GLOBAL ENERGY OUTLOOK STAY LEVERAGED TO OIL

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Investors should consider this report as only a single factor in making their investment decision.

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

FOR ANALYST CERTIFICATION(S), PLEASE SEE PAGE 141.

FOR IMPORTANT FIXED INCOME RESEARCH DISCLOSURES, PLEASE SEE PAGE141.

FOR IMPORTANT EQUITY RESEARCH DISCLOSURES, PLEASE SEE PAGE 143.

RESEARCHCOMMODITIES, CREDIT AND EQUITY VIEWS30 August 2012

GLOBAL ENERGY OUTLOOK

STAY LEVERAGED TO OIL

Barclays | Global Energy Outlook

30 August 2012 1

OVERVIEW

Stay leveraged to oil The key difference we see between oil and most other energy markets is supply, where the challenge is replacing declining oil production. Demand, by contrast, responds to economic weakness to similar degrees across the energy spectrum. And with 3Q12 looking as if it will see a very significant tightening of the oil market, our key Global Energy Outlook recommendation is to stay leveraged to oil and to oil-biased equities and credits.

Beyond our quarterly and annual oil price forecasts, we map the longer-term supply/demand picture, and the signals here are stark. Oil supply from existing fields is falling by close to 4m bls/d per year due to natural decline; global demand is rising by more than 1m bls/d each year, even in the current weak environment. Hence, the supply gap that needs to be filled each year from new fields is more than 5m bls/d. This presents a material challenge for the energy industry. While this long-term supply squeeze may have been less apparent in the quarter just past, 3Q12 looks as if it will see a significant tightening of the oil market, with a 2m bls/d upswing in demand and falls in both OPEC and non-OPEC supply. To this we can add minimal spare capacity and heightened geopolitical tensions in several regions. A release of US strategic reserves would provide only a slight and temporary respite. Thus, we continue to have strong oil price conviction, and our Brent forecast for 2013 is $125/bl. For the longer term, we expect prices to follow an inexorable, if volatile rise to above $180/bl before the decade closes.

Other global energy markets do not have the declining production constraints of oil, and prices are less robust. US natural gas markets now price against coal in the domestic power market. The main question is how deeply into the coal stack gas will compete. We continue to advocate short natural gas positions through the 2012 injection season while watching for entry points below $2.50/mmbtu, as we forecast $3.25/mmbtu for 2013. European natural gas demand continues to suffer from the weak EU economy and a poor competitive position against coal, with LNG cargoes being diverted to the higher priced Asian natural gas markets (which unfortunately are tricky to gain direct exposure to). Coal pricing globally remains subdued, with weaker demand growth from Chinese steel and power producers, coupled with healthy supply increments from traditional exporters and the US, leaving the seaborne market well supplied. We expect 2013 European and Asia delivered prices to be little more than $90/t.

The equities most geared to oil prices are the oil service companies. They will be the biggest beneficiaries of the rising capex needed to fund new supply. Our bi-annual Upstream Spending Survey foresees 11% industry capital spending growth in 2012, after a 22% rise in 2011. We recommend US stocks with strong leverage to the international and offshore up-cycles: Haliburton, National Oilwell Varco, Transocean, Oil States and Lufkin. Among the Europeans, we recommend the seismic names, PGS and Polarcus; Subsea 7 in offshore construction; Hunting for US shale exposure; and Saipem for its high quality, diversified business mix. In Asia, we recommend Sembcorp Marine and Keppel Corp. In oil service credits, we continue to see value in Atwood Oceanics, PGS, Transocean and Rowan.

Although the integrated companies are the largest oil producers, they have captured less than 25% of the past decade’s oil price increase in their cash flow. Our most recent analysis – ‘A Question of Cash’, August 2012 – suggests that their returns on new investment will fall over the coming five years. We prefer oil and exploration-biased E&P names, or integrateds with a strong upstream and growth bias. In the US, we also recommend integrated names

Ahead of our CEO Energy Conference in New York, we bring

together the views of all of our energy analysts globally, across

commodities, credit and equities.

Oil $125/bl in 2013; Other energy markets less robust

Oil-biased equities and credits

Growth-biased integrateds and E&Ps

https://live.barcap.com/go/publications/content?contentPubID=FC1852915�


30 August 2012 2

with a bias to the inland refining market, more of which below. In E&P equities, we recommend Afren, Baytex, Crescent Point, EOG Resources, Noble Energy, Petrobakken, Plains Exploration, Tullow Oil and Whiting Petroleum. Of the integrateds, we recommend BG, CNOOC, GALP, Imperial and Suncor. In credit, we retain our preference for Canadian integrated names, notably Suncor Energy and Cenovus, and also see upside for BP. In high yield, we favour oily E&Ps, including Hilcop, MEG Energy, Plains E&P and SandRidge Energy.

The spectacular uplift in US shale gas production, and now shale oil, has been the biggest change in global energy market dynamics over recent years. Among the clearest winners have been the US independent refiners. The surfeit of domestic shale oil feedstock relative to the available pipeline capacity to the coastal markets has triggered a material price discount for North America inland crude compared with coastal and international prices. Although we think pipeline development could eliminate most of the lower 48 inland transportation bottlenecks by 2014/15, WTI-linked crude prices will, in our view, remain below coastal market prices due to the cost of shipping oil from north to south. Rising shale oil production and pipeline build outs will only push the bottleneck southward, establishing a new bottleneck in the U.S. Gulf Coast within the next 12-18 months. Our analysis suggests that the structural benefits related to this new bottleneck have not been reflected in the shares. Hence, even after strong price performance, we believe that the US refining segment will remain among the equity market's best performers, and the stocks could potentially double over the next couple of years. We recommend Tesoro, Valero, Marathon Petroleum and Phillips 66 equities. In credit, we highlight curve flatteners in Marathon Petroleum and Phillips 66, and would be buyers of Tesoro CDS given tight spreads.

The expected long term elevated North American crude oil differentials also sees us favour integrated companies with a significant North America refining exposure over their less US-oriented peers for the next 12 months. Hence, our preference for Suncor and Imperial Oil.

With US shale oil volumes growing in the double digits, the current infrastructure is inadequate to handle the influx of new volumes. MLP-driven “yield cos” such as Oneok, Targa Resources and Williams Companies provide high yield, attractive ways to participate in this build out. All offer 15% plus dividend growth off robust current yields.

Outside the US, the refining market outlook remains weak, with too much capacity and ongoing state-subsidised investment. International refiners also have much higher fuel costs than their US peers, which have switched to lower priced natural gas, worth around $5/bl to margins. We do not advocate exposure to the refining segment in Europe or Asia.

In Europe, UK natural gas and power markets look more robust than those in continental Europe; hence, our equity and credit recommendations are biased toward the UK or to transmission names. In equities, we recommend Drax and Snam Retegas. In credit, we would sell Iberdrola cash bonds and sell Enel CDS.

In Asia, we expect coal prices to recover slowly after the weakness in 2Q, and we prefer thermal coal to coking coal. We see only limited value in Asian coal credits, preferring equity names such as China Coal Energy and ITMG.

This summary sets out just a few of the ideas of our energy analysts globally. The following pages detail the opinions of all of our analysts across commodities, credit and equities. Ahead of our CEO Energy Conference in New York, there has rarely been a more interesting time to invest in energy.

Tim Whittaker Global Energy Research

US refining stocks could double

Prefer integrateds with US refining exposure

US infrastructure build

Avoid refining outside the US

UK natural gas better than continental Europe

Asia coal to recover


30 August 2012 3

CONTENTS

Overview – Stay leveraged to oil 1 Price Performance 4 Summary of Energy Themes 8

COMMODITIES Commodities Oil – Lacking stability 16 Geopolitics – Fever pitch 21 LNG – Heading east 24 US Natural Gas – Teaching coal to tango 28 UK Natural Gas – More Norway, less power 32 Coal – Good demand, better supply 36 US Power – Riding the bronco 41 Carbon – Looking for intervention 44

CREDIT

US High Grade Energy & Pipelines – The haves and the have-nots 50 US High Yield Energy – Gas prices and new issuance undermine returns 51 US High Yield Coal – Despite supply-side cuts, challenges persist 52 US High Grade Utilities – Regulated utilities remain stable 53 US High Yield Utilities – Focus on natural gas 54 European High Grade Oil & Gas – A safe haven with pockets of volatility 55 European High Grade Utilities – The former untouchables 57 Asia High Yield Coal – Near–term outlook lacks heat 59 Asia High Grade Energy – On an acquisitive trend 60 Asia High Grade Utilities – Mixed prospects across the region 61

EQUITIES

Americas Integrated Oil – Our favorites are SU and IMO; super majors may underperform other energy names 64 European Integrated Oil – A question of cash 66 European Integrated Oil – SASOL: Shale gas impacts South African oil & gas 70 Asia Ex-Japan Oil & Gas – Preference for leverage to the upstream and capex cycle 72 US Exploration & Production – Oil-shale drilling replacing gas-shale drilling as the focus 76 Canadian Oil & Gas: Exploration & Production (Mid–Cap) – Commodity roller coaster ride 80 European Exploration & Production – Exploring Africa 83 Israel Exploration & Production – Potential farm-in to unlock value 84 US Independent Refiners – New refining Golden Age underway; prefer TSO, VLO, PSX and MPC 87 European Independent Refiners – Still characterised by overcapacity 90 US Oil Services & Drilling – The offshore and international cycles gain momentum 92 European Oil Services & Drilling – Entering the better times 96 US Diversified Natural Gas – Liquids infrastructure, recovery in natural gas prices to drive performance 99 US Coal – This will take time 102 Asia Ex-Japan Metals & Mining – Stabilisation after the perfect storm 105 US Power – Texas and everything else 110 European Utilities – Persistent headwinds 112 US Clean Technology and Renewables – Shares bottoming; however, visibility on pace of recovery still limited 115 Europe Clean Technology & Sustainability – Green power growth 119 Equity Valuation Table 122

CONTACTS 152


30 August 2012 4

PRICE PERFORMANCE

Following our previous Global Energy Outlook in March 2012, oil prices fell by $35/bl, triggering a sell-off in related energy and energy securities markets. Brent and WTI have since recovered most of their falls, and we expect stronger prices for the rest of the year. US natural gas prices touched lows below $2/MMBtu in April, but have also recovered, although we still see a fully supplied market. Energy credits and equities have underperformed their respective markets, equities much more so, although we now expect this to reverse given our stronger oil price outlook. The best performers across all asset classes have been the US refining stocks, and we believe these names will perform even more strongly through 2013. Also in equities, despite an unusually weak performance in the last six months, we expect the oil service and E&P names will rally before year-end. In credit, high yield has outperformed high grade by 2.2pp, though we continue to prefer high grade opportunities.

US Dollar price change, 24 Feb 2012 – 23 Aug 2012

-40 -30 -20 -10 0 10 20 30 40 50

US RefinersUS Power

US GasUS Pipelines

S&P 500EU Utilities

Canada E&PsEU Services

Asia ServicesHangSeng

US IntegratedsEurostoxx 600

EU Integrateds US ServicesEU Refiners

US E&PsAsia Integrateds

Asia RefinersUS Renewables

EU E&PsIsrael E&Ps

Asia MiningEU Renewables

US Mining

US HY ElectricAsian Credit Index

EU HY Credit IndexUS HY Credit Index

US HG Refining US HG Credit Index

US HY Energy US HG Pipelines

US HG ElectricUS HG Oil Field Services

EU HY EnergyEU HG Energy

US HG Energy EU HG Credit Index

US HG Independent E&PEU HG Utilities

US HG Integrated

US PowerUS Natural GasGerman power

US Coal AP12GSCI, Commodity

UK Natural GasBrent Crude

UK powerWTI Crude

US Coal AP14Carbon

Equi

tyCr

edit

Com

mod

ity

The data on the chart show the price performance of each of the named commodities/indices in US dollars for February 24, 2012 to August 23, 2012. Source: Datastream, Bloomberg, Barclays Research

Energy credits and equities have

underperformed their respective

markets since March.

Carbon and US Coal AP14 prices

declined the most since February,

down 17% and 15%, respectively.

Asia credits performed the

strongest, outperforming the US on

average by 3pp.

European stocks were down 4pp

versus the Eurostoxx 600 while US

sectors performed largely in line

with the S&P500.

In Asia, energy equities

underperformed the HangSeng

Index by 5pp.


30 August 2012 5

Over the last twelve months, crude has been the stand-out commodity up an average 9%. The US refiners have been the best performing equity sector, up 62%y/y, followed closely by the service companies and E&Ps. Low US natural gas prices and weak power, carbon, solar and wind markets have had clear consequences for performance across commodities and equities.

US Dollar price change, 23 Aug 2011 – 23 Aug 2012

-60 -40 -20 0 20 40 60 80

US RefinersEU E&Ps

US GasS&P 500

EU ServicesAsia ServicesUS Pipelines

US PowerUS IntegratedsEU Integrateds

Asia IntegratedsHangSeng

Canada E&PsUS Services

Eurostoxx 600EU Utilities

US E&PsAsia Refiners

Israel E&PsEU Refiners

US RenewablesAsia Mining

US MiningEU Renewables

EU HY Credit IndexUS HY Credit Index

US HY ElectricUS HY Energy EU HY Energy

Asian Credit IndexUS HG Refining

US HG CreditEU HG Energy

US HG Energy US HG Integrated

US HG Oil FieldEU HG Utilities

US HGUS HG Pipelines

US HG ElectricEU HG Credit Index

WTI CrudeBrent Crude

GSCI, CommodityUK Natural Gas

UK powerUS Power

US Coal AP12US Coal AP14

US Natural GasGerman power

Carbon

Equi

tyCr

edit

Com

mod

ity

The data on the chart show the price performance of each of the named commodities/indices in US dollars for August 23, 2011 to August 23, 2012. Source: Datastream, Bloomberg, Barclays Research

Oil prices have been the biggest

winners in commodities over the

last 12 months with Brent and WTI

up 5% and 12%, respectively.

High Yield has outperformed High

Grade credit by 6pp since last year.

European Credit marginally

outperformed the US by 0.6pp

while Asian Credit performed 1pp

better than Europe.

US stocks were the worst relative

performers, falling 9pp behind the

S&P500.

European shares faired better

against the weaker European

markets, but were still 5pp down

versus the Eurostoxx 600.

In Asia, Energy equities have

outperformed the HangSeng by

4pp over the last 12 months.


30 August 2012 6

Crude oil and natural gas price performance in USD

40

60

80

100

120

140

160

Aug Sep Nov Dec Jan Feb Mar May Jun Jul Aug

WTI

Brent Price

UK Nat Gas

US Nat Gas

Price performance rebased to 100. Data as of 23 Aug 2011 – 23 Aug 2012. Source: Datastream, Barclays Research

Coal price performance in USD

40

60

80

100

120

140

160


Qinhuangdao(China)

AP14 (SouthAfrica Export)

AP12 (EuropeImport)

Newcastle(Australia)


Power price performance in USD

40

60

80

100

120

140

160


US Power(PJMWest)UK Power (Dayahead)German Power(Day-ahead)


Natural gas prices have continued

to be weak in the US. UK NBP

prices have been more robust.

The WTI-Brent spread has

tightened over the last twelve

months by $4.7/bl to $19.2/bl. We

expect a wide differential to prevail

for at least the next two years.

Seaborne coal prices have fallen by

an average 25% since last year.

We expect no more than a slow

recovery in the 2H12 and into

2013.

UK and German power prices are

down 25% since last year,

reflecting weak demand and

milder weather.

US (PJM West) power prices are

down 17% since last year. We

expect prices to firm in the next

few years as 42GW of coal plants

are retired.


30 August 2012 7

European energy equity price performance in USD

60

80

100

120

140

160

Aug Oct Nov Dec Jan Feb Apr May Jun Jul Aug

EU E&Ps

EU Services

Brent Price

EU Integrateds

Eurostoxx 600

EU Refiners


US energy equity price performance in USD

60

80

100

120

140

160


US Refiners

SNP 500

US Integrateds

WTI

US Services

US E&Ps


Asia energy equity price performance in USD

60

80

100

120

140

160


Asia Services

Brent

Hang Seng

AsiaIntegratedsAsia E&Ps

Asia Refiners


In Europe, the E&P and oil

service stocks have been the

biggest winners over the last 12

months, helped by the recent

recovery in oil price.

In contrast, refiners have suffered

from higher fuel costs and a

difficult margin environment.

US refiners have performed most

strongly in the US, reflecting the

wide WTI discount and low natural

gas fuel costs.

Oil services have stood out in Asia,

outperforming the HangSeng Index

starting in January.

Asian refiners have

underperformed, as they struggle

to be profitable in the face of

excess capacity and government

regulated prices.


30 August 2012 8

SUMMARY OF ENERGY THEMES

INVESTMENT VIEW KEY RECOMMENDATIONS

Commodities

Oil Spare sustainable upstream capacity is very limited, leaving prices highly prone to spikes due to both fundamental and geopolitical factors. We expect non-OPEC supply growth to remain poor, with sharp falls in output outside of the US counteracting the impact of shale oil at the global level. Global oil demand, is expected to remain robust, albeit modest, unless there is a significant macroeconomic discontinuity or a geopolitically based oil price spike. We forecast growth of 1.16 mb/d in 2013, with the annual average moving beyond 90 mb/d for the first time and with quarterly peaks nearing 92 mb/d.

Longer-term prices are likely to be substantially higher than those assumed by consensus in our view, and hence look to build positions at the back of the crude curve on dips. Avoid taking positive positions on crude timespreads during such periods as now when strategic stock releases are likely, as such events are in effect borrowing oil from the future and placing it in the present. We expect Brent to average $125 per barrel in 2013, with upside risks arising from the follow-on from current geopolitical issues.

Geopolitics Once again, the discussion of a possible Israeli strike on Iranian nuclear facilities is reaching a fever pitch. While we continue to believe that the risks remain weighted against a military strike this year, several tail risk events could still trigger a significant escalation in hostilities in the near term, such as an Iranian-backed terrorist incident or the transfer of Syria’s chemical weapons to Hezbollah. Despite the strong growth in Iraqi oil exports, the political and security environment there remains challenging. There has been a recent escalation in Al Qaeda violence, and the Syrian crisis appears to be hurting Iraq's security situation. With oil output back to pre-war levels and the successful July elections, Libya looks as if it is firmly on the road to recovery. Nonetheless, there are a few potential speed bumps ahead, including the federalist movement in the east, the presence of armed militias, and the lack of government institutions, that could trigger a relapse.

LNG The global LNG market has seen largely flat y/y supply in H1 2012, with a slow ramp-up of some new liquefaction facilities and an increase in Qatari volumes just compensating for drops in production elsewhere. Despite the flat balance, Asian LNG takes are up by 16.4 bcm, and this demand growth was facilitated by a reduction in LNG takes in Europe (down by 15.9 bcm) and North America. The pattern of new capacity should see more LNG supply in the market, but this will be more than met by the addition of more regasification facilities, predominantly in Asia.

2012 is now looking like a year of little overall growth in the LNG market, but the next step is likely to be a tightening, rather than a loosening, of the market. While 2014 could see some significant tranches of capacity coming onstream, which could add 30+ bcm/y to capacity, we have pushed back almost all of these as more likely to be fully operational from 2015. As such, the additions to the supply side look limited, while a much bigger demand side is rearing its head in the interim.

Natural Gas - US Our forecast for H2 2012 is for gas to average $2.85/MMBtu, influenced greatly by the US natural gas price we believe is necessary to encourage enough coal displacement. Starting in November, the market will look ahead to winter and the trajectory of supply, and we expect Q4 prices to move higher. Prices in 2013 should be defined by the ongoing fight between gas and coal in the power market. While coal displacement pulls back a bit in our outlook, it is still significant.

We advise investors to stay short through the end of the injection season, but watch for dips below $2.50 for entry points. We would advise producers of natural gas and power to hedge calendar 2013, as the curve looks somewhat overvalued to us at the moment. We expect prices in 2013 to average $3.25, which embeds a fairly bearish view on coal prices for 2013.


30 August 2012 9


Commodities

Natural Gas - Europe

Our outlook for the remainder of 2012 and 2013 is largely unchanged, with LNG takes falling off further and requiring more supply-side response from the market. What the loss of LNG does, though, is make peak supply risks more acute; thus, we expect prices to drift upwards in Q4 and be sustained at higher average prices in 2013 than in 2012.

Our main trade recommendation is either go outright long or purchase a call option on Q1 2012 gas, which is trading at 68 p/therm. We expect NBP prices for Q4 2012 to average 65 p/therm. This is a 10% decrease from our previous forecast but remains bullish against the mid-August forward price of 64p/therm. Our forecast 12-13 winter prices are 67.5 p/therm, down 10% from 74.5p/therm.

Carbon The market continues to look long, with the moribund demand side likely to continue as the European power system de-carbonises and the energy-intensive industry seeing both a reduction in activity and making strides in reducing the carbon intensity of its output. We forecast that the market, given existing rules, will be increasingly long until 2015.

Prices will likely remain low given high inventory levels. Current proposals by the European Commission to shift volumes of European Union Allowances (EUAs) from the early years (2013-15) of the next phase to the back end of the phase will likely increase volatility and average phase prices. Until greater clarity on the proposals is reached, we forecast that prices will average 8 €/t over the coming decade.

Coal We expect the markets to remain well-supplied across H2 2012 and 2013. As a result, we expect Cif ARA prices to stay rooted around $90/t, possibly seeing some support from the oil markets. In terms of demand, we do not expect Chinese imports to maintain the same pace of growth as in H1 (given ample inventories), although coal burn should be well supported through a pickup in economic activity in Q4. European, Indian, and Japanese imports will likely be healthy, but the growth will be outpaced by the increase in supplies and availability of inventories.

We forecast that CIF ARA prices will average $91/t over H2 2012 and $92/t in 2013. FOB Richards Bay is expected to average $91/t in H2 2012 and $94/t in 2013. We are slightly more positive for Newcastle prices, given their stronghold in the Pacific Basin, expecting them to average $93/t in H2 2012 and $97/t in 2013.

Power - US It was fairly obvious that natural gas and coal were going to compete in the power sector in 2012. After all, the power sector is the only real source of price responsive demand, and not only did the gas market carry about 900 Bcf of unused winter gas into 2012, but gas production also started the year 5 Bcf/d above year-ago levels. This forced gas to price low enough to clear, which meant coal experienced a dramatic loss of market share in 2012.

We expect 42GW of coal plant retirements in the next few years and, therefore, a tightening of certain power markets. Forward power prices do not cover the cost of new power plants. While this has been the case for some years, with more markets looking ahead to tighter conditions, a debate is under way about how to structure markets so they bring forward new power plants before a crisis.

Equities

US Integrated Oil Positive

Our base case scenario is that Brent will continue to trade within the range of $90-120 per barrel over the next 12 months. We think WTI may temporarily trade at a higher discount to Brent ($25-30 compared to the recent $12-18 range) by the end of 2012 or early 2013, before narrowing to a range of $5-7/bl by the end of next year. We estimate that the sector is currently reflecting a long-term oil price assumption of $85-90 per barrel. However, we believe the Super Majors will underperform other energy subsectors in 2012.

Suncor (OW, PT CAD48) is currently our favorite name, for its improved reliability in production and utilization levels, potential improvements in cost structure and natural hedge to wide crude oil differentials. We favor Imperial Oil (OW, PT CAD60) for its strong long-term production growth potential, solid financial position, and attractive valuation compared to historical peer comparables.


30 August 2012 10


Equities

European Integrated Oil Neutral

From mid-cycle returns to production targets, the large-cap oil companies have a relatively poor track record of hitting targets. For a number of years (2007-10) the companies nearly abandoned targets all together. The European majors are now focusing on cash flow growth, something that should be expected given the investment going into the ground. However, increasing cash flow alone does not imply good capital efficiency or improving returns. Our analysis shows that although absolute average cash flow for the group rises by 26% to 2016E, cash returns on investment fall from 10.7% to 8.6%. This projected fall in cash returns from the integrated oil companies is one of the main reasons why we do not expect to see a re-rating.

Our favoured companies remain those with leverage to oil prices, and with differentiated growth or exploration profiles. Our current favourites are BG (OW, PT 1800p) and Galp (OW, PT EUR18). Our least preferred names are BP (UW, PT 545p) and OMV (UW, PT EUR28.5).

Asia Ex-Japan Oil Positive

Our investment preference remains upstream focused. Despite a lower level of production growth in the medium term – our covered Chinese Oil & Gas companies are likely to deliver c3% pa production growth 2011-16E. Upstream barrels remain high-margin relative to the industry reflecting China’s less progressive fiscal regime, a zero cost exploration phase, and more prudent financial discipline.

CNOOC (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. The company’s proposed acquisition of Nexen is likely to sustain growth toward the end of this decade. We see Sembcorp Marine (OW, PT S$7) and to a lesser extent Keppel Corp (EW, PT S$13.3) as offering good value with their valuations not yet fully reflecting the peak cycle for oil spending.

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

Gas production growth has decelerated as the impact of $2-3 gas prices has taken hold and activity has moderated. The learning curve and the attractiveness of drilling NGL-rich wells, however, have deeply reduced gas supply costs. We believe gas prices of no more than $4/MMbtu are needed to establish long-term equilibrium.

We continue to favor oil-oriented producers and recommend investors avoid most gas producers. Our top picks in the large-cap group are EOG Resources (OW, PT $138) and Noble Energy (OW, PT $119). In mid-cap space, we prefer Plains Exploration (OW, PT $56) and Whiting Petroleum (OW, PT $62).

Canadian Exploration & Production Positive (Mid-Cap)

We believe that the Canadian mid-cap E&P space provides an attractive mix of growth and income. The industry offers average production growth of 11% in 2012-13E and an average dividend yield of 5.8%. Moreover, the group provides meaningful exposure to nearly all of Canada’s major oil and gas resource plays, excluding the oil sands. Valuations remain high relative to most conventional E&P names, reflecting the attractiveness of the business model and its meaningful income component for yield-oriented investors. Following the recent rally, our target prices imply a one-year total return of just 13.5%.

Our top picks remain biased to the crude oil side for now. They include Crescent Point (OW, PT CAD46) and Baytex (OW, PT CAD51) for their strong track records and clean balance sheets. We like PetroBakken (OW, PT CAD15) as one of our best value names given its exposure to two of the top light oil resource plays in Western Canada.

European Exploration & Production Positive

The E&P industry is currently trading with an average potential upside of 40%, which compares favourably to its historical average of 25%. The E&P space is also trading at a discount (albeit marginal) of 3% to core NAV. As a result we believe that M&A activities that pervaded the group in the last year with the acquisition of Encore Oil, Cove Energy and Nautical Petroleum could continue. Oil Majors and NOC could take advantage of this relatively cheap valuation and pursue more acquisitions. However, we see the company’s exploration portfolio as the critical factor that drives shareholders returns.

Our preference goes to those companies with a balanced exploration pipeline funded by a reliable cash flow. Our top picks are Tullow (OW, PT 1920p) and Afren (OW, PT 190p). We believe they can capitalise on their early entry in East Africa, a region, which recently witnessed a number of major oil and gas discoveries and that could hold a transformation potential for these two companies.


30 August 2012 11


Equities

Israel Exploration & Production Positive

With commercial production from the Tamar gas field expected to begin in 2Q12, finalised supply contracts with the Israel Electric Company and financing now secure, we are Positive on the Israeli E&P industry.

We see Ratio (OW, PT ILS0.45), which is a pure play on the Leviathan discovery, as set to benefit from the potential farm-in of a strategic partner. We recently upgraded Isramco (OW, PT ILS0.69) from UW to OW as we saw near-term catalysts begin to mount, with concrete Tamar off-take agreements and regulatory approval for the contracts’ structure.

US Independent Refiners Positive

We believe the US refining segment will be among the market’s best performing subsectors over the next couple of years and could potentially double from here. We believe the refining sector is undergoing a 3-phase structural improvement, the benefit to earnings power of which is not fully reflected in the market. Between 2009 and 2014, we estimate the relative structural cost advantage will improve by $8-12 per barrel of throughput for the US inland refiners and $3-5 per barrel for the Gulf Coast operators. In our view, improved cash return to shareholders coupled with increased representation in the indices, will lead to an expanded shareholder base, which in turn should translate into reduced share price volatility and, more importantly, a potential revaluation of the group.

We think Tesoro (OW, PT $84), Valero (OW, PT $63), Marathon Petroleum (OW, PT $80), and Phillips 66 (OW, PT $63) currently offer the best risk/reward ratios in the industry.

European Independent Refiners Negative

In contrast to the US refiners, the European refiners are struggling with overcapacity, lacklustre demand and a higher-than-average cost base. In particular, the European refiners use between 5-10% of crude processed to generate energy to run a refinery. At $100/bl this alone represents a $4-8/bl cost disadvantage. When combined with continued weak demand and new capacity being built in Asia and the Middle East, we expect further capacity to close over the coming years. The listed European companies represent some of the best-in-class refineries in Europe, but are still likely to lag behind their US competitors on earnings per barrel and returns.

Our preference remains for those companies that have high quality assets which should convert to cash flow through the cycle – namely Motor Oil (OW, PT EUR9.5) and Neste Oil (OW, PT EUR14), both rated Overweight. Our least preferred names are Saras (UW, PT EUR0.85) and PKN Orlen (UW, PT PLN40).

US Oil Services & Drilling Positive

We recently reshuffled our top picks ahead of the Barclays CEO Energy Conference. The themes of earnings season were clear: the offshore and international cycles are strong; North America is choppy and the group remains under-owned. Institutional money began to re-enter the group as the earnings season progressed. The outlook for international oil service (particularly offshore) remains bright. We expect North American-levered names to continue to face headwinds in 2H12. The battle for ultra-deepwater rig availability has begun.

We prefer stocks with strong leverage to the international and offshore upcycles. Our top five in order of preference are: Halliburton (OW, PT $57), National Oilwell Varco (OW, PT $127), Transocean (OW, PT $77), Oil States (OW, PT $122) and Lufkin (OW, PT $74).

European Oil Services & Drilling Positive

The spending cycle in the oil industry is well under way. After a surprising increase in capex from the oil companies of 22% in 2011, our latest update of our bi-annual Spending Survey shows an expectation of further growth of 11% in 2012. We believe that this is the start of a multi-year spend, as new discoveries made over recent years unlock new plays across the globe.

Our preferred seismic play remains PGS (OW, PT NOK130), while those investors with a smaller-cap bias could consider Polarcus (OW, PT NOK10.8). In offshore construction we prefer Subsea 7 (OW, PT NOK195) for their continued progression into ever deeper offshore waters and greater exposure to the much improved North Sea assets. With its recent acquisitions in the US, we see Hunting (OW, PT 1060p) as a unique way for investors to play the shale theme. Saipem (OW, PT EUR52) remains our favourite stock in the group with its wide portfolio of activities.


30 August 2012 12


Equities

US Diversified Natural Gas Neutral

Yields are suppressed across the capital structure. Expectations are that this backdrop will be in place for the foreseeable future. Conversion to an MLP HoldCo structure for a select group of Diversified Gas Companies has reduced the capital requirements of these companies, increased free cash generation and placed these entities in the position to pay out a high percentage of their cash flow while growing at 2-3x the rate of the underlying asset base. With beginning yields in the 3.0-4.0% range and growth rates of 12-22%, we believe this select group of companies offers investors an unparalleled income value proposition.

Liquids (oil, NGL) volumes are growing double digits. The current infrastructure is inadequate to handle this influx of new volumes. MLP driven “yield cos” such as Oneok Inc. (OW, PT $48)), Targa Resources Corp (OW, PT $52) and Williams Companies (OW, PT $38) provide high yield, attractive ways to participate in this build out. Dry gas drilling has receded sharply and should result in a more balanced supply/demand picture in North America. Slow recovery to a normalized price in the $4/mmbtu range creates significant cash flow leverage for high growth, low cost gas producers such as EQT Corporation (OW, PT $65).

US Coal1 Positive 1Industry view is for the wider US Metals & Mining industry

We expect limited meaningful price recovery in US thermal coal (2014 at the earliest) as ample excess production capacity awaits if/when electricity generation demand recovers on a sustainable basis. Metallurgical coal fundamentals have recently deteriorated significantly. We believe more near-term pain is likely and expect relatively low 4Q12 HCC benchmark settlements ($180/t-190/t). However, we believe a recovery in metallurgical coal prices is likely to occur sooner than a recovery in US thermal coal prices (i.e., early 2013), as global cost pressures constrain supplies. Recovery in European and Asian steel production should happen sooner than thermal coal prices.

Our preferred picks among the coal companies are CONSOL Energy (OW, PT $34) for its relatively low cost structure and Peabody Energy (OW, PT $27) for its strong balance sheet and diversified product mix to withstand the ongoing soft market.

Asia Coal2 Positive 2Industry view is for the wider Asia ex-Japan Metals & Mining industry

The coal markets in Asia are rebounding after a particularly tough 2Q. The recovery is being led through a combination of supply cuts and (modest) demand pick up. While we are unlikely to see the seaborne coal price back where we started in early 2012 (US$115/t average Newcastle price), it should recover steadily from the current spot of c.US$90/t (and RMB630/t Chinese domestic price). The Chinese domestic price should recover with a 1-2 months’ lag and we expect it to be over RMB700/t in 4Q12. We expect coal demand will be supported by power consumption growth (albeit at a slower rate than in the past 10 years) in China and increased urgency in India to improve power availability after the successive grid failures in the country in late July.

Our top picks are China Coal Energy (OW, PT HK$10.1) and ITMG (OW, PT IDR42,000). We prefer thermal coal over coking coal. Therefore, we see China Coal providing the right balance between leverage and safety. With virtually no debt on its balance sheet, the risk if coal prices do not recover is lower. ITMG’s key attraction for investors is its high, stable dividend yield. Furthermore, the company has settled 62% of it volumes on fixed price contracts for the year. Therefore, in spite of coal price volatility, we believe ITMG’s price realisations will fall the least amongst Indonesian coal producers in 2012.

US Power Neutral

For investors the US Power focus is on Texas far ahead of everywhere else. The Texas Public Utility Commission is engaged in developing market incentives for new generation to address their projected low 8% reserve margin in 2014.

Key companies in Texas are NRG Energy (OW, PT $24)), Calpine (OW, PT $19), and NextEra Energy (OW, PT $75). We like integrated power stocks such as American Electric Power (OW, PT $47) and Edison International (OW, PT $50). The catalyst for AEP is the recent constructive Ohio regulatory outcome and subsequent completion of the rehearing process. For EIX, the catalysts are the clearing of the regulatory calendar, the restarting of San Onofre (SONGs) 2, and a resolution on Edison Mission over the next six months.


30 August 2012 13


Equities

European Utilities Neutral

Despite the STOXX Utilities having underperformed the STOXX 600 since 2009, we still foresee a bleak picture overall for the industry. We expect deteriorating power markets, ongoing political risk, pressure on credit, unsupportive commodity trends, and questionable value in equities. However, some favourable structural trends still exist in transmission networks and in UK generation. We are cautious on European integrated utilities and instead recommend investing in names directly exposed to UK power market recovery. We also recommend rebalancing exposure in regulated utilities towards transmission.

Our top picks are Drax (OW, PT £6.95), Snam Retegas (OW, PT EUR3.85), SSE (OW, £15.85), and Veolia Environnement (OW, EUR12.5).

US Clean Technology & Renewables Neutral

We retain our longer-term sanguine view on the industry. In the near-term, we believe that investors are focused on companies that provide technologies/services that can offer a compelling economic value proposition vs. those that depend on regulatory support or the promise of ultimately being cost competitive. Our key coverage in the US Clean Technology & Renewables market include: solar, lighting, smart grids, energy efficiency and alternative fuel vehicles.

Our top picks are Ameresco (OW, PT $14), Power-One, (OW, PT $7), Tesla Motors (OW, PT $38), and Veeco Instruments (OW, PT $45).

EU Clean Technology & Renewables Positive (Energy Efficiency) Neutral (Solar) Positive (Wind)

We expect global wind demand to be broadly flat in 2012 and 2013, with a return to growth in 2014. We remain positive with an 8.5% CAGR in wind installation for 2011-15E. We lowered our wind demand expectations in the US by 12% and 9.1% in 2013 and 2014, respectively, anticipating a higher proportion of shale gas in the energy mix, with environmental concerns likely to be mitigated through legislation. We remain positive on demand in the global solar market with a 14.4% CAGR in solar installations for 2011-15E, mainly supported by strengthening demand in Asia and the Americas.

At the beginning of the year 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. We continue to reiterate our Overweight recommendations on both Outotec (OW, PT EUR60) and Umicore (OW, PT EUR51.5).

Credit US High Grade Energy and Pipelines Overweight (Independent E&P) Market Weight (Refining) Market Weight (Pipelines) Overweight (Oil Field Service)

Relative to the average sub-sector differentials versus U.S. credit during the past three years, E&P and integrated companies screen as fairly valued, oil field service companies are cheap, refining appears rich, and pipelines are essentially at the wides. Predicated on increasing dayrates and utilization, as well as the rig newbuild cycle, we believe that the oil field service sector is poised to outperform in 2H12. Within E&P and integrated, we retain our preference for selected Canadian energy credits, while refining long bonds have value versus intermediates and pipelines offer mixed relative value prospects according to their disparate distribution coverage and leverage metrics.

Put on curve flatteners in Marathon Petroleum Corporation (MPC, MW) and Phillips 66 (PSX, NR). We continue to see value in Transocean Ltd (RIG, OW) and Rowan Companies plc (RDC, NR). Swap out of Williams Partners LP (WPZ, MW) and Enbridge Energy Partners, L.P. (EEP, NR) and into ONEOK Partners LP (OKS, MW). We continue to see value in Suncor Energy Inc. (SUCN, OW) and Cenovus Energy Inc. (CVECN, OW).

US High Yield Energy Market Weight

We do not recommend investing in gas-weighted credits. We prefer oil-weighted credits, including Hilcorp Energy, MEG Energy, Plains Exploration & Production, and SandRidge Energy. In services, we like international-weighted credits, including Atwood Oceanics and Petroleum Geo-Services. In pipeline, we are Overweight Targa Resources Partners.

Buy Targa Resources Partners 2021s (NGLS, OW), Sell Regency Energy Partners 2021s (RGP, MW), pick up 25bp in yield Buy SandRidge Energy 2022s (SD, MW), Sell Chaparral Energy 2022s (CHAPAR, MW), pick up 85bp in yield Buy PGS 2018s (PGS, NR), Sell Hornbeck Offshore 2020s (HOS, NR), pick up 25bp in yield and shorten duration

US High Yield Coal1 Market Weight

Domestic thermal coal fundamentals remain weak but have recently shown some evidence of demand recovery. Producer cuts to production should help rebalance supply/demand, but much will still depend on the price trajectory of natural gas and winter heating demand. We remain Market Weight the metals & mining sector, but hold a cautious view of coal producers, given persistent fundamental weakness in thermal and metallurgical coal.

We believe long-term investments in Cloud Peak (CLD, MW) 8.5% senior notes and Peabody Energy (BTU, MW) 6.25% senior notes will be profitable. We recommend reducing risk in Alpha Natural Resources (ANR, MW). ANR remains heavily exposed to metallurgical coal prices, and we expect continued weakness in this market to weigh on its profitability, driving spreads wider.


30 August 2012 14


Credit

US High Yield Utilities Market Weight

2012 has been defined by an unprecedented level of coal-to-gas switching as natural gas prices continue to trade below $3/mmbtu. While headlines about EPA-mandated shutdowns and market reforms in ERCOT and PJM remain topical, we feel that investor sentiment will ultimately be driven by near-term movements in gas prices and their effect on forward power curves.

While the HY power sector continues to struggle through trough-like conditions for merchant power generation, we think that Calpine (CPN, MW) and NRG Energy (NRG, MW) will ultimately benefit from exposure to the tightening Texas market and solid balance sheets/liquidity that position them to ride through the weak market.

European High Grade Oil & Gas Overweight

In the second half of this year, we believe the oil price will be a key driver for sector spreads. Additionally, LNG-based players’ fundamentals should continue to benefit from favourable trends for demand and pricing. While sector cash flows will continue to be underpinned by relatively solid cash generation from E&P, underlying FCF remains weak (or negative) due to upstream focussed capex spend. In our opinion, ongoing and potential asset disposals will remain key in reducing sector financial risks.

Overweight BP (BPLN) cash. We recommend that credit investors short ENI (ENIIM) 5y CDS (200/210) with ENI trading c.160-170bp back of 'BBB' Italian corporates and tight versus Italy. Sell Repsol (REPSM) EUR 2016s and EUR 2017s and buy Repsol 5y CDS at current levels.

European High Grade Utilities Market Weight

While European Utilities performed in line to above expectations during Q2 12, with few exceptions, we believe continued adverse pressure on business profiles from weaker cash generation and profitability will ultimately lead the agencies to become more conservative on leverage guidance and credit ratings. We thus expect further sector downgrades. In the periphery, the additional material macroeconomic and sovereign weakness – and potential for further sizeable downgrades, including of Spain, in September – will likely continue to weigh negatively on the spreads and ratings of peripheral utilities. We believe large-scale M&A is unlikely. However the UK Water’s United Utilities Group remains subject to market speculation around a takeover and further we believe foreign investors, particularly from China, are likely to continue to buy stable earnings assets in the UK.

Buy CEZCO (CEZ) bonds: Buy Edison (EDF) bonds: Short Iberdrola (IBESM) cash bonds and sell Enel (ENELIM) CDS against buying Iberdrola 5y CDS:

Asia High Yield Coal Market Weight

We expect the earnings weakness seen in 1H12 to persist in the second half. Based on recent contracted prices, most issuers forecast weaker ASPs in 2H12. This is likely to offset expected production increases and lower production costs during the period. We expect a significant deterioration in 2012 credit metrics as a result, although assuming a recovery in the coal market in 2013, this could be temporary. Bond valuations in the Indonesian coal sector are relatively rich despite the industry-wide weakness. Nevertheless, we maintain our neutral stance on the sector, as technicals remain sound given the lack of new Asian HY supply.

Underweight the Bumi Resources bonds. We expect further deterioration in Bumi’s credit profile in the near term. Earnings will remain under pressure on low ASP. The company is also likely to take on more debt to cover cash shortfalls.

Asia High Grade Energy Market Weight

We expect the Asian oil and companies to keep their M&A agenda alive as shrinking domestic reserves and slower production levels encourage them to seek global growth opportunities. While credit metrics will incrementally deteriorate in this sector, the effect on credit ratings is muted for now. Most companies enjoy strong financial flexibility, have sufficient ratings headroom and have demonstrated a willingness to raise equity capital where necessary.

Switch out of POSCO 5.25% 2021s (POHANG UW) into PTT E&P 5.692% 2021s (PTTEPT, MW). Buy Korea National Oil 3.125% 2017s (KOROIL, OW).

Asia High Grade Utilities Market Weight

We expect the Chinese gas utilities companies to remain resilient, with solid operating results, albeit their sizable investment programs could lead to some deterioration in credit metrics. In South Korea, cost recovery challenges persist in the utilities sector, as tariff increases are inadequate to cover fuel costs.

China Resources Gas (CHIRES, OW). Buy KORELE 3.125% 2015s (KHNP, MW) and sell KORELE 5.5% 2014s and KORELE 3% 2015s (KEPCO, UW)

Credit Rating System (for a full definition, please see page 141): Sector Weighting: Overweight, Market Weight, Underweight. Credit Rating: OW, MW, UW. Equity Rating System (for a full definition, please see page 144): 1 Industry view is for the wider North America Metals & Mining industry. 2Industry view is for the wider Asia ex-Japan Metals & Mining industry. Industry view: Positive, Neutral, Negative. Stock Rating: OW, EW, UW.


30 August 2012 15

COMMODITIES


30 August 2012 16

COMMODITIES OIL

Lacking stability The global oil market remains tight, with limited spare capacity; as a result, it is

expected to exhibit a significant degree of sensitivity to geopolitical risks and other potential supply-side complications. The overall tightness in the market, plus the lack of spare capacity and the extent of geopolitical risks, seems to suggest that OECD governments are likely to become more directly involved in the market.

Non-OPEC supply growth is expected to remain poor. Although supply growth from crude and NGLs has been strong in the US, outside the US, the level of non-OPEC supply has fallen sharply in 2012. We expect further growth from the US in 2013, albeit at a diminishing rate, and a more robust performance in the rest of non-OPEC, resulting in a slightly improved overall performance relative to 2012, with supply growth of 0.49 mb/d.

Global oil demand growth is expected to remain robust, albeit modest, unless there is significant macroeconomic discontinuity or a geopolitically based oil price spike. We forecast growth of 1.16 mb/d in 2013, with the annual average moving beyond 90 mb/d for the first time and with quarterly peaks nearing 92 mb/d.

Spare capacity remains limited The global oil market remains far from equilibrium. Sustainable spare upstream capacity is limited at just below 2 mb/d, far short of the 4.5 m/d or 5% level that might represent the borderline of a more comfortable and sustainable situation. With there being little immediate prospect of a substantial increase in spare capacity and with the scope for significant shifts in the geopolitical landscape in key producing areas remaining high, the stage appears to be set for a relatively nervous period of trading, with little sense of markets’ settling happily into any particularly well-defined, stable, or comfortable price range.

A period of relatively anaemic global economic growth following the extreme downturn of 2008/9, as well as mild northern hemisphere winter conditions at the start of 2012 in key consuming areas might prima facie have been expected to represent the basis for a weak oil

Miswin Mahesh +44 (0)20 7773 4291

[email protected]

Paul Horsnell +44 (0)20 7773 1145

[email protected]

Sustainable spare upstream capacity is running at a thin 2%

Figure 1: Barclays projected global oil balances (mb/d)

Annual Annual Annual2011 change Q112 Q212 Q312 Q412 2012 change Q112 Q212 Q312 Q412 2012 change

Demand 88.7 0.80 88.9 88.7 90.7 90.7 89.8 1.09 90.4 89.9 91.8 91.5 90.9 1.16OECD demand 45.6 -0.66 45.5 44.4 45.6 45.9 45.4 -0.29 45.5 44.3 45.5 45.8 45.3 -0.07 non-OECD demand 43.0 1.46 43.4 44.3 45.1 44.9 44.4 1.39 44.9 45.7 46.3 45.7 45.6 1.24

Non-OPEC supply 52.4 0.00 52.8 52.5 52.2 52.9 52.6 0.24 53.2 53.0 52.8 53.4 53.1 0.50non-OPEC excluding FSU 39.1 -0.07 39.4 39.2 38.9 39.6 39.3 0.20 39.8 39.6 39.4 40.0 39.7 0.42FSU 13.3 0.08 13.4 13.3 13.3 13.3 13.3 0.04 13.4 13.4 13.4 13.4 13.4 0.08

OPEC NGLs/condensates 5.8 0.50 6.0 6.2 6.3 6.2 6.2 0.39 6.1 6.3 6.4 6.3 6.3 0.10Call on OPEC crude+inv 30.5 0.29 30.0 30.1 32.2 31.6 31.0 0.47 31.2 30.6 32.6 31.8 31.6 0.56

OPEC crude 29.9 0.48 31.1 31.2 30.9 31.0 31.1 1.18 31.0 31.0 31.8 31.8 31.4 0.33OPEC excluding Iraq 27.3 0.34 27.7 27.7 27.9 28.0 27.8 0.55 28.0 28.0 28.8 28.8 28.4 0.55

Stockbuild -0.7 1.1 1.1 -1.3 -0.6 0.1 -0.2 0.4 -0.9 0.0 -0.2

Source: Barclays Research


30 August 2012 17

price. In reality, however, the industry is running rather hot, at 98% of upstream capacity, and the system is still not generating any surplus at the margin in terms of capacity or inventories. As a result, the oil market remains highly prone to supply shocks, as well as an increasingly complex and interrelated set of geopolitical dynamics in the Middle East. Other factors are intruding on the bearish picture of supply optimists and destroying the simple case that sluggish economic performance plus shale oil must equal a rapidly loosening market. The solution to this apparent mystery is that while oil output is strong in the US, it has slumped elsewhere.

While OECD economies have been under pressure, thus far the weakness in OECD oil demand has been relatively muted and considerably less pronounced than in 2008/9, and non-OECD demand growth has continued at a steady, albeit unspectacular, pace. While the risk of both geopolitical and macroeconomic discontinuities remains, we expect oil markets to remain tight into 2013. We expect OECD demand growth to remain slightly negative, non-OECD demand growth to slow slightly relative to 2012, and non-OPEC supply growth to remain slow, particularly outside North America. Our projected summary global balances are shown in Figure 1. We forecast a modest increase in the call on OPEC crude in 2013, allowing OPEC to produce comfortably above 31 mb/d of crude and close to 38 mb/d of total oil liquids without generating any significant inventory build.

Supply growth in the US, but contraction elsewhere

A burst of growth in non-OPEC supply in 2009 and 2010 has proved to have no legs, and the lacklustre performance of most of the previous decade has returned with the added aspect of some strong regional disparities in performance. Non-OPEC supply grew by almost exactly 2 mb/d across 2009 and 2010 combined. The deceleration since then has been sharp, brought on by a combination of disappointing performance in some new provinces, high decline rates in older areas, and some geopolitically linked outages. As shown in Figure 1, there was no growth in 2011, and we forecast modest 0.25 mb/d growth across 2012 as a whole. Despite the reliance of much political and financial analysis on the perception of a paradigm shift caused by an acceleration in non-OPEC supply growth, the reality is that growth across 2011 and 2012 has fallen to just an eighth of its pace across 2009 and 2010. We expect some improvement in 2013, but only to growth of just below 0.5 mb/d.

Figure 2: Strong growth in US oil output (thousand b/d)

Figure 3: …offset by weak non-OPEC growth outside the US

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despite strong growth in the US


30 August 2012 18

The one area of clear strength in non-OPEC supply is North America the US, in particular – as shown in Figure2. The level of US net oil imports reached a turning point some five years ago and has since fallen by about 4.5 mb/d, to a current level of around 8 mb/d, having been reduced by both demand-side weakness and the growth in indigenous supply. The first phase of strong US supply growth came through corn ethanol; however, the reacceleration of growth since the start of 2011 has been led by crude oil and NGLs, in particular, in price-dependent shale oil plays. Helped by some favourable weather-related base effects, US supply growth exceeded 1 mb/d in Q1 2012 before settling back towards 0.8 mb/d in the succeeding quarters.

We expect growth in US oil supply of about 0.8 mb/d across 2012 as a whole and then around 0.3 mb/d in 2013. We do not expect the US to become oil independent in the future, with an import gap of more than 5 mb/d expected to persevere in 2020 even assuming the maintenance of high prices in what we would consider an already highly supply-optimistic and demand-pessimistic scenario. Instead, we expect that the uneven phasing of US oil output growth and oil infrastructure developments will continue to create pockets of distressed crude, particularly in the Midwest, generating a series of substantial discounts for regional crudes and a set of sometimes nested price dislocations. While some provinces are expected to be heavily discounted relative to WTI, we also expect a continuation of high discounts for WTI relative to Brent and other global market indicators. Given the current phasing of projects, we expect Brent to command an average premium of $10 per barrel to WTI in 2013.

The major reason US supply growth has been associated more with a collapse in regional differentials than with any downwards pressure on global prices is the severe degradation in the performance of the rest of non-OPEC over the past two years, as shown in Figure 3. A steadily improving pattern across 2009 culminated in growth outside the US of more than 1 mb/d in Q2 2010. However, that growth proved remarkably transitory, and by Q2 2011, a y/y decline had set in again. Furthermore, the pattern of decline has continued for the past six quarters. While the US and the rest of non-OPEC were both on an improving trend in 2009 and 2010, resulting in strong overall growth, over the past two years, the latter has tended to cancel out the former, resulting in an overall near flatlining in non-OPEC supply. Some of that weakness is due to political developments, some is due to slower-than-expected development of key incremental projections, and some is due to the continuation of extremely high declines in mature areas such as the North Sea. Thus far, the combined effect of all three sources of output weakness has been such that shale development in the US has left barely a ripple at the global level. We expect the disparity between the underlying health of US and other non-OPEC supply performance to persevere into 2013.

Oil demand dynamics show few watersheds yet

Global oil demand growth has been relatively slow in recent quarters; however, once the effects of weather are adjusted for, it has also been relatively consistent and shown little in the way of discontinuities. The general pattern has been one in which a mild reduction in OECD demand has been outweighed by non-OECD demand growth, leaving annual average global demand growth of about 1%. A large part of the reason for the relatively solid global demand profile has come from the dynamics of OECD demand. In particular, OECD demand has been considerably more robust in this cycle than in the previous one (Figure 4). In the wake of the 2008/09 financial crisis, OECD oil demand fell y/y by 2.5 mb/d or more in three successive quarters and by 1 mb/d in six successive quarters. By contrast, while there have been six successive quarters of falling demand in 2011/12, the decline exceeded 1 mb/d in just one quarter. The declines in the OECD have been almost a full order of magnitude smaller than during 2008/09.

OECD oil demand has weathered the current economic cycle

relatively well


30 August 2012 19

Japan represented an important part of the early cushioning effect for OECD demand in the wake of the March 2011 earthquake, with a large y/y increase in fuel oil use and direct crude burning in power generation as the result of the shutdown of nuclear plants. However, that effect has largely now worked its way out of the base, and the major cushion over the past two quarters has been a sharp upswing in US demand. The y/y fall in US oil demand was a heavy 0.7 mb/d in Q1, with a mild winter adding to the depressive effect on demand of sluggish economic activity. However, in Q2, the y/y pattern was almost exactly flat, and data in Q3 have shown a move into y/y gains. After 13 straight months of y/y declines, US gasoline demand growth moved back into positive territory in April and has moved either side of zero since, in contrast to the heavy declines recorded throughout 2011. The main drag on OECD demand has come from Europe, but even in Europe, the pattern has been mixed, with large falls in the countries at the centre of the sovereign debt crisis but more robust demand indications elsewhere. We forecast that European demand will fall by 0.38 mb/d across 2012 as a whole, with Spain and Italy accounting for almost half that decline, while the decline in 2013 is forecast to be a milder 0.13 mb/d. US demand is expected to return to y/y growth across 2013, and the overall decline in OECD demand is projected at a slim 0.07 mb/d, a significant improvement on the 0.29 mb/d decline forecast for 2012.

While non-OECD oil demand growth has retreated from the highs of 2010, as shown in Figure 5, the pattern of recent quarters has been relatively consistent at a lower growth rate. In 2012, demand growth has come from Asia, the FSU, Latin America, and the Middle East. The main countries generating that demand growth have been, in order, China, Saudi Arabia, Russia, and Brazil, and the demand profile remains particularly exposed to significant economic or political changes in those four countries in particular. The slowdown in Chinese demand is, to the largest extent, already in the data, and we expect a gentle strengthening from this point. However, overall, our forecast is that non-OECD demand will grow less strongly in 2013, with growth of 1.24 mb/d, compared with 1.39 mb/d in 2012. The net effect is that we expect the pace of global demand growth to strengthen a little in absolute terms in 2013, taking it to 1.16 mb/d, compared with 1.09 mb/d in 2012, with the key positive dynamics continuing to come from the relatively benign path of OECD oil demand throughout the current economic cycle, as opposed to the sharp weakening in 2008/09.

Figure 4: Declines in OECD demand are modest (mb/d)

Figure 5: …while non-OECD demand grows slowly (mb/d)

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30 August 2012 20

Politicisation of oil is likely to continue apace The oil market and oil prices are likely to become even more heavily politicised given the above characterisation of the key dynamics. A market that is fundamentally tight; has little spare capacity; and is highly exposed to accidents, weather-related losses, and an undercurrent of potentially seismic geopolitical change is always likely to be a focus for political attention. When one adds to that cauldron the perceived sensitivity of the global economic recovery to oil prices, plus the timing of the current US electoral cycle, it seems clear that government policy and expectations of government policy are likely to be as important for the oil market as supply and demand. Should, as seems likely, the geopolitical context become more fevered after the US election, then one would expect the politicisation of the market to continue well into 2013. We expect the two major potential caps to oil prices over the next year to be the fear of economic discontinuities (including the recurrence of overarching sovereign debt issues) and direct government involvement, be that through strategic stock releases, other interventions into the market mechanism, or interactions with producers. Government intervention to attempt to cap prices would appear inevitable should the geopolitical context darken further, or should prices, through supply and demand dynamics, reach levels that are seen as economically or politically dangerous. Such actions may serve as temporary caps; however, we would not expect governments to be successful in pressing down longer-term prices through direct intervention. However, we do expect an interesting and somewhat surreal period for oil politics, during which the rhetoric of energy surplus and energy interdependence continues to be the primary tone of political and analyst debate while governments simultaneously resort to direct policy actions that are born of the reality of energy deficit and increasing energy dependence. As a result, we expect higher prices in 2013, with a Brent average of $125 per barrel, as well as a substantially more interesting, controversial and politicised market setting.

The economic and political context may lead to greater government involvement in

oil prices


30 August 2012 21

GEOPOLITICS

Fever pitch Once again, the discussion of a possible Israeli strike on Iranian nuclear facilities is

reaching a fever pitch. While we continue to believe that the risks remain weighted against a military strike this year, there are still several tail risk events that could trigger a significant escalation in hostilities in the near term, such as an Iranian-backed terrorist incident or the transfer of Syria’s chemical weapons to Hezbollah.

Despite the strong growth in Iraqi oil exports, the political and security environment there remains challenging. There has been a recent escalation in Al Qaeda violence, and the Syrian crisis appears to be hurting Iraq's security situation.

With oil output back to pre-war levels and the successful July elections, Libya looks like it is firmly on the road to recovery. Nonetheless, there are still a few potential speed bumps ahead, including the federalist movement in the east, the presence of armed militias, and the lack of government institutions, that could trigger a relapse.

The Iranian nuclear issue has remerged as a major story in the oil markets, with multiple stories in the Israeli press indicating that the Netanyahu government is seriously contemplating a military strike prior to the November US elections. Such an action would likely be a catalyst for a significant move higher in oil prices, as it would trigger widespread anxiety about the security of gulf energy supplies. Despite the war drums growing increasingly louder, the Israelis still may be reluctant to take unilateral action, given the degree of difficulty entailed in an Iranian strike. They did launch successful strikes on the Iraqi and Syrian nuclear reactors in 1981 and 2007, but a number of military experts contend the heavily fortified, underground Iranian nuclear sites, as well as the country’s air defence capability, pose a much tougher challenge and that US involvement would be required to set the Iranian program back significantly. Several senior members of the Israeli security establishment have publicly spoken out against unilateral action, and opinion polling seems to point to significant public scepticism about the efficacy of going it alone. The Obama administration, for its part, continues to show no enthusiasm for another military confrontation in the Middle East. Thus, we continue to believe that the risks remain weighted against a military strike this year.

Nonetheless, there are still several tail risk events that could trigger a significant escalation in hostilities in the near term, in our view. One is that a terrorist incident could set off a destabilizing cycle of retaliatory attacks. This summer, there have been several worrying security incidents, most notably the July 18 bus bombing that killed five Israeli tourists and the driver in Bulgaria. Iran experts have warned throughout the year that if Tehran came to feel that its back was up against the wall because of crippling sanctions and the covert campaign targeting its nuclear industry, it could lash out and try to raise the costs for its adversaries for imposing the punitive measures. If the terrorist attacks become more frequent or the wrong official is eventually targeted, the risks of a military confrontation could escalate considerably. Another situation that bears watching is Syria. Anxiety is rising about the security of its stockpile of chemical weapons. The Wall Street Journal reported in July that elements in the Assad government have taken some of the weapons out of the storage facilities and moved them to the border. If any of these weapons end up being transferred to the Iranian-allied Hezbollah, a serious security crisis would likely ensue.

Helima Croft +1 212 526 0764

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Talk of an Israeli strike on Iran intensifies


30 August 2012 22

Beyond these two near-term tail risks, 2013 may produce an inflection point in Western capitals if the diplomatic track remains stalled and Tehran continues to enrich uranium at higher grade levels and transfer centrifuges to the heavily fortified Fordow enrichment site. Western nations may face the difficult choice of either allowing Iran to approach the brink of nuclear breakout capability or taking military action to forestall that possibility. Some leading regional analysts have suggested that the heightened war rhetoric from the Netanyahu government may be part of an effort to push the Obama administration to alter its nuclear redlines publicly. The White House has repeatedly insisted that it will never allow Iran to develop nuclear weapons and has ruled out adopting a containment strategy. The Israeli government, by contrast, maintains that Iran should never be permitted to approach the point at which it can produce a nuclear device in a relatively short time because of the size of enriched uranium stockpiles. If Washington’s Iranian nuclear redline moves – either because of a shift in the Obama administration’s position or the election of Mitt Romney – it could tilt the scales more heavily in favor of strike sometime in the latter half of 2013, in our view.

While the Iranian nuclear program will likely remain the most important geopolitical issue in the oil markets over the next six months, some other stories are also worth keeping on one’s radar. Iraq’s oil exports have climbed to the highest level since before the 2003 US-led invasion, largely because of the opening of new export facilities and the investment of foreign companies in the southern fields. However, the political and security environment remains challenging. According to official estimates, 325 people were killed in July, the highest monthly death toll in over two years. Iraq’s Al Qeada’s offshoot has claimed responsibility for the majority of the recent bombings and shootings, which have largely targeted members of the security services and Shiite civilians. In late July, the group announced that it was commencing “Operation Breaking Walls” and called on the Iraq’s Sunni community to rise up against the Maliki government.

In a worrying development, the Syrian crisis appears to be hurting Iraq's security situation. The leader of Iraqi Al Qaeda affiliate has publicly likened his group’s campaign to topple Prime Minister Maliki's mainly Shiite government to the largely Sunni uprising against Syrian President Assad's Alawite regime. Baghdad has repeatedly sounded the alarm about Al Qaeda militants crossing the border between Syria and Iraq and essentially turning the two countries into one theatre of battle. In addition, Maliki's failure to break decisively with the Assad regime has further strained relations between Iraq and its Sunni neighbors who are actively financing the Syrian rebellion. Maliki has been accused of taking his foreign policy cues from Tehran, which remains a steadfast ally of the Syrian president. Similarly, his continued ties to Assad have also been the source of significant friction with Iraq's Sunni leaders, many of whom support the Syrian uprising. Relations between Maliki and the Sunni political class were already on a distinct downward trajectory after an arrest warrant was issued for the Sunni vice president, accusing him of ordering political assassinations. Thus, not only does Syria have the potential to imperil Iraq's internal security because of increased cross-border terrorist activity, it could also deepen dangerous sectarian divisions within the country and the broader region.

Finally, with oil output back to pre-war levels and the successful July elections, Libya looks like it is firmly on the road to recovery. Nonetheless, there are still a few potential speed bumps that could trigger a relapse. The burgeoning federalist movement in oil-rich eastern Libya could prove challenging. Since the fall of Gaddafi, thousands of eastern activists have called for the creation of a semi-autonomous provincial government that would have its own parliament, police force, and judicial system. The elections were a source of some friction in the east. Armed militants shut down three major export terminals with a combined capacity of 690 thousand b/d for 48 hours to signal their displeasure with the

2012 may produce an important inflection point on the Iranian nuclear program

Syria crisis imperilling Iraq’s security environment

Libya looks on the road to recovery, but challenges remain


30 August 2012 23

regional allocation of seats in the constituent assembly. The new government will also be pressed to make progress in disarming and demobilizing the militias. Libya is home to hundreds of armed militia groups that do not answer to a central authority and clash routinely. Lastly, an urgent task for the new government will be to build effective state institutions. Muammar Gaddafi ruled Libya with an iron grip for more than forty years and prevented the emergence of functioning institutions that could easily step in and run the country in his absence. In particular, it will be vitally important to set in place the right institutions for managing oil revenue to prevent it from being misappropriated and becoming a source of conflict. While the post-Gaddafi trend line has been broadly positive, there is still some hard work ahead before Libya is truly on a sustainable path to prosperity and stability.


30 August 2012 24

LNG

Heading east The global LNG market has seen largely flat y/y supply in H1 12, with a slow ramp-up

of some new liquefaction facilities, and an increase in Qatari volumes, just compensating for drops in production elsewhere.

Despite the flat balance, Asian LNG takes are up by 16.4 bcm, and this demand growth was facilitated by a reduction in LNG takes in Europe (down by 15.9 bcm) and in North America.

The pattern of new capacity should see more LNG supply in the market, but this will be more than met by the addition of more regasification facilities, predominantly in Asia. While the 2013 market balance looks just to be marginally tighter than 2012, 2014 could see a more significant tightening given the scheduled additions of demand.

LNG supply and demand In H1 12, the consistent theme of the LNG market has been the redirection of supply from Europe to Asia. The change in trade has accelerated this year, with Asia’s increased take being seen across almost all of the Asian LNG importers while reductions in take have been seen at all of the EU-located importers. The redirection of trade follows a trend that broadly kicked off with the Great Japanese earthquake of 2011, and has been supported by pricing that puts gas delivered into Asia at a premium. While that premium has begun to narrow, we do expect it to widen out again from Q4 as the market becomes gradually tighter.

Supply: Disappointingly flat In H1 12, LNG supply was largely flat y/y, globally being only 0.8 bcm lower (-1% y/y), reflecting some losses in supply, which offset increases seen in production elsewhere. Growth in supply largely came from Qatar, which was up by 4.2 bcm y/y, while a few other countries contributed smaller increments. We expect that the Qatari increments in H2 12 will be smaller as Qatar ramped up production in H2 last year to accommodate the structural increase in Japanese demand. One of the challenges for Qatar will be to keep growth at the current healthy levels.

Reductions in LNG supply from H1 11 levels came from Australia (-1.8 bcm), Malaysia (-1.2 bcm), Egypt (-1.2 bcm) and a handful of others that saw smaller losses. The Australian losses were, in part, driven by losses at various North West Shelf projects, which in Q1 saw production halted due to a number of tropical cyclones (Iggy and Lua). While Woodside Petroleum’s new LNG project, Pluto, has started to ramp up, those production gains have yet to compensate for the losses from exiting projects. Most of the other losses were just consistent with the typical ebb and flow of operations and can broadly be ascribed to both planned and unplanned maintenance. In terms of regional supply, growth came from the Middle East (3.0 bcm up y/y), while losses were seen in the Atlantic Basin (-1.3 bcm y/y) and the Pacific Basin (-2.5 bcm y/y).

Demand: Balance through redirection While H1 12 saw global LNG take to be slightly down y/y, the direction of trade continued to see an increasing shift eastwards with:

Trevor Sikorski +44 (0)20 3134 0160

[email protected]


30 August 2012 25

Asian imports up by 16.4 bcm. On an annualised basis, this would equate to an incremental take of some 33 bcm on its own. The growth in Asian takes continues to be driven by post-earthquake Japan, which registered the largest y/y growth among all LNG consumers (10.6 bcm, up by 21% y/y). While we expect Japan to keep taking at this accelerated level for much of the year, there will have to be some maintenance of the terminals and base effects will be important as the ramping of LNG take was already well underway through H2 11. We are forecasting that Japan’s additional take this year will be 15 bcm. The other Asian LNG-consuming countries posted import gains in the quarter, with India up by 1.5 bcm, China up by 1.7 bcm and South Korea up by 1.0 bcm y/y. While India, China, Japan, Indonesia and Malaysia are all opening new regassification facilities this year, the relatively slow uptake of these, particularly in the case of the Indian terminals, and the slowdown in Asian growth, has led us to revise the overall increase in Asian demand over 2012 to reach 28 bcm. With additional regas coming online in 2013, the trend for a continued take in Asian LNG will only continue, and we are forecasting that Asian LNG will reach 255 bcm/y by the end of 2013.

European LNG consumption adjusted to this tighter market in H1 12 with a reduced take of some 15.9 bcm. The losses have been most pronounced in the UK, which was down by 6 bcm, although healthy losses in Belgium (-3.1 bcm), France (-2.8 bcm) and Spain (-3.6 bcm) attest to how widespread the weakness in demand for LNG was over this period. The weakness in demand by European LNG is due to: the low levels of economic growth in Europe as it wrestles with issues such as sovereign debt; the reduction in European carbon prices that has reduced the competitiveness of gas as a fuel into power; the increasing competition from pipes into Europe, with both Medgas and Nordstream helping provide incremental gas supply into the market; and the price differentials between Europe and Asia that makes it natural to send cargoes destined for Europe to Asia. With no additional regas likely to come in during 2012, and the economic outlook remaining bearish, it is hard to see where additional demand might come from in the next two years.

Latin America and Middle East consumption was up by around 2.6 bcm, with growth coming from Argentina (1.2), Brazil (0.8), Mexico (0.7), and Chile (0.2). Mexican gains were expected to be higher as it commissioned its new regasification terminal at Manzanillo. Middle East consumption tailed off with moderate y/y losses in Dubai and Kuwait. We are forecasting that the two regions will increase LNG take by around 5 bcm in 2012 and another 4 bcm by 2013.

North American LNG consumption continued to fall, losing 4 bcm y/y and taking North America’s share of global LNG consumption down to 2%. We expect the average level of monthly LNG take into North America to stay around the 0.6 bcm/m level, which will leave North America down by some 5 bcm over the year. Again, with no meaningful demand to speak of, this region is just biding its time before it becomes a net exporter later in the decade.

The strength in Asian consumption, given the failure of the supply side to grow, has meant the global LNG market has balanced largely by diverting cargoes away from Europe and North America. Such diversions have either been a straight diversion from the source or a reload from an initial destination. Re-exports over H1 12 were 1.3 bcm y/y, although participants presumably only do reloads if there are destination clauses in their supply contracts.


30 August 2012 26

Figure 1: y/y change in monthly LNG consumption, by region, bcm

-6

-4

-2

0

2

4

6

8

Jan-09 Apr-09 Jul-09 Oct-09 Jan-10 Apr-10 Jul-10 Oct-10 Jan-11 Apr-11 Jul-11 Oct-11 Jan-12 Apr-12

Asia LA & ME Europe NA

Source: Waterborne, Barclays Research

Outlook

2012 is now looking like a year of little overall growth in the LNG market, but the next step is more likely to be a tightening, rather than a loosening, of the market. The only liquefaction projects until 2014 are those listed earlier, and while 2014 could see some significant tranches of capacity coming onstream, which could add 30+ bcm/y to capacity, we have pushed back almost all of these as more likely to be fully operational from 2015. As such, the additions to the supply side look limited, while a much bigger demand side is rearing its head in the interim.

When looking at the regasification projects, we feel that:

European incremental capacity can broadly be discounted, with it being very difficult in the next few years to justify a new LNG terminal given the stagnant outlook for demand, addition of considerable pipe capacity in the past two years, and possibility that more pipelines are going to be built, particularly into southern Europe. Europe has 33 bcm/y of announced projects by the end of 2014, but it is a big stretch to expect any to come in.

Asia will continue to dominate over the 2012-14 period, with 116 of 190 bcm/y of regas plants having been announced for that region. While not all of these will proceed, there are a wide number of different locations for these plants, and the region does have the economic growth to support very healthy additions.

Latin America will also grow, with 40 bcm/y of announced projects likely in the region.

Figure 2 shows announced additions to LNG supply and demand over the coming years.

Figure 2: LNG – increments in regassification and liquefaction capacity (bcm)

Bcm/y 2011 2012F 2013F 2014 Total

Regassification 35 36 39 114 224 Liquefaction 19 19 6 31 75 Balance (R-L) 17 17 33 83 149

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

Given the above, it does seem that the LNG market will become increasingly Asia-focused while Europe swings back to relying on pipelines for its supply and demand balance.


30 August 2012 27

Figure 5: Global LNG volumes (bcm)

Annual average (bcm) y/y changes (bcm)

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

Supply 299 324 326 350 53 23 2 16

Atlantic Basin 84 76 75 96 3 -8 -1 11

Pacific Basin 114 118 118 123 17 3 0 6.5

Middle East 103 130 133 131 34 27 3 -2

Demand 299 324 326 350 53 25 2 24

Asia 181 206 234 255 26 25 28 21

Europe 87 86 60 59 17 -1 -26 -1

Latin America + Middle East 17 19 24 28 9 2 5 4

N. America 14 13 8 8 0 -1 -5 0

Source: Waterborne, Barclays Research

Figure 6: Global natural gas price forecasts (US$/mmbtu)

2012 2013 2014

US gas (Henry Hub) 2.64 3.25 3.63

Europe (NBP) 9.4 10.1 11.0

Asia (Japan) 16.25 17.6 19.0


Figure 3: Global LNG prices ($/mmbtu)

Figure 4: y/y change in LNG supply (bcm)

0

2

4

6

8

10

12

14

16

18

20

Jan-10 Jul-10 Jan-11 Jul-11 Jan-12 Jul-12

US Lake CharlesSpainUKJapan India

-3

-2

-1

0

1

2

3

4

5

Aus

tral

iaYe

men

Egyp

tM

alay

sia

Alg

eria

Trin

idad

USA

A.D

habi

E.G

uine

a

Liby

aIn

done

sia

Brun

eiR

ussi

a

Om

anPe

ruN

iger

ia

Nor

way

Qat

ar

Source: Waterborne, Barclays Research Source: Waterborne, Barclays Research


30 August 2012 28

US NATURAL GAS

Teaching coal to tango The record level of coal displacement encouraged by decade-low natural gas prices

chewed a big hole in the storage overhang during Q2 of this year. Then, a third consecutively hot summer boosted gas demand and prices, replacing coal displacement as the key gas price driver. With the effects of hot weather waning, the rest of the injection season will be a delicate balance between coal displacement, which must grow back to spring-like levels for storage to end the injection season at a comfortable level, and gas prices. We believe that sufficient coal displacement will be achieved only if prices come down to mid-$2 in September and October.

Supply should again take center stage starting Q4 12 and into 2013. No analysts are forecasting a supply decline large enough to avoid heavy levels of coal displacement in 2013. The only question is how deeply into the coal stack gas must compete. Whether supply grows or falls is uncertain at this point. If it falls, coal displacement will likely retract to the eastern power markets only, allowing prices to rise relative to 2012 levels. If production grows, however, prices would be under pressure and could fall to 2012 levels. Although our base case scenario is for supply to start declining in Q3 12 and into 2013, we do not rule out a spike caused by debottlenecking of the newer shale basins. This alone could bring a large lump of supply into the market, especially in Q4 12.

Overall, in our view, gas prices in 2013 will continue to be defined by the need for gas to fight for market share against coal in the power sector. Given our supply outlook, we believe prices in 2013 will average $3.25/MMBtu.

Decade-low prices encouraged record power demand Natural gas prices this year have made large swings at the front of the curve, as the market plunged on the view that coal displacement was unlikely to absorb enough spare supply. Once coal displacement was larger than expected, the market swung to the view that the storage surplus was not such a downside risk to prices, causing prices to rally. This predictably trimmed coal displacement, and prices fell back again. Coal displacement this year, at its peak, has represented fully one-third of natural gas demand in the power sector (Figure 1). This was supplanted by record-hot weather (in the third hot summer in a row), which also boosted demand and prices.

Before we dig deeper into the rest of the injection season, it is useful to understand what drove the market these past few months. Natural gas demand at the beginning of this year was plagued by a warm winter that, along with record supply, caused storage to end the withdrawal season at 2.4 Tcf, the highest end-of-winter level on record. The year-over-year storage overhang ballooned to nearly 900 Bcf. Given our estimate for the maximum end-of-injection season storage level of 4.15 Tcf, the storage overhang would have to be reduced to 350 Bcf or lower by the end of October. As a result, the market started the year with a structural problem: if storage injections followed the 5-year average trajectory or even last year’s trajectory, storage would fill well before the end of the injection (Figure 2). In that case, prices would plummet. Thus, traders were pricing in the risk of an early fill of storage, resulting in a decline in prices at the front of the curve that persisted through Q1 and most of Q2 this year. The prompt contract finally reached its yearly low in the third week of April at $1.91/MMBtu. This reflected fears that the principal price-responsive source of natural

Shiyang Wang +1 212 526 7464

[email protected]

Michael Zenker +1 212 526 2081

[email protected]

Record level of coal displacement, but only with

decade-low prices


30 August 2012 29

gas demand, coal displacement, was no match for the supply glut. Our view was that while there were limits to coal displacement, a sufficient amount was available if gas prices fell low enough to mop up surplus supply.

In fact, coal displacement was higher than our outlook. The plunge in prices to below $2 instigated record-setting natural gas power burn. By our calculations, coal displacement surged to over 9 Bcf/d, compared with negligible levels in 2008, by far a record. This jump in natural gas demand chewed a big hole in the storage overhang and signalled that prices perhaps do not need to be as low as $2 to prompt a sufficient demand response. Along with some short-covering, high natural gas power burn drove the market to its first rally of the year. That overextended itself, in our view, as prices zoomed past by $2.50, a level where coal displacement in the western power markets rapidly wanes. Our balances at the time indicated that some degree of coal displacement was needed from the western power markets to avoid an early fill of storage. Once coal displacement pulled back with higher gas prices, the first rally ended, as the market recognized that higher prices were trimming demand.

But a second rally came shortly thereafter, as July posted another run of hot weather. This boosted power demand and obviated the need for coal displacement in much of the country and all of the west. Weather therefore replaced coal displacement as the key demand driver. Thus, even as coal displacement declined with the hot weather, prices continued to rally above $3 (Figure 1), as overall demand remained high. A spate of nuclear plant outages this summer also pushed gas burn higher.

This demand and price support has now pulled back with declining temperatures. Even with a hot start, August is trending much cooler than July. As in the spring, the market is again guessing what price level encourages enough demand to continue working the storage overhang lower. Our calculations indicate that coal displacement needs to return to 9 Bcf/d in September and October to avoid storage inventories shooting past 4.0 Tcf – the level that would pressure prices lower anyway. To get to this level, coal plants must again back down in the west, requiring prices to drop to the mid-$2 level again. Even an extremely hot August is incapable of burning enough gas to avoid this western coal displacement scenario. In our view, coal displacement will define prices for the rest of the injection season.

Two short-term rallies this year so far

Coal displacement must grow again to avoid a bearish storage finish

Figure 1: Implied coal displacement (LHS MMcf/d) versus 2012 Henry Hub prices (RHS $/MMBtu)

Figure 2: Storage cannot fill at the pace of the 5-year average or it would become full before the end of the injection season (Bcf)

0

0.5

1

1.5

2

2.5

3

3.5

1,000

2,000

3,000

4,000

5,000

6,000

7,000

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2011 coal displacement2012 coal displacementPrompt Henry Hub 2012

2,000

2,500

3,000

3,500

4,000

4,500

5,000

Jan-12 Mar-12 May-12 Jul-12 Sep-12 Nov-12

2012 trajectory assuming 5-yr average injections

Actual + projected path

Seasonal fill capacity

Source: EIA, Bentek, NRC, CME, Barclays Research Source: EIA, Baker Hughes, Barclays Research


30 August 2012 30

Supply slowing but could surprise to the upside US supply growth has defined the gas market for the past six years. Could there finally be a turn in this seemingly unstoppable march higher? Producers have notably shifted away from highly prolific dry gas drilling to liquids-rich locations. While still gas bearing, these wells yield less gas than dry gas locations, suggesting that if dry gas drilling fell enough, aggregate supply would drop. Our balances have been calling for a gradual pullback in supply from a peak earlier this year, with further declines into 2013.

This conclusion is not reached by merely looking at the gas-directed rig count. In fact, as illustrated in Figure 3, one of the key themes this year is the complete breakdown in the correlation between that and natural gas production. In fact, there are many other moving parts to supply, such as the growth of gas production for liquids-rich and oil wells, the further debottlenecking of shale gas basins, and the completion of wells previously drilled. Including all these variables, we conclude that 2012 will still have y/y supply growth (but declining from the Q1 peak), up 4% from 2011. Aggregate US production would continue a very moderate y/y decline in Q4 this year (Figure 4), keeping in mind that supply in Q4 11 was very strong compared with the rest of that year. For 2013, we forecast a 1.5 Bcf/d y/y decline, but continue to expect supply in 2013 to be above 2011 levels, indicating that supply debottlenecking and growing associated gas production are expected to offset a large part of the production declines from dry-gas basins.

Yet there is more risk of supply beating our outlook. A chunk of new pipeline capacity out of the Marcellus (and other regions), if filled to capacity, could offset declines from other sources of gas. In other words, while we include a debottlenecking of the Marcellus in our outlook, we may not have included enough.

Coal displacement continues to keep a lid on prices Our forecast for H2 12 is for gas to average $2.85/MMBtu, influenced greatly by the price we believe is necessary to encourage enough coal displacement. Starting in November, the market will look ahead to winter and the trajectory of supply, and we expect Q4 prices to move higher. Prices in 2013 should be defined by the ongoing fight between gas and coal in the power market. While coal displacement pulls back a bit in our outlook, it is still hearty. We expect prices in 2013 to average $3.25, which embeds a fairly bearish view on coal prices for 2013.

Gas supply should start to decline in Q3, but there

is upside risk in Q4 12

Figure 3: Gas-directed rig count (RHS) is far from a good indicator of natural gas production (LHS, Bcf/d)

Figure 4: Quarterly supply growth, y/y (Bcf/d)

500

550

600

650

700

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850

900

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61

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66

Jun-11 Aug-11 Oct-11 Dec-11 Feb-12 Apr-12

lower-48 natural gas production

gas-directed rig count

-3,000.0

-2,000.0

-1,000.0

0.0

1,000.0

2,000.0

3,000.0

4,000.0

5,000.0

6,000.0

Q1

2011

Q2

2011

Q3

2011

Q4

2011

Q1

2012

Q2

2012

Q3

2012

E

Q4

2012

E

Q1

2013

E

Q2

2013

E

Q3

2013

E

Q4

2013

E

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


30 August 2012 31

Figure 5: US lower-48 natural gas supply/demand balances and price outlook

Annual average y/y change

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

Supply –total (Bcf/d) 62.74 65.42 67.53 68.97 66.72 2.68 2.11 1.44 -2.25

US L-48 Production 55.30 58.08 62.00 64.48 62.94 2.77 3.92 2.49 -1.54

Canadian Exports to US, net 7.05 6.96 5.94 5.61 5.15 -0.09 -1.02 -0.33 -0.46

US Imports of LNG 1.24 1.18 0.96 0.41 0.40 -0.05 -0.23 -0.54 -0.01

Exports to Mexico 0.85 0.80 1.36 1.54 1.77 -0.05 0.56 0.18 0.23

Demand – total (Bcf/d) 62.85 65.23 66.73 68.26 67.27 2.38 1.50 1.53 -0.99

Residential & Commercial 21.73 21.72 21.73 19.19 21.42 -0.01 0.01 -2.54 2.23

Industrial 16.91 17.87 18.45 18.78 19.08 0.96 0.58 0.32 0.30

Power 18.81 20.21 20.79 24.39 21.00 1.40 0.59 3.59 -3.39

Other 5.41 5.43 5.76 5.90 5.77 0.02 0.32 0.15 -0.13

Storage Inventories (Tcf)

End of March 1.7 1.7 1.6 2.5 2.0 0.0 -0.1 0.9 -0.5

End of October 3.8 3.8 3.8 4.0 3.9 0.0 0.0 0.2 -0.1

Economic Indicators

GDP growth 3.0 1.7 2.0 2.0

Industrial production growth 5.3 4.1 2.0 2.3

Natural gas price ($/MMBtu) $4.16 $4.38 $4.03 $2.64 $3.25


We advise investors to stay short through the end of the injection season, but watch for dips below $2.50 for entry points. We would advise producers (of gas and power) to hedge calendar 2013, as the curve looks somewhat overvalued to us at the moment.


30 August 2012 32

UK NATURAL GAS

More Norway, less power The UK gas market went through some big changes in H1 2012 as LNG takes fell by

some 42% y/y. Market balance was achieved by a ramp up of pipeline imports, with Norwegian and Dutch imports up by 35% and power demand falling by 30% y/y.

While the UK gas balance was seeing some significant shifts, UK pricing was, in contrast, very modest, with y/y changes in average prices negligible. The modest price behaviour pointed to the strong ability of pipeline gas to move into the supply gaps caused by the loss of LNG cargoes to Asia.

Our outlook for the remainder of 2012 and 2013 is largely more of the same, with LNG takes falling off further and requiring more supply-side response from the market. What the loss of LNG does, though, is make peak supply risks more acute and thus we do expect to see prices drift upwards in Q4 and be sustained at higher average prices in 2013 than seen in 2012.

Balancing: Supply and demand response

UK gas demand Natural gas markets are always sensitive to the weather and H1 2012 was characterised by a modest Q1, driven by a warmer-than-usual winter, followed by a stronger Q2, driven by a cool spring. By the end of July, end-use demand in the UK was some 6% y/y lower, although this does hide relatively good residential use and a big reduction from the power sector.

By the end of July, UK demand for gas in the:

Power sector fell by an estimated 4 bcm, a 30% y/y reduction. With total demand for power down, the fall in the share of share has come from the continued poor competitive position of gas-fired generation. With 4.2GW of new CCGT commissioned in 2010 and 2011, and another 2 GW looking to commission in Q4 of this year, the best that most of this plant can do is to replace older CCGT generation rather than coal in the merit order and then for that plant to replace coal plant lost to the limited operating hour derogations under the Large Combustion Plant Directive (LCPD). We expect that over the coming two years, 6.3 GW of coal plant will close due to the impacts of the LCPD, and this will likely add around 20 GWh per year of operation to gas-fired plants. With this being mid-merit plant likely to benefit most, this could add 4.5 bcm/y of gas demand back into power by 2014.

Residential: demand increased by 1.1 bcm (4% up) y/y across the UK, driven by the seasonally cold April–June period. While this sector’s demand is very sensitive to weather fluctuations, the overall pattern suggests an annual y/y increase. The sector is still seeing very little sustained growth and we expect that demand will be broadly around these levels in the coming years, albeit highly sensitive to the coldness of the winter.

Industrial sector demand has fallen by 3%, having lost 55 mcm. The decline in industrial production reflects the marginal slowing down of the UK economy seen throughout 2012.

UK gas supply The big change in UK supply was the sharp drop in supply from LNG. After LNG supply entered the UK market spectacularly in 2009 and ramping up to equate to 50% of supply by


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Demand mixed as residential up on weather, power

demand down

Changes in gas supply were significant


30 August 2012 33

April 2011, it has since fallen off just as spectacularly in 2012. In H1 12, the market share for LNG plunged to an average of 15% of UK supply, with LNG takes down 42% y/y – losing LNG takes of 6 bcm y/y. With the significant drops in LNG take occurring, it was up to pipeline gas to make up the difference. Over the first five months, supply from:

The UKCS continues to fall, dropping by 15% y/y to 19.9 bcm, according to DECC.

Norway to the UK was up by 35% y/y, taking 12.6 bcm over the first five months. We expected that Norwegian volumes would move into the gap created by diversions of LNG, and it has done so, although it has not yet chased the dormant demand in the power sector.

Netherlands to the UK was up by 36% y/y, with Dutch imports hitting 3.8 bcm over the first five months. While Q1 11 flows were affected by an unusually low level of March volumes, excluding March numbers and BBL, takes are still up by some 11% y/y. While stronger than last year, the BBL numbers were still some 13% below the Q1 10 peak levels.

While pipeline supply moved back to make up for some of the LNG reductions, market balance was also achieved by the major reduction in power demand and a reduction in UK exports, with the first seven months seeing net exports to Belgium down by almost 1 bcm. This is an important trend as it suggests to us that some market responsiveness is being seen through interconnector use, but the actual degree of response may be over-stated as the interconnector saw maintenance in June this year when historically this occurred in September.

In terms of use of gas in storage, net withdrawals peaked at around 2.1 bcm by the end of February from the start of the calendar year By mid-August, the market had injected around 150 mcm more gas into storage than it had withdrawn.

UK market balance outlook In terms of the outlook for market balance, we expect:

To see a continuation of the trend of a very significant reduction in supply coming to the UK by LNG. With Asian takes on the increase (see discussion in our LNG section), it is hard to see this trend reversing in the coming two years as regasification additions will continue to outpace liquefaction. As a result, we are forecasting that the UK will lose some 13 bcm of LNG supply in 2012 and another incremental loss of 2 bcm in 2013. If the UK does lose 15 bcm by the end of 2013, the annual take will be just over 10 bcm.

The LNG gap will continue to be met by Norwegian volumes. We note that our 29.5 bcm forecast for supply into the UK market will be the highest annual level of imports recorded. While the UK gas market should remain relatively well supplied this year, the biggest prevailing risk is weather and for a cold Q4 12 to draw down storage and bring back the risks of winter price spikes. While such winter risk is prevalent every year, peak supply issues will now be more acute given the increasing global competition for LNG. An implication of this is that the market will be increasingly sensitive to both expected and unexpected supply outages.

We note that for 2013, the market looks tighter as we see the global LNG market continuing to add more regas than liquefaction (see discussion on global LNG). With LNG likely to be less available next year and UKCS production likely to continue to keep falling, the NBP is only going to balance with a reduction in net exports to the continent. The main mechanism for this to occur is through a reduction in the gap between hub and contract pricing, or for more gas to be supplied on a hub basis on the continent. We expect both of these factors to be at play next year, as hub prices should begin to drift upwards and continued pressure builds on removing oil-indexation from European supply contracts.

While UK exports also fell

Global LNG market tightening but


30 August 2012 34

Despite the risks around even more LNG disappearing, we continue to believe that the UK and Europe as a whole is well supplied by pipes going forward. With little in the way of incremental demand this year or next, and 55 bcm of additional supply capacity having been added by the commissioning of Nordstream, the ability for NBP exports to begin to fall seems extremely plausible – it just remains a question of price.

Price outlook UK NBP D+1 prices have persisted as they did last year. Over H1 12, NBP D+1 prices averaged 58.3 p/therm, less than 1% up on the H1 11 average of 58 p/therm. Over Q2 12, average prices of 57.5 p/therm showed only marginal softening from the Q1 average of 59.1 p/therm (down 3% y/y) and this softening has continued through July with average D+1 prices averaging 55.6 p/therm (less than 1% up y/y). The lack of radical movements in NBP prices is in stark contrast to the significant adjustments seen in the fundamental supply and demand patterns over this period.

We expect NBP prices for Q4 12, to average 65 p/therm (a 10% decrease on our previous forecast), although the forecast remains bullish against the mid-August prevailing forward price of 64p/therm – suggesting only a modest gain to be seen in the contract. In line, we have also adjusted downwards our Q1 13 price forecast to 70 p/therm, down from 77 p/therm. Our forecast 12-13 winter prices are 67.5 p/therm, down 10% from 74.5p/therm. We believe the prices are exposed to considerable weather risk, so our main trade recommendation is either go out-right long, or to purchase a call option, on Q1 12 gas which is trading at 68 p/therm.

We still see price movements all the way to oil-indexed as being unlikely to be required, although most of the big weather risks are concentrated in the winter quarters and these will be increasingly acute beyond the coming winter. For 2013, we expect to see the IUK pipe switch back to being a seasonal swing pipe, which suggests lower summer prices and winter prices that are trending up towards the oil-indexed price.

Figure 1: NBP price forecasts (£p/therm)

Q1 Q2 Q3 Q4 Annual average

2009 47.0 27.7 21.7 28.0 31.1

2010 35.6 37.8 42.9 52.5 42.2

2011 57.1 57.5 54.2 56.8 56.4

2012 59.1 57.5 57E 65E 60E

2013 70E 60E 60E 70E 65E

Source: Ecowin, Barclays Research

Europe and the UK are well supplied with pipes

Prices have been subdued

We expect price risks biased to the upside with weather risk

paramount


30 August 2012 35

Figure 2: UK LNG demand (bcm/m)

Figure 3: UK supply patterns (bcm/m)

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Source: National Grid, Barclays Research Source: IEA, National Grid, Barclays Research

Figure 4: UK supply and demand balance

Annual calendar year volumes

BCM 2009 2010 2011 2012E 2013E

Supply - total 96.2 102.3 87.2 77.9 80.8

UKCS production 66.3 63.4 49.5 42.5 41.0

Pipeline imports 31.8 35.5 29.0 37.4 38.1

Netherlands 6.5 8.2 6.5 8.0 8.5

Norway 24.5 26.0 22.0 29.3 31.0

Belgium 0.7 1.3 0.4 0.1 0.1

LNG imports 10.4 19.2 25.4 12.3 11.3

Pipeline exports 12.2 15.8 16.7 14.3 11.1

Ireland 5.1 5.3 5.5 5.4 5.4

Belgium 5.8 9.0 9.5 7.5 3.5

Others 1.2 1.5 1.6 1.4 1.2

Demand – total 94.7 102.5 85.3 78.0 82.0

Domestic 31.5 36.2 28.3 29.4 29.5

Power 33.4 34.9 28.8 21.0 25.0

Industrial 17.2 18.2 16.0 15.5 15.5

Other 12.5 13.2 12.1 12.1 12.0

Changes in stocks (S-D) 1.5 -0.2 1.9 -0.1 -1.2

Source: DECC, National Grid, Ecowin, Barclays Research


30 August 2012 36

COAL

Good demand, better supply Despite a mild Q1, a cooler Q2 and good relative prices has meant that coal burn in

Europe has been strong, with imports up 6.6 Mt. While Asian demand has been less dynamic, Chinese imports were good with positive levels of restocking as relative prices supported arbitrage with international coal, although these tailed off in Q2.

The story of the market, however, has been supply, with most exporters able to increase production and US volumes becoming more available. With export volumes up, the pressure on prices was to fall and the CiF ARA M+1 prompts shed 15% since the start of the year.

We expect the markets to remain well-supplied across H2 12 and 2013. As a result, we expect Cif ARA prices to stay rooted around $90/t, possibly seeing some support from the oil markets. In terms of demand, we do not expect Chinese imports to maintain the same pace of growth as H1 (given ample inventories), although coal burn will be well supported through a pickup in economic activity in Q4. European, Indian and Japanese imports will be healthy, but the growth will be outpaced by the increase in supplies and availability of inventories.

We are forecasting CIF ARA prices to average $91/t over H2 12 and $92/t over 2013. FOB Richards Bay is expected to average $91/t in H2 12 and $94/t in 2013. We are slightly more positive for Newcastle prices, given their stronghold in the Pacific Basin, expecting them to average $93/t in H2 12 and $97/t in 2013.

Balancing just fine

European demand One consequence of the large reduction in carbon prices in H2 11 is the deterioration in the competitiveness of gas-fired generation plant across the EU. The difficulty for gas plant to get into merit against coal plant is being reflected in European coal burn. Over the first four months of 2012, the consumption of hard coal across the EU is up 7.77 Mt (7.8%) y/y, while lignite consumption is up 3.9 Mt (2.6%) y/y. The increase in EU coal burn does differ by country though, and the response to the changing relative prices has been the greatest where gas is hub priced and the power mix features sufficient coal and gas-fired plant to be competitive. The most responsive countries have been: Spain, where coal burn in power over the first five months is up 5.8 Mt (80% up), driven also by low hydro resources; and the UK, where consumption was up 6.3 Mt (26% up) over the first five months.

Outside these two countries, gains are smaller or losses have occurred, with German hard coal use down 1.1 Mt, although that was more than offset by a 4.4 Mt increase in lignite use, driven in large part by RWE commissioning 1.2 GW of new lignite-generating plant in Nuerath last winter. With EU hard coal production up only 1.7 Mt, the increase in burn was met largely by a 6.6 Mt increase in EU imports, with Spanish imports up 2.9 Mt and UK imports up 3.4 Mt. The increase in European coal burn and imports did coincide with falling coal prices (prompt prices down 20% from 1 January to 1 May), a testament to the healthy supply in the market in 2012. Over this year, these trends should largely continue as carbon prices stay low, gas prices soften only moderately and coal prices remain well in merit in power. However, y/y changes should begin to soften as by Q4 11, carbon prices had already shed considerable value. We forecast that European steam coal consumption should be up


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Miswin Mahesh +44 (0)20 7773 4291

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European demand up on low hydro and low carbon prices

Germany burning more lignite


30 August 2012 37

about 12.5 Mt with lignite adding another 8 Mt. We forecast steam imports to be up 18 Mt as increases in use are in the UK and Spain (net importers), while reductions in Central and Eastern Europe will focus on reducing domestic production.

Other demand: Asia

One of the key developments in H1 12 has been China moving into temporary coal oversupply. The relaxed market balance is a result of several factors: easing demand growth due to the country’s economic growth slowing, with Q2 down to 7.6% q/q from 8.1% in Q1 12; a wet H1 12 that has increased hydro power generation; good domestic coal production, which remained buoyant in H1 12 at 1.96bn tonnes, up 7.7% y/y; and domestic prices holding value better than international prices over the first half of the year, with the arbitrage window for international coals open for much of H1 12. As a result, H1 imports of Chinese steam coal have been at record levels of about 75.6 Mt. All of this led to a large increase in port stocks of both coal and iron ore by June. With storage being hard to find and expensive, two things happened: first, a raft of price renegotiations, defaults and deferrals of coal cargoes going into Southern China began; and second, domestic Chinese prices fell, followed by reports of Chinese production capacity being shut-in, potentially removing 250-300 Mt of production in the process. Port stocks have begun to be drawn down of late to 16.1 Mt, yet remain healthy. Given the strong restocking over H1, we do not expect the same pace of import growth in H2, but we expect it to still be a strong 60 Mt. We believe current high inventories are the primary limit on import growth, although coal burn itself is expected to hold steady in Q3 and increase in Q4, as industrial activity picks up following the feed-through effects of stimulus measures.

In the rest of the region, Indian coal imports are up only moderately y/y (3%) and have lagged expectations, coming below targets set by the country’s own Central Electricity Authority (CEA). Indian imports totalled 48.5 mt in H12012. Within that, steam coal imports by power utilities were sluggish from April to June, totalling 12.67 mt (22% lower than the government’s target of 16.27 mt). A number of issues continue to cap the expansion of imports: the depreciation of the rupee; scarcity of rail wagons; as well as latent power demand remaining unmet through a combination of power cuts. That said, however, we expect Indian coal imports to pick up for the rest of this year, with H2 12 at 62 Mt and 2013 up at 122 Mt, as:

a) India has added 5.2 GW of electricity generation capacity between April and June (above the target of 3.8 GW). Out of this, thermal capacity is one of the largest beneficiaries, with 2.1 GW added in June alone. We expect these projects to meet latent power demand and increase thermal coal usage.

b) Domestic production remains below target, given issues such as the slow pace of issuing forest clearances, which is delaying new projects coming online. Further, a shortage of wagons has meant that coal stocks at domestic mines are accumulating with limited dispatch frequencies.

Taking into account all these factors, we expect Indian coal imports to total 101 mt in 2012 and 122 mt in 2013.

Elsewhere in Asia, Japanese coal imports remain well supported, with H1 imports up 8% y/y, as most nuclear capacity remains offline. The only two reactors online are at the Oi power plant, which largely just replace some power-saving measures that otherwise would have been in place for the summer. According to the FEPC’s latest numbers for July, thermal power generation is 13% higher y/y. We expect Japanese thermal power plants to continue operating at high utilisation through the end of the year, as the continued opposition for the

China well-supplied…


30 August 2012 38

restart of Japan’s nuclear fleet in an environment of high oil prices supports coal burn. Japan imported 63 Mt of coal in H1; given the current favourable backdrop, we expect Japanese imports to hold steady in H2 as well (64 Mt) and for 2013 to reach 131 Mt.

Supply side: Up, up and away Having noted the increase in Chinese domestic production, global supply has been fairly strong in H1 12, with:

Colombia reporting a 13% y/y gain in exports in H1 12 at 40.4 mt. Output for the first half of the year is up 15% to 46.5 mt, and production is in line to hit the official target of 97 mt for 2012. The expansion faced a temporary obstacle due to a 25-day rail worker strike that has been resolved, and Colombian exports are set to resume. With Colombia enjoying a relatively low cost of production, it should still be able to price into key Atlantic and Pacific Basin markets. We expect Colombian coal exports to touch 81 mt in 2012 and maintain similar levels in 2013.

US exports being a highlight of H1 12, with US steam coal exports increasing 55% y/y to 25.6 mt, and Europe taking 13.4 mt. These incremental volumes have come from record-low natural gas prices pushing down domestic coal production and leading to high stock levels that made their way to the export market. Although US coal exports are relatively high-cost, exports become unattractive only if international coal prices near $80/t. Recent mine closures and lower international coal prices lead us to expect US coal export growth to slow in H2 to 20 mt.

South Africa reported a 23%y/y increase for exports in H1 12 at 36.8 mt, selling largely into the Indian market. We expect similar activity in H2, adding another 36 mt in H2 12.

Australian exports were 16% higher y/y at 77.6 mt; we expect another 81 mt in H2, as increased demand in the Pacific and continued capacity expansion augment output.

Indonesian exports have been the relative underperformer among the key suppliers, growing 9% in H1 12 to 165 mt. Although off-spec coal exports remain the favoured fuel choice among price-sensitive Asian consumers, the availability of lower-priced on-spec coal has meant Indonesian coal has lost market share on a cost-quality weighted scale. Also, Indonesia has started to see some supply-side response now that coal prices have been in retreat and some individual miners are high-cost suppliers. In light of this, we expect Indonesian coal export growth to flatten in H2, totalling another 160 mt.

Overall, volume into the market has been more than 45 Mt in the first half of the year, more than sufficient to meet demand from Europe and competition versus China. Looking further ahead, we expect the trend for good volumes into the market to continue and to keep upside to prices moderate for the rest of the year.

Price developments and outlook Coal prices since the beginning of the year to mid-August have fallen at the prompt, with M+1 CiF ARA contracts falling from 15%, from $110/t to $94/t. M+1 FOB Richards Bay has fallen 14%, dropping from $104/t to $89.5/t. The reduction in these contracts was greater, with CiF ARA falling as low as $85/t, but at those prices, there was some supply response with Russian and US volumes having difficulty pricing into Europe. Further, a three-week strike in August by Colombian rail workers disrupted coal supplies from that country and added about $5/t to delivered prices.

Prices have fallen along the curve, with Y+1 Cif ARA contracts falling 12% to $99.8/t and 9% for Y+2. Y+1 FOB Richards Bay has fallen 10% to $96.75/t, while the Y+2 contract has

Export volumes up y/y

Overall good supply volumes

Prices down 10-15%


30 August 2012 39

fallen 8% to $104/t. The reduction in prices at the prompt and along the curve is a testament to a well-supplied market.

The CIF ARA – FOB Richards Bay spread has returned to where it started the year, but this hides considerable volatility, with the spread trading between -$10/t to $5/t with a mean of -$2.4/t. While this is a large range, the spread spent most of the time at levels for which arbitrage between the two markets is closed – with current freight rates between ARA and Richards Bay at about $7/t. We expect the spread to continue to trade in that +/- $7/t range, with the prices largely moving independently of each other but with arbitrage opportunities between the two pricing points limited.

In terms of our outlook, we expect the market to remain well-supplied for the rest of the year, with the prompt CIF ARA and FOB Richards Bay trading at about an average of $91/t.

Figure 1: Global trade balances

Mt 2006 2007 2008 2009 2010 2011 2012F 2013F

Japan 119 126 131 113 125 120 127 131

South Korea 60 66 74 80 89 94 96 97

China 41 31 82 82 111 124 135 132

India 29 35 36 60 75 92 101 115

Europe 169 167 165 153 137 158 176 166

Others 182 198 201 186 202 214 202 208

Total imports 599 624 689 674 738 803 837 849

Y/Y change (%) 11.0% 4.2% 10.3% -2.2% 9.5% 8.8% 4.2% 1.4%

Indonesia 183 195 200 233 291 323 335 365

Australia 111 112 125 139 141 147 158 164

Russia 70 74 70 78 76 81 86 87

South Africa 67 67 68 67 70 69 74 74

US 20 24 35 19 23 34 45 28

Colombia 58 65 69 63 69 76 81 81

Others 96 93 79 61 52 66 76 51

Total exports 605 629 646 661 722 796 843 850

Y/Y change (%) 16% 4% 3% 2% 9% 7% 5.9% 0.8%

Global trade balance 6 5 -43 -13 -16 -7 6 1

Source: McCloskeys, Barclays Research

Figure 2: Price forecasts

Annual averages Quarterly averages

Benchmarks 2009 2010 2011 2012 2013 Q1 12 Q2 12 Q3 12 Q4 12 Q1 13 Q2 13 Q3 13 Q4 13

API 2 (US$/t) 71 93 122 94 92 101 91 90 93 95 89 90 93

API 4 (US$/t) 66 92 117 95 94 105 95 89 93 95 96 93 93

Newcastle (US$/t) 72 99 121 99 97 113 96 91 95 97 99 96 96

Source: Ecowin, Barclays Research

ARA-RB spreads have been volatile


30 August 2012 40

Figure 3: Exchange coal prices

Figure 4: FOB coal prices

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Figure 5: Coal forward curve

Figure 6: Coal price volatility

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Figure 7: 2012 export balances (mt)

Figure 8: 2012 import balances (mt)

H1 2011 H1 2012 % change

Colombia 35.6 40.4 13%

South Africa 30 36.8 23%

Australia 66.7 77.6 16%

Indonesia 152 165 9%

USA 16.5 25.6 55%

H1 2011 H1 2012 % change

India 47 48.5 3%

China 45.3 75.6 67%

Japan 58.35 62.8 8%

South Korea 45.68 45.2 -1%



30 August 2012 41

US POWER

Riding the bronco Power markets have had no choice but to ride natural gas through its wild ups and

downs of 2012. Cash and forward power prices were whipsawed by gas. Then, hot weather greatly boosted power consumption in the eastern two-thirds of the US this summer, particularly in July, pushing power prices and heat rates higher.

While the displacement of coal by natural gas has been a feature of the US power markets since 2009, coal experienced a dramatic additional loss of market share in 2012. While this was simply because surplus gas had no other outlet but the power sector, the scale of pullback on coal output stunned the market, with disruptive consequences to coal producers.

The number of proposed coal plant retirements has grown, partly in response to lower forward gas prices. These retirements would tighten certain power markets. Texas is already facing tight supplies, owing to continued strong demand growth, with inadequate new supply in the pipeline.

Forward power prices do not cover the cost of new power plants, even in Texas. While this has been the case for some years, with more markets looking ahead to tighter conditions, a debate is under way about how to structure markets so they bring forward new power plants before a crisis.

Coal pays the price for the warm winter It was fairly obvious that natural gas and coal were going to compete in the power sector in 2012. After all, the power sector is the only real source of price responsive demand, and the gas market not only carried about 900 Bcf of unused winter gas into 2012, but gas production started the year 5 Bcf/d above year-ago levels. This forced gas to price low enough to clear, which meant plunging deep into the coal stack.

The scale of the hit to coal was dramatic, and continues to be disruptive to the coal industry. Utilities idled coal-burning plants in virtually every region of the country at times during the spring, when gas prices dipped below $2/MMBtu. Coal has ceded share to gas all year. Coal stockpiles, already high from the tepid winter, ballooned, and utilities deferred coal into H2 12 and into 2013. Gas-fired power production through July has surged 38% higher than last year’s levels, levels which were pushed higher by hot weather and coal displacement in 2011 (Figure 1). Coal-fired power output is, consequently, 23% lower (Figure 2), as gas prices have remained competitive with coal all year. For the first month ever, gas-fired output matched coal-fired output in April 2012, then exceeded coal output levels in May and June. Hot weather in July put the coal plants back to work, producing more power than those running on gas, but steady levels of coal displacement will define the rest of the months of 2012, we expect.

The demonstrated amount of coal displacement represents a new high water mark for US power sector fuel flexibility. Now that utilities have learned to adapt to cheap gas, idling coal plants like never before, they will wield this new flexibility when needed.

The plunge of gas prices below coal pummelled coal generator margins (dark spreads). While the short-term effects attract the most attention, forward gas prices have pulled ever closer to forward eastern US coal prices. After accounting for coal transportation costs and

Shiyang Wang +1 212 526 7464

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Michael Zenker +1 212 526 2081

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Coal is pummelled by gas in 2012…

…demonstrating newfound flexibility by plant operators


30 August 2012 42

plant efficiencies, coal plants in the east are facing negative forward margins. That is, if a typical coal plant were to sell forward power in 2013 and 2014, and lock in forward CAPP coal prices, the operator would be locking in a loss. Thus, on top of existing and pending environmental regulations that affect the viability of coal plants, operators are staring at a forward market that for the first time offers no ability to lock in margins.

Coal plant retirements could tighten power markets

It was not long ago that higher gas and resulting power prices gave coal-fueled plants sufficient operating margins to justify a range of retrofits. While many plants have received emissions upgrades, a host of other plants are facing the unwelcome prospect of upgrade-or-retire decisions. These decisions must now consider lower power prices that have been persistently reset by lower spot and forward gas prices. Forward power prices are below break-even cost levels for eastern coal burning plants. Even regulated utilities appear to be adjusting their longer-term price expectations for natural gas, which makes a larger number of coal plants vulnerable. The prospect of a wave of coal plant retirements (we expect 42 GW of retirements) represents the single-largest shift in power market supply/demand balances in the next few years.

Power markets buoyed by strong summer weather While coal plants have had a tough 2012, power markets in general have been animated. While it seemed unlikely, and was not forecasted, this summer followed the footsteps of the much-warmer-than-normal summer of 2011. July 2012, which was 23% warmer than normal, was marked by the persistency of hot weather across the eastern two-thirds of the country, pushing heat rates above year-ago levels (Figure 3). All regions have experienced heat rate expansion, although July 2012 temperatures in Texas were not as extreme as last year.

While we use the standard definition of heat rates (power prices divided by natural gas prices), we note that, at times, coal plants were likely the marginal resource, especially when gas prices were at their lowest. If coal was on the margin, then not only would this tend to reward gas-fired plants with higher power prices, versus if power prices were set only by gas, but run times for gas-fired plants would soar, which is evident in 2012, as implied by Figure 1.

Figure 1: Monthly US gas-fired power generation, ‘000 GWh Figure 2: Monthly US coal-fired power generation, ‘000 GWh

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Source: EIA, Bentek, Barclays Research Source: EIA, Barclays Research

Forward power prices offer no margin for coal plants

Heat rates expanded this summer, rewarding mostly gas-

fired plants


30 August 2012 43

Keeping the lights on Most US power markets are engaged in some form of debate on how to provide incentives for firms to construct new generation. Forward power prices do not cover the cost of a combined cycle gas turbine (CCGT) (Figure 4). While this has been the case each time we have run the numbers for Figure 4, system operators are nervously eyeing a growing list of proposed coal plant retirements, and certainly understand the threat posed to coal plants by lower gas prices.

The New England, New York, and PJM (mid-Atlantic) markets feature a capacity payment that is intended to keep existing plants from retiring and reward generators for adding new capacity. But that capacity payment is included in Figure 4, and falls short of providing enough additional revenue to make new capacity economical.

PJM and MISO (Midwest) have proposed a reliability payment for certain critical plants that are proposing to retire. This short-term payment would keep plants operational for a few years while transmission changes were made, or other plants brought on line.

The Texas power market is in a league of its own, primarily because strong economic growth in the state has propelled power demand to levels that have shrunk reserves well below what the system operator considers safe. That there is a supply shortfall in Texas is not in dispute, but what is being debated is what to do about it. State regulators have voiced their concern that, despite higher power prices this and last summer, power prices have not been high enough to justify new capacity. They raised power price caps in Texas in August 2012, from $3,000/MWh to $4,500/MWh, to give generators the opportunity to make greater margins during periods of peak power demand. Regulators may raise the cap again, to $7,500-$9,000/MWh. Yet, an analysis conducted for the Texas grid operator indicates that raising price caps alone is not likely to bring forth enough needed supply. Texas regulators have hinted that they may consider a form of capacity payment – heresy to a market that has been staunchly energy only. With August traditionally the peak demand month, all eyes will remain on the Texas power market.

Forward power prices still do not cover the cost of new plants

Regulators try to incentivize new capacity in Texas

Figure 3: Power market heat rates (MMBtu/GWh)

Figure 4: Percent of new-build CCGT costs covered by forward power prices and capacity payments (where available)

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10

15

20

NepoolMassHub

Mid-Atlantic

(PJMWest)

Midwest(Cin Hub)

ERCOTNorth

California(SP15)

New York(Zone A)

Q110 Q210 40360Q111 Q211 40725Q112 Q212 41091

68%

51%

64%55% 53%

62%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

MassHub

NY-ZoneA

PJM-West

ERCOT-N

MISO-AD Hub

SP15

Source: ICE, Barclays Research Source: PJM, NEPOOL, NYISO, EIA, Barclays Research


30 August 2012 44

CARBON

Looking for intervention European carbon prices have been volatile over H1 12, while staying at low levels,

and trading in a range of 6-9 €/t. The low levels belie a market that is highly over-supplied and, including the use of offsets, has an inventory after the first four years of phase 2 of 950 Mt (almost 50% of one year’s emissions).

The market continues to look long, with the moribund demand side likely to continue as the European power system de-carbonises and energy-intensive industry seeing both a reduction in activity and making strides in reducing the carbon intensity of its output. We forecast that the market, given existing rules, will be increasingly long until 2015.

Prices will remain low given high inventory levels. Current proposals by the EC to shift volumes of EUAs from the early years (2013-15) of the next phase to the back-end of the phase will serve to increase volatility and average phase prices. Until greater clarity on the proposals is reached, we forecast prices to average 8 €/t over the coming decade.

EU ETS: oversupplied The publication of verified emissions for installations under the EU ETS for 2011 confirmed that the EU ETS is long just in terms of the use of EU allowances (EUAs). The total market balance from the figures means, just in terms of emissions less allocation, that installations received 100 Mt more allowances than emissions in 2011 (up from 60 Mt in the same cohort last year). Adding in another 98 Mt from sovereign auctions, plus expected surpluses of the remaining installations, pushes the market balance closer to 200 Mt. The numbers suggest that over the first four years of phase 2, the net market balance has been -400 Mt of EUAs more than emissions.

The reasons for the EUA over-supply are predominantly owing to:

A reduction in industrial sector emissions, driven by low economic activity and investment in emissions-reducing technology. In terms of the former, industrial production in Europe has lagged real GDP while the sectors covered by the EU ETS have tended to lag industrial production.

A reduction in the carbon content of the output from the power sector combined with a stagnant demand profile. While power demand has not been growing, Europe has continued to add renewable generation with around 50 GW of renewables added to the EUs power systems in the period 2010-12. The result has been consistent reductions in the power sector’s emissions and a squeezing of power wholesale market margins as systems become over-supplied with capacity.

Adding to the over-supply in the market in H1 12 has been:

The issuance of offsets, which, while having slowed, has still seen 160 Mt of CERs issued and around 70 Mt of ERUs issued over the first seven months of this year. While CER issuance has slowed over the past two months, a function of both new issues around industrial gas projects and the economic incentive of low prices to delay issuance, the supply is coming solely into Europe. The total use of offsets in the first four years of the market was 545 Mt, which we expect to swell to at least 800 Mt once 2012 compliance is completed.

Trevor Sikorski +44 20 313 40160

[email protected]

First four years of phase 2 sees carbon market go increasingly long


30 August 2012 45

The sale of phase 3 EUAs. First, through the sales by the EIB of the NER 300 programme that is monetising 200 Mt of phase 3 EUAs this year, of which 163 Mt was sold by the end of July. Secondly, the EC is committed to selling 120 Mt of “early auction” phase 3 EUAs, although none of this has been achieved. While the intention is there, it is possible that the joint procurement decision on a central auction platform may be delayed and that not all of these will come to market. We expect that at least 40 Mt will be sold, with some doubt over the remaining 80 Mt. If that 80 Mt is sold, then there will be further risks to prices in Q4 12, with both EUAs and CERs at risk of hitting phase low prices before climbing to slightly higher next year.

Owing to the high level of supply in the market, prices have stayed fairly low, trading in a 6.2-9.5 €/t range, although the price paths have been punctuated by various bouts of volatility surrounding policy development events aimed at supporting prices in the market (see discussion below). Over H1 12, EUA prices have averaged 7.45 €/t while CERs have averaged 3.76 €/t.

Figure 1: EUA price developments (€/t)

0

5

10

15

20

25

30

35

Jan-08 Jun-08 Dec-08 May-09 Nov-09 Apr-10 Oct-10 Mar-11 Sep-11 Mar-12

EUA front year CER front year EUA-CER spread

Source: ECX ICE, Barclays Research

Market balance

Looking further ahead, the underlying trend of energy intensive industry slowly leaving Europe is one we do expect to continue, and it is hard to see that activity getting back to 2008 levels in the coming years. We are now forecasting that emissions in the industrial sectors will fall by 8% over that period, or by 21% between 2008 and 2020.

As a result of that, and the increasing decarbonisation of power is that the total level of surplus carbon in the market by 2020 will be 2063 Mt, up from our previous forecast of 1721 Mt. Importantly, this means that the market stays longer for longer, removing much of the potential upside to prices in the absence of EC intervention in the market.

Pricing has been low but volatile

Trend is for carbon intensity reduction…

… suggesting market length will increase


30 August 2012 46

Figure 2: EU ETS supply and demand balance (Mt)

2008 2009 2010 2011F 2012F Phase 2 2013F 2014F 2015 F

EUA Allocation (cap) 2003 2052 2079 2099 2334 10,566 2256 2218 2181

Emissions 2119 1882 1937 1893 2117 9,947 2126 2146 2156

Emissions – cap 116 -170 -142 -206 --217 -619 -130 -73 -25

ERU/CER usage 80 80 135 250 400 945 150 175 200

Net position (inc offsets)

36 -250 -277 -456 -719 -1564 -280 -248 -225

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. Reflects current cap and does not account for backending. Source: CITL, Barclays Research

EC intervention: Looking likely

With prices languishing and the market looking structurally long for an extended timeframe, there has been political pressure to support prices through some form of market intervention. In July, the EC released a working paper for consultation that explored both short and longer-term forms of intervention that it might take. The preferred short-term option is to remove some volumes (400-1200 Mt) from the cap for the first few years of the next phase (2013-15) and to put them back into the market in the last few years (say, 2018-20). The longer-term options are all about actually altering the cap to make it more ambitious (higher emission reductions), a set of options that appears politically difficult to achieve in the current economic climate.

As such, the back-ending of volumes seems likely, as it will support prices in the first few years of the phase, while allowing a deeper cap to be operationalised later – through cancelling those allowances. The proposals do introduce a considerable amount of uncertainty to the market as the future price path of carbon will depend on: the volume of allowances to be back-ended; the years in which those volumes will be removed; the years over which the volumes will be replaced; and, finally, if the volumes are to be cancelled.

We assume that a 700 Mt back-ending of EUAs is agreed, although that is more about what we feel is politically possible than what is wanted by the EC. We assume there is no change to the phase 3 cap, and the result of these assumptions is that prices will average around 8 €/t over the phase, but peaking in 2015 at 11 €/t.

Possibly counter-intuitively, we do find that just back-ending auction volumes does increase the average level of prices across the phase, as without intervention, we forecast average phase 3 prices would be around 6 €/t, peaking at 10 €/t in 2020. A cancellation of 700 Mt would push average prices up to 12 €/t, while 1200 Mt being cancelled would push average prices to 19 €/t.

Figure 3: Carbon price outlook

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

EUA 22.6 13.4 14.5 13.4 7.5 6.5 7.5 10 8

CER 17.4 11.8 12.4 10.2 3.9 3.25 3.5 5 3.5

EUA-CER spread 5.2 1.6 2.1 3.2 3.6 3.25 4 5 4.5

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


30 August 2012 47

Figure 4: EUAs, CERs and the spread Figure 5: Market balance (Mt) – no intervention case

0

2

4

6

8

10

Apr-12 May-12 Jun-12 Jul-12 Aug-12

EUA Front year (€/t) sCER Front Year (€/t)

EUA-CER spread

0

500

1,000

1,500

2,000

2,500

2012 2013 2014 2015 2016 2017 2018 2019 2020Cumulative length Demand

Source: ECX ICE, Barclays Research Source: Barclays Research

Figure 6: Forward curves and fair value

Figure 7: Fuel switching (Gas less coal) in generation

1

2

3

4

5

6

7

8

9

10

2012 2013 2014 2015EUA fair trade (€/t) EUA (€/t)

CER (€/t) CER fair trade (€/t)

-20

-10

0

10

20

30

40

Jul-11 Oct-11 Jan-12 Apr-12 Jul-12

54% v 30% 48% v 36%

Gas SRMC - coal SRMC €/MWh

Note: Fair value calculation takes the front DEC price and applies the cost of carryat Euribor to derive future prices. Source: ECX ICE, Barclays Research

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 ICE, Barclays Research

Figure 8: CDM issuance (Mt)

Figure 9: EUA and CER volatility (%)

0

10

20

30

40

50

60

Jan-08 Jan-09 Jan-10 Jan-11 Jan-12

Issued CERs (Mt CO2)

0

20

40

60

80

100

120

Apr-12 May-12 Jun-12 Jul-12 Aug-12

CER VOL EUA VOL

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


30 August 2012 48

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30 August 2012 49

CREDIT


30 August 2012 50

US HIGH GRADE ENERGY & PIPELINES

The haves and the have-nots Refiners and Canadian integrateds should continue outperforming if U.S. and

Canadian crude oil differentials (relative to global benchmarks) remain wide.

The weaker NGL backdrop is not evenly reflected across the MLP sector.

Summary of investment view Within investment grade, the energy and pipelines sectors lagged U.S. Credit by 162bp and 108bp, respectively, during the year-to-date period. However, performance across the energy bucket varied dramatically by sub-sector, with E&P and integrated underperforming by over 250bp and refining and oil field services outperforming by 91bp and 245bp, respectively.

Relative to the average sub-sector differentials versus U.S. Credit during the past three years, E&P and integrated companies screen as fairly valued, oil field service companies are cheap, refining appears rich, and pipelines are essentially at the wides. Predicated on increasing dayrates and utilization, as well as the rig newbuild cycle, we believe that the oil field service sector is poised to outperform in 2H12. Within E&P and integrated, we retain our preference for selected Canadian energy credits (particularly those with regionally advantaged downstream capacity), while refining long bonds have value versus intermediates and pipelines offer mixed relative value prospects according to their disparate distribution coverage and leverage metrics.

From a fundamental standpoint, if the low price of natural gas was the story of 1H12 (and no less important in 2H12, for that matter), natural gas liquids (NGLs) were the focus of investors on 2Q12 earnings calls. We expect ethane prices will remain low due to structural oversupply through 2015, propane will recover slightly (particularly if winter temperatures revert to the mean), and natural gas will be range-bound in order to encourage fuel switching by utilities to balance the market. Rising domestic crude oil production has positive implications for refiners (particularly those with PADD II footprints) and certain pipeline companies with crude oil infrastructure.

Investment recommendations If Gulf Coast crude oil differentials remain wider than historical averages, we believe that

refining curves are too steep – we recommend putting on curve flatteners in Marathon Petroleum Corporation (MPC, MW) and Phillips 66 (PSX, NR).

Improving dayrates and capacity utilization benefit offshore drillers. We continue to see value in Transocean Ltd (RIG, OW) and Rowan Companies plc (RDC, NR).

The challenging NGL environment will weigh on a number of MLPs, but certain credits are already discounting the weaker fundamental backdrop. We recommend swapping out of Williams Partners LP (WPZ, MW) and Enbridge Energy Partners, L.P. (EEP, NR) and into ONEOK Partners, L.P. (OKS, MW).

With a positive outlook for crude oil prices, we continue to see value in Canadian integrateds such as Suncor Energy, Inc. (SUCN, OW) and Cenovus Energy Inc. (CVECN, OW), with both companies benefiting from downstream integration that provides a hedge against wider Canadian crude oil differentials.

Harry Mateer +1 212 412 7903

[email protected]

Ming Zhang +1 212 412 3386

[email protected]


30 August 2012 51

US HIGH YIELD ENERGY

Gas prices and new issuance undermine returns HY Energy bonds have returned 6% on a YTD basis, significantly underperforming the

overall market’s 10% return. Weak natural gas prices have led to a bifurcation in the E&P sector, with the more gas-weighted single-B rated credits now trading ~300bp wider than oil-weighted names. New issue supply in HY Energy/Pipelines has topped $36bn YTD, surpassing 2010’s full-year record of $34bn, also weighing on spreads.

Despite the dislocation, we do not recommend investing in gas-weighted credits. We prefer oil-weighted credits including, Hilcorp Energy, MEG Energy, Plains Exploration & Production, and SandRidge Energy. In services we like international-weighted credits including, Atwood Oceanics and Petroleum Geo-Services. In Pipelines we are Overweight Targa Resources Partners.

Summary of investment view

We continue to look for 5-7% returns for energy bonds in 2012, marking four out of five years that the HY Energy Index would have underperformed the overall HY market. On a yield basis, the HY Index is close to its all-time tights of 6.5%, and the energy index trades about 30bp tight of the market. We note that since inception, energy has traded ~135bp through the market, leaving it cheap on a relative basis. We would be more bullish on the sector absent new issue supply and weak natural gas prices. An added concern could be the large influx of private equity funds devoted to natural resources.

We believe that the High Yield Energy and Pipeline sector is supported by strong asset coverage, hedging that provides downside protection, declining leverage, and oil prices that buffer weak gas prices. From a fundamental perspective, Barclays’ commodity analysts forecast that WTI oil and Henry Hub natural gas prices will average $96/bbl and $2.64/mmbtu, respectively, in 2012. Risks include an economic slowdown, continued low natural gas prices, weaker NGL prices, increasing costs and labor pressures, and for many shale producers seemingly perpetual negative free cash flow.

Investment recommendations Buy NGLS 21s (OW), Sell RGP 21s (MW), pick up 25bp in yield. We believe Targa is

trading cheap to Regency, given its lower leverage (2.9x vs. 3.7x) and better ratings (Ba3/BB vs. B1/BB). While less fee-based than 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 SD 22s (MW), Sell CHAPAR 22s (MW), pick up 85bp in yield. SandRidge is higher rated (B2 vs. B3), is triple the size on a proved reserve basis, is public, and has similar leverage when compared with Chaparral. Both companies are outspending cash flow, though SD’s recent $1.1bn in bond financing helped to build cash and ensure funding through 2013. Chaparral recently reported disappointing 2Q12 production.

Buy PGS 18s (NR), Sell HOS 20s (NR), pick up 25bp in yield and shorten duration. PGS notes are better rated (Ba2/BB vs. Ba3/BB-), and the company has about a half the net leverage compared with Hornbeck. PGS recently lifted its 2012 EBITDA guidance to $750-800mn, from $700mn, reflecting stronger utilization and pricing for seismic services.

Gary Stromberg +1 212 412 7608

[email protected]

Kateryna Kukuruza +1 212 412 7647

[email protected]


30 August 2012 52

US HIGH YIELD COAL

Despite supply-side cuts, challenges persist Domestic thermal coal fundamentals remain weak but have recently shown some

evidence of demand recovery.

Producer cuts to production should help rebalance supply/demand but much will still depend on the price trajectory of natural gas and winter heating demand.

We remain Market Weight the metals & mining sector, but hold a cautious view of coal producers, given persistent fundamental weakness in thermal and metallurgical coal.

Summary of investment view Domestic thermal coal market fundamentals began weakening in late 2011 and remain challenged. The two-pronged assault from coal-to-gas switching, due to near historic lows in natural gas prices, and unseasonably warm winter weather is projected to reduce FY12 thermal coal demand by more than 100mn tons. While demand remains under pressure, several positives have recently emerged, including natural gas prices that have recovered to ~$2.80/MMBtu from less than $2.00/MMBtu and a warmer-than-average summer. Demand commentary from PRB producers, thus, has grown increasingly positive as they believe PRB coal competes with natural gas at these levels. Similarly, the hot summer domestically has driven additional electricity demand, increasing the burn of thermal stockpiles at utilities.

To make production levels more closely match the reduced demand for thermal coal, producers increasingly closed or idled higher costs mines throughout late 1Q12 and 2Q12. Based on annualized 2Q production figures, domestic producers have rationalized more than 100mn tons of thermal coal, bringing the market closer to equilibrium. Fortunately, the combination of supply cuts and modest demand side support should reduce stockpiles at utilities from more than 200mn tons in May to 188mn in August, and contract renegotiations have reportedly grown less frequent. We expect some continued idling of production this fall, with the rebalancing of the thermal coal market relying heavily on winter weather and the natural gas price trajectory.

We believe PRB producers have benefited most from the natural gas price recovery and hot summer weather, given their position at the low end of the cost curve. While there has undoubtedly been a trickle-down effect on Appalachian coal producers, we continue to view them more cautiously, given the higher cash costs of mining in this region. Our concern extends to metallurgical coal, which has recently experienced a sharp drop in demand and price. And many Appalachian coal producers are heavily exposed to met coal price fluctuations.

Investment recommendations We continue to favor exposure to PRB producers and believe that long-term

investments in Cloud Peak (CLD) 8.5% senior notes (MW) and Peabody Energy (BTU) 6.25% senior notes (MW) will be profitable. However, with the high yield market trading at or near its tights, we would not be surprised by some short to medium-term volatility.

With Alpha Natural Resources (ANR) 6.0% (MW) and 6.25% (MW) senior notes having traded up 7/8 dollar points and into the low 90s since early July, we recommend reducing risk. Just as the bonds have tightened more than 100bp, metallurgical coal has sold off ~$50/mt. ANR remains heavily exposed to metallurgical coal prices, and we expect continued weakness in this market to weigh on its profitability, driving spreads wider.

Matthew Vittorioso +1 212 412 1378

[email protected]

Oscar Bate +1 212 412 3732

[email protected]


30 August 2012 53

US HIGH GRADE UTILITIES

Regulated utilities remain stable Our Market Weight recommendation on this defensive sector reflects a predominantly

stable credit profile, expectations of continued significant new issue supply, and tight spreads.

At current spreads, we favor BBB and crossover regulated utilities, as well as utility holding companies with predominantly regulated businesses.

Given continued weak power and natural gas market prices, we remain cautious on unregulated generation subsidiaries and diversified holding companies with larger unregulated generation businesses.

Summary of investment view

Sector strengths include continued stable credit metrics and credit ratings, continued constructive regulatory support for the recovery of ongoing capital investments, and a focus by the industry on balanced risk strategies that emphasize regulated utility investment. Increased capital investment and the decline of bonus tax depreciation from 100% in 2011 to 50% in 2012 will likely increase debt issuance in the sector this year to $33-35bn, compared with $28bn in 2011.

Principal uncertainties include large ongoing capital investment programs, including some large new generation projects, and continued uncertainties regarding environmental regulations from the Environmental Protection Agency governing emissions from coal-fired power plants.

Investment recommendations Buy Duquesne Light Holdings (DQE)(OW) 5.90% bonds due 2021, quoted at +220. 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.

Jim Asselstine +1 212 412 5638

[email protected]


30 August 2012 54

US HIGH YIELD UTILITIES

Focus on natural gas 2012 has been defined by an unprecedented level of coal-to-gas switching as

natural gas prices continue to trade below $3/mmbtu.

While headlines about EPA-mandated shutdowns and market reforms in ERCOT and PJM remain topical, we feel investor sentiment will be ultimately driven by the near-term movements in gas prices and their effect on forward power curves.

While the HY Power sector continues to struggle through trough-like conditions for merchant power generation, we feel Calpine (CPN) and NRG Energy (NRG) ultimately benefit from exposure to the tightening Texas market and solid balance sheets/ liquidity that position them to ride through the weak market.

Summary of investment view Natural gas fired generation has recently breached the 30% threshold, as coal has been losing share to the cheaper fuel in most markets. Coupled with record hot weather in July, gas generation running as baseload capacity during the much of the first half of the year has driven an additional ~3-4 bcf/d of natural gas consumption, supporting prices in the $2.50+/mmbtu range over much of the past six months. CPN’s gas-fired fleet has directly benefited from this trend, realizing a 45% increase in MWh generated y/y in 1H12.

The question, however, will be whether this trend of coal displacement can continue. Higher natural gas prices should reduce demand on the margin, shifting generation back to coal and keeping a near-term ceiling on natural gas prices. As natural gas storage remains at historical highs following the recent boom in shale gas drilling and the record warm winter, investors will be focused intently on the end of the storage season in October, with the potential for inventory levels over 4.0 TcF to pressure gas prices back to levels ($2.00-2.50/mmbtu) that would encourage a return of coal-to-gas switching. With natural gas prices still setting power prices in the day-ahead and forward markets, any pressure on fuel would limit improvements in dark and spark spreads over the next several quarters.

While future profitability will likely weaken for merchant coal-fired operators (NRG, GenOn) as past hedges are replaced at now-lower market prices, the market dynamics in Texas/ERCOT (notably the tightening reserve margin as weather and industrial growth create spikes in demand) should be a positive for existing operators there (NRG, CPN). The Texas Commission (PUCT) has held workshops to address the issue of resource adequacy, and we would expect any resolution to be a longer-term positive for generation margins in ERCOT.

Investment recommendations

NRG (MW): The GEN merger is a positive, given equity funding and the assumption of a non-recourse subsidiary. FCF remains strong, but upside is limited trading flat to the HY Index, as we expect management to be focused more on shareholder returns.

CPN (MW): Solid core holding with Texas exposure, but holdco bonds have limited upside, as the structure trades over 200bp inside the HY Index. Bonds should continue to trade well in light of still-high levels of gas fired generation, but additional outperformance will be challenged at current yields.

Brian Lalli +1 212 412 5255

[email protected]


30 August 2012 55

EUROPEAN HIGH GRADE OIL & GAS

A safe haven with pockets of volatility Oil price and LNG to offset weak production and poor downstream returns.

FCF generation remains weak on upstream capex.

Ratings upside for BP; sovereign-related deterioration for ENI and Repsol not priced.

Summary of investment view In H2 12, we believe the key driver for sector spreads and ratings remains the oil price, with ongoing gas price weakness, and sovereign ratings for ENI and Repsol. Additionally, LNG-based players’ fundamentals should continue to benefit from favourable trends for demand and pricing. This is owing to EM growth and changed attitudes towards nuclear power that have allowed a number of companies during H1 12 to outperform expectations for earnings. However, this comes against a backdrop of oil major production growth remaining paltry relative to the ambitious high single-digit growth targets of BG and Repsol, notwithstanding the sizeable element of project execution risk the latter carries. Further, downstream conditions remain weak owing to structural refining oversupply and under-utilisation, combined with soft oil product demand and spreads. We note that such downstream trends, more acute in Europe, may be further exacerbated by a more severe bout of macroeconomic weakness in Europe and the rebound in oil prices in H2 12 expected by our Barclays’ Commodity analysts. We believe this may weigh on the European downstream focussed names such as OMV and Repsol.

While sector cash flows will continue to be underpinned by relatively solid cash generation from E&P, underlying FCF remains weak (or negative) due to upstream focussed capex spend. In our opinion, ongoing and potential asset disposals will remain key in reducing sector financial risks with material divestments at ENI (Snam), BP (TNK-BP) and Repsol (LNG assets) aimed towards improving gearing and liquidity.

In our view, sector liquidity is strong owing to our belief that sector names are likely to prefer to hold cash and refinance debt on the markets – with in excess of USD23bn bond maturities to end-2013, we expect material issuance months. We see Total and BG Group as most likely to issue owing to an internal cash generation funding shortfall over 2012/2013.

Overall, we expect ratings stability for Shell, Statoil and Total, but continue to see the potential rating movement outside this group. First, for BP, we envisage rating upside in the coming months should a favourable settlement with US authorities be reached and see potential for cash spread compression with its higher rated ‘AA’ peers in a similar fashion to that seen in euro 5y CDS. Second, in the cases of BG/OMV, and ENI and Repsol, we highlight that there remains scope for rating downside owing to the costs of investments/M&A and pressures on sovereign ratings, respectively. While the impact on spreads of the former names may be relatively small, movements for peripheral names may be substantial as rating deterioration (eg, Repsol to sub-IG) is not priced, in our view. The latter could induce underperformance within European credit portfolios.

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

[email protected]


30 August 2012 56

Investment recommendations Overweight BP cash: In our view, settlement with the DoJ with respect to the Macondo

liabilities remains the key driver of spreads. We believe there is a high probably of settlement ahead of US presidential elections. Moreover, disposals, including the potential 50% stake in TNK-BP, remain a key source of positive event risk.

Buy ENI 5y CDS: We recommend credit investors short ENI 5y CDS (195/210) with ENI (Underweight) trading c.160-170bp back of 'BBB' Italian corporates and tight versus Italy (c.30% owner). We see scope for material spread deterioration with fundamental upside remaining constrained by Italian sovereign debt dynamics.

Sell Repsol EUR’16s and EUR’17s and Buy Repsol 5y CDS (365/380) at current levels: We believe that on completion of Spain's review for downgrade at Moody's, Repsol (Underweight) is vulnerable to further downward migration in ratings that are weakly positioned at investment grade. In our opinion, Repsol's credit fortunes are now beyond leverage and dictated by upstream delivery, Spanish downstream performance and sovereign risk, as well as its ability to maintain an adequate liquidity profile.


30 August 2012 57

EUROPEAN HIGH GRADE UTILITIES

The former untouchables Rating risk remains skewed towards the downside owing to adverse business trends.

Macroeconomic and sovereign weakness continues to plague periphery spreads.

Regulated utilities affected by evolving regulatory and political frameworks.

Large-scale M&A unlikely, but United Utilities and Chinese investments are likely.

Summary of investment view While European Utilities performed in line to above expectations during Q2 12, with few exceptions, we believe continued adverse pressure on business profiles from weaker cash generation and profitability will ultimately lead the agencies to become more conservative on leverage guidance and credit ratings. We thus expect further sector downgrades.

Across Europe, weakness continues to stem from weak power and gas prices on unhedged volumes and achieved forward sales, low margins on spread generation, soft energy demand and negative gas-oil spreads. While targeted growth in renewables and emerging markets as well as partnership models are key tools issuers are using to adjust operational and financial risk profiles, a number of names are struggling to contain leverage. Thus, self-help measures, project delivery and improved midstream gas profits remain crucial for ratings. That said, it appears only temporary solace has come from gas contract renegotiations as fixes appear long in the making, and we believe that the main gas importers are likely to return to arbitration/renegotiation before long. We continue to expect Edison and RWE to benefit from sizeable gas contract compensation.

In the periphery, the additional material macroeconomic and sovereign weakness – and potential for further sizeable downgrades, including of Spain, in September – will likely continue to weigh negatively on the spreads and ratings of peripheral utilities.

In H2 12, evolving European regulatory and political frameworks expose the traditionally ultra-defensive regulated utilities, including National Grid (RIIO) and TenneT (political and regulatory noise in Germany) to adverse developments. Additionally, the Spanish government has yet to introduce formal measures that solve the Spanish tariff deficit, and we remain concerned about special taxation having an adverse effect on ratings.

Into year-end, we highlight that the Final Investment Decision for Nuclear New Build (NNB) at Hinkley Point is due in Q4 12 and could be a game changer for Centrica’s business risk profile. However, Centrica’s participation at this juncture is uncertain owing to a lack of clarity on NNB returns in the UK. Additionally, we await France and Belgium’s to-be announced energy policy. We continue to we see little scope for large-scale M&A after corporate deals of EDF SA and GDF Suez in H1 12. However, the UK Water’s United Utilities Group plc (UU) could remain subject to market speculation around a takeover. Further, we believe foreign investors (particularly from China) are likely to continue to buy stable earning assets and equity in the UK, Southern Europe and Latin America, should opportunities be present.

Sector liquidity profiles remain strong, but in September 2012, we expect a flurry of senior and subordinated issuance in the space, including in the periphery.

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

[email protected]


30 August 2012 58

Investment recommendations Overweight CEZ: Given our view that CEZ is likely to remain financially stable versus a

soft sector outlook, wide trading relative to fundamentals despite CEZ’s state ownership (70%), low leverage versus Northern European peers, conservative financial policy and limited need for issuance post dollar deals should provide comfort to credit investors.

Overweight Edison bonds: In the near term, Edison's fundamentals should be boosted by integration into the wider EDF SA group, in addition to benefits from gas contract compensation and liquidity management. On a technical front, we expect S&P and Fitch upgrades to IG to be supportive of Edison bond liquidity and re-entry into the main IG indices. With Edison's outstanding bonds (4.25% EUR'14s, 3.25% EUR'15s and the 3.875% EUR'17s) currently trading roughly 100bp back of EDF, we see scope for substantial spread compression.

Short Iberdrola cash bonds and Sell Enel CDS against buying Iberdrola 5y CDS or Gas Natural 5y CDS: We maintain our cautious stance on Spanish utilities, in particular Iberdrola (Underweight) owing to our concerns about downgrade risk on: 1) Spanish energy reforms and; 2) potential cuts in the sovereign's ratings (to sub-investment grade) that could leave Iberdrola weakly placed within investment grade. At current levels, we do not believe such risk is effectively priced. Owing to our view that these risks are more elevated for Spanish names, we recommend selling Enel 5y CDS (Underweight) against a short position in Iberdrola 5y CDS or Gas Natural (Market Weight) 5y CDS.


30 August 2012 59

ASIA HIGH YIELD COAL

Near-term outlook lacks heat We expect the earnings weakness seen in 1H12 to persist in the second half. Based

on recent contracted prices, most issuers forecast weaker ASPs in 2H12. This is likely to offset expected production increases and lower production costs during the period. We expect significant deterioration in 2012 credit metrics as a result, although assuming a recovery in the coal market in 2013, this could be temporary.

Bond valuations in the Indonesian coal sector look relatively rich in light of the industry-wide weakness. Nevertheless, we maintain our neutral stance on the sector, as technicals remain sound given the lack of new Asian HY supply.

Summary of investment view Earnings pressure in 2H12: Weaker average selling prices (ASPs) in 2H are likely to offset expected increases in production and lower cash production costs at Indonesian coal producers. Revised sales contracts signed at lower ASPs should have commenced in 2Q. The remaining sales, through index-linked contracts or spot, should reflect ongoing weak coal prices. Mitigating this, 2H is usually a period of higher coal production, given the normally drier weather conditions. We also expect production costs to decline on lower oil prices and steps taken by producers to target mining areas with lower strip ratios. We estimate FY12 EBITDA for Adaro, Berau and Bumi Resources to fall by 20-30% y/y, while Indika should report higher adjusted EBITDA on increased dividends from associates.

Liquidity buffer: Nonetheless, we think most issuers have sufficient liquidity to withstand temporary weakness in earnings and cash flow. Adaro, Berau and Indika all have cash balances of over USD400mn. Their ambitious capex budgets could deplete some of this cash, although we believe a significant portion of their capex is deferrable. Only Bumi Resources faces liquidity concerns, in our view. It had cash of USD122mn versus short-term debt of USD260mn at end-2Q12.

Debt concerns at Bumi Resources: Bumi Resources’ high debt leverage and financing costs, and a weak liquidity position make it the most vulnerable to prolonged weakness in coal prices, in our view. The company seems aware of this risk and is considering several debt reduction initiatives, although we think implementation will be challenging. Low commodity prices could hurt its ability to sell a minority stake in its metals subsidiary. The near-term collection of its investments in and loans to related parties is also questionable, as repayments have been consistently delayed. However, near-term default risk is low, in our view. The company has relatively strong financial flexibility given its diverse banking relationships. It may also sell non-core assets (perhaps at a discount) to generate cash.

Investment recommendations Underweight Bumi Resources ‘16/’17 (B1 Stb/BB- Neg). We expect further

deterioration in the issuer’s credit profile in the near term. Earnings will remain under pressure on further ASP weakness. Moreover, the company will likely take on more debt to cover expected cash shortfalls. We estimate its debt/EBITDA will increase to 5.4x in FY12 from 4x in LTM 2Q12. Technicals on the bonds have been relatively strong reflecting the lack of new HY supply in Asia. But we expect them to weaken as investors increasingly focus on the company’s weakening credit metrics and liquidity position.

Erly Witoyo +65 6308 3011

[email protected]


30 August 2012 60

ASIA HIGH GRADE ENERGY

On an acquisitive trend We expect the Asian oil companies to keep their M&A agenda alive as shrinking

domestic reserves and slower production levels encourage them to seek global growth opportunities.

While credit metrics are likely to incrementally deteriorate, we expect the ratings impact to be muted. Most companies have strong financial flexibility, ratings headroom and shown a willingness to raise equity capital when necessary.

Summary of investment view We expect most of the Asian oil and gas companies to remain on an acquisitive footing as they seek to expand their production levels and boost reserves. These companies are well positioned as acquirers, thanks to strong liquidity positions and ample ratings headroom. Additionally, most are state-owned entities, which implies the benefit of extraordinary support, if necessary, from their governments. Given that most transactions would likely be partly funded by debt, we expect the Asian oil and gas industry to be a key source of primary bond issuance over the coming year.

There has been an active M&A scene over the past few months, the biggest deal being that announced by CNOOC. It has proposed to acquire Nexen Inc (Baa3 Neg/BBB- Stb), a Canadian upstream oil and gas company, for USD15.1bn (implied EV of USD17.9bn). This would increase CNOOC’s production level by 20% and expand its proved reserves by 30% to 4.09bn boe. Another Canadian company the subject of acquisition interest is Progress Energy Inc. Petronas has proposed to purchase Progress Energy for CAD5.5bn, paving the way for the Malaysian state-owned company to expand its shale gas assets in Canada. Furthermore, PTT Exploration & Production (PTTEP) will acquire Cove PLC for GBP1.2bn. Cove is a UK-listed upstream oil and gas company which owns an 8.5% stake in sizable natural gas resources offshore Mozambique. Given its lack of financial flexibility, PTTEP plans to fund its capex and acquisition plans with a capital raising of c.GBP2bn, which, if successful, should mitigate its downside ratings risk. Sinopec Corporation has also announced the acquisition of a 49% stake of Talisman’s UK North Sea business for USD1.5bn. Notwithstanding these deals, we think that both PTTEP and Sinopec will remain active M&A participants over the medium-to-long term.

Other potential acquirers are Korea National Oil Corp (KNOC) and Woodside Petroleum. KNOC is targeting a production level of 300,000bbl/day (2011 level: 220,000bbl/day) and it could secure an additional KRW1trn (c.USD880mn) equity injection from the Korean government to support its growth plans (Moody’s, April 2012). With respect to Woodside, management said it is considering potential acquisitions of oil assets in the Gulf of Mexico.


Switch out of POHANG 5.25%’21s (UW) into PTTEPT 5.692% ‘21s (MW): The ratings risk at Posco has escalated while the ratings pressure on PTTEP has receded, albeit this would still depend on the successful execution of its capital increase.

Buy Korea National Oil, KOROIL 3.125% ‘17s (OW): KNOC benefits from strong sovereign support and the potential equity injection from the government to support its growth plans.

Justin Ong +65 6308 2155

[email protected]


30 August 2012 61

ASIA HIGH GRADE UTILITIES

Mixed prospects across the region We expect the Chinese gas utilities companies to remain resilient with solid

operating results, albeit their sizable investment programmes will lead to some deterioration in credit metrics.

In South Korea, cost recovery challenges persist in the utilities sector as tariff increases are not sufficient to cover fuel costs.

Summary of investment view We continue to hold a constructive view on the Chinese gas utilities companies, specifically China Resources Gas (CRG) and Beijing Enterprises Holdings (BEHL). To promote clean energy, the Chinese government targets a doubling of the natural gas utilisation level to 8.3% under the Twelfth Five Year Plan (ends 2015). Substantial investments have been made in developing the natural gas infrastructure – this includes LNG terminals, storage facilities and the pipelines connecting the natural gas reserves in the country’s interior to the population centres. Both CRG and BEHL benefit from a diversified mix of end-users (commercial, industrial and residential) and steady gas supply from upstream providers. We would nonetheless highlight that their credit metrics are likely to weaken over the coming years due to capex and acquisitions, albeit we expect any ratings impact to be mitigated by resilient demand in their end-markets and support from their respective government-linked entities: (1) China Resources Holding, a SOE wholly owned by the China Resources National Corporation, has a 68.5% stake in CRG; and (2) Beijing Enterprises Group (wholly owned by the Beijing municipal government) owns a c.59% stake in BEHL.

We hold a cautious view on Korea Electric Power (KEPCO) given its cost recovery challenges. Its Q2 12 results were weak with a continuation of operating losses, due to high fuel costs and the cost increase in power purchases. Recent tariff hikes have been insufficient for KEPCO to cover higher fuel costs. While KEPCO enjoys the support from the Korean government, tight bond valuations offer little value, in our view. We prefer Korea Hydro & Nuclear (KHNP) as it is largely able to pass any fuel cost increases to KEPCO through the cost-based pool system. Additionally, its nuclear generation has a low fuel cost structure. Away from South Korea, one government-linked utility company that is seeing an improving outlook is Tenaga Nasional (TNB). Thanks to the cost-sharing mechanism between TNB, Petronas and the Malaysian government, TNB has been able to reduce the negative impact from using expensive alternative fuel (oil, coal and distillate). Furthermore, the gas supply for TNB should improve once the new Petronas LNG plant commences operation in August 2012. One major uncertainty, however, is the gas pricing and whether the aggregate supply from Petronas will recover fully to TNB’s daily requirement (1,250mmscfd).


Buy China Resources Gas (OW).

Buy KORELE 3.125% ‘15s (KHNP, MW) and sell KORELE 5.5% ’14s and KORELE 3% ‘15s (KEPCO, UW).

Justin Ong +65 6308 2155

[email protected]


30 August 2012 62



30 August 2012 63

EQUITIES


30 August 2012 64

AMERICAS INTEGRATED OIL

Our favorites are SU and IMO; super majors may underperform other energy names

Our base case scenario is that oil (Brent) will continue to trade within the range of $90-120 per barrel over the next 12 months. We think inland crude (WTI) may temporarily trade at a higher discount to Brent ($25-30 compared to the recent $12-18 range) by the end of 2012 or early 2013, before narrowing to a range of $5-7/bl by the end of next year.

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

Our favorites are Suncor (SU) and Imperial Oil (IMO). We think both companies have a strong financial position combined with solid long term production growth and a natural downstream hedge to U.S. regional crude discounts.

As a relative safe haven during macroeconomic uncertainty earlier this year, we believe the Super Majors will underperform other energy subsectors for the remainder of 2012.

2012 Global Supply, Demand in Balance; Expect Continued Volatility in U.S. Regional Crude Differentials

Despite our concerns about the global economies’ uneven recovery, we think oil price will likely stabilize at their recent level of approximately $110/bl Brent. Reflecting lost production in Iran, Syria and South Sudan, we estimate global spare capacity will remain at 2.0-3.0 mmb/d (million barrels per day), compared to roughly 5.5 mmb/d a year ago. Risk of an event-driven Iranian supply disruption (as opposed to already announced sanctions by the U.S. and Europe) will likely remain a factor for at least the remainder of the year. As a result, absent an unexpected severe double-dip global recession, we expect the oil market will be largely balanced and oil prices (Brent) will remain in the relatively narrow range of $90-120/bl for the rest of the year.

On the other hand, we think the North America regional crude oil differentials will remain extremely volatile. This is a result of the midstream takeaway capacity attempting to meet the rapidly growing crude production through pipeline, unit train, and trucking capacity additions. In light of a likely ongoing elevated differential environment over the next several years, we believe companies with a strong North America integrated business model should fare better than peers.

Finally, we think the major oil companies’ share prices are currently reflecting a long-term oil price deck of $85-90/bl (Brent).

Suncor (SU.TO) SU is currently our favorite name among the Americas-based major oil companies. We like SU for its near term free cash flow generation driven by improved reliability in its core oils sands segment, strong liquids production growth, and advantaged downstream assets.

After several years of poor operating performance in its core oil sands operations, SU gradually improved its reliability in both production volume and upgrader utilization rates. From mid-2010 through the end of 2011, SU’s operated oil sands production averaged close to 330

Paul Y. Cheng, CFA

+1 212 526 1884 [email protected]

BCI, New York

Industry View

POSITIVE

SU

Stock Rating OVERWEIGHT

Price Target CAD 48.00

Price (23-Aug-2012) CAD 31.25

Potential Upside/Downside +54%

mailto:[email protected]�


30 August 2012 65

mb/d (except 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. We believe improved reliability is crucial as SU is in the midst of a multi-year oil sands production growth period, starting with the Firebag-3 project (currently ramping after start-up in 4Q11) and continuing in 2013 and 2018 with Firebag-4 and Firebag-5 start-ups, respectively. We estimate liquids production growth of 5.8% p.a. from 2011-16, with oil sands production increasing at 7.4% p.a. In addition, we think SU cash flow from operations will improve with a shift toward lower cash cost In-Situ production (versus oil sands mining) as the Firebag projects become a greater percentage of total oil sands production. We estimate that unit cash (SG&A + transportation) costs will decline to roughly $38/bl in 2016 from $45/bl in 2011. Finally, the major near term upstream headwind – steeply discounted Canadian crude oil prices – is largely hedged by SU’s downstream segment, where we estimate roughly 65% of the company’s throughput benefits from similar inland U.S. or Canadian discounts.

On the basis of EV/2013 EBIDA, SU is trading at 6.0x compared to the Americas-based major oil companies’ median average of 6.1x and the large-cap Canadian oil & gas companies’ average of 7.1x. From 2006 to 2010, SU traded at a 3.9x premium vs. the integrated oil companies, and 2.5x premium vs. the large-cap Canadian oil producers. Although we do not think the stock will regain its entire prior premium, we do think it should trade at a premium due to its oil sands exposure, and more predictable stronger long-term reserve and production growth profile.

Imperial Oil (IMO.TO) We believe IMO represents the best of ExxonMobil – it shares XOM’s strong financial discipline, robust balance sheet, unparalleled project execution, and R&D capability while enjoying industry leading growth opportunity. We expect the company will grow oil and gas production by nearly 10% p.a. between 2011 and 2016, vs. 0.4% p.a. for ExxonMobil. Given its integrated business model, we also think the company will fare better than its peers under our current outlook for an ongoing elevated North American crude oil differential environment.

We think 1Q12 results highlighted the benefits of an integrated business model, as a decrease in upstream earnings of C$229 million from 4Q11 driven by discounted Canadian crude prices was almost entirely offset by an increase in downstream earnings of C$183 million. Despite extensive 2Q12 downstream operational downtime, we still think an increase in full year 2012 downstream earnings will provide a significant offset to decreased upstream profits. Longer term, we expect peer leading production growth starting late this year with Phase 1 of the company’s Kearl project. In addition, with the recent sanctions of the Nabiye and Kearl expansion projects (projected to come on-stream by late 2015), we think the company is on the verge of a major growth trend that could last through the next two decades. We estimate the company’s total net oil sands production will increase to approximately 370 mb/d in 2016, up from 200 mb/d in 2011. We forecast total liquids production will increase at over 12% per year through 2016 compared to expected Super Major liquids growth of 1.1% and total Major Oil growth of 5.0% per year.

From a valuation perspective, we think Imperial’s premium multiple is justified by the company’s industry leading profitability and growth potential. Indeed, the premium has narrowed to 2.4x vs. its 30-month historical premium of 3.6x over the major oil group average. In comparison, Suncor traded at a 5.0-6.0x premium during the late 90’s as it began a similar period of long-term production growth. Imperial also appears relatively undervalued compared to its parent ExxonMobil, currently trading at 0.2x, below ExxonMobil on an EV/2013 EBIDA basis despite its significantly higher production growth profile.

IMO CT / IMO.TO



Price (23-Aug-2012) CAD 46.06



30 August 2012 66

EUROPEAN INTEGRATED OIL

A question of cash Our favoured companies remain those with leverage to oil prices, and with

differentiated growth or exploration profiles. Our current favourites include BG (PT 1800p) and Galp (PT, EUR18)

Cash flow growth alone is not enough to secure improved returns – we see declining cash returns in the next four years

Little differentiation between the large cap oils

Clocking up cash flow From mid-cycle returns to production targets, the large-cap oil companies have a relatively poor track record of hitting targets. Indeed, for a number of years (2007-2010) the companies nearly abandoned targets all together. The European majors are now focusing on cash flow growth, something that should be expected given the investment going into the ground. However, increasing cash flow alone does not imply good capital efficiency or improving returns. Our analysis shows that although absolute sector cash flow rises by 26% to 2016E, cash returns on investment fall from 10.7% to 8.6%. This projected fall in cash returns over the next five years from the integrated oil companies is one of the main reasons why we do not expect to see a sector re-rating.

Our forecasts show some significant improvements in cash flow – on average the group is up 26% in absolute terms by 2016 from 2011 levels. Throughout this section we use cash flow prior to any adjustments for working capital, to give a clearer idea of the cash flow generated by the underlying businesses. The chart below shows the moves in this cash flow measure 2008-2011 and from 2012-2016 that we forecast.

Figure 1: Cash flow movements

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0

50

100

150

BG GALP BP TOT ENI REP OMV STL RDS

% 2008-2011 2012-2016

Source: Barclays Research (Data shows cash flow from operations, pre working capital movements)

Lydia Rainforth +44 (0)20 3134 6669

[email protected] Barclays, London

Rahim Karim

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

Barclays, London

Industry View

NEUTRAL


30 August 2012 67

Key takeaways:

We expect BG to generate the biggest improvement in cash flow, reflecting the start-up of its QCLNG project in Australia and the ramp-up in Brazil. Galp also benefits from the ramp-up in BM-S-11 and completion of the downstream project.

BP’s movements are impacted by payments into the escrow account, which we have taken at the operational level and should finish in 2012. Excluding this we estimate that cash flow would be down 16% 2008-2011 and up 24% to 2016.

Total’s cash flow growth has been greater than Shell’s since 2008 and we expect more rapid growth in the next five years.

Eni has proved more cyclical to the downturn in the past three years from its European exposure than the rest of the group.

Statoil’s drive to meet its 2020 production target and its considerable exploration success do not feed through to improvements in cash flow in our forecast period.

The pattern in cash flow movements is different to that which we expect from capex, which we show in the chart below.

Figure 2: Capex continues to grow

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ENI GALP TOT REP BP STL RDS OMV BG

% 2008-2011 2012-2016


Key takeaways:

We expect total capex increases of $31bn in 2016 compared to 2011 or 24% higher.

In order to generate better-than-average cash flow, BG has had to grow capex more rapidly than average. This comes to an end in the coming years and we actually see capex levels begin to decline in 2013 before ramping up again in 2016.

Total continues to grow capex on our forecast period, implying little improvement in free cash generation.

GALP continues to invest to grow, but cash flow rises more rapidly than capex.

Despite plans to reinvigorate their respective upstream businesses, on an organic basis we see little additional spending from BP and OMV.


30 August 2012 68

The issue then becomes whether there is a significant difference in capital efficiency between the companies. There are a number of possible ways to address this, including production growth and returns. Eventually we would expect better capital efficiency to show itself through better returns. However the significant write-downs from some of the group in the last three years suggest to us that a cash flow-based measure may be more appropriate.

For these purposes we have focused on calculating a corporate internal rate of return (CIRR). We define this as the internal rate of return implied by the annual cash flow the company generates, the initial investment and the total duration of the assets. In effect this treats the whole company as if it were a single project.

For the calculation we use post tax cash flow, pre interest and pre working capital moves – essentially EBIDA. For asset life we have calculated by dividing the assets at cost by depreciation rather than using the reserve life given differing scales of downstream businesses and differing levels of probable reserves across the companies.

Below we present our estimates of corporate IRRs, compare these to RoACE and examine how we expect the return on future investment to evolve. The chart below shows the difference between the two. Overall we believe that, as a measure of the success of company management our CIRR cash-based measure is the most appropriate.

We conclude from this analysis that there is little to choose between the big cap oils. Of the Major Oil companies in Europe, Shell offers the highest cash returns, but a 1% spread covers Shell, Total and BP. Adjusting for the Macondo payments we estimate that BP’s CIRR falls c4% 2011-2016, the largest fall of the group on our estimates.

Figure 3: Evolution of CIRR 2011-2016

0

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4

6

8

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12

14

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18

BP RDS TOT BG ENI OMV GALP REP STL

% RoACE CIRR


In previous work “Valuation 2011: Growth matters” we showed the importance of growth to share price performance over many years. As the chart below shows, those companies that we see generating higher production growth – GALP, BG and Repsol – are also those showing the biggest improvement in cash returns.

https://live.barcap.com/go/publications/email?FC1740707&m=1311228029823&w=H4xLh_x8Wyt8aqzAJXEvMtKpTA9LRl1o_mTJrqVdzoDu3yyvGLvEzrl-hWvzEpaF�


30 August 2012 69

Figure 4: Evolution of returns 2011-2016

-6.0

-4.0

-2.0

0.0

2.0

4.0

GALP BG REP ENI OMV RDS TOT STL BP

%

Source: Barclays Research. Note BP data is adjusted for Macondo payments.

GALP – Exploration to provide the catalyst 1H 2012 has seen significant progress for GALP. The company closed its transaction with Sinopec in Brazil, taking gearing to just 18% from 119% at the end of the year. In Mozambique it has added over 4.7tcf of gas resources and in Brazil, the first FPSO for the Lula field is now at full capacity. 2H 2012 promises to be better. In addition to the start-up of the upgraded Sines refinery GALP will participate in several high-impact exploration wells and we are still awaiting resource estimates for the Carcara well. In our view, the initial well results suggest that the BM-S-8 area will prove to be commercial. In addition, a second well on the Jupiter field, also in Brazil, is due to be drilled. If successful it would not only prove up an additional 1bn boe of resources but also materially increase the probability of fast-tracking the development of the existing 3bn boe of resources. There is also follow-up work in Area 4 in Mozambique and GALP will also be testing 1.3bn boe of potential gas resources via an early stage exploration opportunity in onshore Portugal. We expect GALP to deliver one of the best production and earnings growth stories in the European oil and gas industry over the next decade and we continue to see significant potential upside to our NAV-based price target of EUR 18/share and maintain our Overweight recommendation.

BG Group – Fostering confidence in Brazil Having reached an all time high relative to the sector in April, BG’s shares have underperformed its peers by 9%, as concerns intensified over the execution of its long term growth profile. This unease has been precipitated by the negative headlines coming from Brazil and Australia, as well as growing concerns over Sir Frank Chapman’s succession. With the details within Petrobras’ strategic update supportive of our current production profile and valuation assessment, and the capex increases in Australia reflected in estimates, we believe BG offers long-term investors a very attractive investment proposition at current levels. We also believe that despite the small downgrade to 2012 volume expectations, the update from management accompanying the figures will have gone a long way to reaffirming confidence in the longer-term investment case. BG offers 39% potential upside to our price target of 1800p and remains a key Overweight.

GALP PL / GALP.LS


Price Target EUR 18.00

Price (23-Aug-2012) EUR 11.71


BG/ LN / BG.L


Price Target GBP 18.00

Price (23-Aug-2012) GBP 12.98



30 August 2012 70

EUROPEAN INTEGRATED OIL

Sasol: shale gas impacts South African oil & gas Our Sasol call: given macro and specifically rand oil price uncertainty, we believe the Sasol share price is unlikely to outperform unless significant project progress and/or cost improvements are achieved – which we do not expect in the short term. The recent shale gas impairment was not expected, although it is line with recent industry impairments, and is a further headwind for Sasol. We have an EW rating with a ZAR375 price target.

Sasol’s share price has lagged the rand oil price in recent weeks – reflecting macro uncertainty and fundamental headwinds, including a shale gas write-down.

We calculate Canadian gas impairment and depreciation relates to around R3.50/share. Sasol did not highlight any need for shale gas impairments at our CFO newsletter investor lunch in Cape Town at end June 2012 and this was not expected - it is, however, in line with recent industry impairments, eg, at BHP Billiton.

We calculate shale gas GTL economics are attractive at a US$80/bl oil price and US$4.50 gas price.

Rand oil price dynamics The correlation between the Sasol share price and the Brent oil price denominated in rand is >0.9 over the last 10 years. Sasol’s share price has lagged the rand oil price in recent weeks – reflecting macro uncertainty and fundamental headwinds, including the shale gas write-down in our view.

Figure 1: Sasol share price versus rand oil price: lagging

0.80.9

1.01.11.2

1.31.4

1.51.6

Jan-11

Feb-1

1

Mar-11

Apr-11

May-11

Jun-11

Aug-11

Sep-11

Oct-11

Nov-11

Dec-11

Jan-12

Feb-1

2

Apr-12

May-12

Jun-12

Jul-12

Sasol share price, rebased Jan 2011 Rand Brent oil price, rebased Jan 2011

Source: Absa Capital, August 2012

Shale gas: the background

In December 2010, Sasol signed an agreement with Talisman Energy to acquire a 50% stake in its Farrell Creek shale gas assets in the Montney basin of British Columbia and Alberta. The C$1,025mn (R6,950mn) acquisition included 53,000 acres with an estimated contingent resource of 9,6 trillion cubic feet (tcf) of gas. In March 2011, Sasol agreed with

Caroline Learmonth +27 11 895 6080

[email protected]

Absa Capital, Johannesburg

Industry View

NEUTRAL



30 August 2012 71

Talisman to acquire 50% in its Cypress A shale gas asset. This C$1,050mn (R7,413mn) acquisition is also located in the Montney Basin. The transaction covers over 63,000 acres of land with an estimated contingent resource of 11.2 tcf.

Shale gas: recent updates We calculate that Canadian gas impairment and depreciation relates to around R3.50/share, putting the mid-point of guidance excluding these one-offs at R45.5 versus Bloomberg consensus prior to the update of R47.67 and our forecast of R51.77 - a disappointment. Sasol did not highlight any need for shale gas impairments at our CFO newsletter investor lunch in Cape Town at end June 2012 and this was not expected - it is, however, in line with recent industry impairments, eg, at BHP Billiton.

Canadian shale gas assets are "under pressure" - this resulted in a "substantial loss" in the year to date. The year-to-date output for the assets on 31 March 2012 was 11.1 billion standard cubic feet (bscf) (100% gross), as we expected. The JV with Talisman agreed to reduce the number of active rigs to four for the first half CY2012 and to three rigs from August 2012, in response to the depressed gas market. No detail was given on the impact of reduced capex on Sasol's buy-in to the JVs with Talisman.

Sasol and Talisman planned to continue shale drilling until end 2012 and will then reconsider how to proceed. Sasol notes a variable cost of around US$1.80. Talisman has previously stated a US$4.50 gas price enables it to meet its investment hurdle rate. Talisman/Sasol are now also investigating the possibility of liquids production from the shale fields.

Sasol expects an increased understanding of shale geology and flow rates/declines as more drilling is undertaken. In general we believe this is still an area of uncertainty for at least the next 12-18 months. Sasol also notes it has a conservative shale depreciation policy (calculated according to well costs and proved developed reserves). Sasol's depreciation rate may therefore theoretically decrease once further detailed work has been completed.

Shale gas economics

Figure 2: Shale gas GTL economics

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1015

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Gas price (US$/mmbtu)

IRR (%) at US$80/bl oil price IRR (%) at US$90/bl oil price Hurdle rate

Source: Absa Capital, August 2012

Sasol reports FY12 results to end June 2012 on 10 September

2012 and has guided HEPS to increase by 20-30%

Sasol is reviewing the results of the Canada GTL feasibility study

- Talisman has decided not to exercise its right to participate in

the Front End Engineering and Design phase


30 August 2012 72

ASIA EX-JAPAN OIL & GAS

Preference for leverage to the upstream and capex cycle

CNOOC (0083.HK, OW, PT HK$21) remains our top pick: Our stock preferences focus on companies with an upstream bias which are also oil price leveraged. We think CNOOC offers good value and returns with its high-margin domestic barrels likely to drive 4% pa production growth over the medium term. The company’s proposed acquisition of Nexen is likely to sustain growth toward the end of this decade.

We see Sembcorp Marine (SCMN.SI, OW, PT S$7) and to a lesser extent Keppel Corp (KPLM.SI, EW, PT S$13.3) as offering good value with their valuations not yet fully reflecting the peak cycle for oil spending. These companies are also delivering sector-leading returns and dividend yields relative to regional peers and complement our top picks in Barclays Research’s extensive global oil services coverage. They are geared to the oil capex cycle rather than to commodity shipping, with strong balance sheets providing financial flexibility to expand organically while sustaining dividends in the medium term.

Upstream focus, high-margin Chinese barrels Our investment preference for our Chinese Oil & Gas companies remains upstream focused, relative to the downstream (Figure 1). Despite a lower level of production growth in the medium term – our covered Chinese Oil & Gas companies are likely to deliver c3% pa production growth 2011-16E, lower than the 2006-10 average of 6% pa – upstream barrels remain high-margin relative to the industry (Figure 2). This reflects China’s less progressive fiscal regime relative to larger resource-rich countries, a zero-cost exploration phase allowing farm-in to foreign-operated projects and shallow water developments. It also relates to more prudent financial discipline, particularly via offshore shared services and materials procurement for CNOOC relative to its local peers. With upstream production in China largely not regulated (except onshore pipeline natural gas), we see more upstream biased companies likely to capture some of the high oil price we expect in the medium term.

Scott Darling +852 2903 3998

[email protected] Barclays Bank, Hong Kong

Clement Chen

+852 2903 2498 [email protected]

Barclays Bank, Hong Kong

Rita Wu +852 2903 4262


Figure 1: Upstream leverage Figure 2: High-margin Chinese barrels

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Industry View

POSITIVE


30 August 2012 73

Natural gas deficit accelerating progress in non-conventionals China has stated its intention to increase natural gas demand to 10% by 2020 within the country’s energy mix (currently c5%). The government has already stated its consumer priority and pricing within the main segments for natural gas demand, with support for residential and power users, which represent c30% of domestic consumption. Historically low natural gas pricing in China has led to greater reliance on natural gas imports (pipeline or LNG), which has also acted as a strategic policy tool to diversify supplies (and perhaps facilitate inter-government pricing negotiations). However, this has led to a period of underinvestment in domestic natural gas developments despite an existing and relatively untapped resource base1, excluding the potential in shale gas or other non-conventional hydrocarbons).2 Domestic demand growth has averaged 16% pa since 2000 and a government target for 240bcm in 2015, implying 15% pa growth which looks increasingly achievable should China meet or exceed power capacity targets.3 As such, the country’s natural gas supply/demand balance looks very tight in the medium term, with some risks to supply owing to the flexible nature of natural gas imports (Figure 3).

Figure 3: Chinese natural gas supply/demand

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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)

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Gradual natural gas price liberalisation We see gradual natural gas pricing reform in China with the eventual development of a provincial natural gas grid structure in the medium term. However, the timing and nature of domestic natural gas pricing reform (i.e. a market-based approach linked to oil products such as in continental Europe or a hub-based supply/demand driven market such as in the US) has yet to be outlined by the government, but recent policy changes suggest a market-based approach. For example, the NDRC announced in December 2011, a new city-gate gas pricing formula that links gas to imported fuel oil (60%) and LPG (40%) applicable to domestic onshore and pipeline imported gas sold through West-East Pipeline Two in Guangdong Province and Guangxi Autonomous Region, an area served mainly by LNG imports. With increased dependency on higher priced pipeline and LNG gas imports, assuming our oil price outlook together with a supply constrained gas market with strong

1 China’s conventional natural gas proven life of c.29 years relative to what the market may perceive as rich natural gas countries such as Norway and Egypt at c.20 and 35 years respectively according to the BP Statistical Review of World Energy. 2 See Barclays Commodities research, China: the next big shale story? 16 November 2010. 3 See Barclays Research, China Power Equipment, Power up for the long ride, 29 November 2011

883 HK / 0883.HK


Price Target HKD 21.00

Price (23-Aug-2012) HKD 14.96


SMM SP / SCMN.SI


Price Target SGD 7.00

Price (23-Aug-2012) SGD 5.06



30 August 2012 74

demand growth, we expect higher average natural gas prices in the medium term in China. Reform in natural gas pricing is likely to close the price gap between domestic wellhead prices for China’s main producers, such as PetroChina and Sinopec and imports.

Fuel price reform in China – a 2013 event? With Brent having reached US$90/bl in late June and inflation in China easing, we would have thought that the Chinese government would have used this window of opportunity to finally reform fuel pricing in the country. We believe concerns around China's economic growth outlook and a recovery in oil prices may have put reform of the country's domestic fuel pricing policy at risk for this year (Barclays’ Economics team recently revised down its China GDP growth forecast, see China: We lower our 2012 GDP forecast to 7.9% from 8.1%, but still expect a H2 recovery, 9 August 2012). With no sign of the State Council announcing partial reforms, the near-term outlook for domestic refiners looks challenging. The proposed new mechanism under consideration is below, but this looks increasingly like being implemented after China’s Premiership change and possibly in 2013:

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%).

Positive on Singapore rig builders

We see Singapore rig-builders as offering attractive investment opportunities within our Asia ex-Japan Oil & Gas sector. These companies demonstrate strong operational efficiencies and project management which has seen them evolve to become industry leaders in the jackup and semisubmersible segments. This is reflected in these companies’ higher operating margins and returns relative to those of their regional peers (Figure 4-5). The Singapore rig-builders’ low gearing (or net cash) positions also provides financial flexibility to grow organically or sustain dividends. These companies offer the highest dividend yields (c5% in 2012) relative to its regional peers and Global Oil companies, on our estimates, which we expect to be maintained in the medium term (Figure 6-7). We see Sembcorp Marine (SCMN.SI, OW, PT S$7) and to a lesser extent Keppel Corp (KPLM.SI, EW, PT S$13.3) as key beneficiaries to the following themes likely to support their advantaged position within the rig building industry, namely:

Structural shift towards deepwater: With 50% of the new oil and gas discoveries made in the past decade offshore, primarily in deepwater, there is demand for oil service equipment and rigs suitable for these environments.

Upgrading ageing rig fleets: With more than 30% of the current global jackup fleet close to retirement age, which is likely to rise to more than 50% in 2015, operators will likely be driven to replace old rigs or re-tool existing ones, supporting further rig orders.

Higher offshore day rates: A rise in demand for deepwater rigs has been reflected in day rates with rigs capable of drilling at greater depths commanding greater premiums. The rise in deepwater day rates has indirectly encouraged rig owners and operators to increase their deepwater fleet capabilities, translating into more orders.

No fuel price reform may extend losses for Chinese refiners this

year, with Sinopec the most exposed

Margins for the Singapore group have been sustained around

‘mid-teens’, while those of regional peers have fallen to

below ‘double-digit’

KEP SP / KPLM.SI

Stock Rating EQUAL WEIGHT

Price Target SGD 13.30

Price (23-Aug-2012) SGD 11.58


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30 August 2012 75

Figure 4: Large rig building bias Figure 5: Highest returns in the sector

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Figure 6: Financial flexibility to deliver organic growth Figure 7: Strong dividend yield outlook

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30 August 2012 76

US EXPLORATION AND PRODUCTION

Oil-shale drilling replacing gas-shale drilling as the focus

Gas production growth has decelerated as the impact of $2-3 gas prices has taken hold and activity has moderated. The learning curve and the attractiveness of drilling NGL-rich wells, however, have deeply reduced gas supply costs. We believe gas prices of no more than $4/MMbtu are needed to establish long-term equilibrium.

We continue to favor oil-oriented producers and recommend investors avoid most gas producers. Our top picks in the large-cap group are still EOG Resources (EOG) and Noble Energy (NBL). In the mid-cap space we prefer Plains Exploration and Production (PXP) and Whiting Petroleum (WLL).

Drilling activity shifting away from dry gas basins Drilling activity continues to shift toward oil producers and more liquids rich plays as a result of ongoing lackluster natural gas prices and robust oil prices. NGL prices have softened this year given surging supply along with weak heating demand last winter. However, we do not believe longer term program decisions will be significantly impacted by current weak NGL prices as longer term prices – except for ethane – are likely to recover to historical relationships with crude oil/gasoline.

Oil plays such as the Permian and the Bakken, and liquids rich plays such as the Eagleford and the Niobrara are capturing a rising share of drilling expenditures, while the search for emerging shales remains intense. Drilling in dry gas areas continue to fall. Haynesville drilling and production probably has the furthest to fall of any dry gas shale play, and the coming decline in Haynesville production has given some hope to the bulls. Slowing activity in dry gas areas of the Marcellus and the Barnett as well as Fayetteville will likely contribute to falling gas volumes later in 2012 and in 2013. We fear that a gas-price rally to over $4 (for forward prices) would lead to a recovery in activity levels and prevent a stronger gas-price rally.

The learning curve has cut gas supply costs; sub-$4/MMbtu may be here to stay We are not among those that assume gas supply costs will exhibit a V-shaped bottom. Mounting gas supply costs have been reversed by unconventional, and especially shale, gas drilling techniques. Controversy still rages as to whether E&P companies can meet growing demand for natural gas with gas prices below $4 and with the sharp reduction in the gas-directed rig count. Recent data has suggested that onshore natural gas production is still near the 4Q11 peaks despite a drop in the gas-directed rig count from more than 900 last year to ~ 500 now. We note that 2011 gas-directed rig counts of ~ 900 along with year-over-year onshore production growth of ~12% implies an equilibrium rig count of as low as 400-500.

Continue to prefer shares of oil-oriented producers; “pure” gas stocks trade at large premiums We estimate that current stock valuations, with the exception of pure play gas names (ECA, SWN and UPL) and RRC, discount commodity prices of roughly $90/bbl WTI and $3.50/MMbtu. EOG Resources and Noble Energy are our top picks for a combination of best value, forward growth and relatively lower risk. We forecast that both NBL and EOG will

Thomas Driscoll +1 212 526 3557

[email protected] BCI, New York

Jeffrey Robertson +1 214 720 9401


Industry View North America Oil & Gas: E&P (Large Cap)

NEUTRAL U.S. Oil & Gas: E&P (Mid-Cap)

POSITIVE


30 August 2012 77

deliver top-tier value growth over the next three years, and that both companies trade at attractive group average multiples on an EV to 2013E cash flow basis. On the mid-cap side, PXP and WLL are our top picks for their leverage to robust oil growth, strong financial positions and attractive valuation relative to peers.

We recommend investors avoid the shares of “pure” gas producers such as ECA, RRC, SWN and UPL. The scarcity premium awarded to gas names, which comprise roughly 10% of the large-cap E&P stock market value, has created a large valuation gap. We estimate that gas prices of more than $5.50/MMbtu are required for ECA, SWN and UPL (all dry gas) to trade at average multiples (using 2013E cash flow), while gas prices in excess of $6/MMbtu would be required for RRC. We recommend investors looking for gas exposure turn to the more-balanced and reasonably priced QEP. On the mid-cap side, we recommend SM for investors seeking exposure to natural gas at a significant valuation discount to peers.

EOG Resources (EOG) The first mover oil-shale advantage is continuing to deliver impressive results for EOG Resources. Development of the company’s very high quality assets is in full swing and well and drilling results continue to surprise to the upside quarter after quarter; the targeted liquids production growth rate for the year was just raised for the third time. EOG has established itself as the dominant operator in the areas where it is active. With early planning, it has managed to avoid major cost creeps as well as logistical, midstream and infrastructure issues that have plagued others. Funding of cap-ex has been a concern for investors but the early conclusion of this year’s $1.2 billion asset divestiture program should alleviate some of these concerns. We estimate that absent a material increase in commodity prices, another $700 million worth of asset sales would be necessary to keep the year-end 2013 debt-to-capital ratio below the company’s self-imposed ceiling of 30%. With EOG’s deep inventory of assets, we do not expect the company will have problems monetizing additional assets. All in, we forecast that EOG will generate top-tier, value-added growth (debt-adjusted) over the 2011-14 period, while the shares trade at a group average multiple.

Figure 1: Highest multiple stocks have lackluster prospects… Figure 2: … they used to have a competitive advantage

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EOG


Price Target USD 138.00

Price (23-Aug-2012) USD 107.01



30 August 2012 78

Noble Energy (NBL) We believe Noble Energy has uniquely positioned itself for years to come through its highly successful exploration program. The company has discovered nearly 2 billion barrels of oil equivalent over the 2006-10 period, securing 85% of its modeled 2020 production. A steep production ramp-up has been in the making for several years now, and 2012 marks the beginning of multi-year debt-adjusted growth in the mid-teens. Two large projects (Galapagos and Aseng) were brought online over the past 7-8 months, adding ~15% to 4Q11 production. The highly economic Niobrara horizontal program has been delivering strong drilling and well results and production is expected to increase at a ~15% annual rate over the next five years. The next generation of high-impact projects (Tamar and Alen) are on budget for first production in 2013. The Marcellus asset, which the company acquired through a JV one year go, is off to a good start – the resource estimate was just raised by 35% to 10 Tcfe due to better well performance. Leviathan (17 tcfe) in Israel, Cyprus (7 tcfe), Diega and Carmen (80-210 mmboe) in West Africa, Gunflint (70-250 mmboe) in the deepwater GOM are some of the more sizable discoveries that will be developed beyond 2015. High impact exploration in core as well as new areas will probably lead to additional discoveries, but even if Noble were to never find another barrel of oil, its 5-10 year future still looks strong. We view the valuation as attractive at 6.0x our 2013 cash flow estimate, the shares trade on par with peers.

Plains Exploration & Production (PXP) We expect continued development of the Eagle Ford Shale to support double-digit production growth through 2014 after which the start-up of the deepwater Lucius project should carry on the positive growth momentum. Strong performance from Eagle Ford Shale, where the company owns approximately 60,000 net acres, has driven better-than-expected oil growth through 1H12 and could provide some upside to management’s current production guidance. Volumes from the play have benefitted from the utilization of pad drilling and improvements to completion methods, which have yielded more prolific wells and some cost savings. The Eagle Ford will be the primary driver of growth over the next couple of years with a more modest contribution from large enhanced oil recovery projects in California. Notably, PXP’s crude from the Eagle Ford and California are priced on Brent-based Indices which currently are at a premium to West Texas Intermediate.

Offshore, PXP has several deepwater Gulf prospects planned through 2014, the most impactful of which could be the Phobos prospect which is scheduled to spud in 4Q12. Exploration success could help extend the company’s growth visibility beyond 2015 when production from Lucius is expected to peak and act as a potential catalyst for shares. The company also has $550 million remaining under its $1 billion share repurchase authorization which management plans to opportunistically implement. PXP currently trades at 5.3x our 2013 pre-interest cash flow estimate compared with a peer average of 5.1x

Whiting Petroleum (WLL) We believe continued drilling success in the Rockies positions WLL to deliver strong oil production and reserve growth over the next several years. Oil accounts for more than 95% of the company’s wellhead revenues. We estimate production could grow more than 20% in 2012, including a 27% increase in oil volumes, primarily underpinned by development programs targeting the Bakken Shale and Three Forks formation. The company has assembled approximately 712,000 net acres in the Williston Basin that it believes are prospective for those plays. Management believes the drilling to date has de-risked a substantial portion of its acreage position with further delineation expected to further add to its future drilling inventory. Outside of the Williston Basin, WLL also has approximately

WLL



Price (23-Aug-2012) USD 43.75


PXP



Price (23-Aug-2012) USD 39.49


NBL



Price (23-Aug-2012) USD 86.60



30 August 2012 79

79,000 net acres in the DJ Basin that are prospective for the Niobrara Shale and 87,000 net acres in West Texas that are prospective for the Bone Spring and Wolfcamp formations. Those plays are still in the early stages of development but could add meaningful oil growth opportunities to supplement that from the core Bakken/Three Forks assets, if successful. WLL currently trades at 4.3x our 2013 pre-interest cash flow estimate compared with a peer average of 5.1x. While greater visibility into the company’s growth outlook has helped to narrow the discount to peers, we believe there is room for the gap to shrink with a longer history of stable growth.


30 August 2012 80

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

Commodity roller coaster ride Canadian commodity prices continue to receive wider differentials (for both oil and

gas) as a function of storage/inventory levels and pipeline/infrastructure limitations. For crude oil, these differentials place an impetus on a west coast pipeline to access Asian markets (i.e., diversify away from U.S. refineries). However, environmental concerns remain major obstacles. On the natural gas side, the push toward LNG continues and seems to enjoy support from most stakeholders and continues apace.

We continue to believe that the Canadian mid-cap E&P space provides an attractive mix of growth and income. The industry offers average production growth of 11% in 2012-13E while providing an average dividend yield of 5.8%. Furthermore, the group provides meaningful (and in many cases dominant) exposure to nearly all of Canada’s major oil and gas resource plays, excluding the oil sands.

Valuations remain high relative to most conventional E&P names, reflecting the attractiveness of the business model and its meaningful income component for yield-oriented investors. Following the recent rally, our target prices imply a one-year total return of just 13. 5%, including an average dividend yield of 5.8%. Our top picks remain biased to the crude oil side for now, including Baytex, Crescent Point and PetroBakken.

Commodity price volatility remains front and centre The Canadian E&P industry remains an important component of the North American energy complex, offering similar resource opportunities and challenges as those in the United States. The continued application of horizontal drilling (with multi-stage fracs) has transformed both oil and natural gas drilling, with companies actively developing plays that had previously been inaccessible. Furthermore, the industry continues to have reasonable access to capital, although activity levels have generally declined this year along with commodity prices (as dictated by both lower rates of return and limited cash flow available for reinvestment).

Pricing for Canadian oil and gas has been impacted by several regional factors. On the oil side, growing Bakken crude oil in the U.S. has displaced Canadian light crudes, while heavy oil has been similarly volatile as strong supply is competing for both pipeline space and access to refineries with heavy capacity. Increasingly, Canadian companies are shipping a portion of their crude oil via rail – the higher costs can be partially (and sometimes more than fully) recovered through the higher prices available by shipping directly to coastal American refineries. More and more, companies accept that rail may be a loss-making proposition, but one that provides important diversification away from western Canadian differentials and thus, plays an important risk management role. On the natural gas side, Canadian pricing remains sluggish owing to the lingering effect of a warm winter (i.e., high storage levels) and reduced demand for export to the U.S., offset by slowing production volumes as producers divert capital away. The basis differential between Canadian and U.S. natural gas is roughly $0.60/mcf today – nearly 50% higher than the long-term average.

Much focus in Canada remains on the country’s ability to export oil and gas to Asian markets, via west coast ports (typically Kitimat). On this front we note that the natural gas pipeline (and proposed LNG facilities) seems to enjoy support from most stakeholders. However, the case is much different on the crude oil side. Both the pipeline (Enbridge’s

Grant Hofer +1 403 592 7460

[email protected] BCC, Toronto

Industry View

POSITIVE


30 August 2012 81

proposed Northern Gateway) and export terminal are facing considerable environmental pushback, particularly in the wake of several recent (generally minor) pipeline spills in North America. Further political tension has arisen given that the benefits of the pipeline accrue to Alberta-based energy companies, while the environmental risk is borne in neighbouring British Columbia. At this point, the economic argument for a western crude oil pipeline is undeniable. However, the war for public and political support remains very much up in the air. Stay tuned.

Mid-cap E&P space – growth and income

We continue to believe that the Canadian mid-cap E&P industry provides a unique mix of growth and income. The sector offers average production growth of 11% in 2012-13E while providing an average dividend yield of 5.8%. Furthermore, the group provides meaningful (and in many cases dominant) exposure to nearly all of Canada’s major oil and gas resource plays (although excluding the oil sands). To be sure, growth/income strategies vary across the space, but we generally find companies to be well-run, with prudent allocation of capital. We also believe that risk levels are lower relative to traditional E&P names, by virtue of dividends (providing support for equity valuations), lower leverage ratios (averaging just 1.8x total debt-to-cash flow in 2013), and meaningful hedging strategies (with an average of 24% hedged this year, before royalties).

In spite of the above-noted positive factors, year-to-date share prices in the group have declined an average of 19% (improving to -12% including Progress’ 67% return following an increased bid from PETRONAS). Much of this weakness has been driven by the pull back in crude oil (including volatile differentials) and natural gas pricing. In some cases, this has created meaningful funding shortfalls prompting several companies to reconsider both capital spending and dividends. While many names have conservatively opted to trim capex (and thus growth), we have also seen significant dividend cuts from two companies (Enerplus and Pengrowth).

Looking ahead, an improved outlook for natural gas (including surprising strength this summer) as well as resurgent crude oil pricing has provided some greater buoyancy to the market. Based on our commodity price outlook, we believe that dividends are well-supported for the group, including average basic payout ratios (i.e., dividends as a percentage of cash flow) of 46% in 2012 and 37% in 2013. Including capital expenditures, total payout ratios are estimated to average 158% in 2012 and 130% in 2013. At these levels, growing cash flows can easily sustain the overspending on the balance sheet, resulting in declining leverage ratios over the period (from 2.0x total debt-to-cash flow at year-end 2012 to 1.8x by year-end 2013).

Valuations remain high relative to most conventional E&P names, reflecting the attractiveness of the business model and its meaningful income component for yield-oriented investors. Based on 2013 metrics, the space currently trades at 6.6x cash flow, or 7.7x EV/DACF. (Note that we do not use earnings for this industry as the data is heavily influenced by accounting treatment of acquisitions, non-cash taxes, etc.) 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. The industry today is trading at a P/NAV ratio of 100% (range: 83% to 115%), which is predicated on long-term commodity price assumptions of US$95/bbl for crude oil and US$4.50/mcf for natural gas.


30 August 2012 82

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

Baytex Energy (OW, $51 PT) – Baytex remains one of our favourite oil weighted names owing to its top tier management team and strong balance sheet (0.9x D/CF), underpinned by a quality heavy oil asset base. We are forecasting annual production growth of 7% in 2012-13, supported by a capital spending budget that represents just 76% of its cash flow each year. This is the strongest in the peer group (which averages 110-120%), and is indicative of the company’s remarkable capital efficiencies, especially given its 87% weighting to crude oil. As a heavy oil producer, the company is exposed to volatile heavy oil differentials. However, employs an extensive hedging strategy to mitigate this exposure, including the utilization of rail shipping to further manage risk. 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). This play is expected to generate meaningful production and reserves growth for many years. Other key assets include North Dakota Bakken and a large inventory of conventional heavy oil assets in Western Canada.

Crescent Point Energy (OW, $46 PT) – Crescent Point is Canada’s premier light oil company, boasting a $14bn market cap that ranks it firmly among Canada’s senior producers, despite it’s smaller production base (year-end production expected to be in excess of 100,000 boe/d, 90% weighted to crude oil). The company provides a very attractive investment profile: 1) its balance sheet is the strongest in the group (1.0x D/CF); 2) it has among the highest netbacks from its light oil-focused assets; 3) it is extensively hedged on the crude oil side (extending into 2016); and 4) it provides conservative guidance (i.e., consistently meets or beats Street expectations). 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. These assets alone offer 10+ years of drilling inventory, providing long-term production and reserves growth. The company offers an attractive dividend yield of 6.7% and production growth averaging 19% in 2012-13 (4% per debt-adjusted share after factoring in its recent financings and acquisitions). The company’s assets offer considerable enhanced oil recovery opportunities, while ongoing operations should support growing value over time as CPG.TO exploits its considerable drilling inventory.

PetroBakken Energy (OW, $15 PT) – PetroBakken remains one of our best value names given its exposure to two of the top light oil resource plays in Western Canada (Bakken and Cardium). Although the company is still working to regain market confidence following operational/balance sheet issues in 2010-11, we believe the story is well positioned today with reasonable leverage ratios (2.2x D/CF) and organic growth expected to average 14% in 2012-13 despite over 4,000 boe/d of asset sales since late 2011. PetroBakken has a focused asset base and its netbacks are among the very best in the group (typically in line with Crescent Point). Corporate production volumes were hampered in 2Q by spring break-up (the seasonal slow period in Canada during the spring melts). However, PetroBakken is targeting growth from 38,000 boe/d in July toward the 52,000-56,000 boe/d range by year-end. This would mimic the impressive growth delivered by the company during the latter half of 2011, and should provide shareholders with catalysts over the balance of the year.

PBN CT / PBN.TO



Price (23-Aug-2012) CAD 13.34


CPG CT / CPG.TO



Price (23-Aug-2012) CAD 41.09


BTE CT / BTE.TO



Price (23-Aug-2012) CAD 47.25



30 August 2012 83

EUROPEAN EXPLORATION & PRODUCTION

Exploring Africa Average potential upside for European E&Ps currently at 40%

Sector trading at marginal discount to Core NAV

Key themes: East Africa exploration, Kurdistan and M&A

East Africa provides transformational opportunities The E&P sector is currently trading with an average potential upside of 40%, which compares favourably to its historic average of 25%. The E&Ps are also trading at a discount albeit marginal of 3% to Core NAV. As a result we believe that M&A activities that pervaded the sector in the last year with the acquisition of Encore Oil, Cove Energy and Nautical Petroleum could continue. Oil Majors and NOC could take advantage of this relatively cheap valuation and pursue more acquisitions. However, we see the company’s exploration portfolio as the critical factor that drives shareholder’s returns. Our preference goes to those companies with a balanced exploration pipeline funded by a reliable cash-flow. Our top picks are therefore Tullow and Afren. We believe they can capitalise on their early entry in East Africa, a region, which recently witnessed a number of major oil and gas discoveries and that could hold a transformation potential for these two companies.

Tullow Oil (OW, PT £19.20) – The most attractive exploration portfolio We believe that Tullow has the most attractive exploration portfolio of its peer group, with a well diversified geological risk across multiple geologies and geographies, and, crucially, with potential to generate material shareholders returns. The company’s recent discovery Ngamia, onshore Kenya, has opened up an entire new oil province that could host more than 10bn bl recoverable (TLW 50%). In our NAV, we carry Tullow’s onshore Kenya assets at 213p risked. However, over time and with more exploration wells drilled, this could move closer to our blue-sky scenario currently at £9.50/sh, which assumes 100% hit rate. In addition, Tullow will soon start a new exploration phase offshore French Guyana, following the 2011 Zaedyus discovery. We believe that Kenya and French Guyana underpin the investment case for the company and could add up to £13/sh to our NAV. In addition, 2013 will see other higher-risk region being targeted, Mauritania and Mozambique that, if successful, could once again prove to be material opportunities for the UK explorer.

Afren (OW, PT 190p) – First oil in Kurdistan plus East Africa upside East Africa also represents a material opportunity for Afren. Over the next 12-18 months, the company is likely to drill three key wells, two offshore and one onshore that if successful could prove to be transformational and could add £1-3/sh net to the company. In the meantime, its producing assets in Nigeria are highly cash-generative and they underpin a Core NAV of 113p/sh. We also estimate Afren to generate a free cash-flow of US$0.4bn in FY12 equivalent of a yield of 19%. This cash will be used to expand its exploration effort in East Africa and progress the development of the Barda Rash field in Kurdistan, which is on track to produce 10-15k boe/d by year. Kurdistan underpins the production growth potential for Afren. If oil export from Kurdistan is resumed, the field could allow the company to production over 100k bl/d by 2017 from a ca 45k boe/d in FY12.

Alessandro Pozzi +44 (0)20 7773 4745


Industry View

POSITIVE

AFR LN / AFRE.L



Price (23-Aug-2012) GBP 1.33


TLW LN / TLW.L



Price (23-Aug-2012) GBP 13.96



30 August 2012 84

ISRAEL OIL & GAS: EXPLORATION & PRODUCTION

Potential farm-in to unlock value With commercial production from the Tamar gas field expected to begin in 2Q12,

finalised supply contracts with the Israel Electric Company and financing now secure, we are positive on the Israeli E&P industry with Ratio and Isramco our top picks.

We see Ratio, which is a pure play on the Leviathan discovery, as set to benefit from the potential farm-in of a strategic partner.

Isramco and the partners in Tamar are completing the development work and are expected to begin commercial production by April 2013.

Outlook for 2013

A farm-in partner for Leviathan may raise the profile of the Israeli E&P industry Leviathan is one of the largest natural gas discoveries globally in the past decade, and commercialising the resource will require the introduction of strategic partners. In its most recent presentation from May, US operator Noble Energy said on its 2Q12 earnings call it was pleased with the interest shown in its Leviathan marketing effort and continues to move toward a new partner announcement by year-end. We recently looked at M&A activity that saw Cove Energy valued at up to c. $5 per barrel of oil equivalent (BoE) in East Africa (see our report), and argued the Eastern Mediterranean may demand similar valuations, which could mean a significant premium to current market values. We feel the market has not yet recognized any of that upside. We expect a partner with mid-stream technical knowledge and marketing abilities who would be able to capitalise on the export potential.

Additional gas resources In addition to the major gas fields, Israel also has several minor fields that are currently under exploration and are altogether estimated to have over 15tcf (2C) of gas, with some fields also targeting for oil. We believe that significant discoveries could be an additional catalyst for the industry.

Deep targets In early May, drilling operations of the deepest oil targets at Leviathan #1 were suspended before the primary targeting layers were reached (middle and lower cretaceous). This was caused by high pressure at the layers that were drilled, and by the mechanical limits of the wellbore. The partners have said they are considering carrying out an additional drill to the deeper layers, via a new rig. However, this might not happen until next year, we believe.

Compelling valuation Our sector trades on an average of 1.3x EV/2 proved and probable +2 contingent resources, vs. European E&P trading on 10.6x EV/2P+2C. We believe the discount comes from both regulatory uncertainty around allowable export limits and the Limited Partnership/General Partnership legal structure. On the other hand, we believe commercial production from Tamar and a potential farm-in partner to the region would significantly increase investor interest and valuations in the sector.

David Kaplan +972 3 623 8747


Tavy Rosner


Barclays, London

Industry View

POSITIVE




30 August 2012 85

Are geopolitical concerns still a reason to stay away? Historically, super-majors have been reluctant to look at Israel for many reasons, including: 1) limited potential resources; 2) limited domestic market opportunity; 3) a natural gas focus; and 4) a challenging geopolitical situation. We believe all of this has changed: 1) the Levant basin is world class, with over 30tcf of gas discovered so far and a full exploration calendar; 2) not only has the domestic opportunity grown but there are also export opportunities; 3) beyond the natural gas discovered, deeper structures are targeting oil; and 4) new governments in North Africa and Iraq have changed the geopolitical paradigm. We believe Israel offers a more stable business environment than do its neighbours and that companies that were reluctant to invest may view the 30-40tcf in the Eastern Mediterranean as a possible addition to a larger asset portfolio.

Our top picks: Ratio and Isramco

Ratio (OW, PT ILS 0.45) We view Ratio as the most levered company to a potential farm-in at Leviathan. Based on Ratio’s 15% working interest in the field and $477m market cap (as of 23 August) we derive an implied field value of $3.4bn or $1.17/boe; which represents a 55% discount to our valuation. We do not believe that Ratio is a potential takeover target; we consider it more likely that candidates in Leviathan’s farm-in will purchase stakes in the asset from each of the partners.

We also view Leviathan deep oil target as a long-term positive for the stock. In early May, the drilling operations of the deepest oil targets were suspended before the primary targeting layers were reached (middle and lower cretaceous). This was caused by high pressure at the layers that were drilled, and by the mechanical limits of the wellbore. The partners said they are considering carrying out an additional drill to the deeper layers, via a new rig. However, we believe this might not happen before the end of 2013 given the lack of available drilling equipment and rigs in the region.

Finally, Ratio has a 100% working interest in Gal, which is located south of Leviathan and is expected to target deep structures. We view Gal as a potential long-term opportunity and a differentiator, as it is one of the few fields that is not part of the Delek/Noble consortium.

Isramco (OW, PT ILS 0.69) We recently upgraded Isramco from UW to OW as we saw near-term catalysts begin to mount. Our former rating was based on our view that Isramco was a pure play on the Tamar reserve; and that was fully priced in, with limited near-term catalysts to drive outperformance.

We believe this has changed as Tamar off-take agreements are now concrete, with the regulator having approved the contracts’ structure. In addition, our Isramco valuation points to 53% potential upside.

In addition, Isramco holds a 39% working interest in Shimshon. The field has been estimated by Netherland Sewell & Associates to have a 2C of 2.3 tcf of gas with a 20% probability. Drilling of the well is expected to be completed in the near future, as technical issues with the borehole forced the operator to delay the exploration. Shimshon is located in Southern Israel and would likely tie back to the Mari-B or Tamar platforms that are situated nearby.

RATIL IT / RATIp.TA


Price Target ILS 0.45

Price (23-Aug-2012) ILS 0.26


ISRAL IT / ISRAp.TA


Price Target ILS 0.69

Price (23-Aug-2012) ILS 0.45



30 August 2012 86

Figure 1: Map of the Israeli gas fields

369

367366365368

361359

360358

347 348348

351

352

375

349

375

350

364

353

370371372373

374

202

280

332

338

357

383

380

378

387388

389

379

335343342

376

203

381

MediterraneanSea

ASHDOD

ASHQELON

TELAVIV

Lease

License

Permit

I/13

I/12

I/7I/8I/10

I/11

331Gal

Leviathan

Tamar

Dalit

Myra Sara

Daniel

Shimshon

Mari and Noa

354

363

362

369

367366365368

361359

360358

347 348348

351

352

375

349

375

350

364

353

370371372373

374

202

280

332

338

357

383

380

378

387388

389

379

335343342

376

203

381

MediterraneanSea

ASHDOD

ASHQELON

TELAVIV

Lease

License

Permit

I/13

I/12

I/7I/8I/10

I/11

331Gal

Leviathan

Tamar

Dalit

Myra Sara

Daniel

Shimshon

Mari and Noa

354

363

362

Source: Israel Ministry of Infrastructures, Barclays Research


30 August 2012 87

US INDEPENDENT REFINERS

New refining Golden Age underway; prefer TSO, VLO, PSX and MPC

We believe the U.S. refining segment will be among the market’s best performing subsectors over the next couple of years and could potentially double from here. We think Tesoro (TSO), Valero (VLO), Marathon Petroleum (MPC) and Phillips 66 (PSX) currently offer the best risk/reward ratios in the industry.

We believe the refining sector is undergoing a 3-phase structural improvement, the benefit to earnings power of which is not fully reflected in the market. As a result, between 2009 and 2014, we estimate the relative structural cost advantage will improve by $8-12 per barrel of throughput for the U.S. inland refiners and $3-5 per barrel for the Gulf Coast operators.

We think sustainability of regional crude price differentials will support higher mid- cycle cash flow and cycle trough earnings power. Adjusting from 2009 cycle trough earnings for our estimated structural crude discounts and major capital projects, we estimate the five major refiners (HFC, MPC, PSX, TSO, and VLO) can easily support a 4% regular dividend yield with only about a 40% payout ratio.

In our view, improved cash return to shareholders coupled with increased representation in the indices, will lead to an expanded shareholder base, which in turn should translate into reduced share price volatility and, more importantly, a potential revaluation of the group.

Basis for the New Refining Golden Age A Three Phase Structural Improvement – We believe the U.S. refining industry has been undergoing a major three-phase, multi-year structural improvement, the return of a new golden age, which has not been fully reflected in the market. Phase 1 has been triggered by the lower North American natural gas price due to the country’s shale gas development in recent years. For every $1/Mcf change in gas price, we estimate the U.S. refining industry’s cash operating cost is impacted by $0.10-0.20/barrel of throughput. Phase 2 has been triggered by the lower North American inland oil prices versus the international markets due to the region’s rapidly rising onshore oil production over the last two years, and the insufficient pipeline takeaway capacity to transport oil from the heartland to the coastal markets. Although we think pipeline development will begin to catch up and could eliminate most of the lower-48 inland transportation bottlenecks by 2014-15, we believe WTI-linked crude prices will remain lower than the coastal market’s respective light oil supply due to the transportation cost shipping oil from north to south. Phase 3 will be triggered when LLS settles into a permanent discount of $3-4/b versus Brent within the next 12–18 months, which would add a new layer of structural input cost advantage. While we think Phases 1 and 2 may already be discounted by the market, we believe Phase 3 – which will impact in excess of 75% of the U.S. refining industry – has not been fully reflected. Accordingly, we believe the U.S. refining segment will be among the market’s best performing subsectors over the next couple of years.

Improved Trough Earnings Power Supports Higher Cash Return – As a result of the aforementioned structural earnings improvement, we believe the independent refiners can support a higher sustainable annual dividend yield of 4% at about 40% of estimated trough earnings power. At our estimated sustainable structural Brent/LLS and LLS/WTI crude

Paul Y. Cheng, CFA +1 212 526 1884


Industry View

POSITIVE



30 August 2012 88

differentials of $3.5 and $6/b, respectively, and adjusted for the contribution of major capital projects, we estimate earnings improvement for the five large refiners from the previous trough of a small loss, to a new trough level of more than $4.00 per share on average.

Potential for Group Revaluation – We think the group could potentially enjoy a revaluation over the next 2-3 years. Long seen as a trading group characterized by high volatility (both in terms of earnings as well as share performance) that was best suited for hedge funds or fast money investments, most investors have historically shied away from the U.S. refiners, particularly given the sector’s small weighting in the benchmark Indices such as the S&P 500 or Russell 1000. However, we think a combination of increased representation in the Indices and improved sustainable earnings and cash flow power could expand the shareholder base, which in turn should translate into reduced share price volatility and, more importantly, a potential revaluation of the group.

Since 2009, independent refineries’ weighting in the S&P 500 Index has tripled from 15 basis (SUN and VLO), to 50 basis (MPC, PSX, TSO and VLO). We also think HollyFrontier (HFC) could be added to the index within the next 12 months, which will increase the group’s weighting to more than 55 basis. In our opinion, portfolio managers who are evaluated based on their relative performance against the index will likely pay more attention to the group in view of its increased impact on the index performance. But more importantly, because of the above mentioned improved free cash flow generation and cash return to shareholder outlook, we believe a 4% regular dividend yield would significantly increase the group’s attractiveness among the long term value investors, particularly in today’s low yield environment. We also think that a higher regular dividend yield will strongly affirm managements’ seriousness in capital discipline and their intention of returning cash to shareholders, as well as their confidence in the companies’ new base earnings power at the trough of the cycle. We believe that recent regular dividend increase announcements from MPC, TSO and VLO were only the first steps and expect the industry will boost their regular dividend payout more aggressively over the next 12–18 months.

Tesoro Petroleum (TSO) TSO remains the favorite among our independent refinery coverage universe. Not only does the company stand to benefit from industry-wide structural improvements, but also company specific operating improvements in its West Coast refining system and major capital projects should significantly enhance the company’s trough earnings power.

TSO stands to benefit from what we believe are sustainable regional crude oil discounts at its niche market inland U.S. refineries, which comprise roughly 20% of total capacity. Specifically, we think the company’s Mandan and Salt Lake City refineries could benefit from crude oil discounts to WTI of $5-8/bl and $6-$7/bl, respectively. Furthermore, at the Anacortes refinery the company currently processes some Canadian light oil and will have the ability to process 50 mb/d (000’s b/d) of Bakken crude by year end via the Anacortes rail project (starting up in December). This will bring total advantaged crude access to over 30% of the total system. In addition to advantaged crude access, we think the company’s improved margin capture rate of the past several years in their core West Coast markets is sustainable but not yet fully reflected in the share price. Between 2006 and 2009, TSO’s California realized margin averaged 108% of Barclays’ representative California margin indicator, or $0.3/b higher than the benchmark, compared to 164%, or $4.5/b higher since 1Q10. Combining our outlook for sustainable crude differentials and the company’s improved capture rate with upcoming major projects, including the Mandan and Salt Lake City refinery expansions as well as the Wilmington Yield Improvement Project, we estimate the company’s new cycle trough earnings power at over $5/share compared to a loss in the 2009 cycle trough.

TSO



Price (23-Aug-2012) USD 38.61



30 August 2012 89

Moreover, we view positively TSO’s recent announcement to acquire BP’s Carson City refinery. However, we haven’t revised our earnings estimate or price target due to uncertainties related to the regulatory approval process. We think the deal will be extremely attractive and could add $5-10/share of asset value if approved with no meaningful restriction. Although recently weak, we think the California refining market’s medium to longer term outlook remains bright, given its high barriers of entry due to its strict product environmental standard and the lack of pipeline capacity to efficiently import product from the Gulf Coast or other U.S. markets. As a result, perhaps contrary to current consensus sentiment, we are encouraged by TSO’s heavy exposure to the CA market.

Valero Energy (VLO) Year to date, VLO has underperformed its independent refiner peers, up 40% compared to the group average of 69%, and gains of 122%, 102%, and 68% for inland market levered Delek US (DK), Western Refining (WNR) and HFC, respectively. We think VLO’s relative underperformance offers an investment opportunity as the company stands to benefit most directly from Phase 3 – a permanent discount of LLS versus Brent, and the only phase yet to play out – a structural improvement in the U.S. refining market.

While we think LLS may begin to trade at a $3-4/bl discount to Brent on a sustainable basis by the end of 2013 (compared to a $3.1/bl premium during 2008–11), we have already begun to see a gradual shift in the pricing relationship. While LLS ended the trading week at a discount to Brent only 11% of the time between 2008 and 2011, in 2012 LLS has ended the week at a discount over 40% of the time. The resulting impact on margins has been clear. In 2012, on days when LLS has traded at a discount to Brent, the LLS 6-3-2-1 indicator margin has averaged $9/bl compared to $5.6/bl when LLS has traded at a premium. In terms of direct exposure to LLS 6-3-2-1, VLO leads its peers with over 55% of total capacity on the Gulf Coast compared to roughly 48% for MPC, 33% for PSX, and no exposure for HFC and TSO.

We think 2013 will be a transition year for VLO as completion of the Port Arthur and St. Charles hydrocracker projects will both boost cash flow (total estimated EBTIDA is $900 million) and reduce capex by over $1.0 billion. Combined with our expectation for a discount of LLS versus Brent, VLO’s free cash flow generation will be substantially higher by the end of next year. Given our expectation for improved cash flow generation, we are encouraged by recent announcements to increase the regular dividend by 17.5% and spin-off the company’s retail business, both of which reinforce management’s commitment to unlocking value and returning cash to shareholders.

On a valuation basis, VLO is trading at just $580 EV/daily barrel of complexity compared to the group average of $852/daily barrel of complexity. On an absolute basis, VLO’s current valuation represents 31% of estimated replacement cost compared to VLO and the group’s average of and 53% and 63% during the previous cycle peak in 2007.

VLO



Price (23-Aug-2012) USD 29.21



30 August 2012 90

EUROPE INDEPENDENT REFINERS

Still characterised by overcapacity Europe the disadvantaged market

Higher margins have not translated t o higher earnings given maintenance

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

Europe still challenged In contrast to the US refiners, the European refiners are struggling with overcapacity, lacklustre demand and a higher-than-average cost base. In particular, the European refiners use between 5-10% of crude processed to generate energy to run a refinery. At $100/bl this alone represents a $4-8/bl cost disadvantage. When combined with continued weak demand and new capacity being built in Asia and the Middle East we expect further capacity to close over the coming years. The listed European companies represent some of the best-in-class refineries in Europe, but are still likely to lag behind their US competitors on an earnings per barrel and returns basis. It is also notable that during 2Q 2012, with indicator margins at nearly four-year high points, the two most liquidly traded refiners – Neste and Saras – were unable to capture the benefit owing to their own maintenance.

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.

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.

Lydia Rainforth +44 (0)20 3134 6669


Industry View

NEGATIVE

MOH GA / MORr.AT



Price (23-Aug-2012) EUR 4.87


NES1V FH / NES1V.HE



Price (23-Aug-2012) EUR 8.41



30 August 2012 91

Figure 1: Crude costs as a percentage of throughput

0

2

4

6

8

10

12

14

PKN MOL OMV LOT CEP SRS HEP NEST ERG ORL MOH

%

Source: Company data, Barclays Research


30 August 2012 92

US OIL SERVICES AND DRILLING

The offshore and international cycles gain momentum

We recently reshuffled our top picks ahead of the Barclays CEO Energy Conference.

The themes of earnings season were clear: the offshore and international cycles are strong; North America is choppy and the group remains under-owned. Institutional money began to re-enter the group as the earnings season progressed.

The outlook for international oil service (particularly offshore) remains bright. We expect North American-levered names to continue to face headwinds in 2H12.

The battle for ultra-deepwater rig availability has begun.

Positioning into the Barclays CEO Energy Conference

With earnings season finally over and the August lull underway, we updated our key recommendations going into the fall and especially in front of the Barclays CEO Energy Conference, which we believe will be a catalyst for the group to continue to rally in early September. The Barclays Conference should once again be one of the largest and best attended Energy-focused conferences of the year. For the first time in several months we believe there is real buying in the group, mostly focused on quality, larger cap stocks. We think this is the beginning of a trend, and expect institutional capital to increasingly flow back into the group as we move into the fall.

Divergence in Fundamentals is Clear; Stock Performance to Follow

Despite somewhat markedly different outlooks, the international and offshore focused stocks have performed only modestly better than the North American-focused names since the June low for the OSX. The large cap diversifieds are up 25%, the capital equipment companies have risen 32%, and the offshore drillers have rallied 26%. However, the NAM-focused names have also rallied off the bottom, with the land drillers up 24% and the well servicing companies increasing by 28.5%. This compares to an 11% move in the S&P 500 since June 26. We expect a much greater divergence in performance over the next two quarters as NAM conditions likely worsen and international and offshore fundamentals improve further. We attribute the move in international/offshore-related stocks to real buying, while the move in NAM-oriented names was driven primarily by short-covering, in our view. As a result, despite the cheap valuations for NAM-leveraged companies, we prefer the stocks with strong leverage to the international and offshore upcycles. Our top five in order are: Halliburton, National Oilwell Varco, Transocean, Oil States and Lufkin.

International Upcycle Intact; Big 4 Post Strong 2Q Volume Growth The outlook for international oil service (particularly offshore) remains bright. The “Big Four” turned in strong sequential growth in international volumes (+11% on average), and the companies’ tone appear incrementally more bullish as 2012 unfolds. Halliburton turned in the strongest top-line growth performance for 2Q (+15% sequentially), with Weatherford (+14%) close behind. Schlumberger and Baker Hughes posted +9% and +6%, respectively. We expect volumes to be up double digits relative to 2011 levels, consistent with our mid-year update to our E&P Spending Survey, with activity particularly strong in Brazil, Colombia,

James West +1 212 526 8796


Industry View

POSITIVE

HAL



Price (23-Aug-2012) USD 34.15


NOV



Price (23-Aug-2012) USD 77.32




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30 August 2012 93

Argentina, Russia and the Middle East, including Saudi Arabia, Kuwait and Iraq. Pricing power has taken hold in certain markets and product lines, but remains limited overall. Service capacity continued to tighten in 2Q and Halliburton reiterated Schlumberger’s call for further international pricing increases.

Figure 1: Big Four International Service Revenues and Sequential Growth Rates

$4,000

$6,000

$8,000

$10,000

$12,000

$14,000

$16,000

1Q08 3Q08 1Q09 3Q09 1Q10 3Q10 1Q11 3Q11 1Q12-15%

-10%

-5%

0%

5%

10%

15%

20%International Revenues

Sequential Growth Rates

Note: $ in millions, Big Four includes BHI, HAL, SLB and WFT. Source: Company data, Barclays Research

Offshore Drillers: The Battle for Availability has Begun

The battle to secure ultra-deepwater began with a flurry of awards over the past month, starting with Noble Corp’s award for the Noble Bob Douglas (12,000’ DP) from Anadarko in the U.S. GOM in mid-July. Since that time, Seadrill has secured awards for three ultra-deepwater units (including two newbuilds). Transocean, Stena, and Petroserv also received long-term contracts, and most notably, Rowan secured a contract for its first of three drillships under construction. Dayrates for these jobs have largely been $590k-600k, near all-time highs and off the $400k-450k post-Macondo lows. Bullish commentary from the deepwater drillers on earnings conference calls depicted a sold-out 2012 and an

Figure 2: Ultra-Deepwater Dayrates (7,500’ and above)

$300,000

$350,000

$400,000

$450,000

$500,000

$550,000

$600,000

$650,000

Apr-10 Jul-10 Nov-10 Feb-11 May-11 Sep-11 Dec-11 Mar-12 Jun-12

There have been a series of awards around the $600k dayrate range recently

Source: IHS-Petrodata







30 August 2012 94

increasingly supply-constrained 2013 with nearly all units spoken for. We expect additional awards in the coming months from numerous majors and large independents and note that market reports indicate more multi-rig packages are likely as operators look to standardize supply chains. We view this as positive for contract drillers with multiple UDW units available through 2015, including RDC, NE, ESV, DO, and SDRL.

North American Land Drillers to Face Headwinds in 2H12

Despite reasonably strong quarterly reports from the land drillers (HP and PTEN posted solid quarterly results while NBR’s results were mostly in line following the company’s preannouncement), it is clear that the current environment in North America is becoming a challenging one for the onshore drillers. So far, contract drilling operations have been rather resilient given the circumstances. It has been some of the drillers’ ancillary product lines (e.g., pressure pumping) that have caused greater disruption to their growth and profitability, and we expect further declines in consensus estimates for 2012 and 2013. International onshore drilling, however, continues to exhibit strong growth, which should mitigate some of the NAM challenges for Nabors and H&P in the second half of this year.

Figure 3: Land Driller Consensus Estimate Revisions

$3.20

$3.40

$3.60

$3.80

$4.00

$4.20

$4.40

Jan-12 Feb-12 Mar-12 Apr-12 May-12 Jun-12 Jul-12 Aug-12

2012 Average 2013 Average

Note: Estimates are for NBR and PTEN. Source: FactSet

U.S. Rigs Should Rebuild Again in 2013 after a 2H12 Slide We expect the U.S. rig count to slide somewhat through the balance of 2012 and then rebuild beginning in 2013, although perhaps at a somewhat slower pace than we previously expected. The summer saw a continued shift in rig activity away from gas and toward oily basins. The U.S. natural gas rig count has fallen by 325 rigs, or 40% since the start of 2012, somewhat outpacing the oil rig count increase of 232 rigs or 19% (the net result has been a 5% decline in the total U.S. rig count). Despite the drop in NGL prices in the last few months, we expect E&P companies to largely continue implementing their spending plans for 2012; however, domestic spending for 2013 remains more uncertain. Although the rig count may moderate somewhat as companies increase efficiencies while overall well counts could stay flat.

Without a clear catalyst to move the U.S. rig count higher before 2013, we expect NAM-levered

names to continue to face headwinds in 2H12.

Additions to the U.S. oil rig count have mostly offset dry gas rig

losses in 2012.


30 August 2012 95

Figure 4: U.S. Rig Count by Type, 2010-Present Figure 5: U.S. Land Rig Count July 2011-Present

400

600

800

1,000

1,200

1,400

1,600

Jan-10 Jul-10 Jan-11 Jul-11 Jan-12 Jul-1

U.S. Rigs Drilling for OilU.S. Rigs Drilling for Natural Gas

77%

70%

52%38%

26%20%17%17%14%14%15%17%19%22%

23%

30%

48%

62%74%

80%83%83%

86%86%85%

83%81%78%

0%

20%

40%

60%

80%

100%

2000

A

2001

A

2002

A

2003

A

2004

A

2005

A

2006

A

2007

A

2008

A

2009

A

2010

A

2011

A

2012

E

2013

E

Oil Natural Gas

Source: Baker Hughes Source: Baker Hughes


30 August 2012 96

EUROPEAN OIL SERVICES AND DRILLING

Entering the better times Energy spending cycle continuing

Pricing returning to the industry and backlogs beginning to grow

Attractive valuation: trading below 10-year average PE, despite being in a multi-year up-cycle

Cycle continues to strengthen The spending cycle in the oil industry is well under way. After a surprising increase in capex from the oil companies of 22% in 2011, our latest update of our bi-annual Spending Survey shows an expectation of further growth of 11% in 2012. We believe that this is the start of a multi-year spend, as new discoveries made over recent years unlock new plays across the globe.

From a European perspective, most companies are 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 and are starting to expand, the start of earnings upgrades that we expect to drive share price performance has yet to occur. For now we remain in an environment in which the fear of earnings cuts, following a two-year downturn, is still lingering in investors’ minds, as the disconnect between expectation from the financial community, fuelled by the robust oil price environment since late 2009, and the inherent inertia in oil companies ability to spend, still exists.

Encouragingly, the first signs of the uptick are beginning to materialise. Pricing for seismic activity in summer 2012 is 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 in the still depressed offshore heavy transportation section. The key will be the level of activity translating into backlog as we go through the year, underpinning a strong year of growth in 2013 and beyond.

Positive industry view, even after recent relative strength 2012 has been an up and down year for European Oil Services, with a strong run at the start of the year followed by a pull-back over European stability issues, a rapidly falling oil price and a resulting market wide risk-off trade. This was then followed by a strong summer rally. As in our last Global Energy Outlook, the key concern, just at the moment, from investors 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 24% since its lows in June and 15% ytd. We see this as less of an issue than we did six months ago. In the upcoming update season, starting with the Barclay’s CEO Energy & Power conference, we expect to see a positive outlook from all of our coverage universe and a confirmation that the projects that will transform backlogs are likely to come within the next 18 months.

Despite the performance ytd, we still believe in the longer-term value in the industry. Currently the industry is trading on 11x 2013F PE, just a 8% premium to the market, significantly the lowest premium that we have seen apart from in rapidly falling markets. Over the 2008-10 period the industry traded typically at a 50% premium to the wider markets and indeed over the 2010-12 period it has averaged 30%. This is largely a result of investors, in our opinion, currently having the shortest earnings horizon that we have seen

Mick Pickup +44 (0)20 3134 6695


Tom Ackermans

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

Barclays, London

Industry View

POSITIVE

Strong recent run should only be a start


30 August 2012 97

in a decade and hence little focus has been placed as yet on the 2013-14F multiples. This is despite the firming fundamentals in the industry that suggest 2013 and 2014 are likely to be years of significant growth. Hence at just 11x 2013F PE, and an historical trading range of 15-17x, 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 industry. We therefore continue to see significant upside potential in the space, and with an average potential upside of over 30%, we remain firmly Positive.

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

Seismic – pricing is moving. Pricing for marine contract work has finally started to move after holding steady for 18 months, as excess capacity following the 2009 downturn was absorbed by strengthening demand. The tipping point for the supply-demand balance appears to us to be now and so far this year we believe that we have seen a 10-15% price improvement for the northern summer season. Until recently there was a debate as to whether this is the start of a major up-cycle, or just a false dawn before a weak winter 2012, but it is becoming clear to us that pricing is likely to hold at this level or improve for the remainder of the year, before the companies attempt another price increase for summer 2013. The key for investors is that current pricing is still 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 2-20%, back towards the 45-50% range, generating rapid earnings expansion. Our preferred play remains PGS, while we believe investors with a smaller-cap bias could do worse than invest in Polarcus.

Offshore construction – record backlogs and not yet going. We view the continued progression into ever deeper offshore waters, and indeed continued mega discoveries in East Africa and Southern America as signs of an even more improving longer-term picture, as new basins are unlocked. The year started well, with ca $3.5bn awarded in Australia and already all three companies have posted record backlogs at one point this year. However, we are yet to see significant workload emerge out of Brazil, Nigeria and Angola and this should materialise as we move through the year. This is on top of a much improved North Sea which should continue to provide a solid baseload of work. As a result, we see Subsea 7 as attractive, with its expanded capability likely to bode well for it. In addition, it is the offshore construction activities of Saipem that are a key reason why view it as our favourite stock in the sector, albeit within a wider portfolio of activities that it performs.

Figure 1:Sector PE relative Figure 2: Sector PE (FY1 monthly)

(10)

(5)

0

5

10

15

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1996A 1998A 2000A 2002A 2004A 2006F 2008A 2010A 2012F

x

(40)%

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Sector PE - High 1999-08 average high premium

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PEFY1 10 yr Ave.

Source: Datastream, Barclays Research Source: Datastream, Barclays Research

SUBC NO / SUBC.OL


Price Target NOK 195.00

Price (23-Aug-2012) NOK 135.60


SPM IM / SPMI.MI



Price (23-Aug-2012) EUR 37.72



30 August 2012 98

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, on the whole, 2012 is likely to see backlogs falling for the second successive year. There are, however, signs of light at the end of the tunnel. Workload away from the Middle East and North Africa is beginning to show signs of growth and although this means a larger number of smaller projects, it can reverse the backlog trend. This has already become apparent in the more downstream and petrochemical-focused names, Tecnicas the prime example, which has won workload in Canada, Australia, Bolivia and has even been successful in Saudi Arabia. For the companies, especially Saipem and Petrofac, the key will be the return of North African volumes and the much anticipated, but apparently delayed, Iraqi upstream workload.

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. Importantly, we expect the company to be able to grow its US business strongly, even in a flat to down rig count environment, as ever increasing lateral well lengths and more complex completions necessitate more specialist tools.

PGS NO / PGS.OL


Price Target NOK 130.00

Price (23-Aug-2012) NOK 88.10


HTG LN / HTG.L


Price Target GBp 1060.0

Price (23-Aug-2012) GBp 788.0



30 August 2012 99

US DIVERSIFIED NATURAL GAS

Liquids infrastructure, recovery in natural gas prices to drive performance

Liquids (oil, NGL) volumes are growing double digits. The current infrastructure is inadequate to handle this influx of new volumes. MLP driven “yield cos” such as Oneok Inc. (OKE), Targa Resources Corp (TRGP) and Williams Companies (WMB) provide high yield, attractive ways to participate in this build out. All offer 15% plus dividend growth off of robust current yields.

Oversupply aggravated by inventory build attributable to abnormally warm winter weather crimped 2012 natural gas prices. Dry gas drilling has receded sharply and should result in a more balanced supply/demand picture in North America. Slow recovery to a normalized price in the $4/mmbtu range creates significant cash flow leverage for high growth, low cost gas producers such as EQT Corp (EQT).

Focus on Liquids, De-emphasis of Gas Drilling; MLP HoldCos Offer Good Income Proposition

Oil drilling has just breeched 70% of all activity. The bulk of gas drilling is being directed toward liquids-rich targets. We believe this skewing will gradually bring natural gas markets back into balance. We estimate abundant resources and continued displacement of coal in the power market will cap gas prices in the $4/mmbtu range for the foreseeable future.

We believe NGL prices will remain weak from a historical perspective, but sufficient to encourage development. Low cost supplies should gradually entice petrochemical industry and exports to accommodate the expected surge in domestic volumes. Infrastructure requirements across the value chain from field services to end users are currently inadequate. While capacity is being rapidly expanded, we expect another round of build in 2015-17 will extend the heady growth rates the industry is experiencing at the present time.

Yields are suppressed across the capital structure. Expectations are that this backdrop will be in place for the foreseeable future. Conversion to an MLP HoldCo structure for a select group of Diversified Gas Companies has reduced the capital requirements of these companies, increased free cash generation and placed these entities in the position to pay out a high percentage of their cash flow while growing at 2-3x the rate of the underlying asset base. With beginning yields in the 3.0-4.0% range and growth rates of 12-22%, we believe this select group of companies offer investors an unparalleled income value proposition.

Weakness in 1H12 NGL Prices Sets Up Attractive Buying Opportunity

An abnormally warm winter, an unusual high level of ethylene cracker turnarounds and a dip in oil prices coupled with growth in supply, caused a sharp decline in NGL prices during the first half of 2012. Resumption of petrochemical demand, ethane rejection and a step up in the level of propane exports have stabilized the outlook for key products: ethane and propane. Furthermore, the entire NGL barrel is poised to exhibit the typical seasonal price pattern for the product (low point June, peak January). NGL margin oriented stocks sold off double digits in 2Q. Across this segment of the gas universe, investors feared recanting of growth rates or worse. While dividend coverage was dented given the decline in gas processing margins, exposed companies have uniformly reiterated dividend growth

Richard Gross +1 212 526 3143


Industry View

NEUTRAL


30 August 2012 100

guidance, including OKE, TRGP and WMB. While the sell-off creates the possibility of valuation recovery expansion, the basic value proposition (yield plus growth) of these three names over the fives years ending 2016 (15%, 25% and 20%, respectively) is highly compelling, in our view.

EQT Corp. (EQT) EQT will continue to exploit its extensive low cost inventory of Marcellus shale drilling locations. Technological leadership, fee-based or vintage held by production (HBP) leases underpin this low cost advantage. We project production growth in excess of 30% over the next five years. Midstream capital intensity to accommodate this volume expansion has been reduced by the formation of an MLP (EQT Midstream Partners), which as it matures will not only reduce parent capital commitments but also accrue value by virtue of GP and LP ownership in the underlying assets. Downstream outlets for incremental production have already been secured at favorable rates. We believe valuation is attractive; using conservative valuations for the non-production assets allow investors to create EQT’s E&P operations at a 30% discount to similarly situated gas producers.

Oneok Inc. (OKE) Roughly 65% of OKE’s cash flow comes from ownership of the GP and LP units in Oneok Partners (OKS). OKS is a major NGL infrastructure field level and outlet transportation provider in the Bakken and MidContinent as well as a large provider of fee-based fractionation and storage services in the market centers of Mont Belvieu, Texas and Conway, Kansas. Furthermore, they provide key interconnecting facilities between these two logistical hubs. OKS plans to bring into service ~ $6 billion in projects in the 2012 to 2015 period, leading us to project a 9.3% distribution growth rate. Another $2 billion in pending projects have not been incorporated into this robust forecast. Importantly, this project inventory is highly diverse from a geographic/value chain perspective, principally fee-based, and virtually fully contracted. Thus, reducing risk and raising the visibility of our projections. We believe the strong distribution growth at OKS will translate into a 12% annual increase in OKE’s dividends over the next five years.

Targa Resources Corp. (TRGP) All of TRGP’s cash flow comes from its ownership of the GP or LP units in Targa Resources Partners (NGLS). NGLS has major positions in gathering and processing in the liquids-rich Permian Basin and MidContinent regions. NGLS is also a significant player in the NGL fractionation, storage and propane export businesses in the Mont Belvieu, Texas NGL hub. Similar to OKE/OKS, its market position in these rapidly growing supply and downstream markets has led to an abundance of high quality, fee based, and fully-contracted facility expansions. NGLS is projected to grow distributions 7.8% annually through 2016. Even with a conservative 30% income tax assumption at the TRGP level, the GP uplift and 100% MLP-based cash flow generation translates into an almost three-fold (21%) annual increase in dividends at TRGP.

Williams Companies (WMB) Approximately 83% of WMB’s cash flow comes from its ownership of the GP and LP units in Williams Partners (WPZ). Driving the underlying growth prospects for the MLP is a strong position in the heart of the two best drilling regions in the Marcellus (northeast and southwest Pennsylvania) and a growing exposure to the Utica/Marcellus wet gas corridor in West Virginia and Ohio. Furthermore, we believe WPZ’s position as a potential outlet for Marcellus volume growth as it outstrips regional demand is assured given the footprint of the partnership’s well-positioned Transco Pipeline. Dividend coverage at WPZ has declined

EQT



Price (23-Aug-2012) USD 54.44


OKE



Price (23-Aug-2012) USD 44.33


TRGP



Price (23-Aug-2012) USD 44.61


WMB



Price (23-Aug-2012) USD 31.88



30 August 2012 101

with the erosion in processing margins which is attributable to the dampened NGL price outlook, leaving WMB more exposed than most to a sharp decline in oil prices. However, our $100 Brent/NGL weighted barrel of 42% of crude forecast supports an 8% 5-year increase in WPZ’s distribution, and a 17% 5-year annual expansion in WMB’s dividend. We expect fee based, contracted capacity projects will be the principal driver of cash flow increases at WPZ.


30 August 2012 102

US COAL

This will take time We expect limited meaningful price recovery in U.S. thermal coal (2014 at the

earliest) as ample excess production capacity awaits if/when electricity generation demand recovers on a sustainable basis.

Meanwhile, metallurgical coal fundamentals have recently deteriorated significantly. We believe more near-term pain is likely and expect relatively low 4Q12 HCC benchmark settlements ($180/t-190/t by our estimates). However, we believe a recovery in metallurgical coal prices is likely to occur sooner than a recovery in U.S. thermal coal prices (i.e., early 2013), as global cost pressures constrain supplies. Recovery in European and Asian steel production should happen sooner than thermal coal prices.

Our preferred picks among the coal companies are those with a relatively low cost structure (CONSOL Energy) and/or stronger balance sheet and diversified product mix to withstand the ongoing soft market (Peabody Energy).

Thermal Coal: Beware the Risks of a False Start After suffering through the most significant demand decline in decades during January-May, thermal coal demand in the U.S. stabilized and recovered in June and July, as U.S. natural gas prices meaningfully rebounded to prompt some switching by utilities back to coal and away from natural gas (largely PRB coal). While encouraging, in our view, this renewed interest in thermal coal-related equities is more likely to be a false start for two reasons.

First, with ample supplies of both natural gas and coal in the U.S., and with natural gas prices weak enough to prompt the unprecedented switch seen earlier in 2012, we believe the utilities have the luxury of rapidly changing fuel consumption patterns to capitalize on small windows of price discrepancies between all-in delivered costs of coal vs. natural gas. We believe this will result in short periods of switching by the utilities depending on the best available fuel source price. Of note, when natural gas prices increase above a certain threshold (most likely $2.75-3.00/mcf), PRB-related coal demand generally increases. Then, as natural gas prices retreat, utilities switch back to natural gas to the point where thermal coal demand slows.

Second, even if there is a sustainable recovery in thermal coal demand, we believe there is ample thermal coal supply waiting to meet the recovery in demand, even at near break-even price levels. Due to the significant demand destruction in early 2012, by our estimates there is ~80mn tons of idled thermal coal production in the U.S. that can be restarted quickly and with minimal cost, or enough capacity to satisfy a 10% rebound in demand. Further, with the largest coal companies now struggling with balance sheet pressures following the wave of transactions in 2011, and with unit costs highly sensitive to volumes, the coal producers are more likely to ramp production rapidly if/when demand recovers, rather than withhold production to help stabilize the market, as was the case in previous cycles.

While we believe thermal coal prices will recover eventually, a sustainable recovery will take time. The combination of stubbornly high inventories, choppy utility buying patterns, and ample thermal coal production capacity is likely to extend the duration of the weak pricing environment for U.S. thermal coal.

David Gagliano +1 212 526 4016


Industry View

POSITIVE *Industry view is for the broader North America Metals & Mining industry


30 August 2012 103

Metallurgical Coal: Beware the Risks of an Unexpected Bounce in Prices in Late 2012 Recently, spot market indicators for global metallurgical coal prices have collapsed. Pacific Basin hard coking coal price indicators have fallen from ~$225/mt in late June to ~$163/mt currently driven by stagnant (and in some regions falling) demand from steel mills and continued supply growth, particularly in lower quality, high-volume coals.

In the near-term, we expect continued soft steel-related demand (both in Europe and China), latent impact of relatively high met coal supplies into the seaborne market, and high met coal inventories, each suggest that the next quarterly benchmark price settlement will likely be weak. We believe a reasonable range is $180-190/mt vs. the 3Q settlement of $225/mt.

However, beyond 4Q12, there are some signals suggesting that a recovery in 2013 metallurgical coal prices is not completely out of the question. First, steel production in general is highly correlated with underlying industrial production growth rates in each particular country. If our economists’ forecasts for a modest recovery in 2013 IP growth rates in China and Europe (albeit off a low base in Europe) proves accurate, we believe this bodes well for a rebound in metallurgical coal demand in general.

Further, with the recent collapse in Pacific Basin metallurgical coal prices and the widening discounts between HCC prices and lower quality grades of met coal appear to be squeezing a significant portion of the lower grade metallurgical coals out of the seaborne market. In our view, this is likely forcing the supply rationalization that is necessary to stabilize the met markets.

With the metallurgical coal industry still dominated by direct negotiations between producers and consumers, and with producers cutting production at a time when consumption should start to recover, we believe a rebound in quarterly benchmark met coal prices will occur in 2013, assuming global steel production rebounds.

Prefer Low Cost and/or Relatively Healthy Balance Sheets

CONSOL ENERGY (CNX) We maintain our view that CNX is the low cost producer in a high cost region. While CNX clearly has high cost assets within its portfolio of coal assets, the company has nearly 20 million tons (or ~33% of annual production) at its sizeable Bailey/Enlow complex. We estimate CNX produces coal at a cash cost in the low-$40s per ton (as with other coal producers, CNX does not disclose cash cost by asset/complex). Given cash costs in Appalachia for other publicly-traded producers are well above $60/ton, in our view, CNX’s lowest cost assets affords the company the opportunity to scale back higher cost assets and still generate sufficient positive cash flows from the lowest cost assets. With direct access to the export markets via the company’s Baltimore terminal, we believe CNX is best placed to capitalize on a recovery in the seaborne thermal and met coal markets when prices recover sufficiently for it to be economically viable to export thermal/met from the eastern U.S. Lastly, with total cash operating costs of $2.00-2.10/mcf, CNX’s natural gas business continues to serve as a relatively stable cash flow generator in a weak pricing environment for both natural gas and coal.

CNX



Price (23-Aug-2012) USD 32.99



30 August 2012 104

Peabody Energy (BTU) Peabody continues to struggle through significant integration pains associated with the Macarthur Coal acquisition last year, which has been further compounded by a collapse in global metallurgical coal and PCI prices. However, in our view, BTU shares reflect this transitional challenge, trading at 6.5x our 2013 EBITDA estimate of $1.8 billion, which in turn includes essentially break-even thermal coal pricing assumptions for unpriced contract positions, and essentially no EBITDA contribution from the Macarthur Coal assets in 2013 (i.e., another low EBITDA year).

But, even with the current operating challenges, in our view, BTU has a relatively strong balance sheet to withstand a prolonged period of soft industry-wide pricing ($1.9 billion of total liquidity, and by our estimates the ability to withstand approximately eight years of similarly weak coal market conditions), and a solid mix of international growth potential when global market conditions improve.

Figure 1: Coal Production by Region

80

130180

230

280330

380

430480

530

2000

2003

2006

2009

2012

2015

Coa

l Pro

duct

ion

(mm

ton

s)

Appalachia Powder River Basin Illinois Basin Other West & Interior

Source: EIA. Barclays Research Estimates

BTU



Price (23-Aug-2012) USD 22.93



30 August 2012 105

ASIA EX-JAPAN METALS & MINING

Stabilisation after the perfect storm The coal markets in Asia (and global seaborne coal markets in general) are rebounding

after a particularly tough 2Q, in our view. The recovery is being led through a combination of supply cuts and (modest) demand pick-up.

The pullback in thermal coal prices due to oversupply in 1Q in the Asian markets turned into a full-scale rout by April as traders reneged on contracts given the significantly lower spot market prices. This led to a significant number of distressed sales and that pushed prices down to a trough of US$83/t in the seaborne markets and RMB600/t in Chinese domestic prices – at which levels we estimate that around 150mn tonnes/annum of seaborne supply (c18% of total) and 400mn tonnes/annum of Chinese domestic supply (c15% of total) would be loss-making.

The inevitable production cuts that followed are helping to balance out the market. The Qinhuangdao port inventories that peaked at an all-time high of 9.4mn tonnes in late June are already down below 7mn tonnes. Coal inventory at power plants in China is also declining and is at around 23 days of burn (vs a peak of 28.5 days and a ‘normal’ period of 16 days).

While we are unlikely to see the seaborne coal price back where we started at the beginning of the year (US$115/t average Newcastle price), it should recover steadily from the current spot of c.US$90/t (and RMB630/t Chinese domestic price). We anticipate it will reach US$100/t in 4Q12. The Chinese domestic price should recover with a 1-2 months’ lag and we expect it to be over RMB700/t in 4Q12.

We continue to see coal demand continuing to be supported by power consumption growth (albeit at a slower rate than in the past 10 years) in China and increased urgency in India to improve power availability after the successive grid failures in the country in late July.

What happened? A quarter of pain, followed by some modest gains

2011 was a year of balance in the coal markets. Chinese domestic supply grew by around 11% y/y in 2011, while demand for coal was matched by a 10.5% y/y growth rate (China accounts for c60% of world thermal coal demand, on our estimates). Though prices weakened modestly as the year passed, the y/y increase of 20% was still impressive.

However, we were coming into 2012 with industrial production still weak – and industrial demand is c75% of Chinese power demand currently (and electricity generation is two-thirds of thermal coal demand). Though absolute industrial activity recovered from its 4Q11 trough in 1Q12, the supply cut-back required to balance out the market had not yet happened (because prices were still well above the marginal cost of Chinese domestic and global producers). Hence, in 1Q coal demand grew around 4.8% y/y, while supply was still growing at 7.5% y/y. This started the slow drift down of prices from around U$120/t down to US$105/t (which was driven by fundamentals).

Subsequently, the ‘technicals’ took over, in our view. The traders of seaborne coal started reneging on contracts and that created an inventory of ‘distressed’ cargoes at sea that needed to find a home. Consequently, prices went into what seemed like a freefall from mid-April to mid-June, to around US$83/t at the trough. At that price, c18% of seaborne supply was loss-making on our estimates, and that led to production cuts.

Ephrem Ravi +852 2903 4892


Industry View

POSITIVE


30 August 2012 106

Chinese domestic prices had held up well in April at around RMB780/t due to maintenance of the key Daqin railway line into the main port of Qinhuangdao. As that came to an end in April a historically high premium of Chinese domestic coal had opened up in Chinese coal vs seaborne coal – which led to record imports and prices in China correcting significantly as well.

While it is ironic that Chinese imports of coal doubled y/y at a time when demand growth for coal was arguably the weakest, it is easily explained in our view by the wide price arbitrage between seaborne and domestic coal prices.

Turning point happened at end of June

Coal fundamentals inflected in the third week of June 2012, in our view. Costs in coal mining and transportation are largely variable costs (unlike in most other bulk mined commodities) and when 150mn tonnes of seaborne coal and 400mn tonnes of Chinese domestic coal was below break-even, it had to elicit a supply response. It has started to come, in our view, and inventory both at ports and power plants peaked in late June (at the same time as the coal price trough) and has been coming down since.

Figure 1: Seaborne vs domestic price arbitrage in Chinese coal Figure 2: Monthly coal imports into China

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Thermal Coal (000't) Met Coal (000't)

Anthracite (000't) Lignite (000't)

Monthly Chinese Coal Imports

Source: Sxcoal, Platts, Barclays Research Source: Sxcoal, Barclays Research

Figure 3: Qinhuangdao port coal inventories (‘000t)

Figure 4: China key IPP coal inventories

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30 August 2012 107

Prices also recovered from a trough of US$83/t.

Figure 5: Seaborne coal prices (US$/t)

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20-Mar 4-Apr 19-Apr 4-May 21-May 5-Jun 20-Jun 4-Jul 19-Jul 3-Aug

ARA NewCastle Richards Bay

Source: Platts, Barclays Research

Demand also has not been as bad as it appears in the press

While the growth rate in demand has undoubtedly slowed, it is still growing. In China, Electricity demand from the residential and commercial sectors continues to grow strongly at double-digit rates, and the weakness is concentrated in agriculture and secondary industries. Even there, demand has started to pick up, in our view, as evidenced by the pickup in coastal freight rates.

Indian demand is the other variable, in our view. Unfortunately, India’s famously erratic monsoon season (which feeds the hydroelectric power generation) seems to have failed this year. In contrast to China, where hydropower generation is going to be higher y/y, Indian hydro power generation is now running at -8.8% y/y (as of end-June). If the significant seasonal pickup in hydropower generation does not transpire, we could end up with a ‘demand beat' for thermal coal of around 7-8mn tonnes in 2H, on our estimates.

Figure 6: China: y/y growth in power consumption by sector

Figure 7: India – shortfall in hydropower generation by region

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ion

June '12 April-June'12

Source: CEIC, NBS, Barclays Research Source: Central Electricity Authority, Barclays Research


30 August 2012 108

Few catalysts to drive the price going forward Over and above the general balancing of the supply/demand balance in the market driven by supply and the macroeconomic environment, we see three key catalyst events to potentially help drive the price higher:

1. Extended supply cuts during the Ramadan holidays in Indonesia in July-August. Indonesia supplies around 43% of the world’s seaborne thermal coal and hence this is material to the market.

2. Indian demand picking up after the monsoon season (Sept-Oct). India is the second-biggest importer of thermal coal and marginal demand from India is eagerly awaited by the market.

3. The Daqin railway maintenance (4Q12) is a likely catalyst, in addition to general production cuts in China. Chinese domestic prices held up in spite of the significant seaborne price weakness in March and April due to the previous round of maintenance and, hence, its importance should not be underestimated, in our view.

In addition, there are the unexpected supply disruptions that are difficult to predict with accuracy due to their nature, but could have a significant impact on prices. One such event we witnessed was the strike by workers on the main Colombian coal rail line Fenoco in July-August. Colombia supplies 10% of the world seaborne coal and the supply disruption there reminds us how fragile the coal supply chain is in terms of labour unrest, weather, natural calamity, political strife, etc; we estimate the disruption can provide upside surprise to the price in the medium term.

Top picks: China Coal Energy, ITMG

China Coal Energy (1898.HK, OW, PT HK$10.10) From a top-down perspective, we prefer thermal coal over coking coal. China Coal provides the right balance between leverage and safety in the current coal price environment, in our view (a 10% change in thermal coal reference price has a c12% estimated impact on earnings). With virtually no debt on its balance sheet, the risk if coal prices do not recover as we expect them to is lower.

The transformation from being a seller of thermal coal on annual contract prices (which are effectively mandated by the NDRC) to a spot-price-based thermal coal company is progressing faster than we had expected. The projects which could potentially contribute 15mn tonnes of metallurgical coal (from almost nothing currently) are on track. Development of other mining regions will reduce the company’s reliance on the Pingshuo operations – which improves the operational diversification of the company. The washing yield in mined raw coal has also improved in the last three quarters, mitigating some of the market’s concerns.

ITMG (ITMG.JK, OW, PT IDR42,000) ITMG’s key attraction for investors is its high (and stable) dividend yield, in our view. Having a large shareholder like Banpu (which owns 65% of the company) ensures that the dividend payouts remain high. In addition to the US$612mn starting net cash position, ITMG will generate over US$1.3bn in free cash flow in the next three years. Even maintaining a 75% payout ratio (87% in 2011), the company would have a dividend yield of 6-7% during this period and its net cash position would be maintained at current levels, on our estimates.

1898 HK / 1898.HK


Price Target HKD 10.10

Price (23-Aug-2012) HKD 7.07


ITMG IJ / ITMG.JK


Price Target IDR 42000.00

Price (23-Aug-2012) IDR 37800.00



30 August 2012 109

The fact that the company has settled close to 62% of its volume on fixed price contracts for the year yields plenty of comfort on earnings, we believe. In spite of the volatility in coal prices, ITMG’s price realisations should fall the least amongst the major Indonesian coal producers in 2012 (we estimate they will fall less than 2% y/y).

ITMG has third-generation CCoWs at its main operations (compared to first- or second-generation for most others) and at current taxation rates pays a corporate tax of 25% (vs 45% for others). This translates to higher earnings and cash flows even at the same coal price. Volume growth of 6% over the next five years enhances its attraction.

The company has maintained a net cash position since 2007 (even through the financial crisis) and had net cash worth 13% of its market cap at the end of 2011. At 9.8x P/E and 5.9x EV/EBITDA (2012E), ITMG is trading at a c9% discount to its local peers, which we think is not justified for a company with such high yields (8% FCF yield for the next two years). While P/B at 4.1x looks high at first glance, we think it is reasonable in the context of 43% ROE over the next three years.


30 August 2012 110

US POWER

Texas and everything else For investors the U.S. Power focus is on Texas far ahead of everywhere else. The

Texas Public Utility Commission is engaged in developing market incentives for new generation to address their projected low 8% reserve margin in 2014. Key companies in Texas are NRG Energy (NRG), Calpine (CPN), and NextEra Energy (NEE).

We like integrated power stocks such as American Electric Power (AEP) and Edison International (EIX). The catalyst for AEP is the recent constructive Ohio regulatory outcome and subsequent completion of the rehearing process. For EIX, the catalysts are the clearing of the regulatory calendar, the restarting of San Onofre (SONGs) 2, and a resolution on Edison Mission over the next six months.

Texas and Everything Else Texas regulators have identified a shortfall in capacity in 2014 and believe reliability is important for the industry. In early June, The Brattle Group presented options to incent new construction, and in early August the Texas Commission (PUCT) held a workshop to review these options. The Brattle Group provided a continuum from price cap increases to a forward capacity market.

The bottom line is that prices aren’t high enough for new construction. Around the clock spark spreads are $12/MWhr for 2013 and $10/MWhr for 2014-15. To incent new gas-fired combined cycle capacity, they would have to rise $15-20/MWhr. This energy price increase can also be expressed as a capacity payment. In capacity terms, this would be $225-250/MW day, which is similar to PJM’s cost of new entry. In Texas, NRG has 12 GW of capacity ex-wind, CPN has 7,500 MW, and NEE has 3,792 MW. NRG’s retail hedges and margin are a potential offset to a capacity market.

We feel confident that some form of market incentive will get approved by the PUCT by year-end. We expect the schedule and proposals to be clearer shortly. The next PUCT meeting is August 30.

PJM Mired in Uncertainty Post Auction Debacle This May’s PJM capacity auction for 2015-16 delivery cleared at $167/MW day in the MAAC zone which covers the Mid-Atlantic. This price was suppressed by the inclusion of two subsidized plants under New Jersey’s Long-Term Capacity Agreement Pilot Program (LCAPP). The approved pricing by PJM is contrary to the rules of the Minimum Offer Price Rule (MOPR) which mandates a bid at 90% of new entry. PJM later justified the lower adjusted MOPR $60/MW day due to the price of equipment ($30/MW day) and weighted average cost of capital ($30/MW day).

There are two places reform could take place, and we believe this precedent stands in the way of a price discovery in PJM. First, is the LCAPP court appeal in New Jersey Federal District Court of Trenton, NJ, which is PPLEnergyPlus et al. versus Lee Solomon et al. Second, there is also an early stages MOPR reform docket which could evolve to address a “bright line” test for auction inclusion. PJM’s Capacity Senior Task Force is working toward a filing with the Federal Energy Regulatory Commission for a fix to be applied to next May’s auction.

Daniel Ford +1 212 526 0836


Gregg Orrill


BCI, New York

Industry View

POSITIVE


30 August 2012 111

American Electric Power (OW, $47 price target; 10% total return). On August 8, the Ohio Public Utility Commission (PUCO) issued a long-awaited, constructive ruling in the company’s ESP (electric security plan) proceeding. In it, PUCO authorized $508mn in a rate stabilization rider (RSR) in excess of the RPM prices that were allowed up to the $189/MW day cap in the July capacity ruling, and that AEP will now go to market 6-12 months earlier than expected in June 2014. We expect this to be affirmed in the re-hearing process with petitions due within 30 days of ruling.

We have held our financial forecasts pending the ESP rehearing. We also await the results of AEP’s cost-cutting work, which has included the hiring of outside consultants to review various businesses. We believe our forecasts are biased higher and await a new guidance package which we suspect will be released around 3Q results, or at the Edison Electric conference in early November. Our EPS estimates are $3.06/$3.10/$3.25 for 2012-14, respectively.

Edison International (OW, $50 price target; 15% total return). On August 13, the California Public Utility Commission issued a two month delay in a final ruling for the company’s general rate case to October 30 with a proposed ruling in August. In the statement, the CPUC left the potential to address the SONGs outage where both units have been down since January. There is concern that this foreshadows a potential disallowance of nuclear costs and could be a near-term negative.

We believe EIX trades $4/share below the worst-case SONGs outcome, with some catalysts ahead. Specifically SONGs is $0.18/share of EPS considering a 10.5% ROE on $1.2bn of rate base. On an NPV basis to the license expiration, this is $0.76/share of value. Excluding this from EIX stock shows value of $4/share above this worst case. On the positive side, we see catalysts from: 1) completion of the GRC affirming 7-8% rate base growth; 2) restart of SONGs 2 this Fall; 3) a resolution on merchant independent power company Edison Mission by the December interest payment (which the company said they won’t make); and 4) a dividend increase in 2013 with a targeted payout of 45-55% of utility SCE’s earnings.

A Fall in Gas? As we exit the summer, forward gas has been trading in the $3/Mcf range, although there remains a likely move to the mid-$2s ahead of the October end of storage season. According to our Gas and Power Commodities analyst Mike Zenker, coal to gas switching will need to continue running at 3+Bcf/day levels to avoid full storage. Weakness in the power stocks could provide an opportunity as supply reaction leads to a temporary improvement in gas to $4+/mcf in 2013, before settling in at our $3.35/mcf estimate. We see commodity prices of $2.70/mcf gas and $61/ton coal at NYMEX, producing 3 Bcf/day of switching versus 2011. We also forecast 42 GW of coal shutdowns which leads to an incremental 2.1 Bcf/day of demand in 2015 and a 56mn ton reduction in coal demand. This assumes $4/mcf gas and $70/ton NYMEX coal.

Figure 1: Projected Coal Shutdowns (MWs) CA MRO FRCC ERCOT SPP SERC NIHUB PJM-West PJM-East NYISO NEPOOL Total

Total Capacity Considered 2,045 24,388 10,093 18,770 22,249 82,304 25,453 76,438 18,789 2,625 2,514 316,564Capacity Excluded 61 1,537 220 433 220 1,700 1,115 1,838 1,073 174 155 9,160Capacity Included 1,985 22,850 9,873 18,337 22,029 80,604 24,287 74,653 17,715 2,451 2,359 307,006

Capacity Shut 50 3,718 1,447 319 281 16,620 1,819 3,307 1,205 810 622 30,329Capacity Still Running 1,935 19,133 8,426 18,018 21,749 63,984 22,468 71,346 16,511 1,641 1,737 276,677

Total Dormant and Shut 387 6,046 1,139 254 606 20,861 1,375 3,566 5,335 977 1,046 42,203

Source: FactSet, SNL, Barclays Research

AEP



Price (23-Aug-2012) USD 42.60


EIX



Price (23-Aug-2012) USD 43.60



30 August 2012 112

EUROPEAN UTILITIES

Persistent headwinds Despite the Stoxx Utilities having underperformed the STOXX 600 since 2009, we still foresee a bleak picture overall for the industry. We expect deteriorating power markets, ongoing political risk, pressure on credit, unsupportive commodity trends and questionable value in equities. However, some favourable structural trends still exist in transmission networks and in UK generation. (For more details, please see our last published sector piece “European Utilities and Infrastructure: Persistent headwinds”, 13 July 2012).

Pan-Europe power market: spread generators under pressure

The structural outlook for continental Europe’s major power market remains challenging, given a general picture of stagnant power demand, overcapacity, growing competition and unsupportive commodity price fundamentals.

The UK is the only market where we see a positive structural outlook. We believe 2012 will be the trough, with market tightening from winter 2012/13 driven by accelerated LCPD coal plant closure, driving spark spreads higher. The UK carbon tax should drive absolute power prices higher over the longer term, while a more favourable structural outlook for gas prices relative to coal should benefit clean darks spreads in the nearer term.

We believe Germany has the worst outlook over 2012-15. The reserve margin is tight, but we argue this masks the true picture; we expect spreads and load factors for incumbent coal/gas generators to decline sharply, as competition from new thermal/renewable capacity intensifies. This is likely to be exacerbated by growing overcapacity in the neighbouring Dutch market. The Belgian and French power markets look tight, but we expect sentiment spill-over from Germany to keep prices subdued.

Spain and Italy markets are oversupplied currently, with falling power demand the main near-term challenge. We expect a resolution to the Spanish tariff deficit to be the main driver of industry profitability rather than the wholesale power price, and a declining Italian gas premium vs. the European average continues to put pressure on Italian power prices.

Peter Bisztyga +44 (0)20 3134 4763


Industry View

NEUTRAL

Figure 1: Pan-Europe power price trends have generally been bearish (€/MWh)

Figure 2: Europe as a whole set to remain over supplied (reserve margin, %)

20

30

40

50

60

70

80

90

Jan-10 Jul-10 Jan-11 Jul-11 Jan-12 Jul-12Germany Italy Spain

UK Nordic France

0%5%

10%15%

20%25%30%

35%40%45%

2011 2012E 2013E 2014E 2015E 2016EGermany UKFrance & Benelux ItalySpain Nordic

Below 8% = tight

Source: Barclays Research, Bloomberg Source: Barclays Research


30 August 2012 113

Given the bleak power market outlook in continental Europe, we expect marginal coal or gas-fired generators to suffer most, and this is further exacerbated by the competition from highly efficient new thermal capacity and renewables.

We expect 32GW of highly competitive new thermal generation assets to come online over the next three years, more than offsetting 19GW of planned LCPD closures. 60% of new capacity is concentrated in Germany and the Netherlands.

Uneconomic, inflexible thermal capacity is already being closed/mothballed, mainly in Germany and the UK. However, while the closure of very marginal gas plant may help tighten headline reserve margins, it has only a limited impact on spark/dark spreads. Closure of mid-merit coal plant has a more positive impact.

We expect 73GW of renewable capacity additions in the major European markets 2012-15E (over 40% in Germany) reducing gas/coal-fired output by ~100TWh pa (-11%) and squeezing spreads by €3.1/MWh on average. In aggregate, we estimate this will equate to a €2.6bn pa hit to industry profitability.

Our top picks: Drax, Snam Retegas, SSE and Veolia

We are cautious on European integrated utilities and instead recommend investing in names directly exposed to UK power market recovery. We also recommend rebalancing exposure in regulated utilities towards transmission.

Drax (OW, £6.95 PT) We think the stock does not reflect strategic value as one of the most flexible generation assets in the UK, nor its wide range of development options. We see significant operational gearing into structural power market tightening in the UK expected from 2013. Following the government’s recent subsidy announcement, Drax will convert to a biomass power plant through a unit-by-unit approach, significantly de-risking its equity story. Our current price target implies 50% upside, and our bull case DCF implies blue-sky potential to £11.50 based on full conversion of all six units.

Figure 3: Net thermal capacity additions by region (GW, 2012-15E)

Figure 4: Estimated impact of future renewables growth on spark/dark spreads (€/MWh, 2012-15E)

-15

-10

-5

0

5

10

15

Germany UK France Benelux Spain Italy Nordic

LCPD Closure Mothballing/Other ClosureNew Coal/Lignite New GasNew Nuclear

UK and France seeing material net

l

Germany and Benelux seeing greatest capacity

ddi i

(5.1 )

(2.7 )

(1.4 ) (1.2 )

(3.0 )

(2.3 )

(1.5 )

(6.0 )

(5.0 )

(4.0 )

(3.0 )

(2.0 )

(1.0 )

0.0

Germany UK France Benelux Spain Italy Nordic


DRX LN / DRX.L



Price (23-Aug-2012) GBp 462.0



30 August 2012 114

Snam Rete Gas (OW, €3.85 PT) We expect Italian government support for new gas infrastructure projects, driven by its desire to liberalise the gas market, to fuel growth for Snam. We believe Snam’s regulatory framework will adjust appropriately to compensate for macro volatility, while different timing of reviews helps to smooth the risk profile. We think the refinancing risk has been overly discounted. Despite Italian bond yields of ~6%, we expect Snam to achieve a cost of debt of ~4% thanks to mixture of maturities and loan types. The shares look undervalued to us at ~5% discount to RAV vs. an historical premium of ~5%. Our valuation implies a total shareholder return of 25%, including a best-in-class dividend yield of 7.6%,

SSE (OW, £15.85 PT) We estimate structural tightening of the UK power market should push spark spreads up fivefold to £11/MWh and increase SSE’s EPS by 30% 2013-16E. We also forecast electricity transmission RAV to grow fourfold under the new RIIO-T1 regime, driving a 12% increase in SSE’s EPS 2013-16E. SSE’s >13% EPS CAGR is one of the highest among the Integrated Utilities, more than justifying its premium 9.8x 2013/14 P/E, in our view. Our EPS forecast is 10% ahead of Bloomberg consensus. Whilst we cannot rule out a credit rating downgrade given current balance sheet pressures, we expect this to ease from next year, allowing >7% dividend growth, combined with a 6.2% yield.

Veolia Environnement (OW, €12.5 PT) Management is well-positioned, in our view, to deliver major restructuring that could drive >15% EPS CAGR 2011-16E. We also believe Veolia’s business mix is appealing: its waste business does not face the same risks as Suez (lower exposure to UK landfill/Netherlands, higher hazardous waste), and should have higher operating leverage to eventual macro recovery. €6bn of cash (before disposals) and long debt maturity provide flexibility for early repayment, reinvestment, or higher shareholder returns. Veolia trades at ~30% discount to historical multiples and, in our view, has a sustainable dividend, currently yielding 8.2%.

VIE FP / VIE.PA



Price (23-Aug-2012) EUR 8.44


SSE LN / SSE.L



Price (23-Aug-2012) GBp 1345.0


SRG IM / SRG.MI



Price (23-Aug-2012) EUR 3.29



30 August 2012 115

US CLEAN TECHNOLOGY AND RENEWABLES

Shares bottoming; however, visibility on pace of recovery still limited

A tempered macro economic backdrop and decreased regulatory support has accelerated the much needed rationalization of the U.S. Clean Technology & Renewables market, allowing those vendors with economically cost competitive technologies/solutions, and comparatively better balance sheets to begin making their mark as industry survivors.

The aforementioned coupled with depressed valuations suggest that industry trends have bottomed. However, as demand questions still linger and the cycle of rationalization is far from over, the timing and trajectory of the recovery in the U.S. Clean Technology & Renewables industry remains limited.

Thus, we retain our longer-term sanguine view on the industry. In the near-term, we believe that investors are focused on companies that provide technologies/services that can offer a compelling economic value proposition vs. those that depend on regulatory support or the promise of ultimately being cost competitive. Our key coverage in the U.S. Clean Technology & Renewables market include: solar, lighting, smart grids, energy efficiency and alternative fuel vehicles.

Solar: Focus on U.S. Growth against a Cautious Global Backdrop

Remarkably, against a backdrop of declining regulatory support amongst major markets, cost competitive alternatives (i.e., natural gas) and general pessimism around the renewables space, both domestic and global solar demand has proven to be better-than-expected this year. Largely driven by resilient demand in more developed markets such as Europe and rising demand in emerging markets such as China, the U.S. and Japan among others, global solar installations are expected to crest above 30-35GW for the year. This compares to our expectations of ~25GW at the start of the year, a 20-40% improvement. The U.S. market itself is expected to more than double to 2.5GW driven by a combination of expected utility scale build outs and continued growth in the residential and commercial markets. We recognize that one of the primary drivers of the better-than-expected demand environment – more resilient near-term demand in markets such as Germany and Italy – is unlikely sustainable as FiT cuts have been (or are expected to be) implemented shortly. However, as new market growth continues to help fill the demand gap, we believe a more diversified global market is a positive as the industry will be less reliant on demand from any one specific region.

Despite this improved demand environment, we have not changed our cautious tone, largely because we have yet to see the accelerated industry rationalization needed to return the market to a more stabilized supply/demand paradigm. Though some rationalization has occurred, it hasn’t been enough to bridge the gap between demand and the oversupply in the marketplace. Thus, issues such as ongoing ASP declines continue to negatively impact vendors, driving out the timing of when and at what level profit (both gross and operating) will stabilize and ultimately recover. In our view, the single most important factor determining the trajectory of stocks in the solar market is the timing of margin stabilization, and ultimately the level at which they recover. Thus, we continue to believe that the best way to invest in the solar market is to focus on vendors that 1) are direct (or

Amir Rozwadowski +1 212 526 4043


Olga Levinzon


BCI, New York

Shrenil Bhansali +1 212 526 7570


Industry View

NEUTRAL


30 August 2012 116

close to) beneficiaries of rising installation volume; and 2) have comparably stable margin structures. In our coverage universe, Power-One is the best fit name and thus, remaining our only OW rated stock in the solar market.

LED and Lighting: Increasingly More Constructive We continue to view the longer-term opportunities offered by light emitting diode (LED) penetration in general lighting as attractive. While still comparatively high on a capital cost basis, the value proposition for LED systems continues to improve driven by the combination of more attractive price points and the broader availability of products in the marketplace. This coupled with improving domestic construction trends paint an incrementally favorable backdrop for the longer-term market opportunity. However, we don't believe that we are at the inflection point in the market just yet as there is still a material gap in price points vs. traditional lighting technology. Given the pace of pricing declines, particularly in the chipset part of the LED value chain, demand inflection could emerge in the latter part of 2013/early 2014.

In our view, LED penetration of general lighting has always been a "when", rather than "if" story. We recognize that timing the inflection point for general lighting penetration is going to be a key element in driving material appreciation in the LED names. However, it has been our experience that specifically pinpointing the exact time of when an inflection in demand is likely to emerge is often times a futile exercise. The inflection point for new technologies is rarely defined until it has already taken place. Rather, we believe that investors would be best served by focusing on vendors whose margins have stabilized despite the lack of incremental volume growth, and are positioned to benefit when demand pick up takes place. In our coverage universe, Veeco Instruments is the best fit name meeting these characteristics.

Smart Grids: Waiting on the International Front We continue to remain neutral on the smart grid market, largely due to the limited visibility on the international upgrade cycle. Similar to LEDs, we believe that international upgrades are a "when", rather than "if" story. However, the smart grid market deals with large scale capital expenditure plans (vs. consumer/enterprise markets where the largest opportunity for LEDs resides), there is an added element besides just cost that drives the upgrade cycle. Moreover, visibility on the specifications for various upgrade opportunities (i.e., technologies utilized, the need to invest in new standards, etc.) is still limited. Thus, the level of investment required to capitalize on this upgrade cycle is still an unknown element that could impact the near and long term margin structures of the vendors involved.

That being said, we have been encouraged by recent developments in the smart grid arena. Notably, both Elster and Itron are making concerted efforts to optimize their costs ahead of the pending upgrade cycle. Most recently evidenced by better-than-expected gross margins and expectation for further improvement, we believe both companies are taking the appropriate approach toward right-sizing operations ahead of the international upgrade cycle, which we estimate could be $10 billion in just Europe over the next seven years (for further detail, please see our recent report entitled “Smart Grids: Keep an Eye of Europe,” 08/15/12). Moreover, Melrose's recent bid to acquire Elster underscores the longer-term opportunity for vendors that participate in this market – both from a cost execution standpoint as well as a longer-term revenue perspective. Given the lower-end valuation for the industry, along with the impending upgrade cycle in Europe, we believe that the smart grid space is one that bears monitoring in the mid-term for investors in the clean technology arena.


30 August 2012 117

Energy Efficiency Market: Healthy Opportunities – Execution Key We continue to retain a positive view on the energy efficiency market. As previously highlighted, we believe that the tempered broader economic environment has increased pressures on companies in the clean tech space that are overly reliant on government subsidies, and/or cannot provide cost competitive technologies today. Against this backdrop, energy efficiency stands out as comparatively better as it remains the low hanging fruit of the group. In other words, deploying more energy efficient solutions/technologies enables real cost savings today vs. waiting for a multi-year payback period. We recognize that the implementation of these types of technologies takes time and generally require financing/upfront capital in order to execute. However, over the mid to longer-term, we believe that investors interested in the clean technology industry should focus on areas that provide real economic benefit without the need to depend on subsidies and can provide cost competitive technologies. Ameresco remains our preferred name in energy efficiency.

Alternative Fuel Vehicles: Remain Focused on Specific Markets

By end markets, we are relatively positive on the near-term outlook for the electric vehicle (EV) market, 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.

In our view, we believe the adoption of electric vehicles is likely to be driven by two primary markets. 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. These consumers 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 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 Ameresco (AMRC; OW): Ameresco remains our top pick in the energy efficiency

market. We recognize that contract awards/conversion is likely to remain lumpy, particularly in the federal arena where execution seems to face increased hurdles against the backdrop of an election year. However, as the company's total backlog grows at a healthy rate and its business mix continues to drive a favorable mix shift in its margins, we believe that over the mid-to-longer term, Ameresco is poised to benefit from the dual challenges of reducing overall energy costs and limited capital for upfront infrastructure upgrades. Coupled with its healthy cash flow position and steady balance sheet, we retain our Overweight rating on the shares.

Power-One (PWER; OW): While the solar demand environment has demonstrated steady signs of improvement year-to-date, oversupply in key parts of the solar food chain make it difficult for investors to find vendors that can profitably benefit from rising global installations. In our view, this dynamic underscores our selection of Power-One as our preferred name in the solar space. Specifically, we believe that the company's

AMRC



Price (23-Aug-2012) USD 11.99


PWER



Price (23-Aug-2012) USD 6.11



30 August 2012 118

leading share in the global inverter market (second to SMA), and relatively more stable margins position the company well to benefit from rising global installations. With respect to the former, Power-One recently delivered record inverter shipments during its most recent (June) quarterly report, highlighting its exposure to rising global installations. While we recognize that the company's disproportionate exposure to Europe – in particular Italy – is a risk over the longer-term given expectations of waning regional demand, we do think that the company has already made the right moves by investing ahead in key regions such as the U.S. and China where we expect it to gain share. Moreover, as some of the headwinds that negatively impacted its gross margins in recent quarters seem to have passed (i.e., pricing declines, negative impact from underutilization of its new production facilities in China and the U.S.), we believe that the inverter market should retain its comparatively stronger margins due to relatively higher technology barriers of entry. Thus, given the current status of the solar market, we retain our Overweight rating on Power-One.

Tesla Motors (TSLA; OW – co-covered with U.S. Autos and Auto Parts analyst Brian Johnson): In our view, Tesla remains at the cusp of a multi-year product cycle driven by its innovative electric vehicle platform that caters to the right niche of the consumer market. We recognize that the next six months or so are a critical point for the company. Now that management has delivered the first commercial versions of its Model S sedan, the key driver of the shares will be whether the company can ramp its facility in order to meet expectations for its target run rate of 20,000 cars per annum. Moreover, management's recent willingness to embrace a potential capital raise leaves the potential for the emergence of a dilutive event as an overhang on the shares. That being said, we believe that the company has the tools and talent necessary to meet its production targets. Moreover, while the company may opt to do a capital raise, we believe that increased security on its balance sheet would in fact alleviate some investor concerns and provide the company with the next round of capital to further drive additional innovation investment at the company.

Veeco Instruments (VECO; OW – lead covered by U.S. Display and Lighting analyst Olga Levinzon): With LED equipment demand bottoming out in recent quarters, we believe Veeco is on the cusp of a gradual, multi-year cyclical recovery, with the only question remaining the magnitude of growth. We believe the key drivers of the next metal organic chemical vapour deposition (MOCVD) tool order recovery include: 1) sustained high utilization levels and improved profitability at the LED makers; 2) some improvement in macro conditions; and 3) increased confidence that LED lighting demand will continue to expand, thereby requiring additional capacity. We see several of these conditions already in place, and look for improved profitability and incremental confidence on demand to drive the next wave of tool orders. While China consolidation at the chip-maker level will remain an overhang, we do not see the potential for a used tool market to supplant the need for newer, more productive, and more cost-efficient tools – particularly at the Korean, Taiwanese, and Tier 1 Chinese LED makers. We view Veeco as best positioned into this LED equipment recovery driven by expectations for further market share gains, superior cross-cycle gross margins, management’s focus on cost control, and strong support from ~$14 in net cash per share. We reiterate our Overweight rating.

TSLA



Price (23-Aug-2012) USD 30.73


VECO



Price (23-Aug-2012) USD 33.20



30 August 2012 119

EUROPEAN CLEAN TECHNOLOGY & SUSTAINABILITY

Green power growth We expect global wind demand to be broadly flat in 2012 and 2013, with a return to

growth in 2014; we remain positive with an 8.5% CAGR in wind installation for 2011-15E.

We lower our wind demand expectations in the US by 12% and 9.1% in 2013 and 2014, respectively, anticipating a higher proportion of shale gas in the energy mix, with environmental concerns likely to be mitigated through legislation.

We remain positive on demand in the global solar market with a 14.4% CAGR in solar installations for 2011-15E, mainly supported by strengthening demand in Asia and the Americas.

Global wind market

Americas: lowered wind demand forecast to reflect shale gas implications We note that wind remains one of the fastest-growing power generation technologies globally and our revised forecasts imply a CAGR of 8.5% over the next five years. However, we have lowered our expectations for 2014 and 2015 in the US to 3.7GW and 4.0GW from 4.2GW (-12.0%) and 4.4GW (-9.1%), respectively, to reflect our expectation that the utility driven market is likely to view shale gas as cleaner power source than coal, and more favourable than wind given its lower cost (see full report ‘SRInvest: Shale gas - a death blow to renewables?’). While the U.S. Senate Finance Committee passed an extension plan for the Production Tax Credit (PTC), we still view it as unlikely that the bill will face a House vote until post-election in November, and maintain our expectation for a decline in installations in 2013 from 2012 levels. We remain positive on the outlook for South America, and forecast a 2012-2015E CAGR of 14.4%.

Asia: structural focus on clean technology We estimate a CAGR of 6.5% for 2011-15E period, considering China’s continued focus on grid connected wind power capacity. Wind power is the largest renewables segment after hydro in China with 62.4GW of installed capacity at the end of 2011, representing 6% of China’s total power capacity and 1.5% of power generation. We forecast domestic wind power capacity installations of 17.4GW in 2013 growing to 21.8GW by 2015, or a CAGR of 8.1% over a period of 2011-15E. We also forecast significant growth in the Indian wind market, primarily driven by favourable regulation.

EMEA: Positive momentum continues in Turkey and Eastern Europe We forecast a CAGR in installations of 9.0% over the period 2011-15E. Offshore installations in Europe continue to accelerate, and we expect this market to represent 23% of European wind demand from 2011-15E. We expect that Germany will surpass the UK to become the largest offshore market during 2012-13E, driven by favourable incentives and a strong project pipeline. We also note that positive momentum continues in Turkey and parts of Eastern Europe, which we forecast to be a key growth driver for the region as a whole.

Rupesh Madlani +44 (0)20 3134 7503


Arindam Basu


BCI, New York

Christopher Smith +44 (0)20 3555 1791


Industry View Energy Efficiency

POSITIVE Solar

NEUTRAL Wind

POSITIVE

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30 August 2012 120

Global solar market

Solar demand – driven by Asia Pacific region, mainly China We currently forecast global solar demand of 25.3GW and 28.6GW in 2012 and 2013, respectively, though given activity levels year to date, we believe that there is some upside to our expectations. This view reflects particularly strong pull-forward demand in what have historically been key markets, particularly Germany, where 4.3GW was installed in the first half of 2012 despite Government efforts to slow the pace of installations. This has been coupled with ongoing significant rates of price decline stimulating demand across a wide range of geographies, and more recently adopted policy support in less established solar markets such as China and Japan. In these markets, we currently forecast 2013 demand of 6.0GW and 2.2GW, respectively, with economic drivers and checks suggesting the market tracking strongly in China, and the introduction of a favourable feed-in tariff being implemented in Japan in the second half of 2012 likely to support the energy mix shift away from nuclear power.

Polysilicon pricing pressure now hitting tier 1 supplier margins We note the current spot polysilicon price is around the US$18-21/kg, with pricing pressure driving ASPs to levels where even low-cost tier 1 manufacturers are realising negative margins, and highlight GCL-Poly’s profits warning earlier in August. Given this situation, we believe that polysilicon ASPs should find some support at current levels for manufacturers such as Wacker Chemie and OCI, with the scope to lower prices limited by levels of cost reduction. We expect that this cost reduction will be the focus for the coming quarter for the majority of suppliers, with less effort expended on capacity expansion, which should help ease the oversupply situation given ongoing growth in the end market. However, we do highlight that high inventory levels may keep demand for Chinese wafers and polysilicon relatively depressed in the second half of 2012, particularly should anti-dumping measures be pursued in Europe. With sources reporting that inventory levels in China at the beginning of August were as high as 10GW, we believe that volumes could be lower through the third quarter of 2012, which may continue to put downward pressure on pricing despite the negative earnings that have been seen.

Figure 1: Polysilicon ASP evolution

15

23

31

39

47

55

Sep-11 Nov-11 Jan-12 Mar-12 May-12 Jul-12

Polysilicon Spot (US$/kg) Polysilicon Spot - 4 Week Average (US$/kg)

Source: PVInsights, Barclays Research


30 August 2012 121

European CleanTech & Sustainability 2012 Best Stock Ideas At the beginning of the year, 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. We continue to reiterate our Overweight recommendations on both Outotec and Umicore, and briefly summarise our view on these companies below.

Outotec (OTE1V.HE): Overweight, PT EUR60.0 (Energy Efficiency - Positive): 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. The company has raised guidance during the year, and we believe that it will continue to benefit from resource scarcity going forward.

Umicore (UMI.BR): Overweight, PT EUR51.5 (Energy Efficiency - Positive): 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. Management has maintained guidance throughout the year, which has been well received by the market, and we expect that recycling strength will continue throughout the second half of 2012.

UMI BB / UMI.BR



Price (23-Aug-2012) EUR 38.49


OTE1V FH / OTE1V.HE



Price (23-Aug-2012) EUR 38.50



30 August 2012 122

EQUITY VALUATION TABLE – INTEGRATED OIL

Equities Region Price 23 Aug

Stock Rating

Industry View

Target Price

Potential, % Dividend Yield, %

EPS Currency

Barclays EPS 2012F

Consensus EPS 2012F

Difference, %

2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2012F

Integrated OilBG Group EU 13.0 OW Neu 18.0 39 7.8 7.4 5.8 10.6 10.3 8.4 15.3 14.7 10.8 (4.8) (4.9) (2.4) 1.3 GBP 0.88 0.86 3

BP EU 4.45 UW Neu 5.45 22 3.7 4.0 3.5 5.4 5.7 4.5 6.3 7.5 6.5 2.5 3.2 8.3 4.7 GBP 0.59 0.60 -1

Chevron US 111 OW Pos 133 20 3.6 4.2 4.7 5.4 6.0 6.6 8.4 9.1 10.2 6.6 1.6 0.2 3.2 USD 12.20 12.72 -4CNOOC Asia 14.8 OW Pos 21.0 42 4.4 4.1 3.5 5.2 5.0 4.3 7.7 8.2 7.1 15.7 6.8 9.2 2.1 RMB 1.48 1.45 2

ConocoPhillips US 56.2 EW Pos 62.0 10 3.7 4.1 4.3 5.3 6.7 6.8 9.4 12.1 11.0 8.2 (1.8) (3.0) 4.7 USD 4.65 5.49 -15

Eni EU 17.5 UW Neu 21.0 20 4.1 2.9 2.5 6.0 4.5 3.9 9.1 8.6 7.4 2.7 9.3 11.1 6.2 EUR 2.03 2.11 -4Exxon Mobil US 87.3 EW Pos 93.0 7 5.4 6.3 6.9 7.3 8.5 9.3 10.4 12.1 12.7 5.7 7.4 3.4 2.5 USD 7.20 7.71 -7

Galp EU 11.7 OW Neu 18.0 54 17.3 12.7 10.0 16.3 14.6 12.3 36.5 26.3 20.9 (6.8) (3.5) 0.7 1.7 EUR 0.45 0.44 1

Hess US 49.8 EW Pos 60.0 21 3.9 3.7 3.6 4.8 5.0 4.6 8.0 8.8 8.0 (12.0) (23.3) (5.9) 1.2 USD 5.65 5.74 -2Husky Energy US 26.2 EW Pos 28.0 7 5.1 5.6 5.8 6.1 6.7 6.8 12.8 15.9 16.9 0.1 2.0 0.4 4.6 CAD 1.65 1.70 -3

Imperial Oil US 46.1 OW Pos 60.0 30 7.6 7.8 6.8 9.5 10.0 8.6 11.7 12.1 10.5 1.4 (1.8) 0.1 1.0 CAD 3.80 3.72 2

Marathon Oil US 27.7 EW Pos 33.0 19 3.3 3.1 3.2 5.1 5.5 5.3 8.6 11.3 10.7 16.4 (6.5) (3.2) 2.5 USD 2.45 2.68 -9Murphy Oil US 52.6 OW Pos 70.0 33 2.9 3.9 4.3 4.5 5.1 5.6 8.5 10.6 11.7 (4.7) (10.9) (13.7) 2.2 USD 4.95 5.24 -6

OMV EU 26.2 UW Neu 28.5 9 4.2 3.6 2.9 4.6 4.2 3.6 8.0 6.1 5.1 (0.1) 7.7 15.5 4.6 EUR 4.29 4.31 -1

Petrobras Latam 21.0 OW Pos 32.0 52 4.7 5.7 4.3 6.4 7.4 5.8 6.8 9.8 6.6 (5.5) (12.2) (4.9) (2.3) USD 2.15 2.46 -13Petrochina Asia 9.65 EW Pos 13.0 35 5.4 5.5 4.3 5.7 5.9 4.8 10.9 11.6 8.7 7.1 4.6 7.8 3.9 RMB 0.68 0.76 -10

PTT E&P Asia 149 OW Pos 220 48 4.9 4.2 3.1 6.7 5.9 4.5 11.1 9.2 6.8 1.2 (2.1) 8.3 4.3 THB 16.17 16.05 1

Repsol EU 14.2 OW Neu 20.0 41 4.5 4.2 3.8 5.4 5.2 5.0 9.0 8.3 7.3 (8.0) 6.6 5.3 5.6 EUR 1.72 1.53 12Royal Dutch Shell EU 23.0 EW Neu 26.5 15 3.9 3.6 3.2 6.0 5.5 4.9 8.9 8.3 7.3 3.9 5.1 7.2 4.9 USD 4.26 4.38 -3

Sasol S. Africa 357 EW Neu 375 5 6.4 4.5 4.6 9.3 6.3 6.6 10.5 6.9 7.3 5.5 1.7 4.0 4.5 ZAR 51.77 46.80 11

Sinopec Asia 7.17 EW Pos 9.80 37 4.4 5.0 4.3 4.9 5.4 4.8 7.2 7.9 6.1 0.9 (5.1) (1.4) 3.9 RMB 0.74 0.72 3Statoil EU 147 OW Neu 185 26 2.4 2.1 2.1 5.0 4.4 4.3 9.4 8.4 7.9 (0.4) 1.3 2.9 4.6 NOK 17.47 17.40 0

Suncor Energy US 31.3 OW Pos 48.0 54 4.5 4.9 4.6 5.6 6.5 6.0 8.7 9.9 9.2 6.4 3.6 3.0 1.6 CAD 3.15 2.87 10

Total EU 39.4 EW Neu 45.0 14 3.3 3.2 3.1 5.1 5.0 4.6 7.8 7.6 7.5 5.1 2.6 4.2 5.9 EUR 5.15 5.29 -3

Average Sector 27 5.1 4.8 4.4 6.5 6.5 5.9 10.5 10.5 9.3 2.0 -0.4 2.4 3.3 -1

FCF yield, %EV/EBITDA, x EV/EBIDA Price/Earnings, x

Source: Barclays Research. All estimates are as of August 23, 2012. Share prices and target prices are shown in the primary listing currency and EPS estimates are shown in the reporting currency. Stock rating: OW = Overweight; EW = Equal Weight; UW = Underweight Industry view: Pos = Positive; Neu = Neutral; Neg = Negative


30 August 2012 123

EQUITY VALUATION TABLE – INDEPENDENT REFINERS


Stock Rating

Sector View

Target Price


EPS Currency

Barclays EPS 2012F

Consensus EPS 2012F

Difference, %

2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2012F

Independent RefinersAlon USA US 13.0 UW Pos 14.0 8 7.3 4.4 4.4 8.8 5.9 5.8 26.1 8.4 9.6 (6.6) 19.0 18.0 1.2 USD 1.55 1.67 -7China BlueChemical Ltd. Asia 4.56 OW Pos 7.50 64 4.4 4.1 3.5 5.3 4.9 4.2 8.7 8.4 7.3 5.0 6.8 9.4 4.4 RMB 0.45 0.45 -1

Delek US 25.3 OW Pos 30.0 18 4.7 3.0 3.0 6.7 4.2 4.3 9.8 6.0 6.9 3.4 12.8 12.1 1.8 USD 4.25 3.70 15Dongyue Group Asia 4.17 OW Pos 5.60 34 2.2 4.1 3.5 2.8 5.0 4.3 3.3 7.7 6.7 32.1 (4.5) (2.5) 1.4 RMB 0.45 0.64 -30ERG EU 5.39 EW Neg 7.00 30 7.0 5.6 5.1 11.9 10.2 9.4 (16.5) 49.4 29.1 (25.3) (2.1) 1.2 7.4 EUR 0.11 0.07 56

Essar Energy EU 107 OW Neg 180 68 12.8 13.4 8.6 17.5 39.1 16.9 15.7 39.9 6.7 (71.7) (88.0) (29.1) 0.0 GBp 8.81 8.83 -0Grupa Lotos EU 25.8 EW Neg 34.0 32 12.0 13.6 8.9 24.1 10.7 8.0 (27.2) 18.8 7.5 7.4 (0.7) 8.0 0.0 PLN 1.37 2.98 -54Hanwha Chem Corp. Asia 21,200 EW Pos 23,000 8 18.5 21.3 17.5 - - - 17.9 69.0 27.9 (0.3) (0.1) (0.4) 2.1 KRW 307 1185 -74

Hellenic Petroleum EU 5.39 EW Neg 6.00 11 9.8 8.5 7.7 9.1 8.5 7.8 11.9 13.6 11.6 7.6 (0.3) 11.3 8.3 EUR 0.40 0.68 -42HollyFrontier Corp. US 38.8 EW Pos 55.0 42 4.1 2.7 3.7 6.1 4.1 5.5 6.0 5.3 6.9 15.6 15.8 12.0 5.3 USD 7.35 6.47 14Honam Petrochemical Asia 247,500 OW Pos 400,000 62 9.2 16.5 8.5 - - - 7.0 14.5 6.5 0.0 0.1 0.0 0.7 KRW 17075 16734 2

LG Chem Asia 312,500 OW Pos 430,000 38 14.3 15.4 12.0 - - - 9.7 13.3 9.7 0.0 0.0 0.0 1.3 KRW 23490 23789 -1Marathon Petroleum US 49.0 OW Pos 80.0 63 3.7 3.1 3.9 5.1 4.5 5.3 7.3 6.1 8.0 12.1 10.8 14.4 2.4 USD 8.10 7.47 8MOL EU 16,175 EW Neg 22,500 39 - - - 5.0 4.0 4.2 4.8 4.9 5.9 14.5 19.5 16.4 6.2 HUF 3013 2099 44

Motor Oil EU 4.87 OW Neg 9.50 95 5.1 5.4 4.7 5.4 6.8 6.5 3.4 4.3 4.0 (53.3) 26.9 28.4 10.3 EUR 1.13 1.26 -10Neste EU 8.41 OW Neg 14.00 66 9.0 6.3 5.5 10.8 7.2 6.2 29.0 9.3 7.6 (10.2) 8.1 11.9 5.4 EUR 0.91 0.64 42ORL Israel 1.58 EW Neu 2.50 58 23.0 12.2 11.2 - - - (11.0) 9.9 8.4 (0.9) 6.2 7.4 7.5 USD 0.04 0.09 nm

Phillips 66 US 41.3 OW Pos 63.0 52 4.1 3.6 4.2 4.1 3.6 4.3 0.0 5.8 7.4 11.1 11.2 10.5 1.0 USD 7.15 6.00 19PKN Orlen EU 37.3 UW Neg 40.0 7 8.7 6.0 4.7 4.2 5.2 4.8 20.9 10.9 12.9 5.2 8.6 8.2 0.0 PLN 3.41 3.45 -1Saras EU 0.86 UW Neg 0.85 (1) 5.5 6.3 3.6 5.8 6.3 4.5 nm nm 11.3 (14.3) 9.8 17.8 0.0 EUR (0.01) (0.02) nm

Sinofert Holdings Ltd. Asia 1.56 OW Pos 2.10 35 13.4 10.8 8.8 15.3 13.1 10.6 13.4 10.9 9.4 88.8 12.2 15.0 1.1 RMB 0.12 0.12 -2Sinopec Shanghai Petchem Asia 2.09 EW Pos 3.00 44 6.8 25.5 8.8 6.8 25.5 8.8 nm nm 19.7 (12.3) (26.5) (19.7) 0.0 RMB (0.16) (0.08) nmSK Innovation Co., Ltd. Asia 169,500 EW Pos 187,000 10 11.1 13.9 10.9 - - - 4.9 9.6 7.4 0.0 -0.2 0.0 1.7 KRW 17703 16923 5

S-Oil Corporation Asia 105,500 OW Pos 150,000 42 12.7 10.5 9.8 - - - 10.1 10.5 8.3 -0.0 0.0 0.0 4.5 KRW 10032 8390 20Sunoco US 46.7 EW Pos 50.0 7 16.7 14.1 11.5 15.6 17.6 15.0 nm 55.0 26.7 (10.8) 0.0 (2.5) 1.7 USD 0.85 1.19 -29Tesoro Corporation US 38.6 OW Pos 84.0 118 4.1 2.8 3.4 5.7 3.9 4.6 9.8 6.1 7.6 6.8 7.8 5.9 0.8 USD 6.30 5.81 8

Valero Energy US 29.2 OW Pos 63.0 116 4.6 4.1 4.4 6.2 5.5 5.8 8.6 7.2 9.0 6.3 9.4 12.4 2.2 USD 4.05 3.86 5

Average Sector 43 9.0 9.1 7.0 8.7 9.3 7.0 7.2 16.2 10.7 0.4 2.3 6.2 2.9 -1




30 August 2012 124

EQUITY VALUATION TABLE – EXPLORATION & PRODUCTION


Stock Rating

Sector View

Target Price


EPS Currency

Barclays EPS 2012F

Consensus EPS 2012F

Difference, %

2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2012F

Exploration & ProductionAfren EU 1.33 OW Pos 1.90 43 6.8 2.0 1.8 - - - 18.2 8.1 7.0 (19.6) 18.4 12.8 0.0 USD 0.26 0.27 -4Anadarko Petroleum US 68.9 OW Neu 84.0 22 - 5.2 5.9 - - - 20.5 19.4 23.8 (9.6) 3.8 1.2 0.5 USD 3.55 3.43 3Apache Corp US 87.6 OW Neu 117 34 - 3.6 3.7 - - - 7.3 8.8 9.0 2.6 (9.6) 4.6 0.7 USD 10.00 10.15 -1ARC Resources Canada 23.3 EW Pos 25.0 7 8.8 10.4 8.9 - - - 30.0 310.8 43.7 - - - 5.2 CAD 0.26 0.29 -10Avner Oil Exploration Israel 1.90 EW Pos 2.91 53 12.8 14.1 6.1 - - - 23.5 18.3 7.0 7.7 8.7 9.1 0.0 ILS 0.03 0.04 -35Baytex Energy Corporation Canada 47.3 OW Pos 51.0 8 11.5 11.2 9.6 - - - 27.9 87.2 31.0 10.1 9.2 10.0 5.6 CAD 2.29 1.93 19Bill Barrett US 21.9 OW Pos 27.0 23 4.4 4.9 4.3 - - - 12.3 48.6 24.3 (44.4) (45.0) (19.4) 0.0 USD 0.45 0.38 18Bonavista Energy Corporation Canada 17.2 EW Pos 18.0 5 7.1 10.0 7.8 - - - nm nm 35.1 19.9 12.6 15.5 8.4 CAD 0.25 0.26 -5Bowleven EU 0.65 OW Pos 2.15 231 nm nm nm - - - nm nm nm (45.5) (39.7) (40.6) 0.0 USD (0.03) (0.06) 51Cairn Energy EU 2.99 EW Pos 4.45 49 nm nm nm - - - nm nm nm 20.5 (6.0) (9.2) 0.0 USD (0.08) 0.05 nmCanadian Natural Resources Canada 30.9 OW Neu 36.0 17 - 5.6 5.3 - - - 13.4 17.1 17.1 (1.8) (1.6) (2.0) 1.3 CAD 2.07 1.84 13Canadian Oil Sands US 21.5 EW Neu 22.0 3 - 12.5 13.3 - - - 9.1 13.0 13.0 6.9 (4.8) (9.7) 6.3 CAD 1.65 1.76 -6Cenovus Energy US 32.4 EW Neu 41.0 27 - 6.6 7.2 - - - 19.8 16.6 18.5 (0.6) (1.5) (2.8) 2.7 CAD 1.95 1.78 10Cimarex Energy US 58.0 OW Pos 77.0 33 4.6 5.4 4.7 - - - 9.5 15.3 12.5 (5.4) (8.1) (5.4) 0.8 USD 3.80 4.01 -5Comstock Resources US 16.3 EW Pos 17.0 5 5.5 5.5 4.3 - - - nm nm nm (92.2) (25.0) (14.0) 0.0 USD (1.15) (1.09) -6Concho Resources US 93.0 OW Pos 104 12 10.1 8.5 6.6 - - - 22.3 22.7 16.2 (1.5) (2.1) (1.0) 0.0 USD 4.10 4.03 2Cove Energy EU 2.40 UW Pos 2.40 0 nm nm nm - - - nm nm nm (3.2) (5.6) (1.4) 0.0 USD (0.01) (0.01) -24Crescent Point Energy Canada 41.1 OW Pos 46.0 12 11.3 9.4 8.1 - - - 53.9 147.3 71.2 11.4 11.3 11.6 6.7 CAD 0.97 1.03 -6Crimson Exploration US 4.57 OW Pos 6.00 31 5.5 5.3 4.2 - - - nm nm nm (7.6) (12.8) (1.2) 0.0 USD (0.20) (0.13) -54Delek Drilling Israel 10.8 EW Pos 16.5 53 11.5 14.1 6.0 - - - 84.3 68.7 26.6 - - - 0.0 ILS 0.00 0.08 nmDelek Energy Systems Israel 1,287 OW Pos 1,363 6 22.2 21.9 12.8 - - - nm nm nm - - - 0.0 ILS (1.88) (1.88) 0Denbury Resources US 15.4 OW Pos 20.0 30 5.9 5.6 5.5 - - - 10.8 11.0 11.4 2.0 1.6 (2.7) 0.0 USD 1.40 1.36 3Devon Energy US 60.5 EW Neu 66.0 9 - 6.3 5.9 - - - 10.0 21.2 16.4 (13.2) (11.5) (12.3) 1.3 USD 2.85 3.43 -17EnCana Corp US 21.8 EW Neu 17.0 (22) - 5.9 7.3 - - - 40.2 19.8 (435) 57.7 47.6 47.2 3.7 USD 1.10 1.01 9Enerplus Corporation Canada 15.7 EW Pos 16.0 2 6.4 6.6 5.7 - - - 18.6 51.3 16.7 20.2 19.9 22.1 10 CAD 0.59 0.41 43Enquest EU 1.16 EW Pos 1.45 25 1.8 1.7 2.2 - - - 24.2 12.7 15.3 23.1 10.2 (10.8) 0.0 USD 0.14 0.22 -35EOG Resources US 107 OW Neu 138 29 - 5.8 5.6 - - - 28.3 25.2 26.8 (9.4) (8.0) (5.6) 0.7 USD 4.25 4.53 -6Exco Resources US 7.17 EW Pos 5.00 (30) 5.5 7.1 8.4 - - - 12.9 14.3 29 (35.8) 0.8 (5.7) 2.2 USD 0.50 0.33 52Forest Oil US 7.37 EW Pos 7.00 (5) 4.5 5.7 5.3 - - - 7.6 21.1 18.4 (69.3) (27.1) (0.8) 0.0 USD 0.35 0.35 0Isramco Negev 2 Israel 0.45 OW Pos 0.69 53 nm nm 7.8 - - - nm nm 7.8 - - - 0.0 ILS 0.00 (0.02) nmJKX Oil & Gas EU 0.86 EW Pos 1.75 103 1.9 1.3 1.1 - - - 4.0 2.4 3.5 (27.1) 11.8 23.3 0.0 USD 0.56 0.38 48Kosmos Energy US 9.51 OW Neu 14.0 47 - 7.7 5.4 - - - nm nm nm 0.5 (4.4) (15.2) 0.0 USD (0.10) (0.16) 38MEG Energy US 38.4 OW Neu 49.0 28 - 27.4 24.5 - - - 69.3 192 110 (8.2) (20.3) (15.9) 0.0 CAD 0.16 0.19 -18

Newfield Exploration US 31.4 EW Neu 32.0 2 - 5.3 5.1 - - - 7.9 13.1 10.6 (25.1) (16.6) (7.6) 0.0 USD 2.40 2.49 -4




30 August 2012 125

EQUITY VALUATION TABLE – EXPLORATION & PRODUCTION CONTINUED


Stock Rating

Sector View

Target Price


EPS Currency

Barclays EPS 2012F

Consensus EPS 2012F

Difference, %

2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2012F

Exploration & ProductionNexen US 25.5 OW Neu 24.0 (6) - 4.0 3.9 - - - 13.3 28.4 24.3 (3.2) (2.6) (0.9) 0.8 CAD 0.90 1.18 -24Noble Energy US 86.6 OW Neu 119 37 - 6.4 5.2 - - - 16.5 19.2 14.4 (7.7) (8.6) (9.6) 1.0 USD 4.50 4.89 -8

Occidental Petroleum US 87.3 EW Neu 99.0 13 - 5.1 5.2 - - - 10.4 13.1 14.2 (3.0) (0.8) (0.3) 2.4 USD 6.65 6.90 -4Pengrowth Energy Canada 7.01 UW Pos 7.00 (0) 5.4 7.1 5.3 - - - 18.1 319 33.4 26.4 17.5 19.3 9.8 CAD 0.13 0.04 nm

Penn Virginia US 6.47 UW Pos 5.00 (23) 4.4 4.2 4.8 - - - nm nm nm (101) (43.0) (58.2) 1.7 USD (0.70) (0.85) 18Penn West Petroleum Canada 14.6 UW Pos 15.0 3 6.7 8.1 6.9 - - - nm nm 99.9 22.5 16.9 20.4 7.4 CAD 0.49 0.31 59PetroBakken Energy Canada 13.3 OW Pos 15.0 12 6.2 7.1 4.7 - - - nm nm 12.4 28.5 24.6 32.2 7.2 CAD 0.39 0.24 63

Peyto E&D Canada 20.7 EW Pos 23.0 11 10.5 11.4 8.6 - - - 22.6 35.0 24.6 11.6 10.4 13.8 3.5 CAD 0.61 0.64 -5Pioneer Natural Resources US 96.1 OW Neu 107 11 - 7.0 6.5 - - - 24.4 24.3 18.5 (7.3) (10.4) (4.9) 0.0 USD 3.95 4.13 -4

Plains E&P US 39.5 OW Pos 56.0 42 7.1 5.0 4.8 - - - 25.3 22.6 24.7 (13.2) (5.0) (4.0) 0.0 USD 1.75 2.05 -15Premier Oil EU 3.77 OW Pos 6.10 62 11.7 3.7 3.1 - - - 19.0 8.0 7.2 (11.2) (1.1) (0.8) 1.1 USD 0.75 0.67 11

Progress Energy Resources Canada 22.1 EW Pos 22.0 (0) 11.5 35.8 22.9 - - - nm nm nm 4.5 2.6 4.2 1.8 CAD (0.39) (0.38) -1QEP Resources US 27.2 OW Neu 33.0 21 - 5.0 4.8 - - - 15.3 20.1 17.5 (2.6) (2.6) (5.2) 0.3 USD 1.35 1.50 -10

Quicksilver Resources US 3.70 UW Pos 3.00 (19) 5.5 6.6 6.3 - - - nm nm nm (68.3) (25.1) (2.8) 0.0 USD (0.25) (0.19) -32Range Resources US 65.7 EW Neu 46.0 (30) - 15.4 13.9 - - - 59.5 82.1 77.2 (7.8) (9.4) (3.5) 0.2 USD 0.80 0.66 21

Ratio Oil Exploration Israel 0.26 OW Pos 0.45 73 nm nm nm - - - nm nm nm 0.3 0.2 0.2 0.0 ILS (0.00) 0.00 -Resolute Energy US 8.51 OW Pos 11.0 29 8.1 7.5 6.3 - - - 24.3 85.1 56.7 (12.9) (18.3) (14.3) 0.0 USD 0.10 0.06 67

Rockhopper Exploration EU 1.86 EW Pos 3.50 88 nm nm nm - - - nm nm nm (25.1) (35.3) (0.8) 0.0 USD (0.21) (0.10) nmSalamander Energy EU 2.04 OW Pos 2.65 30 4.0 4.0 2.1 - - - nm 17.1 9.5 (8.5) (6.5) 9.4 0.0 USD 0.19 0.17 11

SandRidge Energy US 6.52 EW Pos 7.00 7 9.6 6.0 4.9 - - - nm 32.6 26.1 (39.8) (36.6) (29.4) 1.5 USD 0.20 0.11 82SM Energy US 46.2 OW Pos 76.0 65 4.9 4.6 3.8 - - - 18.1 44.0 25.0 (29.5) (20.2) (12.5) 0.2 USD 1.05 0.83 27Soco International EU 3.47 UW Pos 3.55 2 11.2 3.7 2.6 - - - 20.9 9.2 7.7 (0.6) 1.7 2.3 0.0 USD 0.59 0.70 -16

Southwestern Energy US 31.0 EW Neu 26.0 (16) - 8.2 7.8 - - - 17.0 26.9 25.8 (3.7) (5.7) (2.6) 0.0 USD 1.15 1.22 -6Stone Energy US 24.8 OW Pos 37.0 49 3.0 2.8 2.6 - - - 6.1 8.0 7.8 (16.2) (7.9) 4.8 0.0 USD 3.10 2.96 5

Swift Energy Company US 20.9 EW Pos 25.0 20 4.5 5.4 4.6 - - - nm nm 27.9 (14.6) (43.2) (30.9) 0.0 USD 0.35 0.42 nmTalisman Energy US 13.3 EW Neu 11.0 (17) - 4.3 4.0 - - - 22.8 38.1 38.1 (16.9) (9.8) (18.1) 2.0 USD 0.35 0.53 -34

Trilogy Energy Canada 23.4 OW Pos 27.0 16 14.5 11.7 7.0 - - - nm nm 22.5 7.9 9.8 16.1 1.8 CAD 0.12 0.08 50Tullow Oil EU 14.0 OW Pos 18.2 30 13.7 11.7 9.5 - - - 30.8 27.1 20.3 (0.7) (1.9) (0.5) 0.9 USD 0.82 0.79 4

Ultra Petroleum US 21.6 UW Neu 13.0 (40) - 7.2 9.6 - - - 8.5 14.9 30.8 (14.0) (2.2) (2.8) 0.0 USD 1.45 1.52 -5Venoco US 10.7 EW Pos 10.0 (6) 7.9 5.7 6.2 - - - 19.8 10.1 21.3 (18.2) (12.8) (14.7) 0.0 USD 1.05 1.01 4

Vermilion Energy Canada 46.9 EW Pos 51.0 9 8.6 7.8 6.0 - - - 32.0 22.6 13.8 11.1 11.8 13.5 4.9 CAD 2.39 2.30 4W&T Offshore US 17.7 EW Pos 17.0 (4) - 3.8 3.4 - - - 6.7 13.6 11.8 18.2 4.5 6.9 1.8 USD 1.30 1.10 18

Whiting Petroleum US 43.8 OW Pos 62.0 42 5.0 4.7 4.2 - - - 11.3 13.5 12.0 (7.0) (11.0) (7.4) 0.0 USD 3.25 3.30 -2WPX Energy US 14.3 EW Neu 18.0 26 - 4.0 4.5 - - - nm nm nm (14.2) (16.5) (13.0) 0.0 USD (0.40) (0.36) -11

Average Sector 22 7.8 7.7 6.5 - - - 22 43.3 17 (8.6) (5.2) (1.9) 1.6 6




30 August 2012 126

EQUITY VALUATION TABLE – OIL SERVICES & DRILLING


Stock Rating

Sector View

Target Price


EPS Currency

Barclays EPS 2012F

Consensus EPS 2012F

Difference, %

2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2012F

Oil Services & Drilling Part IAker Solutions EU 102.8 U/W Pos 125.0 22 12.9 8.6 6.5 - - - 34.7 13.5 9.2 (1.8) (0.7) 6.7 4.1 NOK 7.63 7.95 -4AMEC EU 11.1 U/W Pos 13.5 21 10.9 10.7 8.0 - - - 15.8 14.1 11.0 4.1 6.1 9.0 3.2 GBP 0.79 0.79 -0

Baker Hughes US 47.4 O/W Pos 63.0 33 6.2 5.8 4.7 - - - 11.3 12.5 10.5 (4.6) (4.7) 4.3 1.3 USD 3.80 3.73 2

Basic Energy Services US 11.8 E/W Pos 16.0 36 - - - - - - 6.2 8.7 13.1 - - - 0.0 USD 1.35 1.38 -2Bristow Group US 46.7 E/W Pos 52.0 11 9.3 8.9 8.2 - - - 14.0 14.6 13.2 8.9 (3.3) (1.9) 1.3 USD 3.19 NA -

Cameron International US 54.0 O/W Pos 77.0 43 13.5 10.8 7.9 - - - 20.2 16.6 12.1 (1.3) (2.5) 4.7 0.0 USD 3.25 3.22 1CARBO Ceramics US 70.1 E/W Pos 97.0 38 6.7 6.8 6.3 - - - 12.4 13.9 13.4 1.3 5.2 2.5 0.0 USD 5.05 4.95 2

CGGVeritas EU 23.8 E/W Pos 30.5 28 7.2 5.0 3.3 - - - nm 22.0 9.3 2.1 4.0 13.4 0.0 USD 1.36 1.39 -2

Chart Industries US 71.1 OW Pos 91.0 28 19.6 13.3 8.2 - - - 38.5 25.4 15.1 2.8 (1.3) 4.4 0.0 USD 2.80 2.69 4COSL Asia 13.0 UW Pos 13.0 (0) 8.6 7.7 7.1 - - - 11.9 10.6 9.7 6.9 5.2 5.7 1.9 RMB 1.01 1.07 -6

Core Laboratories US 120.9 OW Pos 137.0 13 22.3 17.9 15.8 - - - 31.9 25.2 21.2 0.0 0.0 0.0 0.9 USD 4.80 4.76 1

Diamond Offshore Drill'g US 66.5 UW Pos 56.0 (16) - - - - - - 10.0 16.2 13.2 7.0 5.5 2.1 5.3 USD 4.10 4.45 -8Dockwise EU 14.0 OW Pos 24.0 72 6.8 7.6 4.0 - - - nm 13.2 4.8 (5.8) (22.2) 31.0 0.0 USD 1.33 0.92 45

Dresser-Rand Group US 51.6 OW Pos 70.0 36 14.6 9.8 7.0 - - - 30.7 18.4 12.6 - - - 0.0 USD 2.80 2.67 5

Dril-Quip US 73.1 OW Pos 77.0 5 18.4 13.3 9.6 - - - 29.4 24.3 17.2 1.5 1.3 0.9 0.0 USD 3.00 2.95 2Ensco US 57.0 OW Pos 64.0 12 - - - - - - 18.6 11.1 8.5 (0.1) (0.4) 4.7 2.5 USD 5.15 5.34 -4

Exterran Holdings US 18.6 EW Pos 16.0 (14) 7.6 6.6 5.3 - - - nm nm 195.8 1.6 5.6 12.5 0.0 USD (1.10) (1.03) -7EZRA Holdings Limited Asia 1.04 OW Pos 1.70 63 20.9 12.2 9.8 - - - 16.8 11.2 7.9 (72.3) (9.4) (5.1) 0.0 USD 0.07 0.07 7

FMC Technologies US 47.5 EW Pos 47.0 (1) 15.7 13.4 9.7 - - - 29.4 23.8 18.3 (0.9) 0.3 3.4 0.0 USD 2.00 2.09 -5

Global Geophysical Services US 4.76 OW Pos 11.0 131 2.2 1.8 1.4 - - - 24.3 7.4 4.0 - - - 0.0 USD 0.65 0.61 6GulfMark Offshore US 36.1 OW Pos 53.0 47 8.2 8.5 6.0 - - - 19.1 19.0 8.5 8.3 (6.7) (9.0) 0.0 USD 1.90 1.82 4

Halliburton US 34.2 OW Pos 57.0 67 5.4 5.4 4.2 - - - 10.2 10.2 8.2 2.3 (0.6) 4.1 1.0 USD 3.35 3.30 2

Helmerich & Payne US 47.0 EW Pos 56.0 19 5.1 4.0 3.8 - - - 11.9 9.3 9.2 (3.4) (2.0) 1.3 0.6 USD 5.05 5.06 -0Hercules Offshore US 4.25 UW Pos 3.00 (29) - - - - - - nm nm 40.5 0.6 (2.0) 3.9 0.0 USD (0.45) (0.49) 8

Hornbeck Offshore Services US 40.3 OW Pos 48.0 19 13.8 9.0 7.6 - - - nm 24.4 14.6 0.5 7.3 11.2 0.0 USD 1.65 1.44 15

Hunting EU 788 OW Pos 1060 35 12.9 8.2 6.9 - - - 20.4 14.1 12.0 (1.6) 2.6 10.0 2.8 GBp 55.96 58.61 -5ION Geophysical US 6.56 OW Pos 11.0 68 6.8 4.9 3.6 - - - 29.5 14.7 10.1 - - - 0.0 USD 0.45 0.45 -1

Keppel Corporation Limited Asia 11.4 EW Pos 13.3 17 12.1 10.7 10.6 - - - 13.6 11.8 11.9 (5.5) 0.5 6.5 4.6 SGD 0.96 1.02 -6Key Energy Services US 8.66 EW Pos 13.0 50 5.2 4.3 3.3 - - - 9.5 9.1 6.6 (40.7) 3.3 12.1 0.0 USD 0.95 0.92 4

Lufkin Industries US 52.0 OW Pos 74.0 42 14.9 9.1 6.1 - - - 21.4 16.8 11.6 (3.5) (0.1) 3.9 1.0 USD 3.10 3.01 3

Maire Tecnimont EU 0.58 EW Pos 0.80 38 nm 9.5 3.4 - - - nm nm 3.4 (101) (99.3) 21.2 (4.4) EUR (0.09) (0.07) -22MRC Global US 22.1 OW Pos 29.0 32 - - - - - - nm 13.8 9.2 (6.3) 6.5 6.0 0.0 USD 1.60 1.53 5

Nabors Industries US 15.6 EW Pos 17.0 9 4.8 4.1 3.5 - - - 10.5 8.4 7.8 (3.8) (10.6) 24.4 0.0 USD 1.85 1.91 -3

National Oilwell Varco US 77.3 OW Pos 127.0 64 8.5 7.0 9.2 - - - 16.2 12.8 10.0 5.1 3.4 8.2 0.6 USD 6.05 5.96 1Noble Corp US 38.4 OW Pos 48.0 25 - - - - - - 29.1 13.3 8.9 (16.2) (0.4) 4.8 1.5 USD 2.90 2.71 7

Oceaneering International US 55.2 OW Pos 57.0 3 12.7 10.0 8.0 - - - 26.8 21.3 17.2 1.8 5.6 6.0 1.1 USD 2.60 2.65 -2Oil States International US 77.6 OW Pos 122.0 57 7.6 5.6 4.8 - - - 13.2 9.3 8.4 - - - 0.0 USD 8.35 8.06 4

Parker Drilling US 4.48 EW Pos 8.00 79 3.8 3.5 2.7 - - - 8.3 6.9 5.6 5.5 (18.3) 4.7 0.0 USD 0.65 0.61 7

Patterson-UTI Energy US 15.6 OW Pos 24.0 54 3.0 2.9 2.8 - - - 7.3 8.2 8.4 (14.4) (6.2) (4.9) 1.3 USD 1.90 1.85 3Petrofac EU 14.9 UW Pos 19.0 27 9.5 8.8 7.1 - - - 15.1 12.8 10.8 10.0 (6.9) (1.6) 2.6 GBP 1.16 1.17 -0

Petroleum Geo-Services EU 88.1 OW Pos 130.0 48 6.9 4.6 3.2 - - - nm 17.8 7.2 (0.7) 2.1 7.0 1.7 USD 0.85 0.81 5




30 August 2012 127

EQUITY VALUATION TABLE – OIL SERVICES & DRILLING CONTINUED


Stock Rating

Sector View

Target Price


EPS Currency

Barclays EPS 2012F

Consensus EPS 2012F

Difference, %

2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2012F

Oil Services & Drilling Part IIPolarcus EU 5.52 OW Pos 10.8 96 13.3 6.3 3.0 - - - nm 17.2 3.4 (81.0) (44.6) 37.2 0.0 USD 0.06 0.06 -8Rowan Cos US 35.6 OW Pos 45.0 26 - - - - - - 30.1 18.7 10.6 (26.4) (3.7) (0.9) 0.0 USD 1.90 2.10 -10

Saipem EU 37.7 OW Pos 52.0 38 9.7 8.5 6.7 - - - 18.1 16.0 12.4 2.4 5.0 10.1 2.1 EUR 2.35 2.34 1SBM Offshore EU 11.1 UW Pos 15.8 42 5.4 5.8 5.0 - - - nm 5.3 4.1 (11.4) (24.4) (15.5) 9.3 EUR 2.07 1.89 10

Schlumberger US 74.2 OW Pos 98.0 32 10.7 9.0 7.4 - - - 20.2 16.7 13.5 2.1 3.6 5.2 1.4 USD 4.45 4.31 3

SEACOR Holdings US 89.2 EW Pos 83.0 (7) - - - - - - 30.2 23.2 12.7 (6.6) (3.2) 9.0 0.0 USD 3.85 3.85 -0Seadrill Limited US 41.0 OW Pos 47.0 15 12.5 11.7 9.8 - - - 21.9 12.6 10.2 (3.6) (1.9) 1.3 8.2 USD 3.25 3.14 4

Sembcorp Marine Asia 5.03 OW Pos 7.00 39 10.5 9.9 8.4 - - - 15.0 13.7 12.1 (1.1) 1.3 5.5 5.0 SGD 0.37 0.31 18Subsea 7 EU 135.6 OW Pos 195.0 44 7.8 7.2 5.0 - - - 19.5 17.1 12.1 (0.7) 2.6 10.2 1.6 USD 1.36 1.51 -10

Superior Energy Services US 22.0 OW Pos 33.0 50 5.8 2.7 2.1 - - - 10.7 7.8 7.3 0.5 (3.3) 11.8 0.0 USD 2.80 2.83 -1Technip EU 85.9 EW Pos 102.0 19 9.9 8.5 6.1 - - - 19.5 19.0 13.7 3.2 6.1 8.3 1.9 EUR 4.51 4.66 -3

Tecnicas Reunidas EU 35.4 EW Pos 43.5 23 10.5 9.7 8.2 - - - 14.5 14.1 12.8 15.5 6.1 9.7 3.8 EUR 2.51 2.50 0

Tenaris US 41.3 OW Pos 60.0 45 19.9 15.7 13.2 - - - 18.3 12.5 10.4 - - - 1.6 USD 3.30 3.07 7Tetra Technologie US 6.81 EW Pos 13.0 91 - - - - - - 17.5 10.5 6.8 17.5 (28.0) 6.7 0.0 USD 0.65 0.62 4

TGS EU 167.7 UW Pos 215.0 28 5.3 3.6 3.3 - - - 17.4 10.9 9.8 6.5 4.1 5.5 5.3 USD 2.63 2.48 6Thermon Group Holdings US 22.9 OW Pos 24.0 5 15.1 13.0 10.3 - - - nm 27.5 19.9 - - - 0.0 USD 0.83 NA -

Tidewater US 48.5 OW Pos 71.0 46 - - - - - - 20.9 24.5 11.8 14.1 10.9 4.2 2.1 USD 1.98 NA -

Transocean US 48.5 OW Pos 77.0 59 - - - - - - 36.3 17.3 10.1 3.7 5.3 3.5 0.0 USD 2.80 3.00 -7Weatherford International US 12.7 OW Pos 23.0 81 6.8 5.6 4.2 - - - 18.2 11.1 7.5 (7.1) 3.4 6.0 0.0 USD 1.15 1.13 2

Wood Group EU 8.13 OW Pos 10.0 23 12.8 8.4 6.6 - - - 18.8 14.4 11.7 1.3 5.6 8.2 1.4 GBP 0.56 0.54 5Average Sector 34 10.8 8.5 6.7 - - - 20.0 15.5 15.3 (3.7) (1.5) 6.1 1.5 2




30 August 2012 128

EQUITY VALUATION TABLE – PIPELINES


Stock Rating

Sector View

Target Price


EPS Currency

Barclays EPS 2012F

Consensus EPS 2012F

Difference, %

2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2012F

PipelinesAccess Midstream Partners LP US 29.6 O/W Neu 33.0 12 15.6 11.9 9.8 - - - 21.6 17.2 15.5 - - - 5.8 USD 1.72 1.40 23AmeriGas Partners, L.P. US 40.7 U/W Neu 41.0 1 17.9 16.1 9.6 - - - nm nm 17.3 - - - 7.8 USD (0.15) 0.18 nm

Atlas Pipeline Partners LP US 34.6 O/W Neu 38.0 10 6.0 12.2 12.2 - - - 6.6 19.4 26.6 - - - 6.5 USD 1.79 1.23 45Blueknight Energy Partners, L.P. US 6.42 U/W Neu 7.00 9 5.3 5.3 4.9 - - - 15.2 15.1 23.5 - - - 6.9 USD 0.42 0.42 1Breitburn Energy Partners L.P. US 18.9 E/W Neu 23.0 22 - - - - - - 22.2 34.3 75.5 - - - 9.6 USD 0.55 0.93 -41

Buckeye Partners, L.P. US 49.6 E/W Neu 57.0 15 14.9 14.0 11.6 - - - 16.2 18.9 14.5 - - - 8.4 USD 2.62 2.71 -3Calumet Specialty Products Partners US 27.0 E/W Neu 27.0 (0) 12.2 7.2 8.4 - - - 27.5 8.3 11.2 - - - 8.7 USD 3.25 3.17 3

Copano Energy LLC US 30.5 EW Neu 33.0 8 nm 124.5 13.3 - - - nm nm 23.1 - - - 7.5 USD (1.86) 0.09 nmCrestwood Midstream Partners LP US 23.2 EW Neu 27.0 17 12.3 11.0 8.8 - - - 23.2 31.2 19.0 - - - 8.7 USD 0.74 0.67 11

Crosstex Energy LP US 15.0 EW Neu 18.0 20 8.8 10.1 8.3 - - - - - - - - - 8.8 USD (0.12) (0.34) 66DCP Midstream Partners LP US 43.0 OW Neu 50.0 16 14.7 12.8 10.0 - - - - - - - - - 6.3 USD 2.32 2.07 12

Eagle Rock Energy Partners LP US 9.12 EW Neu 10.0 10 9.5 9.0 8.6 - - - - - - - - - 9.6 USD 0.11 0.01 957Enbridge Energy Partners US 29.5 EW Neu 32.0 9 11.7 11.7 9.1 - - - 22.1 26.8 19.1 - - - 7.3 USD 1.10 1.04 6

Enduro Royalty Trust US 19.0 OW Neu 23.0 21 - - - - - - 60.3 10.5 10.4 - - - 9.6 USD 1.82 1.80 1Energy Transfer Equity LP US 42.5 OW Neu 50.0 18 - - - - - - - - - - - - 5.7 USD 2.42 1.84 32

Energy Transfer Partners LP US 42.3 EW Neu 53.0 25 10.0 9.3 7.4 - - - - - - - - - 8.5 USD 5.49 1.27 nmEnterprise Products Prtns LP US 52.8 OW Neu 58.0 10 15.3 14.5 13.3 - - - 23.7 22.2 21.1 - - - 4.8 USD 2.38 2.52 -6Exterran Partners LP US 21.8 EW Neu 29.0 33 10.7 9.0 8.4 - - - nm nm 19.7 - - - 9.3 USD 0.11 0.57 -81

Ferrellgas Partners US 18.9 UW Neu 16.0 (15) 11.3 13.7 10.9 - - - nm nm 32.6 - - - 10.6 USD (0.14) (0.16) 10Global Partners LP US 23.8 EW Neu 24.0 1 15.3 10.3 9.3 - - - 27.3 12.5 10.5 - - - 8.7 USD 1.91 1.57 21

Holly Energy Partners LP US 66.9 EW Neu 67.0 0 18.1 13.9 12.3 - - - 23.9 25.1 22.0 - - - 5.5 USD 2.67 2.79 -4Inergy L.P. US 20.9 EW Neu 20.0 (4) 11.9 14.0 17.8 - - - nm nm 23.9 - - - 8.4 USD (0.11) 0.02 nm

Inergy Midstream, L.P. US 22.4 OW Neu 25.0 12 - 17.1 9.8 - - - 0.0 35.9 21.4 - - - 6.7 USD 0.62 0.69 -10Magellan Midstream Partners, LP US 82.0 EW Neu 84.0 2 17.7 16.0 14.5 - - - 23.2 21.0 18.3 - - - 4.6 USD 3.90 3.97 -2

Markwest Energy Partners, LP US 50.9 OW Neu 58.0 14 16.4 14.9 12.2 - - - 0.0 0.0 0.0 - - - 6.3 USD 2.65 2.19 21Memorial Production Partners L.P. US 17.4 EW Neu 21.0 21 - - - - - - 0.0 8.7 11.6 - - - 8.8 USD 2.00 1.70 18

Niska Gas Storage Partners LLC US 12.5 UW Neu 11.0 (12) 8.0 12.1 11.9 - - - nm nm nm - - - 11.2 USD (0.47) (0.14) nmNuStar Energy LP US 51.8 EW Neu 56.0 8 12.5 14.2 11.0 - - - 18.2 31.9 16.7 - - - 8.5 USD 1.63 1.65 -1

Oiltanking Partners LP US 35.9 OW Neu 34.0 (5) 21.0 16.8 14.2 - - - 59.8 22.1 20.2 - - - 4.1 USD 1.63 1.56 4ONEOK Partners LP US 55.6 OW Neu 65.0 17 12.9 13.2 12.5 - - - - - - - - - 4.8 USD 2.92 2.93 -0PAA Natural Gas Storage LP US 18.4 EW Neu 19.0 3 19.3 17.1 16.0 - - - 18.9 18.1 16.5 - - - 7.8 USD 1.02 0.99 3

Pacific Coast Oil Trust US 18.9 OW Neu 22.0 16 - - - - - - 0.0 12.5 9.2 - - - 8.0 USD 1.52 1.53 -1Penn Virginia Resource Partners, L.P. US 24.4 OW Neu 29.0 19 17.6 16.9 9.5 - - - 19.2 45.9 22.2 - - - 8.8 USD 0.53 0.53 0

Plains All American Pipeline US 86.5 OW Neu 92.0 6 12.9 10.8 10.0 - - - 16.5 15.3 15.1 - - - 5.0 USD 5.65 5.65 -0Regency Energy Partners LP US 22.9 OW Neu 26.0 13 16.3 14.8 13.0 - - - - - - - - - 8.0 USD 0.38 0.52 -26

Rose Rock Midstream, L.P. US 27.7 OW Neu 30.0 8 13.1 11.0 7.7 - - - nm 20.5 16.9 - - - 5.6 USD 1.35 1.44 -6Spectra Energy Partners, LP US 32.3 EW Neu 34.0 5 12.6 11.8 10.4 - - - 19.8 19.8 18.1 - - - 6.0 USD 1.63 1.69 -3

Suburban Propane Partners US 37.4 UW Neu 42.0 12 8.8 14.1 4.7 - - - 11.6 56.5 13.1 - - - 9.1 USD 0.66 0.69 -4Sunoco Logistics Partners L.P. US 44.0 EW Neu 44.0 0 11.3 9.4 9.3 - - - 17.3 13.4 15.5 - - - 4.2 USD 3.28 3.40 -3

Targa Resources Partners LP US 40.2 OW Neu 49.0 22 10.2 10.5 9.4 - - - - - - - - - 6.5 USD 1.81 1.70 6TC Pipelines, LP US 45.4 EW Neu 45.0 (1) 11.6 12.5 12.0 - - - 15.0 18.5 18.1 - - - 6.8 USD 2.45 2.61 -6

Tesoro Logistics LP US 42.6 OW Neu 44.0 3 35.6 17.1 9.5 - - - 38.4 22.3 15.2 - - - 3.9 USD 1.91 1.83 4Vanguard Natural Resources US 28.3 OW Neu 32.0 13 - - - - - - 12.2 21.8 16.2 - - - 8.5 USD 1.30 1.37 -5

Western Gas Partners LP US 46.4 OW Neu 52.0 12 18.6 16.0 13.1 - - - - - - - - - 4.2 USD 1.95 1.68 16Williams Partners LP US 50.9 OW Neu 61.0 20 11.4 12.5 11.1 - - - - - - - - - 6.3 USD 2.38 2.46 -3

Average Sector 11 13.8 15.6 10.7 - - - 20.0 21.6 19.1 - - - 7.0 26


Source: Barclays Research. All estimates are as of August 23, 2012. Share prices and target prices are shown in the primary listing currency and EPS estimates are shown in the reporting currency. Stock rating: OW = Overweight; EW = Equal Weight; UW = Underweight. Industry view: Pos = Positive; Neu = Neutral; Neg = Negative


30 August 2012 129

EQUITY VALUATION TABLE – METALS & MINING


Stock Rating

Sector View

Target Price


EPS Currency Barclays EPS 2012F

Consensus EPS 2012F

Difference, %

2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2012F

Metals & MiningAdaro Energy Tbk PT. Asia 1,410 EW Pos 1,700 21 4.2 6.5 5.1 - - - 8.6 13.3 9.6 15.5 (2.4) 12.1 3.4 USD Cents 1.11 2.00 -44AK Steel Holding Corp. US 5.67 OW Pos 7.00 23 5.9 6.7 3.9 - - - nm nm 6.2 (80.0) (47.6) (31.9) 1.8 USD (0.25) (0.21) nm

Alcoa Inc. US 8.63 EW Pos 10.0 16 5.4 7.6 5.0 - - - 12.2 25.4 10.2 9.0 (4.8) 6.0 1.4 USD 0.34 0.29 17Alpha Natural Resources US 6.59 OW Pos 9.00 37 38.5 6.5 6.6 - - - nm nm (4.5) 10.9 (5.1) 6.7 0.0 USD (1.66) (1.33) -25Aluminum Corporation China Asia 3.27 UW Pos 3.00 (8) 13.3 40.8 12.7 - - - nm nm 69.6 (17.5) 1.1 8.5 0.0 RMB (0.30) (0.15) nm

Angang Steel Asia 4.06 EW Pos 7.60 87 9.5 8.6 5.6 - - - nm nm 28.6 0.1 8.2 14.4 0.0 RMB (0.17) (0.19) 12Arch Coal US 6.76 EW Pos 8.00 18 5.8 8.2 7.4 - - - nm nm (49.7) 7.9 (8.7) (6.8) 3.0 USD (0.34) (0.43) vBHP Billiton Asia 33.1 OW Pos 42.0 27 5.1 6.3 5.7 - - - 8.1 10.9 10.8 8.3 3.3 5.4 3.3 USD 3.17 3.19 -1

Bumi Resources Asia 940 EW Pos 1,600 70 5.0 7.8 5.6 - - - nm nm 11.9 24.2 9.4 14.9 0.0 USD Cents (0.35) 1.00 -135Century Aluminum US 6.74 OW Pos 9.00 34 6.2 6.9 3.2 - - - nm nm 9.1 (5.9) 3.1 11.0 0.0 USD (0.21) (0.45) -54

China Coal Energy Asia 6.87 OW Pos 10.1 47 3.8 4.7 4.1 - - - 7.6 8.7 6.9 (3.7) (16.6) (6.5) 3.4 RMB 0.64 0.69 -7China Hongqiao Group Asia 3.60 OW Pos 8.00 122 1.9 2.7 2.0 - - - 2.9 3.4 2.9 18.8 0.8 21.3 7.4 RMB 0.87 0.97 -10China Shenhua Energy Asia 29.5 OW Pos 36.2 23 6.2 6.2 5.8 - - - 10.5 10.9 10.5 2.1 1.9 6.6 3.7 RMB 2.23 2.35 -5

China Steel Corporation Asia 26.1 UW Pos 23.2 (11) 16.0 21.9 15.0 - - - 19.7 45.0 21.9 16.9 5.4 5.8 2.0 TWD 0.58 0.66 -12Cloud Peak Energy US 17.8 UW Pos 17.0 (4) 3.9 5.4 5.9 - - - 7.2 10.0 14.8 2.8 (0.3) 0.1 0.0 USD 1.78 1.80 -1Coal India Limited Asia 359 OW Pos 411 15 13.5 10.8 9.6 - - - 20.9 15.3 13.9 4.6 9.4 1.9 2.8 INR 23.41 23.35 0

CONSOL Energy US 33.0 OW Pos 34.0 3 6.2 8.9 8.9 - - - 10.9 25.6 30.5 1.9 (6.9) (4.2) 1.5 USD 1.29 1.63 -21CST Mining Group Limited Asia 0.11 EW Pos 0.17 55 (10.2) 8.1 (4.3) - - - nm nm 12.5 (31.0) (18.2) 15.0 0.0 USD Cents 0.03 0.00 nm

Freeport-McMoRan US 36.8 OW Pos 63.0 71 3.3 4.6 2.8 - - - 7.6 10.6 6.9 11.6 1.3 9.1 3.4 USD 3.47 3.39 2Harum Energy Asia 6,300 EW Pos 7,000 11 6.4 7.7 6.6 - - - 10.7 12.4 10.6 11.4 8.0 8.7 5.7 USD Cents 5.37 6.20 -13Hindalco Industries US 113 OW Pos 159 40 5.2 6.6 6.4 - - - 9.0 6.4 6.3 (0.0) 0.0 (27.1) 1.6 INR 17.64 16.23 9

Hindustan Zinc US 132 OW Pos 142 7 7.4 6.2 5.5 - - - 11.3 10.0 9.3 6.3 6.0 10.2 2.1 INR 13.18 13.18 0Indo Tambangraya Megah Asia 36,900 OW Pos 42,000 14 5.0 5.7 6.0 - - - 8.0 9.5 10.3 14.3 8.9 10.0 7.9 USD 0.41 0.42 -3

IRC Limited Asia 0.72 OW Pos 1.50 108 140 -322.5 59.1 - - - nm nm (35.0) (60.5) (58.7) (48.1) 0.0 USD Cents (0.73) 0.00 nmJiangxi Copper US 18.5 OW Pos 23.0 24 6.7 6.5 5.3 - - - 8.0 9.7 8.5 13.9 9.0 7.4 2.1 RMB 1.56 2.06 -24Jindal Steel & Power Asia 407 OW Pos 555 36 8.2 7.2 7.5 - - - 10.2 9.5 8.7 (13.3) (7.8) (19.6) 0.4 INR 42.80 42.82 -0

JSW Steel Asia 719 EW Pos 690 (4) 6.4 5.7 5.5 - - - 9.3 30.7 10.2 (12.5) (12.0) (13.0) 2.0 INR 23.43 22.65 3Maanshan Iron & Steel. Asia 1.66 EW Pos 2.70 63 5.5 6.1 4.5 - - - nm nm 12.8 (30.8) 8.0 32.1 0.3 RMB 0.01 -0.07 -116Minmetals Resources Asia 3.15 OW Pos 5.20 65 2.5 3.4 2.2 - - - 6.7 6.1 3.7 20.5 5.5 16.8 0.0 USD 0.07 0.07 -5

National Aluminium Asia 52.3 UW Pos 49.0 (6) 5.2 6.6 6.8 - - - 12.6 15.5 19.0 4.8 6.4 (0.2) 4.8 INR 3.38 3.45 -2NMDC Limited Asia 187 UW Pos 173 (7) 6.6 5.8 4.8 - - - 11.4 10.2 9.4 6.5 2.9 2.1 1.9 INR 18.33 19.74 -7

Noranda Aluminum Holding US 6.35 EW Pos 8.00 26 3.4 7.1 4.7 - - - 6.2 21.5 9.8 17.5 (11.1) 10.4 22.2 USD 0.30 0.27 9Nucor Corporation US 39.1 EW Pos 38.0 (3) 8.0 9.5 6.6 - - - 16.5 22.8 13.5 3.5 (2.9) 7.8 3.7 USD 1.72 1.85 -7Peabody Energy US 22.9 OW Pos 27.0 18 5.7 6.8 6.5 - - - 6.0 12.6 12.8 12.7 1.8 3.4 1.5 USD 1.82 2.07 -12

POSCO Asia 374,500 OW Pos 460,000 23 6.5 7.3 6.0 - - - 7.9 9.7 8.1 (1.1) 4.2 8.4 2.7 KRW 38491 37296 3Sesa Goa Asia 190 UW Pos 176 (8) 1.4 2.7 2.7 - - - 4.0 6.2 8.2 23.6 15.5 15.5 2.1 INR 30.78 31.77 -3Steel Authority of India Asia 84.2 UW Pos 81.0 (4) 4.9 7.7 6.2 - - - 6.9 9.8 7.8 (21.5) (13.2) (13.9) 2.8 INR 8.58 9.20 -7

Steel Dynamics US 12.3 EW Pos 14.0 14 5.7 7.0 4.8 - - - 9.8 16.2 8.8 11.2 2.8 12.9 3.2 USD 0.76 0.87 -13Stillwater Mining US 10.6 OW Pos 15.0 41 6.5 15.4 11.7 - - - 8.4 55.4 28.8 9.2 (4.3) (6.8) 0.0 USD 0.19 0.32 -40

Tata Steel Limited Asia 399 OW Pos 532 33 5.5 7.6 5.5 - - - 5.7 19.1 7.7 (16.3) (18.5) 5.9 3.5 INR 20.88 20.18 3TB Bukit Asam Asia 14,950 OW Pos 18,500 24 7.5 7.5 5.4 - - - 11.2 10.9 8.5 9.5 10.0 7.8 5.5 IDR 1372 1467 -6UC Rusal Asia 4.35 EW Pos 5.00 15 7.3 18.5 8.8 - - - 36.0 13.2 5.1 13.8 1.5 11.9 0.0 USD 0.04 0.06 -29

United States Steel US 21.2 EW Pos 23.0 9 8.3 5.4 4.7 - - - nm 13.7 8.8 (22.3) 9.0 7.4 0.9 USD 1.55 1.55 -0Yanzhou Coal Mining Asia 11.7 OW Pos 17.9 53 4.2 5.5 5.3 - - - 5.3 7.4 7.8 19.9 (1.8) 4.5 4.1 RMB 1.29 1.41 -8

Average Sector 28 9.6 0.7 7.0 - - - 10.2 15.2 9.8 0.4 (2.2) 3.3 2.7 -14




30 August 2012 130

EQUITY VALUATION TABLE – DIVERSIFIED NATURAL GAS


Stock Rating

Sector View

Target Price


EPS Currency

Barclays EPS 2012F

Consensus EPS 2012F

Difference, %

2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2012F

Diversified Natural GasAGL Resources Inc. US 39.2 EW Neu 41.0 5 12.8 6.7 6.3 - - - 14.3 15.2 13.2 - - - 4.7 USD 2.58 2.66 -3Atmos Energy US 35.2 EW Neu 36.0 2 7.7 7.2 7.1 - - - 15.3 15.0 14.2 - - - 3.9 USD 2.34 2.29 2Enbridge Inc US 39.5 OW Neu 45.0 14 14.1 15.7 12.7 - - - 26.7 24.5 21.8 - - - 2.9 CAD 1.61 1.63 -1Energen Corp US 51.2 EW Neu 54.0 5 6.5 5.4 5.2 - - - 13.1 14.5 12.4 - - - 1.1 USD 3.54 3.58 -1EQT Corporation US 54.4 OW Neu 65.0 19 9.9 10.9 7.9 - - - 24.6 35.8 22.6 - - - 1.6 USD 1.52 1.52 0MDU Resources Group US 21.8 EW Neu 23.0 6 10.9 11.1 10.5 - - - 18.2 18.7 16.7 - - - 3.1 USD 1.16 1.14 2

National Fuel Gas US 49.2 EW Neu 52.0 6 7.0 7.8 7.1 - - - 18.2 20.3 18.5 - - - 3.0 USD 2.42 2.46 -2New Jersey Resources US 45.3 UW Neu 46.0 1 13.5 17.6 13.9 - - - 18.1 16.5 17.4 - - - 3.4 USD 2.75 2.72 1ONEOK Inc US 44.3 OW Neu 48.0 8 9.2 9.3 8.0 - - - 26.4 25.7 21.6 - - - 2.9 USD 1.72 1.69 2Piedmont Natural Gas Co US 31.3 UW Neu 32.0 2 - - - - - - 19.9 19.7 17.6 - - - 0.0 USD 1.59 1.58 1Questar Corp US 19.8 EW Neu 20.0 1 8.6 8.4 8.3 - - - 17.0 17.0 16.0 - - - 3.3 USD 1.16 1.18 -2Southwest Gas Corp US 42.3 UW Neu 42.0 (1) 7.1 6.5 6.3 - - - 17.4 15.2 15.4 - - - 2.7 USD 2.79 2.70 3Spectra Energy US 28.8 OW Neu 31.0 7 7.4 8.6 7.7 - - - 16.2 19.2 16.5 - - - 4.0 USD 1.50 1.60 -6WGL Holdings US 39.7 UW Neu 42.0 6 8.2 8.3 7.8 - - - 17.6 15.7 15.0 - - - 3.9 USD 2.53 2.50 1

Williams Cos US 31.9 OW Neu 38.0 19 13.4 15.6 13.2 - - - 26.0 27.7 22.9 - - - 3.8 USD 1.15 1.19 -3

Average Sector 7 9.7 9.9 8.7 - - - 19.3 20.0 17.5 - - - 2.9 -0




30 August 2012 131

EQUITY VALUATION TABLE – POWER & UTILITIES


Stock Rating

Sector View

Target Price


EPS Currency

Barclays EPS 2012F

Consensus EPS 2012F

Difference, %

2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2012F

PowerAES Corp US 11.4 OW Neu 15.0 32 6.0 5.7 5.3 - - - 10.9 9.3 9.1 5.1 20.7 19.7 0.4 USD 1.22 1.23 -1Ameren Corp US 33.2 EW Neu 34.0 3 6.9 6.5 6.8 - - - 12.9 13.5 15.9 5.9 (2.6) (4.4) 4.8 USD 2.46 2.44 1

Calpine Corp. US 17.8 EW Neu 19.0 7 10.2 10.3 9.2 - - - nm nm 34.9 1.1 1.6 5.3 0.0 USD 0.15 0.31 -52Covanta Holding US 17.7 OW Neu 20.0 13 8.8 8.1 7.7 - - - 33.7 27.8 23.2 9.0 10.6 10.2 3.4 USD 0.64 0.58 10Exelon Corp US 36.9 EW Neu 40.0 9 6.7 7.7 7.5 - - - 8.9 13.4 13.5 (2.4) (9.8) (8.0) 5.7 USD 2.75 2.76 -0FirstEnergy Corp US 44.9 EW Neu 45.0 0 8.6 7.3 7.8 - - - 13.0 13.0 15.1 (0.5) 2.4 (0.3) 4.9 USD 3.44 3.36 2GenOn Energy US 2.53 OW Neu 3.00 19 6.4 10.8 6.9 - - - nm nm nm (9.5) (28.5) (0.9) 0.0 USD (0.23) (0.35) 33NextEra Energy US 67.4 OW Neu 75.0 11 10.0 10.2 9.1 - - - 15.4 14.9 13.8 (7.5) (17.3) (1.8) 3.6 USD 4.51 4.54 -1

NRG Energy US 21.2 OW Neu 24.0 13 7.3 6.8 5.5 - - - 36.0 16.2 20.2 (22.4) 11.1 13.7 0.8 USD 1.31 0.98 33Ormat Technologies US 20.3 UW Neu 18.0 (11) 10.5 10.4 8.6 - - - nm 44.2 24.5 (15.5) (15.9) 10.5 0.6 USD 0.46 0.60 -23PPL Corporation US 29.1 EW Neu 30.0 3 8.8 8.4 8.1 - - - 10.7 12.4 12.2 (4.5) (12.3) (13.4) 4.8 USD 2.34 2.35 -0Public Service Enterprise US 31.9 EW Neu 32.0 0 6.3 6.9 7.2 - - - 11.6 13.4 13.7 7.8 (0.0) (4.3) 4.4 USD 2.39 2.40 -0

Average Sector 8 8.1 8.3 7.5 - - - 17.0 17.8 17.8 (2.8) (3.3) 2.2 2.8 0UtilitiesCentrica EU 323 UW Neu 260 (20) 6.6 5.7 5.2 - - - 12.5 12.2 11.8 13.9 3.7 6.2 5.0 GBp 26.43 26.87 -2Drax Group EU 462 OW Neu 695 50 5.9 6.5 10.2 - - - 8.3 9.2 20.3 9.1 (2.2) 0.1 5.4 GBp 49.98 49.71 1E.ON EU 17.9 UW Neu 16.0 (10) 8.8 7.2 7.0 - - - 13.6 7.8 10.7 0.3 6.5 5.9 6.2 EUR 2.28 2.06 11Enagas SA EU 14.8 OW Neu 15.7 6 8.0 7.4 6.7 - - - 9.6 9.3 8.5 0.4 0.2 10.7 7.0 EUR 1.59 1.55 3Endesa S.A. EU 13.6 OW Neu 17.0 25 4.8 5.2 4.8 - - - 6.8 7.7 7.4 13.6 12.4 16.8 4.4 EUR 1.76 1.84 -5Enel SpA EU 2.53 EW Neu 3.00 19 5.7 5.9 5.5 - - - 5.3 6.5 6.4 21.1 16.6 21.2 6.1 EUR 0.39 0.37 5

Fortum Oyj EU 14.0 EW Neu 15.1 8 8.0 8.0 7.1 - - - 10.7 10.2 9.6 3.8 4.5 18.0 7.1 EUR 1.37 1.39 -1Gas Natural SDG SA EU 10.2 EW Neu 12.5 23 6.6 6.4 6.2 - - - 7.7 9.0 8.8 22.2 14.0 10.7 7.3 EUR 1.12 1.30 -14GDF Suez SA EU 19.6 EW Neu 20.0 2 6.3 6.4 5.8 - - - 13.1 11.8 10.6 7.7 6.7 8.8 7.8 EUR 1.66 1.61 3Iberdrola SA EU 3.12 UW Neu 3.60 15 7.1 7.0 6.7 - - - 6.7 7.0 7.1 0.7 11.7 5.9 9.0 EUR 0.45 0.45 -1National Grid Plc EU 686 OW Neu 720 5 9.8 10.2 9.5 - - - 13.2 13.4 12.5 (1.7) (2.3) (4.9) 5.7 GBp 51.33 54.90 -6Pennon Group Plc EU 739 OW Neu 870 18 11.4 11.1 10.7 - - - 15.3 17.4 16.2 3.8 (0.7) (1.1) 3.6 GBp 42.52 46.40 -8

Red Electrica Corporacion EU 34.1 EW Neu 37.0 9 7.7 8.0 7.1 - - - 10.0 11.4 10.0 4.0 (1.6) 1.9 6.5 EUR 3.00 3.57 -16Redes Energeticas Nacionais EU 2.01 EW Neu 2.50 24 7.8 6.6 5.7 - - - 9.4 7.7 7.4 (16.5) (14.1) (13.2) 8.7 EUR 0.26 0.27 -4RWE EU 32.4 EW Neu 32.0 (1) 7.2 7.0 6.5 - - - 7.1 8.2 8.1 (4.8) 0.4 2.8 6.2 EUR 3.97 4.05 -2Seche Environnement SA EU 26.7 UW Neu 20.0 (25) 2.9 4.7 4.6 - - - 14.1 12.9 11.8 24.5 29.2 30.9 4.9 EUR 2.07 1.85 12Severn Trent Plc EU 1,726 EW Neu 1,695 (2) 10.3 10.5 10.0 - - - 16.3 20.5 16.8 3.2 2.3 3.1 4.1 GBp 84.18 101.10 -17Snam Rete Gas SpA EU 3.29 OW Neu 3.85 17 8.6 8.9 8.7 - - - 11.3 12.0 11.7 (8.4) (8.5) (5.9) 7.6 EUR 0.28 0.28 -1

SSE PLC EU 1,345 OW Neu 1,585 18 8.3 8.5 8.0 - - - 12.0 11.9 11.3 3.0 4.8 0.0 6.0 GBp 112.7 115.60 -3Suez Environnement EU 8.98 EW Neu 9.00 0 6.0 6.2 6.3 - - - 19.3 19.1 16.6 36.6 35.5 35.9 7.2 EUR 0.47 0.65 -28Terna SpA EU 2.75 OW Neu 3.05 11 9.1 8.8 8.8 - - - 12.0 12.8 12.5 (11.0) (13.5) (10.8) 6.9 EUR 0.22 0.21 2United Utilities Group EU 708 UW Neu 665 (6) 11.1 11.2 10.9 - - - 20.2 20.1 18.8 3.4 (1.3) 0.1 4.5 GBp 35.30 40.20 -12Veolia Environnement EU 8.44 OW Neu 12.5 48 6.1 6.0 5.4 - - - 14.5 12.1 9.2 50.9 49.8 51.9 8.3 EUR 0.70 0.56 24Verbund EU 16.4 EW Neu 21.0 28 9.4 7.8 8.4 - - - 17.2 10.9 10.3 (5.1) 4.0 5.6 4.1 EUR 1.51 1.20 26

Average Sector 11 7.6 7.5 7.3 - - - 11.9 11.7 11.4 7.3 6.6 8.3 6.2 -1




30 August 2012 132

EQUITY VALUATION TABLE – CLEAN TECHNOLOGY & RENEWABLES


Stock Rating

Sector View

Target Price


EPS Currency

Barclays EPS 2012F

Consensus EPS 2012F

Difference, %

2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2011A 2012F 2013F 2012F

Clean Technology & RenewablesA123 Systems US 0.36 EW Neu 1.00 178 nm nm nm - - - nm nm nm (767) (604) (245) 0.0 USD (2.13) (2.04) -4Abengoa EU 13.1 EW Pos 17.0 29 6.2 6.6 5.7 - - - 5.5 5.2 3.6 (58.2) (128) 4.7 3.5 EUR 2.52 1.61 57Acciona EU 37.8 UW Pos 29.0 (23) 7.8 7.6 7.5 - - - 11.9 17.2 16.5 6.0 (6.2) (8.9) 4.7 EUR 2.20 2.71 -19Alerion Cleanpower EU 3.50 EW Pos 4.00 14 11.8 9.9 7.6 - - - 19.3 79.5 12.0 19.3 74.4 77.8 3.1 EUR 0.04 0.15 -71Ameresco US 12.0 OW Neu 14.0 17 10.4 10.1 7.3 - - - 15.9 17.7 13.3 - - - 0.0 USD 0.68 0.69 -2Centrotherm PVs EU 1.19 EW Neu 6.00 404 nm 2.6 1.4 - - - nm nm 6.2 (618) (85.0) 5.0 0.0 EUR (0.28) (1.06) 74EDP Renovaveis EU 2.83 EW Pos 4.00 41 7.5 6.7 6.1 - - - 27.7 19.1 13.7 21.3 (2.5) 2.1 0.0 EUR 0.15 0.15 -1Elster Group US 20.5 EW Neu 20.5 0 5.0 5.2 4.7 - - - 16.8 18.5 15.4 8.1 1.8 8.0 0.0 USD 1.11 1.14 -3Enel Green Power EU 1.27 OW Pos 2.00 57 5.7 5.9 5.6 - - - 15.5 13.7 11.9 (8.4) (7.8) (5.0) 2.7 EUR 0.09 0.09 4First Solar US 24.6 EW Neu 18.0 (27) 4.0 10.4 2.3 - - - 4.4 5.7 6.2 0.0 0.0 0.0 0.0 USD 4.35 4.47 -3Gamesa Corporacion EU 1.41 OW Pos 3.00 113 3.7 3.3 2.8 - - - 6.7 9.1 5.1 (244) 11.9 16.2 1.9 EUR 0.16 (0.05) nmGCL-Poly Energy Holdings EU 1.19 EW Neu 2.30 93 4.5 8.8 7.4 - - - 4.3 30.5 13.2 (88.4) (19.4) (3.5) 0.7 HKD 0.04 0.01 294GT Advanced Technologies US 6.36 EW Neu 7.00 10 2.3 3.2 2.3 - - - 4.9 4.8 4.7 - - - 0.0 USD 1.32 1.32 -0Gurit Holding EU 428 EW Pos 480 12 5.3 4.3 3.4 - - - 8.1 8.1 7.4 (18.5) 0.4 17.1 3.5 CHF 52.78 52.65 0Itron US 44.2 EW Neu 42.0 (5) 6.8 7.5 6.9 - - - 10.3 11.6 11.7 3.2 13.0 9.6 0.0 USD 3.80 3.83 -1Johnson Matthey EU 23.6 OW Pos 27.5 16 11.6 9.8 9.8 - - - 18.6 15.1 15.7 (2.1) (0.1) (0.3) 6.6 GBP 1.56 1.61 -3Manz EU 20.5 EW Neu 24.6 20 nm 13.9 10.8 - - - nm nm nm (51.4) (20.1) 15.4 0.0 EUR 1.23 0.91 35Mersen EU 22.1 EW Pos 28.0 27 3.2 3.3 2.9 - - - 7.5 7.2 6.1 (1.7) 14.0 10.7 0.0 EUR 3.07 2.50 23Meyer Burger Technology EU 14.6 EW Neu 15.0 3 1.5 11.8 5.3 - - - nm nm 34.6 (15.4) (15.0) 13.6 0.0 CHF (0.22) (0.91) 76Nordex EU 3.10 EW Pos 4.50 45 89.3 5.6 6.2 - - - nm 18.3 19.3 (35.8) (27.8) 4.0 0.0 EUR 0.17 0.06 nmOCI Co EU 198,000 EW Neu 175,000 (12) 3.8 6.7 5.7 - - - 5.5 18.6 15.8 - - - 0.0 KRW 10637 10692 -1Outotec EU 38.5 OW Pos 60.0 56 12.7 8.5 7.7 - - - 21.9 13.5 12.6 12.2 3.6 3.5 3.0 EUR 2.84 2.76 3Phoenix Solar EU 0.98 EW Neu 3.00 206 nm (0.3) (0.7) - - - nm 1.0 0.8 710 211 84.7 (17.2) EUR 1.03 (0.33) nmPower-One US 6.11 OW Neu 7.00 15 2.2 2.0 1.3 - - - 7.0 10.2 9.6 0.0 0.0 0.0 0.0 USD 0.60 0.61 -2Prysmian EU 13.2 OW Pos 16.0 21 20.4 6.7 5.5 - - - nm 10.5 8.3 (1.3) 6.0 9.6 2.6 EUR 1.25 1.32 -5PV Crystalox Solar EU 0.08 EW Neu 0.04 (50) nm nm nm - - - nm nm nm (15.4) 7.2 6.5 (4.6) EUR (0.02) (0.07) 73Renewable Energy Corp EU 1.80 EW Neu 3.25 81 0.7 4.5 4.1 - - - nm nm nm 131.6 143.7 48.7 0.0 NOK (0.37) (0.60) 39Saft Groupe EU 19.9 EW Pos 23.5 18 5.1 5.2 4.4 - - - 9.8 11.9 9.9 8.8 (2.0) 1.2 2.9 EUR 1.68 1.85 -9SMA Solar Technology EU 26.6 EW Neu 30.0 13 2.0 3.6 4.4 - - - 5.5 10.3 17.0 0.6 (8.4) 3.4 2.6 EUR 2.58 2.35 10SolarWorld EU 1.13 EW Neu 2.50 121 4.2 5.8 5.7 - - - nm 20.5 18.5 (210) (10.2) 17.6 7.9 EUR 0.06 (1.22) -105Suzlon Energy EU 16.6 EW Pos 20.0 21 12.6 6.0 4.6 - - - nm nm 4.9 (2.0) 0.1 0.2 0.0 INR 2.17 (0.26) nmTerna Energy EU 1.22 UW Pos 1.50 23 5.6 5.4 5.7 - - - 16.9 10.6 8.9 51.7 57.6 54.8 3.0 EUR 0.12 0.16 -28Tesla Motors US 30.7 OW Neu 38.0 24 nm nm 26.5 - - - nm nm 43.7 (9.3) (5.9) (6.0) 0.0 USD (2.70) (2.66) -1Trina Solar US 5.13 EW Neu 5.00 (3) nm nm (90.1) - - - nm nm nm - - - 0.0 USD (2.32) (1.51) -54Umicore EU 38.5 OW Pos 51.5 34 7.7 8.2 7.1 - - - 13.4 13.7 11.8 4.4 0.2 1.2 2.5 EUR 2.80 2.53 11Vestas Wind Systems EU 33.4 EW Pos 47.0 41 4.9 3.9 2.9 - - - nm nm 5.1 6.8 (52) (5.4) 0.0 EUR 0.33 0.12 nmWacker Chemie EU 53.0 EW Neu 73.5 39 3.3 4.9 4.6 - - - 7.8 14.9 27.8 (8.9) (25.9) 9.1 1.3 EUR 3.55 3.06 16Yingli Green Energy US 2.05 EW Neu 2.00 (2) nm nm 17.5 - - - nm nm nm - - - 0.0 USD (1.20) (1.06) 13

Average Sector 44 9.1 6.3 3.4 - - - 11.5 15.4 12.9 (35.5) (14.4) 4.6 0.8 13




30 August 2012 133

APPENDIX

Valuation Methodology and Risks for Key Overweights

Americas Integrated Oil

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 Barclays Research Price Target: Our earnings estimates are based on Barclays Research's current commodity price assumptions, including oil & gas prices, refining and marketing margins as well as chemical product margins. Thus, results will be subject to change 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.


Asia ex-Japan Metals & Mining

China Coal Energy Co., Ltd. (1898 HK / 1898.HK)

Valuation Methodology: Our 12-month price target of HK$10.1 for China Coal Energy is based on our base case NPV of HK$10.1/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 Barclays Research 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. A further risk to the company comes from potentially lower washing yields at Pingshuo mine.

Indo Tambangraya Megah Tbk PT. (ITMG IJ / ITMG.JK)

Valuation Methodology: We set our TP for ITMG at our base case NPV valuation of IDR42,000/share through a DCF methodology, using a WACC of 10.5% and Terminal Growth Rate of 2%. We believe this best captures the heavy capital intensity and longer dated nature of mining business involving operations at multiple geographies with different mine lives, growth programmes with long lead times and volatility in commodity prices. Near term earnings-based multiples are less useful due to the highly volatile nature of commodity prices (and earnings are levered on the commodity prices).

Risks which May Impede the Achievement of the Barclays Research Price Target: In addition to the top-down risk in the form of volatility in commodity prices, general cost inflation and taxation and resource nationalism, there are several other organisation specific risks which can have a material impact on our valuations. These include operational and production delivery risks at current operations and execution risks in major projects involving sizable cash outflows upfront. We quantify some of these key risks in our upside and downside case valuations for 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 Barclays Research 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.


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Keppel Corp. (KEP SP / KPLM.SI)

Valuation Methodology: Our 12-month price target of S$13.30 for Keppel is derived from our sum-of-the parts valuation because Keppel has a diversified business model with four main segments: offshore & marine (rig building), property, infrastructure and investments. We use a target P/E of 18x to value the company's rig-building business, which is a premium to SembMarine's historical average P/E of 16x, and current market values to value the company's listed-subsidiaries. We have also tested our valuation for Keppel's offshore and marine business using a DCF-based methodology, and our terminal value is then taken on a WACC-g basis assuming 4% long-term growth. Our discount rate used is 9%. The valuation using both methods is checked against historical trading multiples for our Global Oil Services coverage.

Risks which May Impede the Achievement of the Barclays Research Price Target: All our estimates are based on Barclays Global 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 outcomes. 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 Keppel Corp specifically profitability can change significantly with the changes in labour laws in countries where the company operates; delays to equipment delivery, changes to policy within the real estate sector and lower oil industry spending which may impact rig orders.

Sembcorp Marine (SMM SP / SCMN.SI)

Valuation Methodology: Our 12-month price target of S$7.00 for Sembcorp Marine is derived from our sum-of-the-parts valuation. We have assigned a target P/E of 18x for 2012E for the company's rig-building, conversion and ship repair business, which is a premium to the company's 10-year average P/E of 16x . We value the company's stake in COSCO's shipyard group and COSCO Corp at their respective market values. We have tested our valuation using a DCF-based methodology with our terminal value taken on a WACC-g basis assuming 4% long-term growth. Our discount rate is 9%. The valuation using both methods is checked against historical trading multiples with our Global Oil Services coverage.

Risks which May Impede the Achievement of the Barclays Research Price Target: All our estimates are based on Barclays Global 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 outcomes. 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 Sembcorp Marine specifically profitability can change significantly with the changes in labour laws in countries where the company operates; delays to equipment delivery and lower oil industry spending which may impact rig orders.

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 $48.30 per share (with a target multiple of 1.2x) and a premium 2013 EV/DACF multiple of 10.0x (2013E DACF: $624mn).

Risks which May Impede the Achievement of the Barclays Research Price Target: Our cash flow estimates are predicated on a natural gas price forecast of C$2.20-2.85/mcf and an oil price forecast of US$93-95/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 $41.20 per share (with a target multiple of 1.2x), and a 2013 EV/DACF multiple of 9.8x (2013E DACF: $1,783mn).


PetroBakken Energy Ltd. (PBN CT / PBN.TO)

Valuation Methodology: Our price target is based on our going concern NAV of $16.00 per share (with a target multiple of 1.0x) and a 2013 EV/DACF multiple of 5.0x (2013E DACF: $940mn).


European Clean Technology & Sustainability: Energy Efficiency

Outotec Oyj (OTE1V FH / OTE1V.HE)

Valuation Methodology: Our EUR60.0 Price Target is derived from our Renewables Valuation Model assuming a high growth period of 5 years, sales growth of 10.7%, capital employed growth of 36.0%, and return on sales of 10.0%. We assume normalised growth of 2.0%, long term return on sales of 7.5%, and pre-tax WACC of 13.3%. Our Barclays Capital Renewables Valuation Model assumes a two-stage growth period. The first period recognises 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 normalised 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 normalised level. Together,


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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 analysing 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 Barclays Research Price Target: The company may see a 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.

Umicore SA (UMI BB / UMI.BR)

Valuation Methodology: Our EUR 51.50 Price Target is derived from our Renewables Valuation Model assuming a high growth period of 3 years, sales growth of 3.5% capital employed growth of 9.5% and return on sales of 15.5%. We assume normalised growth of 3.0% long term return on sales of 18.0% and pre-tax WACC of 16.4%.

Risks which May Impede the Achievement of the Barclays Research 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 Barclays Research 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 Barclays Research 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.

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 Barclays Research 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.


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Tullow Oil (TLW LN / TLW.L)

Valuation Methodology: In valuing each individual stock, we have used a risk-based methodology which aims at finding the Net Asset Value through a bottom-up approach. We have grouped 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 have named the risk factors applied to the E&A assets 'Chance of Success’ (CoS), as commonly known within the industry. They reflect 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 have applied an industry standard 10% discount rate.

Risks which May Impede the Achievement of the Barclays Research 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 Tullow, we believe additional delays in the approval of pre-emption rights in Uganda by local authorities could have a negative impact on its share price performance.

European Oil Services & Drilling

Hunting (HTG LN / HTG.L)

Valuation Methodology: Our price target for Hunting has been derived from a DCF-based methodology. We have used our forecasted cash flows for the 2012-2014F period and thereafter assumed a cyclical growth (20% 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 20% premium to DCF, in line with 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 Barclays Research 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 outcomes. All estimates assume no marked changes in the current political landscape.

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 2012-2014F period and thereafter assumed a cyclical growth (20% pa) until a turn in 2015 when revenues fall (20% pa) until 2017. Margins used for 2015-17F 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 Barclays Research 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.

Polarcus (PLCS NO / PLCS.OL)

Valuation Methodology: Our price target for Polarcus has been derived from a DCF-based methodology. We have used our forecasted cash flows for the 2012-2014F 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 12%, ahead of the 10% that we use for the sector to account for the volatility seen in Norwegian-listed stocks, the extreme cyclicality seen in the seismic industry and the low market capitalization of the stock. The valuation is then checked against historical trading multiples.

Risks which May Impede the Achievement of the Barclays Research 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 Polarcus 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.

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 2012-2014F 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 Barclays Research 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


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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 forecast cash flows for the 2012-2014F 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 oline 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 Barclays Research 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 outcomes. 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 Oil's shares is derived using a perpetuity valuation approach, using a 15% discount rate. Our calculation is based on our 2012 cash flow forecasts which comprise both dollar and local currencies. Our price target is set in local currency. Risks which May Impede the Achievement of the Barclays Research 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 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 Barclays Research 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.

Drax Group (DRX LN / DRX.L)

Valuation Methodology: We value Drax based on a DCF valuation model and a steady-state discounted EV/EBITDA. We assume a 8.0% post-tax WACC and mark our commodity price assumptions to market. Our central scenario assumes that Drax converts to 50% biomass co-firing by 2016, with biomass costs at £8/GJ on average, with a recovery in UK spark spreads to £11/MWh. Our steady state EV/EBITDA applies a 6.0x multiple to 2016E earnings and discounts back to 2012. Our price target is broadly the average of these approaches. Risks which May Impede the Achievement of the Barclays Research Price Target: Drax is a risky stock and several uncertainties remain, which could trigger both upside and downside risks: 1) future Government power market and renewable policy; 2) the level of capex required to convert the plant; 3) technical uncertainties, including the impact of conversion on thermal efficiency adn capacity; 4) capital structure; 5) biomass availability and price; 6) the overall level of power prices. Drax's DCF is highly sensitive to these assumptions.

Snam Rete Gas SpA (SRG IM / SRG.MI)

Valuation Methodology: We value Snam RG using an adjusted RAB base methodology. The value associated with outperformances vs the Regulatory Asset Base is based on a DCF methodology (average cost of capital 4.8% in the 2010-2014 period). In particular, we include extra value coming from extra remunerated investments, from the financial structure, from cost cutting and from fiscal payments. Net debt and other liabilities are at book value.

Risks which May Impede the Achievement of the Barclays Research Price Target: Snam RG profits and valuation are sensitive to changes in the regulatory framework and partially to the level of gas volumes.

SSE (SSE LN / SSE.L)

Valuation Methodology: We value SSE using a SOTP based on divisional DCF models. We assume a 5.0% long-term retail margin and marked-to-market commodity prices. We use a post-tax nominal WACC of 7.0%.

Risks which May Impede the Achievement of the Barclays Research Price Target: SSE's power generation business is exposed to spark spreads, dark spreads and absolute power prices. These could drive both upside and downside to the shares. SSE's network assets are exposed to UK RPI, and have upcoming regulatory reviews which could alter returns. SSE's balance sheet is relatively stretched which could impede future investments. SSE's UK supply business is at risk should aggressive price competition break out.


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Veolia Environnement (VIE FP / VIE.PA)

Valuation Methodology: We value Veolia based on an average between a DCF, a SOtP and an economic value added approach. Our SOtP approach is mainly based on peer comparison multiples for the water and waste divisions and an average historical transaction ratio for energy services segment (EV/EBITDA of 6x). financial assets and discountinued operations (50% stake in VTD, UK regulated water and US solid waste activities) correspond to the value at balance sheet at end-2011. We value minority shareholdings using a 13x exit PE. as regards to oujr DCF valuation, we assumed a 5.84% WACC (8% market premium, 3% risk-free rate, 1.13x Beta relative to the CAC40 and 2.8% spread), a 4.4% EBIT CAGR and 1.8% long-term growth rate.

Risks which May Impede the Achievement of the Barclays Research Price Target: Risks to our 1-OW rating: 1) further decline in the macro backdrop; 2) management failure to deliver on strategy commitments; 3) higher than expected French contract renewal rate; 4) relevraging rather than paying down debt.

Israel Oil & Gas: E&P

Isramco Negev 2 LP (ISRAL IT / ISRAp.TA)

Valuation Methodology: We use a sum of the parts valuation which values each of the reserves individually using a 10% discount rate. We value Tamar at $7.8b and then multiple the NPV by the working intetest.

Risks which May Impede the Achievement of the Barclays Research Price Target: Changes to the local tax regime and volitility of the natural gas market may have a negative impact on our forecasts.

Ratio Oil Exploration (RATIL IT / RATIp.TA)

Valuation Methodology: We use a sum of the parts valuation which values each of the reserves individually using a 10% discount rate. Levithan is divided into two projects a) Leviathan gas whose NPV is $7.1bn and on which we apply a 80% chance of success b) Leviathan Oil whose NPV is $7.7bn and COS is 12%.

Risks which May Impede the Achievement of the Barclays Research Price Target: Changes to the local tax regime, international disputes over the location of Leviathan and volitility of the natural gas market may have a negative impact on our forecasts.

North America Metals & Mining

CONSOL Energy (CNX)

Valuation Methodology: Our $34 price target is based on a 8.4x EV multiple of our 2013 EBTIDA estimate of $1.3B.

Risks which May Impede the Achievement of the Barclays Research 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)

Valuation Methodology: Our $27 price target is based on a 7.0x EV multiple of our 2013 EBTIDA estimate of $1.9B.

Risks which May Impede the Achievement of the Barclays Research 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 $138 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 $90.00/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 Barclays Research 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 $119 is derived by applying a 7.80x 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 $90.00/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 Barclays Research 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.


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North America Utilities

American Electric Power (AEP)

Valuation Methodology: Our price target is $47, which reflects a regulated group utility multiple of 14.5x our 2014 EPS estimate of $3.25.

Risks which May Impede the Achievement of the Barclays Research Price Target: Key risks include wholesale commodity prices, state and federal regulation, interest rates, and asset sale execution.

Edison International (EIX)

Valuation Methodology: Our price target is $50 which is an average regulated utility P/E multiple of 14x our $3.53 2014 EPS.

Risks which May Impede the Achievement of the Barclays Research Price Target: Risks to the outlook include wholesale commodity prices, generation development market conditions, the outcome of regulatory proceedings, rating agency actions, foreign currency translation, interest rates, and access to the capital markets.

U.S. Clean Technology & Renewables

Ameresco Inc. (AMRC)

Valuation Methodology: Our price target of $14 equates to ~15x our CY13 EPS estimate of $0.09

Risks which May Impede the Achievement of the Barclays Research Price Target: Weak end 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 Ameresco's inability to secure financing could materially impact its ability to deliver energy savings solutions.

Power-One Inc. (PWER)

Valuation Methodology: Our $7 price target equates to ~11x our CY13 EPS estimate of $0.64.

Risks which May Impede the Achievement of the Barclays Research 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 ~16x our CY14 EPS estimate of $2.38, equating to 53x our CY13 EPS estimate of $0.70.

Risks which May Impede the Achievement of the Barclays Research 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. Display & Lighting

Veeco Instruments Inc. (VECO)

Valuation Methodology: Our $45 price target is based on 11x our normalized EPS of ~$4.00 or 14x our CY13 EPS plus net cash per share of ~$14.

Risks which May Impede the Achievement of the Barclays Research Price Target: 1) Veeco's market share declines as Aixtron's next generation tools gain share in Veeco's core accounts. 2) China's central government halts MOCVD tool subsidies, thereby curtailing MOCVD demand out of China. 3) Aggressive capacity additions by Chinese manufacturers and/or improved production yields contribute to a substantial LED oversupply, driving a fall-off in MOCVD demand. 4) LED penetration into general lighting takes longer than anticipated.

U.S. Diversified Natural Gas

EQT Corporation (EQT)

Valuation Methodology: Our price target of $65 is based on shares trading at 100% of our NAV analysis using 2013 EBITDA multiples of 8.5x for the utility, 12x for midstream, and 7x for E&P.

Risks which May Impede the Achievement of the Barclays Research Price Target: Gas price exposure is extensively hedged resulting in in rollover risk over the long term. Earnings are seasonal and tied to the severity of winter weather. Regulated operations are subject to prudency review of costs and capital investments plus are granted returns which correlate with the level of interest rates. Performance contracting results are back-end loaded and subject to execution risks.

ONEOK Inc. (OKE)

Valuation Methodology: Our price target of $48 is predicated on a weighted average of four valuation metrics: 1) 2013e EPS of $2.05 and P/E multiple of 17.5x, 2) 2013e dividend of $1.50 and yield of 3.2%, 3) EV/EBITDA of 9.5x, and 4) NAV of $65.

Risks which May Impede the Achievement of the Barclays Research Price Target: OKE has a 42.8% ownership interest in OKS, a natural gas distribution business where results are tied to regulatory approvals of current and future rate relief requests, and Energy Services where results are impacted by natural gas prices, basis differentials and costs of obtaining storage and pipeline capacity.


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Targa Resources Corp. (TRGP) Valuation Methodology: Our price target of $52 is based on a 12-month distribution run rate of $1.96 and target yield of 3.75%.

Risks which May Impede the Achievement of the Barclays Research Price Target: The underlying MLP is long NGL, crude and gas, and therefore margins and volumes have a positive relationship with commodity prices. The NGL downstream business (35% of total) is exposed to petchem and refinery demand, which can be affected by U.S. and global economic growth. Lastly TRGP growth is dependent on NGLS's ability to access the equity capital market to fund growth on a regular basis.

Williams Cos. (WMB)

Valuation Methodology: Our price target of $38 is based on a 12-month dividend run rate of $1.32 and a target yield of 3.5%. Risks which May Impede the Achievement of the Barclays Research Price Target: Rising interest rates, a sharp drop in commodity prices, and the underlying MLP's ability to successfully increase cash distributions at our forecasted rate.

U.S. Independent Refiners

Tesoro Corporation (TSO) Valuation Methodology: We value TSO on a discounted Price/Tangible Book value basis. Our 2015 forecast book value for Tesoro is $48.4/share, to which we apply a 2.2x multiple, a discount to historic cycle peak valuation multiples. To this we add estimated cumulative cash return per share over the 2012 -2015 time period of $5.1/share to arrive at an estimated equity value of $111/share. We then discount to 2013 using a 10% discount rate to arrive at an estimated fair value price target of $84/share.


Valero Energy (VLO)

Valuation Methodology: We value VLO on a discounted Price/Tangible Book value basis. Our 2015 forecast book value for Valero is $42.6/share, to which we apply a 1.8x multiple, a discount to historic cycle peak valuation multiples. To this we add estimated cumulative cash return per share over the 2012 -2015 time period of $5.5/share to arrive at an estimated equity value of $82/share. We then discount to 2013 using a 10% discount rate to arrive at an estimated fair value price target of $62/share. We add $1/share for estimated retail spin-off value creation.


U.S. Oil & Gas: E&P (Mid-Cap)

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 $1,722 million less estimated net debt at year-end 2012 of $3,677 million less an estimated derivative loss of $128 million in 2013 plus an estimated value of the company's equity stake in McMoran Exploration of $700 million.

Risks which May Impede the Achievement of the Barclays Research Price Target: Our NYMEX price deck is $93/bbl for oil and $2.75/MMBtu for gas in 2012 and $90/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.

Whiting Petroleum (WLL) Valuation Methodology: Our target price is based on a multiple of 5.5x our hedge-adjusted 2013 pre-interest cash flow estimate of $1,631 million less estimated net debt at year-end 2012 of $1,184 million plus an estimated value of WLL's ownership stake in Whiting USA Trust I of $22 million plus an estimated derivative gain of $16 million in 2013 and beyond. Risks which May Impede the Achievement of the Barclays Research Price Target: Our NYMEX price deck is $93/bbl for oil and $2.75/MMBtu for gas in 2012 and $90/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.

U.S. Oil Services & Drilling

Halliburton Co. (HAL)

Valuation Methodology: Our 12-month price target of $57 is based on 13.8x our 2013 earnings estimate of $4.15.

Risks which May Impede the Achievement of the Barclays Research 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.

National Oilwell Varco (NOV)

Valuation Methodology: Our price target of $127 is based on 15.1x our 2013 earnings estimate of $7.75 plus $10 excess cash. Risks which May Impede the Achievement of the Barclays Research 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. Source: Barclays Research.


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ANALYST CERTIFICATION(S) We, Tim Whittaker, Paul Horsnell, Miswin Mahesh, Helima Croft, Trevor Sikorski, Shiyang Wang, Michael Zenker, Harry Mateer, Ming Zhang, Gary Stromberg,Oscar Bate, Matthew Vittorioso, Jim Asselstine, Emmanuel Owusu-Darkwa, Erly Witoyo, Justin Ong, Paul Cheng, Rahim Karim, Lydia Rainforth, CarolineLearmonth, Clement Chen, Scott Darling, Rita Wu, Thomas Driscoll, Jeffrey Robertson, Grant Hofer, Alessandro Pozzi, David Kaplan, James West, Mick Pickup,Richard Gross, David Gagliano, Ephrem Ravi, Daniel Ford, Gregg Orrill, Peter Bisztyga, Olga Levinzon, Amir Rozwadowski, Arindam Basu, 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 subjectsecurities 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 specificrecommendations or views expressed in this research report. IMPORTANT DISCLOSURES: FIXED INCOME, CURRENCIES, AND COMMODITIES RESEARCH Barclays Research is a part of the Corporate and Investment Banking division of Barclays Bank PLC and its affiliates (collectively and each individually,"Barclays"). For current important disclosures regarding companies that are the subject of this research report, please send a written request to: Barclays Research Compliance, 745 Seventh Avenue, 17th Floor, New York, NY 10019 or refer to http://publicresearch.barcap.com or call 212-526-1072. Other Material Conflicts: The Corporate and Investment Banking division of Barclays is providing investment banking services to LINN Energy in the potential acquisition of propertiesin the Jonah Field, located in the Green River Basin of southwest Wyoming, from BP America Production Company. Our rating and estimates on Linn Energydo not incorporate this potential transaction. The Corporate and Investment Banking Division of Barclays is acting as financial advisor to Repsol YPF SA in relation to the forming of an exploration andproduction venture in Russia with Alliance Oil Co. Barclays Capital Inc. and/or one of its affiliates does and seeks to do business with companies covered in its research reports. As a result, investors should beaware that Barclays may have a conflict of interest that could affect the objectivity of this report. Barclays Capital Inc. and/or one of its affiliates 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 researchreport (and related derivatives thereof). Barclays trading desks may have either a long and / or short position in such securities and / or derivativeinstruments, which may pose a conflict with the interests of investing customers. Where permitted and subject to appropriate information barrier restrictions, Barclays fixed income research analyst(s) regularly interact with its trading desk personnel to determine current prices of fixed income securities. Barclaysfixed 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, Currencies andCommodities Division ("FICC") and the outstanding principal amount and trading value of, the profitability of, and the potential interest of the firms investingclients in research with respect to, the asset class covered by the analyst. To the extent that any historical pricing information was obtained from Barclays trading desks, the firm makes no representation that it is accurate or complete. All levels, prices and spreads are historical and do not represent currentmarket levels, prices or spreads, some or all of which may have changed since the publication of this document. The Corporate and Investment Bankingdivision of Barclays 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 researchproducts, whether as a result of differing time horizons, methodologies, or otherwise. In order to access Barclays Statement regarding Research Dissemination Policies and Procedures, please refer to https://live.barcap.com/publiccp/RSR/nyfipubs/disclaimer/disclaimer-research-dissemination.html. Explanation of the Barclays Research High Grade Sector Weighting System Overweight: Expected six-month excess return of the sector exceeds the six-month expected excess return of the Barclays 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 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 U.S. Credit Index, the Pan-European Credit Index, or the EM Asia USD High Grade Credit Index, as applicable. Explanation of the Barclays Research High Grade Credit Rating System The High Grade Credit 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 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 U.S. Credit Index, thePan-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 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 U.S. Credit Index, thePan-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 applicableregulations and/or firm policies in certain circumstances including where the Corporate and Investment Banking division of Barclays is acting in an advisorycapacity 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 U.S. Credit Index or Pan-European Credit Index, as applicable. Explanation of the Barclays Research High Yield Sector Weighting System Overweight: Expected six-month total return of the sector exceeds the six-month expected total return of the Barclays U.S. High Yield 2% Issuer CappedCredit 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.


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IMPORTANT DISCLOSURES: FIXED INCOME, CURRENCIES, AND COMMODITIES RESEARCH (CONTINUED) Market Weight: Expected six-month total return of the sector is in line with the six-month expected total return of the Barclays 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 CreditIndex, as applicable. Underweight: Expected six-month total return of the sector is below the six-month expected total return of the Barclays U.S. High Yield 2% Issuer CappedCredit 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 Barclays Research High Yield Credit Rating System The High Yield Credit Research team employs a relative return based rating system that, depending on the company under analysis, may be applied to eithersome 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 therating 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 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 USDHigh 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 U.S. 2% Issuer Capped High Yield Credit Index, the Pan-European High Yield 3% Issuer Capped Credit Index excluding Financials, or the EMAsia 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 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 USDHigh 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 applicableregulations and/or firm policies in certain circumstances including where the Corporate and Investment Banking division of Barclays is acting in an advisorycapacity 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 (CONTINUED)

Barclays Research is a part of the Corporate and Investment Banking division of Barclays Bank PLC and its affiliates (collectively and eachindividually, "Barclays"). For current important disclosures regarding companies that are the subject of this research report, please send a writtenrequest to: Barclays Research Compliance, 745 Seventh Avenue, 17th Floor, New York, NY 10019 or refer to http://publicresearch.barcap.com orcall 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 NYSE Rule 472 restrictions on communications with a subject company, public appearances and trading securities held by a research analyst’s Account.

Analysts regularly conduct site visits to view the material operations of covered companies, but Barclays policy prohibits them from accepting payment or reimbursement by any covered company of their travel expenses for such visits.

In order to access Barclays Statement regarding Research Dissemination Policies and Procedures, please refer tohttps://live.barcap.com/publiccp/RSR/nyfipubs/disclaimer/disclaimer-research-dissemination.html.

The Corporate and Investment Banking division of Barclays produces a variety of research products including, but not limited to, fundamentalanalysis, equity-linked analysis, quantitative analysis, and trade ideas. Recommendations contained in one type of research product may differfrom recommendations contained in other types of research products, whether as a result of differing time horizons, methodologies, orotherwise.

Primary Stocks (Ticker, Date, Price)

Afren Plc (AFRE.L, 23-Aug-2012, GBP 1.33), Overweight/Positive

Ameresco Inc. (AMRC, 23-Aug-2012, USD 11.99), Overweight/Neutral

American Electric Power (AEP, 23-Aug-2012, USD 42.60), Overweight/Positive

Baker Hughes (BHI, 23-Aug-2012, USD 47.35), Overweight/Positive

Baytex Energy Corp. (BTE.TO, 23-Aug-2012, CAD 47.25), Overweight/Positive

BG Group (BG.L, 23-Aug-2012, GBP 12.98), Overweight/Neutral

China Coal Energy Co., Ltd. (1898.HK, 23-Aug-2012, HKD 7.07), Overweight/Positive

CNOOC (0883.HK, 23-Aug-2012, HKD 14.96), Overweight/Positive

CONSOL Energy (CNX, 23-Aug-2012, USD 32.99), Overweight/Positive

Crescent Point Energy Corp. (CPG.TO, 23-Aug-2012, CAD 41.09), Overweight/Positive

Drax Group (DRX.L, 23-Aug-2012, GBp 462.0), Overweight/Neutral

Edison International (EIX, 23-Aug-2012, USD 43.60), Overweight/Positive

EOG Resources (EOG, 23-Aug-2012, USD 107.01), Overweight/Neutral

EQT Corporation (EQT, 23-Aug-2012, USD 54.44), Overweight/Neutral

Galp Energia (GALP.LS, 23-Aug-2012, EUR 11.71), Overweight/Neutral

Halliburton Co. (HAL, 23-Aug-2012, USD 34.15), Overweight/Positive

Hunting (HTG.L, 23-Aug-2012, GBp 788.0), Overweight/Positive

Imperial Oil Ltd. (IMO.TO, 23-Aug-2012, CAD 46.06), Overweight/Positive

Indo Tambangraya Megah Tbk PT. (ITMG.JK, 23-Aug-2012, IDR 37800.00), Overweight/Positive

Isramco Negev 2 LP (ISRAp.TA, 23-Aug-2012, ILS 0.45), Overweight/Positive

Keppel Corp. (KPLM.SI, 23-Aug-2012, SGD 11.58), Equal Weight/Positive

Motor Oil (MORr.AT, 23-Aug-2012, EUR 4.87), Overweight/Negative

National Oilwell Varco (NOV, 23-Aug-2012, USD 77.32), Overweight/Positive

Neste Oil (NES1V.HE, 23-Aug-2012, EUR 8.41), Overweight/Negative

Noble Energy (NBL, 23-Aug-2012, USD 86.60), Overweight/Neutral

ONEOK Inc. (OKE, 23-Aug-2012, USD 44.33), Overweight/Neutral

Outotec Oyj (OTE1V.HE, 23-Aug-2012, EUR 38.50), Overweight/Positive

Peabody Energy (BTU, 23-Aug-2012, USD 22.93), Overweight/Positive

PetroBakken Energy Ltd. (PBN.TO, 23-Aug-2012, CAD 13.34), Overweight/Positive

Petroleum Geo-Services (PGS.OL, 23-Aug-2012, NOK 88.10), Overweight/Positive

Plains Exploration & Production (PXP, 23-Aug-2012, USD 39.49), Overweight/Positive


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Power-One Inc. (PWER, 23-Aug-2012, USD 6.11), Overweight/Neutral

Ratio Oil Exploration (RATIp.TA, 23-Aug-2012, ILS 0.26), Overweight/Positive

Saipem (SPMI.MI, 23-Aug-2012, EUR 37.72), Overweight/Positive

Sasol Limited (SOLJ.J, 23-Aug-2012, ZAR 357.15), Equal Weight/Neutral

Schlumberger Ltd. (SLB, 23-Aug-2012, USD 74.19), Overweight/Positive

Sembcorp Marine (SCMN.SI, 23-Aug-2012, SGD 5.06), Overweight/Positive

Snam Rete Gas SpA (SRG.MI, 23-Aug-2012, EUR 3.29), Overweight/Neutral

SSE (SSE.L, 23-Aug-2012, GBp 1345.0), Overweight/Neutral

Subsea 7 SA (SUBC.OL, 23-Aug-2012, NOK 135.60), Overweight/Positive

Suncor Energy (SU, 23-Aug-2012, CAD 31.25), Overweight/Positive

Targa Resources Corp. (TRGP, 23-Aug-2012, USD 44.61), Overweight/Neutral

Tesla Motors Inc. (TSLA, 23-Aug-2012, USD 30.73), Overweight/Neutral

Tesoro Corporation (TSO, 23-Aug-2012, USD 38.61), Overweight/Positive

Tullow Oil (TLW.L, 23-Aug-2012, GBP 13.96), Overweight/Positive

Umicore SA (UMI.BR, 23-Aug-2012, EUR 38.49), Overweight/Positive

Valero Energy (VLO, 23-Aug-2012, USD 29.21), Overweight/Positive

Veeco Instruments Inc. (VECO, 23-Aug-2012, USD 33.20), Overweight/Neutral

Veolia Environnement (VIE.PA, 23-Aug-2012, EUR 8.44), Overweight/Neutral

Weatherford International (WFT, 23-Aug-2012, USD 12.72), Overweight/Positive

Whiting Petroleum (WLL, 23-Aug-2012, USD 43.75), Overweight/Positive

Williams Cos. (WMB, 23-Aug-2012, USD 31.88), Overweight/Neutral

Other Material Conflicts:

The Corporate and Investment Banking Division of Barclays is acting as financial advisor to Repsol YPF SA in relation to the forming of anexploration and production venture in Russia with Alliance Oil Co. The Corporate and Investment Banking division of Barclays is providing investment banking services to Cenovus Energy regarding the formationof a joint venture on a portion of their Borealis property. The Corporate and Investment Banking division of Barclays is providing investment banking services to AES Eastern in connection with itsannounced restructuring. The Corporate and Investment Banking Division of Barclays is acting as dealer manager to Ameren Missouri, a subsidiary of Ameren Corporation (AEE), on the announced tender offer to purchase for cash its outstanding 6.00% Senior Secured Notes due 2018 , 6.70% Senior Secured Notesdue 2019, 5.10% Senior Secured Notes due 2018 and 5.10% Senior Secured Notes due 2019. The Corporate and Investment Banking Division of Barclays Bank PLC is acting as corporate broker to Tullow Oil PLC. The Corporate and Investment Banking Division of Barclays Bank PLC is acting as corporate broker to Subsea 7 S.A. The Corporate and Investment Banking Division of Barclays Bank PLC is acting as corporate broker to Hunting Plc. The Corporate and Investment Banking division of Barclays is providing investment banking services to LINN Energy in the potential acquisition ofproperties in the Jonah Field, located in the Green River Basin of southwest Wyoming, from BP America Production Company. Our rating andestimates on Linn Energy do not incorporate this potential transaction.

Guide to the Barclays Fundamental Equity Research Rating System:

Our coverage analysts use a relative rating system in which they rate stocks as Overweight, Equal Weight or 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 (the "industry coverage universe").

In addition to the stock rating, we provide industry views which rate the outlook for the industry coverage universe as Positive, Neutral orNegative (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

Overweight - The stock is expected to outperform the unweighted expected total return of the industry coverage universe over a 12-month investment horizon.

Equal Weight - The stock is expected to perform in line with the unweighted expected total return of the industry coverage universe over a 12-month investment horizon.

Underweight - The stock is expected to underperform the unweighted expected total return of the industry coverage universe over a 12-month investment horizon.


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Rating Suspended - The rating and target price have been suspended temporarily due to market events that made coverage impracticable or tocomply with applicable regulations and/or firm policies in certain circumstances including where the Corporate and Investment Banking Division of Barclays is acting in an advisory capacity in a merger or strategic transaction involving the company.

Industry View Positive - industry coverage universe fundamentals/valuations are improving.

Neutral - industry coverage universe fundamentals/valuations are steady, neither improving nor deteriorating.

Negative - industry coverage universe fundamentals/valuations are deteriorating.

Below is the list of companies that constitute the "industry 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

Adaro Energy Tbk PT. (ADRO.JK) Aluminum Corporation of China Ltd. (2600.HK)

Angang Steel Co., Ltd. (0347.HK)

BHP Billiton Ltd. (BHP.AX) Bumi Resources Tbk PT. (BUMI.JK) 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)

Coal India (COAL.NS) CST Mining Group Ltd. (0985.HK) Harum Energy Tbk PT. (HRUM.JK)

Hindalco Industries Ltd. (HINDA.NS) Hindustan Zinc Ltd. (HZNC.NS) Hyundai Steel Co. (004020.KS)

Indo Tambangraya Megah Tbk PT. (ITMG.JK) IRC Ltd. (1029.HK) Jiangxi Copper Co., Ltd. (0358.HK)

Jindal Steel & Power (JNSP.NS) JSW Steel (JSTL.NS) Maanshan Iron & Steel Co., Ltd. (0323.HK)

Minmetals Resources Ltd. (1208.HK) National Aluminium Co., Ltd. (NALU.NS) NMDC Ltd. (NMDC.NS)

POSCO (005490.KS) Sesa Goa (SESA.NS) Steel Authority of India (SAIL.NS)

Tata Steel (TISC.NS) TB Bukit Asam Tbk PT. (PTBA.JK) UC Rusal (0486.HK)

Yanzhou Coal Mining Co., Ltd. (1171.HK)

Asia ex-Japan Oil & Gas

China Bluechemical Ltd. (3983.HK) China Oilfield Services (COSL) (2883.HK) CNOOC (0883.HK)

Dongyue Group (0189.HK) EZRA Holdings (EZRA.SI) Hanwha Chem Corp. (009830.KS)

Honam Petrochemical (011170.KS) Keppel Corp. (KPLM.SI) LG Chem (051910.KS)

PetroChina (0857.HK) PTT Exploration & Production (PTTE.BK) S-Oil Corporation (010950.KS)

Sembcorp Marine (SCMN.SI) Sinofert Holdings Ltd. (0297.HK) Sinopec (0386.HK)

Sinopec Shanghai Petrochemical Co., Ltd. (0338.HK)

SK Innovation Co., Ltd. (096770.KS)

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) 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) Johnson Matthey (JMAT.L) Mersen S.A. (CBLP.PA)

Outotec Oyj (OTE1V.HE) Prysmian SpA (PRY.MI) Saft Groupe S.A. (S1A.PA)

Umicore SA (UMI.BR)

European Integrated Oil

BG Group (BG.L) BP (BP.L) Eni (ENI.MI)

Galp Energia (GALP.LS) OMV (OMVV.VI) Repsol (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)


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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)

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 (DOCKW.AS) 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)

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) Seche Environnement (CCHE.PA) Severn Trent Plc (SVT.L)

Snam Rete Gas SpA (SRG.MI) SSE (SSE.L) Suez Environnement (SEVI.PA)

Terna SpA (TRN.MI) United Utilities Group Plc (UU.L) Veolia Environnement (VIE.PA)

Verbund (VERB.VI)

Israel Oil & Gas: E&P

Avner Oil Exploration - LP (AVNRp.TA) Delek Drilling - LP (DEDRp.TA) Delek Energy Systems Ltd. (DLEN.TA)

Isramco Negev 2 LP (ISRAp.TA) Ratio Oil Exploration (RATIp.TA)

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)

North America Utilities

Alliant Energy (LNT) American Electric Power (AEP) American Water Works (AWK) Aqua America (WTR) Canadian Utilities Ltd. (CU.TO) CenterPoint Energy Inc. (CNP) CMS Energy (CMS) Consolidated Edison (ED) Dominion Resources (D)


30 August 2012 147


DTE Energy (DTE) Duke Energy (DUK) Edison International (EIX)

Emera Inc. (EMA.TO) Fortis Inc. (FTS.TO) Great Plains Energy Inc. (GXP)

Hawaiian Electric Inds (HE) ITC Holdings (ITC) National Grid Plc (NGG)

NiSource, Inc. (NI) Northeast Utilities (NU) NV Energy, Inc. (NVE)

OGE Energy Corp. (OGE) Pepco Holdings (POM) PG&E Corp. (PCG)

Pinnacle West Capital (PNW) PNM Resources (PNM) Portland General Electric Co. (POR)

SCANA Corp. (SCG) Sempra Energy (SRE) Southern Co. (SO)

TECO Energy (TE) Westar Energy (WR) Wisconsin Energy (WEC)

Xcel Energy (XEL)

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) Trina Solar Ltd. (TSL)

Yingli Green Energy Holding Co., Ltd. (YGE)

U.S. Display & Lighting

Aixtron SE (AIXG) Corning Inc. (GLW) Cree Inc. (CREE)

IPG Photonics (IPGP) Orbotech (ORBK) SemiLEDs Corp. (LEDS)

Veeco Instruments Inc. (VECO)

U.S. Diversified Natural Gas

AGL Resources Inc. (GAS) Atmos Energy (ATO) Enbridge Inc. (ENB.TO)

Energen Corp. (EGN) EQT Corporation (EQT) Kinder Morgan Inc. (KMI)

MDU Resources Group (MDU) National Fuel Gas (NFG) New Jersey Resources (NJR)

ONEOK Inc. (OKE) Piedmont Natural Gas Co. (PNY) Questar Corp. (STR)

Southwest Gas Corp. (SWX) Spectra Energy Corp. (SE) Targa Resources Corp. (TRGP)

WGL Holdings (WGL) Williams Cos. (WMB)

U.S. Independent Refiners

Alon USA Energy (ALJ) Delek US Holdings Inc. (DK) HollyFrontier Corp. (HFC)

Marathon Petroleum Corp. (MPC) Phillips 66 (PSX) 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)

Lufkin Industries, Inc. (LUFK) MRC Global (MRC) Nabors Industries (NBR)


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National Oilwell Varco (NOV) Noble Corp. (NE) Oceaneering International (OII)

Oil States International, Inc. (OIS) 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)

Distribution of Ratings:

Barclays Equity Research has 2425 companies under coverage.

42% have been assigned an Overweight rating which, for purposes of mandatory regulatory disclosures, is classified as a Buy rating; 54% ofcompanies with this rating are investment banking clients of the Firm.

42% have been assigned an Equal Weight rating which, for purposes of mandatory regulatory disclosures, is classified as a Hold rating; 49% ofcompanies with this rating are investment banking clients of the Firm.

13% have been assigned an Underweight rating which, for purposes of mandatory regulatory disclosures, is classified as a Sell rating; 43% of companies with this rating are investment banking clients of the Firm.

Guide to the Barclays Research 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 offices involved in the production of equity research:

London

Barclays Bank PLC (Barclays, London)

New York

Barclays Capital Inc. (BCI, New York)

Tokyo

Barclays Securities Japan Limited (BSJL, 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. (BCCI, 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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This publication has been prepared by the Corporate and Investment Banking division of Barclays Bank PLC and/or one or more of its affiliates (collectivelyand each individually, "Barclays"). It has been issued by one or more Barclays legal entities within its Corporate and Investment Banking division as provided below. It is provided to our clients for information purposes only, and Barclays makes no express or implied warranties, and expressly disclaims all warrantiesof merchantability or fitness for a particular purpose or use with respect to any data included in this publication. Barclays will not treat unauthorized recipientsof this report as its clients. Prices shown are indicative and Barclays is not offering to buy or sell or soliciting offers to buy or sell any financial instrument. 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ENERGY RESEARCH CONTACTS

Commodities

Sijin Cheng Commodities Research +65 6308 6320 [email protected]

Helima Croft Commodities Research +1 212 526 0764 [email protected]

Paul Horsnell Commodities Research +44 (0)20 7773 1145 [email protected]

Miswin Mahesh Commodities Research +44 (0)20 77734291 [email protected]

Kevin Norrish Commodities Research +44 (0)20 7773 0369 [email protected]

Trevor Sikorski Commodities Research +44 (0)20 3134 0160 [email protected]

Sudakshina Unnikrishnan Commodities Research +44 (0)20 777 33797 [email protected]

Shiyang Wang Commodities Research +1 212 526 7464 [email protected]

Credit

Jim Asselstine US Utilities (HG) +1 212 412 5638 [email protected]

Oscar Bate US Metals & Mining +1 212 412 3732 oscar.bate @barclays.com

Kateryna Kukuruza US Energy & Pipelines (HY) +1 212 412 7647 [email protected]

Brian Lalli US Utilities (HY) +1 212 412 5255 [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]

Alyssa Reich US Utilities (HY) +1 212 412 3682 [email protected]

Gary Stromberg US Energy & Pipelines (HY) +1 212 412 7608 [email protected]

Justin Ong Asia-Pacific Energy & Utilities (HG) +65 6308 2155 [email protected]

Matt Vittorioso US Metals & Mining +1 212 412 1378 [email protected]

Erly Witoyo Asia-Pacific Coal +65 6308 3011 [email protected]

Ming Zhang US Energy & Basic Industries (HG) +1 212 412 3386 [email protected]

Equities

Tom Ackermans European Oil Services & Drilling +44 20 7773 4457 [email protected]

Arindam Basu European Clean Technology & Sustainability +1 212 526 2308 [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 and North America Utilities +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]

Richard Gross U.S. Diversified Natural Gas +1 212 526 3143 [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]

David Kaplan Israel Exploration and Production +972 3 623 8747 [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]

Olga Levinzon U.S. Display & Lighting +1 212 526 9134 [email protected]

Rupesh Madlani European Clean Technology & Sustainability +44 20 3134 7503 [email protected]

Gregg Orrill U.S. Power and North America Utilities +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 Independent Refiners +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]

Tavy Rosner Israel Exploration and Production +972 3 623 8628 [email protected]

Amir Rozwadowski U.S. Clean Technology & Renewables +1 212 526 4043 [email protected]

Joshua Stone European Integrated Oil + 44 20 3134 6694 [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]

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