilwell Varco (1-OW, $128); several of the offshore drillers Transocean Ltd (1-OW, PT $73), Rowan Companies (1-OW, PT $51), Noble Corp. (1-OW, PT $46) and Ensco plc (1-OW, PT $64); and select small/mid-caps such as Hornbeck Offshore Services (1-OW, PT $52), GulfMark Offshore (1-OW, PT $65), Superior Energy Services (1-OW, PT $48), Dresser-Rand Group (1-OW, PT $73), Global Geophysical Services (1-OW, PT $17) and ION Geophysical Corp (1-OW, PT $11). We also like the small- and mid-cap North America-focused stocks, especially with most trading below 5x 2012 EV/EBITDA.

European Oil Services & Drilling 1-Positive

With most spending programmes being announced higher than our initial expectations, 2012 is likely to be another year of significant capex growth. Pricing for seismic in summer 2012 is likely to be up 10-15%; offshore construction backlogs are back at all-time highs and all companies are talking of record levels of enquires, including even the still-depressed offshore heavy transportation section. In our opinion, we are well into the next up-cycle and expect continued spending growth for several years.

Our preferred seismic play remains PGS (1-OW, PT NOK120), while those investors with a smaller-cap bias could do worse than invest in Polarcus (1-OW, PT NOK9). Continued progression into ever deeper offshore waters bodes well for Subsea (1-OW, PT NOK185) with its now expanded capabilities and exposure to the much improved North Sea assets. Saipem (1-OW, PT EUR48) with its wide portfolio of activities remains our favourite bellweather stock in the sector.

US Coal1 1-Positive 1Sector view is for the wider US Metals & Mining sector

We expect U.S. thermal coal prices to suffer through an extended period (lasting at least through 2014) of oversupply, brought about by lower natural gas prices, weak electrical demand, and limited incentive to cut contracted production in the near term. While we believe that metallurgical coal prices will rebound into 2H12 as global macro concerns stabilize and Chinese steel production returns to growth, the “hybrid” nature (thermal + met) of most coal companies’ production profile means that low thermal prices could continue to weigh on sector valuations.

Our top stock picks among the coal companies include those with margins more heavily weighted by metallurgical and/or international markets, such as Alpha Natural Resources (1-OW, PT $29), Peabody Energy (1-OW, PT $45), and CONSOL Energy (1-OW, PT $50).


1 March 2012 16


Equities

Asia ex-Japan Coal 1-Positive

Our medium-term positive demand view is tempered by supply-side concerns and inventory overhang. 2012 has started off with the coal companies having excess inventories across the supply chain. While the seaborne market looks stronger at the margin (with India coming back as a buyer), the domestic supply/demand balance in the two largest global markets – China and the US – does not look too promising for the first half. Not withstanding our lukewarm view on the near-term prospects, we like the Asia coal sector on a medium-long term view for two main reasons: 1) Chinese coal has been the quintessential volume growth story, with the big-3 listed producers expected to have volume CAGRs of upwards of 10%, with additional upside from small mine consolidation (compared with 7% for the industry); 2) the shift from contract pricing to spot-based pricing is ongoing for most companies and should lift ASPs better than the global average

China coal energy (1-OW, PT HK$113) remains our top pick: The company is going through a 5-year transformation, the effect of which is not fully priced into the stock. The volume growth (doubling volume from 100mn tonnes in 2009 to over 205mn tonnes in 2015), mix shift (from only 23% spot price exposure in 2009 to over 60% by 2015) and product shift (from 1% coking coal in the mix currently to over 8% by ’15) could more than triple EPS on a constant commodity price scenario and the stock is at 11x ‘12e P/E.

US Power 2-Neutral

We believe power stocks are 7-13% overvalued, with gas prices being the biggest risk. We estimate that the group trades at a $4.33/Mcf gas price, a significant premium to the forward curve and Barclays Capital’s forecast. Coal shutdowns are rising in response to the Environmental Protection Agency’s Mercury Air Toxics Standards rule in 2015 and to low commodity prices. Prices from the May 18 PJM capacity auction will likely increase from last year’s, although some expectations might be getting too high.

We prefer NextEra Energy (1-OW, PT $61), which provides power exposure with long-term contracts insulating the company from short-term swings in price. We are positive on Calpine Corp. (1-OW, PT $18), which is a spark spread generator with limited exposure to gas prices, as their plants are the most efficient. They are also well positioned in our favorite TX and CA markets.

European Utilities 2-Neutral

We do not believe that European Utilities offer compelling valuations at the moment, given the challenging growth outlook, and reiterate our 2-Neutral stance. In our view, the sector is facing structural threats in the form of renewables, competition from new fossil fuel generation and stagnant energy demand.

Within the sector, we prefer companies with defensive characteristics and secular growth potential. These include International Power (1-OW, PT 415p) and National Grid (1-OW, PT 680p). We also prefer those that can directly benefit from commodity price or renewable policy trends such as Drax (1-OW, PT 675p) and Pennon (1-OW, PT 890p).

US Clean Technology & Renewables 2-Neutral

While improving data points suggest that industry trends have begun to bottom, we believe recovery in the U.S. Clean Technology & Renewables sector remains limited, given issues such as diminishing regulatory support and overcapacity in key markets. We thus expect further industry consolidation, driven by capital needs, scale, and high barriers to entry, to continue in the next 6-12 months, enabling incumbents to capitalize on underpenetrated market opportunities.

Power-One (1-OW, PT $6) is our top relative solar sector pick, as we believe the company is well positioned to gain share in the growing North American and Indian markets. Elster (1-OW, PT $18) emerges as our top pick in the smart grid sector, largely as it generates 45% of revenues from Europe, where the next leg of spending should emerge in late 2012/early 2013. Ameresco (1-OW, PT $14) is our energy efficiency pick for its comparatively defensive business model in the current environment; thus, we like its longer-term visibility and cash generative characteristics. Tesla Motors (1-OW, PT $38) is our top pick in the electric vehicles market, as we believe the company, as a premium provider of automobiles, is well positioned to capture share in the broader vehicle market.

European Clean Technology & Renewables 1-Positive (Energy Efficiency) 2-Neutral (Solar) 1-Positive (Wind)

We forecast demand for renewables to have ongoing growth and annual installations for wind and solar to lead to CAGRs of 8.5% and 11.1%, respectively, over 2010-15. This year, we expect wind installations to grow strongly, to reach 47.0GW ahead of the expiry of the PTC in the US. In our view, we will see an increasing switch from centralised-only power generation to a hybrid approach, supported by the ability of rooftop solar to provide a meaningful proportion of a household’s power generation requirements.

We believe Outotec (1-OW, PT EUR57) is well positioned to have further backlog order growth as customers seek to reduce energy costs. We view Umicore (1-OW, PT EUR45) as favourably positioned across recycling for end-of-life goods, which made up 27% of the company's revenues in 2011. We expect Prysmian (1-OW, PT EUR13.5) to continue to deliver margin progression, as the business benefits from exposure to growth in offshore wind and high voltage transmission, as well as leveraging cost synergies from the acquisition of Draka.

Credit Rating System (for a full definition, please see page 149): Sector Weighting: Overweight, Market Weight, Underweight. Credit Rating: OW, MW, UW. Equity Rating System (for a full definition, please see page 151): Sector view: 1-Positive, 2-Neutral, 3-Negative. Stock Rating: 1-OW, 2-EW, 3-UW 1 Sector view is for the wider North America Metals & Mining sector.


1 March 2012 17

COMMODITIES


1 March 2012 18

COMMODITIES OIL

Less downside, more upside We maintain our Brent price forecast of $115/bbl for 2012, which we have held

since last July. However, should the scenario of a rapid deterioration in Iran’s external relations, with no resolution in 2012, continue to force itself into the base case, we would expect the annual average to be as much as $20 higher.

With extremely limited buffers to absorb any of the potential geopolitical mishaps, the backdrop to the oil market is challenging. Thus, maintaining a deep short position would be unwise, in our opinion.

In the longer term, we see limited scope for supply to grow faster than demand; hence, we also maintain our price forecast of $135/bbl for 2015.

Much has changed since the start of the year, although it has only been two months. Through January, the extreme tightness of Q3 was removed, and a much better supplied prompt market started to exert downward pressure on time spreads. To confuse matters, oil demand growth slowed considerably through most of Q4 and early Q1, weighed on by some extremely warm weather, but macroeconomic indicators around the world started to look healthier, creating a juxtaposition that kept oil prices fairly range bound but time spreads weak. However, the momentum in the market has changed considerably since. Despite what looked like a rather well-supplied prompt market, the weakness in time spreads have abated and, in fact, tightness is already starting to emerge. While the spate of cold weather in Europe has helped to normalise balances somewhat, in our view, it has really been the uptick in Asian oil demand that has helped absorb some of these extra OPEC volumes that have come to the market. Indeed, we believe that Asian oil demand is growing at a faster pace than markets are currently pricing in. Add to that a supply picture in which between Sudan, Syria and Yemen, almost 1.2 mb/d of output has been shut in, the excess in supply was temporary indeed. Moreover, shortfalls in North Sea, Mexico, and the FSU continued, resulting in a non-OPEC supply picture that was falling away quicker than demand. At the same time, geopolitical tensions related, but not confined solely to Iran, have ratcheted higher and have intensified since the start of the year. While we have been listing the Iranian situation as a source of upside risk for a decade, there are some new factors that potentially make for a far more dangerous outcome, as the current drift of policy on both sides is creating the risk of a significant escalation, in our view. Against a backdrop of extremely thin buffers of just 1.7 mb/d of spare capacity and OECD inventories that are over 50 mb below seasonal averages, despite the recent move up in oil prices, risks remain skewed to the upside.

Provided the Iran-dominated scenario is not the base case, we think our current price forecast of $115 per barrel is as justifiable now as it was last July. However, a July 2012 base case of a gentle and controlled escalation through 2012 does now appear less likely, and we see some danger of a more uncontrolled (yet still gradual) escalation scenario. This raises the question of how prices might behave in such a scenario, given that it is predicated on the assumption of no actual resolution of the situation in 2012. Under the scenario of a grind higher against the depressing forces of perhaps regular strategic stock releases, negative economic feedback effects and rampant oil price politicisation, we think quarterly averages of $140 per barrel or $150 per barrel are distinctly possible for Q3 and Q4. In terms of daily prices, that would mean that past all-time highs would be significantly exceeded. Overall, we believe the grind- higher scenario, would imply an annual average for 2012 some $20 per barrel above our current forecast, at perhaps $135 per barrel of Brent.

Amrita Sen +44 (0)20 3134 2266

[email protected]

Much has changed since the start of the year…


1 March 2012 19

The key point is that high prices are achieved in this scenario without any closure of Hormuz or any overt military action in or against Iran. We reiterate that this is not our current base case, though it does seem to be moving closer to becoming reality, and would require a significant change in our forecasts should it become the base case. Is this the scenario planned for by governments in the context of the latest escalation of pressure against Iran? We rather doubt that, which is why we would see it as a relatively uncontrolled and potentially highly unpredictable escalation of the situation. Overall, we are maintaining our current price forecasts, but we are signalling the upside risk of any clear movement toward a drawn-out and intensified escalation of the situation concerning Iran’s external relations and nuclear programme.

Macro economy, sovereign debt and oil demand

Sovereign debt and oil demand

The sovereign debt discussion has started to include anything up to and including the insolvency of Greece, a possible breakup of the euro area or a recession there. Though the effect of these three events would be considerably different on financial markets, let alone oil markets, much of the analysis on the Street puts the effect as one: the collapse of oil prices. Should the European crisis transform into a global financial crisis, there would be a strong case to be made for a collapse, albeit temporary, of oil prices towards $70 per barrel.

Indeed, in the 2008-09 cycle, the drying up of credit had the largest effect on oil prices and the commensurate collapse. Back then, world trade fell 19% in the 12 months to May 2009. 10-15% of that was attributable to a drop in the availability of trade finance, according to WTO estimates, with margins above risk-free rates on letters of credit issued in developing countries rising nearly 30-fold. The current problem lies with European, in particular French, banks, traditionally extremely important participants in trade finance. Various market estimates place lending to be down about 5% y/y in 2011, and with the new capital rules preventing other banks from increasing their lending ratios, the situation has the potential to get significantly worse. The recent insolvency of Petroplus (which struggled to find credit following the failure of negotiations with lenders under its revolving credit facility, and the subsequent closures of its refineries) is the most recent example of such problems, although it does remain a unique case.

The European crisis snowballing into a credit or broader financial

crisis would result in oil price collapse

Figure 1: European oil demand, y/y change, thousand b/d

Figure 2: Global manufacturing and IP

-800

-600

-400

-200

0

200

400

1990 1993 1996 1999 2002 2005 2008 2011

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-15

-10

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0

5

10

15

02 03 04 05 06 07 08 09 10 11 12-4

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0

1

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Global industrialproduction*, LHSGlobal manufacturingconfidence (BarCap), RHSNew orders less fin. goodsinventories (BarCap), RHS

6m/6m change, saar normalised diffusion balance

Nov est.

Consistant with stabilization of industrial sector

Source: BP statistical review, Barclays Capital Source: Barclays Capital


1 March 2012 20

However, in terms of collapsing prices, other negative economic events, particularly in Europe, do not seem to have the potential to create price drops of any great severity (unless they created a severe financial crisis). If the break-up constitutes a few countries leaving the system at the edges, or a relatively controlled general move away from the current system, then prices would come under pressure from weak sentiment, but it is hard to see how that could occasion an oil price collapse. The last time Europe mattered for oil demand growth was over a decade ago, and Europe’s income and price elasticities for oil are so low that they have for long done little to alter oil balances. Our own forecast for 2012 euro area GDP is a contraction of 0.2% (ie, a mild recession), the IMF’s is 0.5%, and even an additional 1% contraction would not severely damage the overall robustness of our balances. Moreover, with the second bailout package agreed for Greece recently, policymakers finally seem ready to protect global markets from any potential spillover from a disorderly Greek default scenario, despite implementation risks remaining following the agreement.

Global macroeconomy and oil demand A great paradox currently gripping the oil market is that OECD oil demand has taken a step for the worse right when, arguably, macroeconomic indicators have started to look up. The US is a particular case in point, in which the divergence in data patterns is all too evident: just as the US economy has started to look healthier on the basis of recent readings, US oil demand has taken a significant turn for the worse. Even adjusting for rising efficiency standards in automobiles and fewer miles driven, the weakness in gasoline in particular looks a bit overdone to us. With employment conditions on a steady upward trajectory, home sales data looking perkier, and manufacturing activity picking up, it would seem necessary for the divergence in macroeconomic and gasoline demand to resolve itself relatively promptly. Either the macro data are due for a sharp downward correction across the board or oil demand is likely to be subject to some large upward revisions in the coming months. However, leading indicators such as trucking and rail miles driven remain robust, pointing to healthy activity in a recovering economy, rather than a faltering one.

In fact, in general, the recent macroeconomic data flow suggests that not only are outcomes better than oil market participants expected, but they may not be that poor in absolute terms either. Global manufacturing data and business confidence suggest that industrial production and sentiment have continued to stabilise. In addition to the solid increase in the global manufacturing confidence series in January (see January global manufacturing confidence: Stabilisation is on course for 2012, 1 February 2012), the Barclays Capital global business confidence series recorded the largest increase since February last year. The Barclays Capital aggregate of global manufacturing PMI data recorded its second straight monthly increase, advancing from -0.52 in December to -0.32 in January. Aside from small declines in Turkey and France, all other countries displayed an improvement in PMI. In fact, the euro area flash PMI moved above 50 for the first time since August 2011 and is off to a good start in Q1 12, underlining upside risks to our Q1 baseline GDP forecasts. Given current events, our economists believe the worst is behind us. Even in the UK, services PMI was significantly stronger than expected for January.

The key point is that the economic data seem fairly good in precisely the part of the economy that matters most for oil demand at the margin – China and the US; even in the area of greatest concern – Europe – indications appear healthier at least in relative terms, if not in absolute terms in some instances. If manufacturing does well, China achieves a soft landing and the US economy continues to surprise to the upside, the various global oil demand estimates could yet prove robust or even nudge up.

European recession alone would not be enough to drive

oil prices below $100

World economy better, oil demand indications worse

Confidence and global IP are improving steadily

https://live.barcap.com/go/publications/content?contentPubID=FC1787457�



1 March 2012 21

Current versus past and future oil demand Yet, despite OECD oil demand deteriorating significantly of late, global oil market fundamentals appear to be tighter than implied by recent US oil data releases, the most recent of which also appear to be out of line with US macroeconomic data. In our view, there is at this moment a sharp and unexpected demand surge from Asia and the FSU, on top of which a severe European cold snap has created tighter prompt market conditions than either expected or implied by the US oil data, focus on which remains high given its frequency and prominence. The problem with judging the global pace of oil demand growth is that the epicentre of that growth has definitely moved away from the US to Asia, and China in particular. Yet, due to the lack of prompt alternatives, the more readily available oil data from the US are still used as a global guide to the health of the oil markets. Together with the overload of US macroeconomic data, US oil data by force remain a large driver of daily oil price movements. The difficulty for the market is that data flow is fastest and most detailed in the weaker spots, while it is slower and less comprehensive in areas of runaway demand strength. This often creates false illusions about the state of global demand, and current commentary on demand and inventories seems to point to exactly that.

In the US, the revised data currently extends to November, leaving December and January and now the start of February as provisional readings based on the weekly data. Those provisional readings are very weak indeed. There is a y/y fall in total demand of 1.22 mb/d shown in December, a 1.02 mb/d fall in January, and a fall of 0.44 mb/d for the first small slice of February data. The sharp declines since November, however, are out of line with the positive macroeconomic data flow that has since been on an upward trajectory. In our view, the US oil data releases are probably overstating the extent of the immediate demand weakness and the surge elsewhere is likely to be largely compensating, but it may take several months of murky data flow to resolve these issues.

In particular, gasoline demand in the US has been extremely weak. The reasons for some weakness are fairly clear. US retail gasoline prices are the highest they have ever been in January or February, with the y/y increase currently 12.1%. Further, while the macroeconomic data have been much better, the lagging part of that data recovery still appears to be the consumer. It appears producer confidence is rebounding faster than consumer confidence (ie, fundamentals are stronger for diesel than they are for gasoline). Indeed, the recent run of strong trucking and rail statistics suggests precisely that.

However, while gasoline demand might then be expected to be weak, a y/y fall of over 500 thousand b/d might be overstating it a lot. If you compare the latest data with unrevised weekly data from 2011, the fall looks even worse – as much as 856 thousand b/d. However, February 2011 gasoline was revised down by 347 thousand in monthly data, the largest downwards revision made in the Petroleum Supply Monthly for any month since January 2000. The week-on-week comparison is perhaps best avoided given that context. There are also some technical issues concerning changes in the estimation method for exports, knock-on effects from ethanol due to reductions in some key incentives, as well as the possible effect on the data of refinery closures. Put all that together and any conclusion that the weakness in gasoline is accelerating may be a rather suspect one. We believe that when the various data clouds finally clear, US gasoline demand will be shown to be weaker, but no weaker than it has been for a while, down about 3%; perhaps in relative terms, it may well start to improve given the better economic data flow and approaching potential narrowing in the y/y rate of retail price increases, given the sharp increase in March 2011. In short, gasoline demand remains weak, but we do not believe it has fallen off a cliff in 2012.

Global oil demand in better shape than markets think

US oil demand draws a stark contrast to macroeconomic data

US gasoline… mysteriously low

Real state of gasoline demand will be revealed once the data

clouds clear


1 March 2012 22

Figure 3: Global oil demand growth has rebounded Figure 4: Weather variations influence European demand

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The other key source of demand weakness has been Europe. Here though, oil demand has not fallen due to the European sovereign debt crisis; weather has been the real key factor, as this has shaved off the seasonal peak in demand for winter fuels. The latest JODI data showed European demand in December coming in lower y/y by 802 thousand b/d, extending the weather linked weakness from November when demand had fallen by 859 thousand b/d. Heating oil and fuel oil were the weakest parts of the barrel as Europe faced a warmer than normal winter, with heating degree days 25% higher than usual in Q4. European distillate demand fell y/y by 338 thousand b/d, while fuel oil demand was lower by 186 thousand b/d in December. While the weakness is likely to have persisted in January, February’s indications should be far more supportive given the recent cold weather, normalizing winter fuel demand.

For now though, given the datasets available, an automatic comparison is then made with the 2008-09 cycle, when oil demand fell more than 2 mb/d across H2 08 and H1 09. The circumstances of September 2008 were perhaps almost unique in the immediate freezing of the US economy it created and the associated sharp move down in oil demand, particularly in the middle of the barrel. The y/y fall in US oil demand in September 2008 was a massive 2.56 mb/d. Indeed, it fell more than 1 mb/d y/y in eleven out of twelve months. The point of maximum pain in the OECD as a whole was two months later: OECD oil demand fell 3.9 mb/d y/y in November 2008 and averaged -2.9 mb/d over a nine-month period. In 2011, there were no expectations of any declines in demand of that severity. Beyond the very immediate falling away of US oil demand, reasons for which are discussed above, the damage has been largely contained to falls of 0.5 mb/d, not 2.5 mb/d. Across 2011, US oil demand was 0.36 mb/d lower y/y, compared with 1.2 mb/d in 2008 and 0.73 mb/d in 2009.

Equally, there has been a slight confusion with regards to absolute levels of demand and growth rates, especially with regards to the non-OECD, where due to a very high base, recent demand growth figures have seemed tempered. In our view, Asian oil demand remains robust and in fact poses a significant upside demand risk to global oil demand this year. For instance, a slower growth environment, which played a part in easing Chinese oil demand growth, was evident primarily in the falling away of petrochemical demand in the country. However, the severity of that shortfall was magnified by the significant destocking that took place, with the change in Chinese inventories the slowest in a decade. With Asian petrochemical prices picking up already and the government starting to ease credit constraints, we expect some restocking demand to materialise in 2012. In fact, we now suspect that the upside surprises from Asia (including Japan) are coming through perhaps

European demand for winter fuels impacted by the warmer

than normal winter

… but it is nowhere near as bad as 2008-09

China and India have destocked severely, but could reverse soon


1 March 2012 23

earlier than even we had expected, helping to absorb the extra OPEC volumes in the market and offset demand weakness elsewhere. Although Asian refineries reduced their March intake of West African barrels to around 1.87 mb/d (Bloomberg), February’s intake was a seven-month high of 2.15 mb/d. Equally, Middle Eastern producers, Saudi Arabia, UAE and Kuwait are all supplying full contractual volumes to Asian refineries in March, signalling that demand in the region remains extremely robust.

The strength, however, has not been confined to non-OECD Asia alone, with Japan proving to be a rather large source of support. Japanese oil demand data showed inland deliveries for December rebounded strongly to 4.98 mb/d, the highest levels since February 2008 and constituting exceptionally high y/y growth of 429 thousand b/d. Preliminary January data were even stronger, with oil input at Japan’s main electric utilities surging to 638 thousand b/d (332 thousand b/d of fuel oil and 306 thousand b/d of crude), up 117% from a year earlier. The January numbers almost matched February 2008’s peak of 668 thousand b/d, after declining to just 70 thousand b/d in October 2010, as nuclear power output fell 83% y/y (to only 10% of capacity). Oil input this month is likely to have risen even higher as weather turned colder than usual and nuclear power output continues to head towards zero as the remaining nuclear plants are shut down. There have been unconfirmed reports that the government is considering the restart of two nuclear power stations by April, but until that happens we would expect Japanese oil demand to remain high and could be the wildcard to this year’s global oil demand.

To summarise, we expect oil demand to increase 1.04 mb/d in 2012, as does the bulk of consensus estimates (IEA, EIA, OPEC), marking a slight improvement from 2011. There is very little divergence in overall expectations even in the pattern of growth, with non-OECD countries continuing to carry the burden of growth. Contagion from the European crisis to the financial sector – however small today – remains the key downside risk to oil demand prospects, rather than a recession in Europe itself. With the low point of European GDP appearing to be behind us (in Q4 11) and small but sequential improvements expected through 2012, European demand prospects may not be that dire after all. Moreover, with US and Japanese economic data surprising consistently to the upside, the drag on oil demand from a lacklustre OECD should be less this year than in 2011. As for the non-OECD, structural factors should keep demand well supported, as has been the case for the past decade, while pockets of strength are already appearing in non-OECD Asia, which should continue as these countries restock following some severe destocking in 2011.

Figure 5: Asian petrochemical prices, $/mt Figure 6: Rate of Chinese inventory change, thousand b/d

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3mma

Source: Bloomberg, Barclays Capital Source: China Customs, Barclays Capital

Demand growth likely to surprise to the upside


1 March 2012 24

Spare capacity, geopolitics and oil supply

Non-OPEC supply A highly overlooked aspect of the oil market last year was the drastic disappointment of non-OPEC supplies relative to initial expectations, in particular the deceleration after Q1. 2011 started off on a strong note, with non-OPEC supply in January increasing almost 1 mb/d, continuing the momentum from Q4 10. However, since February, non-OPEC supply growth ground to a halt, despite strong growth in unconventional liquids. Using the IEA as a benchmark for consensus estimates, 2011 non-OPEC output disappointed to the tune of 0.5 mb/d in Q1, 1.2 mb/d in Q2, 0.9 mb/d in Q3 and 0.6 mb/d in Q4 compared with the prediction put out a month before the start of each quarter. For the year as a whole, non-OPEC supply has come in almost 1 mb/d lower than the forecasts put out by the IEA as late as the middle of the year. The underperformance of non-OPEC supply was not confined to the North Sea, but ranged from technical issues in Brazil and Azerbaijan to aggravating decline rates in China. Further, unforeseen events such as fires in Canada, strikes in Kazakhstan and geopolitical outages in Yemen and Syria added to the woes. The only bright spot last year was the US, where the momentum in oil shales continued to tick higher, helping offset some of the weakness from the rest of the world. Exactly a year ago, our prediction for non-OPEC supply growth was -0.06 mb/d. Today, after an earlier ride up and then down again, it stands just a sliver different at -0.01 mb/d.

The consensus view would be for a marked improvement in non-OPEC supply prospects this year, following a plethora of geopolitical or unforeseen technical glitches to output in 2011. The extent of the upturn is slightly more varied than demand, with our expectation of about 0.33 mb/d growth in non-OPEC supplies at the lower end of the range, where the average expectation is for growth to be 0.7-1 mb/d. The disagreements centre on the rest of non-OPEC (ie, outside the Americas), primarily the North Sea and the FSU. Our expectation is for North Sea output to remain weak, as decline rates remain high, falling 0.16 mb/d in 2012, following a 0.33 mb/d decline in 2011. For the FSU, we expect Russian output growth to flat line as the initial upsurge from new fields comes to an end.

2011: A very poor year for non-OPEC supply;

will 2012 be any better?

Figure 7: Non-OPEC supply forecasts for 2011 Figure 8: Non-OPEC supply growth, y/y change, mb/d

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Source: EIA, IEA, OPEC Secretariat, Barclays Capital Source: EIA, Barclays Capital


1 March 2012 25

Among the positives, few would disagree that increased drilling, sustained investment and improved reservoir management technologies in the Americas should continue this year, although the extent of optimism continues to vary widely. We expect oil shales to be the key driver, although some recovery in Gulf of Mexico production can also be expected, given that the after-effects of the Macondo spill have now cleared completely, and new drilling, albeit under a far more stringent regulatory environment, has begun. However, challenging topographies, old fields with high decline rates and difficult political regimes are very much still a part of the non-OPEC supply profile. While posing some stirring prospects following almost a decade of dismal performance by non-OPEC supply, oil shales alone are simply not enough to offset the decline in other parts of non-OPEC and meet all the incremental demand growth. The scale of growth in US output really needs to be put into perspective. Does shale oil help the US reduce its dependence on foreign oil? Yes, it does, but we are not talking about the US turning into a net exporter of oil. In fact, the EIA, in its latest Annual Domestic Energy Outlook, expects the US to increase its oil output 1.2 mb/d, to 6.7 mb/d, by 2020 and reduce required imports from 9 mb/d to 7 mb/d by 2030. Does the US shale oil boom help offset the steady decline in non-OPEC supply last decade? Partially so: together with growth in non-conventional and deepwater oil supplies at higher prices, it does offer some serious growth potential. However, shales by themselves are not necessary or sufficient to ensure positive non-OPEC supply growth every year, as was evident in 2011. Finally, to put some perspective on a global scale, the EIA’s expectation of 1.2 mb/d growth in US oil production over the next ten years translates into an average growth rate of 0.12 mb/d. We are more optimistic, expecting the growth in shale oil output to average 0.2-0.25 mb/d. Contrast that to our expectation of Chinese oil demand growth over the next decade at an annual average pace about 0.7 mb/d, and the conclusions are very clear: oil shales represent an exciting proposition for the US domestic market, but have yet to become a marginal barrel of supply (or oversupply) in the global market.

In summary, while the technological and geopolitical outages that severely curtailed non-OPEC supply growth are unlikely to repeat this year, there may be some downside risk to key agency forecasts of non-OPEC supply growth for 2012, as it would be too early to assume smooth sailing. With political problems in Sudan and the FSU persisting and Yemeni pipelines remaining offline, underperformance in non-OPEC supply growth is not necessarily behind us just yet. We expect non-OPEC supply to continue to disappoint (relative to demand), although the scale of that disappointment may be less than last year. Indeed, the relative dearth of new projects from 2011 feeding into this year leads us to expect actual performance to be worse than the key agency forecasts.

OPEC supply and spare capacity The Middle East changed dramatically last year. One aspect of that is producer price objectives have increased and become more urgent. To give but one example, Saudi Arabia’s oil minister Ali Naimi recently stated that the kingdom was looking to “stabilise” oil prices “around $100”. While it is by no means an official target, nor does it represent a floor for the market, there are clear oil policy implications when, as is the case now, prices are perceived as containing little or nothing in the way of rent for producers. In 2008, Saudi Arabia might have entertained the idea of allowing prices to move below their breakeven, then below $70, at least for a while, given the threat was of a significant world recession in which oil prices may have been perceived to have played some initial part. Providing a temporary boost and a potential kick-start for demand in major consuming economies had some attraction. We would consider it less likely now that Saudi Arabia will likely feel as willing to sacrifice the same amount of its revenues in response to a crisis clearly caused by the debt management policies of key consuming countries, especially when its own perception of its revenue needs has moved higher. Equally, despite what market chatter might often suggest, we do not expect Saudi Arabia to flood the market, allowing prices to

It’s US oil shales versus the rest

2012 non-OPEC supply prospects better than

2011, but only just

OPEC still requires high oil prices for breaking even on their budgets


1 March 2012 26

collapse and accepting revenues below breakeven prices just to create further difficulties for strategic rivals, especially when the call on its crude could easily rise dramatically as the spat between Iran and the West continues. In fact, after the experience of 2008-09, we would expect producers to pull together faster and more effectively, regardless of the often very poor state of their (non-oil) political relationships.

Thus, within OPEC, very little change in status quo is expected. Libyan volumes should continue to return to the market, with the potential to plateau at about 1.3 mb/d by late Q1/early Q2. To accommodate these volumes, ceteris paribus, some adjustments to the production allocation between member states must be made. In this regard, we continue to expect Saudi Arabia to act as swing producer at the margin. In the very short term, OPEC’s ability to rein in output to align the group’s total production to its desired target of 30 mb/d may come with a time lag, depending on the speed at which Libya returns to the market vis-à-vis the speed at which others cut back to accommodate those volumes. Currently, the m/m increase in OPEC output has topped out, although the group’s total remains about 1 mb/d higher than the target. While 100% compliance may prove elusive, we strongly believe that in terms of the primary holders of spare capacity, OPEC and its key producing countries do not wish to overproduce and pressure prices lower. The overall policy stance, while less cautious, has still not moved too far from remaining broadly price defensive, much like last year.

Even after a paring in estimates of oil demand growth, we still forecast a call on OPEC crude and inventories of 31.1 mb/d in 2012 (and 31.7 mb/d in H2). In 2012, the starting point is different because, thanks to the Libyan outage last year, almost 10 mb/d from Saudi Arabia does not represent a point of initial oversupply. Further, despite a counter-seasonal build in inventories in November, the demand pull from Asia and outages in non-OPEC supply have once again resulted in significant inventory drawdowns, with stocks now 60 mb below seasonal averages. Should any trimming be required at the margin, we believe OPEC has enough ammunition to do so. To justify a cut on the scale of what it made in 2008-09, H2 oil demand would have to be 3.5 mb/d lower than the current forecast. The macroeconomic concern is frustratingly low growth and more austerity, but not yet the sort of economic implosion that could produce a 3.5 mb/d decline in oil demand across all of H2. Thus, OPEC remains in control of the market and can keep prices within their desired range of about $100 per barrel, even in the face of slower global growth.

Figure 9: OPEC output, y/y change, mb/d Figure 10: OPEC spare capacity by country

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vs.realistic spare (brought online in 30 days and

sustained)

Source: EIA, IEA, MEES, Platts, Reuters, Bloomberg, Barclays Capital Source: Barclays Capital

Little change in OPEC policy, despite the return of Libya

OPEC in control of the market


1 March 2012 27

The key challenge for OPEC, in our view, is maintaining sufficient spare capacity despite growing adversities on the geopolitical front. We estimate current global spare capacity at close to 1.6 mb/d, as OPEC volumes remain at three-year highs. This points to a system that has extremely high utilisation rates (of 98%) and, hence, is prone to significant disruption should any of the cogs in its wheel malfunction. The issue is that these risks are indeed very high. Leaving geopolitical risks aside (more on that below), the potential for demand to surprise to the upside or non-OPEC supplies to surprise to the downside should not be discounted, as highlighted above. That leaves OPEC with very little wiggle room to ensure that oil prices do not spike higher. Should the group bring its output towards 30 mb/d, spare capacity would rise to about 3 mb/d, which, in our view, is still not sufficient to ensure a smooth year, given the heightened geopolitical risks and potential upside surprises from fundamentals. Thus, the back end of the oil curve looks increasingly cheap, given the large questions regarding where the next 5-10 mb/d of capacity will come from, the fragile political backdrop in Iraq, sanctions affecting Iran’s longer-term output profile and the decision by Saudi Arabia to stop investing beyond 12.5 mb/d of oil output capacity.

Geopolitics The current nature of geopolitics that are gripping oil market headlines are far from benign and are still the main upside risk to oil prices, in our view, although their focus has started to shift from the Arab world to Iran. For several years, we have stated our view that the Iran situation has been on a slow path towards some potentially non-benign outcomes; of late, the issue has become livelier in nature. However, while most outlooks seem to be concentrating on the most dire, and binary, aspects of the situation, particularly the consequences of a blockage of the Straits of Hormuz, we believe the more likely outcomes involve changes in trade and investment flows and political balances throughout the Middle East and could be more a matter of unforeseen consequences and potential political missteps.

Sanctions targeting Iran’s central bank and embargoes against its oil have sparked anger from the Iranians, who in turn may ban exporting oil to the EU itself. If Iran’s customer base narrowed and barrels were swapped (Iranian oil simply flowed into Asia and displaced oil went to Europe), then not much would be different beyond some changes in differentials. In that case, EU sanctions of Iranian oil would have little more effect than the previous US sanctions. Their importance would then be primarily political, changing oil trade flows and potentially resulting in some net withdrawal of oil from the market. So far, we estimate around 300-400 thousand b/d of Iranian exports to have come off the market, as European countries are starting to find alternative sources and even countries like India and China are facing payment constraints.

With the impacts of the sanctions likely to be get worse, with Iran potentially losing over 1 mb/d of exports resulting in rising floating storage off the coasts of Iran or currently Asia, the domestic Iranian economy is likely to suffer further. While some form of retaliatory measure, such as Iran banning exports to the UK and France, is widely expected, a highly likely scenario could involve the existing cold war becoming lukewarm, resulting in a series of proxy wars. In this context, Syria and Iraq may just be the thin edge of the wedge, without the lower-level confrontations necessarily spilling over in a wider and direct conflagration. In such a scenario, oil is likely to grind higher in line with the gradual escalation and non-resolution of the situation. While not a worst-case scenario, this is in reality immensely difficult for policymakers to deal with in terms of the oil market implications. Such a situation could last the rest of this year, into 2013 and even beyond. Under those circumstances, strategic stock releases might be difficult, in that there is the danger that the market might simply pause, absorb the oil and then just carry on, and all the time the remaining strategic reserve will be diminishing. In other words, if the situation

Spare capacity is still very low and to stay low, supporting

the back end of the curve

Iran is the currently centre of geopolitical risks

Remapping oil trade flows

Proxy wars and price spikes


1 March 2012 28

carries on for the foreseeable future, when do you start using your limited strategic reserve bullets? There is a limit as to how long the global oil industry can run quite as hot as it is running now; ultimately, it is likely to buy breathing space through higher prices and suppressing demand, which is of course precisely what policymakers do not want to happen. Throughout that scenario, the Straits of Hormuz might not have to play much of a role, bar the occasional rusty floating mine. Indeed, oil prices can easily tick up to $150 per barrel and beyond in this scenario without any disturbance at all to the passage of oil through Hormuz.

Given 1.6 mb/d of spare capacity, had Iran been the only risk on the horizon, one could argue that there was just about enough excess in the system to absorb the outage (although only by pushing spare capacity to critically low levels, which in itself is highly supportive for prices). The problem for the oil market is that the list of risks is very long. Iraq, which is likely to be another hot spot in 2012, especially with the withdrawal of US troops, is suffering from a fairly straightforward Sunni-Shia division, and violence around oil installations has already increased this year. The geological potential of Iraq is immense, but by that measure, Iraq should probably be producing more than 10 mb/d currently. When put in the context of wider political, institutional and infrastructural constraints, not only does our initial target of 4.5 mb/d by 2015 (by far the most pessimistic forecast made in 2008) seem overly optimistic, but Iraq’s ability to reach such a level even by 2020 is doubtful.

Finally, the sharp increase in violence in Nigeria, which has by and large kept oil facilities unscathed, is slowly but surely changing. Oil spills and force majeures resulting from sabotages are on the rise again and could be a key feature of 2012, while the general backdrop of the country is alarming. Other geopolitical debates surrounding Sudan, Syria and Yemen are heating up and continue to affect oil output.

Effect on prices While the year started off with rather fat tail risks on either side, the possibility of a complete economic meltdown is diminishing fairly quickly, especially post the recent agreement on bailout package on Greece. Sentiment is improving, confidence is returning, and demand in key centres, particularly Asia, is already picking up. The risk of the sovereign debt problems turning into a credit crisis has not gone away entirely, but the probability of growth and oil demand surprising to the upside relative to consensus forecast and/or any combination of the geopolitical risks materialising is now higher, in our view. In particular, the escalating tensions about Iran are manifesting itself in a series of proxy wars, while a messy end-game is becoming increasingly likely. In our view, the cumulative level of concern about reduced supply capacity, and the likely sustained downward pressure on already thin global inventories, mean that price responses above $120 per barrel are becoming closer to a necessary mechanism for market clearance rather than a sign of market fear. Just over a year ago, before Libyan output went offstream, global spare capacity stood at some 4.1 mb/d. Total OECD inventories were around 40 mb above their five-year average, with inventories in Europe at their five-year average. Based on preliminary IEA figures, OECD inventories are now more than 65 mb below the five-average, with European stocks at a 15-year low. By providing coverage for incremental demand and supply shortfalls, the existence of a comfortable level of spare production capacity (and inventory) is, all else equal, a stabilising factor in the market. However, once that buffer starts to erode, the ability of the oil market to absorb supply shocks can reduce sharply, with the opposite effect on price volatility and market sentiment. Thus, in our view, except in the wake of some fairly extreme events, $110 per barrel looks to be the most likely extent of any short-term downside. And for that to happen, all of the geopolitical risks would have to benignly disappear, which at the moment, looks most unlikely.

It is not just Iran: Iraq, Nigeria and other hotspots still brewing

Prices: upside risk rising


1 March 2012 29

In the case of some dramatic dispersal or deferral of tensions, we would expect prices to find support at $100 per barrel at the very least, ie, at a level broadly consistent with incremental non-OPEC supply costs and with the budget requirements at current (recently sharply increased) levels within key producing countries. In reality, we suspect that there are too many large moving parts currently in motion for all the risks to disappear benignly at once. At this stage, the market may still be a headline or two away from a sharp spike higher, but it seems result that prices will continue to grind higher, post any near-term corrections, as the combination of extremely thin buffers and worsening geopolitical tensions comes together in a more sustained manner.


1 March 2012 30

GEOPOLITICS

Crossing the Rubicon There are new fears about the security of the Straits of Hormuz, as Iran and the West

appear to be engaged in a dangerous game of brinkmanship. We still contend that the risk of either an Israeli or a US strike on the Iranian nuclear facilities is low, but it has risen, in our view, from 5-10% last year to 25-30% now.

Violence has escalated in Iraq in the wake of the US troop departure and could imperil oil production if it continues or escalates. Prime Minister Maliki’s efforts to sideline his political rivals are adding to the anxiety about the country’s near-term trajectory.

Nigeria is also experiencing a new wave of unrest that is deepening the country’s regional and religious divide and prompting comparisons to the run-up to the devastating 1967-70 Civil War.

New storm clouds appear to be brewing for several of the oil market’s perennial problem children. Iran’s relations with the West have deteriorated sharply in recent months, prompting fresh fears about a military confrontation that would endanger the security of the Straits of Hormuz. Iraq and Nigeria have experienced new waves of violence that are testing those countries’ leaders, deepening sectarian divisions, and could eventually affect production. All eyes will be watching whether these countries manage to pull back from the brink of a major crisis, or if they have set themselves on a calamitous course for 2012.

The Iranian nuclear issue was seemingly sidelined for much of 2011 as the world was riveted by the events of the Arab Spring, but it returned to centre stage as one of the key political risks in the oil markets in the autumn. In October, US Attorney General Eric Holder charged that senior officials in the Iranian Revolutionary Guards Quds force were behind a foiled plot to assassinate the Saudi Ambassador to Washington by bombing a Georgetown restaurant popular with members of Congress and the diplomatic community. President Obama vowed that the US would ensure that the Iranian government would “pay the price” for its “reckless behavior”. In November, the International Atomic Energy Agency (IAEA) released its most alarming report to date on Iran’s nuclear programme, stating that it is increasingly concerned about possible undisclosed nuclear activities. The IAEA report goes into great detail, relying on a wide variety of sources to make a case that there is credible evidence that Iran is working on the critical technologies required to produce a deliverable weapon. Washington and the EU have responded by imposing stringent new sanctions on Tehran. The United States, the United Kingdom and Canada have banned transactions with the Iranian central bank, while the EU is finalizing the details of an embargo on Iranian oil. At the same time, there appears to be a stepped-up covert campaign to target key Iranian military sites and scientists working in the nuclear industry. Meanwhile, Israeli government officials have once again started dropping hints about launching a unilateral strike on the Iranian nuclear facilities. We believe that there is a heightened risk in 2012 that the Iranian leadership may come to believe that their backs are up against the wall, which could prompt them to engage in erratic behavior and lash out at their adversaries. Vali Nasr, an Iran expert at Tufts University and a former foreign policy advisor in the Obama administration, noted that “at some point sanctions become an act of war” and added, “If you cut Iran out of the oil market, this is no longer economic pressure” (New York Times, 5 December 2011). Similarly, Walter Posch, an Iran expert at the Berlin-based German Institute for International and Security Affairs, maintains that the proposed oil sanctions “will be interpreted by the Iranian government as a sign that the European Union is looking for regime change” (Die

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Will an easy off-ramp emerge for Iran, Iraq and Nigeria in 2012, or

will they continue down a dangerous path?

Risks are rising of a confrontation over the

Iranian nuclear programme


1 March 2012 31

Welt, 6 December, 2011). The ransacking of the British embassy in Tehran in December may be a sign of increasing discontent with the punitive measures. Members of the Iranian leadership have made repeated threats to close the Straits of Hormuz in retaliation to the new sanctions. Such threats for now seem largely hollow. The US Fifth Fleet in Bahrain would likely be able to keep the Straits open in the event of a military confrontation. In addition, it is far from obvious that Tehran would casually opt for a strategy that would prevent it from being able to export crude oil or obtain vital imports. Nonetheless, we think the Iranian leadership will probably ratchet up its anti-Western rhetoric and military exercises to keep oil prices elevated and to ensure a reliable revenue stream. We also fear that these activities run the risk of triggering an unintended escalation through miscalculation. For example, we cannot rule out the possibility that Iran might selectively stop and inspect ships travelling through the Straits, a move that could certainly create a broader crisis. We still contend that the risk of either an Israeli or US strike on Iranian nuclear facilities is low, but it has risen, in our view, from 5-10% last year to 25-30% now.

in Iraq, the security outlook has darkened since the US troop departure in December. Hundreds of people have been killed in a wave of attacks that seem designed to reignite sectarian strife. In January, 64 Shiite pilgrims were killed in an explosion in the southern oil-hub Basra. The blast went off in a tent where the pilgrims were gathering to travel to a mosque in Zubair for the last day of Arbaeen, one of the holiest Shiite holidays. In late December, a series of coordinated bombings in predominantly Shiite districts in Baghdad left 72 people dead. The recent violence brings to memory the 2006 bombing of the al-Askari Mosque in Samarra, which sparked a wave of sectarian bloodletting and set the stage for the civil war. The latest unrest has not triggered retaliatory attacks on Sunnis to date, and the Maliki government has repeatedly urged restraint in the wake of the rising violence. Nonetheless, there are mounting fears that if the attacks continue or escalate, they could inflame sectarian tensions and trigger serious civil unrest. In addition, an increase in violence could imperil Iraq’s oil output. The first direct attack on a foreign oil company operating in Iraq occurred in January. According to the Iraq Oil Report, unknown assailants wearing military uniforms bombed a storage facility belonging to the Canadian exploration firm Terraseis, which is conducting work on Sonangol’s Najmah oilfield project near Mosul. No one was hurt, but several trucks used for conducting seismic drilling were badly damaged. In December, assailants bombed the Rumaila pipeline network, temporarily taking 700,000 bpd of production offline. The political picture in Iraq has also become more problematic in the wake of the US withdrawal. Prime Minister Maliki, who leads a largely Shiite government that enjoys warm relations with Iran, has opted to play hardball with his political rivals. He issued an arrest warrant for the Sunni Vice President Tariq al-Hashimi less than 24 hours after the US formally ended its mission in Iraq. Hashimi, one of the leaders of the Iraqiya party, stands accused of ordering the assassinations of his adversaries and has subsequently fled to the semi-autonomous Kurdish region. Maliki has also tried to have the Sunni speaker of parliament removed from his post after he called the prime minister a dictator. In addition, Iraqi authorities have arrested the deputy chief of the Baghdad provincial council and a senior member of the largely Sunni Iraqiya party, on charges of funding insurgent groups. A key concern is that members of Iraq’s Sunni community will become embittered by the treatment of their political leaders and will once again resort to violence.

The risks of severe political instability are also rising in Nigeria, with the spate of deadly bombings in the North showing no signs of subsiding. In January, nearly 200 people were killed in a series of shootings and car bombings in Kano, Nigeria’s second-largest city. The shadowy Islamist group Boko Haram has claimed responsibility for this and many other

Deadly unrest and dangerous political infighting follow US

troop departure in Iraq

Boko Haram is imperiling Nigerian national unity


1 March 2012 32

recent attacks, including a Christmas Day church bombing in the capital, Abuja, which left 40 people dead. A clear concern is that the latest violence will deepen regional and religious divisions in the country and prompt reprisal attacks on Muslims in southern Nigeria. President Goodluck Jonathan has warned that that the current violence is worse than the 1967-1970 Civil War, noting, “During the civil war, we knew and we could predict where the enemy was coming from…But the challenge we have today is more complicated” (This Day, 9 January, 2012). Part of the problem for the government is that the group has no clear command and control structure, and multiple groups – including some criminal elements – appear to be operating under the Boko Haram banner. Boko Haram, which rails against Western education and has called for the adoption of Sharia law in all of Nigeria’s 36 states, rose to prominence in summer 2009. Clashes between its followers and security officials, following the killing of the group’s charismatic leader by the police, left more than 700 people dead. Since then, it has engaged in a steady stream of attacks on public officials and religious leaders, usually by masked assailants on motor bikes. Boko Haram may be tapping into the general unhappiness with the outcome of the April elections in the north and the growing sense of political alienation in the region. The elections were very polarizing along regional and religious lines. Many in the north were deeply unhappy about Jonathan’s decision to seek a full term in office, as it violated the 1999 agreement to rotate the presidency between the Muslim north and Christian south every eight years. Although many in the south, especially in Jonathan’s home base in the oil region, were elated with the election results, they were greeted with significant violence in the north, where post-election rioting left more than 800 people dead and 65,000 displaced, according to Human Rights Watch. John Campbell, the Senior Africa Fellow at the Council on Foreign Relations and the former US Ambassador to Nigeria, maintains that Boko Haram represents “an indigenous, grassroots insurrection against a discredited Abuja government and against the traditional Northern Nigerian Islamic establishment” and warns that the Nigerian government is failing to address the deep-seated grievances that underpin support for the group. Oil production could eventually be affected if there is a wider political and security breakdown in Nigeria.


1 March 2012 33

OIL PRODUCTS

Refinery closures: Too little too late? OECD refinery closures have gained momentum, but any support to margins is likely

to be short-lived given the plethora of capacity additions in the non-OECD. We expect an overcapacity of almost 2 mb/d by the end of this year.

We expect light-heavy crude differentials to get compressed over the coming years, as the crude slate gets increasingly lighter, while refinery upgrades have focused on processing heavier grades.

Fuel oil balances are getting increasingly constructive as Japanese nuclear plant closures boost demand, while the ongoing refinery upgrades limit supplies and the new tax system in the biggest supplier disincentivises its production.

Marred by high crude oil prices and lower margins, closure of simple OECD refineries has finally started to gain some traction. Almost 1 mb/d of refining capacity is going to be lost in the US by the middle of this year, while the bankruptcy of Petroplus takes out further European capacity. While refining margins globally have received a significant boost from this transformation, we do not believe the strength will last. Seasonal uptick aside, and beyond a large-scale loss of refining capacity, global margins are likely to track historical averages. There is enough capacity globally (current and scheduled) to meet incremental product demand growth and, in our view, any strength beyond that seasonality should be sold into. Overall, though the OECD refinery closures have gathered pace, they remain small relative to the refinery additions in the non-OECD. Indeed, after adjusting for these closures, net capacity addition in 2011 and 2012 is a combined 4 mb/d, resulting in an overcapacity of almost 2 mb/d by the end of the year. Indeed, it may take many years for downstream excess to be burned up fully. In our view, the diagnosis is still of a crude-led market extending into the medium term, with rising crude price floors and potentially a need for some further burning up of demand to ration scarcer capacity.

Capacity additions are hefty and rising… Figure 11 summarises our estimates for net capacity additions by year and region, and includes all projects we believe could be realised and the refineries that have or will be mothballed. If, as we expect, margins stay relatively low, further refineries may be at risk of

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Almost 2 mb/d of refinery capacity is being shut down, but

still we see little upside to margins

Figure 11: Net refinery capacity additions, by region

kb/d 2010 2011 2012 2013 2014 2015+

China 1230 951 575 700 900 2783India 378 500 399 520 300 80North America 195 -469 -450 28 25 0Other Asia 423 340 500 520 1310 2180Africa 85 125 432 59 49 539ME 305 398 260 315 400 3045FSU 305 253 757 316 530 626Europe -301 -570 -389 0 60 214Latin America 65 152 403 326 165 1030Total 2685 1680 2487 2784 3739 10497

Note: 2012 North America includes Sunoco’s Philadelphia shut down, while Europe does not include the closure of Petroplus’ Coryton refinery, which we believe will remain operational. Source: Barclays Capital:

OECD refinery closures gaining momentum, taking away a

chunk of overcapacity


1 March 2012 34

closure and a few of the new projects could fall off the list. While the sudden raft of closures of US and European refineries has injected some life into the otherwise ailing downstream sector, total capacity additions into the middle of the decade still look rather large.

While we find that the capacity expansion profile has been significantly truncated since our previous survey due to the recent announcements of refinery closures, the process has not yet gone far enough. Strong demand for crude in China and India is one of the key positive factors for the upstream over the next five years. However, aggressive refinery expansions plans in the same countries are key negative factors for downstream margins. Even assuming that all of the announced closure of nameplate capacity in the OECD is removed from the market permanently (ie, no buyers are found, etc), this is still a bumper year for capacity additions from Asia and the FSU, with our Barclays Capital Refining Database pointing to a record number of additions globally (see Barclays Capital big book on refining: Still unbalanced, 16 May 2011). Even the OECD is adding a significant tranche of new capacity this year. Capacity additions only get worse beyond 2012, as the Middle East and Latin America are set to bring online large refineries. Spare crude output capacity started the downswing at a very limited level, and has remained under OPEC’s effective control throughout the cycle. By contrast, spare distillation capacity started the cycle at higher levels, and has been further bolstered by lower demand and significant capacity increments.

… while the light-heavy spreads narrow Challenges for refineries do not simply end with mere capacity additions. They also have the challenge of adapting to a rapidly changing crude slate. Significant transformations in crude quality are already taking place with the depletion of conventional oil resources and the increasing importance of non-conventional oils in global production. Over the past decade, with large existing reservoirs depleting, the production share of extra-heavy oils was expected to grow, mostly with the development of oil sands and extra-heavy oil projects in Canada and Venezuela, respectively. However, with the commercialisation of oil shales and the growth of non- conventional extra-light crudes, such as gas-related liquids, the slate is now getting lighter once again. For instance, the IEA expect OPEC NGLs to rise by 1.6 mb/d by 2016 to 7.4 mb/d, US NGLs to grow by 0.6 mb/d to 2.7 mb/d over the same time period and oil shales to be 1 mb/d higher in 2016 compared with now, thereby making the incremental barrel lighter. This comes at a time when global upgrading capacity and installation of coker units are at a record high and refineries around the world have invested

However, any support to margins is likely to be temporary, given large non-OECD additions

The crude slate is getting lighter at a time when refineries are

installing cokers

Figure 12: Light-heavy crude oil differentials

Figure 13: Growth in global NGL output

(Maya - LLS, $/bbl)

-30

-24

-18

-12

-6

0

05 06 08 10 12

(y/y change, thousand b/d)

-100

0

100

200

300

400

2008 2009 2010 2011

North America

Middle East

Source: Bloomberg, Barclays Capital Source: EIA, Barclays Capital




1 March 2012 35

heavily to process heavy-sour grades. Incremental refining coming online favours heavy crude too, given the complexity of the Asian refineries coming onstream and in particular the large Middle Eastern refineries all biased towards processing heavy crude. The combination of the incremental crude barrel getting lighter and the marginal refinery preferring heavier slates is likely to create a significant compression in light-heavy differentials over the coming years, in our view, rendering a lot of the large capital investments undertaken by refineries to upgrade rather futile.

The regional divergence is worse, with the lighter barrels increasing in North America and the Middle East, both regions in which investment to process heavy crude in refineries is on the rise. European crude slate is set to get heavier and contain more sulphur, as more Urals and African crude is blended into the North Sea liquids, while a large number of refineries in North West Europe are still configured to process the light sweet North Sea crude, with little capital outlay to invest in conversion and hydro-treatment to process heavier, sourer crudes. Worse still, Europe remains significantly short of distillates, a trend that is likely to worsen as the crude slate gets heavier, making it costlier to process the middle distillates.

Regional breakdown The global refining landscape is undergoing a much-needed transformation as it accommodates a prolonged period of lacklustre margins through rapid closures and idling in the OECD. The current system has too many refineries in the wrong places producing the wrong fuels. That is, there are too many refineries in North America and Europe, where demand is falling, producing too much gasoline and in some cases fuel oil, and not enough distillates, which is the marginal barrel of incremental consumption, globally. Thus, while the demand centres of Asia, Middle East and Latin America continue to build sophisticated refineries to feed growing domestic demand, OECD refineries are finally starting to close. While the momentum is gaining, we believe there is still a long way to go for rationalisation on a global basis, as we envisage a staggered path of closures for OECD refineries, home usually to thousands of workers and often the centre around which townships are built. However, with oil majors increasingly moving away from the integrated model, the refining business is no longer shielded by the umbrella of upstream profitability, and thus should incentivise a quicker timeline for closures of non-profitable refining capacity.

US

In the US, a diverse set of outcomes has emerged. US East Coast (PADD 1) refineries have failed to benefit from the cheaper and dislocated US crude, WTI or, for that matter, the cheaper heavy and sour crude imports from Canada. Rivals in the Midwest (PADD 2) have benefited from cheap Canadian and North Dakota crudes trapped by the lack of export pipelines, while refiners on the US Gulf Coast (PADD 3) have larger and more complex facilities capable of buying heavy sour crudes and processing them into a higher share of valuable gasoline and distillate. Indeed, as US PADD 1 refineries across 2011 had an average gross margin of about $4.8 per barrel (ie, negative margins once operating costs are included), US Midwest refineries enjoyed near-record margins of $22.25 per barrel and US Gulf Coast refineries just under $19 per barrel.

Not surprisingly then, East Coast refiners’ margins have been under pressure as they struggle with old facilities, lack of complexity, rising product specifications, and fierce competition from Europe for both crudes to process and share in the gasoline market. In 2007, East Coast refiners paid on average about $4.50 per barrel above the national average. By June 2011, East Coast refiners were paying almost $11 above the national average, more than $17 above the Midwest and $9 above the Gulf Coast. With the margin situation worsening in the latter half of 2011, capacity reduction gathered pace.

US slate is getting lighter and Europe heavier

Too many refineries in the wrong places producing

the wrong fuel…


1 March 2012 36

2011’s capacity reductions across the US totalled 559 thousand b/d, of which PADD 1 was a large 449 thousand b/d, with Sunoco’s Philadelphia refinery (330 thousand b/d) joining that list in 2012. The recent closure of the 550 thousand b/d Hovensa refinery in the US Virgin Islands, together with the already announced closures of Hess and reduced runs at United Refining’s refineries (combined capacity 140 thousand b/d), does help to rationalise a significant portion of US refining capacity. Valero’s 235 thousand b/d Aruba refinery, which is currently operating at 50% utilisation, could face a similar fortune this year, in our view.

Yet the geographical bias in refining fortunes, as well as expectations surrounding the future stream of crude grade/quality, has meant that closures are limited to the East Coast and the Caribbean, while new distillation and expansion capacity is being brought online in the other regions. The most prominent here is the 325 thousand b/d expansion plan of Motiva’s refinery in Port Arthur (PADD 3) scheduled to be completed in Q2 12. Other expansion plans total a small 69 thousand b/d, with expansions and upgrades at BP’s Whiting refinery and Valero’s Port Arthur facility accounting for the bulk of it. For 2013 and 2014, expansion plans are limited, totalling less than 30 thousand b/d in each year.

With plentiful availability of cheaper alternatives in the North, the lack of sufficient pipeline takeaway capacity from Cushing and greater pipeline access into Cushing, WTI is likely to remain dislocated, creating a strong margin environment for Midwest refineries. We expect refinery runs and margins to remain high in this region until a pipeline start-up from Cushing helps to change perception about WTI.

While Gulf Coast refineries are undergoing a significant amount of upgrading capacity with establishment of new coker capacity, our view of a compression in light-heavy spreads could pose some problems for profitability. The abundance of light, sweet crude and NGLs in the Eagle Ford, together with light crude brought by rail from Bakken, is surging at a time when Gulf Coast refineries have spent millions on upgrading capacity. Eagle Ford shale oil is being moved to Corpus Christi and Houston by rail and pipeline, with more capacity coming on stream this year. Bakken shale oil, too, is blended into Canadian and US midcontinent crude streams, and is being railed down to St James, Louisiana. Just a few years ago, the marginal barrel was getting heavier led by Canada and Venezuela; with Canadian exports to the US increasing, these refineries invested in upgrading capacity to

Figure 14: US gross refining margins, $/bbl

Figure 15: US upgrading vs distillation capacity

US Northeast

Brent US Midwest

WTI US Gulf Coast

WTS

PADD 1 PADD 2 PADD 3

Q1 11 $4.75 $18.78 $14.71

Q2 11 $4.72 $26.26 $19.41

Q3 11 $5.03 $28.18 $26.38

Q4 11 $4.80 $15.78 $15.11

2011 $4.83 $22.25 $18.90

Q1 12 $8.63 $21.51 $18.76

-100

-50

0

50

100

150

200

250

300

350

400

2011 2012 2013 2014

Distillation

Upgrading

Desulphurisation

North American refining capacity additions, kb/d

Source: Barclays Capital Source: IEA, Barclays Capital


1 March 2012 37

take advantage of cheaper heavy crude. Since then, not only has the boom in shale oil altered the API gravity and sulphur content of the marginal barrel, but the problem in establishing pipelines from Canada to the Gulf Coast (Keystone XL) could deprive the region of heavier Canadian crude as well. Thus, with a compression in light-heavy spreads, the profitability of these refineries may be put into question in the coming years.

Europe

Europe faces the most challenging environment, with refineries biased towards producing gasoline, demand for which is declining in the OECD and the existing refinery base is comprised of extremely simple, unsophisticated refineries in which margins have been dented severely in a strong crude oil price environment. This is made worse by the poor state of finance at European refineries, which has limited investment in upgrading capacity, at a time when light-sweet crude is proving dear in the region (lost Libyan crude last year, unrest in Nigeria, structural decline in North Sea output). Indeed, Europe’s crude slate is changing counter to that of the US. Crude imports, on average, are likely to become of a slightly heavier grade and contain more sulphur, as more Urals and African crude is blended into North Sea liquids. Thus, capacity reductions are the greatest among any region with a total of 1.34 mb/d of refining capacity rationalised (7% of total capacity), compared with 1 mb/d in the US (5% of total capacity). Given the economics, more European closures are required to balance the market; however, the stubbornness of European labour laws is likely to impede this process, with companies filing for bankruptcies one of the only few ways out.

FSU

Several refinery projects are coming online in Russia in 2012, upgrading 531 thousand b/d and new capacity of 226 thousand b/d, in addition to the 253 thousand b/d in capacity added in 2011. Despite these refineries being outdated, very few closures are expected in 2012 as domestic demand remains robust and with the addition of hydrocrackers, Russian refineries will be able to target diesel starved Europe as a highly lucrative destination for their output. With the speeding up in hydrocracker projects, involving the construction of 57 new processing units, fuel oil availability can be curtailed sharply as a result, especially given that Russia is the world’s largest supplier of fuel oil.

Figure 16: European oil products net trade

Figure 17: Europe’s changing crude slate

mt, 6mma

-0.4

-0.3

-0.2

-0.1

0.0

0.1

0.2

0.3

0.4

00 01 02 03 04 05 06 07 08 09 10 11

Motor Gasoline

Gas/Diesel Oil

0

0.2

0.4

0.6

0.8

1

1.2

1.4

30 32 34 36 38 40

Urals

Brent

API (degrees)

Sulfu

r co

nten

t (%

)

2010

2020

Source: FGE, Barclays Capital Source: Barclays Capital


1 March 2012 38

India

Indian refining capacity has expanded substantially over the years, becoming not only self sufficient in refined products for its domestic consumption but also a key player in the product export market. Total refining capacity in the country at the beginning of 2011 stood at 4.2 mb/d, with 2011 bringing additional capacity of 500 thousand b/d. In 2012, a further 400 thousand b/d of capacity is slated to come online.

Middle East

While home to the bulk of oil upstream, the Middle East has remained a large importer of refined products. This is set to change with some significant planned capacity additions slated to come online primarily after 2014. Saudi Aramco’s 400 thousand b/d Jubail refinery in 2014 and the 400 thousand b/d Ras Tanura facility in 2015 are set to transform the refining landscape in Saudi Arabia, while UAE’s Ruwais refinery will add another 417 thousand b/d in 2015. The doubling of capacity at the Qatari condensate splitter at Ras Laffan will add further volumes in 2015. The current project pipeline in the region suggests an expansion of 1.4 mb/d by 2015 and a further 2.5 mb/d thereafter. The volume and quality of local refining capacity coming online in the Middle East is closely matching the planned additions to incremental crude capacity. As a result, in the post-2014 period, the bulk of heavy-sour grades could be used domestically. Of course, this adds further to the woes of refineries around the world that have invested heavily to process heavy-sour grades, with a knock-on effect on heavy-light differentials.

Latin America

Latin America mirrors the Middle East in terms of a rapidly growing domestic demand market but insufficient refinery capacity. Though Latin American product demand should remain satiated by imports from US refineries (providing the latter with a lucrative outlet), trade volumes are likely to diminish as refining capacity gets added. Several small projects totalling 143 thousand b/d came online in 2011, while this year a larger 400 thousand b/d is scheduled (with Petrobras’ Abre e Lima 230 thousand b/d refinery contributing the most). The current project pipeline indicates an additional 1.4 mb/d of capacity by 2018, but we doubt this would result in self-sufficiency, given the expected rate of demand growth in the region.

China

China was the key driver of the strong refining capacity growth over the past few years. Gross capacity additions exceeded 1 mb/d in both 2009 and 2010, while 2011 brought online a further 700 thousand b/d of capacity, driving 40-50% of overall expansions worldwide. 2012 capacity is now expected to increase 550 thousand b/d, with another 700 thousand b/d in 2013.

A key element to China’s refining landscape is its fuel pricing reform. Even with the recent hike in retail prices, Sinopec has guided that a further fuel price hike is required for its refining business to break even this year based on the current oil price and may require gasoline and diesel price ceilings of c.RMB9600/tonne and c.RMB8800/tonne, respectively. Should a new pricing policy be implemented in China, this would stimulate oil product supply with higher plant utilisations and may result in lower refining margins within Asia. Further, power shortages notwithstanding, diesel shortages, which were widespread last year, are unlikely to arise largely due to the recent pricing changes. Heavy maintenance and run cuts by refineries facing steeply negative margins tightened the domestic diesel balance since end-Q3 11, which, with higher domestic retail prices, should be reversed. Should the price increases continue, together with new refining capacity coming online, China is unlikely to be a sustained diesel importer.


1 March 2012 39

Outlook on products

With the regional imbalances in incremental refining capacity and product demand discussed above, the key question for 2012 will be whether the divergence between gasoline and diesel, which has been so stark over the past few years, is set to continue. While we expect global appetite for distillates to remain strong and steady given the bias from structural elements and geographical mismatches with regard to refinery capacity (Europe in particular), there are some significant changes taking place to the RBOB gasoline market on the supply side, which could propel prices higher in the summer. For the bottom of the barrel, the key development last year was the Fukushima earthquake, which eventually drove stronger demand from Japan towards the end of the year, while the steady upgrading of refineries, especially in Russia, changed the supply landscape significantly.

Distillates Demand

Record high appetite for diesel has supported global oil demand despite macroeconomic adversities prevailing through much of 2011, a trend we expect to persist in 2012.

Chinese diesel demand is expected to be well supported through robust volumes in road transport and rail activity, as well as its continued reliance among heavy industries and the manufacturing sector. The usage of diesel-fuelled power generators – both as back-up by industry in light of the regular blackouts experienced and as a result of the general inadequate power infrastructure coverage in rural areas in particular – remains an ongoing theme in the country.

In India, diesel accounts for more than 70% of road fuel use owing to the intensity of truck and bus fuel consumption. Further, a trend that started in H2 11 with the increasing penetration of diesel within the passenger car segment is set to gain traction in 2012, given that the current retail price discrepancy between gasoline (in line with international prices) and diesel (subsidised) has almost doubled. Given the politically sensitive nature of increasing diesel prices, we do not expect a change in government policy in this regard in the near future.

Middle Eastern demand for distillates is expected to remain healthy while getting added support from seasonal swings, especially in power generation where distillates (in particular gasoil) is increasingly being used to meet fuel requirements. Indeed, much of

The vast divergence between gasoline and diesel – will it

last in 2012?

Distillate demand at record levels in 2011

Figure 18: US rail and diesel demand has been steady

Figure 19: Chinese freight indicators holding up well

3.3

3.5

3.7

3.9

4.1

4.3

4.5

06 07 08 09 10 11 12400

420

440

460

480

500

520

540

560

580

600Diesel demand, mb/d, LHSRail freight index, thousands, RHS

-10%

-5%

0%

5%

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15%

20%

25%

30%

07 08 09 10 11

Total freight

Railways

Highways

Source: Bloomberg, EIA, Barclays Capital Source: NBS, Barclays Capital


1 March 2012 40

the base load, as well as the seasonal variation, in power generation demand is now increasingly being met by distillate, likely supplemented by small amounts of condensate.

Latin American diesel demand is expected to continue growing strongly in 2012, supported by rising road freight and GDP growth. A further layer of support may continue to arise from weather anomalies, with possible repercussions from La Nina (although currently forecast to be mild) already resulting in governments (eg, Chile) extending power rationing measures to April 2012, which in turn should boost the usage of small diesel-fired generators.

However, diesel demand is not just a non-OECD story.

In the US, we expect diesel demand to remain well supported this year as the goods inventory supply chain remains sparse, supporting truck movements. Further, with significant additions made to rail capacity to transport crude from North Dakota and other booming oil shale areas to the Gulf Coast next year, diesel demand should continue to derive strength from it.

While the strength of economic activity remains a large question mark in 2012, with most forecasts pointing to poor economic activity (bearish for diesel demand), albeit counterintuitive, Europe’s dependence on diesel imports is only set to increase further in 2012. On the one hand, Europe’s car fleet remains heavily biased towards diesel, despite price incentives having finally swung back in favour of gasoline, while on the other hand, Europe’s refineries remain biased towards gasoline. As a result, Europe has had to continually source larger volumes of diesel, from ever further away, even as outright oil consumption has declined.

Supply

With global overcapacity in refining and strong crude prices set to keep margins weak, further refinery closures, particularly in Europe, cannot be ruled out, especially given the simple nature of these refineries. In general, European refineries remain disadvantaged, continuing to use oil linked to products for its own use compared with natural gas used by the US refineries. Thus, while we do not see a repeat of 2008’s diesel shortages, owing to the large additions to the global refining complex, we continue to see frictions between supply and demand, particularly in regions such as Europe, supporting diesel prices during peak-demand seasons.

However, some of the acute shortages seen in the distillate market over 2011 have started to ease and should provide for weaker distillate cracks in 2012, in our view. Chinese refinery runs have ramped up, alongside the return of a few key Asian refineries that were closed temporarily last year due to unforeseen events like fires and explosions, which should make for further availability of distillates. The return of Libyan barrels, too, should help in restoring some of the lost European runs, although margins in the region remain rather pitiful. In the absence of unforeseen events (such as refinery fires, loss of diesel-rich light sweet crude, etc) curtailing supplies, the extreme tightness in distillate markets in 2011 should ease.

Gasoline Demand

Gasoline demand was the Achilles heel of global oil demand in 2011, given its bias towards the OECD, and in particular in the US. US gasoline demand fell by a large 4% y/y in the driving season and 2.6% in 2011 as a whole, with the weakness predominantly caused by higher prices and, to a certain extent, weaker GDP. Further, an abundance of naphtha,

Refineries well endowed to produce diesel

In the short run, warm weather caps diesel prices

Gasoline demand in the OECD is very weak, strong in non-OECD


1 March 2012 41

together with a refining complex geared far more towards producing gasoline than distillates globally, means gasoline balances have looked heavy for most of 2011, which remains the case at least in the short term. Non-OECD gasoline demand remained strong, with Brazil, China and India the key demand centres. However, given the still relatively low base of gasoline consumption in these countries, the US remains the key for determining the outlook on gasoline.

For 2012, we believe that US gasoline is unlikely to deteriorate much further, with an improving economy likely to even provide a small boost in demand. Further, we expect Latin American gasoline demand to remain strong in 2012, a key factor that keeps not only global but in particular US gasoline demand (through exports) buoyant. Mexico in particular has shown increasing dependence on US gasoline imports owing to combination of a poor refining sector and a rising middle class with higher incomes offsets effects from the recent reduction in gasoline subsidies. A similar story can be traced in Latin America. Brazilian gasoline demand is also likely to remain supportive for the US gasoline market in 2012. In 2011, together with rising incomes and auto sales, the continued tightness in the ethanol market has meant that conventional gasoline accounts for a higher proportion of this incremental demand.

Supply

Gasoline supply balances are expected to be impacted by a number of refinery closures as well as the availability of naphtha.

Refinery closures

In response to weak demand for gasoline and other refined products, higher crude prices and weak refining margins, refinery operators in the OECD in general have been cutting back capacity, idling, and in a few cases permanently closing their gasoline biased simple refineries.

The shutdowns in PADD 1 have been coming thick and fast. and the available refining capacity in the region is likely to be greatly diminished by mid-late 2012 and is likely to provide support to RBOB futures (delivered in this region). Further, the closure of the Petroplus refineries and the St Croix (0.55 mb/d) closure will add to supply woes for RBOB gasoline. This is not to say that there will be an outright shortage of gasoline globally. Quite the contrary – there is still enough gasoline biased refineries around. However, infrastructural constraints are likely to constraint RBOB. While Europe could easily ramp up

Figure 20: Refining closures in PADD 1

Figure 21: Gasoline demand reacts strongly to price changes

0.0

0.3

0.6

0.9

1.2

1.5

1.8

2011 2012 2013

Capacity

Operating

PADD 1 refining, mb/d, as at the start of the year y/y change

-60%

-40%

-20%

0%

20%

40%

60%

Dec-08 Jun-09 Dec-09 Jun-10 Dec-10 Jun-11 Dec-11-6%

-4%

-2%

0%

2%

4%

6%

Gasoline prices

Gasoline demand

Source: Barclays Capital Source: EIA, Barclays Capital

Latam gasoline demand set to stay strong

Gasoline capacity being reduced, especially in US PADD 1


1 March 2012 42

production if gasoline exports are needed, gasoline prices will have to increase to encourage higher production. As a result, we continue to favour summer RBOB gasoline spreads, long August-September RBOB spreads.

There are further considerations in the gasoline story than the simple elements of supply and demand. Naphtha plays a very important role, required for blending into finished gasoline. In 2011, a weakening petrochemical sector backed off a significant amount of naphtha (used as feedstock especially in Asia), which weakened the gasoline balance by blending into it. In our view, with the Chinese government starting to embark on an expansionary policy once again, alongside the first signs that petrochemical and plastics prices have started to stabilise, the petrochemical sector should fare better this year. This should add an additional layer of tightness to gasoline later this year.

Fuel oil Demand

In the fuel oil markets, supply-side pressures were building up right from the beginning, in the form of refinery upgrades, closure of simple refineries and the passing of a Russian legislation discouraging production of low-end products. These reductions did not trigger a panic alarm as demand for fuel oil was expected to slumber given natural gas started was grabbing a larger share of fuel oil’s pie in power generation, while wafer-thin and highly variable margins at teapot refineries meant their feedstock demand would be marginalised. The only positive for fuel oil was expected to come from the worries of the shipping industry, where bunker fuel oil requirements for the rapidly expanding fleet was an almost certain given the size of the orderbook and the requirement for the initial tank fill if not for an ongoing operational purpose (given the state of dry bulk trade). Further, the introduction of the global sulphur cap for marine fuel oil (reduced from 4.5% to 3.5%) with effect from January 2012 is likely to have positive implications.

As the year progressed, however, it turned out that not only was supply falling, but demand itself was getting amplified in the aftermath of the Japanese earthquake, where the shutdown of nuclear reactors resulted in fuel oil being used extensively for power generation. Japanese appetite for fuel oil continues to make further inroads as more of its nuclear reactors are scheduled to come offline this year. Over October 2011-March 2012,

Stronger naphtha in Asia in 2012 also positive for gasoline

New horizons for fuel oil

Figure 22: Inventories at Singapore have been drawn down Figure 23: Refinery upgrades are tightening the balance

Singapore Residual Oil Stocks (in mb)12

14

16

18

20

22

24

26

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

2011 2009 2010

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

2011 2012 2013 2014 2015 2016

Others North AmericaAsiaFSUMiddle East

Total upgrading capacity, IEA estimates, mb/d

Source: Bloomberg, Barclays Capital Source: IEA, Barclays Capital

Japanese demand supporting fuel oil


1 March 2012 43

Japan’s crude and fuel oil demand for power generation is estimated to be 0.41 mb/d. With only two of the 54 nuclear plants in operation, Japanese LSFO demand for power generation will likely be amplified before it moderates.

Supply

On the supply side, the long-running push to reconfigure refineries globally, particularly by installing cokers to maximise the production of light ends, is coming at the expense of fuel oil output. Around 0.2 mb/d of fuel oil output cuts took place by the end of 2011 in the US alone, and a further 0.11 mb/d is expected this year, with further reductions on average of 0.75 mb/d expected each from Spanish and Indian refineries. The greatest change, nonetheless, is taking place in Russia. Russian refineries currently yield close to 30% fuel oil given the predominantly simple state, and given the limited use domestically, it makes available more than 80% of total fuel oil output for the export market, with most of it directed to Asian markets. The new 60/66 tax law is set to have a detrimental effect on fuel oil supplies, as the government encourages the upgrading of refineries and an increase in the complexity of the products exported. Fuel oil cracks have already started reflecting the future tightness, with Singapore fuel oil narrowing its discount to Dubai crude by more than $6 since the start of the year. The tightness in balances is also being reflected through lower stocks, with inventories at ARA down 21% from September’s levels, while those at Singapore are lower by 14% over the same period.

Conclusion and trade recommendations Beyond a large-scale loss of refining capacity, global margins are likely to track historical averages, with pockets of strength emerging in certain areas (Asia due to higher demand) and certain products (gasoline due to the loss of supply; potentially distillates at peak demand season should refineries face unforeseen/temporary shutdowns; etc). While mismatches in crude slates, prices and incremental refining capacity provide for interesting dynamics in the sector (eg, stronger margins in US Midwest, potential pressure on US Gulf Coast refineries etc), by and large, there is enough capacity globally (currently and slated to come online) to meet incremental product demand growth. While lower utilisation may help to keep margins elevated, should a temporary boost to any product demand arise (for instance power shortages in China fuelling diesel demand), ample refining capacity exists to meet that. Thus, we recommend positioning for inter- and intra-product spreads to extract values arising from potential frictions and mismatches (eg, our recommendation of short heating oil and long gasoline added $15.46; we hold our long RBOB summer gasoline spread (Aug-Sep) position, and we like owning Q4 fuel oil cracks/spreads) and selling into margin strength that may arise due to announcements of some OECD refinery shutdowns or temporary glitches.

Continuous upgrading of refineries penalises the output of

fuel oil, as inventories fall

Margins to trade at historical averages and unseasonal

strength should be sold into


1 March 2012 44

GLOBAL LNG

In a tighter spot Global LNG trade expanded in 2011, led by strong Asian demand. A big part of this

was the increase in Japanese demand in the aftermath of the Tohoku earthquake that has pushed global LNG supply and demand into balance.

The wave of liquefaction capacity additions that was so strong in 2009-10 is now poised to slow sharply, with two facilities coming online in 2012 and an additional one in 2013. Global additions to LNG regasification capacity should start to outpace supply additions by a factor of 4:1 over the coming two years.

Europe will likely be most affected by tightening global LNG balances, losing at least 3 bcm/y (0.3 bcf/d) of LNG imports in 2012. While this does not mean a supply shortfall in aggregate, it dictates that gas prices will be higher.

LNG supply and demand balance The recent period of global LNG supply expansion, which led liquefaction capacity to increase 106 bcm/y (10.3 Bcf/d) through 2009-11, is now set to slow in 2012 and 2013, with aggregate supply additions across those years down to 16 bcm/y (1.6 Bcf/d). Through 2009-11, supply additions were concentrated in the Middle East, with Qatar alone responsible for 62% of that capacity. The expansion of the LNG supply side was accompanied by an expansion of global regasification capacity in new and existing markets, with 27 different installations being commissioned, capable of taking 210 bcm/y (20.3 Bcf/d). The main issue for the global LNG market was that while new markets were starting to increase take, regasification capacity of some 129 bcm (12.5 Bcf/d) located in the US was largely made redundant by the rapid expansion of shale gas in that market. The result was a period of broad global over-supply in the global LNG market that reached its peak in 2010.

2011 began a period of a tightening of the LNG markets that accelerated with the earthquake and Tsunami in Japan, which increased demand for LNG in one of its largest historical markets. The continued global expansion of regasification capacity continued with another 36 bcm/y (3.5 Bcf/d) of import capacity coming on line, while the global market tightening should continue through 2012 and 2013, with another 77 bcm/y (7.5 Bcf/d) expected to come online, outpacing supply capacity growth almost 4:1.

In terms of actual usage of import capacity, Asian markets have been responsible for about 45% of consumption growth since 2008, while Europe’s share has been 35%. In 2011, Asian consumption was even more significant, taking over 90% of the increased output, with Japan and China being particularly important. With regasification continuing to expand in Asia, the fact that Asian LNG consumption growth in 2011 was higher than expected supply growth across 2012 and 2013 raises the prospect of a much tighter market.

LNG supply: Still adding, but slowing In 2011, LNG supply enjoyed another good year of output growth, which continued at a still-high 26 bcm/y (2.5 Bcf/d), while short of the 53 bcm/y (5.2 Bcf/d) pace of supply additions in 2010. We note that 2010 benefited from the start-up of five new liquefaction trains and the continued ramp-up of the eight trains added in 2009. Supply growth in 2011 was attributable mainly to trains added in 2010 running for the full calendar-year 2011.

Trevor Sikorski +44 (0)20 3134 0160

[email protected]

Michael Zenker +1 212 526 2081

[email protected]

Recent supply surge is almost completed

Tsunami in Japan increased demand

New regas in Asia is the story


1 March 2012 45

Growth came from Qatar (up 25 bcm (2.4 Bcf/d)), Yemen (up 4 bcm (0.4 Bcf/d)), and Peru (up 4 bcm (0.4 Bcf/d)). While a dozen countries experienced minor reductions in LNG output from 2010 levels, the bulk of the volume lost was in Indonesia and Algeria (each down 3 bcm (0.3 Bcf/d)), as well as Egypt (down 1 bcm (0.1 Bcf/d)).

Growth in LNG supply will likely slow over the next few years, as capacity additions remain at low levels. Compared with 2009-11, when 13 new liquefaction trains, representing about 103 bcm/y (10 Bcf/d) of nameplate LNG capacity were added, 2012 and 2013 feature only 19 bcm/d (1.8 Bcf/d) of expected new capacity from three facilities: Chevron’s Angola project (7.2 bcm/y (0.7 Bcf/d)); the rebuild of one train of Sonatrach’s Skikda facility (5.1 bcm/y (0.5 Bcf/d)) following an explosion at the train in 2004; and Woodside Petroleum’s delayed Pluto project (6.6 bcm/y (0.65 Bcf/d)).

After accounting for typical project delays, ramp-up times of the three new facilities expected in 2012 and 2013, and our estimate of utilisation rates of the existing LNG facilities, global LNG output is expected to grow just 12 bcm/y (1.2 Bcf/d) in 2012 and 5 bcm/y (0.4 Bcf/d) in 2013.

LNG demand: All about Asia Global LNG trade expanded in 2011, increasing 25 bcm (2.4 Bcf/d), up 8% y/y for January-November. In terms of regional consumption in 2011:

Asia was the leader, with imports up 24 bcm (2.3 Bcf/d) through November (up 13% y/y), and full-year consumption is estimated at 23.7 bcm (2.3 Bcf/d). The growth in Asian takes was driven by post-earthquake Japan registering the largest y/y growth among all LNG consumers (11 bcm/y (1 Bcf/d), 12% up y/y). But all Asian consuming countries posted strong import gains, with China up 4.2 bcm (0.4 Bcf/d), India up 4.6 bcm (0.4 Bcf/d), and South Korea up 2.9 bcm (0.29 Bcf/d) y/y, with India and China showing the benefits of new regasification facilities. Asia represented 95% of the increase in consumption in 2011 through to November.

European LNG consumption growth of 1.0 bcm (0.1 Bcf/d) compares with our forecast of 0.6 bcm (0.06 Bcf/d). While European imports were outpacing 2010 levels by 6.2 bcm (0.6 Bcf/d) through July, deliveries have since fallen 5.8 bcm (0.6 Bcf/d) y/y in the period to November. Southern Europe has largely had y/y reductions, with Iberia down almost 4 bcm/y (0.4 Bcf/d) and Italy down 1 bcm/y (0.1 Bcf/d), as milder weather, weakening economic growth in light of the sovereign debt crisis, competition from new pipeline gas, and a willing market in Asia all played roles in the second half of the year;

Latin America and the Middle Eastern consumption was up about 1.4 bcm/y (0.14) Bcf/d), with almost all of that growth coming in Argentina and Chile. Somewhat offsetting these gains in Latin America were countries that cut their LNG imports in 2011, including Brazil and Mexico. With this region’s takes estimated to be about 19 bcm (1.8 Bcf/d) in 2011, it represents about 6% of total LNG trade.

North American LNG consumption slid even lower in 2011, with a 1 bcm (0.1 Bcf/d) reduction, down to 13.2 bcm (1.3 Bcf/d). North America represented just over 4% of global LNG consumption through November 2011.

Incremental demand growth will be driven by the outpacing in growth of regasification facilities compared with liquefaction facilities. Figure 26 summarises the balance between new capacity additions expected for the coming years and shows that, over 2012 and 2013, regasification capacity outpaces liquefaction about 4:1.

LNG supply growth to slow

Japanese demand leads incremental growth

Regas capacity outpaces liquefaction additions


1 March 2012 46

By import region, Asia dominates the expansion of regasification capacity in 2012-13, with 48 bcm (4.6 Bcf/d) expected to enter operation. Latin America is set to add 15.5 bcm (1.5 Bcf/d) and Europe 10 bcm (1.0 Bcf/d).

Given these capacity dynamics, we expect the European regasification plants that are commissioning to be most at risk of low utilisation rates, adding little to no additional demand into the relevant markets. Higher utilisation of the non-European terminals should be expected, although the effect of the new regas plants this year will likely be more limited, as they will be commissioning. We expect:

Asia to continue to be the main destination for LNG and actively compete for cargoes in 2012 and 2013. We estimate that the aggregate Asian consuming market will grow LNG to 222 bcm (21.7 Bcf/d) in 2013 (adding 21 bcm/y (2 Bcf/d) of additional demand). Another three months of heightened Japanese consumption growth should be part of this story. The numbers suggest that Asia will grow its consumption at about the same rate as global supply growth.

New terminal capacity in Latin America and increased use of terminals in that region and the Middle East, to boost consumption in the combined Latin America/Middle East markets 6.1 bcm (0.6 Bcf/d) by 2013.

Given this, we expect the LNG market to continue to tighten in the coming years, and the most important European market for this will be the UK, which has increasingly relied on LNG to balance its market as UK production continues to ebb; this need to compete for LNG cargoes is the main source of bullishness in the UK market. While a mild Q4 has allowed LNG imports to fall even in this market, a cold Q1 or Q4 12 could again spur prices higher. Iberia has already lost cargoes on low demand and competing piped gas. As gas importation capacity has expanded into the region, with Nord Stream and Medgaz incrementing supply capacity, this could lead to non-UK LNG terminals being used sparingly (Gate, Zeebrugge), which would pave the way for further reductions in LNG usage.

LNG shipping As the LNG trade expanded this year, pressure began to build on charter rates, which have increased from $30,000/day in July 2010 to $130-140,000/day level by the end of 2011. The rapid surge in charter rates, due to available tonnage failing to keep pace fully with the rate of expansion in demand, is likely to persist, as very little in the way of additional tonnage is scheduled to come on line in 2012. With order books better for 2013 and 2014, LNG tanker rates could certainly sit at a high watermark in 2012. Given the expansion of LNG trade, which we put at 12 bcm/y for 2012, we look for the pressure on the tanker market to increase. A further factor tightening this market will likely be the increasing levels of Asian regasification capacity, which should increase the average length of journeys for most cargoes due to the greater call on Qatari gas until more of the very large Australian projects come online in 2014.

Figure 24: LNG: increments in regasification and liquefaction capacity

bcf/d bcm/y

2011 2012F 2013F 2014F Total 2011 2012F 2013F 2014F Total

Regasification 3.5 3.6 3.9 6.8 17.8 36.2 36.9 40.4 70 184

Liquefaction 1.9 1.5 0.6 2.6 6.5 19.4 15.3 6.2 26.5 67

Balance (R-L) 1.6 2.1 3.3 4.3 11.3 17 22 34 44 117

Source: Woodmac, Waterbourne, ICIS Heren, Company websites, Barclays Capital

Increase in tanker rates a concern


1 March 2012 47

Figure 25: Global LNG balances

Bcf/d Bcm

Annual average y/y change Annual total y/y change

2010 2011 2012F 2013 2010 2011 2012F 2013 2010 2011 2012F 2013 2010 2011 2012F 2013

Supply 29.2 31.5 32.6 33.1 5.2 2.5 1.2 0.4 299 322 333 338 53 26 12 5 Atlantic Basin 8 7.5 8.4 8.9 0.2 -0.5 0.9 0.4 82 76 86 90 3 -5 10 5

Pacific Basin 11.2 11.4 11.9 11.9 1.6 0.4 0.5 0 114 117 122 122 17 4 5 0

Middle East 10.1 12.6 12.3 12.3 3.3 2.7 -0.3 0 103 128 125 125 34 27 -3 0

Demand 29.2 31.3 32.5 33 5.2 2.4 1.2 0.5 299 320 332 337 53 25 12 5

Asia 17.7 19.7 21.1 21.7 2.6 2.3 1.4 0.6 181 201 215 222 26 24 14 7

Europe 8.5 8.5 8.2 7.9 1.7 0.1 -0.3 -0.3 87 87 84 81 17 1 -3 -3

Lat Am & Middle East 1.7 1.8 2.2 2.4 0.9 0.1 0.4 0.2 17 19 23 25 9 1 4 2

North America 1.4 1.3 1.0 0.9 0 -0.1 -0.3 -0.1 14 13 10 10 0 -1 -3 -1

Source: Waterborne, Barclays Capital

Figure 26: y/y change in LNG supply, by region (bcm)

Figure 27: y/y change in LNG consumption, bcm

0

20

40

60

80

100

120

140

2010 2011E 2012E 2013E

Pacific Basin Atlantic Basin Middle East

-4

-2

0

2

4

6

8

10

Nov-09 May-10 Nov-10 May-11 Nov-11

Asia LA & ME Europe NA

Source: DECC, National Grid, Barclays Capital Source: Waterborne, Barclays Capital


1 March 2012 48

US NATURAL GAS

Finding a new coal floor The oversupply in the gas market has been even larger than anticipated. Chunky

supply additions coupled with mild winter weather have crushed natural gas prices starting in Q4 11.

With a record inventory overhang expected at the end of the winter season (end of March 2012), the market will need the power sector to absorb a record amount of gas. This should push coal displacement to at least an annual average of 6 Bcf/d, about a third higher than in 2011, to avoid challenging storage capacity in October. We expect coal displacement to ramp up slowly through the year, balancing the natural gas market at an annual average price of $3.05/MMBtu.

Although we expect supply growth to slow somewhat in 2013, prices are likely to recover only slightly from 2012 levels as a large supply overhang next year is expected to again require 2012 levels of coal displacement to balance the market. We expect prices in 2013 to average $3.25.

Overwhelming supply growth keeps pressuring 2012 prices Although our forecast has been among the most bearish in the market, natural gas supply last year exceeded our expectations (Figure 28). Despite an increasingly widespread pessimistic mood in the market, we believe no one expected prices to fall so far and so fast in Q4 11 and into Q1 12. Prices have hit multi-year lows. The compound effects of warm weather and accelerating supply growth have been matched by power demand that appears to be slow in reacting to tumbling prices.

The market fears that supply will run so much higher than demand that there will be no spare storage capacity at the end of the injection season. One might expect producer restraint in an over-supplied market with low prices, yet we expect US production in 2012 to grow an incremental 2.7 Bcf/d y/y, even after growing almost 4 Bcf/d y/y in 2011. The incremental growth reflects our view that gas production should be strong due to the following: a still-too-high gas-directed rig count; associated gas from liquids-rich and unconventional oil plays; the completion and connection of drilled-but-uncompleted wells; and the debottlenecking of the Marcellus shale basin as new pipelines enter service. Figure 29 shows that even though the natural gas-directed rig count has fallen recently, natural gas production has surged. Although producers have been shifting rigs from dry gas basins to liquids-rich areas, these liquids-rich wells often yield significant volumes of natural gas. Figure 30 shows that producers are adding oil rigs at a rate that is almost three times faster than the drop-in gas-directed rigs.

We believe producers are loathe to cut flowing gas production. During the previous plunge in prices (2009), very little gas was shut in, although this round of low prices could test producer resolve. In addition, producers are fairly well hedged for 2012. Our credit research team released its regular producer hedging report last month (High Yield E&P: 2012-13 Hedging Overview, December 20, 2011) showing that producers had 46% of oil/gas production hedged for 2012, with natural gas hedges at $5.52-5.67. Producers have since added modestly to hedge positions. Furthermore, producer revenue is also less sensitive to gas prices even when they are not hedged (Gas and Power Weekly Kaleidoscope: With liquids, are producers insulated from gas prices? December 6, 2011). According to data

Shiyang Wang +1 212 526 7464

[email protected]


[email protected]

Supply has outpaced expectations

Producers are relatively well hedged for 2012






1 March 2012 49

from our equity analysts, by 2012, the sample of producers in our analysis is expected to derive 64% of revenues from liquids owing to strong oil and NGLs prices. Therefore, when hedges are also considered, producers are fairly well insulated from low gas prices.

With supply climbing significantly, the only demand component that could aid an over-supplied market is the power sector. Since 2009, power plant dispatchers in the East have worked to re-shuffle the merit order of natural gas and coal units in the region as gas prices dipped into the range of coal prices. As a result, whenever it is possible economically and logistically, gas runs instead of coal. Coal displacement in 2011 averaged roughly 4.5 Bcf/d, about 2 Bcf/d higher than our estimate for 2010. To not exceed the maximum working gas storage capacity given our supply estimates, our models indicate that coal displacement would need to grow to nearly 6 Bcf/d on average in 2012. This represents more than 8% of total natural gas demand. With certain periods of the year reaching as high as 7-8 Bcf/d of coal displacement, we expect natural gas to start displacing a fair amount of Illinois Basin and some Power River Basin coal delivered to the East, Midwest and Texas during parts of the year. Simply put, gas must price lower to find new demand.

These and other factors are weighing on near-term prices. We believe natural gas prices do not have a floor in the short term. The market is nervous that coal displacement may not be high enough to rid the market of surplus supply. Moreover, contractual obligations that require owners of gas in certain storage fields to draw down their inventory by the end of March (storage ratchets) could create a short-term glut of gas, which would severely drag prices lower. We expect to end winter (end of March 2012) with storage levels at a record high of 2.2 Tcf, which is 22% above the previous record.

This surplus will automatically put the market on track for high inventories for the remainder of 2012. With the market nervous that demand cannot soak up spare gas even with low prices, there will be an ongoing fear of insufficient room in storage for surplus supply. Thus, if the market tests the maximum working gas storage capacity at the end of October, which we expect, it will create another period later this year of very weak prices.

Supply growth slows in 2013 but prices will have limited upside Our balances indicate that production growth in 2013 will slow slightly compared with 2011 and 2012 (Figure 31). Associated gas production from liquids-rich and oil drilling, along with further debottlenecking of supply basins, will continue to add to supply. However, prices should still have trouble rebounding significantly as the large supply overhang from 2012 will still need to be worked off in 2013. Even with a boost in demand from an assumed return to normal weather in 2012-13, we are depending on coal displacement to be the marginal demand.

With only 20% or so of 2013 gas hedged, drilling next year could be a very different story. While we believe drilling is not highly responsive to short-term prices, we have found producer actions greatly affected by whether they are hedged. Forward prices have fallen in near lockstep with prompt-month prices, dragging 2013 rapidly lower ($3.76/MMBtu as of this writing). If producers refrain from hedging 2013 gas, this could mean a bullish pullback in drilling heading into next year, although there is plenty of time to hedge 2013 production. However, a significant pullback in gas-directed drilling might still be too late for prices to recover in any meaningful sense in 2013. With a higher level of supply in 2013 and our forecast for 1% organic demand growth, we continue to expect downward pressure on prices and for gas to price deeply into the coal stack in 2013 to balance the market.

The market needs a lot of coal displacement to balance

Storage ratchets could push cash prices even lower in March

Gas supply growth will continue, albeit at a lower rate in 2013


1 March 2012 50

$3 gas Our price forecast for 2012 is $3.05/MMBtu. We expect the market to still balance above $3.00 for the year as power generators increasingly respond to low natural gas prices and displace coal in growing size. However, gas must remain near this level to price a sufficient amount of coal out of the market. As production growth slows a bit in 2013, we expect natural gas prices to average $3.25, about 50 cents below the current price of calendar 2013.

We advise investors to stay short but to watch for rallies for entry points. We would advise producers (of gas and power) to hedge. Consumers should watch for large swings lower in the front of the curve, that also take the rest of the curve lower, as an entrance point.

Figure 28: Amount that supply has exceeded our lower-48 production forecast (Bcf/d)

Figure 29: Lower-48 natural gas production (Bcf/d, LHS) versus gas-directed rig count lagged by one month (RHS)

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

Jul-11 Aug-11 Sep-11 Oct-11 Nov-11 Dec-11

56

57

58

59

60

61

62

63

64

65

Jan-11 Mar-11 May-11 Jul-11 Sep-11 Nov-11760

780

800

820

840

860

880

900

920

940lower-48 natural gas production

gas-directed rig count

56

57

58

59

60

61

62

63

64

65

Jan-11 Mar-11 May-11 Jul-11 Sep-11 Nov-11760

780

800

820

840

860

880

900

920

940lower-48 natural gas production

gas-directed rig count

Source: EIA, Bentek, Barclays Capital Source: EIA, Baker Hughes, Barclays Capital

Figure 30: Cumulative change in gas-directed and oil-directed rig count

Figure 31: Quarterly supply growth, y/y, Bcf/d

-300

-200

-100

0

100

200

300

400

500

600

700

Aug-10 Nov-10 Feb-11 May-11 Aug-11 Nov-11

decline in gas-directed rig count

gain in oil-directed rig count

0.00.51.01.52.02.53.03.54.04.55.0

Q1

2011

Q2

2011

Q3

2011

Q4

2011

E

Q1

2012

E

Q2

2012

E

Q3

2012

E

Q4

2012

E

Q1

2013

E

Q2

2013

E

Q3

2013

E

Q4

2013

E

Source: Baker Hughes, Bloomberg, Barclays Capital Source: EIA, Barclays Capital


1 March 2012 51

Figure 32: US lower-48 natural gas supply/demand balances and price

Annual average y/y change

2009 2010 2011 2012E 2013E 2010 2011E 2012E 2013E

Supply –total (Bcf/d) 62.74 65.42 67.61 69.24 69.81 2.68 2.19 1.63 0.57

US L-48 Production 55.30 58.08 62.02 64.70 66.37 2.77 3.94 2.68 1.67

Canadian Exports to US, net 7.05 6.96 5.95 5.20 4.43 -0.09 -1.01 -0.75 -0.77

US Imports of LNG 1.24 1.18 0.98 0.88 0.78 -0.05 -0.21 -0.10 -0.09

Exports to Mexico 0.85 0.80 1.33 1.53 1.77 -0.05 0.53 0.20 0.23

Demand – total (Bcf/d) 62.85 65.23 66.28 68.82 69.63 2.38 1.04 2.55 0.81

Residential & Commercial 21.73 21.72 21.44 21.30 21.55 -0.01 -0.28 -0.14 0.26

Industrial 16.91 17.87 18.63 18.93 19.09 0.96 0.76 0.30 0.16

Power 18.81 20.21 20.46 22.60 22.82 1.40 0.25 2.14 0.23

Other 5.41 5.43 5.75 6.00 6.16 0.02 0.32 0.25 0.17

Storage Inventories (Tcf)

End of March 1.7 1.7 1.6 2.2 1.9 0.0 -0.1 0.6 0.1

End of October 3.8 3.8 3.8 4.1 4.1 0.0 0.0 0.3 -0.1

Economic Indicators

GDP growth 3.0 1.7 2.5 2.5

Industrial production growth 5.3 4.1 4.1 4.5

Natural gas price ($/MMBtu) $4.16 $4.38 $4.03 $3.05 $3.25

Source: Barclays Capital


1 March 2012 52

EUROPEAN NATURAL GAS

Complex equations We expect 2012 European and UK gas demand to increase by 6.6 bcm y/y in

Continental Europe and by about 1.1 bcm y/y in the UK as a result of higher residential demand (from a less mild winter), weak industrial demand, and power demand that should be little changed from 2011.

Pipeline supply, with Nordstream and Medgaz online, should expand this year, although there seems to be no intention of filling the pipes to compete for market share. Rather, the expansion of pipeline supply is increasingly likely to allow LNG to be diverted to new LNG markets instead of being used in Europe. Such diversions would be felt acutely in the UK, which is increasingly relying on LNG for supply.

We expect the LNG market to tighten increasingly through the next two years, with liquefaction capacity adding only 21.5 bcm/y by the end of 2013 and regasification adding 77 bcm/y. As a result, we forecast that NBP prices will average 59.5 p/therm in 2012, up 5.5% y/y.

2012 outlook After a year of event-driven price volatility and increasing concern that the global LNG market was tightening on greater Japanese demand, European gas markets enter 2012 with prices in a fairly modest range for the middle of winter. The outlook for the markets includes a number of bearish factors: a very mild winter that reduced gas demand in 2011 and left storage levels very high (about 12 bcm more gas in storage than in 2011); a European macroeconomic outlook for 2012 that is recessionary for real GDP and industrial production; an outlook that includes softening coal prices and no rapid recovery of CO2 prices, and greater supply, with two new pipes coming into service in 2011, augmenting supply in Iberia and northwest Europe (about 35 bcm of added import capacity). Healthy supply and weak demand have meant that January gas at the NBP, which had forward prices in October above 70 p/therm, has been trading at the prompt below 55 p/therm. Such weak fundamentals have led to the clearly bearish tone in the market. However, there are some stronger undercurrents that make navigating these markets more difficult.

Although 52 p/therm does feel low compared with expectations, it is about the same as at the start of 2011 when the system was tighter, the big difference being the price of oil-indexed gas on the continent. Oil prices are expected to stay at $110-120/bbl this year and rise in 2013, providing upside support. Similarly, the global LNG market might begin to tighten over the next couple of years as increments to liquefaction (21.5 bcm/y through 2013 added) and shipping slow to a trickle, while regassification (77 bcm/y through 2013 added) additions promise to be much more robust. With much of this capacity going into emerging Asian markets, the competition for LNG will increase, as should the reliance on piped gas into Europe to help market balance. Losing LNG cargoes to other regions is unlikely to be a significant issue for the supply-demand balance for Europe; the issue is that much of the incremental piped gas is only likely to flow at prices closer to oil-index. With those up at about 75 p/therm, this would support prices. Although such support may take a while to materialise, given current inventories, we think an increasingly tight LNG market is likely to be felt by Q4 12.


[email protected]

Risks to downside and upside

Oil-indexing should provide support


1 March 2012 53

UK Supply-Demand balance UK supply: More than enough in 2011

UK supply in 2011 has been largely about the reduction in UK continental shelf (UKCS) production and the increasing share of LNG in the supply mix.

Production from the UKCS fell again, down some 12 bcm y/y (19% down y/y) after supply disappointed in all quarters. Although UKCS was falling, that reduction in pipe supply was matched by: a reduction in Norwegian supply, with total Norwegian gas production falling 4.95 bcm y/y (down 5% y/y) to 100.6 bcm, as low end-use demand drove Statoil to defer production in the hope that prices would recover in 2012; a 29% y/y reduction in imports from the Netherlands, with flows through the BBL down 2 bcm to 6.8 bcm.; and a reduction in broader imports through the IUK pipeline, with total imports down less than 400 mcm in 2011 (down almost 900 mcm), while exports rose to 10 bcm (up 860 mcm). In terms of net exports, these increased y/y from 7.9 bcm to 9.6 bcm. The net reductions in pipeline supply in 2011 were somewhat offset by the increase in LNG imports, which rose by about 6.9 bcm/y.

In terms of the supply outlook for the next two years, we expect the following:

Norwegian volumes to pick up but be sensitive to the discount of hub prices to oil index. Following the reduction in 2011 supply, the Norwegian Petroleum Directorate reduced its supply forecast to 106.7 bcm for 2012, up by slightly more than 6 bcm y/y but lower than its previous forecast of 111 bcm. Although Norwegian supply will respond to demand, these numbers suggest there could be another 11 bcm/y of gas from Norway to make up any reduction in LNG to the region. Since much of the loss in gas came from a reduction in supply, this paves the way for more Norwegian supply into the market – something that might be needed if LNG cargoes become tight.

Dutch flows should stay at current levels, although there is some scope for an increase in supply if needed, while upside increments will be limited to about 2 bcm.

The net import/export pattern through the IUK could start to fall if the arbitrage gap between hub and oil-indexed prices is eroded. Again, this depends on the tightening of the LNG market, but is to be a likely balancing feature if cargoes start being diverted.

UK demand: A warm year and high relative prices lead to reductions

2011 was a year of lower-than-expected UK demand. After a cold Q4 10, 2011 began with fears of exhausting storage and requiring some form of load-shedding. However, temperatures changed, with most of the 2011 winter months having temperatures above seasonal norms, dragging demand lower.

In 2011, UK demand was weak across all end-use sectors. Power sector demand for gas was down by an estimated 6.0 bcm/y, a 17% y/y reduction. With total demand for power down about 2%, the fall in the gas share has come from the reduced competitiveness of gas-fired generation as a result of the change in relative prices. What is remarkable about these numbers is that they come against the background of 3.7 GW of new CCGT being commissioned in 2010 and 2011, suggesting these new plants have largely been replacing older CCGT generation rather than coal in the merit order. Domestic demand fell by 5.3 bcm (15%) y/y across the UK as a result of above-average temperatures. The deviation stemmed largely from a swing from the second coldest year on record to the second warmest (with average temperatures almost 2 degrees Celsius), with most of that deviation coming in the winter months. Industrial sector demand had an annual estimated decline of 1.8 bcm across 2011. Demand for gas to inject into storage, though, was healthy, with year opening less closing balances showing storage about 2 bcm higher y/y.

… UKCS production saw big drops

UK demand in 2011 declined on weather and relative prices


1 March 2012 54

Across 2012, we look for modest demand as:

A return to more average temperatures supports a rebound in domestic demand (+2.0 bcm). Such demand is highly temperature-sensitive, which assumes that this sector recovers less than half of the demand reduction between 2010 and 2011. In 2013, the sector should see modest growth on population increase and slightly better economic growth;

The UK economy slows, with our macroeconomists forecasting real GDP to fall 0.2% y/y in 2012 and industrial production to fall 2.9% y/y in 2012 and a further 0.3% in 2013. With this prospective economic distress, we forecast industrial demand for gas to fall in both years, with aggregate reductions some 0.7 bcm/y by 2013;

We look for power demand to stabilise at current levels, due largely to a continuation of the relative prices of gas and coal and little recovery forecast for carbon prices. Again, we expect some 3.3 GW of new gas-fired power plants (CCGT) to be added to the system in 2012. However, unless gas starts to price itself more aggressively into the market, we expect these plants to largely replace older gas-fired generating plant; and

Oil-indexed gas prices remains strong as a result of crude markets (see discussion below). This should keep net exports through the IUK at current high levels.

Market balance and price outlook In 2012, we expect end-user demand to increase by 6.6 bcm y/y in Continental Europe and about by 1.1 bcm y/y in the UK on the following competing factor: higher residential demand (due to an expectation of a less mild winter); weak industrial demand; and power demand expected to be little changed from 2011 as softening coal and no rebound in CO2 prices keep gas-fired generation uncompetitive in the merit order.

Pipeline supply, with Nordstream and Medgaz online, should expand this year, although there seems to be no intention of filling the pipes to compete for market share. Rather, the expansion of pipeline supply is likely to allow LNG to be diverted to new LNG markets instead of being used in Europe. As such, we do not view a supply-shortage risk as imminent, given the many supply options available to Europe. However, piped gas has shown every intention of flowing only at prices in line with those that are oil indexed.

We expect the LNG market to tighten increasingly through the next two years, with liquefaction capacity adding only 21.5 bcm/y by the end of 2013 and regassification adding 77 bcm/y. Although utilisation of the regas plants will be an important driver of the markets, and some seem as if they will go into markets in which they will initially be stranded assets (ie, Spain, Italy), 63% of this capacity is going into Asia, which will look for fairly high utilisation. As more regas comes online, there will likely be a desire to send more cargoes out of Europe (which is potentially well supplied with pipes), with potential redirections from the UK being the most significant for hub prices. The LNG shipping market should add to the tightness, with little additional capacity coming online in 2012 in a market already showing signs of constraint.

We forecast day-ahead prices to average 59.5 p/therm, a 20% decrease in our outlook from the previous forecast of 74 p/therm. We have introduced our 2013 price forecast, which comes in at 67.5 p/therm for the calendar year, up 13% y/y. The higher prices reflect the effect of higher oil prices on the Continent and the expectation that the tightness of the LNG market will be increasingly acute in that year.

2012 should see only slight demand recovery…

… with greater import capacity…

… leading to increased LNG diversions

Our price forecasts revised down, but above forward curve


1 March 2012 55

Figure 33: NBP price forecasts (£p/therm)

Q1 Q2 Q3 Q4 Annual average

2010 35.6 37.8 42.9 52.5 42.2

2011 57.1 57.5 54.2 56.8 56.4

2012 55F 55F 57F 70F 59.5F

2013 75F 60F 60F 75F 67.5F

Source: Ecowin, Barclays Capital

Figure 34: UK supply and demand balance

Annual calendar year volumes

BCM 2008 2009 2010 2011E 2012E 2013E

Supply – total 104.1 96.2 102.3 89.8 89.0 90.5

UKCS Production 77.3 66.3 63.4 50.5 48.0 45.6

Pipeline imports 36.3 31.8 35.5 29.0 30.9 35.5

Netherlands 8.5 6.5 8.2 6.8 6.5 8.0

Norway 26.7 24.5 26.0 22.2 23.1 26.2

Belgium 1.1 0.7 1.3 0.4 1.3 1.3

LNG imports 0.8 10.4 19.2 25.9 24.9 23.9

Pipeline exports 10.4 12.2 15.8 14.8 14.8 14.5

Ireland 5.1 5.1 5.3 5.4 5.4 5.4

Belgium 4.3 5.8 9.0 9.6 9.0 8.1

Others 1.0 1.2 1.5 0.7 0.4 1.0

Demand – total 102.5 94.7 102.5 88.4 89.5 91.2

Domestic 33.8 31.5 36.2 30.9 32.9 33.3

Power 35.4 33.4 34.9 28.8 28.8 29.4

Industrial 19.8 17.2 18.2 16.4 15.9 16.2

Other 13.5 12.5 13.2 12.4 12.1 12.3

Changes in stocks 0.3 1.5 -0.2 1.5 -0.5 -0.7

NBP prices (pence/therm) 58.2 31.1 42.2 56.4 59.3 67.5

Source: DECC, Ecowin, Barclays Capital

Figure 35: y/y change in UK demand (bcm/y)

Figure 36: y/y change in UK supply (bcm/y)

-10-8-6-4-202468

H1 10 H2 10 H1 11 H2 11 H112F

H212F

H113F

H213F

Domestic Power Industrial Other

-15

-10

-5

0

5

10

H1 10 H2 10 H1 11 H2 11 H112F

H212F

H113F

H213F

Indigenous Production Pipeline imports LNG

Source: Ecowin, Barclays Capital Source: DECC, National Grid, Barclays Capital


1 March 2012 56

COAL

Year of the dragon? The coal market enters 2012 in a remarkably different place from where it started

2011, with a warm Q4 11 across the Northern Hemisphere depressing demand and leaving port and utility stocks high.

For 2012, we expect some moderation in demand growth as a result of global economic concerns, leaving the market struggling to cope with robust supply additions. We expect emerging Asia to buck this trend, with Japan’s recovery and Indian demand growth, in particular, providing some support for prices.

We forecast that European delivered coal prices will average $102/t this year, 17% lower than last year. Pacific-basin prices, as represented by the Newcastle price, should average $112/t, down 7% from last year.

2012 outlook Having started 2011 with a roar, coal prices ended the year with more of a whimper. The story of the first half of 2011 was the demand-side legacy of a cold Q4 10 combined with weather-related supply shortages that left the traded market tight and sent prices upward to $130/t for coal into Europe (ARA). The second half of 2011 saw a gradual but prolonged retreat from those high levels, with prices closing the year at around $110/t. The price retreat stemmed from a moderation of demand growth related to slower global economic growth and mild weather conditions, alongside robust coal supplies that suffered from few outages at mines or rail and port infrastructure. Further weighing on benchmark prices was the emergence of an appetite among Asian buyers for importing off-spec and sub-bituminous coal material that entered the market at discounts to benchmark coal prices, eventually accounting for an estimated 23% of global trade (McCloskeys). Price-sensitive importers, such as China and India, turned to these volumes, and although demand in these countries remained strong, higher CV benchmark material saw little benefit from this growth. The key to allowing the expansion of the sub-bit trade has been low freight rates, with freight prices 43% lower, on average, in 2011 than in 2010.

The current picture differs markedly from the start of 2011, with a warm Q4 11 across the Northern Hemisphere depressing demand and leaving port and utility stocks high while supply increments continue to come on line and pressure prices. Benchmark (CIF ARA) prices into Europe fell by another $5/t in January, and the legacy of this warm winter should persist for months to come. Key themes for 2012 include:

A moderation in demand growth as the slowdown in the global economy erodes demand for coal for both power generation and industrial production. Although this is the broad theme it does hide differences between the basins:

− Asian demand for imports looks set to remain strong, with our forecast for these to grow by 38 mt/y by the end of 2013. We expect the following:

Chinese demand growth will remain moderate, with import demand growing by 2% in 2012 and 1% in 2013, as the Chinese market should remain mostly balanced for the next couple of years because of internal investment patterns and the impact of price controls at domestic ports.

Miswin Mahesh +44 (0)20 7773 4291

[email protected]

Amrita Sen +44 (0)20 3134 2266

[email protected]


[email protected]

Shiyang Wang +1 212 526 7464

[email protected]

A striking contrast to last year


1 March 2012 57

Indian demand will grow and potentially surprise to the upside. India’s thermal coal structural deficit is expected to widen significantly in the next five years. In 2011, Indian coal imports increased by 14%, to 86 Mt, as economic growth (8.3% y/y increase in real GDP) met an accompanying increase in power demand. We forecast that the Indian economy will achieve 7% y/y real GDP growth in 2012 and another 7.2% y/y in 2013, and that coal imports will increase by 10 Mt (12% y/y) in 2012 and 14 Mt in 2013.

Japanese coal demand should rise by 5% y/y in 2012 and 3% in 2013 as Japan’s crippled nuclear fleet remains largely inactive, with most of the capacity likely to stay off-line in 2012.

− European coal demand is set to remain lacklustre, as the economic slowdown and restocking needs wane and the increase in renewable generation continues apace.

− Latin America looks set to be the strongest centre of demand growth, albeit from relatively low levels. We forecast that demand from this region will grow by 8 Mt/y by the end of 2013.

Healthy supply growth, with rail and port capacity additions continuing over the next two years across the major suppliers, helping to expand supply by 48 Mt/y by end-2013. In particular, we expect volume expansion at most of the main exporters. In the Atlantic basin, we expect South Africa’s exports to improve, with increased capacity utilization at its RBCT terminal following major rail-link improvements. Colombian and Russian exports are expected to be well supported given expansionary targets set by miners in these countries. Pacific exports should grow by 7% in 2012 and 5% in 2013, with weather-induced supply disruptions unlikely to match those of 2011. Although the inherent deficit for seaborne thermal coal in the Pacific Basin should persist because of the relatively large appetite of Pacific consumers, such as India and Japan, we expect the deficit, relative to 2011, to narrow by 19 Mt in 2012 and by another 8 Mt in 2013.

Continued strong appetite for off-spec (sub-bituminous, low CV coal of 5500kc NAR or below) coal, as price-sensitive Asian buyers, many squeezed by price controls on power sales, look for discounted volumes. With freight rates likely in for a prolonged period of modest pricing, there should be few barriers to healthy trade in such low CV coals. We forecast that Indonesian volumes will climb to another record high in 2012, increasing by 26 Mt (8%), to 350 mt; in 2013, we expect further growth of 5%, to 368 mt. However, the appetite for such low CV coal will likely remain in Asia, with European buyers still preferring better coal given more developed environmental restrictions on emissions.

API2-4 spreads are in negative territory once again, for the first time since June 2011. API2-4 spreads below the cost of freight suggest that Europe no longer needs spot South African cargoes to meet its supply-demand balance. As Colombian, Russian, and US export capacity increasingly fills European demand, the likelihood that Europe will need to dip back into the South African market should decline. With this likely to continue, we expect that the spread will be persistently negative.

Market balance

Our 2012 and 2013 supply and demand estimates suggest a loosening of the global thermal coal trade balance. In the Atlantic Basin, we expect demand growth to follow a flat profile across major North West European countries, producing growth of 2% (4 mt) y/y in 2012, mostly from the Latin American region. In 2013, we expect Atlantic Basin coal demand to

Atlantic basin surplus set to expand


1 March 2012 58

fall by 2.2%. We expect good growth among supply centres in the Atlantic, with Russian coal exports to grow 5 mt y/y in 2012, to 86 m, while South African exports are pegged at 70 mt, 2 mt higher y/y.

Although the overall trade deficit in the Pacific Basin should remain intact, as major Asian consuming countries such as India and Japan have structural coal shortages, the deficit should shrink by 15 Mt in 2012 and by 3 Mt in 2013. The smaller deficit reflects our view that China’s coal imports will remain relatively flat in the next two years, as the transport system could still come under pressure from time to time but not to worsen from current levels, barring any unforeseen outages. Australia and Indonesia exports should grow at a healthy pace and help narrow the gap between supply and demand in the region.

Figure 37: S/D balance by basin – Traded coal market (Mt)

Mt y/y change (Mt)

2010 2011F 2012F 2013F 2010 2011F 2012F 2013F

Supply

Total 714 760 815 854 9% 6% 14% 7%

Atlantic Basin 248 262 278 290 5% 6% 6% 5%

Pacific Basin 466 498 537 564 12% 7% 8% 5%

Demand

Total 738 784 811 815 10% 6% 3% 3%

Atlantic Basin 214 226 229 209 8% 6% 1.3% -8.8%

Pacific Basin 524 558 582 606 17% 7% 4% 4%

Stock change -24 -24 4 39

Source: McCloskeys, Barclays Capital

Overall, we expect a continued softening of coal prices in 2012, with both API2 and API4 prices to average $102/t. For 2013, we expect API2 to average $105/t and API4 to average $104/t. In the Pacific Basin, we expect Newcastle prices to average $112/t in 2012, being down 7% y/y on better supply performance, but maintaining value better than the European prices on the more buoyant demand picture in Asia.

Although there are always upside price risks in the coal market from unexpected supply interruptions or demand-inducing weather moves, inventories are high globally and should provide a buffer to any such shocks in the coming months.

Pacific basin deficit set to shrink


1 March 2012 59

Figure 38: S/D balance by country: Traded coal market (Mt)

Mt 2006 2007 2008 2009 2010 2011 2012 2013

Japan 119 126 131 113 125 121 127 131

South Korea 60 66 74 80 89 94 95 96

China 31 41 31 82 111 124 127 128

India 29 35 36 60 75 86 96 110

Taiwan 56 59 59 53 57 60 61 63

Europe 169 167 165 153 137 145 141 145

Others 125 139 143 132 145 154 164 142

Total imports 589 634 638 674 738 784 811 815

Y/Y change (%) 9.1% 7.7% 0.7% 5.6% 9.5% 6.3% 3.4% 0.5%

Indonesia 183 195 200 233 291 324 350 368

Australia 111 112 125 139 141 145 156 164

China 54 45 36 18 14 7 7 7

Vietnam 20 24 16 23 17 22 24 25

Russia 70 74 70 78 76 81 86 87

South Africa 67 67 68 67 69 68 70 74

USA 20 24 35 12 15 25 28 32

Colombia 58 65 69 64 70 72 75 78

Others 22 23 27 20 22 17 19 20

Total exports 605 629 646 655 714 760 815 854

Y/Y change (%) 15.4% 3.9% 2.7% 1.4% 9.0% 6.5% 7.2% 4.8%

Global trade balance 17 -5 8 -19 -24 -24 4 39

API 2 (US$/t) 63 87 144 71 93 123 102 105

API 4 (US$/t) 50 62 120 66 92 119 102 104

Newcastle (US$/t) 49 66 128 72 99 120 112 115

Source: McCloskeys, Barclays Capital

Figure 39: Exchange-traded coal prices, $/t Figure 40: FOB coal prices, $/t

30

60

90

120

150

180

210

240

Feb-07 Feb-08 Feb-09 Feb-10 Feb-11 Feb-12

API 2

API 4

$/t

0

40

80

120

160

200

Feb-03 Feb-06 Feb-09 Feb-12

FOB Richards Bay pricesFOB Newcastle prices

$/t

Source: EcoWin, Barclays Capital Source: McCloskey’s, Barclays Capital


1 March 2012 60

US POWER

Cheap gas and mild weather pummel power While US weather offset sluggish underlying power demand through summer 2011,

helping to support power prices, a chronically soft 2011-12 winter has taken its toll on energy demand, pushing US gas and power prices lower.

Weaker gas prices over the past few years have pushed many eastern coal plants off the margin, but the recent shift to even lower gas prices is displacing coal in almost every US market. This is single-handedly upending age-old customs about which plants tend to serve baseload demand, dramatically compressing power plant margins for coal, nuclear and other non-gas assets, while handing increasing chunks of market share to gas-fueled units.

The Texas power market is facing acutely tight reserve margins. After record winter demand helped cause a February 2011 blackout, record summer 2011 loads led to several power watches and power warnings as reserve levels fell. After adding the risk of plant shutdowns to meet new pollution controls and the effect of the ongoing drought, Texas faces a challenging 2012 with heightened risks of further power price spikes.

Power demand: The winter of our discontent

After two successive colder-than-normal winters followed by two successive warmer-than-normal summers, US energy markets are experiencing a drought of weather demand. Heating degree days for winter 2011-12 are about 10% below the 10-year normal, depressing power consumption. Weak Q4 11 demand helped drive total-year 2011 power consumption 0.4% below 2010 levels. Power consumption remains 0.7% below the pre-recession pace. The Barclays Capital outlook for 4.1% growth in 2012 US industrial production should help boost power demand modestly, but growth in the residential and commercial sectors remains sluggish.

One might think that the surge in new electric vehicle (EV) offerings would portend a significant demand boost for power. However, EV power consumption is starting from near zero, and the outlook for EV sales remains uncertain. Indeed, the US Energy Information Agency (EIA) and our own equity research team expect very different outcomes for the uptake of EVs. Using these two sales forecasts, we estimate that EVs will boost total US power consumption by between 0.14% (using the EIA sales forecast) and 0.55% (using the Barclays Capital sales forecast) by 2020. These projections suggest that unless EV sales surge well beyond these two forecasts, EVs will have a minimal effect on power usage through this decade.

Weak gas prices reshuffle the power deck With most US power markets pricing in lockstep with natural gas prices, the swoon in natural gas prices to new contemporary lows has pulled power prices down. With some variation across regions, forward power prices have tracked forward gas prices lower.

This is not simply a re-pricing of power but represents a seismic shift in the business, with gas decimating the margins available to existing non-gas-fired power plants. Where power prices once were high enough to warrant the construction of new coal, nuclear and wind plants, the plunge in gas prices is now pummelling the margins for all non-gas-fired plants, even those acquired at a discount to new-build costs. Gas-fired power is now much cheaper than most other alternatives (Figure 41).

Shiyang Wang +1 212 526 7464

[email protected]


[email protected]

A drought of weather-driven demand has pushed gas and

power prices lower

Lower gas prices are challenging non-gas-fired plants…


1 March 2012 61

The shift to a lower gas price curve – while never welcome to operators of non-gas-fired units – comes at a particularly troublesome time for coal. Coal-fired power plants have been losing market share to gas for the past few years, with 2012 expected to register more of the same (Figure 42). Just as margins for coal plants are plunging to new lows, coal plant operators are facing a host of new environmental regulations. Coal prices are drifting close to marginal cost, suggesting there is little downside relief to buyers. While the Cross State Air Pollution Rule (CSAPR) was stayed in December 2011, marking a nominal victory for coal plant operators, owners must still decide if upgrading their plants to meet CSAPR and other environmental rules is warranted. We expect low gas prices to only hasten the retirement of a growing amount of coal capacity.

Texas shows signs of a tight market The Texas power market is affected by a regional economy largely spared the effects of the recession. While many regions of the US have not seen power usage return to pre-recession levels, Texas has experienced three consecutive years of record peak demand during the summer. Summer peak demand in 2011 surged to 68,379 MW, which followed a record 2010 summer peak of 65,776 MW, which itself was 2,376 MW higher than the 2009 record peak. A peak winter record in February 2011 contributed to a blackout. The Texas power system, which is essentially isolated from the rest of the US, is in a league of its own.

During the summer and winter demand periods, ERCOT power prices and generator margins demonstrated the type of non-linear behavior that has typified other power markets when reserve levels fall short (Figure 43). Figure 44 illustrates the response of Midwest prices to dangerously low reserve margins in the late 1990s. When power markets grow tight, they tend to surprise. History suggests that power prices typically surge in high demand seasons when reserve levels fall below 15%, and become extremely volatile when reserve levels are at or below 10%.

The summer 2011 sustained power price rally may have been but a prelude for what lies before Texas. ERCOT and NERC projections show reserve levels falling to 12.11% in 2012, 12.07% in 2013, and 7.64% in 2014, and represent a warning to system planners and market watchers. These levels do not include the potential for another hot summer, the retirement of coal units to meet environmental regulations, or the effect of the ongoing drought to plant availability (hydroelectric and cooling water).

Figure 41: All-in cost of new power plants, $/MWh (before subsidies and renewables credits)

Figure 42: Coal- and gas-fired power output, GWh

0204060

80100120140

CCGT($4.88gas)

Westerncoal

($15/toncoal)

Easterncoal

($60/toncoal)

Nuclear Wind

NOx and SOxProperty Tax & InsuranceDecommissioningFuel, Operations & MaintenanceCapital Costs

-

500,000

1,000,000

1,500,000

2,000,000

2007 2008 2009 2010 2011E 2012E

Coal Natural Gas

Source: EIA, NYMEX, Barclays Capital Source: EIA, Barclays Capital

… with coal steadily losing market share

The Texas power is showing the classic signs of a tight market


1 March 2012 62

With prices resurgent in the Texas power market, one might expect generation developers to be racing to add capacity. However, even with tighter markets, forward power prices do not cover the cost of new generation. Neither average cash price levels nor forward prices have remained high enough to cover the costs of a new gas-fired plant. This is typical for power markets. Power forward prices rarely signal the need for new capacity until after that capacity is desperately needed.

Figure 43: Texas (North) power prices, $/MWh

Figure 44: Midwest power prices (RHS) and capacity margins (LHS)

0

100

200

300

400

500

600

Jan-10 May-10 Sep-10 Jan-11 May-11 Sep-11

Capacity margin

0%

5%

10%

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1996 1997 1998 1999 2000 2001 20020

500

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1996 1997 1998 1999 2000 2001 20020

500

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2,500

3,000On-peak power price ($ per MW-hour)

Capacity margin (LHS) On-peak power price (RHS)

Source: ICE, Barclays Capital Source: Platts, MISO, NERC, Barclays Capital

Power prices do not cover the cost of new plants


1 March 2012 63

CARBON

Nothing to shout about 2011 was a year of two halves: in H1, carbon prices gradually rose before stabilising

around the 17 €/t level for Dec 11 EUAs; in H2, prices suffered a severe downward correction, with EUA prices ending the year trading around the 7 €/t level – a 60% reduction in value in six months.

In 2012, the carbon market is looking very oversupplied amid European macroeconomic concerns, and in our view downside risk persists for EUAs and CERs – even from the low prices of January 2012.

For 2012, the only potential upside from current levels is likely to come from attempts by the market regulator, the EC, to reduce supply from 2013. Without such intervention, we believe the EU ETS market would likely see a number of years of only modest price improvement. The outlook for CERs is no better, and with oversupply likely to continue in that market, price upside looks even more limited. Moreover, the outcome of the current macroeconomic issues in Europe holds more downside than upside, in our view.

EU ETS: Looks oversupplied

Over the eight months from June 2011 to February 2012, EUA prices have gone from around 17 €/t to around a 7 €/t mean. The loss of value reflects a market that has become heavily oversupplied with carbon, with:

The EU ETS looks oversupplied just in terms of EUAs, as the prospect of a European economic recovery has been cut short by forecasts that 2012 economic performance will be recessionary. At the start of 2011, our outlook for EU 2012 industrial production (IP) was for 1.5% growth. A year later, our forecast is now for a 2.9% y/y fall – a c.4.5pp change over the year. This has been accompanied by a tightening of credit to market participants across the board. With sovereign debt issues still not fully resolved, the ultimate path of the economy and how it unfolds will have an important bearing on EUA prices. We now forecast that, over Phase 2, the EU ETS will be oversupplied by 650 Mt.

Offset supply is set to remain high. Another key reason for the price decline in 2011 was the heavy supply of offsets. In terms of CERs, 320 Mt worth of CERs were issued in 2011 (a monthly average of 26.6 Mt), beating the previous annual high by some 180 Mt. This doubling of CER volumes in the market was joined by the first meaningful issuance of ERUs, with around 80 Mt coming into the market (up from 36 Mt at the start of 2011). With 400 Mt of offsets to absorb and demand being weakened by the deteriorating economy, prices are starting to worsen.

Phase 3 EUAs are being sold, predominantly through the NER 300 programme that is looking to monetise 300 Mt of Phase 3 EUAs in the coming 18-24 months. The sales started in December 2011 and 200 Mt have been committed to be sold by the end of September 2012. In addition, the EC has promised that 120 Mt of Phase 3 EUAs will be sold early, via the centralised auction platform. We do see risks to these volumes, but, even so, the total volume of Phase 3 EUAs to be sold in 2012 is likely to be around 300 Mt.

Non-allocated NER will be sold in 2012. At the start of Phase 2, EU member states set out reserves of EUAs to allocate to new entrants (NER). Now, at the end of this process,


[email protected]


1 March 2012 64

most countries have said they will sell any Phase 2 NER that has not been allocated. We have a long-held assumption that some 75 Mt will be sold from these accounts by end-2012 (along with the already scheduled sovereign auctions).

Although the supply side looks aggressive, the demand side is likely to remain weak. In terms of industrial emissions, forecasts of a fall in EU IP of 2.9% y/y suggest a y/y reduction in emissions. In terms of power sector demand for permits, this will be a function of the following factors:

Activity-generated emissions in 2012 will be determined by the level of power demand, which should be kept modest by poor forecasts for economic growth. Weather- generated demand remains an unknown, but even if weather is conducive to higher power demand, any increase in emissions is likely to be kept in check by the steady rises in renewable generation that have been a constant feature of power demand.

The need for hedges of future activity. In 2011, a contributing factor to the price decline was the fact that less power hedging demand materialised than expected. Hedging in H2 11 was better than in H1 11, but EUA volumes traded and cleared on exchange in 2011 were up by only around 4.3% y/y, despite being a year closer to 2013, when utilities will receive no free allocations. The story was similar in open interest, with ECX open interest in 2011 increasing by 152 Mt – a smaller rise than in 2010. The relatively low levels of hedging, particularly in H1, stemmed largely from the very low level of power spreads (clean spark and dark spreads) across the European power markets. Although such power spreads increased over H2 11, there is some evidence that they are coming under renewed pressure. If they decline significantly from current levels, hedging demand could fall off again, dragging the carbon market down even further.

Figure 45: EUAs and CERs (€/t) – where to now?

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Source: ECX, Barclays Capital

Given the interplay of a steady stream of supply against a modest and uncertain level of demand, it is hard to see much upside for EUA prices over 2012. In our view, the main source of any potential upside lies in regulatory intervention. A vote by the environmental committee of the EU parliament in December 2011 held out the possibility that some form of price intervention could be implemented. The vote centred on the proposal for the set-aside, a clause to withhold from supply a significant volume of Phase 3 allowances from being auctioned in the first years of the Phase. The volumes would then either be cancelled (requiring a subsequent change to the primary legislation of the EU Directive) or released back

Supply is much more robust than demand

Regulatory intervention looks to be the only source of

upside potential


1 March 2012 65

into the market later in the Phase. Which of these paths to follow would be decided much later, probably when changes to the EU ETS directive are being discussed in relation to Phase 4 (beyond 2020). In terms of price development, we expect little support for prices from this until it is both better defined and the likelihood that it will progress to legislation improves.

Outlook is a long market Other market fundamentals look bearish for the EU ETS, with a Phase 2 (2008-12) balance looking to have significantly more allowances than emissions. Given the discussion above, we forecast that the whole Phase (2008-12) will be long EUAs by 675 Mt, not including the use of offsets. Including the use of an assumed 945 Mt of offsets, the net position is now 1620 Mt. We note that from 2013 the market is a net short in terms of EUAs less cap, but the availability of offsets will keep it long until 2015.

Figure 46: EU ETS supply and demand balance

2008 2009 2010 2011F 2012F Phase 2 2013F 2014F

EUA allocation (cap) 2003 2052 2079 2204 2441 10,778 2256 2220

Emissions 2119 1882 1940 1971 2187 10,096 2315 2342

Emissions – cap 116 -170 -135 -233 -254 -675 59 121

ERU/CER usage 80 80 135 250 400 945 200 200

Net position (inc offsets) 36 -250 -270 -483 -654 -1620 -141 -79

Note: EUA Allocation includes free allocation plus auctioned volumes. 2012 does not include volumes of Phase 3 volumes sold for use in 2013 and onwards. Source: CITL, Barclays Capital

Price outlook summary

Given the discussion above, our 2012 forecast is for little, if any, price movement from current levels, although our H2 12 forecasts do factor in some upside from expected progress on the set-aside concept. Prices for 2013, up at 12 €/t, do reflect the further impact of the operating set-aside but this is far lower than in previous forecasts given lower growth prospects beyond 2012, a lower emissions base and having moved some 80 Mt of early volumes forward from 2012 to 2013. The introduction of a set-aside is assumed to be 140 Mt in 2013 (consistent with a 700 Mt total set-aside for the Phase), but the continued moribund economic performance expected in 2013 should keep price rises muted. Similar dynamics are expected to be in action for 2014 and the remainder of Phase 3, reflecting the lower prices expected in the early years of the Phase and the lower base from which emissions will be starting.

Figure 47: EUA and CER price outlook

Contract (€/tn CO2) 2008A 2009A 2010A 2011 H1 12 H2 12 2013 2014 Phase 3 (13-20)

EUA 22.6 13.4 14.5 13.4 7 8 12 14 18

CER 17.4 11.8 12.4 10.2 4 4 7 7 10

EUA-CER spread 5.2 1.6 2.1 3.2 3 4 5 7 8

Note: CER forecasts are for EC-compliant CERs. Source: Barclays Capital

The Phase looks long by 675 Mt of EUAs, plus the use of some

945 Mt of offsets

Prices likely to stay at current levels


1 March 2012 66

Figure 48: EUA and CER prices (€/tn) Figure 49: Hedging requirements of utilities (Mt CO2)

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Figure 50: Forward curves and fair value (€/t)

Figure 51: Relative costs of generation – spots

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Note: Fair value calculation takes the front DEC price and applies the cost of carryat Euribor to derive a DEC 12 price. Source: ECX, Barclays Capital

Note: The chart shows the cost of gas-fired generation less the cost of coal-fired generation using spot prices for fuels and carbon. NBP used for gas and API 2 used for coal. The first figure refers to gas-fired plant efficiency, second to coal-fired plant efficiency. Source: Ecowin, ECX, Barclays Capital

Figure 52: CDM issuance (Mt CO2)

Figure 53: EUA and CER volatility

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Source: UNFCCC, Barclays Capital Note: 10-day close-to-close volatility. Source: Reuters, Barclays Capital


1 March 2012 67

CREDIT


1 March 2012 68

US HIGH GRADE ENERGY AND PIPELINES

We favor pipelines over energy We see better value in the pipelines sector than in energy, with EPD and ETP two of

our top picks.

Pockets of Value

Independent E&P The high grade E&P sector, despite trading roughly 10bp cheap to its 3y average differential versus U.S. Credit, has been buffeted by concerns about low natural gas prices. Although we believe this concern is warranted in some cases – we are Underweight Encana Corporation (ECACN) – the sector is now comprised of more large, high quality issuers than in the past, which should keep spreads firm. We expect a bond deal from Apache Corporation (APA) to finance recently announced M&A. Against our Underweight on ECACN, we are Overweight Anadarko Petroleum Corporation (AP) and Nexen Inc. (NXYCN).

Integrated Energy The integrated oil and gas category is trading 10bp rich to its 3y average differential versus U.S. Credit, which seems too tight to us in light of an improving environment for risk. The integrated sector is characterized by large, highly rated entities that are fairly defensive. As a result, the sector trades tight to the broader market and is low beta. We are Market Weight the sector and see better value elsewhere in energy.

Oil Field Service Oil field service credits continue to trade cheap to their 3y average differential versus U.S. Credit. We attribute this to persistent wide spreads for Transocean Ltd (RIG) as a result of the Macondo overhang. We recently lowered our recommendation on RIG to Market Weight from Overweight to reflect less attractive risk-reward in the bonds. We remain Overweight Nabors Industries Ltd (NBR), which we expect to reduce debt in 2012, and cautious on Weatherford International Ltd (WFT, MW), which trades tighter than NBR and continues to face an accounting overhang. We still expect WFT to issue debt in 2012.

Refining With the broader rally in risk assets across credit, the refining sector benefited as investors grew less concerned about the effects of new supply related to the pending separation of Phillips 66 from ConocoPhillips (COP, MW). We recently upgraded the sector to Market Weight from Underweight. We expect Phillips 66 to issue up to $6bn of new debt, which could weigh on the sector’s secondary spreads if the market is trading poorly, but we believe that overall levels already reflect the anticipated supply. With Marathon Petroleum Corporation (MPC, MW) now trading slightly wide to Valero Energy Corporation (VLO, MW), we believe that MPC could rally after a new Phillips 66 deal as the sector’s supply overhang is eliminated and these credit benefit from a seasonal rally into summer. We expect both MPC and VLO to issue debt.

Pipelines We recently upgraded the pipelines sector to Overweight from Underweight, reflecting our view that a new issue overhang was already priced into spreads and that the decline in natural gas prices would have a limited effect on spreads for most issuers. Although pipelines are now trading in line with their 3y average differential relative to U.S. Credit, they are well wide to 2010 and 2011 tights. We believe that spreads could tighten during the next several months. We remain constructive on the category and remain Overweight Enterprise Products Partners L.P. (EPD) and Energy Transfer Partners, L.P. (ETP).

Harry Mateer +1 212 412 7903

[email protected]

Ming Zhang +1 212 412 3386

[email protected]


1 March 2012 69

US HIGH YIELD ENERGY

Weak natural gas weighing on spreads Weak natural gas prices have led to a sell-off in E&P credits levered to gas: benchmark

bonds including Chesapeake Energy, EXCO Resources, and Quicksilver Resources are down 5-7% year-to-date.

We are Market Weight the High Yield Energy sector, and despite the sell-off, expect 5-7% returns for energy bonds in 2012. HY Energy is trading ~600bp over Treasuries, about 85bp cheap to its 10-year average.

The majority of the high yield E&P peer group is more leveraged to oil than natural gas, as we estimate ~75% of 2012E net revenues will come from liquids. Our bias is towards more oil-leveraged names, though recent spread tightening has priced in much of this advantage, in our opinion.

Summary of investment view We rate the High Yield Energy sector Market Weight and look for 5-7% returns in 2012, in line with our strategist’s expectations for the high yield market. We believe 2012 will roughly repeat similar themes from 2011 and look for in-line to perhaps modest outperformance of energy names compared with high yield. We would be more bullish on the sector absent new issue supply and weak natural gas prices. In our view, top themes this year will be oil prices outperforming natural gas, producers’ focus on oil/liquids drilling, continued M&A, and robust new issue supply.

From a fundamental perspective, we forecast WTI oil and Henry Hub natural gas prices to average $95/bbl and $3.00/mmbtu, respectively, in 2012. Notably, Barclays Capital’s commodity analysts expect WTI to average $125/bbl in 2013, $137/bbl in 2015, and $185/bbl in 2010. Financial leverage for the peer group is expected to post another annual decline: 2.9x in 2012E, from 3.0x in 2011E, 3.1x in 2010, and 3.2x in 2009. The sharpest deleveraging is again expected in oilfield services, while we expect leverage to tick up in pipelines.

Investment recommendations

Buy MEG 21s (OW), Sell CXO 21s (NR), pick up 125bp in yield. Both companies are B3 rated and have good exposure to oil prices, though the recent divergence in spreads leaves better opportunity in MEG, in our view. MEG ended 2011 with virtually no net debt on its balance sheet and is well positioned to complete Phase 2B of its oil sands build-out, more than doubling production to 60,000 b/d by 2013.

Buy NGLS 21s (OW), Sell RGP 21s (MW), pick up 60bp in yield. We believe Targa is trading cheap to Regency, given its lower leverage (3.0x vs. 3.9x) and better ratings (Ba3/BB vs. B1/BB-). While less fee-based then Regency, Targa remains well hedged in 2012-13. The company has ~$1bn in organic growth projects announced for 2012-13, adding scale – an important factor for future ratings improvement.

Buy PGS 18s (NR), Sell CGV 21s (NR), roughly even yield and shorten duration. PGS notes are better rated (Ba2/BB vs. Ba3/BB-), and the company has about a half turn lower net leverage. While CGV benefits from diversity created through Sercel, PGS has a younger, more capable seismic fleet that generates higher margins.

Gary Stromberg +1 212 412 7608

[email protected]

Kateryna Kukuruza +1 212 412 7647

[email protected]


1 March 2012 70

US HIGH YIELD COAL

Challenging fundamentals look set to persist Domestic thermal coal fundamentals continue to weaken as persistently warmer than

expected winter weather and sub $3/MMBtu natural gas erode demand.

With production largely committed and priced, investors will be watching closely to see whether utilities are able to renegotiate pricing and/or delivery of 2012 commitments.

We are Market Weight the metals & mining sector, but we are cautious on thermal coal names given weak thermal coal fundamentals.

Summary of investment view Domestic thermal coal market fundamentals weakened through the end of 2011 and into the start of 2012. Thermal coal demand has been negatively affected by uncharacteristically mild winter weather. Heating degree days from November 2011 through January 2012 are down roughly 15% versus the 30-year average, with an estimated decline in total electricity consumption of nearly 3% during the same period. Natural gas prices declined some 30% during this period, finding stability in the $2.50-2.75/MMBtu range, making natural gas an increasingly competitive fuel source for power generation and eroding thermal coal demand further. Thermal coal producers have estimated that coal-to-gas switching could result in the loss of as much as 50mn tons of thermal coal in 2012. Producer commentary this earnings season has often focused on thermal export demand growth helping to offset domestic headwinds from weather and gas prices, but limited port capacity is still a constraint.

Producers have met declining thermal demand with only modest reductions in supply as coal producers have committed and priced contracts for most of their 2012 coal production. We expect coal inventories at the utilities to continue to rise as producers produce according to profitable 2012 contracts while utilities see only modestly improving demand and use more natural gas. Thus, 2012 is likely to be marked by oversupply, with producer discipline re-emerging in 2013. We will be watching closely to see if and how 2009-esqe contract price/delivery renegotiations play out between producers and utilities. Lastly, recent demand commentary from metallurgical coal producers leads us to believe that met/thermal crossover tons could swing back into the thermal market and boost supply.

We remain Market Weight the metals & mining sector (including US coal companies), despite our cautious view on thermal coal fundamentals. Many of the thermal coal producers we follow have relatively strong balance sheets and should be able to withstand a period of weakness. We think any significant selling in these names (ACI, BTU, CLD) could create a buying opportunity.

Investment recommendations We recently lowered our rating on Cloud Peak (CLD) 8.25% and 8.50% senior notes to

Market Weight from Overweight. CLD looks well positioned, with 2012 production fully committed and a strong balance sheet (just 1.2x net leverage). But with yields of 6–6.5% and weak thermal coal market fundamentals, we see little upside potential at current levels. We would look to buy CLD bonds on any material weakness from here given its low leverage and strong contract position.

Matthew Vittorioso +1 212 412 1378

[email protected]

Oscar Bate +1 212 412 3732

[email protected]


1 March 2012 71

Arch Coal (ACI) 7.25% senior notes of ’20 have widened 70-80bp relative to Consol Energy (CNX) 6.375s and Alpha Natural (ANR) 6.25s since mid-January. We are comfortable that ACI can remain free cash flow positive under some very bearish assumptions and believe investors should consider swapping out of CNX/ANR into ACI 7.25s to pick up the additional yield at current levels.


1 March 2012 72

US HIGH GRADE ELECTRIC UTILITIES

Regulated utilities remain stable Our Overweight recommendation on this defensive sector reflects its strength

during periods of market volatility. As market conditions stabilize in 2012, we expect the high grade electric utility sector to perform in line with the Credit Index.

At current spreads, we favor BBB and crossover regulated utilities, and utility holding companies with predominantly regulated business models.

Given continued weak pricing conditions, we remain cautious on unregulated generation subsidiaries and diversified holding companies with larger unregulated generation businesses.

Summary of investment view

Sector strengths include: expected moderate electric sales increases in 2012 on a weather-adjusted basis; continued stable financial metrics and credit ratings; continued constructive regulatory support for recovery of ongoing capital investments; and a continued focus by the industry on balanced risk strategies that emphasize regulated utility investment. Increasing capital investment and the decline of bonus tax depreciation from 100% in 2011 to 50% in 2012 will likely increase new debt issuance in the sector this year to $33-35bn, compared with $31bn in new debt issuance in 2011.

Principal uncertainties include increased M&A activity and continued headline risk related to the aggressive program by the U.S. Environmental Protection Agency to develop and implement new regulations on power plant air emissions, cooling water intakes, and coal fly ash disposal. The large M&A transactions announced or completed in 2011 have been conservatively structured, and most have been credit neutral or positive. Continued successful completion of the pending transactions will likely encourage further consolidation within the industry. New EPA regulations will likely result in the early retirement of 45-60 GW of primarily older, coal-fired generating capacity and create additional capex requirements for other plants. These costs should be recoverable by the regulated utilities, but will pose additional challenges for certain unregulated coal-fired generators given the current weak power pricing environment.


Buy Duquesne Light Holdings (DQE)(OW) 5.90% bonds due 2021, quoted at +290. Rated Ba1/BBB-, this crossover holding company with a predominantly regulated utility transmission and distribution business benefits from a constructive regulatory environment, an attractive service territory, and favorable provider of last resort arrangements.

Buy Metropolitan Edison (FE)(MW) 7.70% bonds due 2019, quoted at +135. Met Ed is a low-risk, regulated transmission and distribution utility with a supportive regulatory environment in Pennsylvania and manageable capex requirements.

Jim Asselstine +1 212 412 5638

[email protected]


1 March 2012 73

EUROPEAN HIGH GRADE OIL & GAS

Oil price bias and disposals support sector ratings Oil price bias and upstream growth to strongly support cash flow generation.

Gas negotiations and LNG could act as supports for sector earnings.

Continuation of integrateds becoming less integrated.

Asset disposals to continue to fund increased capex and exploration spend, supporting credit metrics and liquidity.

A defensive play in a volatile market despite isolated sovereign risks.

Summary investment view – Overweight Our positive outlook for the European HG Oil & Gas space is supported by expectations that WTI and Brent prices will improve through 2012 and into 2013. Indeed, our commodities team forecasts a rise of 24% and 5% in Brent and WTI, respectively, in 2012. Although somewhat offset by soft US natural gas prices that are unlikely to improve (Figure 1), we expect the oil price impact to dominate, with gas sales tied to the oil price. We highlight that overall EBITDA and thus cash flow growth in the oil and gas space remains strongly linked to the price of oil (see Figure 2) due to the dominance of E&P in cash generation, fostering cash flow stability or growth throughout the year.

Many of the names in our coverage universe expect to continue increasing development spending, therefore we see rising production from oil and, in particular, natural gas. Our European Oil and Gas names have earmarked significant targets for increasing production, especially given the lost production in 2011 due to instability in the MENA region. This was particularly marked for ENI, OMV and Repsol, which lost 8%, 7% and 9%, respectively, of their production output by (LTM) end-9M 11 vs. FY 10. We view the pace of expected production growth – 6% on average – coupled with our expectations of oil price buoyancy as positive for earnings and ratings. We highlight that the agencies require production targets to be met for rating stabilisation over the coming years. We expect all of our European Oil and Gas names to increase exploration spending through 2012 as the focus on upstream production growth, and achieving higher reserve replacement ratios, continues.

Gas-price negotiations will likely affect Europe’s second largest gas supplier, Statoil, with 2012 being a key year for contract re-negotiations. A continuation of offering European customers gas-linked contracts could be a source of competitive advantage over Gazprom, which has been reluctant to move away from oil-indexation. We are constructive on the realisation of higher LNG prices, which should support the credit profiles of Shell, Total and BG. Indeed at the FY 11 stage, BG Group raised its FY 12 profitability guidance by over 30% owing to favourable trends in the energy-hungry Asian market, in particular. We note that with only 1.6 Bcf/d in liquefaction capacity additions expected (compared to 10 Bcf/d in 2009/10) versus re-gasification capacity growth of 7.5 Bcf/d (compared to c. 20 Bcf/ in 2009/10), there is further upside potential in LNG cargoes until supply additions occur mid-decade.

Challenging refining and marketing conditions will likely continue. Against this tough backdrop, we have noted for some time that the integrateds have been attempting to become less integrated. Overall, if successfully executed, we would expect sector returns and cash flows to be supported owing to R&M’s capital intensity.

Emmanuel Owusu-Darkwa, CFA +44 (0)20 7773 7467

emmanuel.owusu-darkwa @barcap.com


1 March 2012 74

We have expectations of modest positive FCF across the sector. This is owing to increased capex negating the benefits of high oil prices and production increases. However, asset disposals should help to fund the redeployment of resources from lower returning upstream and downstream assets back towards higher margin upstream and sources of future growth through exploration, allowing credit metrics to remain within guided gearing bands. It is only in the case of BG Group where we expect significantly negative FCF in 2012. We highlight that while BG has earmarked USD5bn in disposals out to 2013, it is the successful execution of this which will be important for BG’s ‘A’ rating at S&P. While divestures would support already sound sector liquidity, we believe market access should not be a problem.

In our view, the European sovereign debt crisis will have a limited effect on sector spreads, with ENI and Repsol the key laggards in this regard due to associated linkages with the periphery. In our view, while not related to fundamentals, Total could suffer from the technical pressure of being a ‘French corporate’, with its CDS spreads being well bid on French sovereign widening.

Overall, we expect Oil & Gas Sector fundamentals to remain robust and better positioned to weather macroeconomic and sovereign-related volatility compared to higher-beta sectors. We believe the sector will outperform benchmarks to the extent that market conditions and spreads remain volatile. Underperformance is likely in the improbable scenario that a credit rally presides over the next six months. We therefore recommend Overweighting High Grade European Oil & Gas.

Investment recommendations Switching out of BG Group and into BP (in euro). We need to see evidence of

production growth translating into CFO growth that is ahead of capital expenditure growth before we can be more confident on BG building some rating headroom. In euro cash, we believe that BG trades tight across the curve versus BP. In sterling, we highlight that BG trades tight owing to ‘home country bias,’ while BP suffers from overstated concerns around Macondo liabilities, in our view. It is only in dollars where we currently see value, but this could be offset by further dollar issues.

Buy Repsol 5y CDS. Owing to limited upside in CDS relative to other sector names, spread volatility in Europe and ongoing tail risk on YPF in Argentina, we recommend buying protection at current levels. In our view, 5y CDS (185/195) would trade in the high 200s at the very least if an expropriation of YPF were to occur.

Sell BP 5y CDS against buying 5y CDS protection on Total. We expect BP's spreads and ratings relative to its ‘AA’ peers to narrow should a favourable Macondo settlement be reached, as it would have to be agreeable to BP in the light of its spill role and liquidity. We believe a settlement is therefore a potential source of positive event risk ahead of the trial that is set to start on 5 March 2012. We therefore recommend positioning adequately and selling 5y CDS. We recommend a CDS pair trade that involves selling BP 5y CDS against buying protection on Total (Aa1Stbl /AA- Stbl), for which 5y CDS trades tight – 60/64 – versus the sector.


1 March 2012 75

EUROPEAN HIGH GRADE UTILITIES

Modest expectations Political and regulatory risk, the debt crisis and M&A to affect spreads.

Challenging conditions in generation and supply offset by a reduced amount of regulated income.

Ratings risk is skewed towards the downside with risks of a number of ‘BBB’ ratings.

Market Weight balances recessionary risks and peripheral exposure.

Summary investment view – Market Weight In our opinion, policy and regulation could affect utility credit spreads and ratings significantly in 2012. Taxation and tariff deficit issues in Spain and the French elections for EDF are key risks. We believe that the EU debt crisis will continue to weigh on companies with further near-term downgrades owing to sovereign rating linkages. Rating risk is skewed towards the downside. We highlight that weak credit metrics and deteriorating operating conditions in generation and supply that cannot be offset by self-help measures are likely to further pressure issuer ratings, with some names at risk of falling off the ‘A’ rating cliff into the ‘BBB’ rating range. While, as a sector, integrated utilities have become less defensive than investors have traditionally come to expect, owing to network asset sales, regulated income still provides stability to sector cash flows. We believe event risk from M&A will have differentiated effects depending on companies placing at various rating levels, although we expect limited large-scale transactions.

We have a preference for names that: 1) have ex-euro state owners; 2) face limited adverse political and regulatory risk; 3) are expected to improve credit metrics; 4) are exposed to positive event risk (eg, disposals and gas contract renegotiations); 5) have strong liquidity preventing the need to issue senior debt; and/or 6) trade cheap despite expected fundamental improvements, while being free from near-term constraints from sovereign ratings (such as Gas Natural Fenosa (Overweight)).

Paying respect to excess return performance during 2011, while euro credit indices were dominated by peripheral issuers, utilities still managed to marginally beat the Pan-European Credit Index market by 17bp. Despite the market rally that has accompanied the start of the year, we remain cautious on the periphery in the near term. However, owing to recessionary risks, where utilities will fare better than most, we believe a ‘Market Weight’ recommendation is appropriate.


Switch out of Iberdrola and Enel into Gas Natural Fenosa across the EUR curve. We believe Iberdrola and Enel, through Endesa, are significantly exposed to near-term risk regarding the tariff deficit and special taxation in Spain due to their larger presence in electricity and exposure to likely taxed generation technologies. Iberdrola and Enel’s ratings are already weakly placed due to leverage being at the weaker end of agency guidance for their low ‘A’ ratings. Further, Iberdrola’s ratings would fall on hypothetical Spanish sovereign cuts before Gas Natural Fenosa is affected, given the ratings difference (A-/A3 versus BBB/Baa2, respectively). Enel faces the near-term risk of a BBB+ rating owing to Italy’s downgrade at S&P to ‘BBB+’ and its material refinancing

Emmanuel Owusu-Darkwa, CFA +44 (0)20 7773 7467

emmanuel.owusu-darkwa @barcap.com


1 March 2012 76

need in 2012. We note that Gas Natural Fenosa was the top utility performer in euro cash. In our opinion, Gas Natural Fenosa’s credit profile has benefited from a recent deal with Sonatrach on gas contracts and is a standout improving credit story with debt reduction and higher ratings a core feature of its strategic plans. We particularly recommend switching out of Iberdrola 4.125% EUR’20s into Gas Natural Fenosa 4.5% EUR’20s to pick up 77bp in z-spread and switching out of Enel 4.0% EUR’16s into Gas Natural Fenosa 4.375% EUR’16s to pick up 40bp.

Buy United Utilities plc CDS. Within United Utilities Group plc, the most liquid CDS contract references United Utilities plc and is therefore at risk of adverse movements on a potential leveraged takeover of United Utilities Group plc because S&P rates United Utilities plc only one-notch above sub investment grade. We believe 5y CDS (74/79) is too tight for a BBB-/Baa1 credit and see limited downside potential from buying protection at current levels in this event risk trade.


1 March 2012 77

ASIA HIGH YIELD COAL

Getting too hot We remain constructive on the fundamentals of the Indonesian coal sector. Higher

production targeted by most companies should fuel cash flow growth in the near term and support stable to improving, albeit slight, credit profiles.

Despite our constructive outlook, we believe bond valuations look fair to rich given the rally YTD, high cash prices and potential supply risk. As such, we revise our sector weighting to Underweight from Overweight.

Summary of investment view Supply shortages to persist: We expect the coal supply deficit in Asia to persist in 2012, driven by domestic shortages in major consuming countries such as India and Japan. Export growth from Australia and Indonesia should narrow the supply and demand gap, although any disruptions in these countries could exacerbate the supply tightness. These industry dynamics are likely to support high coal prices in the near term, even if prices are likely to decline from 2011 levels. Our commodities research team is forecasting the Newcastle thermal coal price to average USD112/tonne in 2012 versus USD120/tonne in 2011.

Stable credit profile trends: We expect the credit profiles of companies under our coverage to be stable to slightly improve in the near term. Cash flows should strengthen on higher production, although this may be partly offset by higher debt taken to fund expansion needs. Companies are targeting 10-15% growth in coal production in 2012. Most issuers reported strong liquidity positions at end-3Q11. The only exception was Bumi Resources, although we think the recent refinancing of its USD600mn short-term debt through a four-year bank loan addresses its liquidity concerns.

Growing pains: Plans by the issuers to aggressively grow their businesses could pose risk, especially if funded by debt. Adaro and Indika have acquired assets in the past few years and indicate they will opportunistically continue to do so. Berau Coal and Bumi Resources have focused more on organic growth, although we expect increased capex in the near term to support higher production and investments in non-coal mining businesses.

Bond supply risk? Yield tightening and limited new HY issues in Asia YTD make it an ideal time for Indonesian coal producers to issue bonds, in our view. Berau Coal has already announced a plan to raise USD500mn. We believe other companies may opportunistically come to the bond market to fund expansion needs (ie, Adaro/Indika) or to refinance high-cost debt (Bumi Resources).


Sell Adaro ‘19s (Underweight). The bonds offer one of the lowest yields among Asian HY bonds. While we view the company’s credit profile as relatively stable in the near term, we see higher downside risk on the bonds than upside potential given tight valuations and the company’s growth ambitions.

Switch from Indika ‘18s (Underweight) to Indika ‘16s (Market Weight). The yield curve on the bonds is inverted. We expect this to normalise over time. Further, the two bonds are pari passu to one another and share the same key covenants.

Erly Witoyo +65 6308 3011

[email protected]


1 March 2012 78

ASIA HIGH GRADE ENERGY

Constructive outlook for upstream producers; event risk manageable

We remain constructive on the Asia Oil and Gas sector and in particular upstream producers on the back of elevated oil prices. We expect earnings to improve in 2012, largely due to higher realised oil prices and increased production.

We think merger and acquisition event risk remains elevated but is mitigated by the strong credit profiles of issuers as well as adequate ratings headroom to accommodate a moderate increase in debt-funded leverage.

Summary of investment view Supportive crude oil prices: We believe credit metrics for the E&P sector will remain stable as a result of elevated commodity prices. We forecast Brent and WTI prices to average USD115 and USD110 in 2012, respectively. Our commodities team also believes the potential downside to oil prices will not be as severe as during the 2008-09 cycle, and sees support at the USD90 level even in the event of a severe economic downturn. E&P operators are natural beneficiaries of high oil prices, so we expect earnings to remain underpinned. However, for operators with formula-based (PTTEP) or government-controlled (Petronas for gas output) selling prices, earnings growth may be less well supported.

Elevated but manageable event risk: We expect most E&P operators under our coverage to be acquisitive in 2012 given their aggressive targets for increased production and replacement of reserves. The risk of debt-financed acquisitions is, however, mitigated by the strong credit profiles of companies in the sector as well as a focus on acquiring assets rather than oil and gas companies due to rising competition and difficulties in obtaining regulatory approvals from governments.


Overweight Reliance Industries: We expect the credit profile of Reliance to remain stable in 2012, especially after the sale of its stakes in KGD6 to BP. The sale should likely offset some of the near-term risk of decreased production output from the gas wells, although we do not expect production in the KGD6 gas fields to improve until 2014/2015 at the earliest. Despite the recent announcement of a c.USD2bn share repurchase programme, liquidity at the company remains strong, with cash balance at US$15bn at the end of Dec 2011.

Market Weight CNOOC: We continue to view the CNOOC ’21s as a core position in our coverage universe, given the company’s strong financial and operating profiles compared with other Asian oil and gas companies. Absent any large acquisitions, we believe CNOOC does not require external debt as it is generating sufficient cash flows to fund its planned capex requirements.

Timothy Tay, CFA +65 6308 2192

[email protected]

mailto:[email protected]�


1 March 2012 79

ASIA HIGH GRADE UTILITIES

Stable outlook, fuel cost remains key credit driver We remain cautious on Asian Utilities as we expect input costs to remain high for the

power and gas utilities in 2012, albeit we anticipate continuing strong government support due to low reserve margins.

We expect inflation concerns and slowing growth to weigh on earnings; the ability to pass on rising costs remains a concern in Malaysia, and to a lesser extent, in Korea.

Summary of investment view Elevated fuel costs continue to put pressure on operating margins: We expect input costs to remain high for electric and gas utilities in 2012. Our commodity team’s forecast for the Newcastle coal price for 2012 is USD120/t, compared with an average of USD125/t for 2011. Similarly, the regional LNG gas price, which is referenced to the crude oil price, is also expected to stay elevated. As witnessed in the past year, high input prices were the reason for poor operating earnings among the Korean and Malaysian utilities as they do not benefit from an automatic pass-through mechanism. In our view, the likelihood of an automatic fuel pass-through mechanism being implemented in the near term remains low, given the governments’ motivation to contain inflation, especially with elections looming in both Korea and Malaysia in 2012.

Capex continues to be high in the medium term: Capex is expected to remain elevated for the sector in the medium term as countries such as Malaysia and Korea remain focused on both improving their reserve margins and diversifying their fuel source for generation. KEPCO in particular has provided guidance of KRW15-16trn per year for the next few years as it embarks on an ambitious nuclear build-out plan, which would see several nuclear plants being built. We expect some incremental supply coming from the companies such as KEPCO with large capex programmes.


Overweight Korea Hydro & Nuclear Power Co: KHNP benefits from strong support from the Korean government and has the strongest credit profile among the Korean quasi-sovereigns. As a predominantly nuclear operator, it also has the lowest generation cost per unit and is not exposed to carbon fuel prices like other thermal gencos. This will support the company’s earnings and credit profile in the event of volatile energy prices, in our view.

Underweight Tenaga Nasional: We have a cautious view on Tenaga’s credit profile in 2012 on uncertainty surrounding its gas supply from Petronas. TNB’s operating expense increased substantially in 2H11 after a 20% decline in gas supply from Petronas, which the company said incurred an additional MYR300mn per month in fuel costs. While the recently announced plan to share the incurred increased fuel cost in 2011 between Tenaga, Petronas and the Malaysian government mitigates the deterioration of Tenaga’s credit metrics, we believe that credit metrics will continue to be under pressure until a permanent solution is found by all parties involved.

Timothy Tay, CFA +65 6308 2192

[email protected]



1 March 2012 80

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1 March 2012 81

EQUITIES


1 March 2012 82

AMERICAS INTEGRATED OIL

Our favorites include SU, HES, and IMO; Supermajors will likely underperform

Our base-case scenario is that oil (Brent) could continue to trade mostly in the range of $100-120 per barrel over the next 12 months, while the North American gas market will remain challenging and could average $3.0-4.0/mcf during the same period.

We estimate that the sector is currently reflecting a long-term oil price assumption of approximately $85-90 per barrel.

Our favorites include Suncor Energy, Hess Corporation, and Imperial Oil.

We believe the Supermajors will underperform other energy subsectors in 2012.

2012 oil demand and supply growth should be largely balanced Despite our concerns about the global economy’s uneven recovery, we maintain our Positive sector view. Excluding Libya, we estimate global oil supply capacity will rise 0.5-1.0 million barrels per day (mmb/d) in 2012; our worldwide oil consumption growth assumption is approximately 1 mmb/d. We also think that ongoing political instability in Syria, Yemen, and Egypt will likely lead to some production loss this year, perhaps 200-300 mboe/d, collectively, while we estimate Libya production will rise by 500-700 mb/d y-o-y. Also, we expect Saudi Arabia, if needed, will make room for the resumption of Libyan oil production. On the other hand, risk of Iranian supply disruption is small but seems to be growing. Overall, absent an unexpected severe double-dip global recession, we expect the global oil market will be largely balanced and oil prices (Brent) will remain in the relatively narrow range of $100-120/bl for the bulk of this year. Meanwhile, we think the major oil shares are currently reflecting a long-term oil price deck of $85-90/bl. Thus, we think if oil prices remain in this elevated range over the next several quarters, we could see the major oil share valuations move higher, reflecting the long-term oil price assumption of $90-95/bl.

Suncor Energy (SU.TO) Suncor Energy (SU.TO; 1-Overweight/1-Positive) is currently our favorite name among the Americas-based major oil companies, primarily shaped by its progressing reliability in production and utilization level at its core oil sands operations, potential improvements in cost structure and unit margin using steam-assisted gravity drainage (SAGD) production over mining, attractive valuation, and high oil price leverage. We currently estimate production growth of 5.6% per year from 2011 through 2016 with oil sands production increasing at a faster clip of 7.4% as the company’s Firebag projects come on stream.

After several years of poor operating performance in its core oil sands operations, Suncor has gradually improved its operating performance on both production volume and upgrader utilization rates. Since mid-2010, Suncor’s operated oil sands production has averaged close to 330 thousand barrels per day (mb/d) with the exception during periods of planned major turnaround activities compared to 283 mb/d in 2010, 291 mb/d in 2009, and 227 mb/d in 2008. Utilization levels at the upgrader have also substantially improved, averaging above 85% compared to approximately 71% in 2010, 76% in 2009, and 64% in 2008.

Paul Y. Cheng, CFA +1 212 526 1884

[email protected] BCI, New York

Sector View

1-POSITIVE

Suncor Energy (SU)

Stock Rating 1-OVERWEIGHT

Price Target CAD 48.00

Price (28-Feb-2012) CAD 36.28

Potential Upside/Downside +32%



1 March 2012 83

We believe that SAGD production will play an increasing role in future growth with the Firebag and McKay River operations, which could help lower the company’s overall cost structure. In light of the rapid advancement of in situ technologies (such as solvent-based/assisted extraction methods) over the years, we think the cost differential versus traditional open mining operations could widen over time. We currently estimate the unit costs will gradually reduce to $40.2/bl in 2014 from $44.8/bl in 2011.

We also think the stock is inexpensive. On the basis of EV/2013 EBIDA, SU is currently trading at 6.8x compared to the Americas-based major oil companies’ median average of 6.5x and the large-cap Canadian oil & gas companies’ average of 6.1x. Between 2006 and 2010, SU traded at a 3.9x premium to the integrated oil companies and a 2.5x premium to the large-cap Canadian oil producers. Although we do not think the stock will regain its entire prior premium, we do think the stock should trade at some premium given its larger oil sands exposure and correspondingly more predictable and stronger long-term reserve and production growth profile. On a P/NAV basis, we estimate SU is currently trading at a 13% discount to our estimated NAV value of $42 per share versus an average discount of 9% for the Americas-based major oil companies.

Hess Corporation (HES) Although the company’s guidance for 2012 is weak, we maintain our 1-Overweight/ 1-Positive rating as we see the valuation gap between Hess and other large-cap E&P companies as too wide. We believe all the near-term bad news has now been reflected in the share price. Potential near-term catalysts include news of farm-down of its Ghana discovery (1Q12), good 1Q12 production volumes (late April), drilling results at Ghana (2Q-4Q12), and drilling results at Utica (2H12).

From a valuation standpoint, we estimate HES shares currently trade at 5.0x EV/2013 EBIDA, the lowest in our coverage, compared with the large-cap E&P average of 6.1x and the Americas-based major oil companies’ median of 6.5x. At $100/bl oil (Brent), we estimate the shares currently trade at a 29% discount to our $93 per share NAV estimate compared with the Americas-based major oil companies’ average discount of 9%. On an EV/barrel of proved reserve, we estimate HES trades at $16.3/boe, or a 59% premium to its 2010 PV10 estimate, versus the large E&P companies trading at a 103% premium and the Americas-based integrated peers at a 96% premium.

That said, we believe the burden of proof is clearly on management: Hess needs to convince the market that the weak operating performance of the last several quarters is fully transitory and the 2012 production guidance is merely the company erring on the ultra-conservative side — essentially, we believe it needs to meet or exceed the high end of its production guidance range (370-390 mboe/d, excluding Libya). We would also view favorably management revisiting its 2012E capex and cutting back on exploration spending. Based on our analysis, an appropriate level of exploration spending would be no more than $500-600 million annually given the company’s production level and sizable position in the non-conventional shale oil plays. We do not believe the market is willing to tolerate the company consistently outspending its cash flow by 20-30% while only achieving 3-5% annual production growth; the market is seeking either strong free cash flow and high return or strong production growth. Finally, we would like to see Hess improve its disclosure related to its competitive position in the Bakken operation, including the relative cost position and the EUR/well, among others, in view of the market’s current general skepticism toward the company.

Hess Corporation (HES)


Price Target USD 90.00

Price (28-Feb-2012) USD 65.86



1 March 2012 84

Imperial Oil (IMO.TO) Despite the recent share outperformance since December 2010 (up 18% versus a gain of 4% for the North America majors and an increase of 9% for the S&P 500), we continue to view IMO.TO stock constructively and believe that there still is potential upside to the name.

We expect that the first phase of the company’s core Kearl project will come on schedule and on budget for a late 2012 start-up, despite previous hiccups in module transportation as well as potential delays operating in the winter. Coupled with the recent sanctioning of the Nabiye and Kearl expansion projects set to come on-stream by late 2015, we think the company is at the start of a major growth trend that could last through the next two decades. We currently estimate the company’s total net oil sands production will increase to approximately 380 mb/d in 2016, up from 187 mb/d in 2011. Management currently targets to double gross production of approximately 300 mboe/d in 2011 to 600 mboe/d by 2020. We believe IMO will be one of the fastest growers in our coverage with oil and gas production set to rise by more than 11% per year between 2011 and 2016E and roughly 6-7% per year average growth rate through 2020E.

We reiterate our 1-Overweight/1-Positive rating on the stock due to its strong long-term growth potential and attractive valuation. At $100/bl oil (Brent), we estimate the shares are currently trading at an 11% discount to our C$54 per share NAV estimate compared to a premium of 8% on Husky Energy (HSE) shares and an average discount of 9% for the Americas-based major oil companies group. On the basis of EV/barrel of proved reserve, we estimate the company is trading at C$15.3/boe, an 83% premium over its 2010 PV10 estimate compared with a 145% premium for HSE, an average premium of 96% for the Americas-based major oil companies, and an average premium of 103% for the large-cap E&P companies.

Imperial Oil (IMO CT / IMO.TO)



Price (28-Feb-2012) CAD 47.89



1 March 2012 85

EUROPEAN INTEGRATED OIL

Upstream bias Our favoured companies remain those with leverage to oil prices, and with

differentiated growth or exploration profiles. Our current favourites include BG (PT 1800p), Statoil (PT NOK180) and Galp (PT EUR19.65).

Higher cash flows largely redirected to capex to grow production rather than near term shareholder returns .

Valuations remain tightly focused in 2012 with only a 15% spread in 2012E cash flow multiples between the top five companies by market capitalisation.

Our top picks of the integrated oils for 2012 are BG Group, Galp, Statoil and Repsol YPF. Our investment choices are focused on companies which we expect to show the highest growth and the biggest gearing to drill bit success. These investments are also oil price leveraged and both ourselves and our commodity team continue to see the balance of risk to the upside for our Brent price assumption. The European integrated sector is currently trading on a 2012E PE of 8.0x, a 16% discount to the market – towards the top end of the normal range of a 10%-30% discount. However, with the sector offering a c.10% yield premium, this sector specific security of shareholder return may sustain performance and we retain our 2-Neutral sector view.

The pursuit of growth The key feature of the recent 2011 full-year results presentations was that higher operating cash flow was primarily being used to increase capex (both organic and inorganic) or to reduce gearing rather than being returned to shareholders. Dividends in 2011 were up an average of 4% and capex an average 21%. Clearly, without investment there is no growth and as we have shown in previous research, Integrated Oil Valuation 2011 typically those companies with higher production growth have out performed those offering high dividend yields by 12% pa over the past 10 years.

Unfortunately, the take away from the results season was that less production growth was being delivered by a higher level of capex than our expectations. We started the year expecting 2012 to be a good year for production growth with the return of Libyan volumes

Lucy Haskins +44 (0)20 3134 6694


Rahim Karim

+44 (0)20 3134 1853 [email protected]

Barclays Capital, London

Figure 54: The rising cost of growth

100

150

200

250

300

350

400

2000 2002 2004 2006 2008 2010 2012 2014

% Capex Dividends & share repurchase Production growth

This chart shows, rebased to 100, the relative trends of capital

expenditure, cash returns to shareholders and production growth. When the group saw

excess free cash flow in 2004-08, share repurchase featured

heavily. Now the group have rebased cash returns and are

typically growing these in-line with production. Excess free cash

is used to pursue inorganic opportunities or reduce gearing.

Source: Barclays Capital estimates

Sector View

2-NEUTRAL


1 March 2012 86

and the resumption of activity in the Gulf of Mexico. On average, we anticipated sector volumes up by 4.9%. On average, post the result updates we have revised down our production growth forecasts by 1.2%, as shown in the chart below, and we now see overall growth for the sector of 3.7%. Part of this relates to higher 2011 volumes than we anticipated, but partly a slower ramp up of new projects and the impact of lost Syrian and Yemeni volumes.

Figure 55: Production growth, %

-5

0

5

10

15

20

25

30

35

40

BP Shell Total BG Eni Galp OMV Repsol Statoil

% New forecasts Old forecasts


There was evidence however, that the higher capex over the past two years may at least be feeding through into future growth. Reserves Replacement was over 100% for the second year running. We estimate that the 2011 reserves replacement rate on an SEC reported basis was 127% and adjusted for PSC price effects and acquisitions was 112%.

Given this focus on investment to deliver growth in both cash flow and production, our preference remains for those stocks that have the most potential to deliver on these metrics – hence our Overweight recommendations on BG Group, Statoil and Galp.

Figure 56: Reserves replacement

0

50

100

150

200

250

300

BP RDS TOT BG ENI OMV STL

% Reported Organic



1 March 2012 87

BG Group - Value & Volume A number of companies have signalled that they will pursue a value agenda in their US shale businesses by directing investment away from gas drilling to the liquids-rich part of their portfolio. BG is also taking steps to rein back shale gas volumes but is exploiting the current arbitrage between low Henry Hub prices and strong oil prices in a differentiated fashion. As we had hoped (BG Group: Henry hub not all doom and gloom, 1 December 2011), BG used its 2012 strategy update to focus on the US LNG export options it is building for itself both through the Sabine Port contracts and plans for Lake Charles. The group also focused on the "excellent profit momentum" offered by its existing LNG business as hedges unwind in 2013. With the group's now higher guidance for 2012 and supply/demand balances looking forward, we have lifted our estimates for LNG EBIT by an average 20% pa out to 2015. This resulted in a 6% lift in our sum of the parts price target to 1800p/share. We have as yet to include any value for the US export options, but the Cheniere contract alone could add an incremental 130p to our NAV. We continue to see BG as a key integrated holding and rate the shares 1-OW.

Statoil – Upstream Edge Statoil now appears to be demonstrating an upstream edge. Portfolio action has seen the group reduce its downstream exposure whilst building its opportunity set upstream. More significantly, the group is now replacing its reserves organically even in the mature NCS. This means Norway is a now a safe haven for reinvestment dollars. We would also see risk-on upside offered both by the group's exploration programme and our 2012 $110/bl Brent price assumption (Energy Flash: Oil: Risks now biased to the upside, dated 8 February 2012). We expect 5% growth in entitlement volumes in 2012 vs. a sector average of less than 4% growth. This growth will be delivered with only a 6% lift in spend for 2012. With this modest increase in capex, the group has the financial flexibility to grow its dividend by 4% to NOK6.5/share. This implies a 4.3% yield on this payment, which goes ex on 16 May. Statoil is trading currently on a 2012E EV/EBIDA of 5.0x, a 17% discount to the sector which looks inappropriate given the turnaround story upstream. We rate the shares 1-OW with 16% potential upside to our NOK185 price target.

Galp – Delivery to become important We continue to see Galp as a significantly de-risked investment for 2012. The group's recent capital raising and sale of a 30% stake in its Brazilian assets for $4.8bn to Sinopec implies a price net to Galp of its Brazilian portfolio in its entirety of $12.5bn. When the deal completes early in 2012, gearing will be reduced from 119% as of end 4Q to below 20% on a fully consolidated basis. Now appropriately financed, we believe the group is set to deliver the best top and bottom-line growth story of our coverage set. At the 4Q results stage, the company refrained from providing any major update on its strategy, waiting for its Capital Markets Day on 6 March. At this stage we expect the company to announce its full-year 2011 dividend, and currently forecast EUR0.20/share. We also anticipate that the company will provide an update on reserves and resources, longer-term production guidance and the progress being made in Mozambique. The Sinopec deal has de-risked 55% of our estimate of sum of the parts and 83% of the current share price. We see 51% potential upside to our EUR19.65/price target and rate the shares 1-Overweight.

BG Group (BG/ LN / BG.L)


Price Target GBP 18.00

Price (28-Feb-2012) GBP 15.32


Statoil (STL NO / STL.OL)


Price Target NOK 185.00

Price (28-Feb-2012) NOK 160.50


Galp (GALP PL / GALP.LS)


Price Target EUR 19.65

Price (28-Feb-2012) EUR 13.02


http://my.barcapint.com/RSL/jsp/popupContainer.jsp?pageTitle=Barclays%20Capital%20Live&logoUrl=%2FRSR_S%2Fhtml%2Fbcllogo.html&targetUrl=%2FRSR_S%2Fhtml%2Fbclwait.html%3F%2FDDS%2Fcgi-bin%2Fnph-dvMaintenance.pl%3FpubId%3D1770534�



1 March 2012 88

EUROPEAN INTEGRATED OIL

Sasol: Strong results & growth We believe Sasol is poised to deliver strong FY12 results and further growth. Expansion relates to around 25% of our R455 DCF valuation for Sasol: the major elements of expansion include GTL, synfuels expansion / optimisation and gas. Risks include exiting from Iran (4.7% of group operating profit) on a timeous basis and at above book value of R3.4bn.

We forecast 1H12 HEPS of R24.00 versus Bloomberg consensus of R22 – we forecast FY12 HEPS of R51.70 versus Bloomberg consensus of R46 (range R42-53). Sasol is due to release 1H12 results on Monday 12 March 2012.

Key issues to watch for in the 1H12 results. Project progress – continuing debottlenecking at Oryx GTL plus progress on Uzbekistan

GTL, the proposed US ethane cracker and an update on slower production growth at US shale joint ventures with Talisman.

Outlook for chemicals demand and pricing, given cautious data in the CFO update.

Cash fixed cost inflation controlled to below PPI increases.

Stable synfuels production.

Our 12 month target price for Sasol of R455 is derived from our DCF analysis (using a 12.6% WACC and a 2.75% long term growth rate). The current share price (R402) reflects an increasing amount of this growth due partly, in our view, to the recent site visit to Oryx GTL in Qatar. However continuing evidence is needed relating to progress on further international GTL projects as well as on other project initiatives.

Qatar site visit: confirmation of positive performance and potential growth We attended the Sasol site visit (December 2011) to its US$1bn, 34k bpd Oryx gas-to-liquids (GTL) facility at Ras Laffan, Qatar. Oryx management expect the current Qatari North Field gas moratorium to end at end 2014/beginning 2015. Oryx is being proactive with its shareholder Qatar Petroleum (QP) to be ready in advance of the moratorium ending, convincing it of potentially improving returns to shareholders and its readiness to expand to 100kbpd at Oryx – a positive in our view. Meanwhile Oryx is targeting running at 112% of nameplate capacity through de-bottlenecking – it is operating at 105% currently.

Sasol is studying technology improvements to its GTL plants including: heat exchange reforming to improve carbon efficiency by up to 10%; a reduction of CO2 footprint by 30%; and a reduction of total cost of ownership by 25%. Plant-wide GTL thermal efficiency could increase from 57% to 61% whilst tonnes of CO2 per bbl final product could improve from 0.13 to 0.10. Catalyst regeneration is also being developed to increase catalyst life plus the development of new generation catalyst distribution to improve catalyst productivity. FT reactor developments include an intensified slurry phase reactor to increase capacity, with a capital saving estimated at around 25%/bl. These developments are important in terms of improving GTL economics in the medium/long term.

Caroline Learmonth +27 11 895 6080

[email protected]

Absa Capital, Johannesburg

Sasol (SOL SJ / SOLJ.J)


Price Target ZAR 455.00

Price (28-Feb-2012) ZAR 401.45


Sector View

2-NEUTRAL


1 March 2012 89

CFO update: Iranian disposal fast-tracked Sasol released its regular CFO update at end November 2011. The major issue in the update, in our view, was Sasol entering into discussions to potentially divest its stake in Arya Sasol Polymer Company.

In the CFO update Sasol also noted the availability of significant volumes of natural gas liquids, and specifically ethane, in the US which has opened up opportunities in the ethane feedstock area for cracker-based chemicals. Sasol recently completed a pre-feasibility study into an ethane cracker with downstream value-added ethylene-derivative units at its Lake Charles site in Louisiana. Sasol has approved the advancement of this project into a feasibility study. The envisaged capacity will be 1.0-1.4mntpa at a cost of US$3.5-4.5bn. The feasibility study is scheduled for completion in 2H13. Returns from this project are expected to exceed Sasol's hurdle rate for the US of 10.4%. Sasol states that synergies exist with other activities on this site.

Valuation metrics Over the past ten years the rand Brent oil price and the Sasol share price have shown a

correlation of 0.96 – ie, very high. We note that the Sasol share price has underperformed the Brent oil price during 2011 to date, but the underperformance has reduced since end September, implying mean reversion.

Figure 57: Sasol share price catching up to Rand oil price in recent months

0100200300400500600700800900

1,000

07/01/2011 11/03/2011 13/05/2011 15/07/2011 16/09/2011 18/11/2011 20/01/2012

Brent oil price (R) Sasol SP, rebased to oil price 1/1/11

Source: Bloomberg, Absa Capital, January 2012

On a simplistic basis South African investors look at a 10x current PER multiple as a "sanity check" for Sasol's share price – interestingly the current PER has only averaged 7.6x on a Bloomberg consensus basis over the past five years. Therefore this is not a scientific metric but gives some indication of underlying local sentiment – the current Sasol PER on our estimates is now 7.8x, implying some future upside.

We also note that currently Sasol’s share price is at 1.8x book – ie, there is upside to the current position given the historical average of 2.5x and strong oil price.

In addition, on a divisional basis we note: (i) strong product prices in South Africa are likely to support strong synfuels revenues; (ii) our view is that a continuation of the oil/gas price differential is likely, supporting longer term GTL economics; and (iii) peak chemical margins support a continuation of strong chemical earnings in the short/medium term.


1 March 2012 90

ASIA EX-JAPAN OIL & GAS

Value in upstream growth, pricing reform may take time

CNOOC (0883.HK, 1-OW; PT HK$21) remains our top pick: Our stock preferences focus on companies with an upstream bias that are also oil price leveraged. CNOOC’s offers good value and returns, in our view, with its high-margin domestic barrels likely to drive 4% pa production growth medium term. Balance sheet strength provides flexibility to acquire new overseas assets or increase dividends.

China remains a structural growth story: China remains a key driver for global oil demand growth partly reflecting demand growth for middle distillates owing to continued industrialisation and urbanisation in the country.

Domestic fuel pricing reform may take time: The prospect that China’s inflation remains above the government’s 4% target this year puts reform of the country’s domestic fuel pricing policy at risk, in our view. Although Chinese refiners’ profitability has improved from recent fuel price increases, expectations of widespread energy policy reforms in the short term seems a more complex proposition than the market may expect. We have a 2-Equal Weight rating and price target of HK$10/share on Sinopec Corp. (0386.HK)

Upstream focus, high margin Chinese barrels

We see a moderation in refining/chemical investment in China, relative to the capacity expansion observed in the past decade, and a greater focus on the upstream, which has provided the highest through-cycle returns for the industry. We expect the China Oils sector to deliver 3%pa upstream production growth in 2011-15E, which is about the global industry average for the same period (Figure 58). Chinese Oil & Gas companies are not immune to the challenges facing the industry with production growth still lower than the 2006-10 average of 6%pa. The lower outlook reflects ongoing decline in onshore and offshore production in China, which is likely to be offset by further overseas assets acquisitions and higher domestic exploration and development capex. Despite some production growth moderation, Chinese barrels remain high margin relative to the industry partly owing to the ability of producers to manage costs and a favourable fiscal regime, which has not materially changed post the resource tax and windfall tax adjustments last year. With upstream costs in China having followed the same trend as the industry, we expect the sector to maintain its margin premium (Figure 59).

China remains a structural growth story China remains a key driver for global oil demand growth, partly reflecting demand growth for middle distillates owing to continued industrialisation and urbanisation in the country (Figure 60 and Figure 61). Lower vehicle sales growth in China last year relates to subsidies for new car buyers being taken away rather than availability of credit (many buyers normally pay cash). A recovery in vehicle sales this year is also likely to be supportive of gasoline demand in the country. We expect Chinese oil demand growth to remain robust in 2012 (China up c0.7 mb/d y/y), partly offsetting declines in the US and Europe. Barclays Capital commodities team forecasts global oil demand growth to be up c1.1 mb/d in 2012.

Scott Darling +852 290 33998

[email protected] Barclays Bank, Hong Kong

Clement Chen

+852 290 32498 [email protected]

Barclays Bank, Hong Kong

CNOOC (883 HK / 0883.HK)


Price Target HKD 21.00

Price (28-Feb-2012) HKD 17.76


Sinopec (386 HK / 0386.HK)

Stock Rating 2-EQUAL WEIGHT


Price (28-Feb-2012) HKD 8.78


Sector View

1-POSITIVE


1 March 2012 91

Figure 60: Strong Chinese oil demand growth Figure 61: Driven by diesel demand

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Monthly change y/y in oil demand. Source: China Customs, Barclays Capital Source: China Customs, Barclays Capital

Tight natural gas market We see a tight natural gas market in China with uncertainty around new supply import projects medium term. Natural gas production growth in China has only averaged c14% pa 2000-10. In contrast, natural gas demand growth has averaged 16% pa over the same period and a government target for 240bcm in 2015, implying 15% pa growth, looks increasingly achievable should China meet or exceed power capacity targets. This suggests the country’s natural gas supply/demand balance is very tight medium term; thus, we expect the government to incentivise natural gas investment to manage the country’s natural gas requirements (Figure 62).

Higher inflation may put fuel price reform at risk The prospect that China’s inflation remains above the government’s 4% target this year puts reform of the country’s domestic fuel pricing policy at risk, in our view. China’s current oil product pricing mechanism allows the National Development and Reform Commission (NDRC) to make adjustments in gasoline and diesel prices based on a 4% movement in an average basket crude price over a 22 working day window.

Figure 58: Production growth outlook Figure 59: High-margin Chinese barrels

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Source: Company data, Barclays Capital estimates Upstream cash flow per boe in 2010. Source: Company data, Barclays Capital

China’s inflation remaining above the government’s 4%

target reduces the likelihood of fuel price reform in the country,

in our view


1 March 2012 92

Figure 62: China’s natural gas supply/demand

050

100150200250300350400450500

2008A 2010A 2012E 2014E 2016E 2018E 2020E 2022E 2024E 2026E 2028E 2030EChina Domestic Contracted LNG Turkmenistan BaseMyanmar China Shale/CBM LNG UpsideOther Central Asia Turkmenistan Upside Russia WestRussia East Demand (Low) Demand (Mid)Demand (High)

bcm

China’s natural gas market likely

to remain tight until the end of the decade assuming demand (mid case in figure) growth at

15% pa to 2015E then 4% pa to 2030E

Source: Oxford Institute for Energy Studies estimates, Barclays Capital

Recently there have been suggestions that the NDRC may reduce the adjustment window and change policy so that price changes will be administered by the oil companies rather than the NDRC.1 The proposed new mechanism under consideration is as follows:

Pricing period: Window for fuel price changed from 22 to 10 working days;

Reference price: Crude basket reference price changed to include WTI in addition to Brent, Dubai and Cinta, each weighted by a quarter;

Administration: Company or third party to administer new fuel price changes;

Adjustment range: Current 4% volatility band maintained (although PetroChina suggests this may be lowered to 2%).

Refining losses may continue While the recent increase in domestic gasoline and diesel prices has partly reduced refining losses for Chinese refiners, Sinopec has guided that a further fuel price hike is required for its refining business to break even this year based on the current oil price and may require a gasoline and diesel price ceiling of cRmb9600/ton and cRmb8800/ton, respectively. There is no clarity on timing to implement the above new mechanism, and we believe that the NDRC may implement a new policy based on the relative movement in oil prices relative to the country's domestic fuel price (ie, a large fall in crude oil prices relative to domestic oil product prices may prompt a policy change rather than refining profitability determining reform). Indeed, PetroChina (0857.HK; 1-OW; TP: HK$13.50; Price: HK$11.78 on 28 Feb 2012) believes that the implementation of a new pricing policy (which includes lowering the 4% pricing volatility band) may only occur should the country's inflation fall below the government's 4% target.

Partial fuel liberalisation medium term In the medium term, we believe that partial fuel price liberalisation in China is likely to occur as the government recognises that its consumers need to pay more for their energy and subsidies are not sustainable for an aging demographic. However, we question the timing of reforms and whether strict adherence to any new price mechanism would occur in periods of rising inflation and extreme oil price volatility.

1 See “China Securities Journal: Refined oil prices to be automatically adjusted, NDRC to stop issuing policy changes” of 4 November 2011.

No fuel price reform may extend losses for Chinese refiners this

year with Sinopec the most exposed


1 March 2012 93

US EXPLORATION AND PRODUCTION

Continue to favor oil producers We expect gas-production growth to sharply decelerate, or perhaps reverse, as the

impact of $2-3 gas prices takes hold. Falling gas-supply costs and the attractiveness of drilling NGL-rich wells, however, should prevent a dramatic fall-off in drilling activity. In higher cost areas, activity is moderating and this should allow gas markets to re-establish a long-term equilibrium price of $3.25-4.00 by mid- to late 2013.

We continue to support the purchase of oil-oriented producers and recommend investors avoid most gas producers. Our top picks in the large-cap group are EOG Resources (EOG) and Noble Energy (NBL); in the mid-cap space we favor Denbury Resources (DNR), Plains Exploration (PXP) and Whiting Petroleum (WLL).

Drilling economics suggest gas prices will remain sub-$4/MMbtu Onshore gas supply has accelerated over the past few years – more than filling the gap left by sharply declining Gulf of Mexico (GOM) volumes and lower Canadian and LNG imports. Over the past five years onshore gas production grew at an annual rate of 6-7%. At the same time, annual demand growth has been 1-2%.

Onshore gas supply growth is now slowing in the face of $2-3 gas prices. Recent disclosures provided by large E&P companies suggest that 2012 gas production volumes will be roughly unchanged in 2012 and will fall in 2013 absent a sharp gas-price recovery (by comparison, growth was roughly 7% in 2011 for these same companies). Strong natural gas liquids prices (NGLs can account for over one-third of volumes and more than half of revenue) will likely support gas drilling activity in areas like the Eagle Ford and Southeast Marcellus shales. These liquids-rich targets and falling gas supply costs should prevent a dramatic fall-off in gas production in 2012. We also believe that rising per-well and per-rig productivity will continue to partially offset the impact of declining activity. Finally, with several large producers having taken a longer term view on the U.S. natural gas market, it seems that substantial capital to drill dry-gas prospects may be available even in a sub-$4/MMbtu environment.

To maintain production of around 66 bcfpd (gross), activity levels need to be sufficient to offset a decline of perhaps 16-18 bcfpd. We think that 15-20% of these additions will come from oil-well drilling and most of the rest will come from new liquids-rich gas wells.

Associated gas (gas from oil wells) accounts for an estimated 15-20% of production additions and its share will likely grow to above 20% in the future. Associated gas grew 7% in 2009 and 11% in 2010 after long slow declines and it will likely continue to grow so long as oil prices stay above $75/bbl.

Wet gas production probably accounts for 30-35% of current production additions but we expect it to represent 50-60% of new production by late 2012/early 2013. Wet gas drilling in the core of the Barnett is economic at approximately $3.50/MMbtu; the Cana field, at $2.50/MMbtu; the Southwest Marcellus, at $2.50-4.00/MMbtu; and the Eagle Ford, at $0.00-4.00/MMbtu.

Dry gas production is becoming less important on the margin as oil shales and liquids-rich gas drilling activity rise. We believe that roughly 200-225 rigs are now running in dry gas regions with nearly half of those in the Haynesville field.

Thomas Driscoll +1 212 526 3557


Jeffrey W. Robertson

+1 214 720 9401 [email protected]

BCI, New York

Sector View: North America Oil & Gas:

E&P(Large-Cap)

2-NEUTRAL

U.S. Oil & Gas (Mid-Cap)

1-POSITIVE


1 March 2012 94

A brief review of play-by-play gas-drilling economics suggests that gas production will likely grow in the near term, as long as expected natural gas prices exceed $3.50-4.00/MMbtu. While dry-gas drilling economics may be challenging in many areas (such as the Haynesville), we believe that raising liquids-rich gas drilling will allow gas production to grow given current industry price expectations.

We estimate that 60-80% of production additions from current drilling activity come from fields that are economic below $4/MMbtu. We believe that most E&P companies are assuming long-term gas prices will be at or above $4/MMbtu, so we expect that they will continue to drill in these areas.

Dry gas drilling is challenged and we estimate that about 40% of gas rigs at the beginning of the year were drilling in fields where gas prices of more than $4 are required to earn full-cycle returns. We do not expect drilling activity to fall by this magnitude due to three primary factors: 1) many companies will continue to drill based on a long-term view that gas prices will average more than $4; 2) companies will continue to drill based on the belief that improving recoveries/efficiencies will make these areas economic; and 3) companies will shift activity to more economic areas. The Haynesville field is the single largest area where we think companies need to reduce dry gas drilling activity.

Continue to support oil-oriented producers and recommend investors avoid most gas producers At 6.2x our 2013 debt-adjusted cash flow forecast, the large-cap group trades at a 2% premium to the historical average multiple of forward-year cash flow (our estimates reflect $95/bbl WTI and $3.50/MMbtu HH in 2013). EOG Resources and Noble Energy remain our top long-term, high-quality picks. EOG may have the best oil-shale portfolio in North America and yet it trades at a modest premium to the group, and Noble combines a strong exploration track record with strong North American shale assets. We also recommend Anadarko Petroleum and Apache as well as several balanced (i.e., oil and gas) stocks. We believe the negative impacts of Egypt concerns on APA’s stock price are overdone, while APC’s high-quality exploration portfolio appears to be undervalued.

Among the gas-oriented, or balanced, stocks, we would focus on Devon Energy; in the “not truly gas-oriented” category we like QEP Resources; and in the less than 50% gas group we prefer WPX Energy. We are concerned that Encana, Range Resource, Southwestern Energy and Ultra Petroleum are expensive given our modest gas-price views. We see up to 30-40% downside if investors turn bearish on long-term gas price views. On the mid-cap side, we favor Denbury Resources, Plains Exploration and Whiting Petroleum.

EOG Resources (EOG) We believe the market continues to under-appreciate what would likely be very strong cash flow growth at EOG Resources (1-OW/2-Neu) over the next 12-18 months. Liquids production increased 47% over the course of 2011 and we expect it could grow another 30% this year and likely more than 20% in 2013. The company owns premier oil and liquids-rich assets, including assets in the Eagle Ford Shale, which we believe will provide EOG with multi-year high-return drilling inventory. The recoverable resource potential in the Eagle Ford was just recently raised by 78% to 1,600 million barrels of oil equivalent net after royalty. The Eagle Ford alone represents a $15-20 billion investment opportunity, where direct after-tax rates of return are currently around 80%. Yet, at 6.2x our 2013 debt-adjusted cash flow estimate, the shares trade in line with the large-cap group – we would argue for a premium over the next 12 months.

EOG Resources (EOG)



Price (28-Feb-2012) USD 116.61



1 March 2012 95

Noble Energy (NBL) We expect Noble Energy (1-OW/2-Neu) will likely turn its past exploration success into very strong production and cash flow growth over the next 5-10 years. We think that Noble’s debt-adjusted production per-share growth target of 17% per year is credible and believe that the strong visibility of future growth justifies the current valuation premium. Future growth is likely to come from low-risk U.S. shale assets (Niobrara oil and Marcellus gas) and large development projects in Israel, West Africa and deepwater GOM. A very active exploration program should provide plenty of catalysts throughout the year. NBL shares currently trade at 6.8x our 2013 debt-adjusted cash flow estimate vs. 6.1x for the large- cap group.

Denbury Resources (DNR) Denbury Resources (1-OW/1-Pos) is the most oil-levered company in our mid-cap universe with oil accounting for approximately 98% of wellhead revenues. Production and reserve growth will primarily be underpinned by the implementation of CO2 floods in the Gulf Coast and Rocky Mountains, supplemented by development of the Bakken Shale. The company recently commenced production from new CO2 floods at the Oyster Bayou and Hastings fields in the Gulf Coast. Both are expected to make meaningful contributions to proved reserve growth this year. DNR’s shares trade at 6.3x our 2013 PICF estimate. We believe the company’s long-term, tertiary growth visibility justifies the premium valuation.

Plains Exploration & Production (PXP) Oil accounts for about 55% of PXP's (1-OW/1-Pos) total production and 87% of its total wellhead revenue. Production and reserve growth through 2014 will be underpinned by development programs in the Eagle Ford Shale and California after which start-up of the Lucius project in the deepwater GOM could extend growth visibility beyond 2015. Management estimates its deepwater portfolio could expose the company to more than 500 MMBOE of net resource potential. The most impactful prospect could be Phobos (50% WI), which is operated by Anadarko Petroleum, and could spud late 2012. A discovery at Phobos could represent a significant catalyst for the shares. PXP’s shares trade at 6.1x our 2013 PICF estimate.

Whiting Petroleum (WLL) Whiting Petroleum (1-OW/1-Pos) is the second most oil-levered company in our mid-cap universe with oil accounting for 95% of total wellhead revenues. The company announced a $1.6 billion capital budget for 2012 aimed at growing production 13-19%. Growth will primarily be driven by the continued delineation of leasehold in the Williston Basin that is prospective for the Bakken Shale, Pronghorn Sand and Three Forks play. Based on activity to date, management estimates it has de-risked approximately 45% of its prospective acreage in those plays. The company will also continue to evaluate acreage that is prospective for the Niobrara Shale, Bone Spring and Wolfcamp formations. WLL’s shares trade at 5.3x our 2013 PICF estimate. We believe exploration success that improves future growth visibility will be a key driver of share valuation.

Noble Energy (NBL)



Price (28-Feb-2012) USD 102.48


Denbury Resources (DNR)



Price (28-Feb-2012) USD 20.44


Whiting Petroleum (WLL)



Price (28-Feb-2012) USD 59.94


Plains Exploration & Production (PXP)



Price (28-Feb-2012) USD 44.27



1 March 2012 96

CANADIAN OIL & GAS: EXPLORATION & PRODUCTION (MID-CAP)

Income and growth: the best of both worlds We believe the Canadian E&P sector offers an attractive growth/income profile

(average 12% production growth and 5.5% dividend yield) while providing exposure to Canada’s highest quality resource plays. In our view, the Canadian Mid-Cap names are generally high quality with strong management teams and prudent strategies.

We are forecasting stable dividends for the sector, based on average basic payout ratios of 35-40% and average total payout ratios of 125-140%. Leverage ratios are also reasonable, based on net debt-to-cash flow averaging approximately 1.5x.

With a relatively weak outlook for natural gas, we remain biased toward oil-weighted names. Baytex and Crescent Point stand out as high quality names with strong track records, while PetroBakken remains an inexpensive stock that is rebuilding market confidence.

Resource play exposure with healthy dividends

We believe the Canadian dividend-paying intermediate space is well positioned, with low-risk growth and attractive dividend yields (average 5.5%). The companies have dominant positions in most of Canada’s major resource plays and, importantly, the capital to develop them, supporting production growth averaging 11% in 2012/13E. Dividends are also well supported and should remain stable through 2013. We believe this combination of growth and income should support above-average returns (and lower risk) within the broad energy complex.

Our dividend forecasts imply average basic payout ratios (i.e., dividends as a percentage of cash flow) of 35-40% and average total payout ratios (i.e., dividends plus capex as a percentage of cash flow) of 125-140%. Strategically, virtually every company places dividend stability as a top priority, with production growth being secondary. Leverage ratios are also reasonable, based on net debt-to-cash flow averaging approximately 1.5x.

Given the emphasis on resource play development, our valuation approach balances shorter-term multiples (EV/DACF) along with our going-concern NAV – a methodology which provides for staged development of resource plays in a capital-constrained environment. This model is predicated on our detailed play-by-play economics. Today, we find that the stocks remain expensive relative to most conventional E&P benchmarks, including a 2012 EV/DACF multiple of 8.3x, EV/reserves of $32/boe, and EV/production of $97,000 per boe/d. These robust valuations reflect the premiums ascribed to dividend-paying companies in today’s low-interest rate environment. Also contributing, we believe these companies generally offer high-quality management and prudent balance sheets, along with resource-rich assets and access to capital.

Near-term outlook hampered by oil, gas prices

As with the North American peers, the Canadian energy sector has been impacted by discounted pricing for its crude oil (both light and heavy grades) and the over-supplied natural gas market. In both cases, the application of horizontal drilling with multi-stage completions has dramatically boosted well productivity, contributing to the glut of supply.

Grant Hofer +1 403 592 7460

[email protected] BCC, Toronto

Sector View

1-POSITIVE



1 March 2012 97

On the oil side, this at least appears to be temporary. Warm weather across North America has helped drilling activity over the winter, while strong oil sands production has similarly provided ample supply, backing PADD II crude inventories up to roughly 25% higher than long-term averages. However, as spring break-up sets in (when the melting snow makes ground conditions too soft to operate), refineries return to service, and as the 150,000 bbl/d Seaway pipeline is reversed in June, we expect differentials to narrow back toward more normal levels with crude at US$100/bbl ($3-5/bbl for light oil and $15-20/bbl for heavy oil).

The outlook for natural gas is much more challenging. Natural gas prices in western Canada are currently hovering near C$2.00/mcf as storage levels are at record highs (40% above the five-year average); while rig activity sits similarly high as the sector shifts its drilling programs toward oil and the liquids-rich gas. Our recent analysis (“No easy cure for gas prices”, published February 21, 2012) found that the majority of the natural gas plays being targeted remain economic today (>15% IRR), owing to the high liquids content and increased efficiencies realized through the use of multi-stage frac technologies. Indeed, on average, natural gas resource plays provide a 15% rate of return at a natural gas price of approximately C$1.50/mcf, by our analysis.

With this in mind, it comes as no surprise that natural gas development continues in earnest, although we note that capital budgets in 2012 are, on average, 66% weighted toward crude oil. For this reason we believe that most capex plans are likely to remain unchanged during 2012. However, if gas prices average C$2.00/mcf, those companies most likely to trim capital spending (i.e., highest total payout ratios) include gas-weighted Progress Energy Resources, Enerplus and Peyto. We also expect that Bonavista may choose to pare its spending to preserve the balance sheet.

Shut-ins remain a major topic of conversation in natural gas markets, and Progress has already indicated it will shut-in 10% of its production that is not generating adequate rates of return. Others are also contemplating the same, although on a much smaller scale. On balance, we estimate that gas prices need to be sustained below the C$2.00/mcf level to encourage further shut-ins.

Balance sheets may also come under some pressure, especially given limited natural gas hedging. On average, companies have just 9% of natural gas production hedged for 2012 although a bearish near-term outlook is causing many to revisit their hedging strategies today. The implication is that if natural gas averages C$2.50/mcf this year (in line with the forward strip but below our base case of C$3.00/mcf), we forecast that the average total debt-to-cash flow ratio would grow to 1.9x D/CF, up from 1.7x in our base case.

Investment Recommendations Below we briefly highlight our top investment ideas, including oil-weighted names Crescent Point, Baytex and PetroBakken.

Crescent Point Energy (CPG.TO; 1-OW/Pos) - Crescent Point is Canada’s premier light oil player, with a $14 billion market cap that ranks it firmly among Canada’s senior producers despite production of just 86,600 boe/d (2012E). We like the stock for its focused high netback assets ($51/boe operating netback in 2012E), clean balance sheet (0.9x D/CF), extensive hedge positions (extending into 2015), and conservative guidance. Evidenced by its three light oil acquisitions year to date, the company has aggressively consolidated many of Canada's major light oil resource plays, and is the dominant player in both the Bakken and Shaunavon plays. The company offers an attractive dividend yield of 5.9% and production growth averaging 14% in 2012/13 (4% per debt-adjusted share after factoring

Crescent Point Energy (CPG CT / CPG.TO)



Price (28-Feb-2012) CAD 46.46



1 March 2012 98

in its 59% DRIP participation). The company’s assets offer considerable enhanced oil recovery opportunities, while ongoing operations should support growing value over time as the company exploits its considerable drilling inventory.

Baytex Energy (BTE.TO; 1-OW/Pos) – Baytex remains one of our favourite oil-weighted names owing to its top tier management team and strong balance sheet (1.1x D/CF) underpinned by quality heavy oil asset base. The company targets annual production growth of 8%, and we expect it should be able to deliver with the lowest reinvestment ratio (i.e., percentage of cash flow as capex) in the sector. This growth is complemented by a growing dividend profile: the company has now increased its monthly dividends in each of the past three years and appears positioned to do so again in 2012/13. As a heavy oil producer, the company is exposed to the currently wide heavy oil differentials; however, it employs an extensive hedging strategy to mitigate this exposure. The company’s major asset is in the Peace River Oil Sands at Seal, where heavy oil is extracted using conventional horizontal wells and CSS (cyclic steam stimulation). Other key assets include North Dakota bakken and a large inventory of conventional heavy oil assets in Western Canada.

PetroBakken Energy (PBN.TO;1-OW/Pos) – PetroBakken remains one of our best value names given its exposure to two of the top light oil resource plays in Western Canada (Bakken, Cardium). In 2010 and 2011, the stock came under considerable pressure for both its operational performance and stretched balance sheet. However, a return to strong production growth in the latter half of 2011 combined with several de-leveraging transactions YTD (including two asset sales totalling roughly $530mn in 2012 and a $900mn high yield debt offering) have provided a strong rebound in the share price. The recent sale of 2,900 boe/d of Bakken production to Crescent Point for $427mn was particularly relevant, as it highlighted the vast disparity between its asset value and the shares, which trade at a 40% discount to the transaction value. Looking ahead, the company will seek to continue rebuilding market confidence in 2012 through executing a $700+mn capital program and a solid reserve report. Indeed, with PetroBakken’s recent balance sheet issues now resolved (D/CF levels are now 1.9x), we believe the market will be focused on the stock’s inexpensive relative valuation given its sector-best netbacks ($55/boe operating netback in 2012E) and solid growth (average 10% per debt-adjusted share in 2012/13).

Baytex Energy (BTE CT / BTE.TO)



Price (28-Feb-2012) CAD 57.61


PetroBakken Energy (PBN CT / PBN.TO)



Price (28-Feb-2012) CAD 16.16



1 March 2012 99

EUROPE EXPLORATION AND PRODUCTION

Good, but not over yet 1-Positive sector view: the E&P sector has rebounded from its Q3 11 lows, but we

believe it still offers attractive returns, with an average potential upside of 20%.

Afren is our top pick, as it combines production growth, free-cash flow and an attractive exploration upside at an undemanding price.

M&A activity likely to continue. The most likely targets are those companies with proven geological exposure but distressed finances and depressed equity valuations.

Strong performance, but more to go

Year to date, the sector performance has been strong, rebounding from the Q3 11 lows, with the E&Ps gaining 25%, compared to the wider market’s 10% and 8% for the Euro Integrated Oil names. However, with an average potential upside of more than 20%, based on an oil price of $110/bl in FY12, we believe the sector still offers attractive returns for investors. Our top pick is Afren, which combines cash-flow generative assets together with a few material exploration catalysts from Ghana and Kurdistan. Amongst the AIM-Listed Explorers (ALE), our preference is for Rockhopper, as we believe that the market is currently mispricing the risk associated with the development of its flagship discovery in the Falklands. Finally, we believe that M&A activity is likely to continue across the sector, as a number of companies with proven resources are trading at depressed valuations.

Top Pick, Afren: We believe that Afren offers the most attractive risk-reward profile, as it combines growing production in 2012, which we currently forecast at 45k bl/d in FY12, up from 19k bl/d in FY11, together with an undemanding valuation of 2.1 EV/EBIDA in FY12 and 33% upside to our NAV-derived price target. In 2012, the company will grow its cash-flow from operations by $1.2bn in FY12 from $330mn in FY11 on our numbers, implying a 25% FCF yield which will reduce the company’s gearing to 35% from 11%. Afren also offers two balanced exploration portfolios, which include low-to-moderate risk opportunities in Kurdistan and Ghana, and higher risk exploration prospects in East Africa. We also rate Tullow (PT £18), Premier (PT £5.80) and Salamander (PT £3.50) 1-OWs. We believe Tullow has the most attractive exploration portfolio of the group, with French Guyana now a low-risk asset that could add £6/sh to our NAV over the next few years, as exploration drilling intensifies. This is balanced by several higher-risk basin-opening wells in Mauritania and offshore/onshore Kenya. We also rate Premier and Salamander 1-OW. We believe that, at times, their exploration track record proved to be a drag for the two companies, however, 2012 could represent a turning point as their drilling activities are likely to be concentrated in those areas where they have proven and low-risk geological plays, which offer material potential upside for their shares, in our view.

ALE stocks, M&A trend to continue: We believe that M&A activity is set to continue in the E&P sector, as a number of ALE companies are trading at depressed valuations and could be acquired by larger E&Ps or Oil Majors looking to expand their operations in new areas. Amongst the ALE stock our preference is for Rockhopper (PT £5.80), which over the past two years has fully appraised a large 450MMbl field in the Falklands. The risks associated with the company’s investment case are mainly of a political and technical nature. Nevertheless, we believe they are currently mispriced and, as a result, we estimate 47% potential upside from current levels, even after applying what we believe are conservative assumptions on a 3rd party farm-out, which will bring the much-needed financing to develop the field, and discount to Brent, given the waxy nature of the crude.

Alessandro Pozzi +44 (0)20 7773 4745


Afren (AFR LN / AFRE.L)



Price (28-Feb-2012) GBP 1.39


Sector View

1-POSITIVE


1 March 2012 100

US INDEPENDENT REFINERS

Strong support for the seasonal trade; Could see cyclical upturn pending capacity shutdowns

We recommend overweighting the U.S. Independent Refiners sector to take advantage of the strong seasonal trade. Between 1990 and 2011, the sector averaged an 18% gain from January 1 to the end of May and outperformed the market by 14%. This trading strategy worked in 15 of the last 22 years. In the years when this trade worked, the group outperformed the S&P 500 by 29% through May. This compares to an average underperformance of 10% versus the S&P 500 in the years when the trade did not work.

In light of a normal to heavy spring turnaround season in the Atlantic basin and the recent wave of refinery closure announcements from Hess and Petroplus, we think margin trend will remain robust in the near term and very supportive for this year’s seasonal trade.

If all announced refinery closures are completed, this could trigger a decent cyclical upturn for the global refining market through 2013.

Our favorites are Tesoro Corporation, Valero Energy and Marathon Petroleum.

Refiners trade is not over yet Strong Momentum in This Year’s Seasonal Trade – Following the shutdown of Petroplus’ refining operations on top of the recently announced and potential closures in the Atlantic Basin by Hess, ConocoPhillips and Sunoco, we estimate that total refining shutdowns could reach more than 2 million barrels per day (mmb/d) in 2012 under the most extreme scenario, compared with our estimate of additions from new construction of 2 mmb/d, or a slight net negative capacity growth. Our current base case, however, assumes that only about 1-1.5 mmb/d of the announced plants will actually be permanently shut. Based on our current global oil demand growth rate assumption of 1 mmb/d, capacity shutdown of more than 1.25 mmb/d would likely result in a decent cyclical upturn for the global refining market that could last through the next 12-24 months. We expect to learn more details of potential shutdowns by April/May. Meanwhile, helped by a normal to heavy spring turnaround season in the Atlantic basin and the recent wave of refinery shutdown announcements, we think margin trend will remain robust in the near term and very supportive for this year’s seasonal trade. Historically, refining shares have followed the underlying margin trend, and as such it has tended to be an important indicator of the shares’ future performance. We view valuation as rather secondary and not typically a good indicator of future performance. Our favorites include TSO, VLO and MPC.

What Drives Refining Margins? – Depending on the location and configuration of the refineries, there are three major drivers of the U.S. refiners’ profit margins at present: 1) product crack of light sweet refiners in the waterborne markets; 2) light/heavy differential; and 3) Brent/WTI differential for the inland facilities.

Light/Heavy Differential – Several short-term factors influencing the current spread, which includes the especially strong bunker fuel demand in Asia and an unusual number of spot fuel oil buyers in the Northwest Europe market bidding up the price, have driven the LLS/Maya spread to a 1Q12 QTD average of $6.6/bl compared with the 2011 average of

Paul Y. Cheng, CFA +1 212 526 1884


Sector View

1-POSITIVE



1 March 2012 101

$13.6/bl. However, we think the current spread is unsustainable on a crude quality differential basis, and expect Pemex will continue to adjust the K-Factor until the Maya/LLS spread reaches roughly $10/bl since the current differential gives incentive for refiners to run medium sour instead of heavy sour (please see our report, “K-Factor Reduced for February; Positive for Coastal Heavy Oil Refiners” dated January 12, 2012).

Longer term, we believe there are four primary drivers behind the differential movement: 1) OPEC policy; 2) refineries’ heavy oil processing capacity; 3) global refining utilization rate; and 4) speculation. We believe two of these four factors will be favorable for the light/heavy differentials over the next couple of years, partially offset by one negative driver (heavy oil processing capacity) and one neutral to negative factor (global refining utilization rate). Accordingly, we think the light/heavy spread could begin to improve by late 2012 or early 2013. However, we think the spread will not match the strong period of 2004-2008 when these four drivers were all favorable for the differential. We currently assume the LLS/Maya differential will average $9.20 per barrel between 2012 and 2016 compared with an average of $15.60 between 2004 and 2008 and a low average of $7.80 in 2009.

Brent/WTI Differential – Following the November 2011 announcement of the Seaway pipeline sale and planned partial reversal by the second quarter of this year, the Brent/WTI spread dropped to approximately $9-10/bl from a 3Q11 average of $25.0/bl and a 4Q11 QTD average at the time of $17.7/bl. Since then, however, the spread has begun to widen again to a current 1Q12 QTD average of $15.5/bl. The ongoing developments in Iran, which includes the European Union oil embargo, the possible pre-emptive halt of Iranian exports, and concerns about a potentially significant supply disruption to the Straits of Hormuz, have likely contributed to higher Brent prices over the past several weeks. From now until the reversal, we expect the spread will gradually reduce over the next 1-2 months as concerns about a reversal delay subside, before eventually settling at approximately $4-5/bl by the end of 2013/early 2014 after the start-up of a number of new pipelines including the full reversal of Seaway (late 2012 or early 2013 to 400 mb/d), the reversal of Long Horn by 2H13, and the completion of West Texas Gulf expansion also by 2H13.


1 March 2012 102

Tesoro Corporation (TSO) We believe TSO (1-Overweight/1-Positive) may be one of the most inexpensive stocks in our refining coverage. Based on our analysis using a Brent/WTI assumption of $5/bl and a California indicator margin of $8/bl, we estimate TSO’s annual earnings power at $2.60 per share, including the projected benefits of the Bakken rail project, Mandan expansion and Salt Lake City conversion project. Although we believe this earnings level should support a share price of $36-44 per share, our price target is at the low end of this range to account for uncertainty of earnings related to future growth projects before start-up.

We have been impressed by the company’s improving margin capture rate in the last couple of years in its core West Coast market. Between 2006 and 2009, TSO’s California realized margin averaged 108% of our representative California margin indicator, or $0.3/bl higher than the benchmark, compared with 175%, or $5.2/bl higher, since 1Q10. We do not believe TSO’s share price has fully reflected this significant underlying improvement. Moreover, we think California may have the most upside potential over the next two years compared with other U.S. refining regions in terms of margin improvement. According to our representative refining margin indicators, California was the sole region that had suffered sequential declines in average margin over the past two years in a period of rising margins. However, we think the California refining market’s medium to longer term outlook remains bright given its high barriers to entry produced by its strict product environmental standards and the lack of pipeline capacity to efficiently import product from the Gulf Coast or other U.S. markets. In addition, we think TSO has more potential room for efficiency improvement than its peers because of its relatively weak performance in the past.

Finally, we expect Tesoro Logistics (TLLP) will be able to grow aggressively in the coming years through a combination of organic investment and acquisition opportunities. This should over time substantially enhance the parent corporation’s underlying asset value.

Valero Energy (VLO) Given VLO’s share price drop of 9% compared to a gain of 29% for the group in 2011, as well as the stock’s performance lag against its peers by an average of 7% so far this year, we think VLO’s underperformance coupled with its strong earnings potential (as well as its focus on high complex refineries, geographic expansion and feedstock flexibility) offers an attractive investment opportunity for investors. We rate VLO 1-Overweight/1-Positive.

On EV per daily barrel of complexity, we estimate that VLO is trading at $446 per daily barrel of complexity, or 23% of our estimated greenfield replacement cost. In comparison, we estimate VLO traded at an average of 24% of replacement cost during the three industry cycle troughs in 2009/2010, 2002, and 1999 and at an average of 45% during the cycle peaks in 2007 and 2001.

Based on price to tangible book value, VLO is currently trading at 0.8x compared to TSO at 1.0x, the group median average at 1.7x, and HFC at 2.1x. In comparison, VLO’s corresponding price to tangible book ratios were 0.5x, 1.9x, and 0.9x, respectively, at the trough of the three previous cyclical industry down-cycles in 2009/2010, 2002, and 1999, versus 3.0x and 1.7x, respectively, at the peak of the two previous up-cycles in 2007 and 2001. However, it is worth noting that when VLO was trading below tangible book value, the company was not making money. In contrast, the company earned $3.40 per share in 2011 even after taking into account an after-tax hedging loss of $352 million, or $0.61 per share in 1Q11.

Tesoro Corporation (TSO)



Price (28-Feb-2012) USD 26.91


Valero Energy (VLO)



Price (28-Feb-2012) USD 24.79



1 March 2012 103

On the traditional valuation metrics such as EV/EBITDA and P/E, we estimate that VLO trades at 4.4x EV/2013 EBITDA and 8.7x P/2013 EPS. This compares to its five-year historical average of 4.8x EV/forward EBITDA and 9.5x P/forward EPS.

Based on a Brent/WTI assumption of $5/bl, LLS/Maya of $13/bl, Gulf Coast LLS 6-3-2-1 crack spread of $3/bl and other normalized margin assumptions, we estimate VLO’s sustainable earnings power at $2.30 per share or $7.60 per share on an adjusted EBITDA basis, which includes the benefits of the Port Arthur and St. Charles hydrocrackers (expected to come on-stream by 3Q12 and 4Q12, respectively) and discounting the effects of the company’s estimated long-haul crude mismatch benefit. Based on a 4.5-5.5x EBITDA multiple, we believe VLO should support a valuation of $25-32 per share. Assuming that the Brent/WTI spread will take 24 months to average to $5/bl (using a differential of $9.3/bl instead), we estimate the company’s share price at $26-33. The stock should also be helped by management’s decision to accelerate cash return to shareholders. According to management, the company will target to pay out the highest dividend yield within the refining segment.

Marathon Petroleum (MPC)

We rate MPC 1-Overweight/1-Positive and think the company’s recent approval of a two-year $2 billion share buyback program and the strategic review of a potential MLP of its midstream assets represents a significant indication of management’s commitment to returning cash to shareholders and unlocking value in the company. Although these announcements have been anticipated by the investment community for quite some time, they were previously held up in light of potential tax impacts related to the company’s spin-off from Marathon Oil (MRO) as well as any adverse changes to the company’s investment-grade credit rating. Having received all the approvals required to clear these hurdles, the company should receive a final decision on the potential midstream MLP by the second half of 2012 as well as confirm a renewal or add-on to the current share buyback program over the next 1-2 years, given its strong cash flow generating capability.

Following the announcement of these recent initiatives, we think the company still offers some upside potential to its current share price. Based on a $5/bl Brent/WTI spread, $13/bl LLS/Maya, $3/bl Gulf Coast LLS 6-3-2-1 crack spread and other normalized assumptions, we estimate Marathon Petroleum’s adjusted annual EBITDA at $8.00 per share, which includes our MLP EBITDA estimate of $1.70 per share, or sustainable earnings power of $3.30 per share. Using a 4.5-5.5x multiple for the base adjusted EBITDA and a 9.0x multiple for the MLP EBITDA, we estimate this should support a share price of $42-49. Assuming it may take two years for the Brent/WTI differential to settle at $5/bl (assuming an average of $9.3/bl over the next 24 months), we estimate MPC could be worth $45-51 per share compared to its current share price of $41.67.

Marathon Petroleum (MPC)



Price (28-Feb-2012) USD 41.67



1 March 2012 104

EUROPEAN REFINING & MARKETING

Too little, too late 2012 to be the fourth consecutive year of difficult margins

Petroplus failure was symptomatic, but not a solution

Prefer complexity – Neste Oil and Motor Oil top picks, Saras and PKN least preferred

Near term strength, but it won’t last We expect 2012 to be the fourth consecutive year of difficult margins for the European refining industry caused by overcapacity, lacklustre demand and a higher than average cost base. Those problems have been crystallised with Europe's largest independent refiner, Petroplus, filing for insolvency. The closure of 4% of European capacity combined with the raft of US closures at the end of 2011 may shut down nearly 2mb/d of capacity. These shutdowns, along with the cold weather in Europe, have temporarily tightened the European market and margins have rallied, but we continue to see excess capacity both in Europe and globally. Despite the strong start to 2012, we anticipate only a slightly better year in 2012 than in the very weak 2011; hence, our 3-Negative sector view. However the near-term margin strength is likely to be supportive of the seasonal trade, which normally runs January through to early March. To gain exposure to this trade and our longer-term themes, our preferred picks are those with high quality profitable assets: Motor Oil and Neste Oil (both 1-OW). Our least preferred stocks are Saras and PKN Orlen (both 3-UW).

In periods of excess capacity, earnings can stay low Despite the potential shutdown of nearly 4mb/d of capacity in the past three years, we believe the European and global markets remain well supplied. Over 2011-2014, we estimate 8.2m b/d of new refining capacity will be added globally. Our refinery projects database allows us to track all new and upgrading refinery projects worldwide. With such projected excess supply, it is difficult for us to see a sustained rally in refining margins beyond short term seasonal factors. Higher margins would simply lead to higher utilisation.

Quality assets = cash flow Within this context, European refiners remain disadvantaged. Not only are they exposed to low demand economies, but they also suffer a cost disadvantage: namely, the use of oil to generate power compared with natural gas, which the US refiners typically use. On average, own consumption in Europe is 5% of crude throughput. Only ORL of Israel and Motor Oil of Greece use natural gas. Our preference remains for stocks of those companies that have high quality assets that should convert to cash flow: namely, Motor Oil and Neste Oil. Two companies that may come into this category in 2012 are Hellenic Petroleum and ORL with both having significant upgrade projects due on-stream.

Petroplus failure symptomatic, but not a solution The rapid dissolution of Petroplus came as a surprise to the market highlighting both the weakness of the refining industry and the limited credit available to marginal companies. The potential closure of its refineries would remove 4% of European capacity, but we see this as symptomatic of the wider problems, not a solution. Despite this, we see little risk of failure in the other quoted companies, given different financing arrangements and better underlying assets.

Lydia Rainforth +44 (0)20 3134 6669


Neste Oil (NES1V FH / NES1V.HE)



Price (28-Feb-2012) EUR 9.27


Motor Oil (MOH GA / MORr.AT)



Price (28-Feb-2012) EUR 5.40


Sector View

3-NEGATIVE


1 March 2012 105

Iran sanctions likely to increase costs The EU sanctions on Iranian exports, due to come into force on 1 July 2012, are likely to prove at best an inconvenience to the European refining sector and at worst an additional source of cost inflation.

Overall, we would see the sanctions as being relatively neutral to the wider oil market in economic terms if all they do is change the direction of the flow of exports. If Iran’s customer base simply narrowed and the barrels all flowed into Asia, then not much would be different beyond some changes in differentials and increased freight costs, and perhaps a period of dislocation while consumers sorted out their flows. In that scenario, EU sanctions on the use of Iranian oil would have little more effect than the previous US sanctions and US secondary sanctions. The relevance of the sanctions would then primarily be political.

There are two main determinants of whether the sanctions will ultimately lead to a net withdrawal of oil from the market – and ultimately higher costs for the refiners. The lesser factor is the clearing up of some legal confusion about the EU sanctions. Our understanding is that there is an element of extraterritoriality about the measures in that they are also in effect secondary sanctions, rather like previous US measures. While Iranian crude cannot be imported into the EU, the question is whether a European company could process Iranian crude through a refinery it owned in, for example, Singapore. Our understanding is that a company would not be able to, which would shut Iranian crude out of a number of significant Asian refineries.

The quoted independent refiners in Europe use relatively little Iranian crude with only four of them processing any significant quantity. Given Essar Oil’s domicile in India, but the UK listing of Essar Energy, it is unclear whether the sanctions could apply. For the European refiners that do process Iranian crude, it will likely be replaced by the return of Libyan crude or, in some cases, higher Urals processing. This in turn is likely to increase transportation costs and put upward pressure on some specific grades. We see an average cost increase of c$0.5/bl.

Figure 63: Estimated Iranian throughput

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ESSR ERG HEP SRS LOT MOL MOH NEST ORL PKN

This chart shows Barclays Capital’s estimates of the

proportion of crude oil that each company typically runs. On

average, 2011 was higher than normal owing to the Libyan

crisis. The numbers we show here are what we see as

normalised levels. It is currently unclear whether

Essar will be affected by the European sanctions given the

London listing.



1 March 2012 106

Higher oil price means higher running costs One of the key variable costs for refiners is energy costs. Typically, a refinery in Europe will use between 4% and 6% of crude throughput to power the plant, but this can be higher depending on the processes used, such as the 12% we estimate for PKN, or lower depending on the amount of natural gas usage. As a result, the companies are typically very fuel efficient, but the oil price remains a significant cost. For example, a $10/bl increase in the oil price reduces the net refining margin by $0.5/bl, all else being equal. If the increase in the oil price is supply driven, as we are seeing with the current MENA crisis, the additional costs have less chance of being passed on to the end consumer. The range of crude consumed as a proportion of throughput is less than 2% for Motor Oil and ORL, rising to 12% for PKN. Below we show our estimates of the percentage of oil consumed by each company.

Figure 64: Crude costs as % of gross refining margin

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complexity and availability of other fuels such as natural gas.


We note this effect is lower for the US refiners, which typically use natural gas as the primary source of energy generation.

One offsetting factor is that the group will receive a one-off valuation benefit from the increase in the oil price. Essentially, each refiner will run with 3-4 weeks of inventory, and there is a real one-time benefit of an increasing oil price. Crude oil that a refiner bought at $100/bl can subsequently be sold at a profit if the underlying price that the refiner sells it at is higher than the price at which it is bought. For some companies – such as PKN and Grupa Lotos, which hold mandatory stocks, these effects can be greater. As such, whenever the forward curve is in contango, there remains an incentive for the refiners to run crude.


1 March 2012 107

US OIL SERVICES AND DRILLING

The next Mega-Cycle takes hold North America to remain more resilient as capital budgets shift from gas to oil/liquids

International growth is accelerating; pockets of pricing power developing

The “Big Four” are among the most attractive in our universe

Offshore drilling: Dayrates moving up across the board

We remain bullish on the sector The next mega-cycle for the oil services industry is getting under way. The European debt situation, concerns of a hard landing in China and the resulting volatility, and depressed valuations in global equity markets are masking this shift. We believe the reason to own oil services stocks is clear: The world is becoming increasingly short energy, hydrocarbon prices are at attractive levels for investment and are likely to rise further, cash flow and thus capex on energy investments are increasing rapidly, and the oil services companies are the bottleneck and likely to capture the economic benefit of this unfolding trend. We remain bullish on the oil services, equipment, and drilling companies and believe the group will significantly outperform the broader equity market over the next several years. In our view, the most attractive stocks are the large-cap diversified companies (BHI, HAL, SLB, WFT), the capital equipment names (CAM, NOV), several of the offshore drillers (RIG, RDC, NE, ESV), and select small/mid-caps such as HOS, GLF, SPN, DRC, GGS and IO. We also like the small- and mid-cap NAM-focused stocks, especially with most trading below 5x 2012 EV/EBITDA.

North America to remain resilient

Despite the logistical issues plaguing the U.S. services industry, we remain confident that demand in North America will remain resilient and believe the rig count may exhibit modest growth in 2012. Since year-end, the oil rig count has increased by 79 rigs to 1,272, while the natural gas rig count has declined by 93, to 716. We believe the gas rig count could decline by as many as 150 rigs in 1H12 from end-2011 levels; however, over time, this should be fully offset by a shift toward oil and liquids-rich drilling and the continued recovery in the deepwater Gulf of Mexico. Each of the big three service companies (BHI, HAL, SLB) expect the U.S. rig count to be flat to modestly higher from end of 2011 levels by the end of 2012.

Figure 65: U.S. Natural Gas and Oil Land Rig Counts, 2006-Present

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We expect the natural gas rig count to trend lower through 1H12 due to seasonal factors and reduced dry gas directed

activity

Source: Baker Hughes and Barclays Capital estimates

James C. West +1 212 526 8796


Baker Hughes (BHI)



Price (28-Feb-2012) USD 51.00


Halliburton (HAL)



Price (28-Feb-2012) USD 37.68


Sector View

1-POSITIVE


1 March 2012 108

International growth is accelerating; pricing power developing We forecast an 11% increase in international exploration and production expenditures in 2012, and double-digit gains in international spending for the next several years. By region, spending in 2012 is expected to rise most meaningfully in Latin America, Africa, Europe, the Middle East, and Russia. The three largest diversified oil service companies were universally upbeat about the international rig count outlook in their 4Q11 earnings calls. With activity increasing in the international markets and capacity tightening, we expect the equity markets to shift their focus somewhat from international revenue growth to improving international margins. Pockets of international pricing power are beginning to develop for particular product lines and pricing leverage is likely to increase in 2012.

The ‘‘Big Four’’ are among the most attractive in our universe Investors are very concerned about the prospect of North American margin compression, and sentiment on the “Big Four” remains fairly low. At the same time, the outlook for international growth and pricing looks increasingly positive. What does that mean for the shares? If the last cycle is any guide, we argue 2012 should be a good year for the “Big Four.” The large-cap service companies (BHI, SLB, HAL and WFT) are trading at a 28% discount to their 5-year average on a forward P/E basis (11.7x NTM P/E versus a 5-year average of 16.3x). However, we believe the large caps can run even with declining margins in North America, as long as the international cycle is moving forward. As the market gains greater comfort that a declining rig count is not on the horizon for North America, and the international recovery continues, we expect the multiple gap to shrink considerably.

Figure 66: The Big Four Service Companies: NTM P/E Multiple, 2007-Present

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Feb-12Sep-11Mar-11Sep-10Mar-10Sep-09Mar-09Sep-08Mar-08Sep-07Mar-07

5-YR Average Fwd P/E Multiple: 16.3x

5-YR Median Fwd P/E Multiple: 16.3x

Current Fwd P/E Multiple: 11.7xCurrent Discount to 5-YR Average: 28%

The “Big Four” are trading at a 28% discount to their 5-year

average on a forward P/E basis, a level not seen since the

height of the financial crisis in early 2009

Note: Index is a composite of the “Big Four” Service companies: BHI, HAL, SLB, and WFT Source: FactSet and Barclays Capital estimates

Offshore drillers: dayrates moving up across the board

Deepwater activity is poised to accelerate further in 2012, which is resulting in tightening supply for offshore equipment and consequently higher dayrates. The offshore rig count is around 2008 peak levels and the recent surge in offshore rig construction provides solid visibility for improving activity through at least 2014. Dayrate momentum is also increasing, with ultra-deepwater dayrates crossing the $550,000 per day range and approaching prior peak levels of $600,000 per day.

Schlumberger Ltd. (SLB)



Price (28-Feb-2012) USD 78.78


Weatherford International (WFT)



Price (28-Feb-2012) USD 16.41



1 March 2012 109

EUROPEAN OIL SERVICES AND DRILLING

Signs of a pick-up New energy spending cycle underway and gaining momentum.

We expect to see significant order book growth over the next 12 months.

Attractive valuation: trading below 10-year average PE and offering upside potential to core DCF, despite being in an upturn.

Cycle now underway When our annual capital spending survey was published in December 2011, the general feedback from investors was that our expectation of a 10% rise in capex in 2012 was leaning towards the optimistic side. Especially since this was after a surprising 22% uplift in 2011. Since that time, the oil companies have finalised their plans, most capex programmes have come in some way ahead of our initial expectations and 2012 is likely to be another year of significant growth. In our opinion we are well into the next up-cycle and expect to see continued spending for several years.

From a European perspective, most companies are, however, exposed towards the back end of the spending curve. In the last up cycle, it wasn’t until late 2005/06 that we started to see backlog momentum for the sector and hence whilst orderbooks have remained firm, the start of earnings upgrades that drive share price performance have yet to occur. For now we remain in an environment in which the fear of earnings cuts, following a two-year downturn, is dominating investor thoughts, but over the next six months we expect this to reverse.

Encouragingly, the first signs of the uptick are beginning to materialise. Pricing for seismic activity in summer 2012 is likely to be up by 10-15%; offshore construction backlogs are back at all-time high levels and all companies are talking of record levels of enquires, even the still depressed offshore heavy transportation section. They key will be the level of activity translating into backlog as we go through the year, underpinning a strong year of growth in 2013.

1-Positive sector view: Looking for momentum The key concern from investors at present is not where the sector is, nor where it is likely to go, but more a short-term worry regarding the strength of the share price performance over recent months, the sector (Bloomberg BEUOILS) having outperformed the FTSEurotoxx 300 by over 30% since October 2011. This is largely an unwinding of disconnect created by the risk off trade in the wider markets in mid-2011 and the continued strength in oil prices which underpins Oil Services profitability. This has however, coincided with the traditional seasonal pattern of performance in Oil Services, leaving the sector prone to a short-term correction.

Mick Pickup +44 (0)20 3134 6695


Tom Ackermans

+44 (0)20 7773 4457 [email protected]


Sector View

1-POSITIVE


1 March 2012 110

Despite this short-term worry, we still believe in the longer term value in the sector. Currently the sector is trading on 10.2x 2013F PE, just a 6% premium to the market, significantly the lowest premium that we have seen apart from in rapidly falling markets. This is largely a result of investors, in our opinion, currently having the shortest earnings horizon that we have seen in a decade and hence little focus has been placed as yet on the 2013F multiples. This is despite the firming fundamentals in the sector and 2013 likely to be a year of significant growth. Hence at just 10x 2013F PE and an historic trading range of 15-16x, we believe that there is upside as soon as confidence in the 2013F numbers grows. This is likely to be a result of backlogs expanding in the sector. We therefore continue to see significant upside potential in the space, with an average potential upside of over 30%, we remain firmly 1-Positive.

Figure 67: EU Oil services average monthly sector performance relative to FTSE Eurofirst 300 since 2004

Figure 68: EU Oil services average monthly sector performance relative to FTSE Europe Oil & Gas producers since 2004

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Figure 69:Sector PE relative

Figure 70: Sector PE (FY1 monthly)

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Source: Datastream, Barclays Capital Source: Datastream, Barclays Capital


1 March 2012 111

Within oil services, the differing industries that it covers have wildly varying dynamics and hence risk-reward scenarios. Our sub-industry preferences are as follows.

Seismic – pricing on the rebound? Pricing for marine contract pricing has held steady for the last 18 months as excess capacity following the 2009 downturn was absorbed by strengthening demand. The tipping point for the supply demand balance now appears to be imminent – with several companies discussing this at their recent 4Q results announcement – a 10-15% price improvement for the northern summer season. While there is debate as to whether this is the start of a major upcycle, or just a false dawn before a weak winter 2012, demand from regions such as a revitalised gulf of Mexico, Angola, Brazil and India are likely to mean that pricing will steadily improve. The key for investors is that current pricing is some 50% off peak levels, such that it is easy to see a rapid doubling. In this scenario, operating margins should move from the current average 0-10%, back towards the 45% range and with it generate rapid earnings expansion. Our preferred play remains PGS, while for investors with a smaller-cap bias could do worse than invest in Polarcus.

Offshore construction – deepwater coming back. We still view the continued progression into ever deeper offshore waters, and indeed see discoveries in late 2011 in East Africa and Southern America as signs of an even more improving longer-term picture. The year has already started well, with ca $3.5bn awarded in Australia already and we expect to see significant workload emerge out of Brazil, Nigeria and Angola as we move through the year. This is on top of a much improved North Sea which will provide a solid baseload of work. As a result we see Subsea 7 as attractive, with its expanded capability set likely to bode well for it. In addition, the sector is a key reason why se see Saipem as our favourite stock in the sector, albeit within a wider portfolio of activities.

Onshore construction – change of business model fogs visibility The challenge of 2010-11 continues, with reduced workloads coming out of the once booming Middle east and what does emerge being devoured by Korean contractors. As a result, 2011 is likely to see backlogs falling for the first time in five years and this pressure will continue. The good news is that workload away from the Middle East and North Africa is beginning to show signs of growth and if this materialises a larger number of smaller projects is likely to stabilise both backlogs and earnings. The one bright-spot appears to be in Iraq, where see Saipem as a key beneficiary.

You can play shale in Europe. Shale gas and oil has transformed the energy picture of the United States. However, the region comprises just 15% of the global shale resource and in the coming years, we expect to see an internationalisation of shale activity. Within this context we see Hunting as a unique way for investors to play the shale theme, with its recent acquisitions in the well completion arena not only giving it a strong presence in the US, but giving it an expanded product able to deliver out of its other global manufacturing facilities.

Subsea 7 (SUBC NO / SUBC.OL)


Price Target NOK 185.00

Price (28-Feb-2012) NOK 134.40


Saipem (SPM IM / SPMI.MI)



Price (28-Feb-2012) EUR 38.05


Petroleum Geoservices (PGS NO / PGS.OL)

Stock Rating 1-OVERWEIGHT Price Target NOK 120.00 Price (28-Feb-2012) NOK 84.40 Potential Upside/Downside +42%

Hunting (HTG LN / HTG.L)


Price Target GBp 1060.0

Price (28-Feb-2012) GBp 826.0



1 March 2012 112

US COAL

Challenging thermal coal outlook, prefer metallurgical exposure

We expect U.S. thermal coal prices to suffer through an extended period (lasting at least through 2014) of oversupply, brought about by lower natural gas prices, weak electrical demand, and limited incentive to cut contracted production in the near term.

While we believe that metallurgical coal prices will see a rebound into 2H12 as global macro concerns stabilize and Chinese steel production returns to growth, the “hybrid” nature (thermal + met) of most coal companies’ production profile means that low thermal prices could continue to weigh on sector valuations.

Our top stock picks among the coal companies include those with margins more heavily driven by metallurgical and/or international markets, such as Alpha Natural Resources (ANR), Peabody Energy (BTU) and CONSOL Energy (CNX).

Thermal coal fundamentals continue to deteriorate In recent months, thermal coal fundamentals have deteriorated more than we expected when we initiated coverage with a cautious view toward the U.S. thermal coal sector in early November 2011. The main reasons:

Incremental switching risk - Natural gas prices below $3.00/Mcf are impacting even the lowest cost PRB coals, with as much as 80m tons of incremental coal demand across all regions lost to natural gas over the next five years by our estimates, assuming gas stays below $3.00/Mcf.

Weak winter demand – We are exiting the peak winter-heating months, and it hasn’t been good. Overall electricity generation is down 3.2% y/y for the period Nov-Jan, and coal inventories have actually risen during the typical winter-draw months. This is a bad set-up for the next several months, when inventories will likely continue to build.

Limited supply cuts – Given the U.S. coal producers are “sold out” for 2012, the incentive/opportunity to cut production near term is limited until contracts roll off beginning in 2013.

From these main drivers we estimate a potential incremental surplus of 20-35m tons in 2012 for U.S. thermal coal, which is higher than our prior estimate of 14m tons. Given utility inventories are already above normal (approximately 170m tons, vs. historical average of approximately 150m tons), we believe inventories are at risk of swelling to unsustainably high levels by year-end 2012, suggesting either a) contract deferrals in the coming months, and/or b) an inventory cycle that extends through 2013. Either way, we believe pricing power in thermal coal is unlikely to return until 2014 at the earliest.

This could take a long time to fix

Even though it’s only February 2012, we believe the wheels are now in motion for a period of weak U.S. thermal coal prices over a prolonged cycle brought about by the limited incentive and/or opportunity for the producers to cut back production in year 1 (i.e., 2012), as these shipments are made under fixed volume contracts that were signed in year -1 (i.e., 2011) when fundamentals were significantly better.

David Gagliano +1 212 526 4016


Sector View:

1-POSITIVE * Sector view is for the broader

North America Metals & Mining sector



1 March 2012 113

This timing mismatch in U.S. thermal coal is nothing particularly new. However, unlike previous cycles where the inventory builds were relatively minor and were followed relatively quickly by inventory declines, in our view this year the challenges will be compounded by unusually weak U.S. consumption as a result of low natural gas prices, increased regulatory-related coal-fired closures, and declining U.S. thermal coal exports. Keep in mind that prior to 2012 there was only one period over the last 50 years (2007- 2009) in which U.S. thermal coal consumption by the electric power sector declined y/y for two consecutive years (with 2009’s 10.2% decline the most severe contraction on record). In 2011, U.S. thermal coal consumption for electricity generation declined approximately 4% compared to 2010, and it appears highly likely that 2012 will show another absolute decline.

As the inventory damage in 2012 is slowly (at best) whittled down in 2013 and 2014, we believe this will create an environment of low thermal coal prices and weak volumes, with price increases limited to cost-pushes at the high end of the cost curve and/or renewed export opportunities should global pricing differentials turn favorable at some point in the future (unfortunately global thermal coal prices have fallen faster than U.S. prices until very recently, leaving the export opportunity as a fleeting hope at the moment).

While production cuts and contract deferrals seem inevitable and will likely help ease the magnitude of the inventory build, in our view, this will extend the period before true “pricing power” returns to thermal coal, as deferred volumes will eventually be shipped in 2013 at the same prevailing prices as 2011, smoothing the downside in pricing but at the same time pushing the possibility for potential price increases further into the future (deferring one ton into 2013 from 2012 means one ton less to re-sell at a higher price sometime down the road).

Met coal offers upside, but thermal could remain a headwind We continue to believe that metallurgical coal prices will improve beginning in 2H12 in conjunction with a rebound in global steel production, particularly in China. While the EBITDA contribution from metallurgical coal has been growing rapidly for most U.S. coal producers (except Cloud Peak), thermal coal volumes and prices also matter. Unlike previous coal pricing cycles, our estimates suggest we are entering an unprecedented period in which U.S. thermal coal prices remain weak while metallurgical coal prices rebound. The situation is compounded by the fact that U.S. coal producers (again, except CLD) are now “hybrids,” with significantly greater metallurgical coal exposure than they previously had due to production expansions or recent acquisitions. While the increased exposure to met helps smooth the downside risk stemming from thermal, we believe the incremental risk of thermal coal weakness may dilute the potential benefits from a rebound in met coal (depending on just how bad thermal coal gets), potentially leaving the coal equities in “no man's land” (time to start divesting thermal assets?).

We favor coal stocks with greater exposure to met markets

Alpha Natural Resources (ANR) As the largest producer and exporter of metallurgical coal in the United States, by our estimates Alpha Natural Resources generates over 80% of its EBITDA from the 20% of its production that is sold to steelmakers. This worked against ANR last year, as the stock sharply underperformed the group as investors grew concerned that the company’s acquisition of met-heavy Massey Energy would prove too expensive and too risky in a slower global growth environment. However, with ANR now trading at only 3.7x our 2013 EBITDA estimate (compared to a sector average of 5.0x) , we believe the stock is attractively

Alpha Natural Resources (ANR)



Price (28-Feb-2012) USD 19.22



1 March 2012 114

priced, particularly with metallurgical coal prices having hit an apparent bottom. Should these prices rebound as we expect while management shows continued willingness to shut in high-cost, inefficient production, ANR offers among the best upside in the coal sector, in our view.

Peabody Energy (BTU) With Peabody’s expansion plans in Australia, we estimate the company has the potential to increase met coal volumes by 13.4% in 2013 vs. 2012, on top of the 39.7% volume growth projected for 2012 vs. 2011. In addition, once the pre-stripping work is completed at the Macarthur assets in 2012, unit costs are poised to decline (potentially significantly) beginning in 2013. The net result?: Even with lower PRB price assumptions in 2013, we believe BTU still has the potential to deliver significant (i.e. 44%) y/y earnings growth in 2013. BTU shares are currently trading at 5.1x our 2013 EBITDA estimate, or well below the typical one-year forward EV/EBITDA range for BTU of 5.5-6.5x. Bottom Line: Even with the near-term headwinds in U.S. thermal coal, in our view, BTU’s combination of company-specific growth potential and unit cost declines in 2013 makes it well placed to capitalize on what we believe will continue to be resilient global metallurgical coal prices.

CONSOL Energy (CNX) In our view, CONSOL is also well positioned to capitalize on higher metallurgical coal prices through its high-quality metallurgical coal production (growing through the opening of the BMX and Amonate mines) and direct access to the export markets via the company’s Baltimore terminal. Additionally, we believe the spread between CNX’s current share price and the sum-of-the-parts valuation is simply too wide to ignore (CNX is trading at a 27% discount to our SOP estimate). With CNX finally scaling back some of its own capital spending plans in natural gas (we think it can and should do more), in our view, CNX shares are poised to continue to rebound, particularly if natural gas prices continue to find a floor, and if international met coal prices rebound as we expect during 2H12.

Peabody Energy (BTU)



Price (28-Feb-2012) USD 35.40


CONSOL Energy (CNX)



Price (28-Feb-2012) USD 36.30



1 March 2012 115

ASIA EX-JAPAN COAL

High inventories and supply growth limits positives of demand growth Our medium-term positive demand view for coal in Asia is tempered by supply-side

concerns and inventory overhang. 2012 has started off with excess inventories across the supply chain. Although the seaborne market looks stronger at the margin (with India coming back into the market as a buyer), the domestic supply/demand balance in the two-largest global markets – China and the US – does not look too promising for 1H12. Although strong seaborne prices will help ease import volumes into China (and, hence, downside risk for prices is limited, in our view), we are already past the seasonal peak in coal demand, and the onus on driving up prices now falls on reducing supply. We cover the Asia ex-Japan Coal subsector as part of the Asia ex-Japan Metals & Mining industry for which we have a 1-Postive sector view.

Not withstanding our lukewarm view on the near-term prospects, we like the sector on a medium- to long-term view for two main reasons: 1) Chinese coal has been the quintessential volume growth story with the Big 3 listed producers to have volume CAGRs of upwards of 10% on our estimates with additional upside from the consolidation of the smaller miners (compared with 7% for the industry) and 2) the shift from contract pricing to spot-based pricing is still going on for most companies, which should lift average selling prices (ASPs) to better than the global average.

China Coal Energy (1898.HK; 1-OW; PT HK$13) remains our top pick. The company is going through a 5-year transformation the impact of which does not appear to be fully priced into the stock. The volume growth (doubling volume from 100mn tonnes in 2009 to more than 205mn tonnes in 2015), mix shift (from only 23% spot price exposure in 2009 to more than 60% by 2015) and product shift (from 1% coking coal in the mix currently to more than 8% by 2015) could more than triple CCE’s EPS on a constant commodity price scenario. The stock is trading at a P/E of 11x for 2012E.

China’s coal demand should keep rising at a high-single-digit rate

China is already one of the world’s most reliant economies on coal with close to four-fifths of its generation capacity based on coal – almost double the global average. We do not see that changing dramatically medium term due to environmental constraints restricting the rapid expansion of hydro power, uncertainties about nuclear after the tsunami disaster in Japan and the fact that China is already short of oil and conventional gas. Shale gas and alternative energy could potential be substitutes but that substitution (if economic) would likely take awhile to happen.

For 2011-2015, planned additions to coal-fired plants will add net 260GW of capacity (we have 253MW implied in our coal supply demand model). There is likely to an additional 71MW from hydro, 99MW from wind, 33MW from nuclear and 33MW from gas. Putting all this together, even if all the wind, nuclear and hydro planned capacity is built, China would still end up with a system that is well more than 70% coal fired.

Coal demand has closely followed the trends in electricity generation in China for the past five years, and there are no reasons to assume that this will not be the case in future.

Ephrem Ravi +852 290 34892

[email protected] Barclays Bank, Hong Kong

China’s electricity generation mix is dominated by coal …

… and coal will likely continue to dominate the mix for at least

five years

China Coal Energy (1898.HK)



Price (28-Feb-2012) HKD 10.06


Sector View:

1-POSITIVE


1 March 2012 116

Figure 71: China’s apparent coal demand vs power production

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Consequently, we believe that coal will still do well in a consumption-driven growth model in China even if the investment-demand driven growth phase may be coming to an end (however, we are sceptical of that given that the infrastructure build-out in provinces further from the coast is still ongoing and may take over a decade to complete).

Industrial demand now accounts for 70% of power demand, but that could change quite dramatically as consumption-driven economic growth picks up. Using the US as an example of a large developed country, roughly 25% of power demand should come from industrial demand and a third each from the residential and commercial sectors.

Thermal power generation (and consequently coal demand) continued to be strong in 2011 (as has been the case for the past five years). Coal-fired power generation grew 15.5% last year for a CAGR of 10.6% for the past three years.

Looking forward, we expect the growth rate to moderate as some of the big industrial users of power (aluminium smelting, steel making) are likely to experience slowdowns. However, we expect increasing demand from residential and commercial users to offset the slowdown in industrial demand.

Residential and commercial sector demand could offset

slowing industrial demand for electricity

Figure 72: Sectoral composition of electricity consumption

Figure 73: Per-capita consumption of electricity by sector

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Source: IEA, World Bank, Barclays Capital Source: IEA, World Bank, Barclays Capital

Thermal power generation in China has been growing at

double-digit rates for the past three years


1 March 2012 117

Figure 74: China’s thermal power generation Figure 75: China’s thermal coal use in power generation

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Domestic supply growth is beginning to catch up with demand

After two years of constrained growth, coal production picked up significantly in 2011 with supply growth of 11.5%. This put the domestic market in a surplus for the first time in two years and led to significant inventory build-up across the system on our estimates.

In addition, the import pressure into China increased in 4Q11 with the price of imported seaborne coal at ports lower on a landed basis relative to the price of domestic coal of a comparable basis.

Looking forward, the pace of supply growth is unlikely to slow significantly medium term. Indeed, significant coal mining and rail capacity is being added, especially in Inner Mongolia and Xinjiang Province, which should keep the supply growth rate at more than 7% through 2015 on our estimates.

Supply outstripped demand in 2011, leading to inventory build-

up across the system

Figure 76: Coal inventories at Guangzhou (main receiving port in China)

Figure 77: Coal inventories at Qinhuangdao (main dispatching port)

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We expect supply growth in coal of 7% out to 2015


1 March 2012 118

Figure 78: Pricing of comparable domestic and imported coal at Chinese ports

Figure 79: Coal imports into China

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Figure 80: China’s coal production by province

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Hence, even if demand grows at high-single-digit rates as we expect, the supply growth is likely to moderate the tightness in the market (in addition to the inventory overhang in the short term). Because we estimate that we are in a medium-term plateauing of coal prices in China, we believe the best way to gain exposure to the sector is through bottom-up transformation stories rather than top-down screening for commodity-price leveraged producers.

Buy the best ‘bottom-up’ story: China Coal Energy On the face of it, China Coal Energy (CCE) could be a mistaken for a significant but rather sedate state-owned coal company, selling the majority of its coal on annual contracts to power utilities – effectively making it a quasi-utility without the commodity price related excitement that characterises mining stocks. Although that was true in the past, CCE is undergoing a radical transformation, in our view.

China Coal Energy is undergoing a radical transformation in its

business profile, in our view


1 March 2012 119

Figure 81: China Coal Energy – changes in business mix as the elephant switches into the fast lane

Item 2009 Profile Situation 2016E Profile Situation

Scale Raw Coal Production: 100.8mn tonnes Raw Coal Production: 205mn tonnes

Pricing Contract Structure Contract: 73% Contract: 40%

Spot: 27% Spot: 60%

Coal Type (by volume) Thermal: 98% Thermal: 92%

Coking: 2% Coking: 8%

Coal Type Thermal: 95% Thermal: 78%

Coking: 5% Coking: 22%

Production Base Pingshuo: 86% Pingshuo: 73%

Other Shanxi: 6% Other Shanxi: 11%

Other: 8% Other: 16%

Source: Company data, Barclays Capital estimates

CCE is increasing its scale dramatically (doubling volumes for 2009-16), which should enable changes in its product type profile (coking coal at 8% from c1%, currently) and also de-risking of the production base with Pingshuo going from 85% of the volume to about two-thirds in five years. Most importantly, it is also changing the pricing structure of its coal sales (44% spot sales by 1H11, going to 60% on our estimates). The magnitude of these changes appears underappreciated by the market, in our view, with the stock price not reflecting the potential benefits of the changes. These could add 170% to long-term EPS at constant commodity prices on our estimates.

We estimate the NPV of the current asset suite (plus the Pingshuo East project, which is ramping up now at a 50% risking) at HK$13.5/share (c20% above the current share price), with another HK$6.1bn of NPV if all the projects are executed on time and on estimate another HK$4.1/share if spread between contract and spot pricing closes by half. Asset injections by the parent (which has committed to inject 35mn tonnes/annum of production by 2015) provide another opportunity. Moreover, higher commodity prices provide more non-company-specific upside potential.

The increase in scale, shift to more spot-based sales, and

more coking coal in its product mix could add 170% to EPS from

2011 levels at constant commodity prices

The stock could be worth more than double its current share

price without changes in commodity prices if

management executes on its transformation programme


1 March 2012 120

US POWER

Rising expectations We believe Power stocks are 7-13% overvalued with gas prices being the biggest risk.

The group trades at a $4.33/Mcf gas price, a premium to the forward curve and the Barclays Capital forecast.

Coal shutdowns are rising in response to the EPA’s Mercury Air Toxics Standards (MATS) rule in 2015 and low commodity prices. Auction prices from the May 18 PJM capacity auction will likely show an increase from last year although expectations may be getting too high.

We prefer NextEra Energy, which doesn’t have commodity exposure, and Calpine Corp, which is a spark spread generator with limited exposure and in our favorite TX and CA markets.

Gas price is the biggest risk The biggest risk to Power stocks is low gas prices with the potential for significant spot price downside from the current levels. Our commodities analyst Mike Zenker sees an overhang of 2.2 Tcf in storage with supply running 6.6 Bcf/day above last year’s levels. His gas price estimates are $3.05/mcf for 2012 and $3.25/mcf for 2013.

We believe the group represents a $4.33/mcf gas price which crosses the forward curve in 2014-15 and is well above the Barclays Capital near-term forecast. Included in the forecast is an increase in coal plant displacement by gas of 2.4 bcf/day (5.9 bcf/day cumulative versus a $5.50/mcf gas price). In addition, we see 4,654 MW of nuclear plants currently in unplanned outages which over six months would represent 0.14 bcf/day of production that would also be picked up by gas.

In this environment, we believe gas-fired generators are the best positioned because they have the least gas price sensitivity. Coal or dark spread generators are experiencing a somewhat offsetting impact of lower coal prices when they run on-peak. Nuclear or quark spread generators are impacted overall on margins by lower coal and gas prices.

Figure 82: 4th Quartile Coal to Gas Switching

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Source: SNL, FERC Form1s, company reports, Barclays Capital

Dan Ford, CFA +1 212 526 0836


Gregg Orrill

+1 212 526 0865 [email protected]

BCI, New York

Sector View

2-NEUTRAL




1 March 2012 121

2013 forecasts a risk to credit In January 2012 both Moody’s and Standard & Poor’s issued negative reports on the merchant power outlook. They cited low gas prices, weak demand in the near-term and required capital expenditures to comply with the MATS rule by 2015-16. They also indicated that expiration of hedges in 2013 would have a material negative impact. We expect the companies to provide their 2013 annual updates to the rating agencies starting in the Fall which could lead to rating action for Gencos in the absence of offsetting measures. For independent power companies a more negative outlook from rating agencies could make it more challenging to refinance maturities which ramp-up in the 2014-15 timeframe.

Coal shutdowns mounting, but also PJM auction expectations In a recent update the Edison Electric Institute (EEI) raised its forecast of coal shutdowns to comply with the MATS rule to 50 GW by spring 2015 relative to our 42 GW forecast published in “EPA or Bust” on 9/6/11. That number could continue to rise as companies announce plants written-off in upcoming quarterly reports or otherwise.

The PJM capacity auction for 2015/2016 PJM with results out on May 18 will be the first to show the impact of the shutdowns. We see the potential for Ohio’s ATSI and New Jersey’s PS North zones to clear on their own at prices above $200/MW day. If this is true, the rest of the region could clear below $170/MW. We still see an increase for the rest of PJM from the 2014/2015 auction of $126-137/MW day but potentially shy of consensus. The company with the biggest sensitivity by far to the auction is GenOn Energy where $50/MW day is $165 million.

We prefer 1-OW rated NEE and CPN

NextEra Energy (NEE; 1-OW/2-Neu). NEE provides power exposure but with long-term contracts that insulate the company to a large degree from short-term swings in price. NextEra expects to grow earnings at 5-7% over the next few years with earnings from regulated businesses growing from 58-65% from 2011-2014. On February 17, 2012, the company announced a dividend increase of 9% to $2.40/share annually or a 4.0% dividend yield. The biggest item for 2012 is the Florida rate case which the company has already filed a notice for a $695 million increase to the Commission. We expect a formal filing in March and a final outcome in 4Q12. Our upside case for NEE is $71 which is a 13.8x 2014 integrated utility P/E of $5.20.

Calpine Corp. (CPN; 1-OW/2-Neu). As a spark spread generator CPN has limited exposure to gas prices as their plants are the most efficient and have also taken share from coal plants. On the 4Q11 conference call, management indicated that they have been seeing run times on their baseload gas plants in Texas of 59% versus 34% last January. We also like CPN because 70% of EBITDA is from the Texas and California markets. In Texas, the market has the lowest reserve margins in the country and the Public Utility Commission is adding incentives to send price signals to build. In California, CPN benefits from the carbon market in 2013 as a clean generator; this is a market with high barriers to entry. Lastly, CPN has identified excess cash of $709mn-1.226bn to put to work in 2012 for plant development, balance sheet reduction, or M&A. Our upside case is $29 on near replacement costs of $700/kw for combined cycle, $500/kw for peakers and $4,000/kw for geothermal.

NextEra Energy (NEE)



Price (28-Feb-2012) USD 60.48


Calpine Corp. (CPN)



Price (28-Feb-2012) USD 15.21



1 March 2012 122

EUROPEAN UTILITIES

Under shadow We do not believe that European Utilities offer compelling valuations at the moment,

given the challenging growth outlook, and reiterate our 2-Neutral stance. In our view, the sector is facing structural threats in the form of renewables, competition from new fossil fuel generation and stagnant energy demand.

Within the sector, we prefer companies with defensive characteristics and secular growth potential. These include International Power (PT 415p) and National Grid (PT 680p). We also prefer companies who can directly benefit from commodity price or renewable policy trends such as Drax (PT 675p) and Pennon (PT 890p).

Figure 83: European Utilities have been underperforming the market since 2008

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P/E in line, but high leverage; attractive dividend yield, yet limited growth European utilities have underperformed the market since 2008, and we do not expect the trend to be reversed this year. Despite its poor performance, the sector does not screen cheap compared with sectors, nor does it offer a promising fundamental growth outlook. It is trading at a multiple close to the market average, yet with a substantially higher net debt/EBITDA multiple. In other words, the sector P/E would look much more expensive if it were to de-leverage. Furthermore, despite European Utilities offering high dividend yields, these are driven by generous pay out ratios, with fairly limited dividend growth potential. Therefore, we continue to see major integrated names as value traps, and do not expect them to outperform in 2012.

Peter Bisztyga +44 (0)20 3134 4763


Valuation remains unattractive

Sector View

2-NEUTRAL


1 March 2012 123

Figure 84: Historic forward 1 year P/E trends of European Utilities and the market

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Source: DataStream, Barclays Capital

Structural challenges from both demand and supply sides We consider the structural challenges confronted by the European utilities as two fold:

On one side, they are facing stagnant electricity demand, which is partly driven by the weak economic outlook, and partly by improved energy efficiency. The UK is a particularly pertinent example, where we see the UK household gas and electricity consumption declining by around 3.7% and 2.4% per annum respectively.

On the other side, we believe the European power generation market is becoming increasingly oversupplied. We expect significant new-build of highly efficient gas and coal plants to increase competition and leave old plants uneconomic to run for most of the time. In addition, renewables - especially solar - are crowding out fossil fuel generators, putting pressure on load factors. For example, in Germany, installed capacity in wind and solar has increased by 81% since 2008, representing 36% of the overall generating capacity at 2011. Solar alone is expected to reach 29.8GW of installed capacity in 2012, and has already put significant pressure on German peak power prices, leaving fewer chances for old thermal plants to run.

Figure 85: European Utilities’ net debt/EBITDA is materially higher than the market

Figure 86: Despite offering attractive dividend yield, there is not much dividend growth

1.0

1.5

2.0

2.5

3.0

3.5

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011

Utilities DJ Stoxx ex Finanacials

Utilities

Travel & L.

Telco

Retail

HPC

Oil & Gas Media

Insur.Indstrial Gds &

Serv.

HealthcareFood & Bev.

Fin. Serv.

Cons. & Mat

Chemicals

Basic Res.

Banks

Autos

1.0%

6.0%

11.0%

16.0%

21.0%

2.5% 3.5% 4.5% 5.5% 6.5% 7.5% 8.5%

DPS CAGR 12-14

Div. yield 12

Source: Barclays Capital. Source: Barclays Capital.

Energy demand falling driven by economic weakness and

improved energy efficiency

Renewables policy is crowding out traditional fossil fuel

generation


1 March 2012 124

Last but not least, we expect the sector to continue to be overshadowed by political uncertainties, such as the upcoming election in France, and uncertainty over tariff deficit resolution in Spain. More generally, with European governments fighting hard to combat their budget deficits, we see the utilities as vulnerable to windfall taxation in domestic markets.

We prefer IPR (PT 415p), NG (PT 680p), Drax (PT 675p) and Pennon (PT 890p) The structural challenges we discuss principally affect the integrated utilities. However, we see some interesting opportunities among the regulated utilities and generators. Specifically we identify four stocks, which we believe all have secular growth stories, as well as defensive characteristics.

We recommend International Power (PT 415p). As an independent power generator, it offers great earning visibility thanks to contracted market exposure (70% of its capacity by 2013), and it is well established in emerging markets, benefit from higher GDP growth and robust inflation outlook. With most of its US portfolio in gas plants in Texas region, we see it as a direct beneficiary of tighter US market and upcoming environmental policy changes.

Within the regulated utilities, we prefer National Grid (PT 680p). The UK market has a strong need for infrastructure upgrades. We see NG as well positioned to take the advantage of this capex plan and to earn a high return should it also deliver efficient execution.

We also like Pennon (PT 890p) where we see significant long-term earnings growth from its Viridor waste subsidiary’s generation pipeline, and defensive, inflation-protected returns from its South West Water division.

Finally, we view Drax (PT 675p) as an interesting proposition. With the potential full biomass conversion plan, the equity story could be completely transformed. In the near-term, trends in commodity prices could help support UK clean dark spreads.

Figure 87: Energy consumption per household (kWh) is set to fall in the UK

10,000

12,000

14,000

16,000

18,000

20,000

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011E

2012E

2013E

2014E

2015E

2,500

3,000

3,500

4,000

4,500

5,000

Gas Electricity

10,000

12,000

14,000

16,000

18,000

20,000

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011E

2012E

2013E

2014E

2015E

2,500

3,000

3,500

4,000

4,500

5,000

Gas Electricity

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011E

2012E

2013E

2014E

2015E

2,500

3,000

3,500

4,000

4,500

5,000

Gas Electricity

Source: Barclays Capital.

International Power (IPR LN / IPR.L)



Price (28-Feb-2012) GBP 3.45


National Grid (NG/ LN / NG.L)



Price (28-Feb-2012) GBP 6.42


Drax (DRX LN / DRX.L)



Price (28-Feb-2012) GBP 5.14


Pennon (PNN LN / PNN.L)


Price Target GBp 890.0

Price (28-Feb-2012) GBp 705.0



1 March 2012 125

Figure 88: Potential impact of solar PV on German summer peak power prices in 2012

0

20

40

60

80

100

120

0 10 20 30 40 50 60 70 80

Available Capacity (GW)

SRMC (€/MWh)

59.0

51.4

DemandSupply

€65/MWh

€53/MWh

0

20

40

60

80

100

120

0 10 20 30 40 50 60 70 80

Available Capacity (GW)

SRMC (€/MWh)

59.0

51.4

DemandSupply

€65/MWh

€53/MWh

Source: Barclays Capital.


1 March 2012 126

US CLEAN TECHNOLOGY AND RENEWABLES

Improving data points, though ultimately end market trajectory remains the key question

While improving data points such as comparatively more cost competitive technologies, and industry consolidation suggest that industry trends have begun to bottom, we believe visibility on the pace, and ultimately, the trajectory of the recovery in the U.S. Clean Technology & Renewables sector remains limited given issues such as diminishing regulatory support and overcapacity in key markets.

We thus expect further industry consolidation driven by capital needs, scale, and high barriers to entry to continue in the next 6-12 months, enabling incumbents to capitalize on underpenetrated market opportunities.

The need to fill the gap between energy needs and what fossil fuels can provide, together with ongoing private sector investment, supports our more sanguine view in the long term. Our coverage is focused on four primary end markets: solar, lighting, smart grids, energy efficiency and electric vehicles/storage technology.

Solar: Focus on U.S. growth against a cautious global backdrop

We initiated coverage on the sector in late 2011 (see “U.S. Clean Technology & Renewables; Initiating Coverage: Green Shoots Will Take Time to Blossom,” November 11, 2011) and over the past few months we have seen some encouraging trends in the global solar market data. Specifically, demand has been better than consensus expectations in several key end markets such as Germany, Italy, the U.S. and China. Moreover, following steep pricing declines across the solar value chain last year, we have seen improvement from the December lows, suggesting at least a near-term stabilization. In addition, we continue to see a roster of industry departures and capacity reduction from a number of tier-2 and tier-3 vendors, which is providing some relief around the overcapacity that has plagued the industry.

In our view, the key question is whether or not these trends can prove sustainable over the longer term and help drive the solar market to a more normalized supply/demand paradigm. We continue to believe the industry remains: 1) dependent near term on regulatory incentives to drive adoption; 2) impacted by pricing trends at tier-2 and tier-3 competitors, many of which are making little to no profit; 3) ripe for consolidation and, more likely, rationalization as vendors need to continue to exit the market in order to support the longer-term health of each industry. As pricing trends are likely to remain in flux near term, we remain cautious on the broader solar industry and advocate selective exposure to end markets (i.e., solar inverters) and regions (the United States and China) to position for potential outperformance.

LED and Lighting: Timing of acceleration still uncertain We continue to view the longer-term opportunities offered by LED penetration in general lighting as attractive. However, for the near term, we continue to believe trends are likely to remain sluggish across the value chain as the industry continues to digest material overcapacity along with ongoing pricing pressure. Specifically, we believe the industry continues to closely monitor the potential demand situation in China – one that could ultimately emerge as fairly substantial. Based on our most recent checks, we do believe that a China government subsidy for LED lighting is likely to be announced in the next few

Amir Rozwadowski +1 212 526 4043


Sector View:

2-NEUTRAL




1 March 2012 127

months, supporting our view that the market could be a material growth opportunity. Outside of China, given recent pricing declines, we expect improved adoption of LEDs in general lighting demand – particularly in new construction builds – which should help drive penetration above the <10% levels we currently estimate.

However, one of the primary challenges facing the market – one we do not expect to ease in the coming year – is its overcapacity. Specifically, recent checks confirm our view that utilization levels for most LED makers remains below 50%, suggesting that at the current pace of LED demand, growth is unlikely to absorb the overcapacity. China has yet to see material industry consolidation, which we view as inevitable and necessary, so that change is still ahead of us. Thus, while end market demand trends could improve, we remain cautious as we wait for ongoing pricing reduction and overcapacity issues to ease. We therefore continue to see shares of our LED coverage names as relatively range-bound in the coming months, though believe the chip names are likely to inflect earlier than the equipment names.

Smart grid opportunity: Challenge is to bridge the demand gap We have mixed views on the smart grid opportunity, particularly given the expected reduction in large contract awards in the United States over the next few years. However, we believe North American revenues will be driven by volume of awards as opposed to size, and thus believe vendors that will be able to nimbly maneuver the market will be best positioned to capture remaining growth opportunities.

As adoption cycles are generally slow among risk-averse utilities, we believe that the best way to gain exposure to the space is to position for upcoming stimulus/regulatory incentives which help to increase the deployment cycle of the technology. We see demand potentially beginning in late 2012 but more likely early 2013 driven by regulatory requirements in Europe and ongoing traction internationally. With respect to Europe, over the duration of the upgrade cycle, the size of the opportunity could be material, particularly based on the upgrade needed for 140-150 million meters. While timing is dependent on a number of factors – the least of which is regional macro headwinds – ultimately the opportunity could prove to be quite substantial. We thus would look toward building market improvement over the same time period.

Energy efficiency market: ESCO growth likely to continue We also have a positive view on the energy efficiency market, which we believe is the “low-hanging fruit” of the clean technology and renewables space. We believe that the installation of newer, more energy-efficient solutions (e.g., lighting, building management systems) is a comparatively easier way – and economic manner – in which to reduce energy costs, particularly since residential and commercial energy use is one of the highest outlays in the U.S. market.

In our view, the energy service company (ESCO) market is an attractive way to capitalize on broader energy efficiency trends, while minimizing the up-front capital costs of installing new equipment to improve efficiency. Moreover, it also provides a stable longer-term tailwind given exposure to long-term, highly visible, cash-generative contracts. While contract awards are likely to be lumpy, we continue to see growth in the more traditional MUSH (municipal, university, school and hospital) markets as well as increasing interest from federal entities, which are particularly keen on meeting the dual challenges of energy conservation and reduced budgets.


1 March 2012 128

Electric vehicles: Performance from select vendors will drive growth By end market, we are relatively positive on the near-term outlook for electric vehicles, particularly vendors that provide comparative performance metrics to available internal combustion engine alternatives. We believe the increasing availability of broader options by established automotive OEMs should enable increased consumer awareness, and those vendors that cater to high discretionary income customers should be better positioned toward capitalizing on early adopters in the market.

The adoption of electric vehicles is likely to be driven by two primary subsectors. The first is the premium market, where high discretionary income buyers don’t need to take into account the total cost of ownership (TCO) argument for owning an EV and will pay for innovation as they can afford to take on any risk associated with a pure EV. Recent demand disparity for more mass market models such as the Nissan Leaf and Chevy Volt vs. the demand environment for Tesla’s Model S and recently introduced Model X highlight the difference in end market demand. The second market is where a TCO argument makes complete sense; i.e., in the case of fleet vehicles which have defined driving plans and could benefit from a reduction in fuel costs over multiple vehicles. This could include markets such as fleet vehicles where we have seen strong growth for both electric and natural gas vehicle demand.

Top Picks

Power-One (PWER; 1-OW/2-Neu) is our top relative solar pick as we believe the company is well positioned to gain share in the growing North American and Indian markets. Although incumbency and market share are important, being appropriately situated in the growing markets is key to potential growth. We like Power-One’s ability to continue to drive incremental share gains in core growth geographies; however, we recognize that the company’s performance is unlikely to be completely divorced from broader solar market demand where we continue to see end market volatility.

Elster (ELT; 1-OW/2-Neu) is our top pick in the smart grid subsector, largely as it generates close to 68% of revenues from international markets, 45% of which comes from Europe where the next leg of spending should emerge in late 2012/early 2013. This remains material as we expect market growth to remain steady, punctuated by periods of acceleration due to regulatory incentives/government stimulus. Moreover, as utilities are largely risk averse, we believe competitive displacement is less likely, and thus look for vendors positioned to capitalize on the next wave of stimulus/regulatory-supported spending. We also believe the company is on track with executing its cost reduction initiative which should support its margin structure given increasingly competitive ASPs in the industry.

Ameresco (AMRC; 1-OW/2-Neu) is our energy efficiency pick. Although contract awards are likely to remain lumpy, particularly for MUSH markets, we believe longer-term trends for energy efficiency contracts are positive, particularly in the federal market. We thus consider Ameresco’s ESCO business model comparatively defensible in the current environment, and thus like its longer-term visibility and cash generative characteristics.

Tesla Motors (TSLA; 1-OW/2-Neu – co-covered with U.S. Autos and Auto Parts analyst Brian Johnson) is our top pick in the electric vehicles market as we believe the company is well positioned to capture share in the broader vehicle market as a premium

Power-One (PWER)



Price (28-Feb-2012) USD 4.60


Elster (ELT)



Price (28-Feb-2012) USD 14.58


Ameresco (AMRC)



Price (28-Feb-2012) USD 13.76


Tesla Motors (TSLA)



Price (28-Feb-2012) USD 33.81



1 March 2012 129

provider of automobiles. First and foremost, demand is healthy. We believe the company’s reservation trends indicate that there is strong appetite for the Model S as well as the newly launched Model X. We believe Tesla sits at the right niche of the EV market, focused on high-end users willing to pay for innovation and performance and who would be relatively less bothered by a tepid economic backdrop. On the execution front, the company seems on track to ramp up its NUMMI facility and thus meet its launch deadlines (commercial roll-out by latest July for 20,000 units in 2013).


1 March 2012 130

EUROPEAN CLEAN TECHNOLOGY & SUSTAINABILITY

Green growth in an uncertain world We forecast demand for renewables to see ongoing growth and annual installations

for wind and solar to see CAGRs of 8.5% and 11.1%, respectively, over 2010-15.

This year, we expect wind installations to grow strongly to reach 47.0GW ahead of the expiry of the PTC in the US.

In our view, we will see an increasing switch from centralised-only power generation to a hybrid approach, supported by the ability of rooftop solar to provide a meaningful proportion of a household’s power generation requirements.

Global wind market

Americas: growth for now, uncertain future looms In the US, the Production Tax Credit (PTC) expires at the end of 2013, and we expect to see 15% growth to 6.9GW in 2012 ahead of this. Following this, we anticipate a sharp decline to 2.6GW in installations in 2013. Whilst we do anticipate that an extension of the PTC will be put in place once the impact of the expiration is felt, we believe that allowing the credit to expire and relying only on state-level Renewable Portfolio Standards (RPS) will set the market back somewhat. We remain positive on the outlook for South America, forecasting a 2010-15E CAGR of 46.3%.

Asia: ongoing structural focus on clean technology We continue to anticipate strong growth in the Asia Pacific region, and we believe that annual new installations will be close to 30GW by 2015, driven by ongoing economic and population growth coupled with a structural focus on clean technology. We continue to expect that infrastructure issues in China will improve in the medium term and that strong growth will return to the Chinese market from 2013-2014 onwards as the country aims to reach the additional 70GW of installations targeted in the most recent Five-Year Plan. In the longer term, we believe that there could be upside to our forecast from 2014 onwards should the development of Chinese offshore technology be faster than we anticipate.

EMEA: Steady growth set to continue We forecast a CAGR in installations of 10.6% over 2010-15E. Offshore installations in Europe continue to accelerate, and we expect this market to represent 23% of European wind demand from 2011E-15E. We anticipate strong demand in Eastern Europe with the region likely to represent about 25% of the growth in European wind installations from 2010-15E, driven by excellent wind resource and generous feed-in-tariffs.

Supply chain and pricing outlook Capacity utilisation levels have continued to improve as suppliers have realigned their production capacities to emerging markets to benefit from the stronger demand. We anticipate this trend continuing through 2012 as demand growth outpaces capacity additions although we expect a slight reversal in 2013 as demand growth slows due to our forecast declines in US activity.

Rupesh Madlani +44 (0)20 3134 7503


Christopher Smith

+44 (0)20 3555 1791 [email protected]


Sector View:

1-POSITIVE


1 March 2012 131

Global solar market

Solar demand – what is the outlook? Solar demand drivers remain strong in our view with decentralised electricity demand, energy security concerns and a declining cost of solar energy creating increasingly attractive returns. Tariff levels are declining and remain under constant review in established European markets where the wider economic environment remains particularly challenging. In particular, uncertainty remains over the future of the German market as the government seeks to curb the cost of incentives following record levels of installations in 2011. Asian markets have seen a strong pick-up in installations, and we anticipate that this trend will continue across emerging markets, driven by growing energy demand and a focus on creating a policy environment to support the growth of clean technology. In addition, with significant price falls in recent years and grid parity in several countries combined with moderate expectations, once again, in our view, the risk to demand levels is to the upside from our forecast of 36.4GW for 2015.

Can solar really play a meaningful part in a country’s energy mix? We believe the trend for policy makers will increasingly switch from centralised only power generation to a hybrid approach, which will encourage both utility scale and micro generation. This hybrid approach we believe reduces the need for significant transmission infrastructure investment, helps improve energy security through diversifying power generation sources and also reduces carbon emissions in line with national or international commitments. As we show below, even in a moderate country such as Germany, a household can typically generate a third of its annual power generation requirements through solar power. For developing countries such as India, this estimate is even higher, which we estimate at 71%.

Figure 89: Average daily family home electricity usage against solar generation

0.0

0.8

1.6

2.4

3.2

4.0

0:00

2:00

4:00

6:00

8:00

10:0

0

12:0

0

14:0

0

16:0

0

18:0

0

20:0

0

22:0

0

kW

Generation (kWh) Total Consumption (kWh)

Source: Barclays Capital, Industry Sources


1 March 2012 132

European CleanTech & Sustainability 2012 Best Stock Ideas On 10 January 2012 we published our ‘Generalist Portfolio Manager Best Ideas for 2012’ piece, highlighting the companies in which we have the highest conviction on a twelve-month view. These companies have experienced strong performance year to date, and we reiterate our 1-Overweight recommendations on each. We briefly summarise our view on these companies and performance below.

Outotec (OTE1V.HE): 1-OW, PT EUR57.0 (Energy Efficiency): We believe the company is well positioned to see further backlog order growth as customers seek to improve mining economics and reduce energy costs, with a structural improvement in EBIT margins from service revenues and acquisitions. As at close on 23 February 2012 the stock is +19.6% from the closing price on 9 January 2012.

Umicore (UMI.BR): 1-OW, PT EUR45.0 (Energy Efficiency): We view the company as favourably positioned across recycling for end-of-life goods, which made up 27% and 64% of the company's revenues and EBIT respectively in 2011. We believe that the drive towards recycling, particularly batteries, supports favourable end market development that Umicore is well positioned to benefit from. As at close on 23 February 2012 the stock is +20.0% from the closing price on 9 January 2012.

Prysmian (PRY.MI): 1-OW, PT EUR13.5 (Energy Efficiency): We expect the company to continue to deliver margin progression as the business benefits from exposure to growth in offshore wind and high voltage transmission, as well as leveraging cost synergies from the acquisition of Draka. As at close on 23 February 2012 the stock is +32.1% from the closing price on 9 January 2012.

Outotec (OTE1V FH / OTE1V.HE)



Price (28-Feb-2012) EUR 45.50


Umicore (UMI BB / UMI.BR)



Price (28-Feb-2012) EUR 39.24


Prysmian (PRY IM / PRY.MI)



Price (28-Feb-2012) EUR 12.81



1 March 2012 133

EQUITY VALUATION TABLE – INTEGRATED OIL AND INDEPENDENT REFINERS Equities Price

24 FebStock Rating

Sector View

Target Price

Potential, % Region Dividend yield, %

BarCap EPS 2012F

Consensus EPS 2012F

Difference, %

2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2012F

Integrated OilBG Group 1,523 1-OW 2-Neu 1,800 18 EU - - - 12.3 11.5 9.4 18.0 16.6 12.4 (4.0) (3.0) (1.6) 1.1 91.58 92.56 -1

BP 495 2-EW 2-Neu 550 11 EU - - - 6.2 5.4 4.7 7.0 6.8 6.7 2.8 5.3 7.2 4.2 73.11 70.22 4

Chevron 107 1-OW 1-Pos 133 24 US 3.7 3.9 4.3 5.3 5.6 5.9 8.3 8.9 9.5 6.7 2.9 1.4 3.1 12.30 12.66 -3CNOOC 17 1-OW 1-Pos 21 21 Asia 5.0 8.9 8.5 5.9 5.2 4.7 9.1 8.2 7.7 0.4 (5.8) (5.0) 3.3 2.13 1.88 13

ConocoPhillips 74 2-EW 1-Pos 85 15 US 4.1 4.5 4.4 5.9 6.4 6.4 8.7 9.7 9.8 6.1 1.9 0.6 3.8 7.85 8.27 -5

COSL 13 3-UW 1-Pos 14 1 Asia 10.5 9.8 9.2 12.9 11.8 10.9 11.7 10.7 9.8 7.8 10.7 12.3 1.9 1.25 1.29 -3Eni 17 3-UW 2-Neu 19 9 EU - - - 6.0 5.3 4.6 9.1 8.1 7.1 2.7 9.4 12.2 6.2 2.14 2.19 -2

Exxon Mobil 87 2-EW 1-Pos 93 7 US 5.5 5.8 5.9 7.6 8.0 7.9 10.4 11.2 11.3 5.7 6.0 5.0 2.2 7.80 8.25 -5

Galp 13 1-OW 2-Neu 20 53 EU - - - 18.1 15.9 12.5 40.2 26.7 16.6 (9.2) (2.2) (0.9) 1.6 0.48 0.36 33Gazprom 13 3-UW 2-Neu 15 18 Russia - - - 2.0 1.7 1.6 3.6 3.4 3.5 2.9 3.6 4.0 5.9 3.74 3.53 6

Hess 65 1-OW 1-Pos 90 38 US 5.0 4.0 3.9 6.1 5.4 5.2 10.8 10.2 10.6 (10.0) (6.1) (1.3) 0.9 6.60 6.61 -0

Husky Energy 26 2-EW 1-Pos 28 6 US 4.4 5.0 5.5 5.2 5.9 6.3 11.2 13.6 16.8 1.3 1.2 0.9 4.8 1.85 1.81 2Imperial Oil 49 1-OW 1-Pos 60 23 US 7.3 7.9 7.4 9.3 10.1 9.4 11.5 12.3 11.7 1.0 (2.0) 0.1 0.9 3.90 3.72 5

Lukoil 61 2-EW 2-Neu 70 15 Russia - - - 3.5 3.3 3.1 4.3 4.3 4.5 5.1 9.8 9.9 5.8 14.04 13.58 3

Marathon Oil 34 2-EW 1-Pos 36 5 US 4.0 3.1 3.0 6.3 5.6 5.4 10.9 10.0 10.1 22.6 0.8 (1.0) 1.9 3.50 3.66 -4Murphy Oil 63 1-OW 1-Pos 77 23 US 4.2 4.4 4.3 5.7 5.9 5.7 10.4 10.5 10.3 (5.0) (7.8) (2.5) 1.9 6.15 6.00 3

Novatek 136 2-EW 2-Neu 145 6 Russia - - - 18.0 15.9 13.0 18.6 16.7 13.8 (1.6) 4.0 5.9 4.5 8.16 7.49 9

OMV 29 3-UW 2-Neu 28 -2 EU - - - 4.7 4.4 3.9 8.8 7.2 5.8 (0.1) 5.6 11.3 4.2 3.99 4.05 -2Petrobras (PBR-ADR) 29 2-EW 1-Pos 33 12 Latam 6.0 6.8 5.9 8.1 9.2 8.0 9.3 10.9 8.6 (5.4) (8.4) (5.2) 2.8 2.75 3.28 -16

Petrobras (PBRA-ADR) 28 2-EW 1-Pos 32 15 Latam 5.7 6.5 5.6 7.8 8.8 7.7 8.8 10.3 8.1 (5.7) (8.9) (5.5) 2.9 2.75 3.28 -16

Petrochina 13 3-UW 1-Pos 14 1 Asia 13.7 14.0 14.6 16.4 15.9 10.4 16.5 13.8 6.4 (85.8) (105.7) (60.8) 1.9 1.25 1.29 -3Repsol YPF 20 1-OW 2-Neu 28 37 EU - - - 5.3 4.8 4.1 13.0 8.7 7.3 1.1 7.8 10.7 6.2 2.34 2.11 11

Rosneft 7.4 1-OW 2-Neu 11 41 Russia - - - 4.4 4.4 3.8 5.1 6.2 5.5 6.7 7.3 8.6 2.1 1.19 1.19 0

Royal Dutch Shell A 2,329 2-EW 2-Neu 2,650 14 EU - - - 6.2 5.5 5.2 9.2 7.9 7.7 3.8 5.6 6.5 4.4 4.63 4.45 4Royal Dutch Shell B 2,365 2-EW 2-Neu 2,650 12 EU - - - 6.3 5.6 5.3 9.3 8.0 7.8 3.7 5.5 6.4 4.5 4.63 4.45 4

Sasol 399 1-OW 2-Neu 440 10 S. Africa - - - 9.0 7.4 7.1 11.4 8.7 8.6 1.8 1.6 4.8 4.1 50.63 45.97 10Sinopec 8.8 2-EW 1-Pos 10 14 Asia 4.4 4.2 3.9 5.4 4.9 4.6 8.4 7.4 7.1 4.5 5.8 6.2 3.4 1.19 1.18 0

Statoil 155 1-OW 2-Neu 185 19 EU - - - 5.4 4.9 4.8 10.1 8.9 8.8 2.7 2.5 2.8 4.4 17.48 17.33 1

Suncor Energy 36 2-EW 1-Pos 48 35 US 5.2 5.3 5.4 6.6 6.9 6.9 10.3 9.9 10.3 5.4 5.3 2.3 1.4 3.75 3.30 14Total 42 2-EW 2-Neu 46.5 11 EU - - - 5.6 5.2 4.8 8.2 7.9 7.3 4.8 3.9 4.9 5.6 5.32 5.35 -0

Average 17 5.9 6.3 6.1 7.6 7.2 6.4 11.1 10.1 9.0 (0.9) (1.4) 1.3 3.4 2

Independent RefinersAlon USA 11 3-UW 1-Pos 9.0 -18 US - 4.9 5.2 6.3 6.2 6.4 10.1 12.6 18.4 4.6 17.1 14.2 1.6 0.80 1.16 -31

Delek 14 2-EW 1-Pos 14 2 US 2.7 3.0 4.3 3.9 4.1 5.3 5.3 7.2 15.7 (11.5) 10.7 4.9 1.1 1.85 1.93 -4ERG 8.3 2-EW 3-Neg 11 33 EU - - - 9.3 9.7 9.3 343.6 26.2 25.5 (0.8) 1.2 2.5 4.8 0.32 0.36 -12

Essar Energy 122 1-OW 3-Neg 280 130 EU - - - 16.4 15.9 10.4 16.5 13.8 6.4 (85.8) (105.7) (60.8) 0.0 8.81 8.00 10

HollyFrontier 35 2-EW 1-Pos 29 -18 US 2.0 6.9 8.4 3.0 10.3 11.9 3.7 15.0 18.5 28.4 2.8 1.9 2.6 2.35 2.50 -6Hellenic Petroleum 5.7 2-EW 3-Neg 8.5 49 EU - - - 10.2 7.1 6.9 11.6 7.2 6.9 (9.7) 7.5 14.1 7.9 0.79 0.76 4

Lotos Group 27 2-EW 3-Neg 35 30 EU - - - 11.2 8.1 7.4 9 6.1 5.5 (8.0) 8.7 10.9 0.0 4.42 3.89 14

Marathon Petroleum 44 1-OW 1-Pos 50 15 US 3.4 5.5 5.5 4.8 7.5 7.3 6.4 12.8 13.0 0.1 5.9 9.1 2.3 3.4 5.2 -36MOL 18,810 2-EW 3-Neg 24,500 30 EU - - - 4.7 5.2 4.7 4.3 5.8 5.5 16.2 11.4 12.1 5.1 3,216 2,569 25

Motor Oil 5.6 1-OW 3-Neg 11 95 EU - - - 7.5 7.2 6.8 4.3 4.3 4.2 22.2 22.3 23.0 12.4 1.30 1.27 3

Neste 10 1-OW 3-Neg 14 47 EU - - - 10.8 7.0 6.3 28.7 9.3 8.2 (2.0) 10.7 9.0 5.3 1.02 0.95 7ORL 207 2-EW 3-Neg 250 21 EU - - - 12.1 9.4 9.1 15.9 8.6 8.3 (0.7) 4.7 5.7 8.7 0.24 0.20 20

PKN Orlen 35 3-UW 3-Neg 40 14 EU - - - 5.6 5.9 4.9 73.0 29.9 15.2 (0.8) 2.8 7.1 0.0 1.18 1.40 -16

Saras 1.2 3-UW 3-Neg 1.5 29 EU - - - 4.9 4.2 4.0 14.4 9.8 10.1 14.3 16.6 18.2 10.3 0.12 0.04 66Statoil Fuel & Retail 37 2-EW 2-Neu 42 15 EU - - - 6.4 5.8 5.4 10.3 9.0 8.4 (5.5) 9.7 10.5 5.5 4.05 3.91 4

SunCoke Energy 14 1-OW 1-Pos 18 29 US 12.8 6.2 5.8 13.5 7.8 7.6 17.0 9.6 9.6 (16.3) 4.1 (0.6) 0.0 1.50 1.45 3

Sunoco 39 2-EW 1-Pos 37 -6 US 14.0 9.1 7.0 13.1 10.8 8.4 nm 41.5 24.6 (16.1) 10.1 2.1 2.0 0.95 1.12 -15Tesoro Petroleum 29 1-OW 1-Pos 37 29 US 3.1 4.1 3.6 4.2 5.3 4.8 7.0 11.3 9.6 11.6 (4.3) 2.4 0.0 2.45 2.20 11

Valero 26 1-OW 1-Pos 31 22 US 4.1 4.3 4.3 5.5 5.7 5.6 7.2 7.9 8.6 7.6 1.2 8.2 2.7 3.10 3.51 -12

Average 30 6.0 5.5 5.5 8.1 7.5 7.0 32.7 13.1 11.7 (2.7) 2.0 5.0 3.8 2

FCF yield, %EV/EBITDA, x EV/EBIDA Price/Earnings, x

Source: Barclays Capital Stock rating: 1-OW=1-Overweight; 2-EW=2-Equal Weight; 3-UW= 3-Underweight Sector rating: 1-Pos = 1-Positive; 2-Neu = 2-Neutral; 3-Neg = 3-Negative


1 March 2012 134

EQUITY VALUATION TABLE – EXPLORATION AND PRODUCTION (LARGE-CAP) Equities Price

24 FebStock Rating

Sector View

Target Price


BarCap EPS 2012F

Consensus EPS 2012F

Difference, %

2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2012F

Exploration & ProductionLarge-Cap:Afren 140 1-OW 1-Pos 195 40 EU - - - 7.6 2.2 2.4 19.0 6.3 6.5 (9.7) 25.9 13.7 0.0 0.35 0.32 10Anadarko Petroleum 88 1-OW 2-Neu 100 14 US - 6.1 5.4 - - - 26.1 40.0 44.0 8.3 15.9 17.0 0.4 2.20 3.41 -35Apache Corporation 109 1-OW 2-Neu 133 22 US - 3.9 4.0 - - - 9.1 9.3 10.1 22.6 24.2 25.0 0.5 11.75 12.33 -5Cairn Energy 353 2-EW 1-Pos 445 26 EU - - - - - - 2.1 1.9 1.6 (101.3) (13.0) (13.0) 0.0 -0.02 -0.10 77Canadian Natural Resources 37 2-EW 2-Neu 43 15 US - 5.8 5.4 - - - 18.2 15.6 14.7 14.7 18.5 19.7 1.0 2.40 3.13 -23Canadian Oil Sands 23 2-EW 2-Neu 26 13 US - 6.3 6.4 - - - 9.8 11.0 11.0 17.1 15.8 16.1 5.2 2.10 2.43 -14Cenovus Energy 39 1-OW 2-Neu 42 8 US - 8.7 9.5 - - - 23.7 22.1 26.7 11.1 10.3 9.8 2.1 1.75 2.17 -19Devon Energy 75 1-OW 2-Neu 86 15 US - 5.7 5.5 - - - 12.3 13.4 13.4 18.2 18.0 18.3 0.9 5.60 6.34 -12EnCana Corporation 20 2-EW 2-Neu 17 -15 US - 5.8 7.2 - - - 40.2 nm nm - - - 4.0 0.45 0.56 -20EOG Resources 114 1-OW 2-Neu 144 26 US - 31.4 0.0 - - - 0.0 30.1 26.3 - - - 0.6 3.80 4.67 -19Enquest 125 2-EW 1-Pos 145 16 EU - - - 2.3 2.7 4.2 37.5 14.4 16.5 11.9 (5.5) (14.6) 0.0 0.14 0.13 7JKX Oil & Gas 135 2-EW 1-Pos 175 30 EU - - - 2.8 1.6 1.5 (84.2) 3.8 5.5 (23.2) 7.3 16.3 1.0 0.56 0.52 8Kosmos Energy 14 1-OW 2-Neu 17 17 US - 11.8 9.4 - - - nm 57.9 72.4 - - - 0.0 0.25 0.39 -36Max Petroleum 13 1-OW 1-Pos 28 124 EU - - - 7.1 15.4 9.6 (5.4) (23.8) 65.8 (21.1) (25.4) (0.9) 0.0 -0.01 -0.01 -16MEG Energy 44 2-EW 2-Neu 50 14 US - 19.5 24.7 - - - 79.1 67.5 97.4 - - - 0.0 0.65 0.69 -6Newfield Exploration 42 1-OW 2-Neu 40 -5 US - - - - - - 0.0 9.9 9.8 - - - 0.0 4.25 4.47 -5Nexen Inc. 20 1-OW 2-Neu 23 14 US - 3.3 3.1 - - - 10.5 9.9 9.0 - - - 1.0 2.05 2.12 -3Noble Energy 104 1-OW 2-Neu 123 18 US - 6.3 6.0 - - - 19.9 17.2 13.9 - - - 0.8 6.05 6.16 -2Occidental Petroleum 104 2-EW 2-Neu 105 1 US - 5.9 5.8 - - - 12.5 14.6 14.4 - - - 1.8 7.10 8.36 -15Pioneer Natural Resources 114 2-EW 2-Neu 111 -2 US - 8.2 6.9 - - - 28.9 26.4 18.6 - - - 0.1 4.30 5.40 -20Premier Oil 442 1-OW 1-Pos 580 31 EU - - - 9.7 7.5 4.6 22.3 16.8 8.1 (7.9) (11.5) (1.4) 0.0 0.42 0.72 -41QEP Resources 33 1-OW 2-Neu 40 23 US - 5.3 5.1 - - - 19.7 21.0 26.0 - - - 0.2 2.20 1.97 12Range Resources 66 2-EW 2-Neu 50 -24 US - 13.4 12.7 - - - 65.7 87.6 87.6 - - - 0.2 0.75 1.16 -35Rockhopper Exploration 390 1-OW 1-Pos 580 49 EU - - - (16.0) (23.1) nm (15.0) (24.0) nm (12.0) (14.0) (1.0) 0.0 -0.26 -3.00 91Salamander Energy 253 1-OW 1-Pos 350 39 EU - - - 4.7 6.1 3.5 19.1 15.5 8.5 4.9 (0.9) 16.1 0.0 0.30 0.41 -27Soco International 336 3-UW 1-Pos 355 6 EU - - - 25.6 5.3 3.7 34.1 9.0 7.4 (3.0) 10.0 13.5 1.0 0.60 0.80 -25Southwestern Energy 36 2-EW 2-Neu 30 -16 US - 8.6 8.4 - - - 19.7 28.4 28.4 - - - 0.0 1.25 1.61 -22Talisman Energy 14 2-EW 2-Neu 14 2 US - - - - - - 5.4 38.7 23.4 - - - 2.0 0.35 0.84 -58Tullow Oil 1,540 1-OW 1-Pos 1,800 17 EU - - - 21.0 18.6 14.8 35.6 27.7 19.8 0.2 (3.5) (0.4) 1.0 0.89 0.77 16Ultra Petroleum 24 2-EW 2-Neu 22 -8 US - - - - - - 11.0 0.0 16.5 - - - 0.0 1.45 1.88 -23WPX Energy 19 1-OW 2-Neu 20 6 US - 4.1 4.6 - - - 47.2 nm nm - - - 0.0 -0.55 -0.06 -89Average 17 - 8.9 7.2 7.2 4.0 5.5 17.5 19.6 25.1 (4.3) 4.5 8.4 0.8 -9




1 March 2012 135

EQUITY VALUATION TABLE – EXPLORATION AND PRODUCTION (SMALL AND MID-CAP) Equities Price

24 FebStock Rating

Sector View

Target Price


BarCap EPS 2012F

Consensus EPS 2012F

Difference, %

2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2012F

Exploration & ProductionSmall and Mid-Cap:ARC 25 2-EW 1-Pos 27 6 Canada - - - - - - - - - - - - 4.7 0.46 0.73 -37Baytex 58 1-OW 1-Pos 64 10 Canada - - - - - - - - - - - - 4.5 1.95 2.20 -11Bill Barrett Corp. 29 1-OW 1-Pos 40 38 US - 5.1 4.6 - - - 16.6 30.6 29.1 - - - 0.0 0.95 0.97 -2Bonavista 23 2-EW 1-Pos 27 16 Canada - - - - - - - - - - - - 6.2 0.88 1.11 -21Chesapeake Energy 25 1-OW 1-Pos 31 25 US - 7.4 5.5 - - - 9.2 19.8 11.5 - - - 1.4 1.25 1.30 -4Cimarex Energy 83 1-OW 1-Pos 94 14 US - 6.6 5.6 - - - 13.5 16.6 13.5 - - - 0.5 5.00 5.47 -9Comstock Resources 15 2-EW 1-Pos 15 -2 US - 5.0 4.6 - - - nm nm nm - - - 0.0 -0.25 0.12 -308Concho Resources 115 2-EW 1-Pos 111 -3 US - 8.9 7.5 - - - 26.7 21.1 17.1 - - - 0.0 5.45 5.30 3Crescent Point 46 1-OW 1-Pos 51 10 Canada - - - - - - - - - - - - 6.0 0.67 0.72 -7Crimson Exploration 3.1 1-OW 1-Pos 4.0 31 US - 5.5 4.5 - - - nm nm nm - - - 0.0 -0.20 -0.15 -25Denbury Resources 20 1-OW 1-Pos 24 23 US - 6.2 6.0 - - - 14.5 13.5 13.0 - - - 0.0 1.45 1.46 -1Enerplus 24 3-UW 1-Pos 24 -0 Canada - - - - - - - - - - - - 9.0 1.10 0.89 24Exco Resources 7.6 2-EW 1-Pos 7.0 -8 US - 2.0 1.9 - - - 12.7 21.8 nm - - - 2.1 0.35 0.40 -13Forest Oil 14 1-OW 1-Pos 16 14 US - 5.8 6.2 - - - 13.4 15.6 25.6 - - - 0.0 0.90 1.02 -12NAL 7.7 2-EW 1-Pos 8.0 4 Canada - - - - - - - - - - - - 7.8 0.27 0.24 13Pengrowth 10 3-UW 1-Pos 11 11 Canada - - - - - - - - - - - - 8.5 0.40 0.35 14Penn West 22 2-EW 1-Pos 24 11 Canada - - - - - - - - - - - - 5.0 0.60 0.73 -18Penn Virginia 6.1 2-EW 1-Pos 5.0 -18 US - 4.8 4.5 - - - nm nm nm - - - 3.7 -1.30 -0.99 -31PetroBakken 16 1-OW 1-Pos 19 15 Canada - - - - - - - - - - - - 5.8 1.40 1.24 -13Peyto 19 2-EW 1-Pos 26 38 Canada - - - - - - - - - - - - 3.8 0.90 0.99 9Plains Exploration & Production 45 1-OW 1-Pos 51 15 US - 6.2 6.1 - - - 26.2 16.8 17.5 - - - 0.0 2.65 3.21 -17Progress 11 1-OW 1-Pos 15 33 Canada - - - - - - - - - - - - 3.5 -0.16 -0.15 7Quicksilver Resources 6.0 2-EW 1-Pos 6.0 -0 US - 6.8 6.5 - - - 40.1 nm nm - - - 0.0 -0.05 -0.09 44Resolute Energy 12 1-OW 1-Pos 16 38 US - 7.9 6.6 - - - 25.8 29.1 21.1 - - - 0.0 0.40 0.63 -37SandRidge Energy 8.2 2-EW 1-Pos 9.0 10 US - 7.2 5.5 - - - nm 20.4 10.9 - - - 0.0 0.40 0.13 68SM Energy 81 1-OW 1-Pos 110 36 US - 5.4 4.5 - - - 31.7 24.9 18.4 - - - 0.1 3.25 3.14 4Stone Energy 33 1-OW 1-Pos 43 30 US - 3.0 3.0 - - - 8.4 8.1 8.2 - - - 0.0 4.10 4.15 -1Swift Energy 35 2-EW 1-Pos 35 1 US - 6.1 5.7 - - - 18.8 53.4 nm - - - 0.0 0.65 1.02 -36Trilogy 33 2-EW 1-Pos 41 26 Canada - - - - - - - - - - - - 1.3 1.07 1.07 0Venoco 11 2-EW 1-Pos 12 7 US - 5.9 5.8 - - - 20.9 18.7 14.0 - - - 0.0 0.60 1.11 -46Vermilion 49 2-EW 1-Pos 49 1 Canada - - - - - - - - - - - - 4.7 3.44 2.92 18W&T Offshore 24 2-EW 1-Pos 22 -8 US - 3.9 3.7 - - - 10.6 13.7 12.3 - - - 10.5 1.75 1.70 3Whiting Petroleum 55 1-OW 1-Pos 70 27 US - 5.2 5.0 - - - 14.7 13.3 12.8 - - - 0.0 4.15 4.18 -1Average 14 - 5.7 5.2 19.0 21.1 16.1 2.7 -4




1 March 2012 136

EQUITY VALUATION TABLE – OIL SERVICES AND DRILLING Equities Price

24 FebStock Rating

Sector View

Target Price


BarCap EPS 2012F

Consensus EPS 2012F

Difference, %

2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2012F

Oil Services & EquipmentAker Solutions 94 3-UW 1-Pos 100 6 EU 1.6 3.4 9.1 11.9 11.9 8.8 51.0 15.6 10.4 1.6 3.4 9.1 2.6 6.04 7.31 -17AMEC 1,088 3-UW 1-Pos 1,300 19 EU 10.3 8.5 7.4 13.4 11.0 9.6 15.5 13.5 12.1 6.9 7.3 8.4 3.3 70.04 76.79 -9Baker Hughes 52 1-OW 1-Pos 85 64 US 5.9 5.2 4.4 - - - 12.4 10.7 8.6 - - - 1.2 4.85 4.91 -1Basic Energy Services 21 2-EW 1-Pos 30 45 US 4.7 3.6 3.2 - - - nm 7.8 6.9 - - - - 2.65 2.57 3Bristow Group 49 2-EW 1-Pos 53 9 US 8.6 7.2 6.5 - - - 16.3 11.4 10.0 - - - 1.2 3.00 2.91 3Cameron International 57 1-OW 1-Pos 75 32 US 12.6 10.3 8.2 - - - 21.3 17.2 13.1 - - - - 3.30 3.29 0CARBO Ceramics 92 2-EW 1-Pos 157 70 US 8.8 7.7 5.9 - - - 16.3 14.4 10.9 - - - 1.0 6.40 6.40 0CGGVeritas 23 2-EW 1-Pos 31 34 EU 10.6 6.6 3.0 7.7 5.9 4.0 nm 16.0 8.1 4.2 7.2 12.8 0.0 1.42 1.13 26Chart Industries 64 1-OW 1-Pos 86 33 US 16.2 10.6 7.8 - - - 31.4 18.4 12.9 - - - - 3.50 2.95 19Core Laboratories 128 1-OW 1-Pos 122 -5 US 22.1 18.9 16.2 - - - 33.8 26.6 22.0 - - - 0.9 4.80 4.72 2Dockwise 116 2-EW 1-Pos 180 55 EU 42.0 33.9 21.1 8.8 6.6 4.1 210.5 11.8 5.1 -6.5 -5.0 26.8 - 1.73 2.06 -16Dresser-Rand Group 54 1-OW 1-Pos 74 37 US 14.2 9.7 7.8 - - - 27.5 16.9 12.5 - - - - 3.20 2.88 11Dril-Quip 76 1-OW 1-Pos 85 11 US 18.9 13.3 10.0 - - - 32.6 21.8 16.0 - - - - 3.50 3.20 10Exterran Holdings 14 2-EW 1-Pos 20 39 US 8.4 7.2 6.2 - - - nm nm nm - - - - -0.75 -1.04 -28FMC Technologies 52 2-EW 1-Pos 47 -10 US 19.4 15.5 12.5 - - - 32.4 24.8 20.1 - - - - 2.10 2.18 -3Global Geophysical 12 1-OW 1-Pos 17 46 US 8.4 5.6 4.6 - - - 59.0 11.5 8.5 - - - - 1.00 0.96 4Halliburton 39 1-OW 1-Pos 67 73 US 6.1 5.0 4.2 - - - 11.5 9.6 7.9 - - - 0.9 4.00 3.92 2ION Geophysical Corporation 7.6 1-OW 1-Pos 11 46 US 8.0 5.8 4.8 - - - 33.9 16.9 11.5 - - - - 0.45 0.48 -7Key Energy Services 18 2-EW 1-Pos 19 7 US 8.2 5.4 4.3 - - - 19.6 11.1 8.1 - - - - 1.60 1.64 -2Maire Tecnimont 0.8 2-EW 1-Pos 2.3 175 EU (5.3) 4.0 3.0 -5.2 5.4 4.1 -2.1 5.0 3.4 -97.7 15.8 22.6 6.1 0.17 0.15 13National Oilwell Varco 86 1-OW 1-Pos 128 49 US 9.5 7.5 6.1 - - - 18.0 14.3 11.5 - - - - 6.00 5.94 1Oceaneering International 56 1-OW 1-Pos 56 1 US 13.0 10.5 8.7 - - - 27.2 22.0 17.8 - - - - 2.55 2.61 -2Petrofac 1,590 3-UW 1-Pos 2,060 30 EU 11.0 8.9 6.4 14.2 11.8 9.1 16.5 13.8 10.7 0.3 -0.2 2.3 2.6 1.88 1.82 3PGS 84 1-OW 1-Pos 120 43 EU 13.0 8.7 4.4 15.1 9.6 5.3 nm 14.7 6.6 -1.7 0.0 7.1 0.0 1.01 0.73 38Saipem 38 1-OW 1-Pos 48 27 EU 10.2 8.2 6.6 12.7 10.5 8.8 18.6 14.9 12.2 2.0 8.8 10.6 2.2 2.55 2.36 8SBM Offshore 13 2-EW 1-Pos 20 51 EU 5.0 4.2 3.9 6.7 5.8 5.4 -87.6 6.1 5.3 -16.3 -11.7 -6.4 8.2 2.17 1.78 22Schlumberger 80 1-OW 1-Pos 107 34 US 11.2 9.3 7.8 - - - 21.8 17.2 13.3 - - - 1.4 4.65 4.69 -1Subsea 7 SA 132 1-OW 1-Pos 185 40 EU 7.8 5.9 4.3 11.3 10.3 7.9 20.7 20.9 14.1 0.1 7.5 11.2 0.0 1.12 1.36 -18Superior Energy Services 30 1-OW 1-Pos 48 58 US 11.3 4.4 3.5 - - - 14.7 8.7 6.9 - - - - 2.05 2.10 -2Technip 81 2-EW 1-Pos 97 20 EU 9.3 8.3 6.0 12.3 11.0 8.0 18.9 16.9 12.8 2.9 3.6 6.5 2.0 4.77 4.67 2Tecnicas Reunidas 31 2-EW 1-Pos 42 38 EU 9.3 9.0 5.9 12.8 12.5 8.2 12.7 12.5 11.1 7.5 7.6 8.6 4.4 2.44 2.51 -3Tenaris 40 1-OW 1-Pos 55 36 US 9.8 7.5 6.4 - - - 17.9 13.7 11.1 - - - 1.7 2.95 2.90 2Tetra Technologies 10 2-EW 1-Pos 16 53 US 5.3 5.0 4.0 - - - 27.1 13.9 9.5 - - - - 0.75 0.78 -3Thermon Group Holdings 20 1-OW 1-Pos 22 9 US 11.6 10.6 8.9 - - - 44.0 22.4 17.2 - - - - 0.90 0.81 11Weatherford International 17 1-OW 1-Pos 27 64 US 7.5 5.7 4.6 - - - 19.6 11.8 8.5 - - - - 1.40 1.42 -1Wood Group 724 1-OW 1-Pos 920 27 EU 11.6 7.7 6.1 1.8 10.5 8.4 16.5 13.5 11.0 0.3 6.0 7.9 1.6 0.54 0.82 -35Average 38 10.7 8.6 6.8 9.5 9.5 7.1 25.9 14.8 11.1 (7.4) 3.9 9.8 2.2 1

Offshore and Onshore DrillingDiamond Offshore 67 3-UW 1-Pos 57 -15 US 5.8 7.8 6.5 - - - 10.1 17.5 13.3 - - - 0.7 3.85 4.16 -8Ensco 59 1-OW 1-Pos 64 8 US 14.8 8.5 7.1 - - - 19.4 11.1 9.0 - - - 2.4 5.35 5.59 -4Hercules Offshore 5.4 3-UW 1-Pos 4.0 -26 US 11.2 6.7 5.6 - - - nm nm nm - - - - -0.25 -0.38 -35Noble Corporation 39 1-OW 1-Pos 46 18 US 12.2 7.5 6.2 - - - 29.5 13.4 10.4 - - - 1.4 2.90 3.03 -4Rowan Companies 39 1-OW 1-Pos 51 32 US 14.6 7.3 6.0 - - - 34.8 11.9 9.2 - - - - 3.25 3.00 8Seadrill 41 1-OW 1-Pos 47 15 US 12.1 10.6 9.5 - - - 14.4 11.7 10.2 - - - 7.3 3.50 3.19 10Transocean Inc. 51 1-OW 1-Pos 72 42 US 9.1 7.0 5.8 - - - 39.2 18.8 12.5 - - - 6.1 2.70 2.93 -8Helmerich & Payne 63 2-EW 1-Pos 68 8 US 6.3 5.1 4.1 - - - 14.7 12.0 9.3 - - - 0.4 5.24 5.09 3Nabors Industries 22 2-EW 1-Pos 26 15 US 5.8 4.4 3.8 - - - 15.0 8.9 7.1 - - - - 2.50 2.26 11Parker Drilling 6.6 2-EW 1-Pos 9.0 37 US 4.8 3.7 3.3 - - - 12.1 10.1 7.7 - - - - 0.65 0.74 -12Patterson-UTI Energy 20 1-OW 1-Pos 33 63 US 3.7 3.0 2.6 - - - 9.5 7.8 6.9 - - - 1.0 2.60 2.40 8GulfMark Offshore 55 1-OW 1-Pos 65 18 US 11.8 8.7 6.5 - - - 29.2 15.1 9.8 - - - - 3.65 3.55 3Hornbeck Offshore 43 1-OW 1-Pos 52 21 US 14.3 8.5 6.5 - - - nm 24.6 15.4 - - - - 1.75 1.83 -5SEACOR Holdings 99 2-EW 1-Pos 95 -4 US 8.5 5.7 5.2 - - - 25.6 13.9 11.0 - - - - 7.10 5.97 19Tidewater 61 1-OW 1-Pos 73 20 US 14.9 9.2 6.5 - - - 35.2 15.3 9.1 - - - 1.6 1.90 1.91 -1Average 17 10.0 6.9 5.7 22.2 13.7 10.1 2.6 -1




1 March 2012 137

EQUITY VALUATION TABLE – PIPELINES Equities Price

24 FebStock Rating

Sector View

Target Price


BarCap EPS 2012F

Consensus EPS 2012F

Difference, %

2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2012F

PipelinesRefined Products & Crude OilBuckeye Partners L.P. 61 2-EW 2-Neu 68 12 US 15.6 13.1 11.4 15.6 13.1 11.4 19.9 19.2 16.2 6.2 6.4 7.4 6.8 3.17 3.25 (2.5)Blueknight Energy Partners, L.P. 6.7 3-UW 2-Neu 7.0 4 US 5.9 5.5 4.9 5.9 5.5 4.9 22.2 27.1 18.1 1.3 8.8 10.3 6.6 0.25 0.34 (27.3)Calumet Specialty Products Partners L.P. 24 2-EW 2-Neu 24 0 US 8.6 7.8 7.3 8.6 7.8 7.3 24.4 14.1 11.8 15.0 11.3 12.6 8.8 1.70 2.16 (21.5)Enbridge Energy Partners L.P. 33 2-EW 2-Neu 33 1 US 11.9 10.3 9.2 11.9 10.3 9.2 23.0 19.5 17.8 6.7 7.7 8.1 6.5 1.65 1.50 10.0 Holly Energy Partners L.P. 60 2-EW 2-Neu 62 4 US 14.1 10.3 9.2 14.1 10.3 9.2 21.4 20.3 18.5 6.5 6.7 7.1 5.9 2.95 3.17 (7.0)Magellan Midstream Partners L.P. 73 2-EW 2-Neu 72 -1 US 16.4 15.5 14.3 16.4 15.5 14.3 20.7 19.4 17.8 5.7 5.8 6.3 4.5 3.76 3.79 (0.9)NuStar Energy L.P. 61 2-EW 2-Neu 63 3 US 12.8 11.6 10.4 12.8 11.6 10.4 21.5 20.0 17.7 7.9 7.9 8.5 7.2 3.06 3.04 0.7 Oiltanking Partners L.P. 32 1-OW 2-Neu 28 -13 US 18.3 17.3 14.0 18.3 17.3 14.0 52.9 25.6 22.8 5.6 4.9 5.4 4.2 1.26 1.28 (1.3)Rose Rock Midstream LP 24 1-OW 2-Neu 23 -2 US na 169.9 92.2 na 169.9 92.2 na 22.7 15.2 na 7.0 9.9 6.2 1.04 1.22 (15.0)Sunoco Logistics Partners L.P. 42 2-EW 2-Neu 37 -11 US 11.1 11.0 9.9 11.1 11.0 9.9 16.4 18.6 17.4 7.8 7.0 7.3 4.0 2.25 2.49 (9.7)Tesoro Logistics LP 37 1-OW 2-Neu 36 -2 US 31.1 16.1 11.2 31.1 16.1 11.2 33.0 19.7 15.6 4.8 5.5 7.1 4.0 1.86 1.79 4.2

Average Sub Sector 1 14.6 26.2 17.6 14.6 26.2 17.6 25.5 20.6 17.2 6.8 7.2 8.2 5.9 -6Gathering, Processing & Compression

Atlas Pipeline Partners L.P. 38 1-OW 2-Neu 41 9 US 13.5 11.4 9.4 13.5 11.4 9.4 7.1 29.7 18.8 6.2 6.8 7.4 5.8 1.27 1.49 (14.7)Chesapeake Midstream Partners L.P. 29 1-OW 2-Neu 35 22 US 12.7 10.1 8.3 12.7 10.1 8.3 21.2 17.8 14.2 6.1 7.1 8.3 5.4 1.61 1.53 5.2 Copano Energy L.L.C. 38 2-EW 2-Neu 37 -2 US 12.9 10.7 8.9 12.9 10.7 8.9 (13.3) 29.9 22.5 6.5 7.1 7.4 6.1 1.45 0.92 57.6 Crestwood Midstream Partners LP 29 2-EW 2-Neu 34 18 US 0.0 0.0 0.0 0.0 0.0 0.0 26.1 17.9 11.9 8.4 8.9 8.1 6.8 1.61 1.43 12.8 Crosstex Energy L.P. 17 2-EW 2-Neu 18 5 US 7.8 7.5 7.0 7.8 7.5 7.0 (65.9) 122.1 88.1 14.2 9.6 10.2 7.5 0.14 -0.17 nmDCP Midstream Partners L.P. 48 1-OW 2-Neu 49 2 US 15.6 11.4 9.1 15.6 11.4 9.1 20.4 22.3 18.0 6.1 6.3 6.5 5.4 2.12 1.64 29.3 Eagle Rock Energy Partners L.P. 11 2-EW 2-Neu 12 9 US 10.3 8.4 7.1 10.3 8.4 7.1 28.4 34.3 13.4 8.7 8.8 10.3 7.7 0.32 0.43 (25.6)Exterran Partners L.P. 25 2-EW 2-Neu 27 9 US 10.4 8.6 7.8 10.4 8.6 7.8 118.1 24.5 17.1 12.0 10.5 10.5 7.9 1.15 0.72 59.7 MarkWest Energy Partners L.P. 60 1-OW 2-Neu 61 2 US 13.2 9.0 7.8 13.2 9.0 7.8 15.9 19.1 18.0 7.7 8.2 8.3 5.1 3.13 2.75 14.0 Targa Resources Partners L.P. 42 1-OW 2-Neu 45 8 US 9.9 9.2 7.6 9.9 9.2 7.6 112.3 71.7 122.2 8.5 7.1 8.0 5.8 2.05 1.80 13.9 Western Gas Partners L.P. 45 1-OW 2-Neu 44 -2 US 18.6 13.7 10.9 18.6 13.7 10.9 27.0 19.1 15.6 5.8 6.2 6.8 3.9 2.35 1.99 18.3

Average Sub Sector 7 11.4 9.1 7.6 11.4 9.1 7.6 27.0 37.1 32.7 8.2 7.9 8.3 6.1 17Natural Gas - NGL Pipelines & Storage

Boardwalk Pipeline Partners L.P. 27 2-EW 2-Neu 29 6 US 14.0 12.9 12.0 14.0 12.9 12.0 25.3 20.4 18.8 7.2 6.9 7.4 7.8 1.33 1.36 (1.8)Energy Transfer Partners L.P. 48 2-EW 2-Neu 51 7 US 10.1 9.7 8.7 10.1 9.7 8.7 26.9 19.5 16.9 7.7 7.2 8.2 7.5 2.45 2.02 21.5 Enterprise Products Partners L.P. 52 1-OW 2-Neu 55 6 US 15.5 14.6 13.4 15.5 14.6 13.4 23.3 21.5 20.4 7.2 6.4 6.6 4.8 2.41 2.41 (0.0)Inergy Midstream LP 21 1-OW 2-Neu 23 8 US na 13.2 7.8 na 13.2 7.8 na 29.0 22.2 na 7.6 9.8 7.0 0.73 0.67 9.2 Niska Gas Storage Partners 10 3-UW 2-Neu 9.0 -5 US 11.0 11.3 10.7 11.0 11.3 10.7 (4.3) 84.8 30.2 8.0 8.8 9.7 14.7 0.11 0.29 (61.4)ONEOK Partners L.P. 61 1-OW 2-Neu 65 7 US 12.8 12.7 11.1 12.8 12.7 11.1 18.2 20.8 19.0 6.1 5.8 5.5 4.0 2.93 2.95 (0.8)PAA Natural Gas Storage L.P. 19 2-EW 2-Neu 19 -0 US 29.3 17.7 16.0 29.3 17.7 16.0 19.6 18.6 17.8 7.4 8.1 8.5 7.5 1.02 0.94 9.0 Regency Energy Partners L.P. 27 1-OW 2-Neu 28 5 US 13.5 13.3 13.3 13.5 13.3 13.3 58.4 57.8 31.0 7.3 6.9 7.8 6.9 0.46 0.55 (15.8)Spectra Energy Partners L.P. 33 2-EW 2-Neu 34 4 US 15.5 13.4 11.5 15.5 13.4 11.5 20.1 20.2 18.2 6.5 6.4 7.3 5.8 1.63 1.70 (4.4)TC PipeLines L.P. 47 2-EW 2-Neu 48 3 US 10.8 11.2 11.1 10.8 11.2 11.1 15.4 17.8 17.6 7.8 7.8 7.8 6.6 2.62 2.87 (8.7)

Average Sub Sector 4 14.7 13.0 11.6 14.7 13.0 11.6 22.6 31.1 21.2 7.2 7.2 7.9 7.3 -5Wholesale Distribution

Amerigas Partners L.P. 46 3-UW 2-Neu 41 -11 US 10.6 7.8 5.8 10.6 7.8 5.8 20.0 21.2 14.4 8.6 5.7 7.8 6.6 2.18 2.12 2.8 Ferrellgas Partners L.P. 19 3-UW 2-Neu 17 -10 US 11.6 11.8 10.1 11.6 11.8 10.1 (31.5) 70.2 29.3 8.8 7.9 10.1 10.6 -0.07 0.14 nmGlobal Partners LP 22 2-EW 2-Neu 22 -1 US 15.3 13.5 11.7 15.3 13.5 11.7 28.7 19.5 14.9 9.1 9.6 11.5 9.0 1.63 1.54 5.8 Inergy L.P. 18 2-EW 2-Neu 20 11 US 10.2 10.1 8.4 10.2 10.1 8.4 120.3 81.0 20.4 11.1 11.4 13.0 15.7 0.22 0.16 38.7 Suburban Propane Partners L.P. 45 3-UW 2-Neu 44 -3 US 11.0 13.1 11.3 11.0 13.1 11.3 14.0 19.0 14.9 8.3 6.9 8.3 7.5 2.38 2.52 (5.5)

Average Sub Sector -3 11.7 11.3 9.5 11.7 11.3 9.5 30.3 42.2 18.8 9.2 8.3 10.1 9.9 10Average Sector 2 13.1 14.9 11.6 13.1 14.9 11.6 7.8 7.6 8.6 7.3 4




1 March 2012 138

EQUITY VALUATION TABLE – DIVERSIFIED NATURAL GAS & COAL Equities Price

24 FebStock Rating

Sector View

Target Price


BarCap EPS 2012F

Consensus EPS 2012F

Difference, %

2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2012F

GasE&P OrientedEnergen 55 2-EW 2-Neu 53 -3 US 6.7 5.7 5.0 - - - 14.0 15.3 13.0 9.2 9.8 11.2 1.0 3.58 3.48 3EQT Corp 54 1-OW 2-Neu 64 18 US 10.1 9.2 7.2 - - - 24.2 25.6 18.8 6.5 6.6 8.4 1.6 2.10 2.27 -7MDU Resources 22 2-EW 2-Neu 21 -5 US 12.3 12.2 11.3 - - - 19.4 19.8 18.0 2.3 2.0 2.3 3.1 1.10 1.21 -9National Fuel Gas 50 2-EW 2-Neu 63 25 US 7.2 7.3 6.5 - - - 18.4 19.5 18.4 9.6 8.4 9.2 2.9 2.55 2.52 1

Average Sub Sector 9 9.1 8.6 7.5 - - - 19.0 20.1 17.1 6.9 6.7 7.8 2.1 -3

Non E&P OrientedEnbridge ($Cdn) 38 2-EW 2-Neu 38 -1 US 14.2 13.4 12.6 - - - 27.0 24.7 23.0 5.3 5.8 6.2 2.9 1.60 1.65 -3Questar 20 1-OW 2-Neu 20 1 US 8.2 8.0 7.6 - - - 17.0 16.8 15.7 8.5 8.8 9.3 3.3 1.18 1.19 -1Spectra Energy 32 1-OW 2-Neu 34 7 US 9.8 9.3 9.0 - - - 17.3 16.6 16.0 5.2 5.7 5.9 3.6 1.90 1.89 1Oneok 84 1-OW 2-Neu 80 -5 US 11.7 11.1 9.8 - - - 26.3 21.5 18.2 4.6 6.3 7.3 2.9 3.89 3.74 4

Average Sub Sector 1 11.0 10.4 9.7 - - - 21.9 19.9 18.2 5.9 6.6 7.2 3.2 0

MLP HoldcoTarga Resources 46 1-OW 2-Neu 50 9 US 34.8 22.1 17.2 - - - nm nm nm 2.7 3.7 4.2 3.0 nm 1.22 -

Distribution CompaniesAGL Resources 40 2-EW 2-Neu 43 7 US 9.1 7.8 7.5 - - - 14.6 13.5 12.7 8.1 8.5 8.9 4.4 3.03 3.02 0Atmos Energy 32 2-EW 2-Neu 34 8 US 8.1 7.6 7.4 - - - 13.9 13.8 13.2 8.3 8.7 8.9 4.3 2.31 2.34 -1New Jersey Resources 48 3-UW 2-Neu 46 8 US 15.8 14.1 14.5 - - - 19.1 17.7 18.3 5.1 5.8 5.5 3.2 2.70 2.75 -1Piedmont Natural Gas 33 3-UW 2-Neu 31 -7 US 10.8 9.8 9.2 - - - 21.4 20.5 19.1 6.3 7.1 7.7 3.4 1.65 1.65 0Southwest Gas 43 3-UW 2-Neu 39 -8 US 6.9 6.5 6.6 - - - 19.5 17.1 17.9 7.8 8.7 8.4 2.5 2.51 2.57 -2WGL Holdings 42 3-UW 2-Neu 41 -2 US 9.2 8.8 8.5 - - - 18.6 16.6 16.6 7.9 8.4 8.7 3.7 2.53 2.50 1

Average Sub Sector -0 10.1 9.4 9.2 - - - 18.5 17.1 17.0 7.1 7.7 7.8 3.4 -1

Average Sector 4 9.6 9.0 8.4 18.8 18.6 17.0 7.0 7.2 7.8 2.8 -2

CoalArch Coal Inc. 14 2-EW 1-Pos 15 5 US 7.5 6.6 5.8 - - - 12.6 15.0 11.4 3.7 10.4 9.2 2.8 0.95 1.07 -11Alpha Natural Resources Inc. 20 1-OW 1-Pos 29 43 US 69.0 4.8 3.9 - - - 12.6 31.8 11.3 3.5 13.1 18.8 2.0 0.64 0.99 -35China Coal Energy 10 1-OW 1-Pos 13 29 China 6.7 6.0 4.7 - - - 11.7 10.8 8.3 (8.7) (0.7) 3.7 2.5 0.76 0.73 3

China Shenhua 36 1-OW 1-Pos 45 26 China 7.1 6.9 6.0 - - - 13.0 12.6 11.4 3.8 5.2 8.1 3.2 2.29 2.22 3Cloud Peak Energy Inc. 18 3-UW 1-Pos 17 -7 US 4.0 4.1 4.8 - - - 7.4 8.5 13.8 2.7 2.9 (7.5) 2.2 2.14 2.04 5Consol Energy Inc. 36 1-OW 1-Pos 54 49 US 6.7 6.8 5.9 - - - 12.0 13.9 12.1 1.8 (3.5) 1.7 1.1 2.62 2.71 -3Patriot Coal Corp. 8.1 2-EW 1-Pos 10 23 US 4.5 7.9 4.7 - - - nm nm nm (6.8) (20.5) (12.0) 4.9 -1.74 -1.42 22Peabody Energy Corp. 36 1-OW 1-Pos 45 24 US 7.5 6.4 5.2 - - - 9.6 10.3 7.1 7.7 3.0 10.7 1.1 3.53 3.29 7Yanzhou Coal 19 1-OW 1-Pos 25 32 China 7.6 5.9 5.0 - - - 12.0 9.1 8.0 9.2 6.9 9.5 3.3 1.69 1.90 -11

Average Sector 25 13.4 6.2 5.1 11.4 14.0 10.4 1.9 1.8 4.7 2.6 -2




1 March 2012 139

EQUITY VALUATION TABLE – POWER & UTILITIES Equities Price

24 FebStock Rating

Sector View

Target Price


BarCap EPS 2012F

Consensus EPS 2012F

Difference, %

2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2012F

PowerAES Corporation 14 1-OW 2-Neu 17 23 US - 6.3 6.3 - - - 14.1 10.8 10.2 17.0 20.4 - 0.0 1.27 1.30 -2Ameren Corp. 32 2-EW 2-Neu 30 -7 US - 6.9 7.2 - - - 12.5 13.6 15.9 0.0 0.5 - 5.0 2.36 1.84 28Calpine Corp. 15 1-OW 2-Neu 18 16 US - 10.4 8.8 - - - nm nm 33.0 5.4 6.5 - 0.0 0.05 0.20 -75Covanta Holdings 17 2-EW 2-Neu 17 2 US - 9.3 8.9 - - - 31.9 25.9 21.8 (1.0) (1.6) - 1.8 0.64 0.60 7Dynegy Inc. 1.4 2-EW 2-Neu 2.0 41 US - 17.8 10.4 - - - nm nm nm (78.6) (40.5) - 0.0 -1.20 -1.01 19FirstEnergy Corp 44 2-EW 2-Neu 43 -2 US - 6.9 6.8 - - - 12.4 13.5 13.4 5.2 5.4 - 5.0 3.27 3.29 -1GenOn Energy Inc. 2.5 1-OW 2-Neu 4.0 63 US - 10.9 5.9 - - - nm nm nm (16.6) (5.9) - 0.0 -0.51 -0.33 54NextEra Energy 59 1-OW 2-Neu 61 3 US - 9.4 8.7 - - - 13.5 13.1 11.8 (14.3) (13.8) - 4.1 4.51 4.51 0NRG Energy 18 2-EW 2-Neu 21 18 US - 5.7 5.7 - - - 25.7 20.2 21.1 13.7 16.5 - 0.0 0.88 0.78 13Ormat Technologies 19 2-EW 2-Neu 17 -11 US - 10.2 8.7 - - - (20.2) 34.9 19.4 (1.4) (0.1) - 1.0 0.55 0.55 0PPL Corporation 29 2-EW 2-Neu 30 5 US - 8.0 7.2 - - - 10.5 12.4 12.0 (0.2) (0.5) - 5.0 2.31 2.35 -2Public Service Entrp Group Inc 31 2-EW 2-Neu 32 5 US - 7.0 6.8 - - - 11.1 13.1 12.7 3.6 4.0 - 4.5 2.32 2.41 -4

Average Sector 13 9.1 7.6 12.4 17.5 17.1 (5.6) (0.7) - 2.2 3

UtilitiesIntegrated UtilitiesCentrica 299 3-UW 2-Neu 260 -13 EU 6.2 5.4 5.0 - - - 11.6 11.3 10.9 15.0 4.0 6.7 5.4 26.77 29.80 -10Drax 519 1-OW 2-Neu 675 30 EU 5.4 5.3 10.9 - - - 10.0 10.2 22.9 6.8 1.6 (15.5) 4.9 51.10 28.20 81Endesa 15 1-OW 2-Neu 28 81 EU 5.4 4.9 4.5 - - - 8.1 7.2 6.7 14.6 18.6 24.7 7.0 2.15 2.05 5Enel 3.1 2-EW 2-Neu 3.7 21 EU 5.8 6.2 5.8 - - - 6.8 8.0 7.8 11.0 11.2 15.5 7.5 0.38 0.43 -12E.ON 17 3-UW 2-Neu 14 -16 EU 8.8 7.6 6.8 - - - 14.6 11.5 10.0 (5.6) 6.1 6.4 6.5 1.47 1.61 -8Fortum 19 2-EW 2-Neu 18 -4 EU 9.7 8.8 8.6 - - - 14.1 11.8 11.6 2.9 4.3 6.7 5.4 1.56 1.54 2Gas Natural 13 2-EW 2-Neu 13 -1 EU 7.2 6.6 6.4 - - - 11.9 10.8 10.8 0.8 16.0 15.2 7.7 1.17 1.44 -19GDF 20 2-EW 2-Neu 21 7 EU 6.9 6.5 6.0 - - - 13.4 12.1 10.1 (0.0) 3.1 5.0 7.9 1.62 1.85 -12Iberdrola 4.5 3-UW 2-Neu 5.9 30 EU 7.5 7.4 7.4 - - - 8.8 8.9 9.0 4.0 2.1 3.1 7.7 0.51 0.53 -3International Power 346 1-OW 2-Neu 415 20 EU 7.7 7.5 7.0 - - - 16.3 14.2 12.7 13.0 11.5 12.8 3.0 0.29 0.35 -17RWE 33 2-EW 2-Neu 32 -4 EU 7.4 6.7 6.5 - - - 7.3 7.6 8.8 (0.8) 6.2 11.1 6.6 4.35 4.05 7Verbund 23 2-EW 2-Neu 21 -7 EU 11.5 9.5 10.2 - - - 23.6 14.9 14.2 (3.7) 2.9 4.1 3.0 1.51 1.52 -1

Average 12 7.5 6.9 7.1 - - - 12.2 10.7 11.3 4.8 7.3 8.0 8.0 1

Regulated UtilitiesEnagas 15 1-OW 2-Neu 17 9 EU 8.4 7.8 7.5 - - - 10.3 9.4 8.7 (0.9) (0.5) 1.2 8.0 1.60 1.68 -5National Grid 646 1-OW 2-Neu 680 5 EU 9.7 9.4 9.7 - - - 13.1 12.3 13.1 2.0 (0.0) (2.2) 6.4 52.36 54.30 -4Pennon 701 1-OW 2-Neu 890 27 EU 11.0 11.0 11.1 - - - 16.5 16.3 16.2 1.4 0.8 (2.2) 4.4 43.06 45.70 -6Red Electrica 36 2-EW 2-Neu 39 8 EU 8.3 7.6 7.0 - - - 10.8 9.6 8.7 4.4 4.1 6.0 7.5 3.74 3.77 -1REN 2.1 2-EW 2-Neu 2.5 18 EU 8.0 7.1 6.6 - - - 10.2 8.2 7.8 (8.0) (6.3) (5.5) 8.4 0.26 0.27 -4Severn Trent 1,540 2-EW 2-Neu 1,745 13 EU 10.4 9.7 9.6 - - - 18.4 14.2 13.8 7.4 8.7 9.2 5.3 108.57 101.80 7Snam ReteGas 3.6 1-OW 2-Neu 3.8 5 EU 9.2 9.0 8.9 - - - 12.8 12.2 12.2 (1.3) 0.0 (0.6) 7.2 0.30 0.29 2Terna 2.8 1-OW 2-Neu 3.2 13 EU 9.1 9.0 9.0 - - - 15.3 14.6 14.1 (5.3) (2.7) (3.8) 6.8 0.19 0.20 -3United Utilities 603 2-EW 2-Neu 665 10 EU 10.7 10.6 10.4 - - - 18.1 15.3 14.7 4.3 2.8 4.0 6.0 39.44 40.20 -2

Average 12 9.4 9.0 8.8 13.9 12.5 12.1 0.4 0.8 0.7 3.7 -2Average Sector 12 8.4 7.9 8.0 13.1 11.6 11.7 2.6 4.0 4.3 5.8 -0




1 March 2012 140

EQUITY VALUATION TABLE – RENEWABLES Equities Price

24 FebStock Rating

Sector View

Target Price Potential, % Region Dividend yield, %

BarCap EPS 2012F

Consensus EPS 2012F

Difference, %

2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2012F

European RenewablesEnergy EfficiencyAbengoa 15 2 - EW 1-Pos 17 17 EU 5.9 6.6 5.1 - - - 3.6 7.0 3.8 (16.4) (25.2) 6.9 1.4 2.07 1.78 16Mersen 26 2 - EW 1-Pos 30 14 EU 5.1 4.4 3.7 - - - 9.1 7.9 6.8 2.7 5.3 5.6 0.0 3.26 2.90 12

Outotec 45 1 - OW 1-Pos 57 28 EU 13.0 8.5 7.2 - - - 25.3 16.8 14.9 3.1 3.0 3.2 2.4 2.66 2.59 3Prysmian 13 1 - OW 1-Pos 14 4 EU 24.5 7.3 6.0 - - - nm 11.7 8.9 (5.0) 1.7 2.9 2.7 1.12 1.25 -11

Saft 23 2 - EW 1-Pos 24 2 EU 6.0 5.9 5.1 - - - 11.4 13.8 11.5 7.0 (1.5) 0.8 2.5 1.68 1.97 -15Umicore 39 1 - OW 1-Pos 45 14 EU 13.1 11.6 10.5 - - - 19.6 17.5 16.0 (0.2) 0.7 1.0 0.0 3.03 3.62 -16

Average 13 11.3 7.4 6.3 13.8 12.5 10.3 (1.5) (2.7) 3.4 1.5 -2

Wind EnergyAcciona 60 3 - UW 1-Pos 60 1 EU 10.8 9.9 9.2 - - - 10.9 17.7 13.6 0.1 (3.6) (2.9) 4.5 3.38 3.04 11Alerion 4.4 2 - EW 1-Pos 4.0 -8 EU 14.8 11.2 8.4 - - - 16.0 80.5 14.0 (30.2) (133.8) (102.6) 2.5 0.05 0.07 -27

EDP Renovaveis 4.0 2 - EW 1-Pos 4.8 18 EU 9.3 8.4 7.5 - - - 30.3 22.0 15.5 (20.2) (10.5) (9.4) 0.0 0.19 0.20 -6Enel Green Power 1.5 1 - OW 1-Pos 2.0 34 EU 7.3 7.5 7.0 - - - 16.1 17.1 15.1 (38.8) (11.3) (4.0) 2.2 0.09 0.10 -12

Gamesa 2.7 1 - OW 1-Pos 4.0 49 EU 4.4 5.0 4.2 - - - 9.3 9.5 5.6 (27.6) 1.3 1.6 1.0 0.29 0.25 15Gurit 474 2 - EW 1-Pos 450 -5 EU 4.2 3.2 2.5 - - - 10.5 8.7 7.9 1.3 6.9 5.4 0.0 54.71 46.77 17

Nordex 5.0 2 - EW 1-Pos 4.2 -16 EU nm 6.0 4.1 - - - nm 13.0 11.9 (12.7) (0.2) 13.7 0.0 0.38 0.17 125Suzlon 27 2 - EW 1-Pos 20 -25 EU 15.6 6.7 5.6 - - - nm 12.3 6.6 (16.1) 0.6 0.6 0.0 2.17 1.40 55

Terna 1.5 3 - UW 1-Pos 1.5 -1 EU 10.0 8.1 8.1 - - - 14.0 10.8 8.8 (109.8) (82.5) (65.8) 2.4 0.14 0.21 -34Vestas 58 2 - EW 1-Pos 50 -14 EU 8.0 5.4 4.0 - - - nm 24.0 9.5 1.1 (12.4) 5.3 0.0 0.33 0.33 -1

Average 3 9.4 7.1 6.1 15.3 21.5 10.8 (25.3) (24.5) (15.8) 1.3 2

Solar EnergyCentrotherm 14 2 - EW 2-Neu 10 -26 EU 6.2 2.6 2.0 - - - nm 9.0 7.5 (21.2) 6.8 3.2 3.7 1.50 0.74 51Manz 26 2 - EW 2-Neu 23 -15 EU 9.3 6.7 5.6 - - - nm 21.5 12.9 (18.0) (3.6) (0.9) 0.0 1.23 0.35 71

Meyer Burger 16 2 - EW 2-Neu 20 25 EU 0.3 nm nm - - - nm 7.6 7.0 18.9 8.4 11.9 0.0 2.10 1.25 40OCI 271,000 2 - EW 2-Neu 175,000 -35 EU 4.5 9.0 7.6 - - - 6.7 26.3 20.3 (4.7) (15.1) 6.8 0.0 9,141 29,490 -223

Phoenix Solar 2.8 2 - EW 2-Neu 3.0 7 EU nm 0.5 0.1 - - - nm 2.7 2.4 13.1 3.9 1.5 6.0 1.03 0.30 71PV Crystalox 4.9 2 - EW 2-Neu 4.0 -18 EU nm nm nm - - - 0.8 0.8 0.7 (2.3) 1.0 0.8 0.4 0.08 0.04 49

Q-Cells 0.3 2 - EW 2-Neu 0.4 22 EU nm 8.0 7.4 - - - nm nm 13.9 (15.2) 7.5 9.3 0.0 -2.53 -0.26 -90REC 4.2 2 - EW 2-Neu 4.0 -5 EU 3.3 3.3 3.4 - - - nm 10.1 17.2 14.2 16.4 12.3 0.0 0.42 -0.45 208

SMA Solar 40 2 - EW 2-Neu 50 26 EU 3.4 2.9 2.9 - - - 8.4 8.0 8.3 (3.1) 7.1 2.7 3.4 4.94 4.29 15Solarworld 3.4 2 - EW 2-Neu 3.2 -5 EU 4.1 4.3 4.3 - - - 19.7 26.9 42.1 (3.2) 1.1 5.7 4.7 0.13 0.33 -62

Wacker Chemie 77 2 - EW 2-Neu 75 -2 EU 3.4 5.2 4.8 - - - 8.0 14.9 13.1 (2.5) (3.1) (0.8) 1.7 5.14 5.26 -2

Average -3 4.3 4.7 4.2 8.7 12.8 13.2 (2.2) 2.8 4.8 1.8 29

US RenewablesA123 Systems 1.9 2-EW 2-Neu 4.0 108 US na na na na na na na na na (107.5) (70.1) (61.1) - -1.47 -1.86 21Ameresco 14 1-OW 2-Neu 14 1 US 13.9 11.9 14.6 11.8 9.8 9.2 18.0 14.8 14.0 (9.5) (2.4) (0.3) - 0.92 0.77 20

Elster 15 1-OW 2-Neu 18 24 US 7.4 7.9 11.4 6.6 6.6 5.9 11.9 12.7 11.0 7.1 6.1 10.9 - 1.15 1.23 -7First Solar 36 2-EW 2-Neu 31 -13 US 3.9 3.9 7.8 4.4 5.7 6.6 6.1 9.5 11.7 (3.9) 7.8 6.8 - 3.75 4.17 -10

GT Advanced Technologies 8.9 2-EW 2-Neu 10 12 US 4.3 2.8 3.0 6.1 4.2 4.9 7.4 4.5 5.3 23.6 24.5 22.7 - 2.00 1.92 4Itron 45 2-EW 2-Neu 42 -7 US 6.9 7.6 9.1 6.0 6.3 5.7 10.4 11.2 10.6 3.2 11.2 12.5 - 3.98 3.86 3

Power-One 4.7 1-OW 2-Neu 6.0 28 US 3.0 5.5 5.8 4.4 9.1 7.1 5.3 9.0 7.5 2.0 13.9 12.0 - 0.52 0.55 -6Tesla Motors 34 1-OW 2-Neu 38 13 US na na na na na 28.8 na na 36.3 (8.0) (5.0) (1.3) - -2.23 -2.05 9

Average 21 6.6 6.6 8.6 9.9 10.3 13.8 (11.6) (1.7) 0.3 4




1 March 2012 141

APPENDIX

Valuation Methodology and Risks for Key Overweights

Americas Integrated Oil

Hess Corp. (HES)

Valuation Methodology: Our 12-month price target implies an 8.0% ROMC under a long term nominal oil price deck of $100/bl Brent, representing an equity risk premium of 3.5% based on our current estimated 10-year Treasury yield of 7.0%, or 4.5% after-tax, compared to our target risk premium of 2.5% for XOM, 2.8% for Chevron, 3.2% for ConocoPhillips and 3.5% for Murphy. We also add $28/share for the company's long cycle known resource base and exploration potential.

Risks which May Impede the Achievement of the Price Target: Our earnings estimates are based on Barclays Capital's current commodity price assumption on oil & gas, refining and marketing margins as well as chemical product margins. Thus, results could be subject to changes due to fluctuations in the macro commodity market environment.

Imperial Oil Ltd. (IMO CT / IMO.TO)

Valuation Methodology: Our price target is based on a 5% premium to the company's NAV of C$57/share using a long-term oil price assumption of $100/bl Brent.

Risks which May Impede the Achievement of the Price Target: Our earnings estimates are based on Barclays Capital's current commodity price assumption on oil & gas, refining and marketing margins as well as chemical product margins. Thus, results could be subject to changes due to fluctuations in the macro commodity market environment.

Suncor Energy (SU)

Valuation Methodology: Our 12-month price target implies a 7.0% ROMC under a long-term nominal oil price of $100/bl Brent from 2015, representing an equity risk premium of 2.5% based on our current estimated 10-year Treasury yield of 7.0%, or 4.5% after-tax, compared with our target risk premium of 2.8% for Chevron, 3.2% for ConocoPhillips, and 3.5% for Hess and Murphy.

Risks which May Impede the Achievement of the Price Target: Our earnings estimates are based on Barclays Capital's current commodity price assumption on oil and gas, refining and marketing margins, and chemical product margins. Thus, results could be subject to changes due to fluctuations in the macro commodity market environment.

Asia ex-Japan Metals & Mining

China Coal Energy Co., Ltd. (1898 HK / 1898.HK)

Valuation Methodology: Our 12-month price target of HK$13.0 for China Coal Energy is based on our base case NPV of HK$13.0/share derived from our DCF analysis in which we assume a WACC of 9.4% and a terminal growth rate of 2%.

Risks which May Impede the Achievement of the Price Target: Besides the top-down risk in the form of volatility in commodity prices, general cost inflation and taxation and resource nationalisation, there are several other organisation-specific risks that could have a material impact on our price target being achieved. These include operational and production delivery risks at the company's current operations and execution risks in its major projects involving sizable cash outflows upfront. We quantify some of these key risks in our upside and downside case valuations for the company. Potentially lower washing yields at Pingshuo mine is also one of the risk to the company.

Asia ex-Japan Oil & Gas

CNOOC (883 HK / 0883.HK)

Valuation Methodology: Our price target for CNOOC's shares is derived using a risk-based methodology which aims at finding the Net Asset Value through a bottom-up approach. We have grouped CNOOC's assets into two main categories: Core NAV, which reflects the value of producing assets and those under development, and risked upside which is generated by the value of CNOOC's exploration and appraisal assets on a risked basis. We have named the risk factors applied to the E&A assets 'Chance of Success' (CoS) i.e. geological likelihood of finding and developing hydrocarbon accumulation. We make adjustments to reflect the value of monetary items on the balance sheet. We do not include the present value of G&A costs, as our price target reflects the liquidation price which allows an asset comparison across different stocks. Our final price target is equal to Total NAV. We have applied an industry standard 11% discount rate.

Risks which May Impede the Achievement of the Price Target: Our CNOOC share price target and recommendation depends upon our estimates of profitability and cash flow and the rate at which we discount the cash flows. These estimates in turn are based on assumptions for oil prices and downstream margins. These assumptions depend on the Barclays Capital Global Oil and Gas equity research teams estimates for future energy supply-demand patterns, exchange rates, commodity prices. All of our estimates are subject to revision and may be materially different from eventual outcomes. In addition the company operates on a global basis in many regions with sometimes unstable political regimes and changing fiscal terms. The actions of OPEC can also have a significant influence on the oil market. All estimates assume no marked changes in the current political landscape. Both upstream and downstream operations are subject to planned and unplanned downtime. CNOOC has significant production exposure to China where some oil product and natural gas prices are regulated.


1 March 2012 142

PetroChina (857 HK / 0857.HK)

Valuation Methodology: Our price target for PetroChina’s shares is derived using a discounted cash flow methodology, using a 11% discount rate. The cash flows in our calculation comprise both US dollar and Rmb currencies. Our price target is set in Hong Kong dollars, based on the Rmb and Hong Kong dollar exchange rate on the date the target is initially published. Subsequently, the corresponding ADR price target in US dollars, will move with the prevailing exchange rate on a daily basis. If the dollar exchange rate relative to the local currency moves significantly compared with the rate used when the local currency price target was initially published, we re-calculate and re-publish the local currency price targets using the current dollar exchange rates. Our price targets are not market linked.

Risks which May Impede the Achievement of the Price Target: Our PetroChina share price target and recommendation depends upon our estimates of profitability and cash flow and the rate at which we discount the cash flows. These estimates in turn are based on assumptions for oil prices, downstream and chemical margins. These assumptions depend on the Barclays Capital Global Oil and Gas equity research teams estimates for future energy supply-demand patterns, exchange rates, commodity prices. All of our estimates are subject to revision and may be materially different from eventual outcomes. In addition the company operates on a global basis in many regions with sometimes unstable political regimes and changing fiscal terms. The actions of OPEC can also have a significant influence on the oil market. All estimates assume no marked changes in the current political landscape. Both upstream, downstream and chemical operations are subject to planned and unplanned downtime. PetroChina has significant production exposure to China where some oil product and natural gas prices are regulated.

Sinopec (386 HK / 0386.HK)

Valuation Methodology: Our price target for Sinopec’s shares is derived using a discounted cash flow methodology, using a 11% discount rate. The cash flows in our calculation comprise both US dollar and Rmb currencies. Our price target is set in Hong Kong dollars, based on the Rmb and Hong Kong dollar exchange rate on the date the target is initially published. Subsequently, the corresponding ADR price target in US dollars, will move with the prevailing exchange rate on a daily basis. If the dollar exchange rate relative to the local currency moves significantly compared with the rate used when the local currency price target was initially published, we re-calculate and re-publish the local currency price targets using the current dollar exchange rates. Our price targets are not market linked.

Risks which May Impede the Achievement of the Price Target: Our Sinopec share price target and recommendation depends upon our estimates of profitability and cash flow and the rate at which we discount the cash flows. These estimates in turn are based on assumptions for oil prices, downstream and chemical margins. These assumptions depend on the Barclays Capital Global Oil and Gas equity research teams estimates for future energy supply-demand patterns, exchange rates, commodity prices. All of our estimates are subject to revision and may be materially different from eventual outcomes. In addition the company operates on a global basis in many regions with sometimes unstable political regimes and changing fiscal terms. The actions of OPEC can also have a significant influence on the oil market. All estimates assume no marked changes in the current political landscape. Both upstream, downstream and chemical operations are subject to planned and unplanned downtime. Sinopec has significant production exposure to China where some oil product prices are regulated.

Canadian Oil & Gas: E&P (Mid-Cap)

Baytex Energy Corp. (BTE CT / BTE.TO)

Valuation Methodology: Our target price is based on our going concern NAV of $55.40 per share (with a target multiple of 1.2x) and a premium 2013 EV/DACF multiple of 11.7x.

Risks which May Impede the Achievement of the Price Target: Our cash flow estimates are predicated on a natural gas price forecast of C$3.00-3.50/mcf and an oil price forecast of US$95/bbl (WTI). Should commodity prices, production levels, or leverage differ materially from our estimates, our price target would be affected. The company’s production levels are impacted by a variety of factors including drilling success, reservoir performance and future acquisitions.

Crescent Point Energy Corp. (CPG CT / CPG.TO)

Valuation Methodology: Our target price is based on our going concern NAV of $43.40 per share (with a target multiple of 1.2x), and a 2013 EV/DACF multiple of 10.1x.


PetroBakken Energy Ltd. (PBN CT / PBN.TO)

Valuation Methodology: Our $19.00 target price is based on our going concern NAV of $18.00 per share (with a target multiple of 1.0x) and a 2013 EV/DACF multiple of 6.0x (the lowest in our coverage universe).



1 March 2012 143

European Clean Technology & Sustainability: Energy Efficiency

Outotec Oyj (OTE1V FH / OTE1V.HE)

Valuation Methodology: Our EUR 57.0 Price Target is derived from our Renewables Valuation Model assuming a high growth period of 5 years, sales growth of 13.5% capital employed growth of 36.0% and return on sales of 10.0%. We assume ormalized growth of 2.0% long term return on sales of 8.0% and pre-tax WACC of 13.3%. Our Barclays Capital Renewables Valuation Model assumes a two-stage growth period. The first period ormalized the higher-growth period as defined as a specific number of years, an operating return and sales growth addition, to include a more accurate reflection of the capital employed for the sector, we include an assumption for the scale of capital employed growth in the first high-growth period. The second period is for ormalized margins of a more steady business, with similar assumptions for operating return and sales growth but without a specific growth rate for capital employed, which we assume to be at a more ormalized level. Together, this is an extension of the EV/EBIT and EV/CE methodology, moving away from the simple mathematical derivation of what particular multiples are for a company to a model that generates what we consider to be the fair value multiple under a given set of variable assumptions. Our approach to the valuation of Renewables Companies finds limited relevance in the use of PE or PE relative valuation approaches, particularly given the different impact of IFRS on annual impairment tests for goodwill, different jurisdiction tax rates, treatment of restructuring and other unusual items. Our preferred methodology focuses on valuing companies using identical components that we use in ormalize company performance, operating profitability (EBIT) and capital employed (CE), which, together, define Return on Capital Employed (ROCE). We believe that by representing the total commitment of capital by management, Capital Employed defines the required earnings power or potential of a company, and ROCE is an expression of those earnings.

Risks which May Impede the Achievement of the Price Target: The company may see a further material decline in demand; the company may face further charges for turn key projects impacting earnings; and the order backlog may see deferrals or cancellations.

Prysmian SpA (PRY IM / PRY.MI)

Valuation Methodology: Our EUR 13.5 Price Target is derived from our Renewables Valuation Model assuming a high growth period of 5 years, sales growth of 8.0% capital employed growth of 12.0% and return on sales of 7.0%. We assume ormalized growth of 2.0% long term return on sales of 7.0% and pre-tax WACC of 14.7%.

Risks which May Impede the Achievement of the Price Target: Revenues may be impacted by slower demand for offshore wind farms; reduced government spending on transmission projects as part of austerity measures may limit demand for high voltage cables; Integration of Draka may lead to operational distractions

Umicore SA (UMI BB / UMI.BR)

Valuation Methodology: Our EUR 45.00 Price Target is derived from our Renewables Valuation Model assuming a high growth period of 3 years, sales growth of 11.5% capital employed growth of 7.0% and return on sales of 18.0%. We assume ormalized growth of 3.0% long term return on sales of 20.0% and pre-tax WACC of 17.4%.

Risks which May Impede the Achievement of the Price Target: Umicore may not be able to source residues to drive its waste business. The company is exposed to volatility in metal prices.

European Integrated Oil

BG Group (BG/ LN / BG.L)

Valuation Methodology: Our price target for BG Group’s shares is derived using a discounted cash flow methodology, using a 10% discount rate. Our calculation includes our estimate of value created from future growth based on the company’s past and expected future return spread over its cost of capital. The cash flows in our calculation comprise both dollar and local currencies. Our price target is set in local currency, based on the dollar exchange rate on the date the target is initially published. Subsequently, the corresponding ADR price target in US dollars will move with the prevailing exchange rate on a daily basis. If the dollar exchange rate relative to the local currency moves significantly compared with the rate used when the local currency price target was initially published, we re-calculate and re-publish the local currency price targets using the current dollar exchange rates. Our price targets are not market-linked.

Risks which May Impede the Achievement of the Price Target: Our BG Group share price target and recommendation depends upon our estimates of profitability and cash flow and the rate at which we discount the cash flows. These estimates in turn are based on assumptions for oil prices and downstream margins. These assumptions depend on the Barclays Capital European Oil and Gas equity research teams estimates for future energy supply-demand patterns, exchange rates, commodity prices. All of our estimates are subject to revision and may be materially different from eventual outcomes. In addition the company operates on a global basis in many regions with sometimes unstable political regimes and changing fiscal terms. The actions of OPEC can also have a significant influence on the oil market. All estimates assume no marked changes in the current political landscape. Both upstream and LNG operations are subject to planned and unplanned downtime. BG has significant exposure to LNG, which is still an evolving industry.

Galp Energia (GALP PL / GALP.LS)

Valuation Methodology: Our price target for GALP’s shares is derived using a discounted cash flow methodology, using a 12% discount rate for refining and power generation and 10% for the upstream assets. Our calculation includes our estimate of value created from future growth based on the company’s past and expected future return spread over its cost of capital. The cash flows in our DCF calculation comprise both dollar and local currencies. Our price target is set in local currency.

Risks which May Impede the Achievement of the Price Target: Our GALP share price target and recommendation depends upon our estimates of profitability and cash flow and the rate at which we discount the cash flows. These estimates in turn are based on assumptions for oil prices and downstream margins. These assumptions depend on the Barclays Capital European Oil & Gas equity research teams estimates for future energy supply-demand patterns, exchange rates, commodity prices. All of our estimates are subject to revision and may be materially different from eventual outcomes. In addition individual refineries are subject to crude supply disruptions or operational failures. GALP also faces additional risk to changes in the Brazilian fiscal regime given its significant upstream exposure there.


1 March 2012 144

Sasol Limited (SOL SJ / SOLJ.J)

Valuation Methodology: Our valuation represents the following multiples: FY12 PER 8.8x, FY13 PER 9.5x, FY12 EV/EBIDA 5.8x, FY13 EV/EBIDA 6.1x and FY11 price/NAV 2.0x. Our discounted cash flow analysis shows a 12-month target price of R455, using a discount rate of 12.6% and a long-term growth rate of 2.75%. Risks which May Impede the Achievement of the Price Target: Key risks include the following. Rand strength versus the US$ which negatively impacts profitability and cash flow. The Rand exchange rate is subject to macro factors which are outside management control. Oil price weakness which negatively impacts profitability and cash flow. The oil price is subject to macro factors which are outside management control. Operational disappointments which are unexpected for example stability problems at the core synfuels operations, unplanned shuts of key facilities or accidents. Project delivery disappointments for example cost overruns, delays in commissioning and/or ramping up of new plants and unexpected changes in project economics. Anti-competitive issues – Sasol is under investigation by South African competition authorities in a numer of industries. The timing of the conclusion of these investigations is unknown and if decisions go against Sasol any resulting fines or compromise agreements could be material. Sasol is exposed to a number of potential regulatory changes – these include the imposition of carbon taxes in South Africa for example which are not quantifiable at this stage and for which timing is unclear. The financial effect could be material however. Sasol operates in a number of countries which are not developed economies eg Iran where changes in the local environment and/or international sentiment may require a significant change in strategy.

Statoil ASA (STL NO / STL.OL)

Valuation Methodology: Our price target for Statoil’s shares is derived using a discounted cash flow methodology, using a 10% discount rate. Our calculation includes our estimate of value created from future growth based on the company’s past and expected future return spread over its cost of capital. The cash flows in our calculation comprise both dollar and local currencies. Our price target is set in local currency, based on the dollar exchange rate on the date the target is initially published. Subsequently, the corresponding ADR price target in US dollars, will move with the prevailing exchange rate on a daily basis. If the dollar exchange rate relative to the local currency moves significantly compared with the rate used when the local currency price target was initially published, we re-calculate and re-publish the local currency price targets using the current dollar exchange rates. Our price targets are not market linked.

Risks which May Impede the Achievement of the Price Target: Our Statoil share price target and recommendation depends upon our estimates of profitability and cash flow and the rate at which we discount the cash flows. These estimates in turn are based on assumptions for oil prices and downstream margins. These assumptions depend on the Barclays Capital European Oil and Gas equity research teams estimates for future energy supply-demand patterns, exchange rates, commodity prices. All of our estimates are subject to revision and may be materially different from eventual outcomes. In addition the company operates on a global basis in many regions with sometimes unstable political regimes and changing fiscal terms. The actions of OPEC can also have a significant influence on the oil market. All estimates assume no marked changes in the current political landscape. Both upstream and downstream operations are subject to planned and unplanned downtime. Statoil is 67% owned by the Norwegian government and its business mix is biased towards upstream operations.

European Oil & Gas: E&P

Afren Plc (AFR LN / AFRE.L)

Valuation Methodology: In valuing each individual stock, we use a risk-based methodology that aims to find the Net Asset Value through a bottom-up approach. We group each company’s assets into two main categories: Core NAV, which reflects the value of producing assets, and those under development, and risked upside which is generated by the value of the company’s exploration and appraisal assets on a risked basis. We name the risk factors applied to the E&A assets the ‘Chance of Success’ (CoS), as commonly known within the industry, which reflects the geological likelihood of finding and developing hydrocarbon accumulation. We then make adjustments to reflect the value of monetary items on the balance sheet. We do not include the present value of G&A costs, as our price target reflects the liquidation price which also allows an asset comparison across different stocks. Our final price target is equal to Total NAV. We apply a higher-than-industry standard 12.5% discount to those assets located in Nigeria. Risks which May Impede the Achievement of the Price Target: All our estimates are based on Barclays Capital European Oil&Gas equity research team’s assumptions for future energy supply-demand patterns, exchange rates, commodity prices. All of our estimates are subject to revision and may be materially different from eventual outcomes. For Afren specifically, we see a higher political risk, especially in Nigeria, which often experiences attacks on its oil infrastructure.

European Oil Services & Drilling

Petroleum Geo-Services (PGS NO / PGS.OL)

Valuation Methodology: Our price target for PGS has been derived from a DCF-based methodology. We have used our forecasted cash flows for the 2011-2013F period and thereafter assumed a cyclical growth (20% pa) until a turn in 2015 when revenues fall (20% pa) until 2017. Margins used for 2014-17F period are comparable to those over the 2004-2008 period. Our terminal value is then taken on a (WACC-g) basis assuming 3% long-term growth. Our discount rate used is 11%, ahead of the 10% that we use for the sector to account for the volatility seen in Norwegian-listed stocks and extreme cyclicality seen in the seismic industry. We then set our price target at a 30% premium to this in-line with historical trading patterns and the 0-30% premium that we use for the sector.The valuation is then checked against historical trading multiples. Risks which May Impede the Achievement of the Price Target: All our estimates are based on Barclays Capital European Oil & Gas equity research team’s estimates for future energy supply-demand patterns, exchange rates, commodity prices and the availability of assets within the oils service industry. These estimates are subject to revision and may be materially different from eventual out comes. In addition workload is executed on a global basis in many regions with unstable regimes. All estimates assume no marked changes in the current political landscape. For PGS specifically the earnings in seismic companies depend on the supply of new boats. Also the company executes multi-client work, using its own capital. Future sales of this work may materially change results.


1 March 2012 145

Saipem (SPM IM / SPMI.MI)

Valuation Methodology: Our price target for Saipem has been derived from a DCF-based methodology. We have used our forecasted cash flows for the 2011-2013F period and thereafter assumed a cyclical growth (15% pa) until a turn in 2016 when revenues fall (15% pa) until 2017. Margins used for 2014-17F period are comparable to those over the 2004-2009 period. Our terminal value is then taken on a (WACC-g) basis assuming 3% long-term growth. Our discount rate used is 9%, 100bp lower the 10% that we use for the sector, reflecting its higher debt levels and shareholding by ENI. We then apply a 30% premium comparable to historic trading patterns and the 0-30% that we use for the sector. The valuation is then checked against historical trading multiples.

Risks which May Impede the Achievement of the Price Target: All our estimates are based on Barclays Capital European Oil and Gas equity research team's estimates for future energy All our estimates are based on Barclays Capital European Oil & Gas equity research teams estimates for future energy supply-demand patterns, exchange rates, commodity prices and the availability of assets within the oils service industry. These estimates are subject to revision and may be materially different from eventual out comes. In addition workload is executed on a global basis in many regions with unstable regimes. All estimates assume no marked changes in the current political landscape. For Saipem specifically, earnings are exposed to lump sum contracts, which if executed incorrectly can produce significant negative margins. In addition backlog award can be lumpy and profit recognition on projects is often in a non-linear fashion. As a result there may be periodic swings in profitability.

Subsea 7 SA (SUBC NO / SUBC.OL)

Valuation Methodology: Our price target for Subsea 7 SA has been derived from a DCF-based methodology. We have used our forecasted cash flows for the 2010-2013F period and thereafter assumed a cyclical growth (15% pa) until a turn in 2015 when revenues fall (15% pa) until 2017. Our terminal value is then taken on a (WACC-g) basis assuming 3% long-term growth. Our discount rate used is 10%, in-line with the 10% that we use for the sector. We have then applied a 30% premium in-line with what we use for the sector. The valuation is then checked against historical trading multiples.

Risks which May Impede the Achievement of the Price Target: All our estimates are based on Barclays Capital European Oil & Gas equity research teams estimates for future energy supply-demand patterns, exchange rates, commodity prices and the availability of assets within the oils service industry. These estimates are subject to revision and may be materially different from eventual out comes. In addition workload is executed on a global basis in many regions with unstable regimes. All estimates assume no marked changes in the current political landscape. For Subsea 7 SA specifically, earnings are exposed to lump-sum contracts, which if executed incorrectly can produce significant negative margins. In addition backlog award can be lumpy and profit recognition on projects is often in a non-linear fashion. As a result there may be periodic swings in profitability. Furthermore, all marine activities are subject to risk and rely heavily on the operational efficiency of the company's vessels.

European Refining & Marketing

Motor Oil (MOH GA / MORr.AT)

Valuation Methodology: Our price target for Motor Oils shares is derived using a discounted cash flow methodology, using a 12% discount rate. Our calculation includes our estimate of value created from future growth based on the companys past and expected future return spread over its cost of capital. The cash flows in our DCF calculation comprise both dollar and local currencies. Our price target is set in local currency.

Risks which May Impede the Achievement of the Price Target: .Our Motor Oil share price target and recommendation depends upon our estimates of profitability and cash flow and the rate at which we discount the cash flows. These estimates in turn are based on assumptions for oil prices and downstream margins. These assumptions depend on the Barclays Capital European Oil & Gas equity research teams estimates for future energy supply-demand patterns, exchange rates, commodity prices. All of our estimates are subject to revision and may be materially different from eventual outcomes. In addition individual refineries are subject to crude supply disruptions or operational failures.

Neste Oil (NES1V FH / NES1V.HE)

Valuation Methodology: Our price target for Neste Oil's shares is derived using a discounted cash flow methodology, using a 12% discount rate. Our calculation includes our estimate of value created from future growth based on the company's past and expected future return spread over its cost of capital. The cash flows in our DCF calculation comprise both dollar and local currencies. Our price target is set in local currency.

Risks which May Impede the Achievement of the Price Target: Our Neste Oil share price target and recommendation depend on our estimates of profitability and cash flow and the rate at which we discount the cash flows. These estimates in turn are based on assumptions for oil prices and downstream margins. These assumptions depend on the Barclays Capital European Oil & Gas equity research team's estimates for future energy supply-demand patterns, exchange rates, commodity prices. All of our estimates are subject to revision and may be materially different from eventual outcomes. In addition, individual refineries are subject to crude supply disruptions or operational failures.

European Utilities

Drax Group (DRX LN / DRX.L)

Valuation Methodology: We value Drax based on a DCF valuation model. We assume a 7.6% post-tax WACC and mark our commodity price assumptions to market. Our central scenario assumes that Drax converts to 50% biomass co-firing by 2015, with biomass costs at 2.2x coal on average. However, we also assign a 15% probability to Drax converting to 100% biomass by 2020. In combination, this leads to a £6.75 price target.

Risks which May Impede the Achievement of the Price Target: Drax is a risky stock and several uncertainties remain, which could trigger both upside and downside risks: 1) future ROC bandings or feed-in tariff support; 2) the level of capex required to convert the plant; 3) technical uncertainties, including the impact of conversion on thermal efficiency; 4) capital structure; 5) biomass availability and price; 6) the overall level of power prices. Drax's DCF is highly sensitive to these assumptions.


1 March 2012 146

National Grid Plc (NG/ LN / NG.L)

Valuation Methodology: We value National Grid with a SOTP approach. UK regulated activities are valued with an RAV-adjusted approach, US assets with EV/EBITDA multiples differentiated by businesses and not regulated activities at DCF or multiples as appropriate. Net debt is included at book value.

Risks which May Impede the Achievement of the Price Target: National Grid financials and valuation are based on current tariffs. A change to the regulatory framework might affect our estimates.

Pennon Group Plc (PNN LN / PNN.L)

Valuation Methodology: We value the regulated water business using a DCF approach. We discount cashflows to March 2015 at a WACC unique to the company which is based on our assessment of its cost of debt and equity. For our March 2015 terminal value we take our forecast of COPI-adjusted nominal RCV at that date and apply a premium to reflect our view on the long term strategic positioning of the business. We value Viridor on a sum-of-the-parts basis using DCF and multiple based valuations for the different areas of the business.

Risks which May Impede the Achievement of the Price Target: Arbitrary changes to the regulatory framework; political intervention; dislocation in the credit markets leading to elevated borrowing costs; a sudden sharp downturn in water consumption; a sustained period of deflation; a sudden sharp deterioration in waste volumes, power prices, recyclate prices or gate fees; management changes

North America Metals & Mining

Alpha Natural Resources (ANR)

Valuation Methodology: Our $29 price target is based on a 5.0x EV multiple of our 2013 EBTIDA estimate of $1.77B.

Risks which May Impede the Achievement of the Price Target: A substantial drop in coal prices, or sustained operational difficulties (geology, labor, geopolitical) could cause Alpha to perform materially lower than our expectations.

CONSOL Energy (CNX)


Risks which May Impede the Achievement of the Price Target: A substantial drop in coal and/or natural gas prices, delays in planned development in the company's shale gas plays, or sustained operational difficulties (geology, labor, political) could cause CONSOL to perform materially lower than our expectations.

Peabody Energy (BTU)


Risks which May Impede the Achievement of the Price Target: A substantial drop in international coal prices, delays in development of the company's expansion projects, or sustained operational difficulties (geology, labor, geopolitical) could cause Peabody to perform materially lower than our expectations.

North America Oil & Gas: E&P (Large Cap)

EOG Resources (EOG)

Valuation Methodology: Our price target of $144 is derived by applying a 7.5x multiple on 2013 hedge-adjusted pre-interest cash flow (PICF) estimate, based on a mid-cycle commodity price scenario, to obtain an implied Enterprise Value (EV). The estimate for 2013 PICF is based on a benchmark natural gas price forecast of $3.50/MMBtu (HH) and an oil price forecast of $95.00/bbl (WTI). To calculate a target stock market value, we subtract projected year-end 2012 net debt, FAS143 asset retirement obligation and estimated 2013 hedge gain. Our target EV is based on 2013 PICF before hedging impacts; and our target price treats estimated hedge gains/losses as a financial instrument (i.e. valued at one times the forecast gains/losses).

Risks which May Impede the Achievement of the Price Target: Should commodity prices, production levels, or leverage differ materially from our estimates, our price target would be affected. The company's production levels are impacted by a variety of factors including drilling success, reservoir performance and future acquisitions.

Noble Energy (NBL)

Valuation Methodology: Our price target of $123 is derived by applying a 7.90x multiple on our forward-year (2013) hedge-adjusted pre-interest cash flow (PICF) estimate to obtain an implied Enterprise Value (EV). The estimate for forward-year PICF is based on a benchmark natural gas price forecast of $3.50/MMBtu (HH) and an oil price forecast of $95.00/bbl (WTI). To calculate a target stock market value, we subtract projected year-end 2012 net debt and FAS143 asset retirement obligation. Our target EV is based on 2013 PICF before hedging impacts; and our target price treats estimated hedge gains/losses as a financial instrument (i.e. valued at one times the forecast gains/losses).

Risks which May Impede the Achievement of the Price Target: Should commodity prices, production levels, or leverage differ materially from our estimates, our price target would be affected. The company's production levels are impacted by a variety of factors including drilling success, reservoir performance and future acquisitions.

U.S. Clean Technology & Renewables

Ameresco Inc. (AMRC)

Valuation Methodology: Our price target of $14 equates to ~14x our CY13 EPS estimate of $0.97

Risks which May Impede the Achievement of the Price Target: Wealend demand in the MUSH markets and a delay in federal activity could negatively impact the company's top line trajectory. Moreover, the ESCO business model is highly dependent on third party financing, and thus the inability for Ameresco to secure financing could materially impact its ability to deliver energy savings solutions.


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Elster Group SE (ELT)

Valuation Methodology: Our $18 price target equates to ~14x our CY13 EPS estimate of $1.33.

Risks which May Impede the Achievement of the Price Target: A more prolonged deployment of next generation smart grid technologies in regions outside of the U.S. would negatively impact Elster's top line trajectory and thus serves as a major risk to growth in the company's revenue line. Additional pricing pressure as other vendors look to capture incremental share as well as further consolidation in the market are key risks as well.

Power-One Inc. (PWER)

Valuation Methodology: Our $6 price target equates to ~9x our CY13 EPS estimate of $0.62.

Risks which May Impede the Achievement of the Price Target: Key risks to our outlook include PWER's inability to gain share outside of Europe, incremental pricing pressure in the inverter market beyond our current expectations, and the potential emergence of lower cost players from regions such as China. Moreover, if current solar industry challenges persist, this could negatively impact overall demand for PV systems.

Tesla Motors Inc. (TSLA)

Valuation Methodology: Our price target of $38 is 15x our CY14 EPS estimate of $2.50, equating to 41x our CY13 EPS estimate of $0.93.

Risks which May Impede the Achievement of the Price Target: We consider Tesla a binary event. If management is able to execute on its planned product roadmap, we see significant opportunities in the premium market for its vehicles particularly given technology differentiation and performance. However, the inability to execute - i.e. ramp its production line - could lead to an unravelling of its strategy and ultimately yield a severe cash crunch on its business. Other risks include an inability to differentiate its products from competition from larger scale, better capitalized OEMs.

U.S. Independent Refiners

Marathon Petroleum Corp. (MPC)

Valuation Methodology: Based on a $5/bl Brent/WTI differential, Gulf Coast LLS 6-3-2-1 of $3/bl, LLS/Maya discount of $13/bl, we estimate MPC's adjusted annual EBITDA at $8.0/share, which includes our MLP EBITDA estimate of $1.7/share. Using a 4.5x-5.5x multiple for the base adjusted EBITDA and a 9x multiple for the MLP EBITDA, we estimate that this should support a share price of $42-49. Assuming it may take two years for the Brent/WTI differential to settle at $5/bl (assuming an average of $9.3/bl over the next 24 months), we estimate MPC could be worth $45-51/share. Our price target is based on the upper end of the range due to the company's strong free cash flow generating capability and recently upgraded refining portfolio.

Risks which May Impede the Achievement of the Price Target: Our earnings estimates are based on our current commodity price assumption on oil & gas, refining, and marketing margins as well as chemical product margins. Thus, results could be subject to changes due to fluctuations in the macro commodity market environment.

Tesoro Corporation (TSO)

Valuation Methodology: Risks to Thesis and Valuation (use bold typeface to summarise in 5-9 words the main risk to your thesis): Spell out risks to your thesis and valuation. Add credibility by directly addressing challenging counter-arguments and potential controversies in your assumptions. Highlight the balance of positive & negative risks implied in your valuation framework.


Valero Energy (VLO)

Valuation Methodology: Our price target assumes that VLO should trade at $610 per daily b/d complexity, or 34% of the greenfield replacement cost of $1,800 per b/d complexity. At the bottom of the last two cyclical downturns in 2002 and 1999, the company traded at 29% and 24% of the greenfield replacement cost, respectively.


U.S. Oil & Gas: E&P (Mid-Cap)

Denbury Resources (DNR)

Valuation Methodology: Our price target is based on a target multiple of 7.0x our hedge-adjusted 2013 pre-interest cash flow estimate of $1,652 million less estimated net debt at year-end 2012 of $2,102 million.

Risks which May Impede the Achievement of the Price Target: Our NYMEX price deck is $95/bbl for oil and $3.00/MMBtu for gas in 2012 and $95/bbl for oil and $3.50/MMBtu for gas in 2013. Should commodity prices, production levels, or leverage differ materially from our estimates, our price target would likely be affected. Production levels may be impacted by a variety of factors including drilling success, reservoir performance, and future acquisitions.


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Plains Exploration & Production (PXP)

Valuation Methodology: Our target price is based on a multiple of 6.0x our hedge-adjusted 2013 pre-interest cash flow of $1,623 million less estimated net debt at year-end 2012 of $3,027 million less an estimated derivative loss of $91 million in 2013 plus an estimated value of the company's equity stake in McMoran Exploration of $628 million.


Whiting Petroleum (WLL)

Valuation Methodology: Our target price is based on a multiple of 6.0x our hedge-adjusted 2013 pre-interest cash flow estimate of $1,632 million less estimated net debt at year-end 2012 of $1,560 million plus an estimated value of WLL's ownership stake in Whiting USA Trust I of $40 million less an estimated derivative gain of $1 million in 2013 and beyond.


U.S. Oil Services & Drilling

Baker Hughes (BHI)

Valuation Methodology: Our 12-month price target of $85 is based on 14x our 2013 earnings estimate of $6.05.

Risks which May Impede the Achievement of the Price Target: A material change in commodity prices would alter our earnings outlook and potentially our stance on the entire oil service and drilling sector. Commodity price changes could be affected by a change in the economic climate, gas storage levels, OPEC behavior, increasing non-OPEC oil production and international political and economic risks.

Halliburton Co. (HAL)

Valuation Methodology: Our 12-month price target of $67 is based on 13.8x our 2013 earnings estimate of $4.85.

Risks which May Impede the Achievement of the Price Target: A material change in commodity prices would alter our earnings outlook and potentially our stance on the entire oil service and drilling sector. Commodity price changes could be affected by a change in the economic climate, gas storage levels, OPEC behavior, increasing non-OPEC oil production, and international political and economic risks.

Schlumberger Ltd. (SLB)

Valuation Methodology: Our price target of $107 is based on 17.9x our 2013 earnings estimate of $6.00.


Weatherford International (WFT)

Valuation Methodology: Our price target of $27 is based on 13.8x our 2013 earnings estimate of $1.95.


U.S. Power

Calpine Corp. (CPN)

Valuation Methodology: Our price target of $18 is the average of our asset valuation of $18/share which includes EV of $15B, $1.7B NOL NPV, hedge NPV of $571M, net debt of $9.2B in 2013 and 461M shares and $17/share which is 7.1x Power Open EBITDA of $1.62B and renewable EBITDA of $436M at 8x of geothermal EBITDA less net debt and other items mentioned above.

Risks which May Impede the Achievement of the Price Target: Risks for Calpine are the higher reserve margins, recession, wholesale market regulatory risk; risk of environmental mandates, and gas price.

NextEra Energy (NEE)

Valuation Methodology: Our price target of $61 is based on an average of: $54 for 8.05x 2013 open EBITDA of $5.0B, less a combination of net debt and hedge and wind backlog NPVs of $17.2B; $67 for an asset-based sum-of-parts; and $61 for a 2013 integrated P/E multiple of 12.2x our $4.99 earnings estimate.

Risks which May Impede the Achievement of the Price Target: NextEra Energy Resources has merchant exposure to volatile gas and power prices, and risks associated with expansion in the size of its wind asset base. In addition, volatility around fuel prices and high levels of capital spending at its utility present regulatory risk.

Source: Barclays Capital


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ANALYST CERTIFICATION(S) In relation to our respective sections, we, Tim Whittaker, Amrita Sen, Helima L. Croft, Miswin Mahesh, Trevor Sikorski, Michael Zenker, Shiyang Wang, Harry Mateer, Ming Zhang, Kateryna Kukuruza, Gary Stromberg, Oscar Bate, Matthew Vittorioso, Jim Asselstine, Emmanuel Owusu-Darkwa, CFA, Erly Witoyo, Timothy Tay, CFA, Paul Y. Cheng, CFA, Lucy Haskins, Rahim Karim, Lydia Rainforth, CFA, Caroline Learmonth, Clement Chen, Scott Darling, Thomas R. Driscoll, CFA, Jeffrey W. Robertson, Grant Hofer, CFA, Alessandro Pozzi, James C. West, Tom Ackermans, Mick Pickup, David Gagliano, CFA, Ephrem Ravi, Daniel Ford, CFA, Gregg Orrill, Julie Arav, Peter Bisztyga, Wen Du, Monica Girardi, Susanna Invernizzi, Harry Wyburd, Amir Rozwadowski, Rupesh Madlani and Christopher Smith, hereby certify (1) that the views expressed in this research report accurately reflect our personal views about any or all of the subject securities or issuers referred to in this research report and (2) no part of our compensation was, is or will be directly or indirectly related to the specific recommendations or views expressed in this research report.

IMPORTANT DISCLOSURES: FIXED INCOME RESEARCH For current important disclosures regarding companies that are the subject of this research report, please send a written request to: Barclays Capital Research Compliance, 745 Seventh Avenue, 17th Floor, New York, NY 10019 or refer to http://publicresearch.barcap.com or call 212-526-1072. Barclays Capital does and seeks to do business with companies covered in its research reports. As a result, investors should be aware that Barclays Capital may have a conflict of interest that could affect the objectivity of this report. Any reference to Barclays Capital includes its affiliates. Barclays Capital and/or an affiliate thereof (the "firm") regularly trades, generally deals as principal and generally provides liquidity (as market maker or otherwise) in the debt securities that are the subject of this research report (and related derivatives thereof). The firm's proprietary trading accounts may have either a long and / or short position in such securities and / or derivative instruments, which may pose a conflict with the interests of investing customers. Where permitted and subject to appropriate information barrier restrictions, the firm's fixed income research analysts regularly interact with its trading desk personnel to determine current prices of fixed income securities. The firm's fixed income research analyst(s) receive compensation based on various factors including, but not limited to, the quality of their work, the overall performance of the firm (including the profitability of the investment banking department), the profitability and revenues of the Fixed Income Division and the outstanding principal amount and trading value of, the profitability of, and the potential interest of the firms investing clients in research with respect to, the asset class covered by the analyst. To the extent that any historical pricing information was obtained from Barclays Capital trading desks, the firm makes no representation that it is accurate or complete. All levels, prices and spreads are historical and do not represent current market levels, prices or spreads, some or all of which may have changed since the publication of this document. Barclays Capital produces a variety of research products including, but not limited to, fundamental analysis, equity-linked analysis, quantitative analysis, and trade ideas. Recommendations contained in one type of research product may differ from recommendations contained in other types of research products, whether as a result of differing time horizons, methodologies, or otherwise. In order to access Barclays Capital's Statement regarding Research Dissemination Policies and Procedures, please refer to https://live.barcap.com/publiccp/RSR/nyfipubs/disclaimer/disclaimer-research-dissemination.html.

Barclays Capital is acting as exclusive financial advisor to Enterprise Products Partners (EPD) and rendered a fairness opinion to the Board of Directors of EPD in their definitive merger agreement with Duncan Energy Partners (DEP). The rating on EPD does not incorporate this potential transaction. Barclays Capital is providing investment banking services to Williams Companies, Inc. (WMB) in connection with its potential acquisition of all of the outstanding shares of Southern Union Company (SUG). All ratings, estimates and price targets (as applicable) on Energy Transfer Equity (ETE) and Southern Union (SUG), issued by the firm's Research Department have been temporarily suspended due to Barclays Capital's role in this potential transaction. Barclays Capital is providing investment banking services to Atinum Partners in their agreement to establish a joint venture in the Mississippian oil resource play with Sandridge Energy. Barclays Capital is providing investment banking services to Repsol YPF in the potential acquisition of OAO Eurotek. Barclays Capital is acting as financial advisor to Repsol YPF SA in relation to the forming of an exploration and production venture in Russia with Alliance Oil Co. Barclays Capital is providing investment banking services to Plains All American Pipeline (PAA) in the potential acquisition of BP's Canadian natural gas liquids (NGL) and liquefied petroleum gas (LPG) business. Barclays Capital, the Investment Banking Division of Barclays Bank PLC, is acting as corporate broker to BUMI PLC.

Explanation of the High Grade Sector Weighting System Overweight: Expected six-month excess return of the sector exceeds the six-month expected excess return of the Barclays Capital U.S. Credit Index, the Pan-European Credit Index, or the EM Asia USD High Grade Credit Index, as applicable. Market Weight: Expected six-month excess return of the sector is in line with the six-month expected excess return of the Barclays Capital U.S. Credit Index, the Pan-European Credit Index, or the EM Asia USD High Grade Credit Index, as applicable. Underweight: Expected six-month excess return of the sector is below the six-month expected excess return of the Barclays Capital U.S. Credit Index, the Pan-European Credit Index, or the EM Asia USD High Grade Credit Index, as applicable.

Explanation of the High Grade Research Rating System The High Grade Research rating system is based on the analyst's view of the expected excess returns over a six-month period of the issuer's index-eligible corporate debt securities relative to the Barclays Capital U.S. Credit Index, the Pan-European Credit Index or the EM Asia USD High Grade Credit Index, as applicable. Overweight: The analyst expects the issuer's index-eligible corporate bonds to provide positive excess returns relative to the Barclays Capital U.S. Credit Index, the Pan-European Credit Index, or the EM Asia USD High Grade Credit Index over the next six months. Market Weight: The analyst expects the issuer's index-eligible corporate bonds to provide excess returns in line with the Barclays Capital U.S. Credit Index, the Pan-European Credit Index, or the EM Asia USD High Grade Credit Index over the next six months. Underweight: The analyst expects the issuer's index-eligible corporate bonds to provide negative excess returns relative to the Barclays Capital U.S. Credit Index, the Pan-European Credit Index, or the EM Asia USD High Grade Credit Index over the next six months. Rating Suspended (RS): The rating has been suspended temporarily due to market events that make coverage impracticable or to comply with applicable regulations and/or firm policies in certain circumstances including where Barclays Capital is acting in an advisory capacity in a merger or strategic transaction involving the company. Coverage Suspended (CS): Coverage of this issuer has been temporarily suspended. Not Rated (NR): An issuer which has not been assigned a formal rating. For Australia issuers, the ratings are relative to the Barclays Capital U.S. Credit Index or Pan-European Credit Index, as applicable.


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IMPORTANT DISCLOSURES: FIXED INCOME RESEARCH (CONTINUED) Explanation of the High Yield Sector Weighting System Overweight: Expected six-month total return of the sector exceeds the six-month expected total return of the Barclays Capital U.S. High Yield 2% Issuer Capped Credit Index, the Pan-European High Yield 3% Issuer Capped Credit Index excluding Financials, or the EM Asia USD High Yield Corporate Credit Index, as applicable. Market Weight: Expected six-month total return of the sector is in line with the six-month expected total return of the Barclays Capital U.S. High Yield 2% Issuer Capped Credit Index, the Pan-European High Yield 3% Issuer Capped Credit Index excluding Financials, or the EM Asia USD High Yield Corporate Credit Index, as applicable. Underweight: Expected six-month total return of the sector is below the six-month expected total return of the Barclays Capital U.S. High Yield 2% Issuer Capped Credit Index, the Pan-European High Yield 3% Issuer Capped Credit Index excluding Financials, or the EM Asia USD High Yield Corporate Credit Index, as applicable. Explanation of the High Yield Research Rating System The High Yield Research team employs a relative return based rating system that, depending on the company under analysis, may be applied to either some or all of the company's debt securities, bank loans, or other instruments. Please review the latest report on a company to ascertain the application of the rating system to that company. Overweight: The analyst expects the six-month total return of the rated debt security or instrument to exceed the six-month expected total return of the Barclays Capital U.S. 2% Issuer Capped High Yield Credit Index, the Pan-European High Yield 3% Issuer Capped Credit Index excluding Financials, or the EM Asia USD High Yield Corporate Credit Index, as applicable. Market Weight: The analyst expects the six-month total return of the rated debt security or instrument to be in line with the six-month expected total return of the Barclays Capital U.S. 2% Issuer Capped High Yield Credit Index, the Pan-European High Yield 3% Issuer Capped Credit Index excluding Financials, or the EM Asia USD High Yield Corporate Credit Index, as applicable. Underweight: The analyst expects the six-month total return of the rated debt security or instrument to be below the six-month expected total return of the Barclays Capital U.S. 2% Issuer Capped High Yield Credit Index, the Pan-European High Yield 3% Issuer Capped Credit Index excluding Financials, or the EM Asia USD High Yield Corporate Credit Index, as applicable. Rating Suspended (RS): The rating has been suspended temporarily due to market events that make coverage impracticable or to comply with applicable regulations and/or firm policies in certain circumstances including where Barclays Capital is acting in an advisory capacity in a merger or strategic transaction involving the company. Coverage Suspended (CS): Coverage of this issuer has been temporarily suspended. Not Rated (NR): An issuer which has not been assigned a formal rating.


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IMPORTANT DISCLOSURES: EQUITY RESEARCH

When an equity research report covers six or more subject companies, Barclays Capital generally does not include specific conflict of interest disclosures regarding the subject companies and instead provides the reader with instructions about how to view or obtain the applicable conflictof interest disclosures. In order to comply with the requirements of the Korea Financial Investment Association, specific disclosures aboutsubject companies with securities listed on the Korea Exchange are included herein. To access important disclosures, including, where relevant,price targets, regarding other companies that are the subject of this research report, please send a written request to: Barclays Capital ResearchCompliance, 745 Seventh Avenue, 17th Floor, New York, NY 10019 or refer to http://publicresearch.barcap.com or call 1-212-526-1072.

The analysts responsible for preparing this research report have received compensation based upon various factors including the firm's totalrevenues, a portion of which is generated by investment banking activities.

Research analysts employed outside the US by affiliates of Barclays Capital Inc. are not registered/qualified as research analysts with FINRA.These analysts may not be associated persons of the member firm and therefore may not be subject to NASD Rule 2711 and incorporated NYSERule 472 restrictions on communications with a subject company, public appearances and trading securities held by a research analyst’saccount.

Analysts regularly conduct site visits to view the material operations of covered companies, but Barclays Capital policy prohibits them from accepting payment or reimbursement by any covered company of the their travel expenses for such visits.

In order to access Barclays Capital's Statement regarding Research Dissemination Policies and Procedures, please refer tohttps://live.barcap.com/publiccp/RSR/nyfipubs/disclaimer/disclaimer-research-dissemination.html.

Barclays Capital produces a variety of research products including, but not limited to, fundamental analysis, equity-linked analysis, quantitative analysis, and trade ideas. Recommendations contained in one type of research product may differ from recommendations contained in othertypes of research products, whether as a result of differing time horizons, methodologies, or otherwise.

Primary Stocks (Ticker, Date, Price)

Afren Plc (AFRE.L, 28-Feb-2012, GBP 1.39), 1-Overweight/1-Positive

Alpha Natural Resources (ANR, 28-Feb-2012, USD 19.22), 1-Overweight/1-Positive

Ameresco Inc. (AMRC, 28-Feb-2012, USD 13.76), 1-Overweight/2-Neutral

Anadarko Petroleum (APC, 28-Feb-2012, USD 85.89), 1-Overweight/2-Neutral

Apache Corp. (APA, 28-Feb-2012, USD 109.59), 1-Overweight/2-Neutral

Baker Hughes (BHI, 28-Feb-2012, USD 51.00), 1-Overweight/1-Positive

BG Group (BG.L, 28-Feb-2012, GBP 15.33), 1-Overweight/2-Neutral

Calpine Corp. (CPN, 28-Feb-2012, USD 15.21), 1-Overweight/2-Neutral

Cameron International (CAM, 28-Feb-2012, USD 55.81), 1-Overweight/1-Positive

China Coal Energy Co., Ltd. (1898.HK, 28-Feb-2012, HKD 10.06), 1-Overweight/1-Positive

CNOOC (0883.HK, 28-Feb-2012, HKD 17.76), 1-Overweight/1-Positive

CONSOL Energy (CNX, 28-Feb-2012, USD 36.30), 1-Overweight/1-Positive

Crescent Point Energy Corp. (CPG.TO, 28-Feb-2012, CAD 46.46), 1-Overweight/1-Positive

Denbury Resources (DNR, 28-Feb-2012, USD 20.44), 1-Overweight/1-Positive

Devon Energy (DVN, 28-Feb-2012, USD 73.98), 1-Overweight/2-Neutral

Drax Group (DRX.L, 28-Feb-2012, GBP 5.15), 1-Overweight/2-Neutral

Dresser-Rand Group Inc. (DRC, 28-Feb-2012, USD 53.32), 1-Overweight/1-Positive

Elster Group SE (ELT, 28-Feb-2012, USD 14.58), 1-Overweight/2-Neutral

EnCana Corp. (ECA, 28-Feb-2012, USD 20.09), 2-Equal Weight/2-Neutral

Ensco plc (ESV, 28-Feb-2012, USD 58.34), 1-Overweight/1-Positive

EOG Resources (EOG, 28-Feb-2012, USD 116.61), 1-Overweight/2-Neutral

Galp Energia (GALP.LS, 28-Feb-2012, EUR 13.02), 1-Overweight/2-Neutral

Global Geophysical Services (GGS, 28-Feb-2012, USD 11.32), 1-Overweight/1-Positive

GulfMark Offshore, Inc. (GLF, 28-Feb-2012, USD 52.63), 1-Overweight/1-Positive

Halliburton Co. (HAL, 28-Feb-2012, USD 37.68), 1-Overweight/1-Positive

Hellenic Petroleum (HEPr.AT, 28-Feb-2012, EUR 5.48), 2-Equal Weight/3-Negative

Hess Corp. (HES, 28-Feb-2012, USD 65.86), 1-Overweight/1-Positive

Hornbeck Offshore Services (HOS, 28-Feb-2012, USD 41.72), 1-Overweight/1-Positive

Hunting (HTG.L, 28-Feb-2012, GBp 826.0), 1-Overweight/1-Positive

Imperial Oil Ltd. (IMO.TO, 28-Feb-2012, CAD 47.89), 1-Overweight/1-Positive


1 March 2012 152

IMPORTANT DISCLOSURES: EQUITY RESEARCH (CONTINUED)

International Power Plc (IPR.L, 28-Feb-2012, GBP 3.45), 1-Overweight/2-Neutral

ION Geophysical Corp. (IO, 28-Feb-2012, USD 7.38), 1-Overweight/1-Positive

Marathon Petroleum Corp. (MPC, 28-Feb-2012, USD 41.67), 1-Overweight/1-Positive

Motor Oil (MORr.AT, 28-Feb-2012, EUR 5.40), 1-Overweight/3-Negative

National Grid Plc (NG.L, 28-Feb-2012, GBP 6.42), 1-Overweight/2-Neutral

National Oilwell Varco (NOV, 28-Feb-2012, USD 84.53), 1-Overweight/1-Positive

Neste Oil (NES1V.HE, 28-Feb-2012, EUR 9.27), 1-Overweight/3-Negative

NextEra Energy (NEE, 28-Feb-2012, USD 60.48), 1-Overweight/2-Neutral

Noble Corp. (NE, 28-Feb-2012, USD 39.89), 1-Overweight/1-Positive

Noble Energy (NBL, 28-Feb-2012, USD 102.48), 1-Overweight/2-Neutral

OCI Co., Ltd. (010060.KS, 28-Feb-2012, KRW 269000.00), 2-Equal Weight/2-Neutral

Outotec Oyj (OTE1V.HE, 28-Feb-2012, EUR 45.50), 1-Overweight/1-Positive

Peabody Energy (BTU, 28-Feb-2012, USD 35.40), 1-Overweight/1-Positive

Pennon Group Plc (PNN.L, 28-Feb-2012, GBp 706.0), 1-Overweight/2-Neutral

PetroBakken Energy Ltd. (PBN.TO, 28-Feb-2012, CAD 16.16), 1-Overweight/1-Positive

PetroChina (0857.HK, 28-Feb-2012, HKD 11.78), 1-Overweight/1-Positive

Petroleum Geo-Services (PGS.OL, 28-Feb-2012, NOK 84.40), 1-Overweight/1-Positive

PKN Orlen (PKNA.WA, 28-Feb-2012, PLN 35.85), 3-Underweight/3-Negative

Plains Exploration & Production (PXP, 28-Feb-2012, USD 44.27), 1-Overweight/1-Positive

Polarcus (PLCS.OL, 28-Feb-2012, NOK 5.52), 1-Overweight/1-Positive

Power-One Inc. (PWER, 28-Feb-2012, USD 4.60), 1-Overweight/2-Neutral

Premier Oil (PMO.L, 28-Feb-2012, GBP 4.48), 1-Overweight/1-Positive

Prysmian SpA (PRY.MI, 28-Feb-2012, EUR 12.81), 1-Overweight/1-Positive

QEP Resources (QEP, 28-Feb-2012, USD 34.76), 1-Overweight/2-Neutral

Range Resources Corp. (RRC, 28-Feb-2012, USD 63.72), 2-Equal Weight/2-Neutral

Repsol YPF (REP.MC, 28-Feb-2012, EUR 20.56), 1-Overweight/2-Neutral

Rockhopper Exploration (RKH.L, 28-Feb-2012, GBP 3.82), 1-Overweight/1-Positive

Rowan Companies (RDC, 28-Feb-2012, USD 36.24), 1-Overweight/1-Positive

Saipem (SPMI.MI, 28-Feb-2012, EUR 38.05), 1-Overweight/1-Positive

Salamander Energy (SMDR.L, 28-Feb-2012, GBP 2.50), 1-Overweight/1-Positive

Saras (SRS.MI, 28-Feb-2012, EUR 1.07), 3-Underweight/3-Negative

Sasol Limited (SOLJ.J, 28-Feb-2012, ZAR 401.45), 1-Overweight/2-Neutral

Schlumberger Ltd. (SLB, 28-Feb-2012, USD 78.78), 1-Overweight/1-Positive

Sinopec (0386.HK, 28-Feb-2012, HKD 8.78), 2-Equal Weight/1-Positive

Southwestern Energy Co. (SWN, 28-Feb-2012, USD 33.31), 2-Equal Weight/2-Neutral

Statoil ASA (STL.OL, 28-Feb-2012, NOK 160.50), 1-Overweight/2-Neutral

Statoil Fuel & Retail (SFRET.OL, 28-Feb-2012, NOK 36.75), 2-Equal Weight/3-Negative

Subsea 7 SA (SUBC.OL, 28-Feb-2012, NOK 134.40), 1-Overweight/1-Positive

Suncor Energy (SU, 28-Feb-2012, CAD 36.28), 1-Overweight/1-Positive

Superior Energy Services Inc. (SPN, 28-Feb-2012, USD 29.95), 1-Overweight/1-Positive

Tesla Motors Inc. (TSLA, 28-Feb-2012, USD 33.81), 1-Overweight/2-Neutral

Tesoro Corporation (TSO, 28-Feb-2012, USD 26.91), 1-Overweight/1-Positive

Transocean Ltd. (RIG, 28-Feb-2012, USD 54.18), 1-Overweight/1-Positive

Tullow Oil (TLW.L, 28-Feb-2012, GBP 15.08), 1-Overweight/1-Positive

Ultra Petroleum Corp. (UPL, 28-Feb-2012, USD 24.25), 2-Equal Weight/2-Neutral

Umicore SA (UMI.BR, 28-Feb-2012, EUR 39.24), 1-Overweight/1-Positive

Valero Energy (VLO, 28-Feb-2012, USD 24.79), 1-Overweight/1-Positive


1 March 2012 153


Weatherford International (WFT, 28-Feb-2012, USD 16.41), 1-Overweight/1-Positive

Whiting Petroleum (WLL, 28-Feb-2012, USD 59.94), 1-Overweight/1-Positive

WPX Energy (WPX, 28-Feb-2012, USD 18.60), 1-Overweight/2-Neutral

Other Material Conflicts

Barclays Capital is acting as dealer manager on a tender offer for the Severn Trent Utilities Finance Plc GBP200,000,000 5.25% Notes due 2014.

Barclays Capital is providing investment banking services to Repsol YPF in the potential acquisition of OAO Eurotek.

Barclays Capital is acting as financial advisor to Repsol YPF SA in relation to the forming of an exploration and production venture in Russia withAlliance Oil Co.

Barclays Capital is providing investment banking services to Plains All American Pipeline (PAA) in the potential acquisition of BP's Canadiannatural gas liquids (NGL) and liquefied petroleum gas (LPG) business.

Barclays Capital is providing investment banking services to LINN Energy in relation to the potential acquisition of BP's Hugoton Basin properties.

Barclays Capital, the Investment Banking Division of Barclays Bank PLC, is Corporate Broker to Hunting Plc.

Barclays Capital, the Investment Banking Division of Barclays Bank PLC, is acting as corporate broker to International Power PLC.

Barclays Capital, the Investment Banking Division of Barclays Bank PLC, is acting as corporate broker to National Grid Plc.

Barclays Capital, the Investment Banking Division of Barclays Bank PLC, is acting as corporate broker to Tullow Oil PLC.

Barclays Capital is providing investment banking services to Antero Resources in its acquisition of Crestwood Midstream Partners' (CMLP)Marcellus Shale Gathering Assets.

Barclays Capital is providing investment banking services to AES Eastern in connection with its announced restructuring.

Guide to the Barclays Capital Fundamental Equity Research Rating System:

Our coverage analysts use a relative rating system in which they rate stocks as 1-Overweight, 2-Equal Weight or 3-Underweight (see definitions below) relative to other companies covered by the analyst or a team of analysts that are deemed to be in the same industry sector (the "sectorcoverage universe").

In addition to the stock rating, we provide sector views which rate the outlook for the sector coverage universe as 1-Positive, 2-Neutral or 3-Negative (see definitions below). A rating system using terms such as buy, hold and sell is not the equivalent of our rating system. Investorsshould carefully read the entire research report including the definitions of all ratings and not infer its contents from ratings alone.

Stock Rating

1-Overweight - The stock is expected to outperform the unweighted expected total return of the sector coverage universe over a 12-month investment horizon.

2-Equal Weight - The stock is expected to perform in line with the unweighted expected total return of the sector coverage universe over a 12-month investment horizon.

3-Underweight - The stock is expected to underperform the unweighted expected total return of the sector coverage universe over a 12-month investment horizon.

RS-Rating Suspended - The rating and target price have been suspended temporarily due to market events that made coverage impracticable orto comply with applicable regulations and/or firm policies in certain circumstances including when Barclays Capital is acting in an advisorycapacity in a merger or strategic transaction involving the company.

Sector View

1-Positive - sector coverage universe fundamentals/valuations are improving.

2-Neutral - sector coverage universe fundamentals/valuations are steady, neither improving nor deteriorating.

3-Negative - sector coverage universe fundamentals/valuations are deteriorating.

Below is the list of companies that constitute the "sector coverage universe":

Americas Integrated Oil

Chevron Corporation (CVX) ConocoPhillips (COP) Exxon Mobil Corp. (XOM) Hess Corp. (HES) Husky Energy, Inc. (HSE.TO) Imperial Oil Ltd. (IMO.TO) Marathon Oil Corp. (MRO) Murphy Oil (MUR) Petroleo Brasileiro S.A. (PBR) Petroleo Brasileiro S.A. (PBRA) Suncor Energy (SU)

Asia ex-Japan Metals & Mining

Aluminum Corporation of China Ltd. (2600.HK) Angang Steel Co., Ltd. (0347.HK) China Coal Energy Co., Ltd. (1898.HK) China Hongqiao Group Ltd. (1378.HK) China Shenhua Energy Co., Ltd. (1088.HK) China Steel Corp. (2002.TW) CST Mining Group Ltd. (0985.HK) Jiangxi Copper Co., Ltd. (0358.HK) Jindal Steel & Power (JNSP.NS) JSW Steel (JSTL.NS) Maanshan Iron & Steel Co., Ltd. (0323.HK) NMDC Ltd. (NMDC.NS) Sesa Goa (SESA.NS) Steel Authority of India (SAIL.NS) Tata Steel (TISC.NS) Yanzhou Coal Mining Co., Ltd. (1171.HK)


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Asia ex-Japan Oil & Gas

China Oilfield Services (COSL) (2883.HK) CNOOC (0883.HK) PetroChina (0857.HK)

Sinopec (0386.HK)

Canadian Oil & Gas: E&P (Mid-Cap)

ARC Resources Ltd. (ARX.TO) Baytex Energy Corp. (BTE.TO) Bonavista Energy Corp. (BNP.TO)

Crescent Point Energy Corp. (CPG.TO) Enerplus Corporation (ERF.TO) NAL Energy Corp. (NAE.TO)

Pengrowth Energy Corp. (PGF.TO) Penn West Petroleum Ltd. (PWT.TO) PetroBakken Energy Ltd. (PBN.TO)

Peyto Exploration & Development Corp. (PEY.TO) Progress Energy Resources Corp. (PRQ.TO) Trilogy Energy Corp. (TET.TO)

Vermilion Energy Inc. (VET.TO)

European Clean Technology & Sustainability: Energy Efficiency

Abengoa SA (ABG.MC) Mersen S.A. (CBLP.PA) Outotec Oyj (OTE1V.HE)

Prysmian SpA (PRY.MI) Saft Groupe S.A. (S1A.PA) Umicore SA (UMI.BR)

European Clean Technology & Sustainability: Solar

centrotherm photovoltaics AG (CTNG.DE) Manz AG (M5ZG.F) Meyer Burger Technology AG (MBTN.S)

OCI Co., Ltd. (010060.KS) Phoenix Solar AG (PS4G.F) PV Crystalox Solar PLC (PVCS.L)

Q-Cells SE (QCEG.F) Renewable Energy Corp. ASA (REC.OL) Roth & Rau AG (R8RG.F)

SMA Solar Technology AG (S92G.F) SolarWorld AG (SWVG.F) Wacker Chemie AG (WCHG.DE)

European Integrated Oil

BG Group (BG.L) BP (BP.L) Eni (ENI.MI)

Galp Energia (GALP.LS) OMV (OMVV.VI) Repsol YPF (REP.MC)

Royal Dutch Shell A (RDSa.L) Royal Dutch Shell B (RDSb.L) Sasol Limited (SOLJ.J)

Statoil ASA (STL.OL) Total (TOTF.PA)

European Oil & Gas: E&P

Afren Plc (AFRE.L) Bowleven PLC (BLVN.L) Cairn Energy (CNE.L)

Cove Energy (COVE.L) Enquest (ENQ.L) JKX Oil & Gas (JKX.L)

Max Petroleum (MXP.L) Premier Oil (PMO.L) Rockhopper Exploration (RKH.L)

Salamander Energy (SMDR.L) Soco International (SIA.L) Tullow Oil (TLW.L)

European Oil Services & Drilling

Aker Solutions (AKSO.OL) AMEC plc (AMEC.L) CGGVeritas (GEPH.PA)

Dockwise (DOCK.OL) Hunting (HTG.L) Maire Tecnimont (MTCM.MI)

Petrofac (PFC.L) Petroleum Geo-Services (PGS.OL) Polarcus (PLCS.OL)

Saipem (SPMI.MI) SBM Offshore (SBMO.AS) Subsea 7 SA (SUBC.OL)

Technip (TECF.PA) Tecnicas Reunidas (TRE.MC) TGS (TGS.OL)

Wood Group (WG.L)

European Refining & Marketing

ERG (ERG.MI) Essar Energy (ESSR.L) Grupa Lotos (LTOS.WA)

Hellenic Petroleum (HEPr.AT) MOL (MOLB.BU) Motor Oil (MORr.AT)

Neste Oil (NES1V.HE) PKN Orlen (PKNA.WA) Saras (SRS.MI)

Statoil Fuel & Retail (SFRET.OL)

European Utilities

Centrica (CNA.L) Drax Group (DRX.L) E.ON (EONGn.DE)

Enagas SA (ENAG.MC) Endesa S.A. (ELE.MC) Enel SpA (ENEI.MI)

Fortum (FUM1V.HE) Gas Natural SDG SA (GAS.MC) GDF Suez SA (GSZ.PA)

Iberdrola SA (IBE.MC) International Power Plc (IPR.L) National Grid Plc (NG.L)

Pennon Group Plc (PNN.L) Red Electrica Corporacion SA (REE.MC) Redes Energeticas Nacionais (RENE.LS)

RWE (RWEG.DE) Severn Trent Plc (SVT.L) Snam Rete Gas SpA (SRG.MI)

SSE (SSE.L) Terna SpA (TRN.MI) United Utilities Group Plc (UU.L)

Verbund (VERB.VI)


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North America Metals & Mining

AK Steel Holding (AKS) Alcoa Inc. (AA) Alpha Natural Resources (ANR)

Arch Coal (ACI) Century Aluminum (CENX) Cloud Peak Energy (CLD)

CONSOL Energy (CNX) Freeport-McMoRan C&G (FCX) Noranda Aluminum Holding (NOR)

Nucor Corp. (NUE) Patriot Coal (PCX) Peabody Energy (BTU)

Steel Dynamics (STLD) Stillwater Mining (SWC) United States Steel (X)

North America Oil & Gas: E&P (Large Cap)

Anadarko Petroleum (APC) Apache Corp. (APA) Canadian Natural Resources (CNQ.TO)

Canadian Oil Sands Ltd. (COS.TO) Cenovus Energy Inc. (CVE.TO) Devon Energy (DVN)

EnCana Corp. (ECA) EOG Resources (EOG) Kosmos Energy Ltd. (KOS)

MEG Energy (MEG.TO) Newfield Exploration (NFX) Nexen Inc. (NXY.TO)

Noble Energy (NBL) Occidental Petroleum (OXY) Pioneer Natural Resources (PXD)

QEP Resources (QEP) Range Resources Corp. (RRC) Southwestern Energy Co. (SWN)

Talisman Energy (TLM) Ultra Petroleum Corp. (UPL) WPX Energy (WPX)

U.S. Clean Technology & Renewables

A123 Systems Inc. (AONE) Ameresco Inc. (AMRC) Elster Group SE (ELT)

First Solar Inc. (FSLR) GT Advanced Technologies Inc. (GTAT) Itron Inc. (ITRI)

Power-One Inc. (PWER) Tesla Motors Inc. (TSLA)

U.S. Independent Refiners

Alon USA Energy (ALJ) Delek US Holdings Inc. (DK) HollyFrontier Corp. (HFC)

Marathon Petroleum Corp. (MPC) SunCoke Energy, Inc. (SXC) Sunoco, Inc. (SUN)

Tesoro Corporation (TSO) Valero Energy (VLO)

U.S. Oil & Gas: E&P (Mid-Cap)

Bill Barrett Corp. (BBG) Chesapeake Energy (CHK) Cimarex Energy Co. (XEC)

Comstock Resources (CRK) Concho Resources Inc. (CXO) Crimson Exploration Inc. (CXPO)

Denbury Resources (DNR) Exco Resources Inc. (XCO) Forest Oil (FST)

Penn Virginia Corp. (PVA) Plains Exploration & Production (PXP) Quicksilver Resources Inc. (KWK)

Resolute Energy Corp. (REN) SandRidge Energy Inc. (SD) SM Energy Co. (SM)

Stone Energy Corp. (SGY) Swift Energy Company (SFY) Venoco Inc. (VQ)

W&T Offshore (WTI) Whiting Petroleum (WLL)

U.S. Oil Services & Drilling

Baker Hughes (BHI) Basic Energy Services (BAS) Bristow Group Inc. (BRS)

Cameron International (CAM) CARBO Ceramics (CRR) Chart Industries Inc. (GTLS)

Core Laboratories (CLB) Diamond Offshore Drilling (DO) Dresser-Rand Group Inc. (DRC)

Dril-Quip Inc. (DRQ) Ensco plc (ESV) Exterran Holdings Inc. (EXH)

FMC Technologies (FTI) Global Geophysical Services (GGS) GulfMark Offshore, Inc. (GLF)

Halliburton Co. (HAL) Helmerich & Payne Inc. (HP) Hercules Offshore (HERO)

Hornbeck Offshore Services (HOS) ION Geophysical Corp. (IO) Key Energy Services (KEG)

Nabors Industries (NBR) National Oilwell Varco (NOV) Noble Corp. (NE)

Oceaneering International (OII) Parker Drilling (PKD) Patterson-UTI Energy (PTEN)

Rowan Companies (RDC) Schlumberger Ltd. (SLB) SEACOR Holdings, Inc. (CKH)

Seadrill Limited (SDRL) Superior Energy Services Inc. (SPN) Tenaris S.A. (TS)

Tetra Technologies Inc. (TTI) Thermon Group Holdings (THR) Tidewater Inc. (TDW)

Transocean Ltd. (RIG) Weatherford International (WFT)


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U.S. Power

AES Corp. (AES) Ameren Corp. (AEE) Calpine Corp. (CPN)

Constellation Energy (CEG) Covanta Holding Corp. (CVA) Dynegy Inc. (DYN)

Entergy Corp. (ETR) Exelon Corp. (EXC) FirstEnergy Corp. (FE)

GenOn Energy, Inc. (GEN) NextEra Energy (NEE) NRG Energy (NRG)

Ormat Technologies (ORA) PPL Corporation (PPL) Public Service Enterprise Gp (PEG)

Distribution of Ratings:

Barclays Capital Inc. Equity Research has 2223 companies under coverage.

42% have been assigned a 1-Overweight rating which, for purposes of mandatory regulatory disclosures, is classified as a Buy rating; 53% ofcompanies with this rating are investment banking clients of the Firm.

42% have been assigned a 2-Equal Weight rating which, for purposes of mandatory regulatory disclosures, is classified as a Hold rating; 48% of companies with this rating are investment banking clients of the Firm.

13% have been assigned a 3-Underweight rating which, for purposes of mandatory regulatory disclosures, is classified as a Sell rating; 39% of companies with this rating are investment banking clients of the Firm.

Guide to the Barclays Capital Price Target:

Each analyst has a single price target on the stocks that they cover. The price target represents that analyst's expectation of where the stock will trade in the next 12 months. Upside/downside scenarios, where provided, represent potential upside/potential downside to each analyst's pricetarget over the same 12-month period.

Barclays Capital offices involved in the production of equity research:

London

Barclays Capital, the investment banking division of Barclays Bank PLC (Barclays Capital, London)

New York

Barclays Capital Inc. (BCI, New York)

Tokyo

Barclays Capital Japan Limited (BCJL, Tokyo)

São Paulo

Banco Barclays S.A. (BBSA, São Paulo)

Hong Kong

Barclays Bank PLC, Hong Kong branch (Barclays Bank, Hong Kong)

Toronto

Barclays Capital Canada Inc. (BCC, Toronto)

Johannesburg

Absa Capital, a division of Absa Bank Limited (Absa Capital, Johannesburg)

Mexico City

Barclays Bank Mexico, S.A. (BBMX, Mexico City)

Taiwan

Barclays Capital Securities Taiwan Limited (BCSTW, Taiwan)

Seoul

Barclays Capital Securities Limited (BCSL, Seoul)

Mumbai

Barclays Securities (India) Private Limited (BSIPL, Mumbai)

Singapore

Barclays Bank PLC, Singapore branch (Barclays Bank, Singapore)


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OCI Co., Ltd. (010060 KS / 010060.KS) Stock Rating Sector View

KRW 269000.00 (28-Feb-2012) 2-EQUAL WEIGHT 2-NEUTRAL

Rating and Price Target Chart - KRW (as of 28-Feb-2012) Currency=KRW

Date Closing Price Rating Price Target

09-Feb-2012 302000.00 175000.00

24-Oct-2011 220000.00 225000.00

Closing Price Target Price Rating Change

Jul- 09 Jan- 10 Jul- 10 Jan- 11 Jul- 11 Jan- 12

0.15M

0.20M

0.25M

0.30M

0.35M

0.40M

0.45M

0.50M

0.55M

0.60M

0.65M

27-Sep-2011 222000.00 2-Equal Weight 310000.00

Link to Barclays Capital Live for interactive charting

Barclays Bank PLC and/or an affiliate has been lead manager or co-lead manager of a publicly disclosed offer of securities of OCI Co., Ltd. in theprevious 12 months.

Barclays Bank PLC and/or an affiliate is a market-maker and/or liquidity provider in securities issued by OCI Co., Ltd. or one of its affiliates.

Barclays Bank PLC and/or an affiliate has received compensation for investment banking services from OCI Co., Ltd. in the past 12 months.

Barclays Bank PLC and/or an affiliate expects to receive or intends to seek compensation for investment banking services from OCI Co., Ltd. within the next 3 months.

Barclays Bank PLC and/or an affiliate trades regularly in the securities of OCI Co., Ltd..

Barclays Bank PLC and/or an affiliate has received non-investment banking related compensation from OCI Co., Ltd. within the past 12 months.

OCI Co., Ltd. is, or during the past 12 months has been, an investment banking client of Barclays Bank PLC and/or an affiliate.

OCI Co., Ltd. is, or during the past 12 months has been, a non-investment banking client (securities related services) of Barclays Bank PLC and/or an affiliate.

Valuation Methodology: Our KRW 175000.0 Price Target is derived from our Renewables Valuation Model assuming a high growth period of 5years, sales growth of 12.5% capital employed growth of 7.5% and return on sales of 11.5%. We assume normalised growth of 3.0% long termreturn on sales of 15.0% and pre-tax WACC of 17.8%.

Risks which May Impede the Achievement of the Price Target: Upside risks to our price target include stronger demand for solar installations, improved pricing for polysilicon, faster ramp up in company's production capacity and a more favourable cost position.

Downside risks to our price target include weaker demand for solar installations, sharper decline in polysilicon pricing,delays in capacity ramp up, a less favourable cost position and lower than expected polysilicon quality.

https://live.barcap.com/go/NYF/flex/equity/EquityChart.jsp?ticker=6497004&legend=OCI Co., Ltd.&shortlegend=010060.KS&currency=KRW&enddate=20120228&begindate=20110228&userId=lentonly&appName=RPS�


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This publication has been prepared by Barclays Capital, the investment banking division of Barclays Bank PLC, and/or one or more of its affiliates as provided below. It is provided to our clients for information purposes only, and Barclays Capital makes no express or implied warranties, and expressly disclaims all warranties of merchantability or fitness for a particular purpose or use with respect to any data included in this publication. Barclays Capital will not treat unauthorized recipients of this report as its clients. Prices shown are indicative and Barclays Capital is not offering to buy or sell or soliciting offers to buy or sell any financial instrument. Without limiting any of the foregoing and to the extent permitted by law, in no event shall Barclays Capital, nor any affiliate, nor any of their respective officers, directors, partners, or employees have any liability for (a) any special, punitive, indirect, or consequential damages; or (b) any lost profits, lost revenue, loss of anticipated savings or loss of opportunity or other financial loss, even if notified of the possibility of such damages, arising from any use of this publication or its contents. Other than disclosures relating to Barclays Capital, the information contained in this publication has been obtained from sources that Barclays Capital believes to be reliable, but Barclays Capital does not represent or warrant that it is accurate or complete. The views in this publication are those of Barclays Capital and are subject to change, and Barclays Capital has no obligation to update its opinions or the information in this publication. The analyst recommendations in this publication reflect solely and exclusively those of the author(s), and such opinions were prepared independently of any other interests, including those of Barclays Capital and/or its affiliates. This publication does not constitute personal investment advice or take into account the individual financial circumstances or objectives of the clients who receive it. The securities discussed herein may not be suitable for all investors. Barclays Capital recommends that investors independently evaluate each issuer, security or instrument discussed herein and consult any independent advisors they believe necessary. The value of and income from any investment may fluctuate from day to day as a result of changes in relevant economic markets (including changes in market liquidity). The information herein is not intended to predict actual results, which may differ substantially from those reflected. Past performance is not necessarily indicative of future results. This communication is being made available in the UK and Europe primarily to persons who are investment professionals as that term is defined in Article 19 of the Financial Services and Markets Act 2000 (Financial Promotion Order) 2005. It is directed at, and therefore should only be relied upon by, persons who have professional experience in matters relating to investments. The investments to which it relates are available only to such persons and will be entered into only with such persons. Barclays Capital is authorized and regulated by the Financial Services Authority ('FSA') and member of the London Stock Exchange. Barclays Capital Inc., U.S. registered broker/dealer and member of FINRA (www.finra.org), is distributing this material in the United States and, in connection therewith accepts responsibility for its contents. 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ENERGY RESEARCH CONTACTS

Commodities

Helima Croft Commodities Research +1 212 526 0764 [email protected]

Paul Horsnell Commodities Research +44 (0)20 7773 1145 [email protected]

Michael Zenker Commodities Research +1 415 765 4743 [email protected]

Miswin Mahesh Commodities Research +44 (0)20 77734291 [email protected]

Kevin Norrish Commodities Research +44 (0)20 7773 0369 [email protected]

Amrita Sen Commodities Research +44 (0)20 3134 2266 [email protected]

Trevor Sikorski Commodities Research +44 (0)20 3134 0160 [email protected]

Shiyang Wang Commodities Research +1 212 526 7464 [email protected]

Credit

Jim Asselstine US Utilities (HG/HY) +1 212 412 5638 [email protected]

Oscar Bate US Metals & Mining +1 212 412 3732 oscar.bate @barcap.com

Kateryna Kukuruza US Energy & Pipelines (HY) +1 212 412 7647 [email protected]

Harry Mateer US Energy & Basic Industries (HG) +1 212 412 7903 [email protected]

Emmanuel Owusu-Darkwa European Energy & Pipelines (HG/HY) +44 (0)20 777 37467 [email protected]

Gary Stromberg US Energy & Pipelines (HY) +1 212 412 7608 [email protected]

Timothy Tay Asia-Pacific Energy & Utilities (HG) +65-6308-2192 [email protected]

Matt Vittorioso US Coal, Metals & Mining +1 212 412 1378 [email protected]

Erly Witoyo Asia-Pacific Coal +65 6308 3011 [email protected]

Equities

Tom Ackermans European Oil & Services & Drilling +44 20 7773 4457 [email protected]

Arindam Basu European Renewables +44 20 3134 7216 [email protected]

Peter Bisztyga European Utilities +44 20 3134 4763 [email protected]

Paul Cheng Americas Integrated Oil and U.S. Independent Refiners +1 212 526 1884 [email protected]

Scott Darling Asia ex-Japan Oil & Gas +852 2903 3998 [email protected]

Thomas Driscoll North America Oil & Gas: E & P (Large Cap) +1 212 526 3557 [email protected]

Daniel Ford U.S. Power +1 212 526 0836 [email protected]

David Gagliano North America Metals & Mining +1 212 526 4016 [email protected]

Monica Girardi European Infrastructure & Utilities +39 02 6372 2683 [email protected]

Lucy Haskins European Integrated Oil + 44 20 3134 6694 [email protected]

Grant Hofer Canadian Oil & Gas: E & P (Mid-Cap) +1 403 592 7460 [email protected]

Susanna Invernizzi European Infrastructure & Utilities +39 02 6372 2681 [email protected]

Rahim Karim European Integrated Oil +44 20 3134 1853 [email protected]

Caroline Learmonth South Africa Mining & European Integrated Oil +27 1189 56080 [email protected]

Rupesh Madlani European Renewables +44 20 3134 7503 [email protected]

Gregg Orrill U.S. Power +1 212 526 0865 [email protected]

Mick Pickup European Oil Services & Drilling +44 20 3134 6695 [email protected]

Alessandro Pozzi European Oil & Gas: E&P +44 20 7773 4745 [email protected]

Lydia Rainforth European Refining & Marketing +44 20 3134 6669 [email protected]

Ephrem Ravi Asia ex-Japan Metals & Mining +852 2903 4892 [email protected]

Jeffrey W. Robertson U.S. Oil & Gas: E&P (Mid-Cap) +1 214 720 9401 [email protected]

Amir Rozwadowski U.S. Clean Technology & Renewables +1 212 526 4043 [email protected]

James C. West U.S. Oil Services & Drilling +1 212 526 8796 [email protected]

Tim Whittaker Head of European Equities Research +44 20 3134 6696 [email protected]

EMCC_Outlook2012_Cover:Layout 1 12/12/2011 4:56 PM Page 2

barclays global energy outlook (2)

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